ML13071A392

Technical Requirements Manual (Trm)

ML13071A392
Person / Time
Site:	Comanche Peak
Issue date:	02/21/2013
From:	Luminant Generation Co
To:	Office of Nuclear Reactor Regulation
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Download: ML13071A392 (407)

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TECHNICAL REQUIREMENTS MANUAL (TRM)

FORCOMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 AND 2 CPSES - UNITS 1 AND 2 - TRMiRevision 82TABLE OF CONTENTS11.0USE AND APPLICATION............................................................................11.0-111.1Definitions...............................................................................................11.0-111.2Logical Connectors.................................................................................11.0-1 11.3Completion Times..................................................................................11.0-111.4Frequency..............................................................................................11.0-113.0TECHNICAL REQUIREMENT APPLICABILITY..........................................................................................13.0-113.1REACTIVITY CONTROL SYSTEMS.....................................................13.1-1TR 13.1.31Boration Injection System - Operating..............................................13.1-1TR 13.1.32Boration Injection System - Shutdown.............................................13.1-3TR 13.1.37Rod Group Alignment Limits and Rod Position Indicator.................13.1-6 TR 13.1.38Control Bank Insertion Limits...........................................................13.1-8TR 13.1.39Rod Position Indication - Shutdown.................................................13.1-913.2POWER DISTRIBUTION LIMITS...........................................................13.2-1TR 13.2.31Moveable Incore Detection System..................................................13.2-1TR 13.2.32Axial Flux Difference (AFD)..............................................................13.2-3 TR 13.2.33Quadrant Power Tilt Ratio (QPTR) Alarm........................................13.2-5TR 13.2.34Power Distribution Monitoring System.............................................13.2-613.3INSTRUMENTATION.............................................................................13.3-1TR 13.3.1Reactor Trip System (RTS) Instrumentation Response Times........13.3-1TR 13.3.2Engineered Safety Feature Actuation System (ESFAS) Instrumentation Response Times...............................................13.3-4TR 13.3.5Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation Response Times...............................................13.3-11TR 13.3.31Seismic Instrumentation...................................................................13.3-13TR 13.3.32Source Range Neutron Flux.............................................................13.3-15TR 13.3.33Turbine Overspeed Protection.........................................................13.3-17 TR 13.3.34Plant Calorimetric Measurement......................................................13.3-2113.4REACTOR COOLANT SYSTEM (RCS).................................................13.4-1TR 13.4.14RCS Pressure Isolation Valves........................................................13.4-1 TR 13.4.31Loose Part Detection System...........................................................13.4-2TR 13.4.33Reactor Coolant System (RCS) Chemistry......................................13.4-3TR 13.4.34Pressurizer.......................................................................................13.4-7 TR 13.4.35Reactor Coolant System (RCS) Vent Specification..........................13.4-913.5EMERGENCY CORE COOLING SYSTEMS (ECCS)............................13.5-1TR 13.5.31ECCS - Containment Debris............................................................13.5-1(continued)

TABLE OF CONTENTS (continued)CPSES - UNITS 1 AND 2 - TRMiiRevision 82TR 13.5.32ECCS - Pump Line Flow Rates........................................................13.5-313.6CONTAINMENT SYSTEMS...................................................................13.6-1TR 13.6.3Containment Isolation Valves...........................................................13.6-1 TR 13.6.6Containment Spray System..............................................................13.6-14TR 13.6.7Spray Additive System.....................................................................13.6-1513.7PLANT SYSTEMS..................................................................................13.7-1TR 13.7.2Main Steam Isolation Valves (MSIVs)..............................................13.7-1TR 13.7.3Feedwater Isolation Valves (FIVs) and Feedwater ControlValves (FCVs) and Associated Bypass Valves..........................13.7-2TR 13.7.31Steam Generator Atmospheric Relief Valve (ARV) - Air Accumulator Tank.................................................................13.7-3TR 13.7.32Steam Generator Pressure / Temperature Limitation......................13.7-4TR 13.7.33Ultimate Heat Sink - Sediment and Safe Shutdown Impoundment (SSI) Dam............................................................13.7-6TR 13.7.34Flood Protection...............................................................................13.7-7TR 13.7.35Snubbers..........................................................................................13.7-10TR 13.7.36Area Temperature Monitoring..........................................................13.7-12 TR 13.7.37Safety Chilled Water System - Electrical Switchgear Area Emergency Fan Coil Units..........................................................13.7-15TR 13.7.38Main Feedwater Isolation Valve Pressure / Temperature Limit........13.7-16TR 13.7.39Tornado Missile Shields...................................................................13.7-18 TR 13.7.41Condensate Storage Tank (CST) Make-up and Reject Line Isolation Valves...................................................................13.7-3013.8ELECTRICAL POWER SYSTEMS........................................................13.8-1TR 13.8.31AC Sources (Diesel Generator Requirements)................................13.8-1TR 13.8.32Containment Penetration Conductor Overcurrent Protection Devices......................................................................13.8-313.9REFUELING OPERATIONS..................................................................13.9-1TR 13.9.31Decay Time......................................................................................13.9-1TR 13.9.32Refueling Operations / Communications..........................................13.9-2TR 13.9.33Refueling Machine............................................................................13.9-3 TR 13.9.34Refueling - Crane Travel - Spent Fuel Storage Areas......................13.9-5TR 13.9.35Water Level, Reactor Vessel, Control Rods.....................................13.9-6TR 13.9.36Fuel Storage Area Water Level........................................................13.9-713.10EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAM....................................................................13.10-1TR 13.10.31Explosive Gas Monitoring Instrumentation.......................................13.10-1TR 13.10.32Gas Storage Tanks..........................................................................13.10-5TR 13.10.33Liquid Holdup Tanks.........................................................................13.10-7 TR 13.10.34Explosive Gas Mixture......................................................................13.10-9(continued)

TABLE OF CONTENTS (continued)CPSES - UNITS 1 AND 2 - TRMiiiRevision 8215.0ADMINISTRATIVE CONTROLS............................................................15.0-115.5Programs and Manuals..........................................................................15.0-1TR 15.5.17TRM - Administrative Control Process.............................................15.0-1 TR 15.5.21Surveillance Frequency Control Program........................................15.0-2TR 15.5.31Snubber Augmented Inservice Inspection Program.........................15.0-16 Use and ApplicationTR 11.0CPSES - UNITS 1 AND 2 - TRM11.0-1Revision 56 11.0 USE AND APPLICATION-------------------------------------------------------------------------------------------------------------------------------- NOTE -For the purpose of the Technical Requirements, the Technical Requirements Manual terms specified below should be considered synonymous with the listed Technical Specification terms:-------------------------------------------------------------------------------------------------------------------------------11.1DefinitionsThe definitions contained in the Technical Specifications Section 1.1 , "Definitions" apply to the Technical Requirements contained in this manual. 11.2Logical ConnectorsThe guidance provided for the use and application of logical connectors in Section 1.2 , "Logical Connectors" of the Technical Specifications is applicable to the Technical Requirements contained in this manual.11.3Completion TimesThe guidance provided for the use and application of Completion Times in Section 1.3 , "Completion Times" of the Technical Specifications is applicable to the Technical Requirements contained in this manual.11.4FrequencyThe guidance provided for the use and application of Frequency Requirements in Section 1.4, "Frequency" of the Technical Specifications is applicable to the Technical Requirements contained in this manual.Technical RequirementTechnical SpecificationsTechnical Requirement (TR)Technical Specifications (TS) or Specification(s)Technical Requirement Surveillance (TRS)Surveillance Requirement (SR)

TR ApplicabilityTR 13.0CPSES- UNITS 1 AND 2 - TRM13.0-1Revision 5613.0TECHNICAL REQUIREMENT APPLICABILITYThe guidance provided for the use and application of LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY in Section 3.0, "LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY" of the Technical Specifications is applicable to the Technical Requirements contained in this manual, except as noted below.The guidance provided for the use and application of SURVEILLANCE REQUIREMENT (SR) APPLICABILITY in Section 3.0, "SURVEILLANCE REQUIREMENT (SR) APPLICABILITY" of the Technical Specifications is applicable to the Technical Requirements Surveillance (TRS)

contained in this manual.A cross reference between Section 13.0 of the Technical Requirements Manual and Section 3.0 of the Technical Specifications is as follows:(continued)

Technical Requirement Section Technical Specification SectionTR LCO 13.0.1LCO 3.0.1TR LCO 13.0.2LCO 3.0.2 N/A (See Note 1 below)LCO 3.0.3TR LCO 13.0.4LCO 3.0.4TR LCO 13.0.5LCO 3.0.5 N/A (See Note 2 below)LCO 3.0.6TR LCO 13.0.7LCO 3.0.7 TRS 13.0.1 SR 3.0.1 TRS 13.0.2 SR 3.0.2 TRS 13.0.3 SR 3.0.3 TRS 13.0.4 SR 3.0.4 TR ApplicabilityTR 13.0 13.0 TR APPLICABILITY (continued)CPSES - UNITS 1 AND 2 - TRM13.0-2Revision 56-------------------------------------------------------------------------------------------------------------------------------- NOTES -1.As part of the conversion to the Improved Technical Specifications in July 1999, certain Technical Specifications were relocated to the Improved Technical Requirements Manual. The shutdown requirements (similar to TS LCO 3.0.3) for each Technical Requirement are in three categories: (1) remains with the parent Technical Specification by direct reference to the Technical Specifications, (2) relocated by incorporation into the individual Technical Requirements (i.e. additional conditions were added), or (3) not applicable (i.e. all possible conditions were addressed within the TR LCO). Therefore, the TRM has no corresponding

LCO 3.0.3 similar to the TS LCO 3.0.3

.When a Required Action and Completion Time is not met and no associated Required Action is provided, the condition will be documented in the corrective action program.2.Technical Specification LCO 3.0.6 provides entry into the Safety Function Determination Program (SFDP). The SFDP is not directly applied to the Technical Requirements Manual.

However, TRM requirements may result in inoperable items which either support a parent Technical Specification (e.g. TR 13.3.1, "Reactor Trip System (RTS) Instrumentation Response Times") or provide directions to declare the associated item inoperable and enter the applicable Technical Specification (e.g. TR 13.7.31 , "Steam Generator Atmospheric Relief Valve (ARV) - Air Accumulator Tank").-------------------------------------------------------------------------------------------------------------------------------

Boration Injection System - Operating TR 13.1.31CPSES - UNITS 1 AND 2 - TRM13.1-1Revision 8213.1 REACTIVITY CONTROL SYSTEMSTR 13.1.31 Boration Injection System - OperatingTR LCO 13.1.31Two boration injection subsystems shall be OPERABLE:----------------------------------------------------------------------------------------------------- NOTES -1.TR LCO 13.0.4.c is applicable for entry into MODES 3 and 4 for the charging pump declared inoperable pursuant to TS 3.4.12 provided the charging pump is restored to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after entering MODE 3 or prior to the temperature of one or more of the RCS cold legs exceeding 375°F, whichever comes first.2.In MODE 4 the positive displacement pump may be used in lieu of one ----------------------------------------------------------------------------------------------------

of the required centrifugal charging pumps.APPLICABILITY:MODES 1, 2, 3, and 4 ACTIONSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One boration injection subsystem inoperable (except due to required charging pump inoperable).A.1Restore boration injection subsystem to OPERABLE status.72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />sB.One charging pump inoperable.B.1Restore charging pump to OPERABLE status.

7 daysC.Two boration injection subsystems inoperable.

OR Required Actions and associated Completion Times not met. C.1 Initiate action to restore at least one boration injection subsystem

to OPERABLE status.

ANDC.2Initiate Engineering Evaluation to identify compensatory actions to

be completed in a timely manner.ImmediatelyImmediately Boration Injection System - Operating TR 13.1.31CPSES - UNITS 1 AND 2 - TRM13.1-2Revision 82 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.1.31.1Verify that the temperature of the flow path from the required boric acid storage tanks (including the tank solution temperature) is greater than or equal to 65°F.

7 days TRS 13.1.31.2Verify the boron concentration of the required boric acid storage tank has a minimum boron concentration of 7000 ppm.7 days TRS 13.1.31.3Verify a minimum indicated borated water level of 50% of the required boric acid storage tank.

7 days TRS 13.1.31.4Verify that each valve (manual, power-operated, or automatic) in the required flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.31 days TRS 13.1.31.5Verify that the flow path from the boric acid tanks delivers at least 30 gpm to the RCS.

18 months TRS 13.1.31.6 Demonstrate the required centrifugal charging pump(s) OPERABLE by testing in accordance with the Inservice Testing Plan

.In accordance with the Inservice Testing Plan TRS 13.1.31.7 Demonstrate the required positive displacement charging pump OPERABLE by performing TRS 13.1.31.5.In accordance with TRS 13.1.31.5

Boration Injection System - Shutdown TR 13.1.32CPSES - UNITS 1 AND 2 - TRM13.1-3Revision 82 13.1 REACTIVITY CONTROL SYSTEMSTR 13.1.32 Boration Injection System - ShutdownTR LCO 13.1.32One boration injection subsystem shall be OPERABLE and capable of being powered from an OPERABLE emergency power source.APPLICABILITY:MODES 5 and 6 ACTIONS SURVEILLANCE REQUIREMENTS-------------------------------------------------------------------------------------------------------------------------------- NOTES -1.TRS 13.1.32.2 , TRS 13.1.32.3 , TRS 13.1.32.4 , and TRS 13.1.32.5 are only required to be met when the boric acid storage tank is the required borated water source.

2.TRS 13.1.32.1 , TRS 13.1.32.6, and TRS 13.1.32.7 are only required to be met when the -------------------------------------------------------------------------------------------------------------------------------

RWST is the required borated water source.CONDITIONREQUIRED ACTION COMPLETION TIMEA.Required boration injection subsystem inoperable.

ORRequired boration injection subsystem not capable of

being powered from an OPERABLE emergency power source.A.1Suspend all operations involving positive reactivity additions that could result in loss of required SDM or boron concentration.Immediately Boration Injection System - Shutdown TR 13.1.32 SURVEILLANCE REQUIREMENTS (continued)CPSES - UNITS 1 AND 2 - TRM13.1-4Revision 82(continued)SURVEILLANCEFREQUENCY TRS 13.1.32.1------------------------------------------------------------------------- - NOTE -

Only required to be performed if the outside temperature is less than 40°F.-------------------------------------------------------------------------Verify the RWST has a minimum solution temperature of 40°F.24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> TRS 13.1.32.2Verify that the temperature of the flow path and boric acid storage tank solution temperature is greater than or equal to 65°F.

7 days TRS 13.1.32.3Verify the boron concentration of the boric acid storage tank has a minimum boron concentration of 7000 ppm.

7 days TRS 13.1.32.4Verify a minimum indicated borated water level of 10% when using the boric acid pump from the boric acid storage tank.

7 days TRS 13.1.32.5Verify a minimum indicated borated water level of 20% when using gravity feed from the boric acid storage

tank.7 days TRS 13.1.32.6Verify the boron concentration of the RWST has a minimum boron concentration of 2400 ppm.

7 days TRS 13.1.32.7Verify a minimum indicated borated water level of 24%

when using the RWST.

7 days TRS 13.1.32.8For the required flow path, verify that each valve (manual, power-operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

31 days Boration Injection System - Shutdown TR 13.1.32 SURVEILLANCE REQUIREMENTS (continued)CPSES - UNITS 1 AND 2 - TRM13.1-5Revision 82SURVEILLANCEFREQUENCY TRS 13.1.32.9 Demonstrate the required positive displacement charging pump is OPERABLE by verifying that the flow path from the boric acid storage tanks via a boric acid transfer pump or gravity feed connection to the Reactor Coolant System is capable of delivering at least 30 gpm to the RCS.

18 months TRS 13.1.32.10 Demonstrate the required centrifugal charging pump is OPERABLE by verifying, on recirculation flow, that a differential pressure across the pump of greater than or equal to 2370 psid is developed. In accordance with the Inservice Testing Program TRS 13.1.32.11 Demonstrate the required safety injection pump is operable by verifying, on recirculation flow, the requirements of the IST Program are met for developed head.In accordance with the Inservice Testing Program Rod Group Alignment Limits and Rod Position IndicatorTR 13.1.37CPSES - UNITS 1 AND 2 - TRM13.1-6Revision 82 13.1 REACTIVITY CONTROL SYSTEMSTR 13.1.37 Rod Group Alignment Limits and Rod Position IndicatorTR LCO 13.1.37The Rod Position Deviation Monitor shall be OPERABLE.APPLICABILITY:MODES 1 and 2.

ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One or more rods not within alignment limits.A.1Enter the applicable Condition(s) of TS 3.1.4 ImmediatelyB.One or more rod position indications inoperable.B.1Enter the applicable Condition(s) of TS 3.1.7 ImmediatelySURVEILLANCEFREQUENCY TRS 13.1.37.1--------------------------------------------------------------------------- NOTE -Only required to be performed when the rod position --------------------------------------------------------------------------deviation monitor is discovered to be inoperable.

Verify individual rod positions to be within alignment limit per Technical Specification SR 3.1.4.1. 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> (continued)

Rod Group Alignment Limits and Rod Position IndicatorTR 13.1.37 SURVEILLANCE REQUIREMENTS (continued)CPSES - UNITS 1 AND 2 - TRM13.1-7Revision 82SURVEILLANCEFREQUENCY TRS 13.1.37.2--------------------------------------------------------------------------- NOTE -Only required to be performed when the rod position --------------------------------------------------------------------------deviation monitor is discovered to be inoperable.Verify the OPERABILITY of the Demand Position Indication System and the Digital Rod Position Indication System (DPRI) while performing TRS 13.1.37.1 by verifying that the Demand Position Indication System and the DRPI, for each rod, agrees within 12 steps.

4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Control Bank Insertion LimitsTR 13.1.38CPSES - UNITS 1 AND 2 - TRM13.1-8Revision 82 13.1 REACTIVITY CONTROL SYSTEMSTR 13.1.38 Control Bank Insertion LimitsTR LCO 13.1.38The Control Bank Insertion Limit Monitor shall be OPERABLE.APPLICABILITY:MODE 1, MODE 2 with k eff 1.0 ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Control bank insertion limits not met.A.1Enter the applicable Condition(s) of TS 3.1.6.ImmediatelySURVEILLANCEFREQUENCY TRS 13.1.38.1--------------------------------------------------------------------------- NOTE -Only required to be performed when the rod insertion --------------------------------------------------------------------------limit monitor is discovered to be inoperable.Verify the position of each control bank to be within the insertion limit by verifying the individual rod positions per Technical Specification SR 3.1.6.2

.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Rod Position Indication - Shutdown TR 13.1.39CPSES - UNITS 1 AND 2 - TRM13.1-9Revision 82 13.1 REACTIVITY CONTROL SYSTEMSTR 13.1.39 Rod Position Indication - ShutdownTR LCO 13.1.39One digital rod position indicator (DRPI), excluding demand position indication, shall be OPERABLE for each shutdown or control rod not fully inserted.APPLICABILITY:MODES 3, 4 and 5----------------------------------------------------------------------------------------------------- NOTES -1.This TR LCO is not applicable if the Rod Control System is incapable of rod withdrawal.2.This TR LCO is not applicable if Keff is maintained less than or equal to 0.95, and no more than one shutdown or control bank is withdrawn from the fully inserted position.3.The DRPI System may be de-energized to collect rod drop time data in accordance with SR 3.1.4.3 provided no more than one shutdown or control bank is withdrawn from the fully inserted position and the DRPI System is available during the withdrawal of the shutdown or control ----------------------------------------------------------------------------------------------------bank.ACTIONSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Less than the above required rod position

indicator(s) OPERABLE.A.1Place the Rod Control System in a condition incapable of rod

withdrawal.Immediately (continued)

Rod Position Indication - Shutdown TR 13.1.39 ACTIONS (continued)CPSES - UNITS 1 AND 2 - TRM13.1-10Revision 82 SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEB.Required Action and Completion Time of

Condition A not met.B.1Action shall be initiated to place the unit in a lower MODE.

ANDB.2Be in MODE 4

ANDB.3Be in MODE 5 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 7 hours31 hour3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br />sSURVEILLANCEFREQUENCY TRS 13.1.39.1 Verify each DRPI agrees within 12 steps of the group demand position when the rods are stationary and within 24 steps of the group demand position during rod motion over the full indicated range of rod travel.

Once prior to increasing Keff above 0.95 after each removal of the reactor vessel head.

Moveable Incore Detection System TR 13.2.31CPSES - UNITS 1 AND 2 - TRM13.2-1Revision 79 13.2 POWER DISTRIBUTION LIMITSTR 13.2.31 Moveable Incore Detection SystemTR LCO 13.2.31The Movable Incore Detection System shall be OPERABLE with:a.At least 75% of the detector thimbles,b.A minimum of two detector thimbles per core quadrant, and c.Sufficient movable detectors, drive, and readout equipment to map these thimbles.APPLICABILITY:When the Movable Incore Detection System is used for:a.Recalibration of the Excore Neutron Flux Detection System, orb.Monitoring the QUADRANT POWER TILT RATIO, orc.Measurement of , F Q (Z) and F xy.ACTIONS-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------

TR LCO 13.0.4.c is applicable.

F NHCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One or more required movable incore detection system component(s)

inoperable.A.1Restore the movable incore detection system to OPERABLE

status.Prior to using the system for the above listed

monitoring and

calibration functions.

Moveable Incore Detection System TR 13.2.31CPSES - UNITS 1 AND 2 - TRM13.2-2Revision 79 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.2.31.1Verify Movable Incore Detection System OPERABILITY by irradiating each required detector and determining the acceptability of its voltage curve.

Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to using the system for the above listed monitoring and calibration functions.

Axial Flux DifferenceTR 13.2.32CPSES - UNITS 1 AND 2 - TRM13.2-3Revision 79 13.2 POWER DISTRIBUTION LIMITS TR 13.2.32 Axial Flux Difference (AFD)TR LCO 13.2.32The Axial Flux Difference (AFD) Monitor Alarm shall be OPERABLE.APPLICABILITY:MODE 1 with THERMAL POWER >

50% RTP. ACTIONSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.AFD Monitor Alarm inoperable.A.1Perform TRS 13.2.32.1.Immediately Axial Flux DifferenceTR 13.2.32CPSES - UNITS 1 AND 2 - TRM13.2-4Revision 79 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.2.32.1--------------------------------------------------------------------------- NOTE -Only required to be performed when the AFD Monitor --------------------------------------------------------------------------

Alarm is determined to be inoperable.Monitor and log AFD to verify AFD is within limits for each OPERABLE excore channel.

Once within 30 minutesAND1 hour thereafter QPTR Alarm TR 13.2.33CPSES - UNITS 1 AND 2 - TRM13.2-5Revision 79 13.2 POWER DISTRIBUTION LIMITSTR 13.2.33 Quadrant Power Tilt Ratio (QPTR) AlarmTR LCO 13.2.33The Quadrant Power Tilt Ratio (QPTR) Alarm shall be OPERABLE.APPLICABILITY:MODE 1 with THERMAL POWER > 50% RATED THERMAL POWER.

ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.QPTR not within limit.A.1Enter the applicable Condition(s) of TS 3.2.4.ImmediatelySURVEILLANCEFREQUENCY TRS 13.2.33.1--------------------------------------------------------------------------- NOTE -Only required to be performed when the QPTR alarm is --------------------------------------------------------------------------

determined to be inoperable.

Verify QPTR is within limit by calculation per Technical Specification SR 3.2.4.1

.12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Power Distribution Monitoring System TR 13.2.34CPSES - UNITS 1 AND 2 - TRM13.2-6Revision 79 13.2 POWER DISTRIBUTION LIMITSTR 13.2.34 Power Distribution Monitoring SystemTR LCO 13.2.34The Power Distribution Monitoring System (PDMS) shall be OPERABLE with the minimum type and number of valid inputs from the plant computer

as defined in Table 13.2.34-1.APPLICABILITY:Mode 1 with THERMAL POWER > 25% RTP and the PDMS is used for:a.Recalibration of the Excore Neutron Flux Detection Systemb.Monitoring the QUADRANT POWER TILT RATIO, orc.Measurement of , F Q (Z) and F xy.ACTIONS-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------

TR LCO 13.0.4.c is applicable.

F NHCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One or more PDMS components or required plant computer inputs inoperable.A.1Restore the required PDMS components and plant computer inputs to OPERABLE status.Prior to using the PDMS for the above listed monitoring and calibration functions.

Power Distribution Monitoring System TR 13.2.34CPSES - UNITS 1 AND 2 - TRM13.2-7Revision 79 SURVEILLANCE REQUIREMENTSSSURVEILLANCEFREQUENCY TRS 13.2.34.1Perform a CHANNEL CHECK.Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to using the PDMS for the above listed monitoring

and calibration functions.

TRS 13.2.34.2Verify the PDMS has been calibrated within the required frequency.

Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to using the PDMS for the above listed monitoring

and calibration

functions.

TRS 13.2.34.3--------------------------------------------------------------------------- NOTE -Neutron detectors and thermocouples are excluded --------------------------------------------------------------------------

from CHANNEL CALIBRATION.Verify CHANNEL CALIBRATION has been performed within the required frequency.

Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to using the PDMS for the above

listed monitoring and calibration functions.

TRS 13.2.34.4 Verify CHANNEL FUNCTIONAL TEST has been performed within the required frequency.

Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to using the PDMS for the above

listed monitoring and calibration functions.

Power Distribution Monitoring System TR 13.2.34CPSES - UNITS 1 AND 2 - TRM13.2-8Revision 79Table 13.2.34-1Power Distribution Monitoring System InstrumentationFUNCTIONREQUIRED CHANNEL INPUTS TECHNICALREQUIREMENTSSURVEILLANCE1.Control Bank Position4TRS 13.2.34.1TRS 13.2.34.42.RCS Cold Leg Temperature, Tcold2TRS 13.2.34.1TRS 13.2.34.33.Reactor Power Level1TRS 13.2.34.1TRS 13.2.34.34.NIS Power Range Excore Detector Section Signals6TRS 13.2.34.1TRS 13.2.34.35.Core Exit Thermocouple Temperatures 13 with > 2 per quadrantTRS 13.2.34.1TRS 13.2.34.3 RTS Instrumentation Response TimesTR 13.3.1CPSES - UNITS 1 AND 2 - TRM13.3-1Revision 7413.3 INSTRUMENTATIONTR 13.3.1 Reactor Trip System (RTS) Instrumentation Response Times-------------------------------------------------------------------------------------------------------------------------------- NOTE -This Technical Requirement contains the listing of Reactor Trip System Instrumentation Response Time limits associated with Technical Specification SR 3.3.1.16 and the applicable -------------------------------------------------------------------------------------------------------------------------------

Functions in Technical Specification Table 3.3.1-1

.

RTS Instrumentation Response TimesTR 13.3.1CPSES - UNITS 1 AND 2 - TRM13.3-2Revision 74Table 13.3.1-1 (Page 1 of 2)Reactor Trip System (RTS) Instrumentation Response Time Limits(1)Neutron/gamma detectors are exempt from response time testing. Response time of the neutron/gamma flux signal portion of the channel shall be measured from detector output or input of first electronic component in a channel.(2)An additional 6 seconds maximum delay allowance for the RTD/thermal well response time provides an overall Overtemperature N-16 Response Time of 9.3 seconds for the Tcold input.(3)Includes Single Loop (Above P-8) and Two Loops (Above P-7 and Below P-8)(4)An additional 0.4 seconds maximum calculated voltage decay time from the opening of RCPbreaker until voltage reaches the undervoltage set-point provides an overall time 1.5secondsINITIATION SIGNALRESPONSE TIME IN SECONDS1.Manual Reactor TripN.A.

2.Power Range Neutron Flux a.High Setpoint0.5 (1)b.Low Setpoint0.5 (1)3.Power Range Neutron Flux High Positive Rate.65 (1)4.Intermediate Range Neutron FluxN.A.5.Source Range Neutron FluxN.A.6.Overtemperature N-16 3.3 (1,2)7.Overpower N-16 2 (1)8.Pressurizer Pressurea.Pressurizer Pressure Low 2b.Pressurizer Pressure High 29.Pressurizer Water Level HighN.A.10.Reactor Coolant Flow Low 1 (3)11.Not UsedN.A.12.Undervoltage - Reactor Coolant Pumps1.1 (4)

RTS Instrumentation Response TimesTR 13.3.1CPSES - UNITS 1 AND 2 - TRM13.3-3Revision 74Table 13.3.1-1 (Page 2 of 2)Reactor Trip System (RTS) Instrumentation Response Time LimitsINITIATION SIGNALRESPONSE TIME IN SECONDS13.Underfrequency - Reactor Coolant Pumps 0.614.Steam Generator Water Level Low-Low 215.Not UsedN.A.16.Turbine Tripa.Low Fluid Oil PressureN.A.b.Turbine Stop Valve ClosureN.A.17.Safety Injection Input from ESFASN.A.18.Reactor Trip System Interlocksa.Intermediate Range Neutron Flux, P-6N.A.

b.Low Power Reactor Trips Block, P-7N.A.c.Power Range Neutron Flux, P-8N.A.d.Power Range Neutron Flux, P-9N.A.

e.Power Range Neutron Flux, P-10N.A.f.Turbine First Stage Pressure, P-13N.A.19.Reactor Trip BreakersN.A.

20.Reactor Trip Breaker Undervoltage and Shunt Trip Mechanisms N.A.21.Automatic Trip LogicN.A.

ESFAS Instrumentation Response TimesTR 13.3.2CPSES - UNITS 1 AND 2 - TRM13.3-4Revision 7413.3 INSTRUMENTATIONTR 13.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation Response Times-------------------------------------------------------------------------------------------------------------------------------- NOTE -This Technical Requirement contains the listing of ESFAS Instrumentation Response Time limits

associated with Technical Specification SR 3.3.2.10 and the applicable functions in Technical -------------------------------------------------------------------------------------------------------------------------------

Specification Table 3.3.2-1.

ESFAS Instrumentation Response TimesTR 13.3.2CPSES - UNITS 1 AND 2 - TRM13.3-5Revision 74Table 13.3.2-1 (Page 1 of 6)Engineered Safety Features Actuation System Instrumentation Response Time Limits (1)Includes Diesel Generator starting delay. (4)Diesel generator starting delay is not included. Includes centrifugal charging pumps only. (5)Sequential transfer of charging pump suction from the VCT to the RWST (RWST valves open, then VCT valves close) is not included. (6)Includes sequential transfer of charging pump suction from the VCT to the RWST (RWST valves open, then VCT valves close). (7)Includes Diesel Generator starting delay. Includes containment spray pumps only. (8)RHR mini-flow valves are not included.(15)The response time of less than or equal to 2 seconds is applicable for MODES 1 and 2 and is measured to the loss of stationary gripper coil only. The response time is not applicable (N.A.) for MODES 3 and 4.FUNCTIONAL UNIT AND INITIATION SIGNALRESPONSE TIME IN SECONDS1.Safety Injectiona.Manual InitiationN.A.b.Automatic Actuation Logic and Actuation RelaysN.Ac.Containment Pressure High 11.ECCS 27 (1,5,8) / 27 (4,6,8)2.Reactor Trip2 (15)3.Containment Ventilation IsolationN.A.4.Station Service WaterN.A.5.Component Cooling WaterN.A.6.Essential Ventilation SystemsN.A.

7.Emergency Diesel Generator Operation128.Control Room Emergency RecirculationN.A.9.Containment Spray32 (7)

ESFAS Instrumentation Response TimesTR 13.3.2CPSES - UNITS 1 AND 2 - TRM13.3-6Revision 74Table 13.3.2-1 (Page 2 of 6)Engineered Safety Features Actuation System Instrumentation Response Time Limits (1)Includes Diesel Generator starting delay. (4)Diesel generator starting delay is not included. Includes centrifugal charging pumps only. (5)Sequential transfer of charging pump suction from the VCT to the RWST (RWST valves open, then VCT valves close) is not included. (6)Includes sequential transfer of charging pump suction from the VCT to the RWST (RWST valves open, then VCT valves close). (8)RHR mini-flow valves are not included.(15)The response time of less than or equal to 2 seconds is applicable for MODES 1 and 2 and is measured to the loss of stationary gripper coil only. The response time is not applicable (N.A.) for MODES 3 and 4.(16)Includes containment pressure relief valves only.FUNCTIONAL UNIT AND INITIATION SIGNALRESPONSE TIME IN SECONDS1.Safety Injection (continued)d.Pressurizer Pressure Low1.ECCS 27 (1,5,8) / 27 (4,6,8)2.Reactor Trip 2 (15)3.Containment Ventilation Isolation 5 (16)4.Station Service WaterN.A.5.Component Cooling WaterN.A.6.Essential Ventilation SystemsN.A.

7.Emergency Diesel Generator Operation128.Control Room Emergency RecirculationN.A.9.Containment SprayN.A.

ESFAS Instrumentation Response TimesTR 13.3.2CPSES - UNITS 1 AND 2 - TRM13.3-7Revision 74Table 13.3.2-1 (Page 3 of 6)Engineered Safety Features Actuation System Instrumentation Response Time Limits (3)Includes Diesel Generator starting delay. Includes centrifugal charging pumps only. (4)Diesel generator starting delay is not included. Includes centrifugal charging pumps only. (6)Includes sequential transfer of charging pump suction from the VCT to the RWST (RWST valves open, then VCT valves close). (8)RHR mini-flow valves are not included. (9)Includes containment spray header isolation valves only.(15)The response time of less than or equal to 2 seconds is applicable for MODES 1 and 2 and is measured to the loss of stationary gripper coil only. The response time is not applicable (N.A.) for MODES 3 and 4.FUNCTIONAL UNIT AND INITIATION SIGNALRESPONSE TIME IN SECONDS1.Safety Injection (continued)e.Steam Line Pressure Low1.ECCS 37 (3,6,8) / 27 (4,6,8)2.Reactor Trip 2 (15)3.Containment Ventilation IsolationN.A.4.Station Service WaterN.A.

5.Component Cooling WaterN.A.6.Essential Ventilation SystemsN.A.7.Emergency Diesel Generator Operation128.Control Room Emergency RecirculationN.A.9.Containment SprayN.A.2.Containment Spraya.Manual InitiationN.A.b.Automatic Actuation Logic and Actuation RelaysN.A.c.Containment Pressure High 3119(9)

ESFAS Instrumentation Response TimesTR 13.3.2CPSES - UNITS 1 AND 2 - TRM13.3-8Revision 74Table 13.3.2-1 (Page 4 of 6)Engineered Safety Features Actuation System Instrumentation Response Time Limits (1)Includes Diesel Generator starting delay. (2)Diesel generator starting delay is not included.(10)Includes Containment Pressure High 1, Pressurizer Pressure Low, and Steam Line Pressure Low initiation signals.FUNCTIONAL UNIT AND INITIATION SIGNALRESPONSE TIME IN SECONDS3.Containment Isolationa.Phase A Isolation1.Manual InitiationN.A2.Automatic Actuation Logic and Actuation RelaysN.A.

3.Safety Injection 17 (2,10) / 27 (1,10)b.Phase B Isolation1.Manual InitiationN.A.

2.Automatic Actuation Logic and Actuation RelaysN.A.3.Containment Pressure High 3N.A.4.Steam Line Isolationa.Manual InitiationN.A.b.Automatic Actuation Logic and Actuation RelaysN.A.c.Containment Pressure High 27d.Steam Line Pressure1.Steam Line Pressure Low72.Steam Line Pressure Negative Rate High7 ESFAS Instrumentation Response TimesTR 13.3.2CPSES - UNITS 1 AND 2 - TRM13.3-9Revision 74Table 13.3.2-1 (Page 5 of 6)Engineered Safety Features Actuation System Instrumentation Response Time Limits (1)Includes Diesel Generator starting delay.(10)Includes Containment Pressure High 1, Pressurizer Pressure Low, and Steam Line Pressure Low initiation signals.(11)Includes Feedwater Isolation only. Turbine Trip is not included.(12)Includes motor driven auxiliary feedwater pumps in Units 1 and 2 and feedwater split flow bypass valves in Unit 2 only.(13)Includes turbine driven auxiliary feedwater pump in Units 1 and 2 and feedwater split flow bypass valves in Unit 2 only.(14)Includes motor driven auxiliary feedwater pumps only.FUNCTIONAL UNIT AND INITIATION SIGNALRESPONSE TIME IN SECONDS5.Turbine Trip and Feedwater Isolationa.Automatic Actuation Logic and Actuation RelaysN.A.b.Steam Generator Water Level High-High, P-14 11 (11)c.Safety Injection 7 (10,11)6.Auxiliary Feedwatera.Automatic Actuation Logic and Actuation RelaysN.A.b.Not UsedN.A.

c.Steam Generator Water Level Low-Low 60 (12) / 85 (13)d.Safety Injection 60 (1,10,12)e.Loss of Offsite Power 58 (1,14)f.Not UsedN.A.g.Trip of all Main Feedwater PumpsN.A.h.Not UsedN.A.

ESFAS Instrumentation Response TimesTR 13.3.2CPSES - UNITS 1 AND 2 - TRM13.3-10Revision 74Table 13.3.2-1 (Page 6 of 6)Engineered Safety Features Actuation System Instrumentation Response Time LimitsFUNCTIONAL UNIT AND INITIATION SIGNALRESPONSE TIME IN SECONDS7.Automatic Switchover to Containment Sumpa.Automatic Actuation Logic and Actuation RelaysN.A.b.Refueling Water Storage Tank Level Low-Low Coincident with Safety Injection308.ESFAS Interlocksa.Reactor Trip, P-4N.A.

b.Pressurizer Pressure, P-11N.A.

LOP DG Start Instrumentation Response TimesTR 13.3.5CPSES - UNITS 1 AND 2 - TRM13.3-11Revision 7413.3 INSTRUMENTATIONTR 13.3.5 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation Response Times-------------------------------------------------------------------------------------------------------------------------------- NOTE -This Technical Requirement contains the listing of Loss of Power Diesel Generator Start Instrumentation Response Time limits associated with Technical Specification SR 3.3.5.4 and -------------------------------------------------------------------------------------------------------------------------------

applicable functions in Technical Specification Table 3.3.5-1

.

LOP DG Start Instrumentation Response TimesTR 13.3.5CPSES - UNITS 1 AND 2 - TRM13.3-12Revision 74 (Sup 1)Table 13.3.5-1Loss of Power Diesel Generator Start Instrumentation Response Time LimitsINITIATION SIGNAL AND FUNCTIONRESPONSE TIME IN SECONDS1.Automatic Actuation Logic and Actuation RelaysN.A.2.Preferred Offsite Source bus UV 1(1)3.Alternate Offsite Source bus UV 1(1)4.6.9 KV Class 1E Bus Undervoltage 2 (2)5.6.9 KV Degraded Voltage 6 (5) & 10 (5, 3) / 60 (4)6.480 V Class 1E Bus Low Grid Undervoltage 45 (6)7.480V Class 1E Bus Degraded Voltage 6 (5) & 10 (5, 3) / 60 (4)(1)Response time measured to output of under voltage channel providing the offsite source breaker trip signal.(2)Response time measured to output of under voltage channel providing the DG start signal.(3)An additional 3 seconds is allowed for the Alternate Offsite Source breaker trip signal and another 3 seconds is allowed for DG close permissive signal.(4)Response time measured to output of under voltage channel providing the Preferred and Alternate Offsite Source breakers trip signals after detection of degraded Voltage condition, in the absence of SIAS.(5)Response time measured to output of under voltage channel to confirm degraded condition for providing a Preferred Offsite Source breakers trip on subsequent occurrence

of SIAS.(6)Response time measured to output of under voltage channel to confirm 480V bus low grid condition for providing a Preferred Offsite Source breakers trip on subsequent occurrence

of SIAS.

Seismic InstrumentationTR 13.3.31CPSES - UNITS 1 AND 2 - TRM13.3-13Revision 7413.3 INSTRUMENTATIONTR 13.3.31 Seismic Instrumentation TR LCO 13.3.31The seismic monitoring instrumentation shall be OPERABLE.APPLICABILITY:At all times ACTIONS-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------

TR LCO 13.0.4.c is applicable.CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Seismic monitoring instrument inoperable.A.1Restore seismic monitoring instrument to OPERABLE status.

30 days Seismic InstrumentationTR 13.3.31CPSES - UNITS 1 AND 2 - TRM13.3-14Revision 74 SURVEILLANCE REQUIREMENTS SURVEILLANCEFREQUENCY TRS 13.3.31.1Perform a CHANNEL CHECK.31 days TRS 13.3.31.2Perform a CHANNEL CALIBRATION.18 months TRS 13.3.31.3--------------------------------------------------------------------------- NOTE ---------------------------------------------------------------------------Setpoint verification is not required.Perform a CHANNEL OPERATIONAL TEST.184 days Source Range Neutron Flux TR 13.3.32CPSES - UNITS 1 AND 2 - TRM13.3-15Revision 7413.3 INSTRUMENTATIONTR 13.3.32 Source Range Neutron FluxTR LCO 13.3.322 channels for source range neutron flux monitoring shall be OPERABLE.APPLICABILITY:MODES 3, 4, and 5-------------------------------------------------------------------------------------------------------------------------------- NOTE -Only applicable if the Rod Control System is not capable of rod withdrawal and all control rods -------------------------------------------------------------------------------------------------------------------------------are fully inserted.

ACTIONS CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One required Source Range Neutron Flux

channel inoperable.A.1Restore channel to OPERABLE status.ORA.2Suspend all operations involving positive reactivity changes.48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />s49 hoursB.Both required Source Range Neutron Flux channels inoperable.B.1Restore one channel to OPERABLE status.

ORB.2Suspend all operations involving positive reactivity changes.

4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 4 hours Source Range Neutron Flux TR 13.3.32CPSES - UNITS 1 AND 2 - TRM13.3-16Revision 74 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.3.32.1Perform CHANNEL CHECK.12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> TRS 13.3.32.2---------------------------------------------------------------------------- NOTE ----------------------------------------------------------------------------Not required for the Gamma-Metrics range detectors.Perform COT.184 days TRS 13.3.32.3---------------------------------------------------------------------------- NOTES -1.Neutron detectors may be excluded from CHANNEL CALIBRATION.2.For the source range neutron detectors, ---------------------------------------------------------------------------

performance data is obtained and evaluated.Perform CHANNEL CALIBRATION.18 months Turbine Overspeed ProtectionTR 13.3.33CPSES - UNITS 1 AND 2 - TRM13.3-17Revision 7413.3 INSTRUMENTATIONTR 13.3.33 Turbine Overspeed ProtectionTR LCO 13.3.33At least one Turbine Overspeed Protection Sub-system shall be OPERABLE.APPLICABILITY:MODES 1, 2, and 3----------------------------------------------------------------------------------------------------- NOTE -Not applicable in MODES 2 and 3 with all main steam line isolation valves ----------------------------------------------------------------------------------------------------and associated bypass valves in the closed position.

ACTIONS -------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------Separate Condition entry allowed for each steam line.CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One stop valve or one control valve per high pressure turbine steam line

inoperable.A.1Restore the inoperable valve(s) to OPERABLE status.

ORA.2Close at least one valve in the affected steam line(s).

ORA.3Isolate the turbine from the steam supply.72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s78 hours 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> (continued)

Turbine Overspeed ProtectionTR 13.3.33 ACTIONS (continued)CPSES - UNITS 1 AND 2 - TRM13.3-18Revision 74CONDITIONREQUIRED ACTIONCOMPLETION TIMEB.One stop valve or one control valve per low pressure turbine steam line inoperable.B.1Restore the inoperable valve(s) to OPERABLE status.

ORB.2Close at least one valve in the affected steam line(s).

ORB.3Isolate the turbine from the steam supply.72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s78 hours78 hour9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br />sC.Both Overspeed Protection Sub-systems inoperable.C.1Isolate the turbine from the steam supply.6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />sD.Required Actions and associated Completion Times not met.D.1Initiate action to place the unit in a lower MODE.

ANDD.2Be in MODE 3.

ANDD.3Be in MODE 4.

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 7 hours13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> Turbine Overspeed ProtectionTR 13.3.33CPSES - UNITS 1 AND 2 - TRM13.3-19Revision 74 SURVEILLANCE REQUIREMENTS-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------

The provisions of TRS 13.0.4 are not applicable.SURVEILLANCEFREQUENCY TRS 13.3.33.1Test the Turbine Trip Block using the Automatic Turbine Tester (ATT).

14 days TRS 13.3.33.2Cycle each of the following valves through at least one complete cycle from the running position using the

manual test or Automatic Turbine Tester (ATT).a.Four high pressure turbine stop valves, b.Four high pressure turbine control valves,c.Four low pressure turbine stop valves, andd.Four low pressure turbine control valves.

26 weeks TRS 13.3.33.3 Deleted TRS 13.3.33.4Disassemble at least one high pressure turbine stop valve and one high pressure control valve and perform a visual and surface inspection of valve seats, disks and stems and verify no unacceptable flaws are found. If unacceptable flaws are found, all other valves of that type shall be inspected.

40 months TRS 13.3.33.5Visually inspect the disks and accessible portions of the shafts of at least one low pressure turbine stop valve and one low pressure control valve and verify no unacceptable flaws are found. If unacceptable flaws are found, all other valves of that type shall be

inspected.

40 months (continued)

Turbine Overspeed ProtectionTR 13.3.33 SURVEILLANCE REQUIREMENTS (continued)CPSES - UNITS 1 AND 2 - TRM13.3-20Revision 74SURVEILLANCEFREQUENCY TRS 13.3.33.6Test the Hardware Overspeed Sub-system 2 of 3 relay logic and output relays.

18 months Plant Calorimetric Measurement TR 13.3.34CPSES - UNITS 1 AND 2 - TRM13.3-21Revision 7413.3 INSTRUMENTATION TR 13.3.34 Plant Calorimetric MeasurementTR LCO 13.3.34The Leading Edge Flow Meter (LEFM) shall be used for the completion of SR 3.3.1.2

.APPLICABILITY:MODE 1 > 15% RTP ACTIONS CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.LEFM not availableA.1Restore LEFM to available statusPrior to performance of SR 3.3.1.2B.Required Action or Completion Time of Condition A not metB.1Ensure THERMAL POWER 98.6% RTP.

ANDB.2Perform SR 3.3.1.2 using feedwater venturis ANDB.3Maintain THERMAL POWER 98.6% RTP.Prior to performance of SR 3.3.1.2 As required by SR3.3.1.2Until LEFM is restored to available status and SR3.3.1.2 is performed using LEFM.

Plant Calorimetric Measurement TR 13.3.34CPSES - UNITS 1 AND 2 - TRM13.3-22Revision 74 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.3.34.1Verify availability of LEFM using self-diagnosticsPrior to performance of SR 3.3.1.2 RCS Pressure Isolation ValvesTR 13.4.14CPSES - UNITS 1 AND 2 - TRM13.4-1Revision 5613.4 REACTOR COOLANT SYSTEM (RCS)TR 13.4.14 RCS Pressure Isolation ValvesThis Technical Requirement contains a listing of the RCS Pressure Isolation Valves (PIVs) subject to Technical Specification 3.4.14

.Table 13.4.14-1Reactor Coolant System Pressure Isolation ValvesVALVE NUMBERFUNCTION8948 A, B, C, DAccumulator Tank Discharge8956 A, B, C, DAccumulator Tank Discharge 8905 A, B, C, DSI Hot Leg Injection 8949 A, B, C, DSI Hot Leg Injection8818 A, B, C, DRHR Cold Leg Injection8819 A, B, C, DSI Cold Leg Injection 8701 A, BRHR Suction Isolation8702 A, BRHR Suction Isolation8841 A, BRHR Hot Leg Injection 8815CCP Cold Leg Injection8900 A, B, C, DCCP Cold Leg Injection Loose Part Detection SystemTR 13.4.31CPSES - UNITS 1 AND 2 - TRM13.4-2Revision 56 13.4 REACTOR COOLANT SYSTEMTR 13.4.31 Loose Part Detection SystemTR LCO 13.4.31The Loose-Part Detection System shall be OPERABLE.APPLICABILITY:MODES 1 and 2 ACTIONS-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------

TR LCO 13.0.4.c is applicable.

SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.With one or more required Loose-Part Detection System channels inoperable.A.1Restore required channels to Operable status.

30 daysSURVEILLANCEFREQUENCY TRS 13.4.31.1Perform a CHANNEL CHECK.24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> TRS 13.4.31.2------------------------------------------------------------------------- - NOTE -Setpoint verification is not required.-------------------------------------------------------------------------Perform a CHANNEL OPERATIONAL TEST.31 days TRS 13.4.31.3Perform a CHANNEL CALIBRATION.18 months RCS Chemistry TR 13.4.33CPSES - UNITS 1 AND 2 - TRM13.4-3Revision 56 13.4 REACTOR COOLANT SYSTEMTR 13.4.33 Reactor Coolant System (RCS) ChemistryTR LCO 13.4.33The Reactor Coolant System chemistry shall be maintained within the limits specified in Table 13.4.33-1

.APPLICABILITY:At all times.

ACTIONS CONDITIONREQUIRED ACTIONCOMPLETION TIME------------------------------------------- NOTE -Only applicable in MODES 1, ------------------------------------------2, 3 and 4.A.One or more chemistry parameters in excess of its Steady-State Limit but within its Transient Limit.A.1Restore parameter to within Steady-State limit.24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s------------------------------------------- NOTE -Only applicable in MODES 1, ------------------------------------------2, 3 and 4.B.Required Action and associated Completion Time of Condition A not met.OR One or more chemistry parameters in excess of its Transient Limit.B.1Be in MODE 3.

ANDB.2Be in MODE 5.

6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s36 hours (continued)

RCS Chemistry TR 13.4.33 ACTIONS (continued)CPSES - UNITS 1 AND 2 - TRM13.4-4Revision 56CONDITIONREQUIRED ACTIONCOMPLETION TIME------------------------------------------- NOTE -Applicable in all conditions other than MODES 1, 2, 3 and ------------------------------------------

4.C.Concentration of chloride or floride in the RCS in excess of its Steady-State Limit.C.1Restore concentration of chloride and floride to within its Steady-

State limit.24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />s------------------------------------------- NOTES -1.All Required Actions must be completed whenever this Condition is entered.2.Applicable in all conditions other than MODES 1, 2, 3 ------------------------------------------

and 4.D.Required Action and associated Completion Time of Condition C not met.ORConcentration of chloride or fluoride in the RCS in excess of its Transient Limit.D.1Initiate action to reduce the pressurizer pressure to 500 psig.ANDD.2Perform an engineering evaluation to determine the effects of the out-of-limit condition on the structural integrity of the RCS; determine that the RCS remains acceptable for continued

operation.ImmediatelyPrior to increasing the pressurizer pressure >500 psig.ANDPrior to proceeding to MODE 4.

RCS Chemistry TR 13.4.33CPSES - UNITS 1 AND 2 - TRM13.4-5Revision 56 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.4.33.1--------------------------------------------------------------------------- NOTES -1.Not required to be performed for dissolved oxygen when T avg 250°F.2.Not required to be met for Chloride and Fluoride until 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after entry into MODE 6 from a --------------------------------------------------------------------------defueled state.Verify the RCS chemistry within the limits by analysis of parameter specified in Table 13.4.33-1

.72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> RCS Chemistry TR 13.4.33CPSES - UNITS 1 AND 2 - TRM13.4-6Revision 56Table 13.4.33-1Reactor Coolant System Chemistry LimitsPARAMETERSTEADY-STATE LIMIT TRANSIENT LIMIT Dissolved Oxygen (a)(a) Limit not applicable with Tavg less than or equal to 250 °F. 0.10 ppm1.00 ppm Chloride (b)(b) Limit not applicable when Reactor Coolant System is defueled. 0.15 ppm1.50 ppmFluoride (b) 0.15 ppm1.50 ppm PressurizerTR 13.4.34CPSES - UNITS 1 AND 2 - TRM13.4-7Revision 56 13.4 REACTOR COOLANT SYSTEMTR 13.4.34 PressurizerTR LCO 13.4.34The pressurizer temperature shall be limited to:a.A maximum heatup of 100°F in any 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period, andb.A maximum cooldown of 200°F in any 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period.APPLICABILITY:At all times.

ACTIONS CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.------------------------------------ - NOTE -All Required Actions must be completed whenever this Condition is entered.------------------------------------

Pressurizer temperature in excess of the required limits.A.1Restore pressurizer temperature to within limits.

ANDA.2Perform an engineering evaluation to determine that the effects of the out-of-limit condition on the structural integrity of the pressurizer remains acceptable for continued operation.

30 minutesAs assigned by the Shift Manager, commensurate

with safety.B.Required Actions and associated Completion Times of Condition A not met.B.1Be in at least MODE 3.

ANDB.2Reduce pressurizer pressure to <500 psig.

6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s36 hoursC.Required Actions and associated Completion Times of Condition B not met.C.1Be in MODE 4.

ANDC.2Be in MODE 5.

6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s30 hours PressurizerTR 13.4.34CPSES - UNITS 1 AND 2 - TRM13.4-8Revision 56 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.4.34.1------------------------------------------------------------------------ - NOTE -Only required to be performed during system heatup and cooldown.

---

Verify the pressurizer temperatures to be within the limits.30 minutes RCS VentsTR 13.4.35CPSES - UNITS 1 AND 2 - TRM13.4-9Revision 56 13.4 REACTOR COOLANT SYSTEMTR 13.4.35 Reactor Coolant System (RCS) Vent SpecificationTR LCO 13.4.35At least one Reactor Coolant System vent path consisting of two vent valves in series powered from emergency busses shall be OPERABLE and closed at each of the following locations:a.Reactor vessel head, and b.Pressurizer steam space.APPLICABILITY:MODES 1, 2, 3, and 4.

ACTIONSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One Reactor Coolant System vent path inoperable.A.1Close the inoperable vent path and remove power from the valve actuators of all the vent valves in the inoperable vent path.

ANDA.2Restore the inoperable vent path to OPERABLE status.Immediately 30 daysB.Both Reactor Coolant System vent paths inoperable.B.1Close the inoperable vent paths and remove power from the valve actuators of all the vent valves in the inoperable vent paths.

ANDB.2Restore at least one of the vent paths to OPERABLE status.Immediately72 hours (continued)

RCS VentsTR 13.4.35 ACTIONS (continued)CPSES - UNITS 1 AND 2 - TRM13.4-10Revision 56 SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEC.Required Actions and associated Completion Times of Condition A or B not met.C.1Be in MODE 3.

ANDC.2Be in MODE 5.

6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s36 hoursSURVEILLANCEFREQUENCY TRS 13.4.35.1Verify all manual isolation valves in each vent path are locked in the open position.

18 months TRS 13.4.35.2Cycle each vent valve path through at least one complete cycle of full travel from the control room.

18 months TRS 13.4.35.3Verify flow through the Reactor Coolant System vent paths during venting.

18 months ECCS - Containment DebrisTR 13.5.31CPSES - UNITS 1 AND 2 - TRM13.5-1Revision 56 13.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

TR 13.5.31 ECCS - Containment DebrisTR LCO 13.5.31Pursuant to TS 3.5.2 and 3.5.3, the containment shall be free of loose debris which could restrict, during a LOCA, the pump suctions for the ECCS train(s) required to be OPERABLE.APPLICABILITY:MODES 1, 2, 3 and 4.

ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Loose debris left in containment which could restrict, during a LOCA, the pump suctions for the ECCS train(s) required to be OPERABLE.A.1Enter the applicable Condition(s) of TS 3.5.2 or 3.5.3 for affected ECCS train(s) inoperable.ImmediatelySURVEILLANCEFREQUENCY TRS 13.5.31.1--------------------------------------------------------------------------- NOTE -This surveillance not required for entry into MODE 4 provided that for the entire time below MODE 4, (1) restrictions and access controls used for MODES 1

through 4 are maintained and (2) TRS 13.5.31.2 is --------------------------------------------------------------------------performed as required to support containment entries.Perform a visual inspection of accessible areas of containment to verify that no loose debris (rags, trash, clothing, etc.) is present in the containment which could be transported to the containment sump and cause restriction of the pump suctions during LOCA conditions.

Once prior to entering MODE 4 ECCS - Containment DebrisTR 13.5.31 SURVEILLANCE REQUIREMENTS (continued)CPSES - UNITS 1 AND 2 - TRM13.5-2Revision 56SURVEILLANCEFREQUENCY TRS 13.5.31.2--------------------------------------------------------------------------- NOTE -Only required to be performed during periods when --------------------------------------------------------------------------containment entries are made.

Perform a visual inspection of all areas within containment affected by a containment entry to verify that no loose debris (rags, trash, clothing, etc.) is

present in the containment which could be transported to the containment sump and cause restriction of the pump suctions during LOCA conditions.24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> ECCS - Pump Line Flow RatesTR 13.5.32CPSES - UNITS 1 AND 2 - TRM13.5-3Revision 56 13.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

TR 13.5.32 ECCS - Pump Line Flow RatesTR LCO 13.5.32Pursuant to TS 3.5.2 and 3.5.3, the pump lines for the ECCS train(s) required to be OPERABLE shall have the required flow rates.APPLICABILITY:MODES 1, 2, 3 and 4.

ACTIONSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Pump lines for the ECCS train(s) required to be OPERABLE do not meet required flow rates.A.1Enter the applicable Condition(s) of TS 3.5.2 and 3.5.3 for affected ECCS train(s) inoperable.Immediately ECCS - Pump Line Flow RatesTR 13.5.32CPSES - UNITS 1 AND 2 - TRM13.5-4Revision 56 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.5.32.1Performing a flow balance test, during shutdown, and verify that:a.For centrifugal charging pump lines, with a single pump running:1.The sum of the injection line flow rates, excluding the highest flow rate, is 245 gpm, and 2.The total pump flow rate is 560 gpm.b.For safety injection pump lines, with a single pump running:1.The sum of the cold leg injection line flow rates, excluding the highest flow

rate, is 400 gpm, and 2.The total pump flow rate is 675 gpm. c.For RHR pump lines, with a single pump running, the sum of the cold leg injection line flow rates is 4652 gpm.

Once following completion of modifications to the ECCS subsystems that alter the subsystem flow characteristics.

Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-1Revision 70 13.6 CONTAINMENT SYSTEMSTR 13.6.3 Containment Isolation ValvesThis Technical Requirement contains the listing of Containment Isolation Valves subject to CPSES Technical Specification 3.6.3. Commensurate with Technical Specification Surveillance Requirement SR 3.6.3.5 , Table 13.6.3-1 also contains the isolation time limit for each automatic power operated containment isolation valve.

Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-2Revision 70Table 13.6.3-1 (Page 1 of 12)Containment Isolation ValvesVALVE NO.FSAR TABLE REFERENCE NO.*LINE OR SERVICEMAXIMUM ISOLATION TIME (SECONDS)NOTES AND LEAK TEST REQUIREMENTS1. Phase "A" Isolation ValvesHV-215420Feedwater Sample (FW to Stm Gen #1)5N.A., Note 9HV-215522Feedwater Sample (FW to Stm Gen #2)5N.A., Note 9HV-239927Blowdown From Steam Generator #35N.A.HV-239828Blowdown From Steam Generator #25N.A.HV-239729Blowdown From Steam Generator #15N.A.

HV-240030Blowdown From Steam Generator #45N.A8152 32Letdow Line to Letdown Heat Exchanger10C8160 32Letdow Line to Letdown Heat Exchanger10C 8890A35RHR to Cold Leg Loops #1 & #2 Test Line15N.A.8890B36RHR to Cold Leg Loops #3 & #4 Test Line15N.A.804741Reactor Makeup Water to Pressure Relief Tank & RC Pump Stand Pipe10C884342SI to RC System Cold Leg Loops #1, #2, #3, & #4 Test Line10N.A.888143SI to RC System Hot Leg Loops #2 & #3 Test Line10N.A.882444SI to RC System Hot Leg Loops #1 & #4 Test Line10N.A.882345SI to RC System Cold Leg Loops #1, #2, #3, & #4 Test Line10N.A.810051Seal Water Return and Excess Letdown10C811251Seal Water Return and Excess Letdown10C 713652RCDT Heat Exchanger to Waste Hold up Tank10CLCV-100352RCDT Heat Exchanger to Waste Hold up Tank10CHV-536560Demineralized Water Supply10C HV-536660Demineralized Water Supply10CHV-515761Containment Sump Pump Discharge5CHV-515861Containment Sump Pump5C Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-3Revision 70Table 13.6.3-1 (Page 2 of 12)Containment Isolation ValvesVALVE NO.FSAR TABLE REFERENCE NO.*LINE OR SERVICEMAXIMUM ISOLATION TIME (SECONDS)NOTES AND LEAK TEST REQUIREMENTS HV-348762Instrument Air to Containment5C882563RHR to Hot Leg Loops #2 & #3 Test Line15N.A.HV-240573Sample from Steam Generator #15N.A.

HV-417074RC Sample from Hot Legs5CHV-416874RC Sample from Hot Leg #15CHV-416974RC Sample from Hot Leg #45C HV-240676Sample from Steam Generator #25N.A.HV-416777Pressurizer Liquid Space Sample5CHV-416677Pressurizer Liquid Space Sample5CHV-417678Pressurizer Steam Space Sample5CHV-416578Pressurizer Steam Space Sample5CHV-240779Sample from Steam Generator #35N.A.

HV-417580Accumulators5CHV-417180Sample From Accumulator #15CHV-417280Sample From Accumulator #25C HV-417380Sample From Accumulator #35CHV-417480Sample From Accumulator #45CHV-731181RC PASS Sample Discharge to RCDT5C HV-731281RC PASS Sample Discharge to RCDT5CHV-240882Sample from Steam Generator #45N.A.887183Accumulator Test and Fill10C 888883Accumulator Test and Fill10C896483Accumulator Test and Fill10CHV-555684Containment Air PASS Return5CHV-555784Containment Air PASS Return5CHV-554494Radiation Monitoring Sample5CHV-554594Radiation Monitoring Sample5C Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-4Revision 70HV-555897Containment Air PASS Inlet5CHV-555997Containment Air PASS Inlet5CHV-5560100Containment Air PASS Inlet5CHV-5561100Containment Air PASS Inlet5C HV-5546102Radiation Monitoring Sample Return5CHV-5547102Radiation Monitoring Sample Return5C8880104N 2 Supply to Accumulators10C7126105H 2 Supply to RC Drain Tank10C7150105H 2 Supply to RC Drain Tank10CHV-4710111CCW Supply to Excess Letdown & RC Drain Tank Heat Exchanger5N.A.HV-4711112CCW Return to Excess Letdown & RC Drain Tank Heat Exchanger5N.A.HV-3486113Service Air to Containment5CHV-4725114Containment CCW Drain Tank Pumps Discharge10CHV-4726114Containment CCW Drain Tank Pumps Discharge10C8027116Nitrogen Supply to PRT10C 8026116Nitrogen Supply to PRT10CHV-6084120Chilled Water Supply to Containment Coolers15CHV-6082121Chilled Water Return to Containment Coolers15C HV-6083121Chilled Water Return to Containment Coolers15CHV-4075B124Fire Protection System Isolation10CHV-4075C124Fire Protection System Isolation10C

2. Phase "B" Isolation ValvesHV-4708117CCW Return From RCP"s Motors30CHV-4701117CCW Return From RCP"s Motors30C HV-4700118CCW Supply To RCP"s Motors30CTable 13.6.3-1 (Page 2 of 12)Containment Isolation ValvesVALVE NO.FSAR TABLE REFERENCE NO.*LINE OR SERVICEMAXIMUM ISOLATION TIME (SECONDS)NOTES AND LEAK TEST REQUIREMENTS Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-5Revision 70HV-4709119CCW Return From RCP"s Thermal Barrier15CHV-4696119CCW Return From RCP"s Thermal Barrier15C3. Containment Ventilation Isolation ValvesHV-554258Hydrogen Purge SupplyN.A.C HV-554358Hydrogen Purge SupplyN.A.CHV-556358Hydrogen Purge SupplyN.A.CHV-554059Hydrogen Purge ExhaustN.A.C HV-554159Hydrogen Purge ExhaustN.A.CHV-556259Hydrogen Purge ExhaustN.A.CHV-5536109Containment Purge Air SupplyN.A.C HV-5537109Containment Purge Air SupplyN.A.CHV-5538110Containment Purge Air ExhaustN.A.CHV-5539110Containment Purge Air ExhaustN.A.C HV-5548122Containment Pressure Relief5CNote 8HV-5549122Containment Pressure Relief5CNote 84. Manual ValvesMS-711#4aTDAFW Pump Bypass Warm-up ValveN.A.N.A.

MS-3905aN 2 Supply to Steam Generator #1N.A.N.A.MS-3879aN 2 Supply to Steam Generator #2N.A.N.A.MS-38413aN 2 Supply to Steam Generator #3N.A.N.A.MS-712#17aTDAFW Pump Bypass Warm-up ValveN.A.N.A.MS-39318aN 2 Supply to Steam Generator #4N.A.N.A.FW-11620Feedwater Sample (FW to Stm Gen #1)N.A.N.A., Note 9FW-11322Feedwater Sample (FW to Stm Gen #2)N.A.N.A., Note 9FW-10620bN 2 Supply to Steam Generator #1N.A.N.A. Table 13.6.3-1 (Page 2 of 12)Containment Isolation ValvesVALVE NO.FSAR TABLE REFERENCE NO.*LINE OR SERVICEMAXIMUM ISOLATION TIME (SECONDS)NOTES AND LEAK TEST REQUIREMENTS Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-6Revision 70FW-10422bN 2 Supply to Steam Generator #2N.A.N.A. FW-10224bN 2 Supply to Steam Generator #3N.A.N.A.FW-108 26bN 2 Supply to Steam Generator #4N.A.N.A.7135#52RCDT Heat Exchanger to Waste Holdup TankN.A.CMS-1014TDAFWP Steam SupplyN.A.N.A.MS-12817TDAFWP Steam SupplyN.A.N.A.

SF-01156Refueling Water Purification to Refueling CavityN.A.CSF-01256Refueling Water Purification to Refueling CavityN.A.CSF-02167 Refueling Cavity to Refueling Water PurificationN.A.CSF-02267 Refueling Cavity to Refueling Water PurificationN.A.C1SF-0532SF-005571Refueling Cavity Skimmer Pump DischargeN.A.C1SF-0542SF-005671Refueling Cavity Skimmer Pump DischargeN.A.CSI-8961#83Accumulator Test and FillN.A.N.A.HV-2333B#2MSIV Bypass from Steam Generator #1N.A.Note 1HV-2334B#7MSIV Bypass from Steam Generator #2N.A.Note 1 HV-2335B#11MSIV Bypass from Steam Generator #3N.A.Note 1HV-2336B#15MSIV Bypass from Steam Generator #4N.A.Note 11BS-0016#130Airlock Hydraulic SystemN.A.N.A.

1BS-0017#130Airlock Hydraulic SystemN.A.N.A.1BS-0030#131Airlock Hydraulically Operated EqualizationN.A.Notes 5, 6, 71BS-0025#131Airlock Hydraulically Operated EqualizationN.A.Notes 5, 6, 7 1BS-0056#131aAirlock Manual EqualizationN.A.Notes 5, 61BS-0044#131aAirlock Manual EqualizationN.A.Notes 5, 61BS-0029#131aAirlock Manual EqualizationN.A.Notes 5, 6 1BS-0015#131aAirlock Manual EqualizationN.A.Notes 5, 6Table 13.6.3-1 (Page 2 of 12)Containment Isolation ValvesVALVE NO.FSAR TABLE REFERENCE NO.*LINE OR SERVICEMAXIMUM ISOLATION TIME (SECONDS)NOTES AND LEAK TEST REQUIREMENTS Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-7Revision 70BS-0202#132Airlock Manual EqualizationN.A.Notes 5, 6, 7BS-0203#132Airlock Manual EqualizationN.A.Notes 5, 6, 72BS-0016#133Airlock Hydraulic SystemN.A.Notes 5, 62BS-0017#133Airlock Hydraulic SystemN.A.Notes 5, 6 2BS-0039#133Airlock Hydraulic SystemN.A.Notes 5, 62BS-0040#133Airlock Hydraulic SystemN.A.Notes 5, 62BS-0030#134Airlock Hydraulically Operated EqualizationN.A.Notes 5, 6, 7 2BS-0025#134Airlock Hydraulically Operated EqualizationN.A.Notes 5, 6, 72BS-0056#134aAirlock Manual EqualizationN.A.Notes 5, 62BS-0044#134aAirlock Manual EqualizationN.A.Notes 5, 62BS-0029#134aAirlock Manual EqualizationN.A.Notes 5, 62BS-0015#134aAirlock Manual EqualizationN.A.Notes 5, 65. Power-Operated Isolation Valves HV-2452-14Main Steam to Aux. FPT From Steam Line # 4N.A.N.APV-23255Atmospheric Relief Steam GeneratorN.A.Note 3PV-23269Atmospheric Relief Steam GeneratorN.A.Note 3 PV-232713Atmospheric Relief Steam GeneratorN.A.Note 3HV-2452-217Main Steam to Aux. FPT From Steam Line # 1N.A.N.A.PV-232818Atmospheric Relief Steam GeneratorN.A.Note 3 HV-2491A20aAuxiliary Feedwater to Steam Generator #1N.A.N.A.HV-2491B20aAuxiliary Feedwater to Steam Generator #1N.A.N.A.HV-2492A22aAuxiliary Feedwater to Steam Generator #2N.A.N.A.

HV-2492B22aAuxiliary Feedwater to Steam Generator #2N.A.N.A.HV-2493A24aAuxiliary Feedwater to Steam Generator #3N.A.N.A.HV-2493B24aAuxiliary Feedwater to Steam Generator #3N.A.N.A.HV-2494A26aAuxiliary Feedwater to Steam Generator #4N.A.N.A.HV-2494B26aAuxiliary Feedwater to Steam Generator #4N.A.N.A.Table 13.6.3-1 (Page 2 of 12)Containment Isolation ValvesVALVE NO.FSAR TABLE REFERENCE NO.*LINE OR SERVICEMAXIMUM ISOLATION TIME (SECONDS)NOTES AND LEAK TEST REQUIREMENTS Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-8Revision 708701B33RHR From Hot Leg Loop #4N.A.N.A.8701A34RHR From Hot Leg Loop #1N.A.N.A.8809A35RHR From Cold Leg Loops #1 and #2N.A.N.A.8809B36RHR From Cold Leg Loops #3 and #4N.A.N.A.

8801A42Safety Injection to Cold Leg Loops #1, #2, #3, and #4N.A.N.A.8801B42Safety Injection to Cold Leg Loops #1, #2, #3, and #4N.A.N.A.8802A43SI Injection to RCS Hot Leg Loops #2 and #3N.A.N.A.

8802B44SI Injection to RCS Hot Leg Loops #1 and #4N.A.N.A.883545SI Injection to RCS Cold Leg Loops #1, #2, #3, and #4N.A.N.A.8351A47Seal Injection to RC Pump (Loop #1)N.A.N.A.

8351B48Seal Injection to RC Pump (Loop #2)N.A.N.A.8351C49Seal Injection to RC Pump (Loop #3)N.A.N.A.8351D50Seal Injection to RC Pump (Loop #4)N.A.N.A.

HV-477754Containment Spray to Spray Header (Train B)N.A.N.A.HV-477655Containment Spray to Spray Header (Train A)N.A.N.A.884063RHR to Hot Leg Loops #2 and #3N.A.N.A.

8811A125Containment Recirc. Sump to RHR Pumps (Train A)N.A.N.A.8811B126Containment Recirc. Sump to RHR Pumps (Train B)N.A.N.A.HV-4782127Containment Recirc. to Spray Pumps (Train A)N.A.N.A.

HV-4783128Containment Recirc. to Spray Pumps (Train B)N.A.N.A.

6. Check Valves8818A35RHR to Cold Leg Loop #1N.A.N.A.

8818B35RHR to Cold Leg Loop #2N.A.N.A.8818C36RHR to Cold Leg Loop #3N.A.N.A.8818D36RHR to Cold Leg Loop #4N.A.N.A.804641Reactor Makeup Water to Pressurizer Relief Tank and RC Pump Stand PipeN.A.CTable 13.6.3-1 (Page 2 of 12)Containment Isolation ValvesVALVE NO.FSAR TABLE REFERENCE NO.*LINE OR SERVICEMAXIMUM ISOLATION TIME (SECONDS)NOTES AND LEAK TEST REQUIREMENTS Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-9Revision 70881542High Head Safety Injection to Cold Leg Loops #1, #2, #3, and #4N.A.N.A.SI-8905B43SI to RC System Hot Leg Loop #2N.A.N.A.SI-8905C43SI to RC System Hot Leg Loop #3N.A.N.A.

SI-8905A44SI to RC System Hot Leg Loop #1N.A.N.A.SI-8905D44SI to RC System Hot Leg Loop #4N.A.N.A.SI-8819A45SI to RC System Cold Leg Loop #1N.A.N.A.SI-8819B45SI to RC System Cold Leg Loop #2N.A.N.A.SI-8819C45SI to RC System Cold Leg Loop #3N.A.N.A.SI-8819D45SI to RC System Cold Leg Loop #4N.A.N.A.

838146Charging Line to Regenerative Heat ExchangerN.A.CCS-8368A47Seal Injection to RC Pump (Loop #1)N.A.N.A.CS-8368B48Seal Injection to RC Pump (Loop #2)N.A.N.A.

CS-8368C49Seal Injection to RC Pump (Loop #3)N.A.N.A.CS-8368D50Seal Injection to RC Pump (Loop #4)N.A.N.A.CS-818051Seal Water Return and Excess LetdownN.A.C CT-14554Containment Spray to Spray Header (Tr. B)N.A.N.A.CT-14255Containment Spray to Spray Header (Tr. A)N.A.N.A. CI-03062Instrument Air to ContainmentN.A.C 8841A63RHR to Hot Leg Loop #2N.A.N.A.8841B63RHR to Hot Leg Loop #3N.A.N.A.SI-8968104N 2 Supply to AccumulatorsN.A.CCA-016113Service Air to ContainmentN.A.CCC-629117CC Return From RCP"s MotorsN.A.CCC-713118CC Supply to RCP"s MotorsN.A.CCC-831119CC Return From RCP"s Thermal BarrierN.A.C CH-024120Chilled Water Supply to Containment CoolersN.A.CTable 13.6.3-1 (Page 2 of 12)Containment Isolation ValvesVALVE NO.FSAR TABLE REFERENCE NO.*LINE OR SERVICEMAXIMUM ISOLATION TIME (SECONDS)NOTES AND LEAK TEST REQUIREMENTS Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-10Revision 707. Steam Line Isolation SignalHV-2333A1Main Steam From Steam Generator #15Notes 2 & 3HV-24093Drain From Main Steam Line #15N.A.HV-2334A6Main Steam From Steam Generator #25Notes 2 & 3 HV-24108Drain From Main Steam Line #25N.A.HV-2335A10Main Steam From Steam Generator #35Notes 2 & 3HV-241112Drain From Main Steam Line #35N.A.

HV-2336A14Main Steam From Steam Generator #45Notes 2 & 3HV-241216Drain From Main Steam Line #45N.A.8. Feedwater Isolation Signal HV-213419Feedwater to Steam Generator #15Note 32-FV-219320cFeedwater Preheat Bypass Line S.G. #15Note 3HV- 218520dFeedwater Bypass Line S.G #15Note 3 HV-213521Feedwater to Steam Generator #25Note 32-FV-219422cFeedwater Preheat Bypass Line S.G. #25Note 3HV-218622dFeedwater Bypass Line S.G #25Note 3 HV-213623Feedwater to Steam Generator #35Note 32-FV-219524cFeedwater Preheat Bypass Line S.G. #35Note 3HV-218724dFeedwater Bypass Line S.G #35Note 3 HV-213725Feedwater to Steam Generator #45Note 32-FV-219626cFeedwater Preheat Bypass Line S.G. #45Note 3HV-218826dFeedwater Bypass Line S.G #45Note 3

9. Safety Injection Actuation Isolation810546Charging Line to Regenerative Heat Exchanger10C10. Relief Valves8708B33RHR From Hot Leg Loop #4N.A.N.A.8708A34RHR From Hot Leg Loop #1N.A.N.A.Table 13.6.3-1 (Page 2 of 12)Containment Isolation ValvesVALVE NO.FSAR TABLE REFERENCE NO.*LINE OR SERVICEMAXIMUM ISOLATION TIME (SECONDS)NOTES AND LEAK TEST REQUIREMENTS Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-11Revision 70MS-0215bMain Steam Safety Valve S.G. #1N.A.Note 3MS-0225bMain Steam Safety Valve S.G. #1N.A.Note 3MS-0235bMain Steam Safety Valve S.G. #1N.A.Note 3MS-0245bMain Steam Safety Valve S.G. #1N.A.Note 3 MS-0255bMain Steam Safety Valve S.G. #1N.A.Note 3MS-0589bMain Steam Safety Valve S.G. #2N.A.Note 3MS-0599bMain Steam Safety Valve S.G. #2N.A.Note 3 MS-0609bMain Steam Safety Valve S.G. #2N.A.Note 3MS-0619bMain Steam Safety Valve S.G. #2N.A.Note 3MS-0629bMain Steam Safety Valve S.G. #2N.A.Note 3 MS-09313bMain Steam Safety Valve S.G. #3N.A.Note 3MS-09413bMain Steam Safety Valve S.G. #3N.A.Note 3MS-09513bMain Steam Safety Valve S.G. #3N.A.Note 3 MS-09613bMain Steam Safety Valve S.G. #3N.A.Note 3MS-09713bMain Steam Safety Valve S.G. #3N.A.Note 3MS-12918bMain Steam Safety Valve S.G. #4N.A.Note 3 MS-13018bMain Steam Safety Valve S.G. #4N.A.Note 3MS-13118bMain Steam Safety Valve S.G. #4N.A.Note 3MS-13218bMain Steam Safety Valve S.G. #4N.A.Note 3 MS-13318bMain Steam Safety Valve S.G. #4N.A.Note 3RC-03641aPenetration Thermal ReliefN.A.CWP-717652aPenetration Thermal ReliefN.A.C DD-43060aPenetration Thermal ReliefN.A.C1VD-9072VD-89661aPenetration Thermal ReliefN.A.CPS-50374aPenetration Thermal ReliefN.A.CPS-50177aPenetration Thermal ReliefN.A.CTable 13.6.3-1 (Page 2 of 12)Containment Isolation ValvesVALVE NO.FSAR TABLE REFERENCE NO.*LINE OR SERVICEMAXIMUM ISOLATION TIME (SECONDS)NOTES AND LEAK TEST REQUIREMENTS Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-12Revision 70PS-50278aPenetration Thermal ReliefN.A.CPS-50080aPenetration Thermal ReliefN.A.CWP-717781aPenetration Thermal ReliefN.A.C1SI-89722SI-898383aPenetration Thermal ReliefN.A.C1CC-10672CC-1090114aPenetration Thermal ReliefN.A.C1CH-02712CH-0281120aPenetration Thermal ReliefN.A.C1CH-02722CH-0282121aPenetration Thermal ReliefN.A.CSI-0182125Pressure Relief for Bonnet of MOV 8811AN.A.N.A.SI-0183126Pressure Relief for Bonnet of MOV 8811BN.A.N.A.

CT-0309127Pressure Relief for Bonnet of MOV HV-4782N.A.N.A.CT-0310128Pressure Relief for Bonnet of MOV HV-4783N.A.N.A.Table 13.6.3-1 (Page 2 of 12)Containment Isolation ValvesVALVE NO.FSAR TABLE REFERENCE NO.*LINE OR SERVICEMAXIMUM ISOLATION TIME (SECONDS)NOTES AND LEAK TEST REQUIREMENTS Containment Isolation ValvesTR 13.6.3CPSES - UNITS 1 AND 2 - TRM13.6-13Revision 70Table 13.6.3-1 (Page 12 of 12)Containment Isolation ValvesVALVE NO.FSAR TABLE REFERENCE NO.*LINE OR SERVICE MAXIMUM ISOLATION TIME (SECONDS)NOTES AND LEAK TEST REQUIREMENTSTable Notations*Identification code for containment penetration and associated isolation valves in FSAR Tables 6.2.4-1

, 6.2.4-2 , and 6.2.4-3.#May be opened on an intermittent basis under administrative control.The table does not list local vent, drain and test connections as they are a special class of containment isolation valves and are locked closed to meet containment isolation criteria when located within the penetration boundary. These valves are subject to the same leak rate testing as the other containment isolation valves in the associated penetration, including all applicable leak testing exceptions (see FSAR table 6.2.4-2, including notes). In addition, if these valves are capped (or isolated by blind flange) and under administrative controls they are not required to be leak rate tested. Airlock test connection isolation valves are part of the airlock boundary; therefore, they are subject to the controls of Specification 3.6.2. As such, the requirements of Spec ification 3.6.3 do not apply.Note 1:All four MSIV bypass valves are locked closed in Mode 1. During Mode 2, 3, and 4 one MSIV bypass valve may be opened provided the other three MSIV bypass valves are locked closed and their associated MSIVs are closed.Note 2:These valves require steam to be tested and are thus not required to be tested until the plant is in MODE 3.Note 3:These valves are included for table completeness; the requirements of Specification 3.6.3 do not apply. Instead, the requirements of Specification 3.7.1 , 3.7.2 , 3.7.3 and 3.7.4 apply for main steam safety valves, main steam isolation valves, feedwater isolation valves and steam generator atmospheric relief valves, respectively.Note 4:Not used.

Note 5:10 CFR 50 Appendix J, Type C testing of these valves is satisfied by the testing of the airlock under Technical Specification Surveillance Requirement 3.6.2.1

.Note 6:These valves are included for table completeness; the requirements of Specification 3.6.3 do not apply. Instead, these valves are considered an integral part of the airlock associated with their respective airlock door. Therefore, they are subject to the controls of Specification 3.6.2

.Note 7:These valves are secured in position by hydraulic system locks and/or interlocks and do not require separate locks.Note 8:Including the instrumentation delays of the containment ventilation isolation signal from Pressurizer Pressure Low.Note 9:Upon implementation of FDA-1999-000382-01-00 and acceptance, (1) the requirements for valves HV-2154 and HV-2155 are no longer valid and (2) the requirements for valves FW-113 and FW-116 become effective.

Containment Spray SystemTR 13.6.6CPSES - UNITS 1 AND 2 - TRM13.6-14Revision 70 13.6 CONTAINMENT SYSTEMSTR 13.6.6 Containment Spray SystemThe performance test requirements for the Containment Spray System pumps subject to SR 3.6.6.4 is as follows:In the test mode each Containment Spray pump is required to provide a total discharge flow through the test header of greater than or equal to 3300 gpm at 245 psid with the pump eductor

line open.

Spray Additive System TR 13.6.7CPSES - UNITS 1 AND 2 - TRM13.6-15Revision 70 13.6 CONTAINMENT SYSTEMS TR 13.6.7 Spray Additive System This Technical Requirement contains the detailed technical requirements for verifying equilibrium Containment emergency sump pH commensurate with Technical Specification (TS) Surveillance Requirement SR 3.6.7.1. ACTIONS for not verifying equilibrium Containment emergency sump pH is contained in Technical Specification 3.6.7. The performance test requirements for the Spray Additive System subject to TS SR 3.6.7.1 are as follows:

SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.6.7.1Verify each spray additive manual, power operated, and automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position.31 days TRS 13.6.7.2Verify spray additive tank solution level is > 91% and

< 94%.184 days TRS 13.6.7.3Verify spray additive tank NaOH solution concentration is > 28% and <

30% by weight.184 days TRS 13.6.7.4 Verify each spray additive automatic valve in the flow path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

18 months TRS 13.6.7.5Verify spray additive flow from each solution's flow path.5 years MSIVsTR 13.7.2CPSES - UNITS 1 AND 2 - TRM13.7-1Revision 83 13.7 PLANT SYSTEMSTR 13.7.2 Main Steam Isolation Valves (MSIVs)----------------------------------------------NOTE---------------------------------------------

This Technical Requirement contains a listing of the MSIVs subject to

Technical specification SR 3.7.2.1.---------------------------------------------------------------------------------------------------Table 13.7.2-1 Main Steam Isolation ValvesVALVE NUMBERISOLATION TIME (SECONDS)HV-2333A 5HV-2334A 5HV-2335A 5HV-2336A 5 FIVs and FCVs and Associated Bypass ValvesTR 13.7.3CPSES - UNITS 1 AND 2 - TRM13.7-2Revision 83 13.7 PLANT SYSTEMSTR 13.7.3 Feedwater Isolation Valves (FIVs) and Feedwater Control Valves (FCVs) and Associated Bypass Valves----------------------------------------------NOTE---------------------------------------------

This Technical Requirement contains a listing of the FIVs, FCVs, and Associated Bypass Valves subject to Technical Specification SR 3.7.3.1.---------------------------------------------------------------------------------------------------Table 13.7.3-1Feedwater Isolation Valves and Feedwater Control Valves and Associated Bypass ValvesVALVE NUMBERISOLATION TIME (SECONDS)HV-2134 HV-2135HV-2136 HV-2137HV-2185HV-2186 HV-2187HV-2188FCV-0510 FCV-0520FCV-0530FCV-0540LV-2162LV-2163LV-2164 LV-2165 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 5 ARV - Air Accumulator TankTR 13.7.4CPSES - UNITS 1 AND 2 - TRM13.7-3Revision 83 TR 13.7.4 PLANT SYSTEMSTR 13.7.31 Steam Generator Atmospheric Relief Valve (ARV) - Air Accumulator Tank TR LCO 13.7.31Pursuant to TS 3.7.4, the air accumulator tank for each ARV required to be OPERABLE shall be at a pressure greater than or equal to 80 psig.APPLICABILITY:MODES 1, 2, and 3.

ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Air accumulator tank(s) pressure not within limits.A.1Enter the applicable Condition(s) of TS 3.7.4 for affected ARV(s) inoperable.ImmediatelySURVEILLANCEFREQUENCY TRS 13.7.31.1Verify that the air accumulator tank pressure is within limits. 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Steam Generator Pressure / Temperature Limitation TR 13.7.32CPSES - UNITS 1 AND 2 - TRM13.7-4Revision 83 13.7 PLANT SYSTEMS TR 13.7.32 Steam Generator Pressure / Temperature LimitationTR LCO 13.7.32The temperatures of both the primary and secondary coolants in the steam generators shall be greater than 70°F when the pressure of either coolant in the steam generator is greater than 200 psig.APPLICABILITY:At all times.

ACTIONSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Pressure / Temperature Limitations not met. A.1Reduce the steam generator pressure of the applicable sides to less than or equal to 200 psig.

ANDA.2Perform an engineering evaluation to determine the effect of the overpressurization on the structural integrity of the steam generator. Determine that the steam generator remains

acceptable for continued operation.

30 minutesPrior to increasing steam generator coolant temperatures above 200°F Steam Generator Pressure / Temperature Limitation TR 13.7.32CPSES - UNITS 1 AND 2 - TRM13.7-5Revision 83 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.7.32.1 TRS 13.7.32.2--------------------------------------------------------------------------- NOTE -Not required to be performed for the associated steam

generator when the temperature of both the primary and secondary coolant is > 70 degrees F, or both the primary and secondary coolants are vented and no --------------------------------------------------------------------------longer capable of being pressurized.Verify that the pressure in each side of the steam generator is less than 200 psig.--------------------------------------------------------------------------- NOTE -Only Required when vent paths for the associated --------------------------------------------------------------------------steam generator are being used to meet the LCO.Verify the primary and secondary vent paths are established for the associated steam generator.

1 hour24 hours Ultimate Heat Sink - Sediment and SSI Dam TR 13.7.33CPSES - UNITS 1 AND 2 - TRM13.7-6Revision 83 13.7 PLANT SYSTEMSTR 13.7.33 Ultimate Heat Sink - Sediment and Safe Shutdown Impoundment (SSI) DamTR LCO 13.7.33The average sediment depth shall be less than or equal to 1.5 feet in the service water intake channel and the SSI dam shall exhibit no abnormal degradation or erosion.APPLICABILITY:MODES 1, 2, 3, and 4.

ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.With the average sediment depth in the service water intake channel greater than

1.5 feet.A.1Initiate action in accordance with the Corrective Action Program to remove sediment from the service water intake channel.ImmediatelyB.The SSI dam has abnormal degradation or erosion.B.1Enter the applicable Condition(s) of TS 3.7.9 for SSI inoperable due to a degraded dam.ImmediatelySURVEILLANCEFREQUENCY TRS 13.7.33.1Visually inspect the SSI dam and verify no abnormal degradation or erosion.

12 months TRS 13.7.33.2Verify that the average sediment depth in the service water intake channel is less than or equal to 1.5 feet.

12 months Flood Protection TR 13.7.34CPSES - UNITS 1 AND 2 - TRM13.7-7Revision 83 13.7 PLANT SYSTEMSTR 13.7.34 Flood ProtectionTR LCO 13.7.34Flood protection shall be provided for all safety-related systems, components, and structures when the water level of the Squaw Creek Reservoir (SCR) exceeds 777.5 feet.----------------------------------------------------------------------------------------------------- NOTE -All elevations and SCR water levels in this specification are expressed in ----------------------------------------------------------------------------------------------------feet Mean Sea Level, USGS datum.APPLICABILITY:At all times.

ACTIONSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.------------------------------------ - NOTE -Only applicable in MODES1, 2, 3 and 4.------------------------------------

Required flood protection measure(s) not in place.A.1Initiate action to place the unit in a lower MODE.

ANDA.2Be in MODE 3.

ANDA.3Be in MODE 4.

ANDA.4Be in MODE 5.

1 hours1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 7 hours13 hour1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />s37 hours Flood Protection TR 13.7.34CPSES - UNITS 1 AND 2 - TRM13.7-8Revision 83 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.7.34.1--------------------------------------------------------------------------- NOTE -Only required to be performed when SCR water level is --------------------------------------------------------------------------< 776 feet.Verify the water level of SCR is measured to be within the limits. 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> TRS 13.7.34.2--------------------------------------------------------------------------- NOTE -Only required to be performed when SCR water level is --------------------------------------------------------------------------776 feet.Verify the water level of SCR is measured to be within the limits.

2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> TRS 13.7.34.3--------------------------------------------------------------------------- NOTE -Only required to be performed when SCR water level is --------------------------------------------------------------------------> 777.0 feet.Verify flood protection measures are in effect by verifying that flow paths from the SCR which are open for maintenance are isolated from the SCR by isolation valves, or stop gates, or are at an elevation above 790feet. 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />(continued)

Flood Protection TR 13.7.34 SURVEILLANCE REQUIREMENTS (continued)CPSES - UNITS 1 AND 2 - TRM13.7-9Revision 83 SURVEILLANCEFREQUENCY TRS 13.7.34.4--------------------------------------------------------------------------- NOTE -Only required to be performed when SCR water level is --------------------------------------------------------------------------> 777.5 feet.Verify flood protection measures are in effect by verifying that any equipment which is to be opened or is open for maintenance is isolated from the SCR by

isolation valves, or stop gates, or is at an elevation above 790 feet. Once within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> after SCR water level > 777.5 feet ANDPrior to opening any equipment for maintenance Snubbers TR 13.7.35CPSES - UNITS 1 AND 2 - TRM13.7-10Revision 83 13.7 PLANT SYSTEMSTR 13.7.35 SnubbersTR LCO 13.7.35All snubbers shall be OPERABLE. The only snubbers excluded from the requirements are (1) those installed on nonsafety-related systems and then only if their failure or failure of the system on which they are installed would have no adverse effect on any safety-related system or (2) those snubber(s) that have an evaluation which determines that the supported TS system(s) do not require the snubber(s) to be functional in order to support

the OPERABILITY of the system(s).APPLICABILITY:MODES 1, 2, 3, and 4. MODES 5 and 6 for snubbers located on systems required OPERABLE in those MODES.----------------------------------------------------------------------------------------------------- NOTE -While this LCO is not met, MODE changes shall be restricted to those MODE changes allowed by the applicable LCO's for the equipment which ----------------------------------------------------------------------------------------------------may be potentially inoperable as a result of the inoperable snubber(s).

ACTIONS-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------Separate Condition entry allowed for each snubber.CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One or more snubbers inoperable.A.1Enter the operability determination process for attached system(s).

ANDA.2Perform an engineering evaluation in accordance with the approved snubber augmented inservice inspection program on the attached component.Immediately72 hours (continued)

Snubbers TR 13.7.35CPSES - UNITS 1 AND 2 - TRM13.7-11Revision 83 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.7.35.1Each required snubber shall be demonstrated OPERABLE by performance of the requirements of the approved snubber inservice testing/inspection program in TR 15.5.31

.Per snubber inservice testing/

inspection program.

Area Temperature Monitoring TR 13.7.36CPSES - UNITS 1 AND 2 - TRM13.7-12Revision 83 13.7 PLANT SYSTEMSTR 13.7.36 Area Temperature MonitoringTR LCO 13.7.36The maximum temperature limit for normal conditions of each area shown in Table 13.7.36-1 shall not be exceeded for more than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and the maximum temperature limit for abnormal conditions of each area given in Table 13.7.36-1 shall not be exceeded.APPLICABILITY:Whenever the equipment in an affected area is required to be OPERABLE.----------------------------------------------------------------------------------------------------- NOTE -While this LCO is not met due to exceeding the maximum temperature limit for abnormal conditions, MODE changes shall be restricted to those allowed by the applicable LCOs for the equipment which may be potentially ----------------------------------------------------------------------------------------------------

inoperable due to exceeding the limit for abnormal conditions.

ACTIONS-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------Separate condition entry is allowed for each area listed in Table 13.7.36-1

.CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One or more areas exceeds the maximum temperature limit(s) for normal conditions shown in Table13.7.36-1 for more than 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. ---------------------------------------------------- NOTE -Required Action must be completed ---------------------------------------------------whenever Condition A is entered.A.1Initiate action in accordance with the Corrective Action Program to restore the temperature(s) to within normal limits, including an analysis to demonstrate the

continued OPERABILITY of the affected equipment.Immediately (continued)

Area Temperature Monitoring TR 13.7.36 ACTIONS (continued)CPSES - UNITS 1 AND 2 - TRM13.7-13Revision 83 SURVEILLANCE REQUIREMENTSB.One or more areas exceeds the maximum temperature limit(s) for abnormal conditions shown in Table13.7.36-1

.B.1.1Restore the area(s) to within the maximum temperature limit(s) for abnormal conditions.

ORB.1.2.1Enter the appropriate Condition(s) of the appropriate TS(s) for the equipment in the affected area(s) inoperable. ORB.1.2.2.1Perform a review of the qualification envelope for the affected equipment. ANDB.1.2.2.2Declare INOPERABLE any affected equipment in a

qualification envelope that has been exceeded.

ORB.1.3Perform an analysis that justifies continued operation.

4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 4 hours 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> 4 hours 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />sSURVEILLANCEFREQUENCY TRS 13.7.36.1 Verify the temperature in each of the areas shown in Table 13.7.36-1 to be within limit(s). 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Area Temperature Monitoring TR 13.7.36CPSES - UNITS 1 AND 2 - TRM13.7-14Revision 83 Table 13.7.36-1Area Temperature MonitoringAREAMAXIMUMTEMPERATURE LIMIT (°F)NORMAL CONDITIONS ABNORMAL CONDITIONS1.Electrical and Control BuildingNormal Areas104131Control Room Main Level (El. 830'-0")80104Control Room Technical Support Area (El. 840'-6")104104UPS/Battery Rooms104113Chiller Equipment Areas1221312.Fuel BuildingNormal Areas104131Spent Fuel Pool Cooling Pump Rooms1221313.Safeguards Buildings Normal Areas104131 AFW, RHR, SI, Containment Spray Pump Rooms122131RHR Valve and Valve Isolation Tank Rooms122131 RHR/CT Heat Exchanger Rooms122131Diesel Generator Area122131Diesel Generator Equipment Rooms130131Day Tank Room1221314.Auxiliary Building127131Normal Areas104131CCW, CCP Pump Rooms122131CCW Heat Exchanger Area122131CVCS Valve and Valve Operating Rooms122131 Auxiliary Steam Drain Tank Equip. Room122131Waste Gas Tank Valve Operating Room1221315.Service Water Intake Structure1271316.Containment BuildingsGeneral Areas120129Reactor Cavity Exhaust150190 CRDM Shroud Exhaust163172 Safety Chilled Water System - Electrical Switchgear Area Emergency Fan Coil Units TR 13.7.37CPSES - UNITS 1 AND 2 - TRM13.7-15Revision 83 13.7 PLANT SYSTEMSTR 13.7.37 Safety Chilled Water System - Electrical Switchgear Area Emergency Fan Coil UnitsTR LCO 13.7.37The safety chilled water system electrical switchgear area emergency fan coil units shall be OPERABLE.APPLICABILITY:MODES 1, 2, 3, and 4.

ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One or more required electrical switchgear area emergency fan coil unit(s) inoperable. A.1Declare Safety Chilled Water train(s) inoperable (TS 3.7.19).ORA.2Declare affected fan coil unit(s) and their supported equipment

inoperable.ImmediatelyImmediatelySURVEILLANCEFREQUENCY TRS 13.7.37.1Verify electrical switchgear area emergency fan coil units start on an actual or simulated Safety Injection

actuation signal.

18 months on a STAGGERED TEST

BASIS Main Feedwater Isolation Valve Pressure / Temperature LimitTR 13.7.38CPSES - UNITS 1 AND 2 - TRM13.7-16Revision 83 13.7 PLANT SYSTEMSTR 13.7.38 Main Feedwater Isolation Valve Pressure / Temperature LimitTR LCO 13.7.38The valve body and neck of each main feedwater isolation valve shall be greater than or equal to 90°F, when feedwater line pressure is greater than

675 psig.APPLICABILITY:MODES 1, 2, 3 and during pressure testing of the steam generator or main feedwater line.

ACTIONS-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------Separate Condition entry allowed for each main feedwater isolation valve.CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One or more main feedwater isolation valves outside of the required limits.A.1Restore main feedwater isolation valve(s) pressure and/or temperature to within limits.

ANDA.2------------------------------------------ - NOTE -Required Action A.2 must be completed whenever Condition A

is entered.-----------------------------------------

Perform an engineering evaluation to determine the effect of the overpressure on the structural integrity of the main feedwater isolation valve(s) and determine that the main

feedwater isolation valve(s) remains acceptable for continued operation.

1 hour72 hours (continued)

Main Feedwater Isolation Valve Pressure / Temperature LimitTR 13.7.38 ACTIONS (continued)CPSES - UNITS 1 AND 2 - TRM13.7-17Revision 83 SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEB.Required Actions and associated Completion Times of Condition A not met.B.1Be in MODE 3.

ANDB.2Be in MODE 4.

6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s12 hoursSURVEILLANCEFREQUENCY TRS 13.7.38.1--------------------------------------------------------------------------- NOTE -Not required to be performed in MODE 1 with the main --------------------------------------------------------------------------

feedwater isolation valve open.Each main feedwater isolation valve shall be determined to be greater than or equal to 90°F.12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Tornado Missile ShieldsTR 13.7.39CPSES - UNITS 1 AND 2 - TRM13.7-18Revision 83 13.7 PLANT SYSTEMS TR 13.7.39 Tornado Missile ShieldsTR LCO 13.7.39Required equipment shall be protected from tornado generated missiles as required by Allowances of Table 13.7.39-1

.APPLICABILITY:Whenever supported equipment is required to be OPERABLE.-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------Only applicable if any required missile shield is not in its missile protection configuration.

ACTIONS-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------Separate Condition entry allowed for each missile shield.

SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Allowances of Table13.7.39-1 not met for one or more missile shields.A.1Declare equipment supported by affected missile shield(s) inoperable.ImmediatelySURVEILLANCEFREQUENCY TRS 13.7.39.1 Verify allowances of Table 13.7.39-1 are satisfied.Prior to removal of any missile shield Tornado Missile ShieldsTR 13.7.39CPSES - UNITS 1 AND 2 - TRM13.7-19Revision 83 Table 13.7.39-1 Missile Shield AllowancesShields: S1-27 Door, Unit 1 Safeguards Corridor El. 810' 6"Related Specifications

3.7.12 Allowance:1.Unit 1 and 2 in MODES 5 and 6, or Unit 1 in MODES 5 and 6 and the Unit 1 Safeguards Bldg. is NOT in Direct Communication with the Unit 2 Primary Plant Ventilation Pressure Boundary.a.May be open under administrative control provided the capability to close immediately on notification of a Tornado Warning exist.b.May be removed under administrative control provided the capability exists to reinstall immediately on notification of a National Weather Service issued Tornado Warning, Tornado Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES.2.Unit 1 in MODES 5 and 6, Unit 2 in MODES 1, 2, 3 and 4, and the Unit 1 Safeguards Bldg. is in Direct Communication with the Unit 2 Primary Plant Ventilation Pressure Boundary.a.May be open under administrative control provided:*Unit 2 enters LCO 3.7.12 CONDITION B, and*It is continuously manned, with direct communications established to the control room, and*It is capable of immediate closure upon notification from the Control Room of a Tornado Warning or Unit 2 Safety Injection.b.May be removed under administrative control provided:*Unit 2 enters LCO 3.7.12 CONDITION B, and*The capability exists to re-install immediately on notification of a National Weather Service issued Tornado Warning, Tornado

Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES.3.Unit 1 and 2 in MODES 1, 2, 3 and 4.May be open under administrative control for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided:a.Units 1 and 2 enter LCO 3.7.12 CONDITION B, andb.It is continuously manned, with direct communications established to the control room, andc.It is capable of immediate closure upon notification from the Control Room of a Tornado Warning, Unit 1 Safety Injection or Unit 2 Safety Injection.

Tornado Missile ShieldsTR 13.7.39CPSES - UNITS 1 AND 2 - TRM13.7-20Revision 83 Table 13.7.39-1Missile Shield AllowancesShields: S2-27 Door, Unit 2 Safeguards Corridor El. 810' 6"Related Specifications

3.7.12 Allowance:1.Unit 1 and 2 in MODES 5 and 6, or Unit 2 in MODES 5 and 6 and the Unit 2 Safeguards Bldg. is NOT in Direct Communication with the Unit 1 Primary Plant Ventilation Pressure Boundary.a.May be open under administrative control provided the capability to close immediately on notification of a Tornado Warning exist.b.May be removed under administrative control provided the capability exists to reinstall immediately on notification of a National Weather Service issued Tornado Warning, Tornado Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES.2.Unit 2 in MODES 5 and 6, Unit 1 in MODES 1, 2, 3 and 4, and the Unit 2 Safeguards Bldg. is in Direct Communication with the Unit 1 Primary Plant

Ventilation Pressure Boundary.a.May be open under administrative control provided:*Unit 1 enters LCO 3.7.12 CONDITION B, and*It is continuously manned, with direct communications established to the control room, and*It is capable of immediate closure upon notification from the Control Room of a Tornado Warning or Unit 1 Safety Injection.b.May be removed under administrative control provided:*Unit 1 enters LCO 3.7.12 CONDITION B, and*The capability exists to re-install immediately on notification of a National Weather Service issued Tornado Warning, Tornado Watch, or other Special Weather Statement with winds in

excess of 60 mph affecting CPSES.3.Unit 1 and 2 in MODES 1, 2, 3 and 4.May be open under administrative control for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided:

a.Units 1 and 2 enter LCO 3.7.12 CONDITION B, andb.It is continuously manned, with direct communications established to the control room, and Tornado Missile ShieldsTR 13.7.39CPSES - UNITS 1 AND 2 - TRM13.7-21Revision 83 c.It is capable of immediate closure upon notification from the Control Room of a Tornado Warning, Unit 1 Safety Injection or Unit 2 Safety Injection.Shields: S1-38B Door, Auxiliary Bldg. El. 852' 6' S1 -38D Door, Train B Electrical Equipment AreaRelated Specifications

3.7.12 (S1-38B only); 3.8.9 (S-38D only)

Allowance:1.Unit 1 and 2 in MODES 5 and 6, or Unit 1 in MODES 5 and 6 and the Unit 1 Safeguards Bldg. is NOT in Direct Communication with the Unit 2 Primary Plant Ventilation Pressure Boundary.a.May be open under administrative control provided the capability to close immediately on notification of a Tornado Warning exist.b.May be removed under administrative control provided the capability exists to reinstall immediately on notification of a National Weather Service issued Tornado Warning, Tornado Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES.2.Unit 1 in MODES 5 and 6, Unit 2 in MODES 1, 2, 3 and 4, and the Unit 1 Safeguards Bldg. is in Direct Communication with the Unit 2 Primary Plant Ventilation Pressure Boundary.a.May be open under administrative control provided:*It is continuously manned, with direct communications established to the control room, and*It is capable of immediate closure upon notification from the Control Room of a Tornado Warning or Unit 2 Safety Injection.b.May be removed under administrative control provided:*Unit 2 enters LCO 3.7.12 CONDITION B, and*The capability exists to re-install immediately on notification of a National Weather Service issued Tornado Warning, Tornado

Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES.3.Unit 1 and 2 in MODES 1, 2, 3 and 4.May be open under administrative control for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided:a.It is continuously manned, with direct communications established to the control room, andTable 13.7.39-1Missile Shield Allowances Tornado Missile ShieldsTR 13.7.39CPSES - UNITS 1 AND 2 - TRM13.7-22Revision 83 b.It is capable of immediate closure upon notification from the Control Room of a Tornado Warning, Unit 1 Safety Injection or Unit 2 Safety Injection.Shields: S2-38B Door, Auxiliary Bldg. El. 852' 6" S2-38D Door, Train B Electrical Equipment AreaRelated Specifications

3.7.12 (S2-38B only); 3.8.9 (S-38D only)

Allowance:1.Unit 1 and 2 in MODES 5 and 6, or Unit 2 in MODES 5 and 6 and the Unit 2 Safeguards Bldg. is NOT in Direct Communication with the Unit 1 Primary Plant Ventilation Pressure Boundary.a.May be open under administrative control provided the capability to close immediately on notification of a Tornado Warning exist.b.May be removed under administrative control provided the capability exists to reinstall immediately on notification of a National Weather Service issued Tornado Warning, Tornado Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES.2.Unit 2 in MODES 5 and 6, Unit 1 in MODES 1, 2, 3 and 4, and the Unit 2 Safeguards Bldg. is in Direct Communication with the Unit 1 Primary Plant Ventilation Pressure Boundary.a.May be open under administrative control provided:*It is continuously manned, with direct communications established to the control room, and*It is capable of immediate closure upon notification from the Control Room of a Tornado Warning or Unit 1 Safety Injection.b.May be removed under administrative control provided:*Unit 1 enters LCO 3.7.12 CONDITION B, and*The capability exists to re-install immediately on notification of a National Weather Service issued Tornado Warning, Tornado

Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES.3.Unit 1 and 2 in MODES 1, 2, 3 and 4.May be open under administrative control for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided:a.It is continuously manned, with direct communications established to the control room, andTable 13.7.39-1Missile Shield Allowances Tornado Missile ShieldsTR 13.7.39CPSES - UNITS 1 AND 2 - TRM13.7-23Revision 83 b.It is capable of immediate closure upon notification from the Control Room of a Tornado Warning, Unit 1 Safety Injection or Unit 2 Safety Injection.Shields: Access Cover Plates (4) El. 852' 6", above Unit 1 Safeguard Bldg. CorridorRelated Specifications

3.4.7*, 3.4.8*, 3.7.12 , 3.9.5*, and 3.9.6*. Allowance:1.Unit 1 and 2 in MODES 5 and 6, or Unit 1 in MODES 5 and 6 and the Unit 1 Safeguards Bldg. is NOT in Direct Communication with the Unit 2 Primary Plant Ventilation Pressure Boundary. May be removed under administrative control provided either:a.The floor plugs (El. 831' 6" corridor) over each OPERABLE Unit 1 RHR heat exchanger are in place, orb.The capability exists to re-install the missile shield or floor plugs immediately upon notification of a National Weather Service issued Tornado Warning, Tornado Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES. If only one RHR system is OPERABLE, either its missile shield or floor plug shall be in place.2.Unit 1 in MODES 5 and 6, Unit 2 in MODES 1, 2, 3 and 4, and the Unit 1 Safeguards Bldg. is in Direct Communication with the Unit 2 Primary Plant Ventilation Pressure Boundary. May be removed under administrative control provided:a.Unit 2 enters LCO 3.7.12 CONDITION B, and either*The floor plugs (El. 831' 6" corridor) over each OPERABLE Unit 1 RHR heat exchanger are in place, or*The capability exists to re-install the missile shield or floor plugs immediately upon notification of a National Weather Service issued Tornado Warning, Tornado Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES. If only one RHR system is OPERABLE, either its

missile shield or floor plug shall be in place.*Only affects RHR operabilityTable 13.7.39-1Missile Shield Allowances Tornado Missile ShieldsTR 13.7.39CPSES - UNITS 1 AND 2 - TRM13.7-24Revision 83 Shields: Access Cover Plates (4) El. 852' 6", above Unit 2 Safeguard Bldg. CorridorRelated Specifications

3.4.7*, 3.4.8*, 3.7.12 , 3.9.5*, and 3.9.6*. Allowance:1.Unit 1 and 2 in MODES 5 and 6, or Unit 2 in MODES 5 and 6 and the Unit 2 Safeguards Bldg. is NOT in Direct Communication with the Unit 1 Primary Plant Ventilation Pressure Boundary. May be removed under administrative control provided either:a.The floor plugs (El. 831' 6" corridor) over each OPERABLE Unit 2 RHR heat exchanger are in place, orb.The capability exists to re-install the missile shield or floor plugs immediately upon notification of a National Weather Service issued Tornado Warning, Tornado Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES. If only one RHR system is OPERABLE, either its missile shield or floor plug

shall be in place.2.Unit 2 in MODES 5 and 6, Unit 1 in MODES 1, 2, 3 and 4, and the Unit 2 Safeguards Bldg. is in Direct Communication with the Unit 1 Primary Plant Ventilation Pressure Boundary. May be removed under administrative control provided:a.Unit 1 enters LCO 3.7.12 CONDITION B, and either*The floor plugs (El. 831' 6" corridor) over each OPERABLE Unit 2 RHR heat exchanger are in place, or*The capability exists to re-install the missile shield or floor plugs immediately upon notification of a National Weather Service issued Tornado Warning, Tornado Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES if only one RHR system is OPERABLE, either its missile shield or floor plug shall be in place.*Only affects RHR operabilityTable 13.7.39-1Missile Shield Allowances Tornado Missile ShieldsTR 13.7.39CPSES - UNITS 1 AND 2 - TRM13.7-25Revision 83 Shields: E-40A Door, Control RoomRelated Specifications: 3.7.10 Allowance:In all MODES may be open under administrative control for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided:a.It is continuously manned, with direct communications established to the control room, andb.It is capable of immediate closure upon notification from the Control Room (of a Tornado Warning, Safety Injection, Loss-of-Offsite Power, or Intake Vent-High Radiation).Shields: Unit 1 Containment Equipment Hatch Missile Shield (Outer Cover)*Related Specifications

3.6.6 Allowance: Unit 1 in MODES 1, 2, 3 and 4.May be removed in MODE 4 for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided the capability exists to immediately reinstall the missile shield upon notification of a National Weather Service issued Tornado Warning, Tornado Watch or other special Weather Statement with winds in excess of 60 mph affecting CPSES.

Not required in MODES 5, 6 or Defueled.Shields: Unit 2 Containment Equipment Hatch Missile Shield (Outer Cover)*Related Specifications

3.6.6 Allowance: Unit 2 in MODES 1, 2, 3 and 4.May be removed in MODE 4 for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided the capability exists to immediately reinstall the missile shield upon notification of a National Weather Service issued Tornado Warning, Tornado Watch or other special Weather Statement with winds in excess of 60 mph affecting CPSES.

Not required in MODES 5, 6 or Defueled.* The Inner cover of the Equipment Hatch is considered part of the containment liner and is addressed in accordance with LCO 3.6.1 , "Containment."Table 13.7.39-1Missile Shield Allowances Tornado Missile ShieldsTR 13.7.39CPSES - UNITS 1 AND 2 - TRM13.7-26Revision 83 Shields:EDG Missile Shield Barriers:Room 1-084 (EDG CP1-MEDGEE-01) El. 810'-6"Room 1-085 (EDG CP1-MEDGEE-02) El. 810'-6" Room 2-084 (EDG CP2-MEDGEE-01) El. 810'-6" Room 2-085 (EDG CP2-MEDGEE-02) El. 810'-6" Related Specifications: 3.8.1, 3.8.2 Allowance: The Hinged Middle Panel shield may be opened under administrative control whenever the respective Train of EDG is required to be OPERABLE provided:a.No more than one OPERABLE EDG train per unit shall have its missile shield removed/opened at one time,b.The 36 hour4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> weather forecast by the National Weather Service for the period immediately following initial disassembly activities of the hinged middle panel indicates no anticipated severe weather event including the potential threat of thunderstorms, Tornado Watch, Tornado Warning or other Special Weather Statement with winds in excess of 60 mph affecting CPNPP,c.The hinged middle panel including the bolted locations on the internal and external sides of the middle panel shall be fully restored to missile shield functional status within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after initial loosening (disengagement) of the middle panel's first bolted location,d.All bolted locations of the two side (end) panels with the exception of the splice plate bolted connections with the hinged middle panel, shall not be loosened during the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> period the hinged middle panel is breached/opened,e.All tools and replacement hardware shall be staged locally to support immediate shield restoration,f.A single point of contact within the work group responsible for missile shield impairment/restoration shall be provided and have direct communication to the control room available at all times,Table 13.7.39-1Missile Shield Allowances Tornado Missile ShieldsTR 13.7.39CPSES - UNITS 1 AND 2 - TRM13.7-27Revision 83 g.The National Weather Service forecast in addition to local weather conditions shall be periodically monitored for changing weather

conditions during the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> period the hinged middle panel is breached/opened to ensure emergent severe weather conditions do not develop or are anticipated for the area andh.The capability exists to fully restore the hinged middle panel prior to being affected by an approaching emergent severe weather event including notification of a thunderstorm, Tornado Watch, Tornado Warning or other Special Weather Statement with winds in excess of 60 mph. If the EDG missile barrier cannot be fully restored within the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance time for any reason, the respective train of Diesel Generator shall be declared INOPERABLE in accordance with the related Technical Specifications.

The Two Side (End) Panel shields may only have bolted locations not associated with the hinged middle panel loosened and/or the panel removed/opened when the respective train of Diesel Generator is not required OPERABLE by the related Technical Specifications.Table 13.7.39-1Missile Shield Allowances Tornado Missile ShieldsTR 13.7.39CPSES - UNITS 1 AND 2 - TRM13.7-28Revision 83 Table 13.7.39-1 Missile Shield Allowances Shields:Related Specifications

Access Cover Plate, Unit 1 Diesel FO Truck Fill Station 3.8.1 , 3.8.2Access Cover, Unit 1 RWSTNone Access Cover, Unit 1 CST 3.7.6Access Cover, Unit 1 RMWSTNone Service Water Tunnel, Manhole Cover (Common) El. 810' 6"

3.7.8 Removable

Slab (Hatch Cover), Electric Fire Pumps 3.7.8 CPX-FPAPFP-01 AND CPX-FPAPFP-03 Access Cover Plate, Unit 2 Diesel FO Truck Fill Station 3.8.1 , 3.8.2Access Cover, Unit 2 RWSTNone Access Cover, Unit 2 CST 3.7.6Access Cover, Unit 2 RMWSTNoneAllowance: May be removed under administrative control provided the capability exists to re-install the missile shield immediately upon notification of a National Weather Service Issued Tornado Warning, Tornado Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES.

Tornado Missile ShieldsTR 13.7.39CPSES - UNITS 1 AND 2 - TRM13.7-29Revision 83 Table 13.7.39-1 Missile Shield Allowances Shields:Related Specifications

Cover Plates (2), Unit 1 Diesel FO Storage Tanks 3.8.1 , 3.8.2Access Cover Plates (2), Unit 1 Diesel FO Storage Tanks 3.8.1 , 3.8.2Removable Slab SW Piping (Unit 1/2 Train B) El. 810' 6" 3.7.8 Removable Slab (Hatch Cover) SW Pump, CP1-SWAPSW-02

3.7.8 Removable

Slab (Hatch Cover) SW Pump, CP1-SWAPSW-01 3.7.8Manhole Cover, MH#E1A1, Unit 1 SW Train A 3.7.8Manhole Cover, MH#E1A2, Unit 1 SW Train A 3.7.8Manhole Cover, MH#E1B1, Unit 1 SW Train B 3.7.8Manhole Cover; MH#E1B2, Unit 1 SW Train B 3.7.8Cover Plates (2), Unit 2 Diesel FO Storage Tanks 3.8.1 , 3.8.2Access Cover Plates (2), Unit 2 Diesel FO Storage Tanks 3.8.1 , 3.8.2 Removable Slab (Hatch Cover) SW Pump, CP2-SWAPSW-02

3.7.8 Removable

Slab (Hatch Cover) SW Pump, CP2-SWAPSW-01 3.7.8Manhole Cover, MH#E2A1, Unit 2 SW Train A 3.7.8Manhole Cover, MH#E2A2, Unit 2 SW Train A 3.7.8Manhole Cover, MH#E2A3, Unit 2 SW Train A 3.7.8Manhole Cover, MH#E2A4, Unit 2 SW Train A 3.7.8Manhole Cover, MH#E2A5, Unit 2 SW Train A 3.7.8Manhole Cover, MH#E2B1, Unit 2 SW Train B 3.7.8Manhole Cover, MH#E2B2, Unit 2 SW Train B 3.7.8Manhole Cover, MH#E2B3, Unit 2 SW Train B 3.7.8Manhole Cover, MH#E2B4, Unit 2 SW Train B 3.7.8Manhole Cover, MH#E2B5, Unit 2 SW Train B 3.7.8Allowance:May be removed under administrative control for up to 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided:a.The capability exists to re-install the missile shield immediately upon notification of a National Weather Service issued Tornado Warning, Tornado Watch, or other Special Weather Statement with winds in excess of 60 mph affecting CPSES, andb.No more than one OPERABLE train per unit of a system shall have its missile shields removed at one time.

CST Make-up and Reject Line Isolation ValvesTR 13.7.41CPSES - UNITS 1 AND 2 - TRM13.7-30Revision 83 13.7 PLANT SYSTEMSTR 13.7.41 Condensate Storage Tank (CST) Make-up and Reject Line Isolation ValvesTR LCO 13.7.41Two CST make-up and reject line isolation valves shall be OPERABLE.APPLICABILITY:MODES 1, 2, and 3, except when the CST make-up and reject line is isolated by a closed and de-activated isolation valve.

ACTIONS-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------The make-up and reject line may be unisolated intermittently under administrative controls.CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One CST make-up and reject line isolation valve inoperable.A.1Isolate the make-up and reject line.ANDA.2Verify the flowpath is isolated.72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />sOnce per 31 daysB.Two CST make-up and reject line isolation valves inoperable.B.1Isolate the make-up and reject line.4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> (continued)

CST Make-up and Reject Line Isolation ValvesTR 13.7.41 ACTIONS (continued)CPSES - UNITS 1 AND 2 - TRM13.7-31Revision 83 SURVEILLANCE REQUIREMENTSC.Required Actions and associated Completion Times for Conditions A or B

not met.C.1Verify by administrative means OPERABILITY of backup water supply.ANDC.2Restore both affected valves to OPERABLE.4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />sANDOnce per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter 7 daysSURVEILLANCEFREQUENCY TRS 13.7.41.1Verify each CST make-up and reject line isolation valve actuates to the isolation position on an actual or simulated actuation signal.

18 months TRS 13.7.41.2Verify a make-up and reject line isolation actuation signal is initiated on CST HI-HI level.

18 months AC Sources (Diesel Generator Requirements)

TR 13.8.31CPSES - UNITS 1 AND 2 - TRM13.8-1Revision 83 13.8 ELECTRICAL POWER SYSTEMS TR 13.8.31 AC Sources (Diesel Generator Requirements)TR LCO 13.8.31Pursuant to TS 3.8.1 and 3.8.2 , the Technical Requirements Surveillances (TRS) listed below for the diesel generator(s) (DGs) required to be capable of supplying the onsite Class 1E power distribution subsystem(s) shall be met.APPLICABILITY:MODES 1, 2, 3, 4, 5 and 6.

ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One or more of the following surveillances not met for required DG(s).A.1Enter the applicable Condition(s) of TS 3.8.1 or 3.8.2 for the effected DG(s) inoperable.ImmediatelySURVEILLANCEFREQUENCY TRS 13.8.31.1 Verify diesel generator is aligned to provide standby power to the associated emergency busses. 31 days TRS 13.8.31.2--------------------------------------------------------------------------- NOTE -Verify requirement during MODES 3, 4, 5, 6, or with --------------------------------------------------------------------------core off-loaded.Subject the diesel to inspections in accordance with procedures prepared in conjunction with the diesel owners group's preventive maintenance program.

18 months(continued)

AC Sources (Diesel Generator Requirements)

TR 13.8.31 SURVEILLANCE REQUIREMENTS (continued)CPSES - UNITS 1 AND 2 - TRM13.8-2Revision 83 SURVEILLANCEFREQUENCY TRS 13.8.31.3--------------------------------------------------------------------------- NOTE -Verify requirement during MODES 3, 4, 5, 6, or with --------------------------------------------------------------------------core off-loaded.Verify that the auto-connected loads to each diesel generator do not exceed the continuous rating of 7,000 kW.18 months on a STAGGERED TEST BASIS TRS 13.8.31.4--------------------------------------------------------------------------- NOTE -Verify requirement during MODES 3, 4, 5, 6, or with --------------------------------------------------------------------------core off-loaded.Verify that the following diesel generator lockout features prevent diesel generator from starting:a.Barring device engaged, orb.Maintenance Lockout Mode.

18 months TRS 13.8.31.5Pump out each fuel oil storage tank, remove accumulated sediment and clean the tank using a sodium hypochlorite solution or equivalent.

10 Years TRS 13.8.31.6 Perform a pressure test of those portions of the diesel fuel oil system designed to Section III, subsection ND of the ASME Code, when tested pursuant to the Inservice

Inspection Program.

10 Years Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-3Revision 83 13.8 ELECTRICAL POWER SYSTEMSTR 13.8.32 Containment Penetration Conductor Overcurrent Protection DevicesTR LCO 13.8.32All containment penetration conductor overcurrent protective devices, which are listed in Table 13.8.32-1 , shall be OPERABLE.APPLICABILITY:MODES 1, 2, 3 and 4.

ACTIONS-------------------------------------------------------------------------------------------------------------------------------- NOTES -1.TR LCO 13.0.4.c is applicable to overcurrent protective devices in circuits which have their associated protective device tripped/removed and their inoperable protective device racked out, locked open, or removed.-------------------------------------------------------------------------------------------------------------------------------2.Separate Condition entry is allowed for each overcurrent protection device.

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 ACTIONS (continued)CPSES - UNITS 1 AND 2 - TRM13.8-4Revision 83 CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.One or more of the containment penetration conductor overcurrent protective device(s) inoperable.A.1.1.1Verify the circuit(s) de-energized by racked out, locked open, or removed inoperable protective device(s). ANDA.1.1.2 Tripping/ removing the associated protective device(s).

ORA.1.2.1Verify the circuit(s) de-energized by tripped/removed associated protective device(s). ORA.1.2.2 Verify the circuit(s) de-energized by racked out, locked open, or removed

inoperable protective device(s).

ANDA.2Declare the affected system(s) or component(s) inoperable.72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />sANDOnce per 31 days thereafter72 hours72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />sANDOnce per 7 days thereafter72 hoursANDOnce per 7 days thereafter72 hoursB.Required Actions and associated Completion Times not met.B.1Be in MODE 3.

ANDB.2Be in MODE 5.

6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />s36 hours Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-5Revision 83 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.8.32.1Verify that the medium voltage 6.9 kV and low voltage 480V switchgear circuit breakers are OPERABLE by:a.A CHANNEL CALIBRATION of the associated protective relays,b.An integrated system functional test which includes simulated automatic actuation of the system and verifying that each relay and associated circuit breakers and control circuits function as designed, andc.For each circuit breaker found inoperable during these functional tests, one or an additional representative sample of at least 10% of all the circuit breakers of the inoperable type shall also be functionally tested until no more failures are found or all circuit breakers of that type have been functionally tested.

72 monthsANDAt least 10% of the breakers of a group tested every 18 months(continued)

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 SURVEILLANCE REQUIREMENTS (continued)CPSES - UNITS 1 AND 2 - TRM13.8-6Revision 83 SURVEILLANCEFREQUENCY TRS 13.8.32.2Verify that the 480V and lower voltage molded case circuit breakers are OPERABLE by performing the

following:a.Inverse time overcurrent trip test to verify that the test trip time does not exceed the maximum trip time per the breaker time-current characteristics.b.Instantaneous overcurrent trip test.c.Circuit breakers found inoperable during functional testing shall be replaced by OPERABLE breakers prior to resuming operation.d.For each circuit breaker found inoperable during these functional tests, an additional representative sample of at least 10% of all the circuit breakers of the inoperable type shall also be functionally tested until no more failures are found or all circuit breakers of that type have been functionally tested.

72 monthsANDAt least 10% of the breakers tested every 18 months for breaker groups with 4 breakers ORAt least 1 breaker tested every 36 months for breakers

groups with 2 or 3 breakers.TRS 13.8.32.3 Subject each medium voltage 6.9kv switchgear circuit breaker to an inspection and preventive maintenance in accordance with procedures prepared in conjunction with its manufacturer's recommendations.

60 months TRS 13.8.32.4 Subject each low voltage 480V switchgear circuit breaker to an inspection and preventive maintenance in accordance with procedures prepared in conjunction with its manufacturer's recommendations.

60 months TRS 13.8.32.5Subject each 480V and lower voltage molded case switchgear circuit breaker to an inspection and preventive maintenance in accordance with procedures prepared in conjunction with its manufacturer's recommendations.

72 months Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-7Revision 83 Table 13.8.32-1a (Page 1 of 13)Unit 1 Containment Penetration Conductor Overcurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED1.6.9 KVAC from Switchgearsa.Switchgear Bus 1A1RCP #111)Primary Breaker 1PCPX1a)Relay 50M1-51b)Relay 86M2)Backup Breakers 1A1-1 or 1A1-2a)Relay 51M3b)Relay 51 for 1A1-1 c)Relay 51 for 1A1-2 d)Relay 86/1A1b.Switchgear Bus 1A2RCP #121)Primary Breaker 1PCPX2a)Relay 50M1-51b)Relay 86M2)Backup Breakers 1A2-1 or 1A2-2a)Relay 51M3b)Relay 51 for 1A2-1 c)Relay 51 for 1A2-2 d)Relay 86/1A2 Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-8Revision 83 Table 13.8.32-1a (Page 2 of 13)Unit 1 Containment Penetration Conductor Overcurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWEREDc.Switchgear Bus 1A3RCP #131)Primary Breaker 1PCPX3a)Relay 50M1-51b)Relay 86M2)Backup Breakers 1A3-1 or 1A3-2a)Relay 51M3b)Relay 51 for 1A3-1c)Relay 51 for 1A3-2d)Relay 86/1A3d.Switchgear Bus 1A4RCP #141)Primary Breaker 1PCPX4a)Relay 50M1-51b)Relay 86M2)Backup Breaker 1A4-1 or 1A4-2a)Relay 51M3b)Relay 51 for 1A4-1c)Relay 51 for 1A4-2 d)Relay 86/1A4 Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-9Revision 83 Table 13.8.32-1a (Page 3 of 13)Unit 1 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED2.480 VAC from Switchgears2.1480V Switchgear 1EB11.Compartment 3BContainment Recirc Fan CP1-VAFNAV-01a)Primary Breaker 1FNAV11)Relay: Amptector Trip Unit of Breaker 1FNAV1b)Backup Breakers 1EB1-1 and BT-1EB13 1)Long Time and Instantaneous Relay 2)Time Delay Relay 2.2480V Switchgear 1EB21.Compartment 3BContainment Recirc Fan CP1-VAFNAV-02a)Primary Breaker 1FNAV21)Relay: Amptector Trip Unit of Breaker 1FNAV2b)Backup Breakers 1EB2-1 and BT-1EB24 1)Long Time and Instantaneous Relay 2)Time Delay Relay 2.3480V Switchgear 1EB31.Compartment 8BCRDM Vent Fan CP1-VAFNCB-01a)Primary Breaker 1FNCB11)Relay: Amptector Trip Unit of Breaker 1FNCB1b)Backup Breakers 1EB3-1 and BT-1EB13 1)Long Time and Instantaneous Relay 2)Time Delay Relay 5051-1FNAV1-----------------------

-621-1FNAV1-----------------------

-5051-1FNAV2-----------------------

-621-1FNAV2-----------------------

-5051-1FNCB1------------------------621-1FNCB1------------------------

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-10Revision 83 Table 13.8.32-1a (Page 4 of 13)Unit 1 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED2.Compartment 9BContainment Recirc Fan CP1-VAFNAV-03a)Primary Breaker 1FNAV31)Relay: Amptector Trip Unit of Breaker 1FNAV3b)Backup Breakers 1EB3-1 and BT-1EB13 1)Long Time and Instantaneous Relay 2)Time Delay Relay 2.4480V Switchgear 1EB41.Compartment 8BCRDM Vent Fan CP1-VAFNCB-02a)Primary Breaker 1FNCB21)Relay: Amptector Trip Unit of Breaker 1FNCB2b)Backup Breakers 1EB4-1 and BT-1EB24 1)Long Time and Instantaneous Relay 2)Time Delay Relay 2.Compartment 9BContainment Recirc Fan CP1-VAFNAV-04a)Primary Breaker 1FNAV41)Relay: Amptector Trip Unit of Breaker 1FNAV4b)Backup Breakers 1EB4-1 and BT-1EB24 1)Long Time and Instantaneous Relay 2)Time Delay Relay 5051-1FNAV3-----------------------

-621-1FNAV3-----------------------

-5051-1FNCB2------------------------621-1FNCB2------------------------5051-1FNAV4-----------------------

-621-1FNAV4-----------------------

-

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-11Revision 83 Table 13.8.32-1a (Page 5 of 13)Unit 1 Containment Penetration Conductor Overcurrent Protective DevicesDEVICE NUMBER AND LOCATION SYSTEM POWERED3.480VAC from Motor Control Centers3.1Device Location-MCC 1EB1-2 Compartment Numbers listed below.

Primary and Backup Breakers-Both primary and backup breakers have identical trip ratings and are in the same MCC Compt. These breakers are General Electric type THED with thermal-magnetic trip elements.MCC 1EB1-2 COMPT. NO.

G.E.BKR. TYPESYSTEM POWERED4GTHEDMotor Operated Valve 1-TV-46914MTHEDMotor Operated Valve 1-TV-46933FTHEDContainment Drain Tank Pump-039HTHEDReactor Cavity Sump Pump-019MTHEDReactor Cavity Sump Pump-027HTHEDContainment Sump #1 Pump-017MTHEDContainment Sump #1 Pump-02 6HTHEDRCP #11 Motor Space Heater-016MTHEDRCP #13 Motor Space Heater-038BTHEDIncore Detector Drive "A" 8DTHEDIncore Detector Drive "B"7BTHEDIncore Detector Drive "F"3BTHEDStud Tensioner Hoist Outlet-01 7DTHEDHydraulic Deck Lift-01 4BTHEDReactor Coolant Pump Motor Hoist Receptacle-428HTHEDRC Pipe Penetration Cooling Unit-018MTHEDRC Pipe Penetration Cooling Unit-025HTHEDRCP #11 Oil Lift Pump-015MTHEDRCP #13 Oil Lift Pump-0310BTHEDPreaccess Filter Train Package Receptacle-1712HTHEDContainment Ltg. XFMR-28 (PNL C11 & C12)2MTHEDRC Drain Tank Pump No. 12FTHEDContainment Ltg. XFMR-16 (PNL C7 & C9)1MTHEDContainment Ltg. XFMR-12 (PNL C1 & C5)3MTHEDPreaccess Fan No. 11 Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-12Revision 83 Table 13.8.32-1a (Page 6 of 13)Unit 1 Containment Penetration Conductor Overcurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED3.2Device Location-MCC 1EB2-2 Compartment Numbers listed below.Primary and Backup Breakers-Both primary and backup breakers have identical trip ratings and are located in the same MCC compt. These breakers are General Electric type THED with thermal-magnetic trip elements.

MCC 1EB2-2 COMPT. NO.G.E.

BKR. TYPESYSTEM POWERED4GTHEDMotor Operated Valve 1-TV-46924MTHEDMotor Operated Valve 1-TV-46943FTHEDContainment Drain Tank Pump-04 7HTHEDContainment Sump No. 2 Pump-03 7MTHEDContainment Sump No. 2 Pump-04 6HTHEDRCP #12 Motor Space Heater-02 6MTHEDRCP #14 Motor Space Heater-04 5BTHEDIncore Detector Drive "C"2BTHEDIncore Detector Drive "D"7BTHEDIncore Detector Drive "E" 5DTHEDContainment Fuel Storage Crane-01 3BTHEDStud Tensioner Hoist Outlet-02 4BTHEDContainment Solid Rad Waste Compactor-01 10BTHEDRCC Change Fixture Hoist Drive-01 10FTHEDRefueling Cavity Skimmer Pump-01 12BTHEDPower Receptacles (Cont. E1. 841')

8HTHEDRC Pipe Penetration Fan-03 8MTHEDRC Pipe Penetration Fan-045HTHEDRCP #12 Oil Lift Pump-02 5MTHEDRCP #14 Oil Lift Pump-0412HTHEDPreaccess Filter Train Package Receptacles - 186DTHEDContainment Auxiliary Upper Crane-01(a)2FTHEDContainment Ltg. XFMR-13 (PNL C2)2DTHEDContainment Access Rotating Platform-01 2MTHEDReactor Coolant Drain Tank Pump-02 9FTHEDContainment Ltg. XFMR-17(PNL C8 & C10) 9MTHEDContainment Ltg. XFMR-15 (PNL C4 & C6) 3MTHEDPreaccess Fan-12(a) Upon implementation and acceptance by Operations of FDA-2002-001062-01; the System Powered is changed from "Containment Auxiliary Upper Crane -01" to "Containment Building Welding Receptacle El. 905'-9"".

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-13Revision 83 Table 13.8.32-1a (Page 7 of 13)Unit 1 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED3.3Device Location-MCC 1EB3-2 Compartment numbers listed below.Primary and Backup Breakers-Unless noted otherwise, both primary and backup breakers have identical trip ratings and are located in the same MCC compt. These breakers are General Electric type THED with thermal-magnetic trip elements.

MCC 1EB3-2COMPT. NO.

G.E.

BKR. TYPE SYSTEM POWERED8RFTHEDJB-1S-10050, Altern. Feed to Motor Operated Valve 1-8702A1GTHEDMotor Operated Valve 1-81129GTHEDMotor Operated Valve 1-8701A 9MTHEDMotor Operated Valve 1-8701B5MTHEDMotor Operated Valve 1-8000A5GTHEDMotor Operated Valve 1-HV-6074 4GTHEDMotor Operated Valve 1-HV-60764MTHED (a)Motor Operated Valve 1-HV-60782GTHEDMotor Operated Valve 1-HV-46962MTHEDMotor Operated Valve 1-HV-47013GTHED (a)Motor Operated Valve 1-HV-55413MTHED (a)Motor Operated Valve 1-HV-55431MTHEDMotor Operated Valve 1-HV-6083 6FTHEDMotor Operated Valve 1-8808A6MTHEDMotor Operated Valve 1-8808C7MTHEDContainment Ltg. XFMR-18 (PNL SC1 & SC3) 8MTHEDNeutron Detector Well Fan-09 8RMTHEDMotor Operated Valve 1-HV-4075C(a) Primary protection is provided by Gould Tronic TR5 fusible switch with 3.2A fuse.

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-14Revision 83 Table 13.8.32-1a (Page 8 of 13)Unit 1 Containment Penetration Conductor Overcurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED3.4Device Location-MCC 1EB4-2 Compartment numbers listed below.Primary and Backup Breakers-Unless noted otherwise, both primary and backup breakers have identical trip ratings and are located in the same MCC compt. These breakers are General Electric type THED with thermal-magnetic trip elements.

MCC 1EB4-2COMPT. NO.

G.E.

BKR. TYPE SYSTEM POWERED1MTHEDJB-1S-1230G, Altern. Feed to Motor Operated Valve 1-8701B8GTHEDMotor Operated Valve 1-8702A8MTHEDMotor Operated Valve 1-8702B 4MTHEDMotor Operated Valve 1-8000B4GTHEDMotor Operated Valve 1-HV-60753GTHEDMotor Operated Valve 1-HV-60773MTHED (a)Motor Operated Valve 1-HV-60792GTHEDMotor Operated Valve 1-HV-55622MTHED (a)Motor Operated Valve 1-HV-55635FTHEDMotor Operated Valve 1-8808B 5MTHEDMotor Operated Valve 1-8808D6MTHEDContainment Ltg. XFMR-19(PNL SC2 & SC4)7MTHEDNeutron Detector Well Fan-10 (a) Primary protection is provided by Gould Tronic TR5 fusible switch with 3.2A fuse.

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-15Revision 83 Table 13.8.32-1a (Page 9 of 13)Unit 1 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED4.480VAC From Panelboards4.1Pressurizer Heater Groups A, B, & D a.Primary Breakers -General Electric Type TJJ Thermal Magnetic breakers. Breaker No. & Location-Ckt. Nos. 2 thru 4 of Panelboards 1EB2-1-2, 1EB3-1-2, 1EB4-1-1, 1EB4-1-2 and Ckt. Nos. 2 thru 5 of Panelboards 1EB2-1-1 and 1EB3-1-1.

b.Backup Breakers (a) --General Electric Type THJS or TJH4S with longtime and insts. solid state trip devices with

400 Amp. sensor. Breaker No. & Location-Ckt. No. 1 of Panelboards 1EB2-1-1, 1EB2-1-2, 1EB3-1-1, 1EB3-1-2, 1EB4-1-1 and 1EB4-1-2.4.2Pressurizer Heater group Ca.Primary Breakers -General Electric Type THED breakers.Breaker No. & Location-For both 1EB1-1-1 & 1EB1-1-2 are located at Ckt. Nos. 2 thru 4.b.Backup Breakers -General Electric Type TJJ Thermal Magnetic breakers. Breaker No. & Location-Ckt Nos. 2 thru 4 of Switchboards 1EB1-1-1 &

1EB1-1-2.(a) When a branch circuit breaker is tripped or placed in the off position or there is an open in the heater circuit(e.g., an open heater element), then the breaker settings for the main (feeder) circuit breaker should be adjust-ed per drawing E1-2400-296. If a breaker was previously in the 'off' position and is then placed in the 'on'position, then the breaker settings for the main (feeder) circuit breaker should be adjusted per drawing E1-2400-296.

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-16Revision 83 Table 13.8.32-1a (Page 10 of 13)Unit 1 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED4.3480VAC From Plant Support Power System PanelboardsBoth primary and backup breakers have identical trip settings and are located in the same panel board. These breakers are Square D type FC, KH, and LH.a)Panelboard 1B11-1-1 Device Location Breaker TypeSystem PoweredCkt 2FCContainment Elevator CP1-MEELRB-01 Ckt 4KHWelding Receptacles Distribution Panel 1B11-1-1-1Ckt 6LHContainment Polar Crane CP1-MESCCP-01b)Panelboard 1B11-1-2 Device Location Breaker TypeSystem PoweredCkt 2FCFuel Transfer System Rx Side Cont. Pnl for TBX-FHSTTS-02Ckt 14FCContainment Lighting Xfmr CP1-ELTRNT-14Ckt 16FCManipulator Crane 1-01 TBX-FHSCMC-01 Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-17Revision 83 Table 13.8.32-1a (Page 11 of 13)Unit 1 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATION SYSTEM POWERED5.120V Space Heater Circuits from 480V SwitchgearsContainment Recirc. Fan and CRDM Vent Fan Motor Space Heatersa.Primary Devices - N/A (Fuse) b. Backup Breakers BKR. LOCATION

& NUMBERWESTINGHOUSE BKR. TYPE Swgr. 1EB1, Cubicle 3A, CP1-VAFNAV-01Space Heater Bkr.EB1010 Swgr. 1EB2, Cubicle 3A, CP1-VAFNAV-02 Space Heater Bkr.EB1010 Swgr. 1EB3, Cubicle 9A, CP1-VAFNAV-03Space Heater Bkr.EB1010 Swgr. 1EB4, Cubicle 9A, CP1-VAFNAV-04 Space Heater Bkr.EB1010 Swgr. 1EB3, Cubicle 8A, CP1-VAFNCB-01Space Heater Bkr.EB1010 Swgr. 1EB4, Cubicle 8A, CP1-VAFNCB-02 Space Heater Bkr.EB1010 Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-18Revision 83 Table 13.8.32-1a (Page 12 of 13)Unit 1 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED6.125V DC Control PowerVariousa.Primary Devices - N/A (Fuse)b.Backup Breakers PANELBOARD NO.CKT.NO.GENERAL ELECTRIC BREAKER TYPEXED1-11,6TEDXED2-13,6TEDXD2-38TED1ED2-114,17TED 1D2-310TED1ED3-15TED1ED1-27TEDTBX-WPXILP-01Main(LBK3)FB(Westinghouse)7.120V AC Control Power from Isolation XFMR TXEC3 & TXEC4a.Primary Devices - N/A (Fuse)b.Backup Breakers -Square D Type QOB located in Miscellaneous Signal Control Cabinet.1)Panel Board A, Ckt. Bkr. connected at TB4-132)Panel Board B, Ckt. Bkr. connected at TB6-78.120V AC Power for Personnel and Emergency Airlocksa.Primary Devices - N/A (Fuse)b.Backup Breakers PANELBOARD NO.CKT.NO.GENERAL ELECTRIC BREAKER TYPEXEC234TEDXEC1-22TED Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-19Revision 83 Table 13.8.32-1a (Page 13 of 13)Unit 1 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED9.118V AC Control Power a.Primary Devices - N/A (Fuse)b.Backup Breakers PANELBOARD NO.CKT.NO.GENERAL ELECTRIC BREAKER TYPE1EC58TED1EC63TED10.Emergency Evacuation System Warning Lights Powera.Primary Devices - N/A (Fuse)b.Backup Breakers PANELBOARD NO.CKT.NO.SQUARE D BREAKER TYPEXEC3-39,10FY11.DRPI Data Cabinet Power Suppliesa.Primary Breakers PANELBOARD NO.CKT.NO.SQUARE D BREAKER TYPE1C141,2FAb.Backup Breakers PANELBOARD NO.CKT.NO.SQUARE D BREAKER TYPE1C14Main Pnl. Bkrs.FA Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-20Revision 83 Table 13.8.32-1b (Page 1 of 14)Unit 2 Containment Penetration Conductor Overcurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED1.6.9 KVAC from Switchgearsa.Switchgear Bus 2A1RCP #211)Primary Breaker 2PCPX1a)Relay 50M1-51b)Relay 86M2)Backup Breakers 2A1-1 or 2A1-2a)Relay 51M3b)Relay 51 for 2A1-1 c)Relay 51 for 2A1-2 d)Relay 86/2A1b.Switchgear Bus 2A2RCP #221)Primary Breaker 2PCPX2a)Relay 50M1-51b)Relay 86M2)Backup Breakers 2A2-1 or 2A2-2a)Relay 51M3b)Relay 51 for 2A2-1 c)Relay 51 for 2A2-2 d)Relay 86/2A2 Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-21Revision 83 Table 13.8.32-1b (Page 2 of 14)Unit 2 Containment Penetration Conductor Overcurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWEREDc.Switchgear Bus 2A3RCP #231)Primary Breaker 2PCPX3a)Relay 50M1-51b)Relay 86M2)Backup Breakers 2A3-1 or 2A3-2a)Relay 51M3b)Relay 51 for 2A3-1c)Relay 51 for 2A3-2d)Relay 86/2A3d.Switchgear Bus 2A4RCP #241)Primary Breaker 2PCPX4a)Relay 50M1-51b)Relay 86M2)Backup Breaker 2A4-1 or 2A4-2a)Relay 51M3b)Relay 51 for 2A4-1c)Relay 51 for 2A4-2 d)Relay 86/2A4 Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-22Revision 83 Table 13.8.32-1b (Page 3 of 14)Unit 2 Containment Penetration Conductor Overcurrent Protective DevicesDEVICE NUMBER AND LOCATION SYSTEM POWERED2.480 VAC from Switchgears2.1480V Switchgear 2EB11.Compartment 3BContainment Recirc FanCP2-VAFNAV-01a)Primary Breaker 2FNAV11)Relay: Amptector Trip Unit of Breaker 2FNAV1b)Backup Breakers 2EB1-1 and BT-2EB13 1)Long Time and Instantaneous Relay

2) Time Delay Relay 2.2480V Switchgear 2EB21.Compartment 3BContainment Recirc FanCP2-VAFNAV-02a)Primary Breaker 2FNAV21)Relay: Amptector Trip Unit of Breaker 2FNAV2b)Backup Breakers 2EB2-1 and BT-2EB24 1)Long Time and Instantaneous Relay 2)Time Delay Relay 2.3480V Switchgear 2EB31.Compartment 8BCRDM Vent FanCP2-VAFNCB-01a)Primary Breaker 2FNCB11)Relay: Amptector Trip Unit of Breaker 2FNCB1b)Backup Breakers 1EB3-1 and BT-1EB13 1)Long Time and Instantaneous Relay 2)Time Delay Relay 2.Compartment 9BContainment Recirc FanCP2-VAFNAV-03a)Primary Breaker 2FNAV31)Relay: Amptector Trip Unit of Breaker 2FNAV3b)Backup Breakers 2EB3-1 and BT-2EB13 1)Long Time and Instantaneous Relay 2)Time Delay Relay 5051-2FNAV1-----------------------

-621-2FNAV1-----------------------

-5051-2FNAV2-----------------------

-621-2FNAV2-----------------------

-5051-2FNCB1------------------------621-2FNCB1------------------------5051-2FNAV3-----------------------

-621-2FNAV3-----------------------

-

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-23Revision 83 Table 13.8.32-1b (Page 4 of 14)Unit 2 Containment Penetration Conductor Overcurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED2.4480V Switchgear 2EB41.Compartment 8BCRDM Vent Fan CP2-VAFNCB-02a)Primary Breaker 2FNCB21)Relay: Amptector Trip Unit of Breaker 2FNCB2b)Backup Breakers 2EB4-1 and BT-2EB24 1)Long Time and Instantaneous Relay 2)Time Delay Relay 2.Compartment 9BContainment Recirc Fan CP2-VAFNAV-04a)Primary Breaker 2FNAV41)Relay: Amptector Trip Unit of Breaker 2FNAV4b)Backup Breakers 2EB4-1 and BT-2EB24 1)Long Time and Instantaneous Relay 2)Time Delay Relay 5051-2FNCB2------------------------621-2FNCB2------------------------5051-2FNAV4-----------------------

-621-2FNAV4-----------------------

-

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-24Revision 83 Table 13.8.32-1b (Page 5 of 14)Unit 2 Containment Penetration Conductor Overcurrent Protective DevicesDEVICE NUMBER AND LOCATION SYSTEM POWERED3.480VAC from Motor Control Centers3.1Device Location-MCC 2EB1-2 Compartment Numbers listed below.

Primary and Backup Breakers-Both primary and backup breakers have identical trip ratings and are in the same MCC Compt. These breakers are General Electric type THED with thermal-magnetic trip elements.MCC 2EB1-2 COMPT. NO.

G.E.BKR. TYPESYSTEM POWERED4GTHEDMotor Operated Valve 2-TV-46914MTHEDMotor Operated Valve 2-TV-46933FTHEDContainment Drain Tank Pump-039HTHEDReactor Cavity Sump Pump-019MTHEDReactor Cavity Sump Pump-027HTHEDContainment Sump #1 Pump-017MTHEDContainment Sump #1 Pump-026HTHEDRCP #21 Motor Space Heater-016MTHEDRCP #23 Motor Space Heater-038BTHEDIncore Detector Drive "A" 8DTHEDIncore Detector Drive "B"7BTHEDIncore Detector Drive "F"3BTHEDStud Tensioner Hoist Outlet-017DTHEDHydraulic Deck Lift-014BTHEDReactor Coolant Pump Motor Hoist Receptacle-428HTHEDRC Pipe Penetration Cooling Unit-018MTHEDRC Pipe Penetration Cooling Unit-02 5HTHEDRCP #21 Oil Lift Pump-015MTHEDRCP #23 Oil Lift Pump-0310BTHEDPreaccess Filter Train Package Receptacle-17 10FTHEDS.G. Wet Layup Circ. Pump 01 (CP2-CFAPRP-01)12MTHEDS.G. Wet Layup Circ. Pump 03 (CP2-CFAPRP-03)12HTHEDContainment Ltg. XFMR-28 (PNL 2C11 & 2C12)12BTHEDPersonnel Air Lock Hydraulic Unit #2 (CP2-BSAPPA-02M)2MTHEDRC Drain Tank Pump No. 12FTHEDContainment Ltg. XFMR-16 (PNL 2C7 & 2C9) 1MTHEDContainment Ltg. XFMR-12 (PNL 2LPC1 & 2LPC5)3MTHEDPreaccess Fan No. 11 Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-25Revision 83 Table 13.8.32-1b (Page 6 of 14)Unit 2 Containment Penetration Conductor Overcurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED3.2Device Location-MCC 2EB2-2 Compartment Numbers listed below.Primary and Backup Breakers-Both primary and backup breakers have identical trip ratings and are located in the same MCC compt. These breakers are General Electric type THED with thermal-magnetic trip elements.

MCC 2EB2-2 COMPT. NO.G.E.

BKR. TYPESYSTEM POWERED4GTHEDMotor Operated Valve 2-TV-46924MTHEDMotor Operated Valve 2-TV-46943FTHEDContainment Drain Tank Pump-04 7HTHEDContainment Sump No. 2 Pump-037MTHEDContainment Sump No. 2 Pump-046HTHEDRCP #22 Motor Space Heater-02 6MTHEDRCP #24 Motor Space Heater-045BTHEDIncore Detector Drive "C" 2BTHEDIncore Detector Drive "D"7BTHEDIncore Detector Drive "E" 5DTHEDContainment Fuel Storage Crane-013BTHEDStud Tensioner Hoist Outlet-0210BTHEDRCC Change Fixture Hoist Drive-0110FTHEDRefueling Cavity Skimmer Pump-0112BTHEDPower Receptacles (Cont. E1. 841')

1MTHEDS.G. Wet Layup Circ. Pump 02 (CP2-CFAPRP-02)12MTHEDS.G. Wet Layup Circ. Pump 04 (CP2-CFAPRP-04)8HTHEDRC Pipe Penetration Fan-038MTHEDRC Pipe Penetration Fan-045HTHEDRCP #22 Oil Lift Pump-025MTHEDRCP #24 Oil Lift Pump-0412HTHEDPreaccess Filter Train Package Receptacles - 186DTHEDContainment Auxiliary Upper Crane-01 (a)2FTHEDContainment Ltg. XFMR-13 (PNL 2LPC2)2DTHEDContainment Access Rotating Platform-012MTHEDReactor Coolant Drain Tank Pump-029FTHEDContainment Ltg. XFMR-17 (PNL 2C8 & 2C10) 9MTHEDContainment Ltg. XFMR-15 (PNL 2LPC4 & 2LPC6)3MTHEDPreaccess Fan-12(a) Upon implementation and acceptance by Operations of FDA-2002-001062-05; the Systems Powered is changed from "Containment Auxiliary Upper Crane -01" to "Containment Building Welding Receptacle El. 905'-9"."

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-26Revision 83 Table 13.8.32-1b (Page 7 of 14)Unit 2 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED3.3Device Location-MCC 2EB3-2 Compartment numbers listed below.Primary and Backup -Unless noted otherwise, both primary and backup breakers have identical trip ratings and are located in the same MCC compt. These breakers are General Electric type THED with thermal-magnetic trip elements.

MCC 2EB3-2COMPT. NO.

G.E.

BKR. TYPE SYSTEM POWERED8RFTHEDAltern. Feed to Motor Operated Valve 2-8702A1GTHEDMotor Operated Valve 2-81129GTHEDMotor Operated Valve 2-8701A9MTHEDMotor Operated Valve 2-8701B5MTHEDMotor Operated Valve 2-8000A 5GTHEDMotor Operated Valve 2-HV-60744GTHEDMotor Operated Valve 2-HV-60764MTHED (a)Motor Operated Valve 2-HV-60782GTHEDMotor Operated Valve 2-HV-4696 2MTHEDMotor Operated Valve 2-HV-47013GTHEDMotor Operated Valve 2-HV-55413MTHEDMotor Operated Valve 2-HV-5543 1MTHEDMotor Operated Valve 2-HV-60836FTHEDMotor Operated Valve 2-8808A6MTHEDMotor Operated Valve 2-8808C7MTHEDContainment Ltg. XFMR-18 (PNL 2SC1 & 2SC3)8MTHEDNeutron Detector Well Fan-09 8RMTHEDMotor Operated Valve 2-HV-4075C(a) Primary protection is provided by Gould Tronic TR5 fusible switch with 3.2A fuse.

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-27Revision 83 Table 13.8.32-1b (Page 8 of 14)Unit 2 Containment Penetration Conductor Overcurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED3.4Device Location-MCC 2EB4-2 Compartment numbers listed below.Primary and Backup -Unless noted otherwise, both primary and backup breakers have identical trip ratings and are located in the same MCC compt. These breakers are General Electric type THED with thermal-magnetic trip elements.

MCC 2EB4-2COMPT. NO.

G.E.

BKR. TYPE SYSTEM POWERED1MTHEDAltern. Feed to Motor Operated Valve 2-8701B8GTHEDMotor Operated Valve 2-8702A8MTHEDMotor Operated Valve 2-8702B4MTHEDMotor Operated Valve 2-8000B4GTHEDMotor Operated Valve 2-HV-6075 3GTHEDMotor Operated Valve 2-HV-60773MTHED (a)Motor Operated Valve 2-HV-60792GTHED (a)Motor Operated Valve 2-HV-55622MTHED (a)Motor Operated Valve 2-HV-55635FTHEDMotor Operated Valve 2-8808B5MTHEDMotor Operated Valve 2-8808D6MTHEDContainment Ltg. XFMR-19 (PNL 2SC2 & 2SC4) 7MTHEDNeutron Detector Well Fan-10 (a) Primary protection is provided by Gould Tronic TR5 fusible switch with 3.2A fuse.

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-28Revision 83 Table 13.8.32-1b (Page 9 of 14)Unit 2 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED4.480VAC From Panelboards4.1Pressurizer Heater Groups A, B, & D a.Primary Breakers -General Electric Type TJJ Thermal Magnetic breakers. Breaker No. & Location-Ckt. Nos. 2 thru 4 of Panelboards 2EB2-1-2, 2EB3-1-2, 2EB4-1-1, 2EB4-1-2 and Ckt. Nos. 2 thru 5 of Panelboards 2EB2-1-1 and 2EB3-1-1.

b.Backup Breakers (a) -General Electric Type THJS or TJH4S with longtime and insts. solid state trip devices with

400 Amp. sensor. Breaker No. & Location-Ckt. No. 1 of Panelboards 2EB2-1-1, 2EB2-1-2, 2EB3-1-1, 2EB3-1-2, 2EB4-1-1 and 2EB4-1-2.4.2Pressurizer Heater group Ca.Primary Breakers -General Electric Type THED breakers.Breaker No. & Location-For both 2EB1-1-1 & 2EB1-1-2 are located at Ckt. Nos. 2 thru 4.b.Backup Breakers -General Electric Type TJJ Thermal Magnetic breakers. Breaker No. & Location-Ckt Nos. 2 thru 4 of Switchboards 2EB1-1-1 &

2EB1-1-2.(a) When a branch circuit breaker is tripped or placed in the off position or there is an open in the heater circuit(e.g., an open heater element), then the breaker settings for the main (feeder) circuit breaker should be adjust-ed per drawing E2-2400-296. If a breaker was previously in the 'off' position and is then placed in the 'on'position, then the breaker settings for the main (feeder) circuit breaker should be adjusted per drawing E2-2400-296.

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-29Revision 83 Table 13.8.32-1b (Page 10 of 14)Unit 2 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED4.3480VAC From Plant Support Power System PanelboardsBoth primary and backup breakers have identical trip settings and are located in the same panelboard (with the exception of Ckt 1 / Bkr-1 located in Panelboard 2B10-1-2 and Ckt 1 / Bkr-2 located in Panelboard 2B10-1-2a). These breakers are Square D type FH, KH, FA, and LH.a)Panelboard 2B10-1-2 Device Location Breaker TypeSystem PoweredCkt 2FHContainment Elevator CP2-MEELRB-01 Ckt 4KHContainment Welding ReceptaclesCkt 6LHContainment Polar Crane CP2-MESCCP-01 Ckt 1 / Bkr-1LHContainment Jib Crane CP2-MEMECA-16Disconnect Switches CP2-ECDSNC-15&16b)Panelboard 2B10-1-1-1 Device Location Breaker TypeSystem PoweredCkt 4 (b)FHPersonnel Airlock Hydraulic Unit #2(CP2-BSAPPA-02M)Ckt 6FHFuel Transfer System Rx Side Cont. Pnl for TCX-FHSTTS-02Ckt 10FHContainment Lighting XfmrCP2-ELTRNT-14Ckt 8FHManipulator Crane 1-01 TXC-FHSCMC-01c)Panelboard 2B10-1-2a Device Location Breaker TypeSystem PoweredCkt 1/Bkr-2FAContainment Jib Crane CP2-MEMECA-16Disconnect Switches CP2-ECDSNC-15 &16(b)Breakers become electrical penetration overcurrent protection devices only when transfer switch CP2-BSTSNB-01 is aligned to plant support power panel 2B10-1-1-1/04/BKR-1 and 2. Transfer switch CP2-BSTSNB-01 is normally aligned to MCC 2EB1-2/12B/BKR-1 and 2.

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-30Revision 83 Table 13.8.32-1b (Page 11 of 14)Unit 2 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATION SYSTEM POWERED5.120V Space Heater Circuits from 480V SwitchgearsContainment Recirc. Fan and CRDM Vent Fan Motor Space Heatersa.Primary Devices - N/A (Fuse) b. Backup Breakers BKR. LOCATION

& NUMBERWESTINGHOUSE BKR. TYPE Swgr. 2EB1, Cubicle 3A, CP2-VAFNAV-01Space Heater Bkr.EB1010 Swgr. 2EB2, Cubicle 3A, CP2-VAFNAV-02 Space Heater Bkr.EB1010 Swgr. 2EB3, Cubicle 9A, CP2-VAFNAV-03Space Heater Bkr.EB1010 Swgr. 2EB4, Cubicle 9A, CP2-VAFNAV-04 Space Heater Bkr.EB1010 Swgr. 2EB3, Cubicle 8A, CP2-VAFNCB-01Space Heater Bkr.EB1010 Swgr. 2EB4, Cubicle 8A, CP2-VAFNCB-02 Space Heater Bkr.EB1010 Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-31Revision 83 Table 13.8.32-1b (Page 12 of 14)Unit 2 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED6.125V DC Control PowerVariousa.Primary Devices - N/A (Fuse)b.Backup Breakers PANELBOARD NO.

CKT. NO.GENERAL ELECTRIC BREAKER TYPEXED1-16 (c)TEDXED2-16 (c)TED2ED2-111,17TED2ED1-111TED2D2-36,10,11TED (a)2D2-29TED (a)2ED2-212TED (a)2ED3-15TED 2ED1-27,8TED (a)TBX-WPXILP-01Main(LBK3) (c)FB(Westinghouse)7.120V AC Control Power from Isolation XFMR TXEC3 & TXEC4a.Primary Devices - N/A (Fuse) b.Backup Breakers -Square D Type QOB located in Miscellaneous Signal Control Cabinet.1)Panel Board A, Ckt. Bkr. connected at TB3-52)Panel Board B, Ckt. Bkr. connected at TB5-1(a)Upon implementation and acceptance by Operations of FDA-2002-002756-01; breakers 2D2-3/11, 2D2-2/9, 2ED2-2/12, and 2ED1-2/8 are no longer required meet the requirements of TRM 13.8.32

.(c)These circuits provide backup protection to both Units 1 and 2. Testing of these breakers is controlled by Unit 1 surveillance program.

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-32Revision 83 Table 13.8.32-1b (Page 13 of 14)Unit 2 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED8.120 AC Power for Personnel and Emergency Airlocksa.Primary Devices - N/A (Fuse) b.Backup Breakers PANELBOARD NO.CKT. NO.GENERAL ELECTRIC BREAKER TYPEXEC112TEDXEC2-23TED9.118V AC Control Power a.Primary Devices - N/A (Fuse)b.Backup Breakers PANELBOARD NO.CKT. NO.GENERAL ELECTRIC BREAKER TYPE2C222TED (a)2PC110TED (a)2PC410TED (a)2EC17TED (a)2EC24,7TED(a)2EC58TED2EC63,8TED (a)(a) Upon completion and acceptance by Operations of FDA-2002-002756-01; breakers 2C2/22, 2PC1/10, 2PC4/10, 2EC1/7, 2EC2/4, 2EC2/7, and 2EC6/8 are no longer required to meet the requirements of TRM 13.8.32

.

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32CPSES - UNITS 1 AND 2 - TRM13.8-33Revision 83 Table 13.8.32-1b (Page 14 of 14)Unit 2 Containment Penetration ConductorOvercurrent Protective DevicesDEVICE NUMBER AND LOCATIONSYSTEM POWERED10.Emergency Evacuation System Warning Lights Powera.Primary Devices - N/A (Fuse) b.Backup Breakers PANELBOARD NO.CKT. NO.SQUARE D BREAKER TYPEXEC4-39,10FY11.DRPI Data Cabinet Power Suppliesa.Primary Breakers PANELBOARD NO.CKT. NO.SQUARE D BREAKER TYPE2C141,2FAb.Backup Breakers PANELBOARD NO.CKT. NO.SQUARE D BREAKER TYPE2C14Main Pnl. Bkrs.FA Decay Time TR 13.9.31CPSES - UNITS 1 AND 2 - TRM13.9-1Revision 7713.9 REFUELING OPERATIONSTR 13.9.31 Decay TimeTR LCO 13.9.31The reactor shall be subcritical for at least 75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br />.APPLICABILITY:During movement of irradiated fuel in the reactor vessel.

ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Reactor subcritical for less than 75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br />.A.1Suspend all operations involving movement of irradiated fuel in the

reactor vessel.ImmediatelySURVEILLANCEFREQUENCY TRS 13.9.31.1Determine the reactor has been subcritical for at least 75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br /> by verification of the date and time of subcriticality.Prior to movement of irradiated fuel in

the reactor vessel.

Refueling Operations / Communications TR 13.9.32CPSES - UNITS 1 AND 2 - TRM13.9-2Revision 7713.9 REFUELING OPERATIONS TR 13.9.32 Refueling Operations / CommunicationsTR LCO 13.9.32Direct communications shall be maintained between the control room and personnel at the refueling station.APPLICABILITY:During CORE ALTERATIONS.

ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.No direct communications between the control room and personnel at the refueling station.A.1Suspend all CORE ALTERATIONS.ImmediatelySURVEILLANCEFREQUENCY TRS 13.9.32.1Verify direct communications between the control room and personnel at the refueling station.

Once within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> prior to the start of CORE ALTERATIONS AND12 hours Refueling MachineTR 13.9.33CPSES - UNITS 1 AND 2 - TRM13.9-3Revision 7713.9 REFUELING OPERATIONS TR 13.9.33 Refueling MachineTR LCO 13.9.33The refueling machine main hoist and auxiliary monorail hoist shall be used for movement of drive rods or fuel assemblies and shall be OPERABLE

with: a.The refueling machine main hoist used for movement of fuel assemblies having: 1.A minimum capacity of 2850 pounds, and 2.An overload cutoff limit less than or equal to 2800 pounds.b.The auxiliary monorail hoist used for latching, unlatching and movement of control rod drive shafts having:1.A minimum capacity of 610 pounds, and2.A load indicator which shall be used to prevent lifting loads in excess of 600 pounds.---------------------------------------------------------------------------------------------------- NOTE -Special evolutions may require the use of hoists and load indicators in addition to the auxiliary monorail hoist.---------------------------------------------------------------------------------------------------APPLICABILITY:During movement of fuel assemblies and/or latching, unlatching or movement of control rod drive shafts within the reactor vessel.

ACTIONSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Requirements for hoist OPERABILITY not satisfied.A.1Suspend use of any inoperable hoist from operations involving the movement of fuel assemblies and/or latching, unlatching or movement of control rod drive shafts within the reactor vessel.Immediately Refueling MachineTR 13.9.33CPSES - UNITS 1 AND 2 - TRM13.9-4Revision 77 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.9.33.1The refueling machine main hoist used for movement of fuel assemblies within the reactor vessel shall be demonstrated OPERABLE by performing a load test of at least 2850 pounds and demonstrating an automatic load cutoff when the main hoist load exceeds 2800 pounds. Once within 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> prior to the start of such operations TRS 13.9.33.2The auxiliary monorail hoist and other hoists and associated load indicators used for latching, unlatching or movement of control rod drive shafts within the reactor vessel shall be demonstrated OPERABLE by performing a load test of at least 610 pounds.

Once within 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> prior to the start of such operations Refueling - Crane Travel - Spent Fuel Storage AreasTR 13.9.34CPSES - UNITS 1 AND 2 - TRM13.9-5Revision 7713.9 REFUELING OPERATIONS TR 13.9.34 Refueling - Crane Travel - Spent Fuel Storage AreasTR LCO 13.9.34Loads in excess of 2150 pounds shall be prohibited from travel over fuel assemblies in a storage pool.APPLICABILITY:With fuel assemblies in the storage pool.

ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Technical Requirement not met.A.1.Place the crane load in a safe condition.ImmediatelySURVEILLANCEFREQUENCY TRS 13.9.34.1--------------------------------------------------------------------------- NOTE -Only required to be performed when the hoist is being used to move loads over fuel assemblies in a spent fuel --------------------------------------------------------------------------storage pool.Each hoist load indicator shall be demonstrated OPERABLE by performing a load test of at least 2200 pounds.7 days(continued)

Refueling - Crane Travel - Spent Fuel Storage AreasTR 13.9.34 SURVEILLANCE REQUIREMENTS (continued)CPSES - UNITS 1 AND 2 - TRM13.9-6Revision 77SURVEILLANCEFREQUENCY TRS 13.9.34.2--------------------------------------------------------------------------- NOTE -Only required to be performed when the hoist is being used to move loads over fuel assemblies in a spent fuel --------------------------------------------------------------------------storage pool.Fuel Handling Bridge Crane interlocks which permit only one trolley-hoist assembly to be operated at a time shall be verified.6 months Water Level, Reactor Vessel, Control Rods TR 13.9.35CPSES - UNITS 1 AND 2 - TRM13.9-7Revision 7713.9 REFUELING OPERATIONS TR 13.9.35 Water Level, Reactor Vessel, Control RodsTR LCO 13.9.35At least 23 feet of water shall be maintained over the top of the irradiated fuel assemblies within the reactor vessel.APPLICABILITY:During movement of control rods within the reactor vessel while in MODE 6.

ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Technical Requirement not met.A.1Suspend all operations involving movement of control rods within the reactor vessel.ImmediatelySURVEILLANCEFREQUENCY TRS 13.9.35.1 The water level shall be determined to be at least its minimum required depth.24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />sANDOnce within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> prior to the movement of control rods in MODE 6 Fuel Storage Area Water Level TR 13.9.36CPSES - UNITS 1 AND 2 - TRM13.9-8Revision 7713.9 REFUELING OPERATIONSTR 13.9.36 Fuel Storage Area Water LevelTR LCO 13.9.36The fuel storage area water level shall be 23 ft over the top of irradiated fuel assemblies seated in the storage racks.APPLICABILITY:Whenever irradiated fuel assemblies are in the storage racks.----------------------------------------------------------------------------------------------------- NOTE -While This LCO is not met, do not commence crane operations with loads ----------------------------------------------------------------------------------------------------

over irradiated fuel in the storage racks.

ACTIONS SURVEILLANCE REQUIREMENTSCONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Fuel storage area water level < 23 feet above irradiated fuel assemblies seated in the storage racks.A.1Suspend crane operations with loads in the affected fuel storage areas and restore the water level to within its limit.

4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />sSURVEILLANCEFREQUENCY TRS 13.9.36.1Verify the fuel storage area water level 23 ft above the irradiated fuel assemblies seated in the storage racks.

7 days Explosive Gas Monitoring InstrumentationTR 13.10.31CPSES - UNITS 1 AND 2 - TRM13.10-1Revision 6513.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAMTR 13.10.31 Explosive Gas Monitoring InstrumentationTR LCO 13.10.31Pursuant to Technical Specification 5.5.12a , the explosive gas monitoring instrumentation channels shown in Table 13.10.31-1 shall be OPERABLE with their Alarm/Trip Setpoints set to ensure that the limits specified in TR13.10.34 are not exceeded.APPLICABILITY:During Waste Gas Holdup System operation on the inservice recombiner.

ACTIONS-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------Separate Condition entry is allowed for each recombiner.CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.An explosive gas monitoring instrumentation channel Alarm/Trip Setpoint less conservative than required.A.1Declare channel inoperable.ImmediatelyB.Any required channel inoperable.B.1Restore the inoperable channel to OPERABLE status.

30 daysC.No inlet oxygen monitor channel OPERABLE on the inservice recombiner.C.1Verify the associated inlet hydrogen monitor(s) OPERABLE.Immediately(continued)

Explosive Gas Monitoring InstrumentationTR 13.10.31 ACTIONS (continued)CPSES - UNITS 1 AND 2 - TRM13.10-2Revision 65CONDITIONREQUIRED ACTIONCOMPLETION TIMED.No outlet oxygen monitor channel OPERABLE on the inservice recombiner.D.1Suspend operation of the Waste Gas Holdup System.

ORD.2Take and analyze grab samples while maintaining oxygen < 1%

by volume.ImmediatelyOnce per 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />sE.Less than the required hydrogen monitor Channels OPERABLE on the inservice recombiner.

ORNo inlet oxygen monitor channel and no outlet oxygen monitor channel

OPERABLE on the inservice recombiner.

ORNo inlet oxygen monitor channel and no inlet hydrogen monitor channel OPERABLE on the inservice recombiner.E.1Suspend oxygen supply to the affected recombiner(s).

ANDE.2.1Suspend addition of waste gas to the system.

ORE.2.2Take and analyze grab samples while maintaining oxygen < 1% by volume.ImmediatelyImmediatelyOnce per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> during degassing OROnce per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> during other operations Explosive Gas Monitoring InstrumentationTR 13.10.31CPSES - UNITS 1 AND 2 - TRM13.10-3Revision 65 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.10.31.1 Perform a CHANNEL CHECK of each explosive gas monitoring instrumentation channel shown in Table13.10.31-1

.Once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> during Waste Gas Holdup System operationANDOnce per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to Waste Gas Holdup System

operation.

TRS 13.10.31.2Perform a CHANNEL OPERATIONAL TEST of each explosive gas monitoring instrumentation channel shown in Table 13.10.31-1

.31 days TRS 13.10.31.3Perform a CHANNEL CALIBRATION of each explosive gas monitoring instrumentation channel shown in Table13.10.31-1. This shall include the use of standard gas samples in accordance with the manufacturer's recommendations.

92 days Explosive Gas Monitoring InstrumentationTR 13.10.31CPSES - UNITS 1 AND 2 - TRM13.10-4Revision 65Table 13.10.31-1Explosive Gas Monitoring Instrumentation **One hydrogen and two oxygen monitors are required to be OPERABLE for the operating recombiner during Waste Gas HOLDUP System operationINSTRUMENTREQUIRED CHANNELS1.Waste Gas Holdup System Explosive Gas Monitoring Systema.Hydrogen Monitors1 per recombinerb.Oxygen Monitors2 per recombiner Gas Storage TanksTR 13.10.32CPSES - UNITS 1 AND 2 - TRM13.10-5Revision 65 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAM TR 13.10.32 Gas Storage TanksTR LCO 13.10.32Pursuant to TS 5.5.12b, the quantity of radioactivity contained in each gas storage tank shall be 200,000 Curies of noble gases (considered as Xe-133 equivalent).APPLICABILITY:At all times.

ACTIONS -------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------Separate condition entry allowed for each gas storage tank.CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Radioactivity in one or more storage tank(s) not within limit.A.1Suspend all additions of radioactive material to the

tank(s).ANDA.2Reduce radioactivity in tank(s) to within limit.

ANDA.3------------------------------------------ - NOTE -Required Action A.3 must be completed whenever Condition A is entered.-----------------------------------------

Describe events leading to exceeding limits in Radioactive

Effluent Release Report.Immediately48 hoursPer TS 5.6.3 Gas Storage TanksTR 13.10.32CPSES - UNITS 1 AND 2 - TRM13.10-6Revision 65 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.10.32.1------------------------------------------------------------------------- - NOTE -Only required to be performed when radioactive materials are being added to the tank.

---

Determine the quantity of radioactive material in each gas storage tank to verify within limit.Once within 92 days after the addition of radioactive material being added to the tank, but not more often than 92 days Liquid Holdup TanksTR 13.10.33CPSES - UNITS 1 AND 2 - TRM13.10-7Revision 6513.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAMTR 13.10.33 Liquid Holdup TanksTR LCO 13.10.33Pursuant to TS 5.5.12c, the quantity of radioactive material in each outdoor unprotected tank shall be limited to 10 Curies, excluding tritium and dissolved or entrained noble gases.APPLICABILITY:At all times.

ACTIONS-------------------------------------------------------------------------------------------------------------------------------- NOTE --------------------------------------------------------------------------------------------------------------------------------Separate Condition entry allowed for each tank.CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Quantity of radioactive material in one or more tanks exceeds limits.A.1Suspend all additions of radioactive material to the

tank(s).ANDA.2Reduce quantity of radioactive material in tank(s) to within limits.

ANDA.3------------------------------------------- - NOTE -Required Action A.3 must be completed whenever Condition A is entered.------------------------------------------

Describe events leading to exceeding limits in Radioactive

Effluent Release Report.

Immediately.48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />sPer TS 5.6.3 Liquid Holdup TanksTR 13.10.33CPSES - UNITS 1 AND 2 - TRM13.10-8Revision 65 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.10.33.1------------------------------------------------------------------------- - NOTE -Only required to be performed when radioactive materials are being added to the tank.

---

Analyze a representative sample of each tank's contents to verify within limits.

7 days Explosive Gas MixtureTR 13.10.34CPSES - UNITS 1 AND 2 - TRM13.10-9Revision 6513.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAMTR 13.10.34 Explosive Gas MixtureTR LCO 13.10.34Pursuant to TS 5.5.12a, the concentration of oxygen in the Waste Gas Holdup system shall be 3% by volume whenever the hydrogen concentration is > 4% by volume.APPLICABILITY:At all times.

ACTIONS -------------------------------------------------------------------------------------------------------------------------------- NOTE -Only applicable when hydrogen concentration in the Waste Gas Holdup system is > 4% by -------------------------------------------------------------------------------------------------------------------------------

volume.CONDITIONREQUIRED ACTIONCOMPLETION TIMEA.Oxygen concentration in Waste Gas Holdup system

> 3% by volume and 4% by volume.A.1Reduce oxygen concentration to within limits.48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />sB.Oxygen concentration in Waste Gas Holdup System

> 4% by volume.B.1Suspend all additions of waste gases to the system.

ANDB.2Reduce oxygen concentration to 4% by volume.ImmediatelyImmediately Explosive Gas MixtureTR 13.10.34CPSES - UNITS 1 AND 2 - TRM13.10-10Revision 65 SURVEILLANCE REQUIREMENTSSURVEILLANCEFREQUENCY TRS 13.10.34.1Monitor the hydrogen and oxygen in the Waste Gas Holdup Systems as specified by TR 13.10.31

.As specified in TR13.10.31 Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-1Revision 83 15.0 ADMINISTRATIVE CONTROLS15.5 Programs and ManualsTR 15.5.17TRM - Administrative Control Processa.Introduction CPSES has relocated certain information from the Technical Specifications to a separate controlled document based on the NUMARC Technical Specification Improvement Program, the Westinghouse Owners Group MERITS Program, and the Commission's Interim Policy Statement for improvement of Technical Specifications for nuclear power plants (52

FR 3788 of February 6, 1987). This information is now contained in a separate document to be called the CPSES Technical Requirements Manual (TRM). The following is a description of the administrative program for control, distribution, updating, and amending the information contained in the TRM. The Explosive Gas and Storage Tank Radioactivity Monitoring Program, as required by TS 5.5.12, is contained in Section 13.10 of the TRM.b.Document ControlThe TRM is considered a licensing basis document and as such, overall control of the document is addressed by the site-wide procedures for licensing document control.c.Document DistributionThe TRM is considered a controlled document and distribution is controlled by site wide procedures for licensing basis document control.(continued)

Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-2Revision 83 d.Changes / Deletions to the TRM Changes to the TRM are controlled by the procedure on licensing document change control. This procedure addresses the administrative requirements necessary to change/amend CPSES licensing documents (e.g., Fire Protection Report, Offsite Dose Calculation Manual). For changes to the TRM, the procedure requires initiation of a Licensing Document Change Request (LDCR). The LDCR is the mechanism whereby changes are tracked to ensure that appropriate reviews, approvals, and signatures are obtained. TRM changes are evaluated per 10CFR50.59. TRM changes require a review by SORC and the approval of the Plant Manager. Changes to the TRM must comply with the

requirements of Technical Specification 5.5.17 of the CPSES Units 1 and 2 Technical Specifications.e.Plant Changes That May Affect the TRMChanges made at CPSES have the potential to affect (or be affected by) the TRM. These include items such as design modifications, procedure changes, other licensing document changes, etc. When TRM changes are required, the changes should be initiated and approved consistent with the plant activity (e.g., modification, procedure change etc.).f.Distribution of TRM Changes / DeletionsChanges to the TRM will be issued on a replacement page basis to controlled document holders promptly following approval of the change.g.Report of TRM Changes / Deletions to the NRC Changes to the TRM will be reported to the NRC on the same frequency as the FSAR.Proposed TRM changes that are determined to require prior NRC approval (as defined by 10CFR50.59) will either not be made or will be submitted to the NRC for prior review and approval.TR 15.5.21Surveillance Frequency Control ProgramThe Technical Specification Surveillance Requirement Frequencies subject to the provisions of TS 5.5.21, "Surveillance Frequency Control Program" are listed in

Table 5.5.21-1, "Technical Specification Surveillance Requirement Frequencies." Changes to these Frequencies shall only be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1 and TR 15.5.17. The provisions of Technical Specifications Surveillance Requirements 3.0.2 and 3.0.3 are applicable to the Frequencies established in the Surveillance Frequency Control Program.(continued)

Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-3Revision 83 Note: Bracketed text in the Frequency is NOT subject to the Surveillance Frequency Control Program. The bracketed text is repeated from the Technical Specifications for completeness.(continued)

Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-4Revision 83 Table 15.5.21-1 (Sheet 1 of 12)Technical Specification Surveillance Requirement FrequencySURVEILLANCEFREQUENCYSR 3.1.1.1 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.1.2.1 [Once prior to entering MODE 1 after each refueling AND ----------------NOTE-------------- Only required after 60 EFPD ---------------------------------------] 31 EFPD thereafter SR 3.1.4.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> SR 3.1.4.2 92 days SR 3.1.5.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> SR 3.1.6.2 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.1.6.312 hours0.00361 days <br />0.0867 hours <br />5.15873e-4 weeks <br />1.18716e-4 months <br /> SR 3.1.8.230 minutes SR 3.1.8.31 hour3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br /> SR 3.1.8.424 hours0.00491 days <br />0.118 hours <br />7.010582e-4 weeks <br />1.61332e-4 months <br /> SR 3.2.1.1[Once after each refueling prior to THERMAL POWER exceeding 75% RTP AND Once within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after achieving equilibrium conditions after exceeding, by 20% RTP, the THERMAL POWER at which was last verified AND] 31 EFPD thereafter F Q C Z Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-5Revision 83 SR 3.2.1.2[Once after each refueling prior to THERMAL POWER exceeding 75% RTP AND Once within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after achieving equilibrium conditions after exceeding, by 20% RTP, the THERMAL POWER at which was last verified AND] 31 EFPD thereafter SR 3.2.2.1[Once after each refueling prior to THERMAL POWER exceeding 75% RTP AND] 31 EFPD thereafter SR 3.2.3.1 7 days SR 3.2.4.1 7 days SR 3.2.4.2 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.3.1.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.3.1.2 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.3.1.3 31 effective full power days (EFPD) SR 3.3.1.4 62 days on a STAGGERED TEST BASIS SR 3.3.1.5 92 days on a STAGGERED TEST BASIS SR 3.3.1.6 92 EFPD SR 3.3.1.7 184 days Table 15.5.21-1 (Sheet 2 of 12)Technical Specification Surveillance Requirement FrequencySURVEILLANCEFREQUENCY F Q C Z Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-6Revision 83 SR 3.3.1.8 [------------------------------------NOTE------------------------------------ Only required when not performed within previous] 184 days

[--------------------------------------------------------------------------------- Prior to reactor startup AND 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reducing power below P-10 for power and intermediate instrumentation AND Four hours after reducing power below P-6 for source range instrumentation AND] Every 184 days thereafter SR 3.3.1.9 92 days SR 3.3.1.10 18 months SR 3.3.1.11 18 months SR 3.3.1.13 18 months SR 3.3.1.14 18 months SR 3.3.1.15 Prior to exceeding the P-9 interlock whenever the unit has been in MODE 3, if not performed in previous 31 days SR 3.3.1.16 18 months on a STAGGERED TEST BASIS SR 3.3.2.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.3.2.2 92 days on a STAGGERED TEST BASIS SR 3.3.2.4 92 days on a STAGGERED TEST BASIS SR 3.3.2.5 184 days SR 3.3.2.6 92 days OR 18 months for Westinghouse type AR relays with AC coils Table 15.5.21-1 (Sheet 3 of 12)Technical Specification Surveillance Requirement FrequencySURVEILLANCEFREQUENCY Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-7Revision 83 SR 3.3.2.7 31 days SR 3.3.2.8 18 months SR 3.3.2.9 18 months SR 3.3.2.10 18 months on a STAGGERED TEST BASIS SR 3.3.2.11 18 months SR 3.3.3.1 31 days SR 3.3.3.3 18 months SR 3.3.4.1 31 days SR 3.3.4.2 18 months SR 3.3.4.3 18 months

SR 3.3.5.1 Prior to entering MODE 4 when in MODE 5 for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and if not performed in previous 92 days SR 3.3.5.2 Prior to entering MODE 4 when in MODE 5 for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and if not performed in previous 92 days SR 3.3.5.3 18 months SR 3.3.5.4 18 months on a STAGGERED TEST BASIS SR 3.3.6.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.3.6.2 92 days on a STAGGERED TEST BASIS SR 3.3.6.3 92 days on a STAGGERED TEST BASIS SR 3.3.6.4 92 days SR 3.3.6.5 92 days OR 18 months for Westinghouse type AR relays with AC coils SR 3.3.6.7 18 months Table 15.5.21-1 (Sheet 4 of 12)Technical Specification Surveillance Requirement FrequencySURVEILLANCEFREQUENCY Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-8Revision 83 SR 3.3.7.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.3.7.2 92 days SR 3.3.7.6 18 months SR 3.3.7.7 18 months SR 3.4.1.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.1.2 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.1.3 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.1.4 18 months SR 3.4.2.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.3.1 30 minutes SR 3.4.4.1 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 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.5.2 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.5.3 7 days SR 3.4.6.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.6.2 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.6.3 7 days SR 3.4.7.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.7.2 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.7.3 7 days SR 3.4.8.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.8.2 7 days SR 3.4.9.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.9.2 18 months Table 15.5.21-1 (Sheet 5 of 12)Technical Specification Surveillance Requirement FrequencySURVEILLANCEFREQUENCY Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-9Revision 83 SR 3.4.11.1 92 days SR 3.4.11.2 18 months SR 3.4.12.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.12.2 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.12.3 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.12.4 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> SR 3.4.12.5 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for unlocked open vent valve(s)

AND 31 days for locked open vent valve(s) SR 3.4.12.6 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> SR 3.4.12.8 31 days SR 3.4.12.9 18 months SR 3.4.13.1 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> SR 3.4.13.2 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> SR 3.4.14.1 [In accordance with the Inservice Testing Program, and] 18 months

[AND Prior to entering MODE 2 whenever the unit has been in MODE 5 for 7 days or more, and if leakage testing has not been performed in the previous 9 months except for valves 8701A, 8701B, 8702A and 8702B AND Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following check valve actuation due to flow through the valve] SR 3.4.14.2 18 months SR 3.4.15.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.4.15.2 92 days Table 15.5.21-1 (Sheet 6 of 12)Technical Specification Surveillance Requirement FrequencySURVEILLANCEFREQUENCY Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-10Revision 83 SR 3.4.15.3 18 months SR 3.4.15.4 18 months SR 3.4.15.5 18 months SR 3.4.16.1 7 days SR 3.4.16.2 14 days

[AND Between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after a THERMAL POWER change of 15% RTP within a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period] SR 3.5.1.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.5.1.2 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.5.1.3 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.5.1.4 31 days

[AND ----------------------------------NOTE--------------------------------- Only required to be performed for affected accumulators

---

Once within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after each solution volume increase of 101 gallons that is not the result of addition from the refueling water storage tank] SR 3.5.1.5 31 days SR 3.5.2.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.5.2.2 31 days SR 3.5.2.5 18 months on a STAGGERED TEST BASIS SR 3.5.2.6 18 months on a STAGGERED TEST BASIS SR 3.5.2.7 18 months SR 3.5.2.8 18 months Table 15.5.21-1 (Sheet 7 of 12)Technical Specification Surveillance Requirement FrequencySURVEILLANCEFREQUENCY Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-11Revision 83 SR 3.5.4.1 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.5.4.2 7 days SR 3.5.4.3 7 days SR 3.5.5.1 31 days SR 3.6.2.2 24 months SR 3.6.3.1 31 days SR 3.6.3.3 31 days SR 3.6.3.7 18 months SR 3.6.3.8 18 months on a STAGGERED TEST BASIS SR 3.6.4.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.6.5.1 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.6.6.1 31 days SR 3.6.6.5 18 months SR 3.6.6.6 18 months SR 3.7.2.2 18 months SR 3.7.3.2 18 months SR 3.7.5.1 31 days SR 3.7.5.3 18 months on a STAGGERED TEST BASIS SR 3.7.5.4 18 months on a STAGGERED TEST BASIS SR 3.7.6.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.7.7.1 31 days SR 3.7.7.2 18 months SR 3.7.7.3 18 months on a STAGGERED TEST BASIS SR 3.7.8.1 31 days Table 15.5.21-1 (Sheet 8 of 12)Technical Specification Surveillance Requirement FrequencySURVEILLANCEFREQUENCY Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-12Revision 83 SR 3.7.8.2 92 days SR 3.7.8.3 18 months on a STAGGERED TEST BASIS SR 3.7.9.1 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.7.9.2 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> SR 3.7.10.1 31 days SR 3.7.10.3 18 months on a STAGGERED TEST BASIS SR 3.7.11.1 18 months SR 3.7.12.1 31 days SR 3.7.12.3 18 months on a STAGGERED TEST BASIS SR 3.7.12.4 18 months on a STAGGERED TEST BASIS SR 3.7.12.6 18 months SR 3.7.15.1 7 days SR 3.7.16.1 7 days SR 3.7.18.1 31 days SR 3.7.19.1 31 days SR 3.7.19.2 18 months on a STAGGERED TEST BASIS SR 3.7.20.1 31 days SR 3.7.20.2 31 days SR 3.7.20.3 18 months on a STAGGERED TEST BASIS SR 3.8.1.1 7 days SR 3.8.1.2 31 days SR 3.8.1.3 31 days SR 3.8.1.4 31 days SR 3.8.1.5 31 days Table 15.5.21-1 (Sheet 9 of 12)Technical Specification Surveillance Requirement FrequencySURVEILLANCEFREQUENCY Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-13Revision 83 SR 3.8.1.6 92 days SR 3.8.1.7 184 days SR 3.8.1.8 18 months SR 3.8.1.9 18 months on a STAGGERED TEST BASIS SR 3.8.1.10 18 months on a STAGGERED TEST BASIS SR 3.8.1.11 18 months on a STAGGERED TEST BASIS SR 3.8.1.12 18 months SR 3.8.1.13 18 months on a STAGGERED TEST BASIS SR 3.8.1.14 18 months SR 3.8.1.15 18 months on a STAGGERED TEST BASIS SR 3.8.1.16 18 months on a STAGGERED TEST BASIS SR 3.8.1.17 18 months on a STAGGERED TEST BASIS SR 3.8.1.18 18 months SR 3.8.1.19 18 months on a STAGGERED TEST BASIS SR 3.8.1.20 10 years SR 3.8.1.21 18 months SR 3.8.1.22 31 days on a STAGGERED TEST BASIS SR 3.8.3.1 31 days SR 3.8.3.2 31 days SR 3.8.3.4 31 days SR 3.8.3.5 31 days SR 3.8.4.1 7 days SR 3.8.4.2 18 months SR 3.8.4.3 18 months Table 15.5.21-1 (Sheet 10 of 12)Technical Specification Surveillance Requirement FrequencySURVEILLANCEFREQUENCY Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-14Revision 83 SR 3.8.6.1 7 days SR 3.8.6.2 31 days SR 3.8.6.3 31 days SR 3.8.6.4 31 days SR 3.8.6.5 92 days SR 3.8.6.6 60 months

[AND 18 months when battery shows degradation or has reached 85% of expected life with capacity < 100% of manufacturer's rating AND 24 months when battery has reached 85% of the expected life with capacity 100% of manufacturer's rating] SR 3.8.7.1 7 days SR 3.8.8.1 7 days SR 3.8.9.1 7 days SR 3.8.10.1 7 days SR 3.9.1.1 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> SR 3.9.2.1 31 days SR 3.9.3.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.9.3.2 18 months SR 3.9.4.1 7 days SR 3.9.4.2 7 days SR 3.9.4.3 18 months SR 3.9.5.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Table 15.5.21-1 (Sheet 11 of 12)Technical Specification Surveillance Requirement FrequencySURVEILLANCEFREQUENCY Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-15Revision 83 SR 3.9.6.1 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> SR 3.9.6.2 7 days SR 3.9.7.1 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Table 15.5.21-1 (Sheet 12 of 12)Technical Specification Surveillance Requirement FrequencySURVEILLANCEFREQUENCY Programs and Manuals15.5CPSES - UNITS 1 AND 2 - TRM15.0-16Revision 83 TR 15.5.31Snubber Inservice Testing/Inspection ProgramThe snubbers are visually examined, functionally tested, and maintained in accordance with ASME OM Code, Subsection ISTD, "Preservice and Inservice

Examination and Testing of Dynamic Restraints (Snubbers) in Light-Water Reactor Nuclear Power Plants", latest issue as mandated by 10CFR50.55a for the current interval.

A current list of individual snubbers with information of snubber location and size and of system affected shall be available for inspection. Changes to the Snubber Inservice Testing/Inspection Program shall be made in accordance with 10CFRPart50.59.

CPSES - UNITS 1 AND 2 - TRMEL-1Revision 84 CPSES/TRM COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 & 2 TECHNICAL REQUIREMENTS MANUAL (TRM)EFFECTIVE LISTING FOR SECTIONS Revision Record:OriginalSubmitted July 21, 1989Revision 1September 15, 1989Revision 2January 15, 1990 Revision 3July 20, 1990Revision 4April 24, 1991Revision 5September 6, 1991 Revision 6November 22, 1991Revision 7March 18, 1992Revision 8June 30, 1992 Revision 9December 18, 1992Revision 10January 22, 1993Revision 11February 3, 1993 Revision 12July 15, 1993 Revision 13September 14, 1993Revision 14November 30, 1993Revision 15April 15, 1994 Revision 16May 11, 1994Revision 17February 24, 1995Revision 18April 14, 1995 Revision 19May 15, 1995Revision 20June 30, 1995Revision 21January 24, 1996 Revision 22February 24, 1997Revision 23March 13, 1997Revision 24June 26, 1997 Revision 25July 31, 1997Revision 26February 24, 1998Revision 27April 14, 1999 Revision 28April 16, 1999Revision 29July 27, 1999Revision 30July 27, 1999 Revision 31August 5, 1999Revision 32September 24, 1999Revision 33October 7, 1999 Revision 34June 29, 2000Revision 35September 30, 2000Revision 36May 30, 2001 Revision 37August 14, 2001Revision 38October 16, 2001Revision 39March 27, 2002 Revision 40August 15, 2002Revision 41September 24, 2002Revision 42October 11, 2002 CPSES - UNITS 1 AND 2 - TRMEL-2Revision 84 CPSES/TRM COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 & 2 TECHNICAL REQUIREMENTS MANUAL (TRM)EFFECTIVE LISTING FOR SECTIONS Revision Record:Revision 43January 23, 2003Revision 44February 4, 2003Revision 45October 7, 2003 Revision 46February 17, 2004Revision 47March 23, 2004Revision 48April 23, 2004 Revision 49September 28, 2004Revision 50July 22, 2005Revision 51August 4, 2005 Revision 52September 27, 2005Revision 53October 27, 2005Revision 54December 29, 2005 Revision 55February 28, 2006 Revision 56June 1, 2006Revision 57July 27, 2006Revision 58September 20, 2006 Revision 59October 20, 2006Revision 60January 18, 2007Revision 61January 31, 2007 Revision 62February 26, 2007Revision 63April 11, 2007Revision 64June 21, 2007 Revision 65December 19, 2007Revision 66February 28, 2008Revision 67March 13, 2008 Revision 68April 4, 2008Revision 69September 11, 2008Revision 70November 13, 2008 Revision 71May 20, 2009Revision 72September 29, 2009Revision 73March 2, 2010 Revision 74October 7, 2010Revision 75November 30, 2010Revision 76February 7, 2011 Revision 77April 18, 2011Revision 78June 9, 2011Revision 79December 22, 2011 Revision 80June 18, 2012Revision 81July 24, 2012Revision 82September 11, 2012 Revision 83October 2, 2012Revision 84October 30, 2012 CPSES - UNITS 1 AND 2 - TRMEL-3Revision 84 CPSES/TRM COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 & 2 TECHNICAL REQUIREMENTS MANUAL (TRM)EFFECTIVE LISTING FOR SECTIONSTRM TOCRevision 82Section 11.0Revision 56Section 13.0Revision 56Section 13.1Revision 82Section 13.2Revision 79Section 13.3Revision 74 Section 13.4Revision 56Section 13.5Revision 56Section 13.6Revision 70 Section 13.7Revision 83Section 13.8Revision 83Section 13.9Revision 77 Section 13.10Revision 65Section 15.0Revision 83 CPSES - UNITS 1 AND 2 - TRMEL-4Revision 84 CPSES/TRM COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 & 2 TECHNICAL REQUIREMENTS MANUAL (TRM)EFFECTIVE LISTING FOR SECTIONSTRM Bases TOCRevision 84Section B 13.0Revision 56Section B 13.1Revision 82Section B 13.2Revision 79 Section B 13.3Revision 74Section B 13.4Revision 56Section B 13.5Revision 84 Section B 13.6Revision 70Section B 13.7Revision 83Section B 13.8Revision 83 Section B 13.9Revision 77Section B 13.10Revision 56Section B 15.0Revision 83EL-1Revision 84EL-2Revision 84 EL-3Revision 84EL-4Revision 84 CPSES - UNITS 1 AND 2 - TRMDOC-1Revision 84Technical Requirements Manual - Description of Changes REVISION 56 LDCR-TR-2006-7 (EVAL-2005-005086-12) (TJE):

Administrative change for software conversion only.The type of changes include changes such as (1) correction of spelling errors, (2) correction of inadvertent word processing errors from previous changes, and (3) style guide changes (e.g., changing from a numbered bullet list to an alphabetized bullet list and vice versa, change numbering of footnote naming scheme). The entire TRM and TRM Bases will be reissued as Revision 56. For the text and tables there will be no change bars in the page margins for the editorial changes. The list of effective pages is being replaced with a list of effective sections, tables, and figures. Sections Revised:AllTables Revised:AllFigures Revised:All REVISION 57 LDCR-TR-2006-9 (EVAL-2004-000501-1) (TJE):Correct tag number in Table 13.8.32-1b section 3.1 MCC 2EB1-2 compartment number 12B from "Personnel Air Lock Hydraulic Unit #2" to "Personnel Air Lock Hydraulic Unit #2 (CP2-BSAPPA-02M)"1.) In Table 13.8.32-1b, the last sentence in section 4.3 description, replace the existing words, "These breakers are Square D type FC, KH, and LH." with the words,"These breakers are Square D type FH, KH, FA, and LH." 2.) Correct typos in tag numbers in Table 13.8.32-1b section 4.3.a, a.) Devise Location Ckt 2, change Breaker Type from FC to FH b.) Device Location Ckt 1 / Bkr-1, under System Powered, by removing the "-" between CP and 2 in two places.3.) Corrects tag number in Table 13.8.32-1b section 4.3.b a.) Devise Location Ckt 4, "Personnel Airlock Hydraulic Units CP-2-MEMEHU-01 and 02" to "Personnel Airlock Hydraulic Unit #2 (CP2-BSAPPA-02M)"

CPSES - UNITS 1 AND 2 - TRMDOC-2Revision 84Technical Requirements Manual - Description of ChangesREVISION 57 (continued) LDCR-TR-2006-9 (EVAL-2004-000501-1) (TJE) (continued): b.) Devise Location Ckt 6, change Breaker Type from F4 to FHCorrect typo to remove a dash in Table 13.7.39-1, Shield tag number from, "Removable Slab (Hatch Cover) SW Pump, CP-1-SWAPSW-02" to "Removable Slab (Hatch Cover)

SW Pump, CP1-SWAPSW-02" REVISION 58 LDCR-TR-2006-3 (EVAL-2005-004275-02) (TJE):1.) Currently, TRS 13.8.31.2 reads, "Subject the diesel to an inspection in accordance with procedures prepared in conjunction with its manufacture's recommendations for this class of standby service." The LDCR proposes to revise the TRS 13.8.31.2 to read, "Subject the diesel to inspections in accordance with procedures prepared in conjunction with the diesel owners group's preventive maintenance program."NOTE:The revision of this SR is proposed due to changes in the PM program recommended by the Cooper Owners Group which the CPSES EDGs are included in. The PM program is not being deleted nor are the vendor's recommendations being ignored. The current PM program is being enhanced to include vendor input, predictive maintenance input, performance based input and the Cooper Owners Group input. The program changes will provide the site with the opportunity to move from a prescriptive time based program to a risk informed performance based program.At the end of this section, add the words, "The diesel's preventative maintenance program is commensurate for nuclear standby service, which takes into consideration the following factors: manufacturer's recommendations, diesel owners group's recommendations, engine run time, equipment performance, calendar time, and plant preventative maintenance programs."NOTE:The revision of this SR is proposed due to changes in the PM program recommended by the Cooper Owners Group which the CPSES EDGs are included in. The PM program is not being deleted nor are the vendor's recommendations being ignored. The current PM program is being enhanced to include vendor input, predictive maintenance input, performance based input and the Cooper Owners Group input. The program changes will provide the site with the opportunity to move from a prescriptive time based program to a risk informed performance based program.

CPSES - UNITS 1 AND 2 - TRMDOC-3Revision 84Technical Requirements Manual - Description of Changes REVISION 59 LDCR-TR-2004-5 (EVAL-2004-001881-04) (TJE):Circuit Breaker 1ED1-1/14/BKR will be deleted from Table 13.8.32-1a under number 6.b. Backup Breakers. LDCR-TR-2005-10 (EVAL-2004-000773-05) (RAS):Revise TR LCO 13.3.33 from "At least one Turbine Overspeed Protection System shall be OPERABLE" to "At least one Turbine Overspeed Protection Sub-system shall be OPERABLE" Revise Condition C from " Turbine overspeed protection inoperable for reasons other than Condition A or B" to Both Overspeed Protection Sub-systems inoperable"Revise TRS 13.3.33.1 to replace the Unit specific surveillance statements with the following statement applicable equally to both Units:"Test the Turbine Trip Block using the Automatic Turbine Tester (ATT)." Delete TRS 13.3.33.3 and its associated frequency.Revise TRS 13.3.33.6 as follows to make it applicable to both Units:"Test the Hardware Overspeed Sub-system 2 of 3 relay logic and output relays" Delete the existing TRM Bases description and replace in its entirety with the following:

BACKGROUNDThis specification is provided to ensure that the turbine overspeed protection instrumentation and the turbine Stop and Control Valves are operable and will protect the turbine from excessive overspeed. Protection from excessive overspeed is necessary to prevent the generation of potentially damaging missiles which could impact and damage safety-related components, equipment and structures. Turbine overspeed is limited by rapid closure of the turbine Stop or Control Valves whenever turbine power exceeds generator output, as would exist immediately following a load rejection.The Electrohydraulic Control (EHC) System is the primary means of limiting the extent of an overspeed event, with the turbine Overspeed Protection System as a backup. The EHC System is designed to limit transient overspeed to less than 110% of rated speed after a full load rejection by closing both the High Pressure (HP) and Low Pressure (LP) Control Valves. This function of the EHC System is performed by the normal speed/load control logic in conjunction with additional protection logic that ensures closure of all control valves under certain load rejection scenarios (Reference 1).

CPSES - UNITS 1 AND 2 - TRMDOC-4Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)To minimize the possibility of a component failure resulting in a loss of the control function, the EHC System utilizes triple redundant speed and load inputs, dual redundant digital controller processors, and dual redundant outputs (amplifiers, proportional valves, and follow-up piston banks) to the Control Valves.In the unlikely event that the EHC System fails to limit the overspeed condition, the Overspeed Protection System will act to limit the overspeed to less than 120% of rated speed.The Overspeed Protection System is made up of the following basic component groups:

Independent and redundant speed sensors and associated signal processing instrumentation, including bistables, provide individual speed channel trip signals to the Turbine AG-95F Digital Protection System and the hardware overspeed trip system (both described below) whenever turbine speed exceeds 1980 rpm.The Turbine AG-95F Digital Protection System consists of three independent and redundant trains of equipment, including input modules, dual redundant automation processors and associated software, output modules, and output relays. The AG-95F System is a fail-safe system in that all inputs and outputs are normally energized in the non-tripped state.Each train of the AG-95F System processes the individual speed channel trip signals using 2 of 3 trip logic. When the trip logic is satisfied, the associated output relays de-

energize, each one subsequently de-energizing its associated Turbine Trip Block solenoid valve. The Relay Protection System consists of relay logic and output relays that are diverse from, and completely bypass, the AG-95F Digital Protection System described above. The logic and output relays are normally energized in the non-tripped state.The relay logic processes the individual speed channel trip signals using 2 of 3 trip logic. When the trip logic is satisfied, all three output relays de-energize, each one

subsequently de-energizing its associated Turbine Trip Block solenoid valve.

The Turbine Trip Block utilizes three independent and redundant solenoid valves to actuate associated hydraulic pistons that are configured in a manner that provides a hydraulic 2 of 3 trip logic. When any two of the three solenoid valves de-energize, actuation of the associated pistons rapidly de-pressurizes the turbine Trip Fluid System, causing all turbine Stop and Control Valves to close. De-energization of a single solenoid valve will not trip the turbine.The Overspeed Protection System consists of two redundant and diverse sub-systems, the Hardware Overspeed Sub-system and the Software Overspeed Sub-system, that are configured using the component groups described above. Either of these sub-systems

can independently trip the turbine.

CPSES - UNITS 1 AND 2 - TRMDOC-5Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)The Hardware Overspeed Sub-system utilizes a set of three dedicated speed channels, each of which provides a trip signal to the Relay Protection System. Upon receipt of trip

signals from any two of these speed channels, the relay logic de-energizes all three output relays which subsequently de-energize all three Turbine Trip Block solenoid valves, causing the turbine to trip.As a backup, the three dedicated Hardware Overspeed Sub-system speed channels also provide trip signals to all three of the AG-95F System protection trains. Upon receipt of trip signals from any two of these speed channels, the output relay of each protection train is de-energized, subsequently de-energizing all three Turbine Trip Block solenoid valves, causing the turbine to trip. The Software Overspeed Sub-system utilizes a second set of three dedicated speed channels which provide input to all three of AG-95F System protection trains. Upon receipt of trip signals from any two of these speed channels, the output relay of each protection train is de-energized, subsequently de-energizing all three Turbine Trip Block solenoid valves, causing the turbine to trip. The Software Overspeed System speed channels also provide speed signals to the EHC System as described above.The design of the Overspeed Protection System includes several testing features that are used to ensure OPERABILITY of the system. These features include three Automatic Turbine Tester (ATT) tests that are manually initiated by the operator. They also include a test that is automatically executed by the system to ensure OPERABILITY of the speed channel instrumentation.The ATT HP and LP Valve Tests cycle all Stop and Control Valves to ensure reliability and continuity of service. The HP and LP Stop Valve closure times are also verified to be within required response times (500 and 1500 msec, respectively). These tests cycle one pair of Stop and Control Valves at a time, so they may be performed with the plant on-line below approximately 85% power.The ATT Turbine Trip Block Test de-energizes each Turbine Trip Block solenoid valve and verifies that the associated hydraulic piston moves to the trip position. The solenoid

valve/piston pairs are sequentially tested one at a time, until all three are tested. Each pair is reset prior to testing the subsequent pair. Since only one solenoid valve/piston pair is tested at a time, the Trip Fluid System is never de-pressurized, and the turbine does not trip.Each of the six individual speed channels (three for the Hardware Overspeed Sub-system and three for the Software Overspeed Sub-system), is automatically tested once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when turbine speed is >40 rpm. These tests verify that the speed channels trip when speed is simulated above 1980 rpm. The tests are initiated by the AG-95F System in a manner that precludes two speed channels from being tested at the same time. If desired, the speed channel tests may also be initiated by the operator.Alarms are provided to alert the operator in the event a fault/failure is detected during the execution of any of the aforementioned tests.

CPSES - UNITS 1 AND 2 - TRMDOC-6Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)APPLICABLE SAFETY ANALYSISThe Overspeed Protection System is required to be OPERABLE to provide sufficient protection against generation of potentially damaging missiles which could impact and damage safety-related components, equipment and structures. The turbine missile analysis is presented in Reference 2. Using References 3 through 5 as a basis, this analysis concludes that the risk for loss of an essential system due to a turbine missile event is acceptably low.The robust design of the Overspeed Protection System, with its multiple speed channels, diverse hardware and software logic, and multiple Turbine Trip Block solenoid valves/

hydraulic pistons, meets the intent of SRP 10.2 Part III for redundancy and independence.

LCOThe Turbine Overspeed Protection Sub-systems are the Hardware Overspeed Sub-system and the Software Overspeed Sub-system, one of which shall be OPERABLE.The robust design of these sub-systems allows for the failure of individual components without rendering the sub-system(s) inoperable. Specifically, the minimum operability

requirements for the Hardware Overspeed Sub-system include:two OPERABLE dedicated hardware speed channels, and OPERABLE hardware relay logic with two OPERABLE output relays and associated Turbine Trip Block solenoid valves/hydraulic pistons ORtwo OPERABLE dedicated hardware speed channels and two OPERABLE AG-95F System trains, including output relays and associated Turbine Trip Block solenoid valves/

hydraulic pistonsThe minimum operability requirements for the Software Overspeed Sub-system include:

two OPERABLE dedicated software speed channels and two OPERABLE AG-95F System trains, including output relays and associated Turbine Trip Block solenoid valves/

hydraulic pistonsIndividual component failures that do not render the sub-system(s) inoperable are addressed under the Corrective Action Program (CAP) with restoration times commensurate with the severity of the failure and the operational impact associated with

the rework or repair.Furthermore, component failures that result in rendering only one Overspeed Protection Sub-system inoperable are also addressed under the CAP with restoration times commensurate with the severity of the failure and the operational impact associated with the rework or repair.

CPSES - UNITS 1 AND 2 - TRMDOC-7Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)

APPLICABILITYThe OPERABILITY of one Overspeed Protection Sub-system ensures that the Overspeed Protection System is available to prevent an overspeed event while the unit is operating in MODE 1, 2, and 3 with steam available to roll the turbine. The APPLICABILITY is modified by a Note specifying that Overspeed Protection Sub-system OPERABILITY is not required in MODE 2 and 3 if the turbine is isolated from the steam supply by closing all Main Steam Isolation Valves and associated bypass valves.

ACTIONSA.1, A.2, and A.3This ACTION is modified by a Note that specifies that separate Condition entries are allowed for each steam line if valves are inoperable in multiple steam lines.If an HP Stop or Control Valve is inoperable such that it is not capable of properly isolating the steam line to the turbine in response to an overspeed event, action must be taken to restore the valve(s) to OPERABLE status. Failure to restore the valve(s) to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> requires that compensatory action be taken within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to ensure that the affected steam line is isolated by other means.The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time for restoring the valve(s) takes into account the OPERABILITY of the remaining valve in the affected steam line and reasonable time for rework or repair. The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> compensatory action Completion Time is reasonable, based on operating experience, for reaching the required unit conditions from full power operation in an orderly manner and without challenging unit systems.B.1, B.2, and B.3This ACTION is modified by a Note that specifies that separate Condition entries are allowed for each steam line if valves are inoperable in multiple steam lines.If an LP Stop or Control Valve is inoperable such that it is not capable of properly isolating the steam line to the turbine in response to an overspeed event, action must be taken to restore the valve(s) to OPERABLE status. Failure to restore the valve(s) to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> requires that compensatory action be taken within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to ensure that the affected steam line is isolated by other means.The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time for restoring the valve(s) takes into account the OPERABILITY of the remaining valve in the affected steam line and reasonable time for rework or repair. The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> compensatory action Completion Time is reasonable, based

on operating experience, for reaching the required unit conditions from full power operation in an orderly manner and without challenging unit systems.

CPSES - UNITS 1 AND 2 - TRMDOC-8Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)

C.1If both Overspeed Protection Sub-systems are inoperable, such that neither is capable of initiating a turbine trip in response to an overspeed event, action must be taken within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to isolate the turbine from the steam supply.The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Completion Time for isolating the turbine from the steam supply is reasonable, based on operating experience, for reaching the required unit conditions from full power

operation in an orderly manner and without challenging unit systems.

D.1, D.2, and D.3 In the event that the aforementioned ACTIONS and associated Completion Times cannot be satisfied, action must be initiated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to place the unit in a lower MODE, with subsequent action to place the unit in MODE 3 within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to place the unit in MODE 4 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after entering MODE 3. The need to perform these actions would most likely result from the inability to isolate the turbine from the steam supply. Placing the unit in MODE 4 will reduce steam pressure to the point where there is insufficient motive force to overspeed the turbine, even if it is not isolated from the steam generators.The Completion Times are reasonable, based on operating experience, for reaching MODE 3 and MODE 4 from full power operation in an orderly manner and without challenging unit systems.TECHNICAL REQUIREMENTS SURVEILLANCEThe TRS 13.3.33 requirements are modified by a Note that specifies that the provisions of TRS 13.0.4 are not applicable.

TRS 13.3.33.1This TRS specifies testing of the Turbine Trip Block using the Automatic Turbine Tester (ATT). This test de-energizes each Turbine Trip Block solenoid valve and verifies that the associated hydraulic piston moves to the trip position. The solenoid valve/piston pairs are sequentially tested one at a time, until all three are tested. Each pair is reset prior to testing the subsequent pair. Since only one solenoid valve/piston pair is tested at a time, the Trip Fluid System is never de-pressurized, and the turbine does not trip.The 14 day test Frequency is based on the assumptions in the analyses presented in References 2 and 4.

CPSES - UNITS 1 AND 2 - TRMDOC-9Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)

TRS 13.3.33.2This TRS specifies testing of the turbine HP and LP Stop and Control Valves using the ATT. These tests cycle all Stop and Control Valves to ensure reliability and continuity of service. The HP and LP Stop Valve closure times are also verified to be within required response times (500 and 1500 msec, respectively). These tests cycle one pair of Stop and Control Valves at a time, so they may be performed with the plant on-line below approximately 85% power.The 12 week test Frequency is based on the assumptions in the analyses presented in References 2 and 4.

TRS 13.3.33.3This TRS has been deleted.

TRS 13.3.33.4This TRS requires disassembly and inspection of at least one HP Stop Valve and one HP Control Valve on a 40 month Frequency to satisfy the turbine inservice inspection requirements described in Reference 6.

TRS 13.3.33.5This TRS requires inspection of at least one LP Stop Valve and one LP Control Valve on a 40 month Frequency to satisfy the turbine inservice inspection requirements described in Reference 6.

TRS 13.3.33.6This TRS requires a test of the Hardware Overspeed Sub-system 2 of 3 relay logic and output relays to ensure that this equipment is capable of processing an overspeed turbine trip signal on demand.This equipment cannot be tested with the unit at power because performance of the test will trip the turbine. The 18 month test Frequency is consistent with Technical Specification test Frequencies assigned to similar equipment, and it affords the opportunity to test the equipment while the unit is shutdown. This test Frequency is judged to be acceptable based on the reliability of the equipment.REFERENCES1. CPSES FSAR, Section 10.2.2.72. CPSES FSAR, Section 3.5.1.3 CPSES - UNITS 1 AND 2 - TRMDOC-10Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)3. Engineering Report No. ER-504, Probability of Turbine Missiles from 1800 R/MIN Nuclear Steam Turbine-Generators with 46-Inch Last Stage Turbine Blades, Allis-Chalmers (Siemens) Power Systems, Inc, October 1975 [VL-04-001540]4. Supplement to ER-504, Comparison MTBF Evaluation Comanche Peak ST Protection and Trip System and Engineering Report No. ER-504 Probability of Turbine Missiles, Siemens Power Corporation, February 11, 2004 [VL-05-000489]5. CT-27331, Revision 4, Missile Probability Analysis Methodology for TXU Generation Company LP, Comanche Peak Units 1 and 2 with Siemens Retrofit Turbines, Siemens Westinghouse Power Corporation, October 29, 2004 [VL-05-001268]6. CPSES FSAR, Section 10.2.3.67. 59EV-2004-000774-01 and 59EV-2004-000774-02, 10CFR50.59 Evaluations for installation of the Turbine Generator Digital Protection System in Comanche Peak Unit 1 and Unit 2, respectively REVISION 60 LDCR-TR-2007-1 (EVAL-2004-001966-05) (TJE):

Change TRS 13.3.31.2 frequency to 24 months from 18 months. LDCR-TR-2006-10 (EVAL-2006-002274-01) (CBC):LDCR-TR-2006-010, EVAL-2006-002274-01: The Required Action and Completion Time for A.1.1 and A.1.2 of TRM 13.7.35, "Snubbers" are replaced with "Enter the operability determination process for attached system(s)." [Required Action] and "Immediately" [Completion Time]. Condition B and it's associated Required Action and Completion

Time are deleted. TRM 13.7.35, "Snubbers" Condition A, Required Action A allows 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for an inoperable snubber (to either be repaired or replaced) before the associated system/train is declared inoperable. Although this 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provision was relocated from Technical Specifications during conversion to the Improved STS, the NRC has indicated that it is improper to allow an exception to the TS definition of Operability for this support system by way of the TRM. As a result, the industry and the NRC have developed a revision to the STS in TSTF-372. This TSTF is NRC approved and ready for adoption.

The TSTF allows 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (or 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for a snubber affecting both trains) for seismic snubbers before declaring the system inoperable using a risk informed approach by the addition new TS 3.0.8. Since there are no current plans to adopt TSTF-372 at Comanche Peak, TRM 13.7.35 is revised to remove the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> delay. Deletion of the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> delay is consistent with the NRC's expectations as stated in 70FR23252.

CPSES - UNITS 1 AND 2 - TRMDOC-11Revision 84Technical Requirements Manual - Description of ChangesREVISION 60 (continued)

TR LCO 13.7.35 is revised to exclude certain snubbers. Those snubber(s) that have an analysis which determines that the supported TS system(s)) do not require the snubber(s) to be functional in order to support the operability of the system(s) are excluded from TR LCO 13.7.35. This is consistent with Section 4.1 of TSTF-IG-05-03, IMPLEMENTATION GUIDANCE FOR TSTF-372, REVISION 4, "ADDITION OF LCO 3.0.8, INOPERABILITY OF SNUBBERS," dated October 2005 and RIS-2005-020, REVISION TO GUIDANCE FORMERLY CONTAINED IN NRC GENERIC LETTER 91-18, INFORMATION TO LICENSEES REGARDING TWO NRC INSPECTION MANUAL

SECTIONS ON RESOLUTION OF DEGRADED AND NONCONFORMING CONDITIONS AND ON OPERABILITY," dated September 26, 2005.

REVISION 61 LDCR-TR-2006-1 (EVAL-2004-001966-03) (TJE):Justification: The use of the new Seismic Monitoring System with only free-field ground motion input will not compromise the ability of the system to determine whether or not the OBE was exceeded and subsequent shutdown of both units per Appendix A of 10CFR100. Therefore, the new Seismic Monitoring System does not present any added risk to public health or nuclear safety. The deletion of the steps for restoring the seismic monitoring system to an operable status and for the interpretation of the seismic data reflects a change in technology provided with the new system. The previous seismic monitoring system was rendered inoperable during the process of recording a seismic event. With the exception of the three triaxial accelerometers, the previous system used smoked scribe plates in the sensors that can not distinguish between different seismic events. In order to interpret the data from a seismic event and restore operability, the scribe plates had to be retrieved from the field, replaced with freshly smoked scribe plates, and then individually interpreted. The new seismic monitoring system is not rendered inoperable by a seismic event. The new system has the ability to digitally record up to 90-minutes of seismic ground motion over any number of discrete seismic events. The new seismic monitoring system will automatically; analyze the earthquake data, provide a real-time display of the data analysis and its results on the system monitor, print a hard copy of the analysis results, and if the OBE is exceeded the system will also provide Control Room annunciation. Based on the changes introduced by the new seismic monitoring as discussed above, the deletion of the steps for post-seismic event activities is acceptable. 1.) TR LCO 13.3.31 delete the words, "shown in Table 13.3.31-1" 2.) Replace Condition A, including the Note with the words, "Seismic monitoring instrument inoperable."3.) Replace Required Action A.1 with the words, "Restore seismic monitoring instrument to OPERABLE status."

CPSES - UNITS 1 AND 2 - TRMDOC-12Revision 84Technical Requirements Manual - Description of ChangesREVISION 61 (continued)4.) Replace the Completion Time of "24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />" with "30 days."5.) Delete Required Actions A.2 and A.3 and the associated Completion Times.Delete Conditions B and C and the associated Required Actions and Completion Times.

1.) Delete the Note that says:"Refer to Table 13.3.31-1 to determine which TRS apply for each seismic monitoring instrument."2.) Change TRS 13.3.31.2 Frequency from 24 months to 18 months.Delete Table 13.3.31-1 and associated foot notes Delete the entire Bases section and replace it with the following words:"The OPERABILITY of the seismic monitoring system ensures that sufficient capability is available to promptly determine whether the OBE has been exceeded and to collect information to evaluate the response of features important to safety. This capability is required pursuant to Appendix A of 10CFR100. The instrumentation provided meets the intent of Regulatory Guide 1.12, "Instrumentation for Earthquakes," April 1974, as described in the FSAR. The seismic monitoring system will record and analyze a seismic event to determine OBE exceedance in accordance with the requirements described in the FSAR." REVISION 62 LDCR-TR-2006-5 (EVAL-2004-001881-04) (TJE):Circuit Breaker 1ED1-1/14/BKR will be deleted from Table 13.8.32-1a under number 6.b. Backup Breakers.

REVISION 63 LDCR-TR-2007-2 (EVAL-2004-002710-05) (TJE):The FDA installs the Head Assembly Upgrade Package (HAUP) on the replacement reactor vessel closure head during 1RF12. The objective of the HAUP modification is to simplify the process of removal and installation of the reactor vessel closure head assembly for refueling operations (i.e., shorten the duration). Therefore, this LDCR will show unit differences.Add "(Unit 2 Only)" after "General Area CRDM Shroud Exhaust" in the Temperature Limit table under "Area Monitored." Additionally, add a second entry of "140" under "Normal Conditions" and "149" under "Abnormal Conditions" and "CRDM Air Handling Unit Inlet (Unit 1 Only)" under "Area Monitored."

CPSES - UNITS 1 AND 2 - TRMDOC-13Revision 84Technical Requirements Manual - Description of ChangesREVISION 63 (continued) LDCR-TR-2005-3 (EVAL-2005-000224-01) (TJE):Revised note 12 to include motor driven AFW pumps in Units 1 and 2 and feedwater split flow bypass valves in Unit 2 only due to deletion of split flow valves in Unit 1 as a result of the design modification to replace the SGs in Unit 1.Revised note 13 to include turbine driven AFW pumps in Units 1 and 2 and feedwater split flow bypass valves in Unit 2 only due to deletion of split flow valves in Unit 1 as a result of the design modification to replace the SGs in Unit 1.Under Feedwater Isolation Signal on Table 13.6.3-1 add "2-" in front of valve numbers FV-2193, FV-2194, FV-2195, and FV-2196.

REVISION 64 LDCR-TR-2007-8 (EVAL-2007-001391-01) (TJE):The last sentence of TRM 15.5.31.i, "Snubber Service Life Program," reads, " Part replacement shall be documented and the documentation shall be retained in accordance with Technical Specification 6.10.2." Replace the reference to "Technical Specifications 6.10.2" with "FSAR 17.2.17.2.12."LA 50/36 relocated the record retention requirements of snubbers from TS to the FSAR. This LDCR corrects the reference to the implementing document. LDCR-TR-2004-9 (EVAL-2003-001212-04) (TJE):Remove the Note and the Tables in the Background section of TRB 13.1.31 which required specific BAT levels and BAT temperatures to be maintained during startup and shutdown modes when the gravity feed path from the BAT to the CCP's was used when sparging the BAT with nitrogen. "Note: The level values for the Boric Acid Storage Tank (BAST) are non-conservative when using the gravity feed path from the BAST to the CCPs. The BAST levels are correct when using the path from the BAST to the Boric Acid Transfer Pump. The only place that it is incorrect is when using the BASTs to feed the CCPs through the gravity feed path when the BASTs have been sparged with nitrogen. This issue is being addressed in the corrective action program (SMF-2003-001212). In the interim, conservative limits for the BAST tanks levels have been identified in operations procedures. The conservative limits are: Gravity Feed to CCPUnit Mode BAT Temperature Required BAT Level1 1-4 "<or=" 110 degree F 63 percent1 1-4 "<or=" 95 degree F 56 percent1 1-4 "<or=" 80 degree F 53 percent CPSES - UNITS 1 AND 2 - TRMDOC-14Revision 84Technical Requirements Manual - Description of ChangesREVISION 64 (continued) LDCR-TR-2004-9 (EVAL-2003-001212-04) (TJE) (continued):2 1-4 "<or=" 110 degree F 95 percent2 1-4 "<or=" 95 degree F 89 percent2 1-4 "<or=" 80 degree F 86 percent"Remove the Note and the Tables in TRS 13.1.31.3 which required specific BAT levels and BAT temperatures to be maintained during startup and shutdown modes when the gravity feed path from the BAT to the CCP's was used when sparging the BAT with nitrogen. "Note: The level values for the Boric Acid Storage Tank (BAST) are non-conservative when using the gravity feed path from the BAST to the CCPs. The BAST levels are correct when using the path from the BAST to the Boric Acid Transfer Pump. The only place that it is incorrect is when using the BASTs to feed the CCPs through the gravity feed path when the BASTs have been sparged with nitrogen. This issue is being addressed in the corrective action program (SMF-2003-001212). In the interim, conservative limits for the BAST tanks levels have been identified in operations procedures. The conservative limits are: Gravity Feed to CCPUnit Mode BAT Temperature Required BAT Level1 1-4 "<or=" 110 degree F 63 percent1 1-4 "<or=" 95 degree F 56 percent1 1-4 "<or=" 80 degree F 53 percent2 1-4 "<or=" 110 degree F 95 percent 2 1-4 "<or=" 95 degree F 89 percent2 1-4 "<or=" 80 degree F 86 percent"Remove the Note and the Tables in the Background section of TRB 13.1.32 which required specific BAT levels and BAT temperatures to be maintained during startup and shutdown modes when the gravity feed path from the BAT to the CCP's was used when sparging the BAT with nitrogen. "Note: The level values for the Boric Acid Storage Tank (BAST) are non-conservative when using the gravity feed path from the BAST to the CCPs. The BAST levels are correct when using the path from the BAST to the Boric Acid Transfer Pump. The only place that it is incorrect is when using the BASTs to feed the CCPs through the gravity feed path when the BASTs have been sparged with nitrogen. This issue is being addressed in the corrective action program (SMF-2003-001212). In the interim, conservative limits for the BAST tanks levels have been identified in operations procedures. The conservative limits are:

CPSES - UNITS 1 AND 2 - TRMDOC-15Revision 84Technical Requirements Manual - Description of ChangesREVISION 64 (continued) LDCR-TR-2004-9 (EVAL-2003-001212-04) (TJE) (continued):conservative limits for the BAST tanks levels have been identified in operations procedures. The conservative limits are: Gravity Feed to CCPUnit Mode BAT Temperature Required BAT Level1 1-4 "<or=" 110 degree F 63 percent1 1-4 "<or=" 95 degree F 56 percent1 1-4 "<or=" 80 degree F 53 percent 2 1-4 "<or=" 110 degree F 95 percent2 1-4 "<or=" 95 degree F 89 percent2 1-4 "<or=" 80 degree F 86 percent"Remove the Note and the Tables in TRS 13.1.32.4 and TRS 13.1.32.5 which required specific BAT levels and BAT temperatures to be maintained during startup and shutdown modes when the gravity feed path from the BAT to the CCP's was used when sparging

the BAT with nitrogen. "Note: The level values for the Boric Acid Storage Tank (BAST) are non-conservative when using the gravity feed path from the BAST to the CCPs. The BAST levels are correct when using the path from the BAST to the Boric Acid Transfer Pump. The only place that it is incorrect is when using the BASTs to feed the CCPs through the gravity feed path when the BASTs have been sparged with nitrogen. This issue is being addressed in the corrective action program (SMF-2003-001212). In the interim, conservative limits for the BAST tanks levels have been identified in operations procedures. The conservative limits are: Gravity Feed to CCPUnit Mode BAT Temperature Required BAT Level1 1-4 "<or=" 110 degree F 63 percent1 1-4 "<or=" 95 degree F 56 percent1 1-4 "<or=" 80 degree F 53 percent2 1-4 "<or=" 110 degree F 95 percent 2 1-4 "<or=" 95 degree F 89 percent2 1-4 "<or=" 80 degree F 86 percent" LDCR-TR-2005-6 (EVAL-2005-002551-01) (TJE):1.) In the second paragraph on page 13.3-8, replace the last sentence which reads, "SR 3.3.1.2 Note 1 requires that the NIS and N-16 Power Monitor channels be adjusted if the absolute difference is > 2% RPT."

CPSES - UNITS 1 AND 2 - TRMDOC-16Revision 84Technical Requirements Manual - Description of ChangesREVISION 64 (continued) LDCR-TR-2005-6 (EVAL-2005-002551-01) (TJE) (continued):with the words, "SR 3.3.1.2 requires that the NIS Power Range channels be adjusted if the calorimetric heat balance calculation results exceed the NIS Power Range indication by more than +2% RTP, and the N-16 Power Monitor channels be adjusted if the calorimetric heat balance calculation results exceed the N-16 Power Monitor indication by more than +2% RTP."2.) In the second sentence of the third paragraph on page 13.3-8, replace the "+-" with a "+". The sentence will be revised to read, "At that time, the NIS and N-16 power indications must be normalized to indicate within at least + 2% RTP of the calorimetric measurement."Please note that this change makes the TRM Bases consistent with NRC License Amendment 133.

REVISION 65 LDCR-TR-1999-12 (EVAL-2006-002367-01) (TJE):Add a new paragraph to the end of the TRM Bases LCO 13.1.32 to allow the required Boric Acid Storage Tank (BAST) flowpath to be considered OPERABLE during BAST recirculation if capable of being manually realigned to the injection flowpath.When recirculating the BAST, manual action to align the required flowpath to the injection mode consists of locally closing one valve, XCS-8477A for BAST X-01 or XCS-8477B for BAST X-02. The Technical Requirement specifically credits the gravity feed path as one acceptable flowpath. The gravity feed flowpath must be manually aligned by operating valves locally. Also, other Technical Specifications (for example TS 3.5.3) provide an allowance to take credit for manually realigning required flowpaths. Providing the flexibility to take credit for the capability of manual realignment of the required flowpath will allow operation of the BA System to maintain proper chemistry control of the required borated water source when the alternate source and/or flowpath is unavailable.This change will make the TRM consistent with OPS procedure SOP-105.

Add the following words to the last paragraph of Bases LCO 13.1.31 on page B 13.1-3,"An OPERABLE Boration Injection System is required to be capable of being manually aligned when boration is required, and in all cases within 15 minutes, to establish boration flow. When local manual control is being credited, administrative controls are utilized to ensure 1) appropriate personnel are aware of the status of the Boration Injection System, and 2) specified individuals are designated and readily available to perform the valve alignment necessary to establish boration flow."

CPSES - UNITS 1 AND 2 - TRMDOC-17Revision 84Technical Requirements Manual - Description of ChangesREVISION 65 (continued) LDCR-TR-1999-12 (EVAL-2006-002367-01) (TJE) (continued):Add the following new paragraph to the end of the Bases LCO 13.1.32 on page B 13.1-10,"An OPERABLE Boration Injection System is required to be capable of being manually aligned when boration is required, and in all cases within 15 minutes, to establish boration flow. When local manual control is being credited, administrative controls are utilized to ensure 1) appropriate personnel are aware of the status of the Boration Injection System, and 2) specified individuals are designated and readily available to perform the valve alignment necessary to establish boration flow." LDCR-TR-2006-2 (EVAL-2006-000569-01) (TJE):In the Background section of the TRM Bases TRM, 13.1-1, replace the second paragraph which reads, "The components required to perform this function include: (1) borated water sources, (2) charging pumps, (3) separate flow paths, (4) boric acid transfer pumps, and (5) an emergency power supply from OPERABLE diesel generators." with the words, "The components required to perform this function in MODES 1, 2, 3, and 4 include: (1) borated water sources, (2) pumps, (3) separate flow paths, and (4) the associated train Class 1E bus power supplies."In the TRM Bases section 13.1.32, page 13.1-8, insert the following paragraph after the first paragraph in the Background section, "The components required to perform this function in MODES 5 and 6 include: (1) a borated water source, (2) pump(s), (3) a functional flow path and (4) the associated train Class 1E bus power supply." LDCR-TR-2007-9 (EVAL-2006-002367-02) (TJE):Technical Specifications was revised via LDCR TS-2006-001 (EVAL-2006-000627 01) reflect current organizational titles per letter CPSES-200502468-01-01.TS 5.1.1, 5.2.1, 5.2.2.d, 5.5.1.b, and 5.5.17 use to specify that the Plant Manager is responsible for the designated functions described by the respective Specification with a Note stating these "Duties may be performed by the Vice President of Nuclear Operations if that organizational position is assigned." This Note was deleted from the Technical Specifications. There are no changes to the prerequisite qualifications for the position, the assigned responsibilities, or the organizational reporting relationships for the Plant Manager or the Site Vice President, formerly the Vice President, Nuclear Operations.

CPSES - UNITS 1 AND 2 - TRMDOC-18Revision 84Technical Requirements Manual - Description of ChangesREVISION 65 (continued) LDCR-TR-2007-9 (EVAL-2006-002367-02) (TJE) (continued):LDCR TR-2007-009 proposes to delete this Note in accordance with LDCR TS-2006-001 (EVAL-2006-000627-01-01) and is an administrative change which will make the TRM more accurately reflect the current, and expected future, organizational structure at CPSES.In 15.5.17.d, delete the "*" after the words "Plant Manager" and delete the note at the bottom of the page that says, "* Duties may be performed by the Vice President of Nuclear Operations if that organizational position is assigned." LDCR-TR-2007-12 (EVAL-2006-000569-02) (TJE):Correct TRM Table number from 13.10.31-11 tp 13.10.31-1 REVISION 66 LDCR-TR-2007-5 (EVAL-2004-002063-13) (TJE):On TRM Table 13.8.32-1a, Page 7 of 13, section 3.3, delete "or THFK" from the description of the system powered and delete the following breaker information from the table:"7F THFK Electric H2 Recombiner Power Supply PNL 01" On TRM Table 13.8.32-1a, Page 8 of 13, section 3.4, delete "or THFK" from the description of the system powered and delete the following breaker information from the table:"6F THFK Elect. H2 Recombiner Power Supply PNL 02" On TRM Table 13.8.32-1b, Page 7 of 14, section 3.3, delete "or THFK" from the description of the system powered and delete the following breaker information from the table:"7F THFK Electric H2 Recombiner Power Supply PNL 01" On TRM Table 13.8.32-1b, Page 8 of 14, section 3.4, delete "or THFK" from the description of the system powered and delete the following breaker information from the table:"6F THFK Elect. H2 Recombiner Power Supply PNL 02" CPSES - UNITS 1 AND 2 - TRMDOC-19Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2007-11 (EVAL-2006-000629-02) (TJE):

Technical Justification: The primary basis for TR LCO 13.9.31 is to ensure sufficient fission product decay prior to fuel movement such that anticipated doses resulting from a postulated fuel handling accident (FHA) would not exceed regulatory limits. The proposed change is expected to increase the dose consequences of a FHA and, as a result, the accident analysis for this event was revised and is documented in WPT-16939. The revised analysis results demonstrate that calculated accident doses to personnel both offsite and in the control room at the above conditions increase slightly, however all are well within the limits specified in Regulatory Guide 1.195 and 10CFR100. The revised FHA results have been incorporated into DBD-ME-027 Rev. 9.On page 13.9-1, change 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> to 75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br /> in TR LCO 13.9.31, Condition A, and in TRS 13.9.31.1Replace the words in TRB 13.9.31, "Decay Time," which read, "The minimum requirement for reactor subcriticality prior to movement of irradiated fuel assemblies in the reactor vessel ensures that sufficient time has elapsed to allow the radioactive decay of the short-lived fission products. This decay time is consistent with the assumptions used in the safety analyses." with the words, "The minimum required time for reactor subcriticality prior to movement of irradiated fuel assemblies in the reactor vessel ensures sufficient radioactive decay of those fission products that contribute to the radiological consequences of a postulated fuel handling accident. Per Regulatory Guide 1.195, these fission products include xenon, krypton and iodine whose activity is assumed to be instantaneously released to the refueling cavity during the accident. The fraction of iodine retained within the cavity is determined by the water depth above the damaged fuel assembly as specified in Technical Specifications LCO 3.9.7, "Refueling Cavity Water Level." Retention of noble gases within the cavity is negligible. Release of fission products from the refueling cavity to the environment

occurs over a 2-hour time period. The required decay time and the water level requirement of Technical Specifications LCO 3.9.7 ensure the control room, exclusion area boundary, and low population zone dose limits of References 1, 3 and 4 are met following a fuel handling accident within containment. The assumptions for a fuel handling accident occurring within the fuel building are similar and the radiological consequences are equivalent. The required decay time is consistent with the assumptions used in the safety analysis (Ref. 5)."REFERENCES 1. Regulatory Guide 1.195, May 2003 2. Technical Specifications

3. 10CFR100 CPSES - UNITS 1 AND 2 - TRMDOC-20Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2007-11 (EVAL-2006-000629-02) (TJE) (continued): 4. Appendix A to 10CFR50, General Design Criteria 19 5. FSAR Section 15.7.4" REVISION 67 LDCR-TR-2007-3 (EVAL-2005-002580-02) (TJE):Change the frequency of TRS 13.3.33.2 from every "12" weeks to every "26" weeks as approved by NRC in License Amendment 143 issued on 2/29/08.1.) In TRS 13.3.33.1, change the words "References 2 and 4" to "Reference 2"2.) In TRS 13.3.33.2, a.) insert "manual test or the" in first sentence before ATT, and b.) change the frequency from "12" weeks to "26" weeks and change Reference "4" to "5".In the Reference section B 13.3, 1.) delete the VL number from Reference 32.) replace Reference 4 with the word "Deleted" In the Reference section B 13.3,1.) for Reference 5, change the revision from "4" to "5", change the date from "October 29, 2004" to "January 18, 2007," and delete the VL number.2.) Correct a typo by changing "59EV-2004-000774-01" to "59EV-2004-000773-01" and "59EV-2004-000774-02" to "59EV-2004-000773-02."3.) Add Reference 8, "LDCR TR-2007-003, Change TRS 13.3.33.2 Frequency from 12 weeks to 26 weeks, EVAL-2005-002580-02."In B 13.3 of the Applicable Safety analyses second sentence of first paragraph, change "Using References 3 through 5"to "Using References 3 and 5"In the Actions sections of the second paragraph, change "If an HP" to "If a HP"In the Actions section under B.1, B.2, and B.3 second paragraph, first sentence, replace "If an LP" with "If a LP" CPSES - UNITS 1 AND 2 - TRMDOC-21Revision 84Technical Requirements Manual - Description of Changes REVISION 68 LDCR-TR-2007-6 (EVAL-2006-004119-03) (TJE):The PDMS instrumentation does not change any of the key safety parameter limits or levels of margin as considered in the reference design basis evaluations.Add new TR section 13.2.34 which will read, "TR 13.2.34 Power Distribution Monitoring System 13.2-6"The PDMS instrumentation does not change any of the key safety parameter limits or levels of margin as considered in the reference design basis evaluations.In the Applicability section of TR 13.2.32, 1.) change 15% to 50% and 2.) add a note that says, "Mode 1 with THERMAL POWER "greater than or equal to" 15%

RTP during Unit 1, Cycle 13"The PDMS instrumentation does not change any of the key safety parameter limits or levels of margin as considered in the reference design basis evaluations.1.) In TRS 13.2.32.1 Surveillance Notes, a.) In Note 1, delete the words, "and for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after restoring to OPERABLE status"b.) Add Note 3 that will read, "Only required to be performed for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after restoring the AFD Monitor Alarm to OPERABLE status during Unit 1, Cycle 13.2.) In TRS 13.2.32.1 Frequency note, add "for Unit 1, cycle 13" after the words "Only required."The PDMS instrumentation does not change any of the key safety parameter limits or levels of margin as considered in the reference design basis evaluations.Add the new TR 13.2.34, "Power Distribution Monitoring System" REVISION 69 LDCR-TR-2008-1 (EVAL-2006-003080-16) (TJE):In TR 13.3.34,1.) Delete the "*" in the Applicability section2.) Required Actions B.1 and B.3, delete "(3411 MWth), and CPSES - UNITS 1 AND 2 - TRMDOC-22Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2008-1 (EVAL-2006-003080-16) (TJE) (continued):3.) Delete the note at the bottom of the page that says, "*This TRM requirement applies to Unit 2 only until implementation of the 1.4% uprate for Unit1 during 1RF09."Revise 13.3.34 Plant Calorimetric Measurement to show Unit differences. For Unit 2 Cycle 11, the RATED THERMAL POWER is 3458 MWth, and the core power should be reduced to 3411 MWth if the LEFMv is unavailable. For Unit 1, the RATED THERMAL POWER is 3612 MWth, and the core power should be reduced to 3562 if the LEFMv is unavailable.In the Reference sections, add the following three references:2. License Amendment Request (LAR)07-004, Revision to the Operating License and Technical Specifications 1.0, "Use and Application" and 3.7.17, "Spent Fuel Assembly Storage" to Revise Rated Thermal Power from 3458 MWth to 3612 MWth. Docket Nos.

50-445 and 50-446, CPSES.3. WCAP-16840-P, Rev. 0, Comanche Peak Nuclear Power Plant Stretch Power Uprate Licensing Report.4. License Amendment 146, Revision to the Operating License and Technical Specifications 1.0, "Use and Application" to Revise Rated Thermal Power from 3458 MWth to 3612 MWth. Docket Nos. 50-445 and 50-446, CPSES.

REVISION 70 LDCR-TR-2007-10 (EVAL-2007-002743-03) (TJE):

Relocate the TS detailed technical requirements for verifying equilibrium Containment emergency sump pH commensurate with Technical Specification (TS) Surveillance Requirement SR 3.6.7.1 to the TRM 13.6.7. ACTIONS for not verifying equilibrium Containment emergency sump pH is contained in Technical Specification 3.6.7. The performance test requirements for the Spray Additive System are subject to TS SR 3.6.7.1.This change affects the Containment Spray System which is intended to respond to and mitigate the effects of a LOCA. The Containment Spray System will continue to function in a manner consistent with the plant design basis. There will be no degradation in the performance of nor an increase in the number of challenges to equipment assumed to function during an accident situation. LDCR-TR-2008-3 (EVAL-2008-003080-1) (TJE):In the TRM Bases 13.3.33, Applicable Safety Analyses section, last sentence, replace "through" with "and".In TRM Bases 13.3.33, Reference 3, change 46 to 44.Deleted References 7 and 8 of TRM Bases 13.3.33.

CPSES - UNITS 1 AND 2 - TRMDOC-23Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2008-3 (EVAL-2008-003080-1) (TJE) (continued):In TRM 13.9.34 header, add an "a" to "Storge" to correctly spell Storage.

REVISION 71 LDCR-TR-2009-002 (EVAL-2009-001094-02) (RAS):Revises the limit for the OTN16 Reactor Trip function in Table 13.3.1-1 (item 6) to less than or equal to 3.3 seconds and footnote 2 to state "An additional 6 seconds maximum delay allowance for the RTD/thermal well response time provides an overall Overtemperature N-16 Response Time of less than or equal to 9.3 seconds for the Tcold input." REVISION 72 LDCR-TR-2009-003 (EVAL-2008-002987-03) (RAS):Replace the second NOTE for TRS 13.3.32.3 with the following "For the source range neutron detectors, performance data is obtained and evaluated."The bias curve that is described is for establishing the bias voltage to filter gamma pulses and provides no meaningful assessment of detector condition.

REVISION 73 LDCR-TR-2009-001 (EVAL-2009-000465-02) (RAS):Revise Table 13.3.1-1 to add a response time limit of </=650 msec for Positive Flux Rate Trip function to Table 13.3.1-1.

REVISION 74 LDCR-TR-2008-004 (EV-CR-2008-003510-00-5) (TJEW):Add the following words to the end of the first sentence of the fourth paragraph in TRB 13.3.5 for the discussion of the bases for LOP DG Start Instrumentation Response Times, "for continued operability of motors to perform their ESF function"Revise response times for the following signals and functions in TRM Table 13.3.5-1 (Page 1 of 1) "Loss of Power Diesel Generator Start Instrumentation Response Time Limits":A.) In number 2 and 3, replace "N/A" with "less than or equal to 1 second" and add note

"(1)" B.) In number 4, change note "(1)" to note "(2)"

CPSES - UNITS 1 AND 2 - TRMDOC-24Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2008-004 (EV-CR-2008-003510-00-5) (TJE) (continued):C.) The response times in numbers 5 and 7 currently says "less than or equal to 10" and has notes 1, 2, and 3 and "/ less than or equal to 63" with notes 1, 2, and 4.Replace response times 5 and 7 with "greater than or equal to 6 & less than or equal to 10 / less then or equal to 60". Add note 5 to the 6 seconds, notes 5 and 3 to the 10 seconds, and note 4 to the 60 seconds.D.) Delete the current response time in number 6 "less than or equal to 63" with notes 1 and 2. Replace the response time with "greater than or equal to 45" an add notes 6 and 3.E.) Replace notes 1, 2, 3, and 4 which currently say, "(1) Response time measured to output of undervoltage channel only.

(2) Two additional seconds allowable for alternate offsite source breaker trip functions.

(3) With SI (4) Without SI" with these notes below:"(1) Response time measured to output of under voltage channel providing the offsite source breaker trip signal.(2) Response time measured to output of under voltage channel providing the DG start signal.(3) An additional 3 seconds is allowed for the Alternate Offsite Source breaker trip signal and another 3 seconds is allowed for DG close permissive signal.(4) Response time measured to output of under voltage channel providing the Preferred and Alternate Offsite Source breakers trip signals after detection of degraded Voltage condition, in the absence of SIAS. "(5) Response time measured to output of under voltage channel to confirm degraded condition for providing a Preferred Offsite Source breakers trip on subsequent occurrence of SIAS.(6) Response time measured to output of under voltage channel to confirm 480V bus low grid condition for providing a Preferred Offsite Source breakers trip on subsequent occurrence of SIAS.

CPSES - UNITS 1 AND 2 - TRMDOC-25Revision 84Technical Requirements Manual - Description of Changes REVISION 75 LDCR-TR-2010-002 (EV-CR-2007-003164-00-19) (TJEW):Technical Justification: The Fuel Handling Bridge Crane can initiate the fuel-handling accident described in FSAR Section 15.7.4. This requires dropping of a spent fuel assembly in the spent fuel pool fuel storage area floor resulting in the rupture of the cladding of all the fuel rods in the assembly. This accident is based upon dropping one spent fuel assembly, since FSAR Section 9.1.4.2.3.2 states that the FHBC carries one trolley-hoist assembly, which is the design of existing FHBC.In order to maintain credibility of the fuel handling accident the FHBC must not have ability to handle more than one fuel assembly at a time. This condition is maintained because the control station is interlocked so it controls only the trolley - hoist assembly under which it is located. On the other assembly the hoist hook must be raised fully up and empty, and be moved to the extreme east end of the trolley, before the control station

can control the assembly under it is located.The Trolley - Hoist assembly location is monitored and hardwired to permissive controls bypassing the PLC. An assembly must be in the east parking location before either the trolley or hoist of the opposite assembly is allowed to operate. The surveillance must test and the bases must reference these interlocks.On page 13.9-5 Add new Surveillance Requirement TRS 13.9.34.2, associated note, and frequency:

The note will read, "Only required to be performed when the hoist is being used to move loads over fuel assemblies in a spent fuel storage pool."The new Surveillance Requirement states, "Fuel Handling Bridge Crane interlocks which permit only one trolley-hoist assembly to be operated at a time shall be verified." The frequency will be 6 months.

On page B 13.9-4,1.) Add the header, "LCO" prior to the existing paragraph discussing TRS 13.9.34.1 2.) Indent the original paragraph next to the LCO header.3.) Next add the new TR Surveillance shown as follows:

TRS 13.9.34.2 In order to prevent more than a single fuel assembly being moved over other fuel assemblies in a storage pool, interlocks prevent control of a trolley-hoist assembly unless the opposite trolley-hoist assembly has the hook unloaded and completely up, and the trolley located in the far east end parking area.

CPSES - UNITS 1 AND 2 - TRMDOC-26Revision 84Technical Requirements Manual - Description of Changes REVISION 76 LDCR-TR-2011-001 (EV-CR-2010-004974-5) (RAS):

Adds a new section to TRM Table 13.7.39-1 to add allowances for removal of the EDG Missile Shield Barriers in rooms 1-084 (EDG CP1-MEDGEE-01), 1-085 (EDG CP1-MEDGEE-02), 2-084 (EDG CP2-MEDGEE-01), and 2-085 (EDG CP2-MEDGEE-02). The allowances establish new administrative controls for the Units 1 & 2 EDG missile resistant barriers and the associated Bases section TRB 13.7.39 to allow a section of the existing EDG missile barrier to be breached/opened for a limited time period without having to

declare the respective Train of EDG INOPERABLE.

REVISION 77 LDCR-TR-2011-002 (EV-CR-2011-004788-1) (JDS):Add Note to Modify the LCO to allow the use of additional hoists for special evolutions such an the unlatching of bent control rod drive shafts. This note is necessary to allow alignment of the CRDM unlatching tool to the CRDM shaft. In addition, Condition A and the associated Required Actions were modified to apply the immediate Completion Times for all hoists where OPERABILITY may not be satisfied.Surveillance requirement TRS 13.9.33.2 was modified to apply to other hoists and load indicators used to support unlatching of the CRDM shafts from the control rods.The Bases for TRM 13.9.33 was modified to provide a discussion regarding the note modifying the LCO to allow the use of additional hoists and load indicators for special evolutions. In addition, the text was modified to identify that the auxiliary hoist is "typically" used for unlatching of CRDM shafts from the control rods.

REVISION 78 LDCR-TR-2008-002 (EV-CR-2007-000920-20) (RAS):Justification: The breakers in the compartments listed above no longer perform overcurrent protection of containment penetration conductors. FDA-2007-000920-01 determinated the motor power leads inside MCCs 1EB1-2 and 1EB2-2 and made all affected breakers spares. FDA-2007-000920-2 ABANDON THE UNIT 1 SG CHEM FEED SYSTEM IN PLACE including these MCCs.From Table 13.8.32-1a (Page 5 of 193, FSAR page 13.8-11, remove MCC 1EB1-2 Compartment numbers 10F and 12M.Justification: The breakers in the compartments listed above no longer perform overcurrent protection of containment penetration conductors. FDA-2007-000920-01 determinated the motor power leads inside MCCs 1EB1-2 and 1EB2-2 and made all affected breakers spares.

From Table 13.8.32-1a (Page 6 of 13), FSAR page 13.8-12, remove MCC 1EB2-2 Compartment numbers 1M and 12M.

CPSES - UNITS 1 AND 2 - TRMDOC-27Revision 84Technical Requirements Manual - Description of Changes REVISION 79 LDCR-TR-2010-004 (EV-CR-2010-009959-1) (TJD):In the APPLICABILITY, replace the ">" symbol with a >

symbol.Correct the TRM 13.2.32 for AFD to be consistent with TS 3.2.3 for AFD.

Delete the entire NOTE prior to the ACTIONS section.Delete outdated information related to Constant Axial Offset Control (CAOC).Replace the existing CONDITION A with the following: "AFD Monitor Alarm inoperable."CONDITION A is being changed to more accurately reflect the purpose of TRM 13.2.32.Replace the existing REQUIRED ACTION A.1 with the following: "Perform TRS 13.2.32.1."REQUIRED ACTION A.1 is being changed to more accurately reflect the purpose of TRM 13.2.32.Delete SURVEILLANCE NOTES 2 and 3.

Delete outdated information related to Constant Axial Offset Control (CAOC).Delete the "1." from the first NOTE in the SURVEILLANCE NOTES section.After the TRM changes, there will be only one note and the "1." is no longer needed.

Delete the "S" from "-NOTES-" title in the SURVEILLANCE NOTES section.Make the NOTES title singular because after the changes there will be only one note.Delete all the text in the FREQUENCY section and replace it with the following:

"Once within 30 minutes AND1 hour thereafter."

Delete outdated information related to Constant Axial Offset Control (CAOC), and replace with a Frequency consistent with the new CONDITION A AND REQUIRED ACTION A.1.Delete all text from the first paragraph of Bases 13.2.32, except for the first sentence.Delete outdated information related to Constant Axial Offset Control (CAOC).

CPSES - UNITS 1 AND 2 - TRMDOC-28Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2010-004 (EV-CR-2010-009959-1) (TJD) (continued):Delete the following text from the second sentence of the second paragraph of Bases 13.2.32: "for the calculation of AFD penalty minutes for which a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> history is required" and replace it with the following text: "to increase the frequency of documented AFD monitoring while the AFD Monitor alarm is inoperable. The Surveillance Frequency of once within 30 minutes and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> thereafter is adequate because AFD is controlled by the operator and any deviations of AFD from TS LCO 3.2.3 requirements should be readily noticed. The initial Surveillance Frequency of once within 30 minutes is to support compliance with TS LCO 3.2.3 ACTIONS"Delete outdated information related to Constant Axial Offset Control (CAOC), and replace with information consistent with the new TRS 13.2.32.1 FREQUENCY.Delete the following text from the last sentence in Bases 13.2.32, "AFD penalty minute."Delete outdated information related to Constant Axial Offset Control (CAOC).

REVISION 80 LDCR-TR-2011-003 (EV-CR-2010-005809-9) (JCH):

Referenced Section: TR-15.5.31 Description of Change: Most of TR-15.5.31 page 15.0-2 through 15.0-8 will be deleted, no longer applicable and replaced with instruction to perform Snubber Inservice Program iwa Code OM-Sub-Section ISDT as follows:

TR 15.5.31 Snubber Inservice Testing/Inspection Program All snubbers are required OPERABLE to ensure that the structural integrity of the Reactor Coolant System and all other safety-related systems is maintained during and following a

seismic or other event initiating dynamic loads. The snubbers are grouped, visually examined, functionally tested, and maintained in accordance with ASME OM Code, Subsection ISTD, "Preservice and Inservice Examination and Testing of Dynamic Restraints (Snubbers) in Light-Water Reactor Nuclear Power Plants", Latest issue as mandated by 10CFR 50.55A for the current

interval. A list of individual snubbers with detailed information of snubber location and size and of system affected shall be available at the plant in the Unit-1 and Unit-2 Snubber inservice Program Plan. The addition or deletion of any hydraulic or mechanical snubber shall be made in accordance with Section 50.59 of 10 CFR Part 50. The service life of a snubber is established via manufacturer input and information through consideration of the snubber service conditions and associated installation and maintenance records (newly installed snubbers, seal replaced, spring replaced, in high radiation area, in high temperature area, etc.). The requirement to monitor the snubber service life is included to ensure that the snubbers periodically undergo a performance CPSES - UNITS 1 AND 2 - TRMDOC-29Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2011-003 (EV-CR-2010-005809-9) (JCH) (continued):evaluation in view of their age and operating conditions. These records will provide statistical bases for future consideration of snubber service life. Documentation shall be retained in accordance with FSAR 17.2.17.2.13Technical Justification: This change is due to conversion of our TRM controlled Snubber program to Code OM Sub-Section ISTD iaw RIS-2010-6.There are no commitments affected by this change.

There are no safety concerned elevated by this change, this is an enhancement to the Snubber inservice testing/inspection program and does not change how those tests and inspections are performed, documented nor are the results of testing or inspections modified in any way. LDCR-TR-2011-004 (EV-CR-2010-005809-8) (JCH):

Referenced Section: TRS-13.7.35.1Description of Change: Delete word, "augmented" and add the word, "testing" to TRS 13.7.35.1 Page 13.7.9 of the TRM.Technical Justification: Due to conversion of our TRM controlled Snubber program to Code OM Sub-Section ISDT iaw RIS-2010-6 the Snubber program is no longer augmented. The word testing is added as a clarification that this program is a snubber

inservice testing/inspection program.There are no commitments affected by this change.

There are no safety concerned elevated by this change, this is an enhancement to the Snubber inservice testing/inspection program and does not change how those tests and inspections are performed, documented nor are the results of testing or inspections modified in any way.

REVISION 81 LDCR-TR-2012-001 (EV-CR-2011-008700-6) (RAS):Add the following paragraph:"Due to the access opening in the operating deck of the circulating water discharge structure, the stop gates isolate the CW tunnels for lake levels below 778 feet only. Any opening in the CW system at an elevation below the probable maximum flood level of 789.7 feet must be closed or isolated in order to isolate the lake levels above778 from the open pathway that could lead to flooding of the Turbine Building and lower level of the Electrical & Control Building on elevation 778."

CPSES - UNITS 1 AND 2 - TRMDOC-30Revision 84Technical Requirements Manual - Description of Changes REVISION 82 LDCR-TR-2009-004 (EV-CR-2009-008637-2) (CBC):Pages 13.7-1, 2Pages B13.7-1, 2 The proposed License amendment would modify the TS by removing the specific isolation time for the isolation valves from the associated Technical Specification Surveillance Requirements (SR 3.7.2.1 - Main Steam Isolation Valves, SR 3.7.3.1 -

Feedwater Isolation Valves (FIVs), Feedwater Control Valves (FCVs), and bypass valves).The specific isolation time required to meet the TS Surveillance Requirements will be located outside of the TS in a document subject to control by the 10 CFR 50.59 process (i.e. Technical Requirements Manual TR 13.7.2)). The SR 3.7.2.1 to verify the isolation time remains in the Technical Specifications. The changes are consistent with Nuclear Regulatory Commission (NRC) approved Industry / Technical Specification Task Force (TSTF) TSTF-491 Revision 2. The availability of this TS improvement was announced in the Federal Register on December 29, 2006 (71FR78472) as part of the consolidated line item improvement process (CLIIP). LDCR-TR-2012-004 (EV-CR-2011-002186-25) (RAS):Add new TR 5.5.21 and associated Bases to relocate the Frequency for selected TS Surveillance Requirements from the Technical Specifications to a licensee-controlled Surveillance Frequency Control Program as approved in License Amendment 156. LDCR-TR-2012-002 (EV-CR-2012-006277-2) (CBC):Add new surveillance TRS 13.1.32.11:

"TRS 13.1.32.11 Demonstrate the required Safety Injection pump is OPERABLE by verifying, on recirculation flow, the requirements of the Inservice Testing Program are met for developed head." Frequency "In accordance with Inservice Testing Program" Basis for change:Utilization of a SI pump to fulfill the requirement to have an operable boration path in Mode 6 with thereactor head removed requires verification of the operability of the selected pump. Operability of theselected pump is based on the IST testing.

Replace the first sentence in the BACKGROUND section with the following:"A description of the CVCS Boration Injection System is provided in the Bases for TR 13.31.1, "Boration Injection System - Operating". Utilization of a SI pump for fulfillment of CPSES - UNITS 1 AND 2 - TRMDOC-31Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2012-002 (EV-CR-2012-006277-2) (CBC) (continued):TR 13.1.32 when in Mode 6 with the reactor head removed requires maintenance of a flow path from the RWST, through the selected pump, and into the RCS cold legs."Basis for Change:The existing text refers to CVCS boration paths (only) and refers back to TR 13.31.1 for a description of those flow paths.

At the end of the APPLICABLE SAFETY ANALYSES section, add (new item):"A safety injection pump and associated flow paths from the RWST and to the RCS cold legs can be utilized to fulfill TR 13.1.32 in Mode 6 with the reactor head removed. The requirements of TRS 13.1.32.1, TRS 13.1.32.6, TRS 13.1.32.7, TRS 13.1.32.8, and TRS 13.1.32.11 are applicable to this configuration. Refer to Reference 1 for details."Revise item "b." in the LCO section of TRB 13.1.32 (changed item) as follows:"Either a centrifugal charging pump or positive displacement charging pump or a safety injection pump (in Mode 6 with the reactor head removed only), and"Basis for Change" The existing text refers to CVCS boration paths (only) and the specified change simply adds the SI flow path and the associated limitation on its use.At the end of the TECHNICAL REQUIREMENTS SURVEILLLANCE section add the following (new item): "TRS 13.1.32.11 This surveillance requires verification that the selected SI pump is OPERABLE as determined by the Inservice Testing Program. This TRS is applicable only when a SI pump is being used as the required boration injection subsystem in Mode 6 with the reactor head removed. This TRS is analogous to TRS 13.1.32.10 for the centrifugal charging pump."Basis for Change:This new SR is applicable only when a SI pump is being used, i.e., in Mode 6 with the reactor head removed, and is analogous to TRS 13.1.32.10 for the centrifugal charging pump. This change to the Bases is required to support the (new) TR 13.1.32.11.Add a "REFERENCES" section to the end of the BASES for TR 13.1.32 as follows:REFERENCES 1. Westinghouse letter WPT-17618 to R. Flores, dated August 6, 2012, "LUMINANT COMANCHE PEAK NUCLEAR POWER PLANT UNIT 2, Boration Flow Path in Mode 6 with Reactor Vessel Head Removed" CPSES - UNITS 1 AND 2 - TRMDOC-32Revision 84Technical Requirements Manual - Description of Changes REVISION 83 LDCR-TR-2012-005 (EV-CR-2012-009618-1) (CBC):Thefrequencyfortheintegratedtestsequence/lossofoffsitepowertestingisrevisedfrom"18months"to"18monthsonaSTAGGEREDTESTBASIS".AsdocumentedinEV CR201100218621,thischangewasevaluatedandapprovedinaccordancewithTS5.5.21.

SurveillanceRequirementSource,Number(s)&Description(s):TechnicalSpecificationsSRslocatedinTRMTable15.5.21 1:

SRNo.Description3.5.2.5ECCSFlowpathValveActuationonSafetyInjection3.5.2.6ECCSPumpActuationonSafetyInjection3.6.3.8PhaseAValveActuationonSafetyInjection(18152only)3.7.5.3AFWValveAutomaticActuationonLossofOffsitePower3.7.5.4MDAFWPumpActuationonSafetyInjection3.7.7.3CCWPumpActuationonSafetyInjection3.7.8.3SSWPumpActuationonSafetyInjection3.7.10.3ControlRoomEmergencyRecirculationonLossofOffsitePower3.7.12.3PrimaryPlantVentilationActuationonSafetyInjection3.7.19.2SafetyChilledWaterPumpandChillerandSwitchgearAreaEmergencyFanCoilUnitActuationonSafetyInjection3.7.20.3UPSA/CTrainActuationonSafetyInjection3.8.1.9SingleLargestLoadRejection3.8.1.10FullLoadRejection3.8.1.11EmergencyBusLoadShed,DGStart,SequenceandRunonLossofOffsitePower3.8.1.13DGNonEmergencyTripSignalsBypassedonLossofOffsitePowerandSafetyInjection3.8.1.15DGHotRestart3.8.1.16DGSynchronizationandLoadTransfer3.8.1.17DGSafetyInjectionOverrideTest3.8.1.19EmergencyBusLoadShed,DGStart,SequenceandRunonSafetyInjectioninConjunctionwithLossofOffsitePower TechnicalRequirementsManual:

TRSNumberDescription13.7.37.1SafetyChilledWaterPumpandChillerandSwitchgearAreaEmergencyFanCoilUnitActuationonSafetyInjection13.8.31.3Diesel7000KWLoadLimitTheassociatedTRMBasesarealsoupdated.

CPSES - UNITS 1 AND 2 - TRMDOC-33Revision 84Technical Requirements Manual - Description of Changes REVISION 84 LDCR-TR-2012-006 (EV-CR-2012-011438-1) (CBC):The frequency for TRS 13.5.32.1 states "Once following completion of modifications to the ECCS subsystems that alter the subsystem flow characteristics." However, there is no discussion of this requirement in the TRM Bases. This change provides additional information with respect to the bases of this requirement as an enhancement. This change clarifes the basis of why this testing is performed, and when this testing frequency condition is met. The TRB number for "ECCS - Pump Line Flow Rates" is changed from

"13.5.31" to "13.5.32" (editorial correction).

TECHNICAL REQUIREMENTS MANUAL (TRM) BASES FORCOMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 AND 2 CPSES - UNITS 1 AND 2 - TRMB iRevision 84Table of ContentsB 13.0TECHNICAL REQUIREMENT APPLICABILITY..........................................B 13.0-1B 13.1REACTIVITY CONTROL SYSTEMS.....................................................B 13.1-1TRB 13.1.31Boration Injection System - Operating..............................................B 13.1-1TRB 13.1.32Boration Injection System - Shutdown.............................................B 13.1-8TRB 13.1.37Rod Group Alignment Limits and Rod Position Indicator.................B 13.1-13TRB 13.1.38Control Bank Insertion Limits...........................................................B 13.1-14TRB 13.1.39Rod Position Indication - Shutdown.................................................B 13.1-15B 13.2POWER DISTRIBUTION LIMITS...........................................................B 13.2-1TRB 13.2.31Moveable Incore Detection System..................................................B 13.2-1 TRB 13.2.32Axial Flux Difference (AFD)..............................................................B 13.2-2TRB 13.2.33Quadrant Power Tilt Ratio (QPTR) Alarm........................................B 13.2-3TRB 13.2.34Power Distribution Monitoring System.............................................B 13.2-4B 13.3INSTRUMENTATION.............................................................................B 13.3-1TRB 13.3.1Reactor Trip System (RTS) Instrumentation Response Times........B 13.3-1 TRB 13.3.2Engineered Safety Features Actuation System (ESFAS) Instrumentation Response Times...............................................B 13.3-2TRB 13.3.5Loss of Power (LOP) Diesel Generator (DG) Start InstrumentationResponseTimes...............................................B 13.3-3TRB 13.3.31Seismic Instrumentation...................................................................B 13.3-4TRB 13.3.32Source Range Neutron Flux.............................................................B 13.3-5 TRB 13.3.33Turbine Overspeed Protection.........................................................B 13.3-7TRB 13.3.34Plant Calorimetric Measurement......................................................B 13.3-10B 13.4REACTOR COOLANT SYSTEM............................................................B 13.4-1TRB 13.4.14Reactor Coolant System (RCS) Pressure Isolation Valves..............B 13.4-1TRB 13.4.31Loose Parts Detection System.........................................................B 13.4-2 TRB 13.4.33 Reactor Coolant System (RCS) Chemistry....................................B 13.4-3TRB 13.4.34Pressurizer.......................................................................................B 13.4-4TRB 13.4.35Reactor Coolant System (RCS) Vents Specification........................B 13.4-5B 13.5EMERGENCY CORE COOLING SYSTEMS (ECCS)............................B 13.5-1TRB 13.5.31ECCS - Containment Debris............................................................B 13.5-1 TRB 13.5.32ECCS - Pump Line Flow Rates........................................................B 13.5-2B 13.6CONTAINMENT SYSTEMS...................................................................B 13.6-1TRB 13.6.3Containment Isolation Valves...........................................................B 13.6-1 TRB 13.6.6Containment Spray System..............................................................B 13.6-2TRB 13.6.7Spray Additive System.....................................................................B 13.6-3B 13.7PLANT SYSTEMS..................................................................................B 13.7-1TRB 13.7.2Main Steam Isolation Valves (MSIVs)..............................................B 13.7-1TRB 13.7.3Feedwater Isolation Valves (FIVs) and Feedwater ControlValves (FCVs) and Associated Bypass Valves..........................B 13.7-2TRB 13.7.31Steam Generator Atmospheric Relief Valve (ARV) - Air Accumulator Tank.................................................................B 13.7-3(continued)

Table of Contents (continued)CPSES - UNITS 1 AND 2 - TRMB iiRevision 84TRB 13.7.32Steam Generator Pressure / Temperature Limitation......................B 13.7-4TRB 13.7.33Ultimate Heat Sink - Sediment and Safe Shutdown Impoundment (SSI) Dam............................................................B 13.7-5TRB 13.7.34Flood Protection...............................................................................B 13.7-6TRB 13.7.35Snubbers..........................................................................................B 13.7-7TRB 13.7.36Area Temperature Monitoring..........................................................B 13.7-8TRB 13.7.37Safety Chilled Water System - Electrical Switchgear AreaEmergency Fan Coil Units..........................................................B 13.7-9TRB 13.7.38Main Feedwater Isolation Valve Pressure / Temperature Limit........B 13.7-10 TRB 13.7.39Tornado Missile Shields...................................................................B 13.7-11TRB 13.7.41Condensate Storage Tank (CST) Make-up and Reject Line Isolation Valves...................................................................B 13.7-13B 13.8ELECTRICAL POWER SYSTEMS........................................................B 13.8-1TRB 13.8.31AC Sources (Diesel Generator Requirements)................................B 13.8-1 TRB 13.8.32Containment Penetration Conductor Overcurrent Protection Devices......................................................................B 13.8-2B 13.9REFUELING OPERATIONS..................................................................B 13.9-1TRB 13.9.31Decay Time......................................................................................B 13.9-1TRB 13.9.32Refueling Operations / Communications..........................................B 13.9-2TRB 13.9.33Refueling Machine............................................................................B 13.9-3 TRB 13.9.34Refueling - Crane Travel - Spent Fuel Storage Areas......................B 13.9-4TRB 13.9.35Water Level, Reactor Vessel, Control Rods.....................................B 13.9-5TRB 13.9.36Fuel Storage Area Water Level........................................................B 13.9-6B 13.10EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAM.............................................................................................B 13.10-1TRB 13.10.31Explosive Gas Monitoring Instrumentation.......................................B 13.10-1TRB 13.10.32Gas Storage Tanks..........................................................................B 13.10-2TRB 13.10.33Liquid Holdup Tanks.........................................................................B 13.10-3 TRB 13.10.34Explosive Gas Mixture......................................................................B 13.10-4B 15.5PROGRAMS AND MANUALS...............................................................B 15.0-1TRB 15.5.21Surveillance Frequency Control Prgoram........................................B 15.0-1 TR LCO and TRS ApplicabilityTRB 13.0CPSES - UNITS 1 AND 2 - TRMB 13.0-1Revision 56B 13.0 TECHNICAL REQUIREMENT (TR)

LIMITING CONDITION FOR OPERABILITY (TR LCO)AND TECHNICAL REQUIREMENT SURVEILLANCE (TRS) APPLICABILITY BASESRelated information is located in Technical Specification Bases 3.0.

Boration Injection System - OperatingTRB 13.1.31CPSES - UNITS 1 AND 2 - TRMB 13.1-1Revision 82B 13.1 REACTIVITY CONTROL SYSTEMSTRB 13.1.31 Boration Injection System - Operating BASESBACKGROUNDThe Boration Injection System is a subsystem of the Chemical and Volume Control System (CVCS). The CVCS regulates the concentration of chemical neutron absorber (boron) in the Reactor Coolant System (RCS) to control reactivity changes. The Boration Injection System ensures that negative reactivity control is available during each MODE of facility operation. The amount of boric acid stored in the borated water sources exceeds the amount required to bring the reactor to hot shutdown and to compensate for subsequent xenon decay. The shutdown reactivity requirements are specified in Technical Specifications LCO 3.1.1 , "SHUTDOWN MARGIN (SDM)," LCO 3.1.5 , "Shutdown Bank Insertion Limits," LCO 3.1.6, "Control Bank Insertion Limits," and LCO 3.9.1 , "Boron Concentration."The components required to perform this function in MODES 1, 2, 3, and 4 include: (1) borated water sources, (2) pumps, (3) separate flow

paths, and (4) the associated train Class 1E bus power supplies.Boric acid is stored in two boric acid tanks (BATs). Each BAT has a total volume of 46,000 gallons. The combined boric acid tank capacity is sized to store sufficient boric acid solution for refueling plus enough for a cold shutdown from full power operation immediately following refueling with the most reactive control rod not inserted. The two boric acid tanks are shared between Units 1 and 2. Two boric acid transfer pumps are provided for each unit with one pump normally required to provide boric acid to the suction header of the charging pumps, and the second pump in reserve. They are both aligned to take suction from separate boric acid tanks. On a demand signal by the reactor makeup controller, the pump starts and delivers boric acid to the suction header of the charging pumps. The pump can also be used to recirculate the boric acid tank fluid.The Refueling Water Storage Tank (RWST) is also credited with being a required borated water source. The charging pumps and RWST are available to support the core cooling function in the event of a loss of coolant accident. Two charging pumps may be manually aligned, as necessary, to inject borated water from the RWST to the RCS for negative reactivity control. OPERABILITY of the charging pumps, the RWST, and appropriate core cooling flow paths are required as part of the Emergency Core Cooling System (ECCS). The Technical

Specifications in Section 3.5 address the ECCS core cooling requirements.(continued)

Boration Injection System - OperatingTRB 13.1.31 BASESCPSES - UNITS 1 AND 2 -TRMB 13.1-2Revision 82 BACKGROUND (continued)As listed below, the required indicated levels for the boric acid storage tanks and the RWST include allowances for required/analytical volume, unusable volume, measurement uncertainties (which include instrument error and tank tolerances, as applicable), margin, and other required volume.

• Additional volume required to meet Technical Specification 3.5.4

. APPLICABLE

SAFETY ANALYSESThe Boration Injection System is not assumed to be OPERABLE to mitigate the consequences of a design basis accident (DBA) or transient.

However, the Boration Injection System satisfies, in part, General Design Criteria 26. In the event of a malfunction of the CVCS, which may cause a boron dilution event, manual operator action is to ensure the primary water makeup control valves in the Reactor Makeup System are closed. The Boration Injection System is required to be OPERABLE to provide sufficient boration flow paths to accomplish (1) chemical shim reactivity control, and (2) boration in the event SDM is discovered to be outside the Technical Specification limit. The primary method of boration is performed from the BAT(s). An acceptable alternative form of boration is boron injection from the RWST. With the RCS average temperature above 200°F, two boron injection subsystems are required to ensure single functional capability in the event an assumed failure renders the flow path from one subsystem inoperable. The boration capability of either flow path is sufficient to provide the required SHUTDOWN MARGIN from expected operating conditions after xenon decay and cooldown to 200ºF. The maximum expected boration capability requirement occurs at EOL from full power equilibrium xenon conditions and requires 15,700 gallons of 7000ppm borated water from the boric acid storage tanks or 70,702 gallons of 2400 ppm borated water from the refueling water storage tank (RWST).(continued)TankMODESInd.LevelUnusable Volume (gal)Required Volume (gal)Measurement UncertaintyMargin (gal)Other (gal)RWST1, 2, 3, 495%45,49470,7024% of spanN/A357,535*BAT1, 2, 3, 450%3,22115,7006% of spanN/AN/A Boration Injection System - OperatingTRB 13.1.31 BASESCPSES - UNITS 1 AND 2 -TRMB 13.1-3Revision 82LCOTwo boration injection subsystems are defined as:1.Two of the following three injection flow paths: (a) the flow path from the boric acid storage tanks via either a boric acid transfer pump or a gravity feed connection and a charging pump to the RCS, and (b) two flow paths from the RWST via a centrifugal

charging pump to the RCS, and, 2.Two centrifugal charging pumps (Note 2 allows the use of the positive displacement pump in lieu of a centrifugal charging pump in Mode4), and,3.One borated water source(s) (BAT and/or RWST) as required to support the injection flow paths of number 1 above.The LCO is modified by Note 1, which allows operation in MODE 3 and 4 with CCPs made incapable of injecting pursuant to TS 3.4.12 , "Low Temperature Overpressure Protection (LTOP) System," for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or until temperature of all RCS cold legs exceeds 375°F. This allowance is necessary since the LTOP arming temperature is below the MODE 3 boundary temperature of 350°F. Since TS 3.4.12 requires certain pumps be rendered incapable of injecting at and below the LTOP arming temperature, time is needed to restore the inoperable pumps to OPERABLE status following entry into MODE 3. This TRM Note is consistent with Note 2 to TS3.5.2 , "ECCS - Operating." The limitation for a maximum of two charging pumps to be OPERABLE and the requirement to verify one charging pump to be inoperable below 350°F provides assurance that a mass addition pressure transient can be relieved by the operation of a single PORV.An OPERABLE Boration Injection System is required to be capable of being manually aligned when boration is required, and in all cases within 15 minutes, to establish boration flow. When local manual control is being credited, administrative controls are utilized to ensure 1) appropriate personnel are aware of the status of the Boration Injection System, and 2) specified individuals are designated and readily available to perform the valve alignment necessary to establish boration flow.APPLICABILITYThe OPERABILITY of two boration injection subsystems ensures that the Boration Injection System is available for reactivity control while the unit

is operating in MODES 1, 2, 3 and 4. (continued)

Boration Injection System - OperatingTRB 13.1.31 BASESCPSES - UNITS 1 AND 2 -TRMB 13.1-4Revision 82ACTIONSA.1If one boration injection subsystem is inoperable (except due to an inoperable required charging pump), action must be taken to restore the subsystem to OPERABLE status. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time takes into account the redundant capabilities afforded by the remaining OPERABLE boration injection subsystem and reasonable time for repairs. The Completion Time is consistent with the time allowed to restore an ECCS train to OPERABLE status.

B.1If one boration injection subsystem is inoperable due to an inoperable charging pump, action must be taken to restore the required charging pump to OPERABLE status. The 7 day Completion Time takes into account the redundant capabilities afforded by the remaining OPERABLE charging pump and reasonable time for repairs.

C.1 and C.2If both the required boration injection subsystems are inoperable the Boration Injection System may not be capable of supporting the negative reactivity control function. Therefore, immediate action must be taken to restore at least one subsystem to OPERABLE status. Action must continue until one boration subsystem is restored to OPERABLE status. If both the required boration injection subsystems are inoperable or if an inoperable boration injection subsystem(s) cannot be returned to OPERABLE status within the associated Completion Time for reasons other than the inoperability of a required centrifugal charging pump, an engineering evaluation under the Corrective Action Program (CAP) is immediately initiated, consistent with TR 13.0 , Applicability NOTE 1.

Using NRC guidance (e.g., Generic Letter 91-18) for resolution of degraded and nonconforming conditions, the engineering evaluation for continued operation should include a risk-informed assessment of current plant conditions (e.g., operating Mode, inoperable equipment, planned maintenance evolutions, etc.) and identify actions (compensatory and/or corrective) and associated completion times necessary to maintain the unit in a safe condition. Example compensatory actions while corrective actions are pursued might include suspension of activities that could result in positive reactivity changes if in Modes 3 or 4 or suspending high risk work activities if maintaining the unit at power.If a required centrifugal charging pump cannot be restored to OPERABLE status within the associated Completion Time, the(continued)

Boration Injection System - OperatingTRB 13.1.31 BASESCPSES - UNITS 1 AND 2 -TRMB 13.1-5Revision 82LCOC.1 and C.2 (continued) requirements of Technical Specification 3.5.2 , Condition C should be applied if in MODES 1, 2 or 3; Technical Specification 3.5.3 , Condition C should be applied if in MODE 4.The need for additional conditions and actions, beyond those described in Conditions A and B, are to be controlled in accordance with the corrective action program until the equipment is restored to OPERABLE status. The provision for using the corrective action program to address situations beyond the TRM LCO Conditions is not intended to be used merely as an operational convenience to extend allowed outage time intervals beyond those specified.

TECHNICAL REQUIREMENTS SURVEILLANCE TRS 13.1.31.1This TRS requires verification that the boration flow path for the required BAT(s) and boron solution temperature of the required BAT(s) is greater than 65°F. This temperature is sufficient to prevent boric acid crystal

from precipitating for the highest allowed concentration of boric acid in the BATs.The Frequency of 7 days for performance of the surveillance has been shown to be acceptable through operating experience and is consistent with the Technical Specification surveillance Frequency for verifying the RWST boron solution temperature.TRS 13.1.31.2This TRS requires a verification of the boron solution concentration of the required BAT(s) every 7 days. The minimum boron solution concentration requirements of the required BAT(s), along with the boron solution volume requirements, ensure cold shutdown boron weight is available for injection (i.e., SDM equivalent to 1.3% k/k at 200°F). The Frequency to verify boron concentration is appropriate since the BAT boron solution concentration is normally stable and has been shown to be acceptable through operating experience. In addition, the Frequency is consistent with the Technical Specification surveillance Frequency for verifying the RWST boron solution concentration.TRS 13.1.31.3This surveillance requires verification that the BAT boron solution volume is at least 50%. The minimum boron solution volume, along with the (continued)

Boration Injection System - OperatingTRB 13.1.31 BASESCPSES - UNITS 1 AND 2 -TRMB 13.1-6Revision 82 TECHNICAL REQUIREMENTS SURVEILLANCE TRS 13.1.31.3 (continued)boron solution concentration requirements, ensures cold shutdown boron weight is available for injection (i.e., SDM equivalent to 1.3% k/k at 200°F). The boron solution volume limit of the RWST is specified in Technical Specification 3.5.4 and ensures sufficient volume is available to inject the required cold shutdown boron weight including any unusable volume. The 7day Frequency to verify boron solution volume is appropriate since the BAT volumes are normally stable and has been shown to be acceptable through operating experience. In addition, the

Frequency is consistent with the Technical Specification surveillance Frequency for verifying the RWST boron solution volume.

TRS 13.1.31.4Verifying the correct alignment for each boration injection subsystem manual, power operated, and automatic valve provides assurance that the proper flow paths exist for boration injection subsystem operation. This TRS does not apply to valves that are locked, sealed, or otherwise secured in position, since they are verified to be in the correct position prior to being locked, sealed, or secured. A valve may be in the non boration injection position provided the valve is capable of being manually repositioned to the boration injection position. This TRS does does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This TRS does not apply to valves that cannot be inadvertently misaligned, such as check valves.The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve position.TRS 13.1.31.5Verification that the flow path from the BATs delivers at least 30 gpm to the RCS demonstrates that gross degradation of the boric acid transfer pumps, CCPs, crystallization of boric acid in the boration injection subsystems, and other hydraulic component problems have not occurred. The 18 month Frequency was developed considering it is prudent that this Surveillance be performed during a plant outage. This is due to the plant conditions needed to perform the TRS and the potential for unplanned plant transients if the TRS is performed with the

reactor at power.(continued)

Boration Injection System - OperatingTRB 13.1.31 BASESCPSES - UNITS 1 AND 2 -TRMB 13.1-7Revision 82 TECHNICAL REQUIREMENTS SURVEILLANCE (continued)

TRS 13.1.31.6Periodic surveillance testing of CCPs to detect gross degradation caused by impeller structural damage or other hydraulic component problems is performed in accordance with Section XI of the American Society of Mechanical Engineers (ASME) Code. This type of testing may be accomplished by measuring the pump developed head at only one point of the pump characteristic curve. This verifies both that the measured performance is within an acceptable tolerance of the original pump baseline performance and that the performance at the test flow is greater than or equal to the performance assumed in the plant safety analysis. The activities and Frequencies necessary to satisfy the requirements of this TRS are accomplished with the performance of SR 3.5.2.4

.TRS 13.1.31.7Periodic surveillance testing of the positive displacement pump is performed to ensure that it meets the minimum flow requirements of the Boron Injection System when used in lieu of a CCP in Mode 4. This is accomplished by verifying that it delivers at least 30 gpm from a BAT to

the RCS per TRS 13.1.31.5. The 18 month Frequency was developed considering it is prudent that this Surveillance be performed during a

plant outage.

Boration Injection System - Shutdown TRB 13.1.32CPSES - UNITS 1 AND 2 - TRMB 13.1-8Revision 82B 13.1 REACTIVITY CONTROL SYSTEMSTRB 13.1.32 Boration Injection System - Shutdown BASESBACKGROUNDA description of the CVCS Boration Injection System is provided in the Bases for TR 13.31.1, "Boration Injection System-Operating". Utilization of a SI pump for fulfillment of TR 13.1.32 when in Mode 6 with the reactor head removed requires maintenance of a flow path from the RWST, through the selected pump, and into the RCS cold legs.

The components required to perform this function in MODES 5 and 6 include: (1) a borated water source, (2) pump(s), (3) a functional flow path and (4) the associated train Class 1E bus power supply.As listed below, the required indicated levels for the boric acid storage tanks and the RWST include allowances for required/analytical volume, unusable volume, measurement uncertainties (which include instrument error and tank tolerances, as applicable), margin, and other required volume. APPLICABLE SAFETY ANALYSESThe boration subsystem is not assumed to be OPERABLE to mitigate the consequences of a DBA or transient. However, the boration injection subsystem satisfies, in part, General Design Criteria 26. In the case of a malfunction of the Chemical and Volume Control System (CVCS), which caused a boron dilution event, an appropriate response by the operator is to isolate the source of primary water makeup.The boron injection capability requirement in conjunction with the cooldown capability identified in Branch Technical Position RSB 5-1 ensures the ability to reach cold shutdown conditions within a reasonable time period.In the determination of the required combination of boration flow rate and (continued)TankMODESInd.LevelUnusable Volume (gal)Required Volume (gal)Measurement Uncertainty Margin (gal)Other (gal)RWST5, 624%98,9007,1134% of span10,293N/ABAT5, 6 5, 6(gravityfeed)10%20%3,221 3,221 1,100 1,1006% of span6% of span N/A 3,679 N/A N/A Boration Injection System - Shutdown TRB 13.1.32 BASESCPSES - UNITS 1 AND 2 -TRMB 13.1-9Revision 82 APPLICABLE SAFETY ANALYSES (continued)boron concentration, there is no unique requirement that must be satisfied. Since it is imperative to raise the boron concentration of the Reactor Coolant System (RCS) as soon as possible, the boron concentration should be a highly concentrated solution, such as that normally found in the boric acid storage tank, or the Reactor Water Storage Tank (RWST). The operator should borate with the best source available for the plant conditions.With the RCS temperature below 200°F, one boron injection subsystem is acceptable without single failure consideration on the basis of the stable reactivity condition of the reactor and the additional restrictions prohibiting CORE ALTERATIONS and positive reactivity changes in the event the single boron injection subsystem becomes inoperable.The TS 3.4.12 limitation for a maximum of two charging pumps to be OPERABLE below 350°F provides assurance that a mass addition pressure transient can be relieved by the operation of a single PORV. The boron capability required below 200°F is sufficient to provide the required SHUTDOWN MARGIN after xenon decay and cooldown from

200°F to 140°F. This condition requires either 1,100 gallons of 7000 ppm borated water from the boric acid storage tanks or 7,113 gallons of 2400 ppm borated water from the RWST.A safety injection pump and associated flow paths from the RWST and to the RCS cold legs can be utilized to fulfill TR 13.1.32 in Mode 6 with the reactor head removed. The requirements of TRS 13.1.32.1, TRS 13.1.32.6, TRS 13.1.32.7, TRS 13.1.32.8, and TRS 13.1.32.11 are applicable to this configuration. Refer to Reference 1 for details.LCOIn MODES 5 and 6, one boration injection subsystem is required to be OPERABLE to provide a boration flow path to allow immediate boration in the event SDM is discovered to be outside the Technical Specification limit. To ensure reliability is maintained in the event of a loss of the normal AC power source, the required boration injection subsystem must be capable of being powered from an OPERABLE emergency power source. One boration injection subsystem is acceptable without single failure consideration on the basis of the relatively stable reactivity condition of the reactor.For the required boration injection subsystem to be considered OPERABLE, all of the following are required:a.An injection flow path (1) from the required boric acid storage tank via either a boric acid transfer pump or a gravity feed connection and a charging pump to the RCS, or (2) from the

RWST via a charging pump to the RCS, and(continued)

Boration Injection System - Shutdown TRB 13.1.32 BASESCPSES - UNITS 1 AND 2 -TRMB 13.1-10Revision 82 LCO (continued)b.Either a centrifugal charging pump or positive displacement charging pump or a safety injection pump (in Mode 6 with the reactor head removed only), andc.A borated water source from either a BAT or the RWST.An OPERABLE Boration Injection System is required to be capable of being manually aligned when boration is required, and in all cases within 15 minutes, to establish boration flow. When local manual control is being credited, administrative controls are utilized to ensure 1) appropriate personnel are aware of the status of the Boration Injection System, and 2) specified individuals are designated and readily available to perform the valve alignment necessary to establish boration flow.APPLICABILITYIn MODE 5 SDM is required to ensure the reactor will be held subcritical with margin for the most reactive Rod Control Cluster Assembly fully withdrawn. SDM is required in MODE 6 to prevent an open vessel inadvertent criticality. As such, the OPERABILITY of one boron injection subsystem ensures reactivity control is available while in MODES 5 and 6. Boration Injection System requirements in MODES 1, 2, 3, and 4 are addressed in TR 13.1.31, "Boration Injection System - Operating."ACTIONSA. 1With the required boration injection subsystem inoperable or the boration injection subsystem not capable of being powered by an OPERABLE emergency power source, the operator must immediately suspend operations involving positive reactivity additions that could result in loss of required SDM or loss of required boron concentration. The Required Actions minimize the potential for inadvertent criticality. Suspending positive reactivity additions that could result in failure to meet the minimum SDM or boron concentration limit is required to assure continued safe operation. Introduction of coolant inventory may allow dilution of the RCS but the source of makeup water is required to contain sufficient boron concentration such that when mixed with the RCS inventory the resulting boron concentration in the RCS meets the

minimum SDM or refueling boron concentration. This may result in an overall reduction in RCS boron concentration, but provides acceptable margin to maintaining subcritical operation. Introduction of temperature changes including temperature increases when operating with a positive MTC must also be evaluated to ensure they do not result in a loss of required SDM.(continued)

Boration Injection System - Shutdown TRB 13.1.32 BASESCPSES - UNITS 1 AND 2 -TRMB 13.1-11Revision 82 TECHNICAL REQUIREMENTS SURVEILLANCE TRS 13.1.32.1This TRS requires verification that the boron solution temperature of the required RWST is greater than 40°F. This temperature is sufficient to prevent boric acid crystals from precipitating out of solution at the highest allowed concentration of boric acid in the RWST.The Frequency of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for performance of the surveillance has been shown to be acceptable through operating experience and is consistent with the Technical Specification surveillance Frequency for verifying the RWST boron solution temperature.TRS 13.1.32.2See Bases for TRS 13.1.31.1TRS 13.1.32.3See Bases for TRS 13.1.31.2TRS 13.1.32.4 and TRS 13.1.32.5This surveillance requires verification that the BAT boron solution volume is at least 10% when using the boric acid pump from the boric acid storage tank or 20% when using gravity feed from the boric acid storage tank. The minimum boron solution volume, along with the boron solution concentration requirements, ensures cold shutdown boron weight is available for injection (e.g., SDM equivalent to 1.3% k/k at 200°F). The 7day Frequency to verify boron solution volume is appropriate since the BAT volumes are normally stable and has been shown to be acceptable through operating experience. In addition, the Frequency is consistent

with the Technical Specification surveillance Frequency for verifying the RWST boron solution volume.

TRS 13.1.32.6 and TRS 13.1.32.7This surveillance requires verification that the RWST solution boron concentration is at least 2400 ppm and the indicated boron solution volume is at least 24%. The minimum boron solution volume, along with the boron solution concentration requirements, ensures cold shutdown boron weight is available for injection (e.g., SDM equivalent to 1.3% k/k at 200°F). The 7day Frequency to verify boron solution volume is appropriate since the RWST volume is normally stable and has been shown to be acceptable through operating experience. In addition, the Frequency is consistent with the Technical Specification surveillance Frequency for verifying the RWST boron solution concentration and volume in MODES 1, 2, 3 and 4.(continued)

Boration Injection System - Shutdown TRB 13.1.32 BASESCPSES - UNITS 1 AND 2 -TRMB 13.1-12Revision 82 TECHNICAL REQUIREMENTS SURVEILLANCE (continued)

TRS 13.1.32.8See Bases for TRS 13.1.31.4TRS 13.1.32.9See Bases for TRS 13.1.31.7TRS 13.1.32.10See Bases for TRS 13.1.31.6TRS 13.1.32.11 This surveillance requires verification the selected SI pump is OPERABLE as determined by the Inservice Testing Program. This TRS is applicable only when a SI pump is being used as the required boration injection subsystem in Mode 6 with the reactor head removed. This TRS is analogous to TRS 13.1.32.10 for the centrifugal charging pump.REFERENCES1.Westinghouse letter WPT-17618 to R. Flores, dated August 6, 2012, "LUMINANT COMANCHE PEAK NUCLEAR POWER PLANT UNIT 2, Boration Flow Path in Mode 6 with Reactor Vessel Head Removed."

Rod Group Alignment Limits and Rod Position Indicator TRB 13.1.37CPSES - UNITS 1 AND 2 - TRMB 13.1-13Revision 82B 13.1 REACTIVITY CONTROL SYSTEMSTRB 13.1.37 Rod Group Alignment Limits and Rod Position Indicator BASES Related requirements/information is located in Technical Specification Bases Section 3.1.4

.

Control Bank Insertion LimitsTRB 13.1.38CPSES - UNITS 1 AND 2 - TRMB 13.1-14Revision 82B 13.1 REACTIVITY CONTROL SYSTEMS TRB 13.1.38 Control Bank Insertion Limits BASES Related requirements/information is found in Technical Specification Bases Section 3.1.6.

Rod Position Indication - Shutdown TRB 13.1.39CPSES - UNITS 1 AND 2 - TRMB 13.1-15Revision 82B 13.1 REACTIVITY CONTROL SYSTEMS TRB 13.1.39 Rod Position Indication - Shutdown BASES Related requirements/information is located in Technical Specification Bases Section 3.1.7.The following discussion is provided to clarify TR 13.1.39 APPLICABILITY.

Control rod testing includes the following independent but related activities:1.Digital Position Indication System (DRPI) testing per SR 3.1.7.1 and TRS 13.1.39.1

,2.Control rod drop timing per SR 3.1.4.3, and3.Control Rod Drive Mechanism (CRDM) step traces, which is not a Surveillance Requirement, but is an integral part of control rod functional testing.These activities may be performed independently or concurrently.

If Keff is maintained 0.95, and no more than one shutdown or control bank is withdrawn from the fully inserted position, control rods may be withdrawing in MODES 3, 4, and 5 for any reason. The limitations on Keff and control rod bank withdrawal are consistent with assumptions made in the design calculations that determine the boron concentration necessary to provide assurance that inadvertent criticality will be avoided.Once DRPI is declared OPERABLE for all shutdown and control banks, the requirement for Keff 0.95 is removed. This allows for significantly reduced boron concentration in preparation for plant startup activities.One CPSES approved method of measuring rod drop times is an established industry method that produces DRPI coil voltage traces. The standard procedure withdraws one shutdown or control bank at a time. DRPI shall be available (but may or may not be OPERABLE) during the withdrawal of the rods, with the limitations on Keff described above. The data necessary to generate DRPI coil voltage traces is obtained from the induced voltage in the position indicator coils as the rod is dropped. The induced voltage is small compared to normal voltage and cannot be observed if DRPI remains energized and OPERABLE. With the rods fully withdrawn, DRPI is de-energized, rendering it inoperable, and the reactor trip breakers are opened to drop the rods.

Once the rods have been dropped, DRPI is energized again.Another CPSES approved method of measuring rod drop times uses the Plant Process Computer (PPC). The PPC method relies on normal operating DRPI indications to determine the time a control rod reaches a specified position. DRPI shall be available (but may or may not be OPERABLE) during the withdrawal of the rods, with the limitations on Keff described above.

DRPI remains energized during testing.

Moveable Incore Detection SystemTRB 13.2.31CPSES - UNITS 1 AND 2 - TRMB 13.2-1Revision 79 B 13.2 POWER DISTRIBUTION LIMITSTRB 13.2.31 Moveable Incore Detection System BASESThe OPERABILITY of the movable incore detectors with the specified minimum complement of equipment ensures that the measurements obtained from use of this system accurately represent the spatial neutron flux distribution of the core. The OPERABILITY of this system is demonstrated by irradiating each detector used and determining the acceptability of its voltage curve. For the purpose of measuring F Q(Z) or a full incore flux map is used. Quarter-core flux maps, as defined in WCAP-8648, June 1976, may be used in recalibration of the Excore Neutron Flux Detection System, and full incore flux maps or symmetric incore thimbles may be used for monitoring the QUADRANT POWER TILT RATIO when one Power Range channel is

inoperable.

FH N AFDTRB 13.2.32CPSES - UNITS 1 AND 2 - TRMB 13.2-2Revision 79 B 13.2 POWER DISTRIBUTION LIMITSTRB 13.2.32 Axial Flux Difference (AFD)

BASESRelated information is located in Technical Specification Bases Section 3.2.3In the event the AFD Monitor Alarm is inoperable, TRM Surveillance 13.2.32.1 requires logging the AFD value with a specific frequency. The purpose of the logging function is to increase the frequency of documented AFD monitoring while the AFD Monitor alarm is inoperable. The Surveillance Frequency of once within 30 minutes and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> thereafter is adequate because AFD is controlled by the operator and any deviations of AFD from TS LCO 3.2.3 requirements should be readily noticed. The initial Surveillance Frequency of once within 30 minutes is to support compliance with TS LCO 3.2.3 ACTIONS.

The requirement to periodically monitor the AFD indication is not relaxed nor is the requirement to comply with the limitations of TS 3.2.3 affected.

QPTR AlarmTRB 13.2.33CPSES - UNITS 1 AND 2 - TRMB 13.2-3Revision 79 B 13.2 POWER DISTRIBUTION LIMITSTRB 13.2.33 Quadrant Power Tilt Ratio (QPTR) Alarm BASESRelated information is located in Technical Specification Bases Section 3.2.4 Power Distribution Monitoring System TRB 13.2.34CPSES - UNITS 1 AND 2 - TRMB 13.2-4Revision 79 B 13.2 POWER DISTRIBUTION LIMITSTRB 13.2.34 Power Distribution Monitoring System BASESBACKGROUNDThe Power Distribution Monitoring System (PDMS) generates a continuous measurement of the core power distribution using the methodology documented in Reference 1. The measured core power distribution is used to determine the most limiting core peaking factors, and F Q (Z). The most limiting measured core peaking factor values are used to verify that the reactor is operating within design limits.

The PDMS requires information on current plant and core conditions in order to determine the core power distribution using the core peaking factor measurement and measurement uncertainty methodology described in Reference 1. The core and plant condition information is used as input to

the continuous core power distribution measurement software that continuously and automatically determines the current core peaking factor values.In order for the PDMS to accurately determine the peaking factor values, the core power distribution measurement software requires accurate information about the current reactor power level, average reactor vessel inlet temperature, control bank positions, the Power Range Detector

calibrated voltage or current values, and the measured Core Exit Thermocouples (T/C). At least 13 of the T/C must be OPERABLE at all times for PDMS OPERABILITY.

APPLICABLE SAFETY ANALYSESThe PDMS is used for periodic measurement of the core power distribution to confirm operation within the design limit, and periodic calibration of the excore detectors. This system does not initiate any automatic protection action. The PDMS is not assumed to be OPERABLE to mitigate the consequences of a DBA or transient (Reference 2).LCOThe TR LCO requires the PDMS to be OPERABLE with the specified number of channel inputs from the plant computer for each Function listed in Table 13.2.34-1.This ensures that the measured plant and core condition information input to the core power distribution measurement software with the PDMS OPERABLE is adequate to accurately calculate the core peaking factors. The peaking factor calculations include measurement uncertainty which

bounds the actual measurement uncertainty of an OPERABLE PDMS.(continued)

FH N Power Distribution Monitoring System TRB 13.2.34 BASES (continued)CPSES - UNITS 1 AND 2 -TRMB 13.2-5Revision 79APPLICABILITYIn order for the PDMS to be used for the listed functions, the reactor must be in MODE 1 and >

25% RTP. The PDMS must be calibrated above 25% RTP to assure the accuracy of the calibration data set which can be generated from the incore flux map, core exit thermocouples, and other input channels. Below 25% RTP, the PDMS may not be used for the listed functions since the calculated power distribution is of reduced accuracy and

may not be used to demonstrate compliance with the LCO limits.ACTIONSA.1With one or more PDMS components or required plant computer inputs

inoperable, the PDMS may not be used for the applicable monitoring and calibration functions until the required inputs are restored to an OPERABLE status.Control bank position inputs may be bank positions from either 1) valid Demand Position indications or 2) the average of all valid individual RCCA positions in the bank determined from Rod Position Indication (RPI) System values for each Control Bank. A maximum of 1 rod position indicator may be inoperable when RCCA position indications are being used as input to the PDMS.Reactor Power Level inputs may be reactor thermal power derived from either a valid secondary calorimetric measurement, the average Power Range Neutron Flux Power, or the average N-16 Power.The total number of Excore Detectors must consist of at least 3 pairs of corresponding upper and lower detector section signals.

TECHNICAL REQUIREMENTS SURVEILLANCE T RS 13.2.3 4.1Performance of a CHANNEL CHECK prior to using the PDMS to obtain a core power distribution measurement ensures that a gross instrumentation failure has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value.

Significant deviations between the two instrument channels could be an indication of excessive instrument drift in one of the channels. A CHANNEL CHECK will detect gross channel failure; thus it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.(continued)

Power Distribution Monitoring System TRB 13.2.34 BASESCPSES - UNITS 1 AND 2 -TRMB 13.2-6Revision 79 TECHNICAL REQUIREMENTS SURVEILLANCE TRS 13.2.34.1 (continued)The Frequency is based on the need to establish that the required inputs to the PDMS are valid prior to using the PDMS to obtain a core power distribution measurement to be used to confirm that the reactor is operating within design limits.

TRS 13.2.3 4.2Upon initial plant startup following refueling, the PDMS uses a calibration data set calculated by the core designer for the new core.An accurate incore flux map for PDMS calibration may be obtained upon exceeding 25% RTP. The initial calibration data set generated in each operating cycle must utilize incore flux measurements from at least 75% of the incore thimbles, with at least two incore thimbles in each core quadrant. The incore flux measurements in combination with inputs from the Table 13.2.34-1 channels (which have been calibrated/tested in accordance with TRS 13.2.34.3 and TRS 13.2.34.4) are used to generate the updated calibration data set, including the nodal calibration factors and the thermocouple mixing factors.Following the initial calibration discussed above, the calibration data set must utilize incore flux measurements from at least 50% of the detector thimbles with at least 2 detector thimbles per core quadrant.Following the initial calibration discussed above, the required frequency is 31 EFPD when the minimum core exit thermocouple coverage is available for the PDMS calibration. The minimum thermocouple coverage consists of 13 thermocouples with a minimum of two per core quadrant.The required frequency is 180 EFPD when the optimum core exit thermocouple coverage is available for the PDMS calibration. The optimum thermocouple coverage is defined by all interior fuel assemblies (non-peripheral) have an OPERABLE Core Exit Thermocouple within at least a chess knight's move.

T RS 13.2.3 4.3 and 13.2.34.4 A CHANNEL CALIBRATION (or CHANNEL FUNCTIONAL TEST) is verified to have been performed prior to using the PDMS to measure the core power distribution, and every 24 months, or approximately at every refueling. The test or calibration verifies that the channel responds to a (continued)

Power Distribution Monitoring System TRB 13.2.34 BASESCPSES - UNITS 1 AND 2 -TRMB 13.2-7Revision 79 TECHNICAL REQUIREMENTS SURVEILLANCETRS 13.2.34.3 and 13.2.34.4 (continued)measured parameter with the necessary range and accuracy. TRS 13.2.34.3 is modified by a note stating that neutron detectors are excluded form the CHANNEL CALIBRATION. The CHANNEL CALIBRATION for the power range neutron detectors consists of a normalization of the detectors based on a power calorimetric and power distribution measurement. The required frequency is based on operating experience and consistency with the typical industry refueling cycle.

REFERENCES:

1.WCAP-12472-P-A, "BEACON Core Monitoring and Operations Support System," August 1994.2.10 CFR 50.46.

RTS Instrumentation Response Times TRB 13.3.1CPSES - UNITS 1 AND 2 - TRMB 13.3-1Revision 74B 13.3 INSTRUMENTATIONTRB 13.3.1 Reactor Trip System (RTS) Instrumentation Response Times BASESThe bases for the Reactor Trip System are contained in the CPSES Technical Specifications. The measurement of response time at the specified frequencies provides assurance that the Reactor trip actuation associated with each channel is completed within the time limit assumed in the safety analyses. No credit was taken in the analyses for those channels with response times indicated as not applicable. Response time may be demonstrated by any series of sequential, overlapping, or total channel test measurements provided that such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either: (1) in place, onsite, or offsite test measurements, or (2) utilizing replacement sensors with certified response time.The overall response time limit for the overtemperature N-16 reactor trip function is 8 seconds, as noted in TRM Table 13.3.1-1, Item 6. Note 2 clarifies that a maximum of 6 seconds is allowed for the RTD/thermal well response time, as described in FSAR Table 15.0-4. Taken together with the overall response time requirement of 8 seconds, the allowed response time components (RTD/thermal well and "electronic") are specified in a manner consistent with the accident analyses.

ESFAS Instrumentation Response Times TRB 13.3.2CPSES - UNITS 1 AND 2 - TRMB 13.3-2Revision 74B 13.3 INSTRUMENTATIONTRB 13.3.2 Engineered Safety Features Actuation System (ESFAS) Instrumentation Response Times BASES The bases for the Engineered Safety Features Actuation System are contained in the CPSES Technical Specifications. The measurement of response time at the specified frequencies provides assurance that the Engineered Safety Features actuation associated with each channel is completed within the time limit assumed in the safety analyses. No credit was taken in the analyses for those channels with response times indicated as not applicable. Response time may be demonstrated by any series of sequential, overlapping, or total channel test measurements provided that such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either: (1) in place, onsite, or offsite test measurements, or (2) utilizing replacement sensors with certified response time.

LOP DG Start Instrumentation Response Times TRB 13.3.5CPSES - UNITS 1 AND 2 - TRMB 13.3-3Revision 74B 13.3 INSTRUMENTATIONTRB 13.3.5 Loss of Power (LOP) Diesel Generator (DG) Start InstrumentationResponseTimes BASES TRM Table 13.3.5-1 contains the initiation signals and function response time limits for the LOP DG Start Instrumentation. The response time limits for each function are consistent with the analytical limits presented in the FSAR, Chapter 15

.The Chapter 15 Accident Analysis contains separate analyses for the Design Basis Accident (DBA) and Loss of Offsite Power (LOOP) events. CPSES assumes these events to occur independently of each other and does not postulate the simultaneous occurrence of a Design Basis Accident (DBA) and a Loss of Offsite Power.For purposes of accident analysis however, CPSES conservatively assumes a LOOP concurrent with a turbine trip. All DBAs, with the exception of Feedwater Line Break (FWLB), generate an immediate Safety Injection Actuation Signal (SIAS) with a resultant DG start initiation, reactor trip, turbine trip, and an assumed LOOP. For the FWLB, the DG is postulated to start from a LOOP signal. The response times for the LOP DG Start Instrumentation assure that on a LOOP, the DG will start in sufficient time to meet the 60 second requirement for Auxiliary Feedwater Pump (AFWP) running for mitigation of the FWLB.CPSES provides for equipment protection due to sustained degraded or low grid voltage conditions for continued operability of motors to perform their ESF function. However, the CPSES accident analysis does not assume degraded grid conditions to occur simultaneously with a DBA. For conservatism, safety buses are promptly isolated from an established degraded grid or low grid condition upon the subsequent occurrence of an SIAS. Response time requirements for LOP DG Start Instrumentation assure that, on occurrence of an SIAS subsequent to an established degraded or low grid condition, the safety buses are isolated from the degraded or low grid condition in sufficient time to allow for the closure of the DG output circuit breaker to the safety bus within 10 seconds from the receipt of the SIAS start signal by the

DG.The measurement of response time at the specified frequencies provides assurance that the Loss of Power features associated with each channel is completed within the time limit assumed in the safety analyses. No credit was taken in the analyses for those channels with response times indicated as not applicable. Response time may be demonstrated by any series of sequential, overlapping, or total channel test measurements provided that such tests demonstrate the total channel response time as defined. Sensor response time verification may be demonstrated by either: (1) in place, onsite, or offsite test measurements, or (2) utilizing

replacement sensors with certified response time.

Seismic InstrumentationTRB 13.3.31CPSES - UNITS 1 AND 2 - TRMB 13.3-4Revision 74B 13.3 INSTRUMENTATIONTRB 13.3.31 Seismic Instrumentation BASESThe OPERABILITY of the seismic monitoring system ensures that sufficient capability is available to promptly determine whether the OBE has been exceeded and to collect information to evaluate the response of features important to safety. This capability is required pursuant to Appendix A of 10CFR100. The instrumentation provided meets the intent of Regulatory Guide 1.12, "Instrumentation for Earthquakes," April 1974, as described in the FSAR. The seismic monitoring system will record and analyze a seismic event to determine OBE exceedance in accordance with the requirements described in the FSAR.

RTS Instrumentation - Source Range Neutron FluxTRB 13.3.32CPSES - UNITS 1 AND 2 - TRMB 13.3-5Revision 74B 13.3 INSTRUMENTATIONTRB 13.3.32 Reactor Trip System (RTS) Instrumentation - Source Range Neutron Flux BASESTechnical Specification 3.3.1 requires the source range reactor trip function to be OPERABLE in Modes 3, 4 and 5, when the Rod Control System is capable of rod withdrawal or all control rods are not fully inserted. However, when in the converse condition, i.e., the Rod Control System is not capable of rod withdrawal and all control rods are fully inserted, the source range neutron flux channels are only required to be available to monitor the reactivity state of the core; however, no reactor trip function is required.The primary function of the source range neutron flux monitors in Modes 3, 4, and 5, when the source range reactor trip function is not required to be OPERABLE per TS3.3.1, is to provide a visual signal to alert the operator to unexpected changes in core reactivity such as an inadvertent boron dilution accident, an unexpected moderator temperature change or an improperly loaded fuel assembly. Either the set of two Westinghouse-supplied BF 3 source range detectors or the set of two Gamma-Metrics Neutron Flux Monitoring System channels may be used to perform this reactivity-monitoring function.

The CPSES design includes two separate systems for monitoring the neutron flux. The Westinghouse portion of the system consists of three instrumentation ranges: the Source Range, Intermediate Range and the Power Range. Each portion consists of detectors, power

supplies, signal processing equipment and indicators. The Westinghouse source range neutron flux monitors provide audio and visual indications of neutron count rate. The audible output provides a warning in the main control room and containment of any potentially hazardous condition. However, with the implementation of CPSES TS Amendment 64, (the Improved Technical Specifications), the audible count indication was deleted as a requirement for the source range neutron flux monitors.

A separate Gamma-Metrics Neutron Flux Monitoring System (NFMS) is installed to satisfy the requirements of Regulatory Guide 1.97, "Instrumentation For Light-Watered-Cooled Nuclear Power Plants To Assess Plant And Environs Conditions During And Following An Accident." The Gamma-Metrics NFMS monitors neutron flux from the source range through 200% Rated Thermal Power (RTP) during all Modes of plant operation. This system utilizes two separate (Class 1E) fission chamber neutron detectors for all ranges of neutron flux indication. Specific

requirements for this function of the Gamma-Metrics NFMS are contained in Technical Specification 3.3.4

.Both the Westinghouse source range neutron flux monitors and the Gamma-Metrics Neutron Monitoring System are functionally equivalent and bo th are qualified to Class 1E standards. (continued)

RTS Instrumentation - Source Range Neutron FluxTRB 13.3.32 BASES (continued)CPSES - UNITS 1 AND 2 -TRMB 13.3-6Revision 74 The channel check performed on the Gamma-Metrics detectors verifies the actual process signal as it is input to the sensor. Because of the inherent nature of the statistical emission of source range neutrons from the reactor core, the process signal provides an observable fluctuation that is visible on the end devices (control room instrumentation). Furthermore, there are no alarm, interlock or trip functions associated with these channels. Therefore, a Channel Operability Test is not required for the Gamma-Metrics detectors.Related information is located in Technical Specification Bases 3.3.1 Turbine Overspeed ProtectionTRB 13.3.33CPSES - UNITS 1 AND 2 - TRMB 13.3-7Revision 74B 13.3 INSTRUMENTATION TRB 13.3.33 Turbine Overspeed Protection BASESBACKGROUNDThis specification is provided to ensure that the turbine overspeed protection instrumentation and the turbine Stop and Control Valves are operable and will protect the turbine from excessive overspeed. Protection from excessive overspeed is necessary to prevent the

generation of potentially damaging missiles which could impact and damage safety-related components, equipment and structures. Turbine overspeed is limited by rapid closure of the turbine Stop or Control Valves whenever turbine power exceeds generator output, as would exist immediately following a load rejection.The Electrohydraulic Control (EHC) System is the primary means of limiting the extent of an overspeed event, with the turbine Overspeed Protection System as a backup. The EHC System is designed to limit transient overspeed to less than 110% of rated speed after a full load rejection by closing both the High Pressure (HP) and Low Pressure (LP) Control Valves. This function of the EHC System is performed by the normal speed/load control logic in conjunction with additional protection logic that ensures closure of all control valves under certain load rejection scenarios (Reference 1).To minimize the possibility of a component failure resulting in a loss of the control function, the EHC System utilizes triple redundant speed and load inputs, dual redundant digital controller processors, and dual

redundant outputs (amplifiers, proportional valves, and follow-up piston banks) to the Control Valves.In the unlikely event that the EHC System fails to limit the overspeed condition, the Overspeed Protection System will act to limit the overspeed to less than 120% of rated speed.The Overspeed Protection System is made up of the following basic component groups:*Independent and redundant speed sensors and associated signal processing instrumentation, including bistables, provide individual speed channel trip signals to the Turbine AG-95F Digital Protection System and the hardware overspeed trip system (both described below) whenever turbine speed exceeds 1980 rpm.

(continued)

Turbine Overspeed ProtectionTRB 13.3.33 BASESCPSES - UNITS 1 AND 2 -TRMB 13.3-8Revision 74 BACKGROUND (continued)*The Turbine AG-95F Digital Protection System consists of three independent and redundant trains of equipment, including input modules, dual redundant automation processors and associated software, output modules, and output relays. The AG-95F System is a fail-safe system in that all inputs and outputs are normally energized in the non-tripped state.Each train of the AG-95F System processes the individual speed channel trip signals using 2 of 3 trip logic. When the trip logic is

satisfied, the associated output relays de-energize, each one

subsequently de-energizing its associated Turbine Trip Block

solenoid valve.*The Relay Protection System consists of relay logic and output relays that are diverse from, and completely bypass, the AG-95F Digital Protection System described above. The logic and output

relays are normally energized in the non-gripped state.The relay logic processes the individual speed channel trip signals using 2 of 3 trip logic. When the trip logic is satisfied, all

three output relays de-energize, each one subsequently de-

energizing its associated Turbine Trip Block solenoid valve.*The Turbine Trip Block utilizes three independent and redundant solenoid valves to actuate associated hydraulic pistons that are configured in a manner that provides a hydraulic 2 of 3 trip logic.

When any two of the three solenoid valves de-energize, actuation

of the associated pistons rapidly de-pressurizes the turbine Trip Fluid System, causing all turbine Stop and Control Valves to close. De-energization of a single solenoid valve will not trip the

turbine.The Overspeed Protection System consists of two redundant and diverse sub-systems, the Hardware Overspeed Sub-system and the Software Overspeed Sub-system, that are configured using the component groups described above. Either of these sub-systems can independently trip the

turbine.The Hardware Overspeed Sub-system utilizes a set of three dedicated speed channels, each of which provides a trip signal to the Relay Protection System. Upon receipt of trip signals from any two of these

speed channels, the relay logic de-energizes all three output relays

which subsequently de-energize all three Turbine Trip Block solenoid

valves, causing the turbine to trip.(continued)

Turbine Overspeed ProtectionTRB 13.3.33 BASESCPSES - UNITS 1 AND 2 -TRMB 13.3-9Revision 74 BACKGROUND (continued)As a backup, the three dedicated Hardware Overspeed Sub-system speed channels also provide trip signals to all three of the AG-95F System protection trains. Upon receipt of trip signals from any two of these speed channels, the output relay of each protection train is de-

energized, subsequently de-energizing all three Turbine Trip Block solenoid valves, causing the turbine to trip.The Software Overspeed Sub-system utilizes a second set of three dedicated speed channels which provide input to all three of AG-95F System protection trains. Upon receipt of trip signals from any two of these speed channels, the output relay of each protection train is de-energized, subsequently de-energizing all three Turbine Trip Block solenoid valves, causing the turbine to trip. The Software Overspeed System speed channels also provide speed signals to the EHC System as described above.The design of the Overspeed Protection System includes several testing features that are used to ensure OPERABILITY of the system. These features include three Automatic Turbine Tester (ATT) tests that are manually initiated by the operator. They also include a test that is automatically executed by the system to ensure OPERABILITY of the speed channel instrumentation.The ATT HP and LP Valve Tests cycle all Stop and Control Valves to ensure reliability and continuity of service. The HP and LP Stop Valve closure times are also verified to be within required response times (500 and 1500 msec, respectively). These tests cycle one pair of Stop and Control Valves at a time, so they may be performed with the plant on-line below approximately 85% power.

The ATT Turbine Trip Block Test de-energizes each Turbine Trip Block solenoid valve and verifies that the associated hydraulic piston moves to the trip position. The solenoid valve/piston pairs are sequentially tested one at a time, until all three are tested. Each pair is reset prior to testing the subsequent pair. Since only one solenoid valve/piston pair is tested at a time, the Trip Fluid System is never de-pressurized, and the turbine does not trip.

Each of the six individual speed channels (three for the Hardware Overspeed Sub-system and three for the Software Overspeed Sub-system), is automatically tested once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when turbine speed is >40 rpm. These tests verify that the speed channels trip when speed is simulated above 1980 rpm. The tests are initiated by the AG-95F(continued)

Turbine Overspeed ProtectionTRB 13.3.33 BASESCPSES - UNITS 1 AND 2 -TRMB 13.3-10Revision 74 BACKGROUND (continued)System in a manner that precludes two speed channels from beingtested at the same time. If desired, the speed channel tests may also be initiated by the operator.Alarms are provided to alert the operator in the event of a fault/failure is detected during the execution of any of the aforementioned tests.

APPLICABLE SAFETY ANALYSESThe Overspeed Protection System is required to be OPERABLE to provide sufficient protection against generation of potentially damaging missiles which could impact and damage safety-related components, equipment and structures. The turbine missile analysis is presented in Reference 2. Using References 3 and 5 as a basis, this analysis concludes that the risk for loss of an essential system due to a turbine

missile event is acceptably low.The robust design of the Overspeed Protection System, with its multiple speed channels, diverse hardware and software logic, and multiple Turbine Trip Block solenoid valves/hydraulic pistons, meets the intent of SRP 10.2 Part III for redundancy and independence.LCOThe Turbine Overspeed Protection Sub-systems are the Hardware Overspeed Sub-system and the Software Overspeed Sub-system, one of which shall be OPERABLE.The robust design of these sub-systems allows for the failure of individual components without rendering the sub-system(s) inoperable. Specifically, the minimum operability requirements for the Hardware Overspeed Sub-system include:*two OPERABLE dedicated hardware speed channels, and associated OPERABLE hardware relay logic with two OPERABLE output relays and associated Turbine Trip Block solenoid valves/hydraulic pistons OR*two OPERABLE dedicated hardware speed channels and two associated OPERABLE AG-95F System trains, including output relays and associated Turbine Trip Block solenoid valves/

hydraulic pistons (continued)

Turbine Overspeed ProtectionTRB 13.3.33 BASESCPSES - UNITS 1 AND 2 -TRMB 13.3-11Revision 74 LCO (continued)The minimum operability requirements for the Software Overspeed Sub-system include:*two OPERABLE dedicated software speed channels and two associated OPERABLE AG-95F System trains, including output relays and associated Turbine Trip Block solenoid valves/

hydraulic pistonsIndividual component failures that do not render the sub-system(s) inoperable are addressed under the Corrective Action Program (CAP) with restoration times commensurate with the severity of the failure and the operational impact associated with the rework or repair.

Furthermore, component failures that result in rendering only one Overspeed Protection Sub-system inoperable are also addressed under the CAP with restoration times commensurate with the severity of the failure and the operational impact associated with the rework or repair.The OPERABILITY of one Overspeed Protection Sub-system ensures that the Overspeed Protection System is available to prevent an overspeed event while the unit is operating in MODE 1, 2, and 3 with steam available to roll the turbine. The APPLICABILITY is modified by a Note specifying that Overspeed Protection Sub-system OPERABILITY is not required in MODE 2 and 3 if the turbine is isolated from the steam supply by closing all Main Steam Isolation Valves and associated bypass

valves.ACTIONSA.1, A.2, and A.3This ACTION is modified by a Note that specifies that separate Condition entries are allowed for each steam line if valves are inoperable in multiple steam lines.

If a HP Stop or Control Valve is inoperable such that it is not capable of properly isolating the steam line to the turbine in response to an overspeed event, action must be taken to restore the valve(s) to OPERABLE status. Failure to restore the valve(s) to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> requires that compensatory action be taken within the

following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to ensure that the affected steam line is isolated by other means.(continued)

Turbine Overspeed ProtectionTRB 13.3.33 BASESCPSES - UNITS 1 AND 2 -TRMB 13.3-12Revision 74ACTIONSA.1, A.2, and A.3 (continued)The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time for restoring the valve(s) takes into account the OPERABILITY of the remaining valve in the affected steam line and reasonable time for rework or repair. The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> compensatory action Completion Time is reasonable, based on operating experience, for reaching the required unit conditions from full power operation in an orderly manner and without challenging unit systems.

B.1, B.2, and B.3This ACTION is modified by a Note that specifies that separate Condition entries are allowed for each steam line if valves are inoperable in multiple steam lines.If a LP Stop or Control Valve is inoperable such that it is not capable of properly isolating the steam line to the turbine in response to an overspeed event, action must be taken to restore the valve(s) to OPERABLE status. Failure to restore the valve(s) to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> requires that compensatory action be taken within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to ensure that the affected steam line is isolated by other means.The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time for restoring the valve(s) takes into account the OPERABILITY of the remaining valve in the affected steam line and reasonable time for rework or repair. The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> compensatory action Completion Time is reasonable, based on operating experience, for reaching the required unit conditions from full power operation in an orderly manner and without challenging unit systems.

C.1If both Overspeed Protection Sub-systems are inoperable, such that neither is capable of initiating a turbine trip in response to an overspeed event, action must be taken within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to isolate the turbine from the steam supply.The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Completion Time for isolating the turbine from the steam supply is reasonable, based on operating experience, for reaching the required unit conditions from full power operation in an orderly manner and without challenging unit systems.(continued)

Turbine Overspeed ProtectionTRB 13.3.33 BASESCPSES - UNITS 1 AND 2 -TRMB 13.3-13Revision 74 ACTIONS (continued)

D.1, D.2, and D.3 In the event that the aforementioned ACTIONS and associatedCompletion Times cannot be satisfied, action must be initiated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to place the unit in a lower MODE, with subsequent action to place the unit in MODE 3 within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to place the unit in MODE 4 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after entering MODE 3. The need to perform these actions would most likely result from the inability to isolate the turbine from the steam supply. Placing the unit in MODE 4 will reduce steam pressure to the point where there is insufficient motive force to overspeed the turbine, even if it is not isolated from the steam generators.The Completion Times are reasonable, based on operating experience, for reaching MODE 3 and MODE 4 from full power operation in an orderly manner and without challenging unit systems.

TECHNICAL REQUIREMENTS SURVEILLANCEThe TRS 13.3.33 requirements are modified by a Note that specifies that the provisions of TRS 13.0.4 are not applicable.

TRS 13.3.33.1This TRS specifies testing of the Turbine Trip Block using the Automatic Turbine Tester (ATT). This test de-energizes each Turbine Trip Block solenoid valve and verifies that the associated hydraulic piston moves to trip position. The solenoid valve/piston pairs are sequentially tested one at a time, until all three are tested. Each pair is reset prior to testing the subsequent pair. Since only one solenoid valve/piston pair is tested at a time, the Trip Fluid System is never de-pressurized, and the turbine does not trip.The 14 day test Frequency is based on the assumptions in the analyses presented in Reference 2.TRS 13.3.33.2This TRS specifies testing of the turbine HP and LP Stop and Control Valves using the manual test or the ATT. These tests cycle all Stop and Control Valves to ensure reliability and continuity of service. The HP and LP Stop Valve closure times are also verified to be within required response times (500 and 1500 msec, respectively). These tests cycle one pair of Stop and Control Valves at a time, so they may be performed with the plant on-line below approximately 85% power.The 26 week test Frequency is based on the assumptions in the analyses presented in Reference 2 and 5.(continued)

Turbine Overspeed ProtectionTRB 13.3.33 BASESCPSES - UNITS 1 AND 2 -TRMB 13.3-14Revision 74 TECHNICAL REQUIREMENTSSURVEILLANCE

(continued)

TRS 13.3.33.3 This TRS has been deleted.TRS 13.3.33.4This TRS requires disassembly and inspection of at least one HP Stop Valve and one HP Control Valve on a 40 month Frequency to satisfy the turbine inservice inspection requirements described in Reference 6.TRS 13.3.33.5This TRS requires inspection of at least one LP Stop Valve and one LP Control Valve on a 40 month Frequency to satisfy the turbine inservice inspection requirements described in Reference 6.TRS 13.3.33.6This TRS requires a test of the Hardware Overspeed Sub-system 2 of 3 relay logic and output relays to ensure that this equipment is capable of processing an overspeed turbine trip signal on demand.

This equipment cannot be tested with the unit at power because performance of the test will trip the turbine. The 18 month test Frequency is consistent with Technical Specification test Frequencies assigned to similar equipment, and it affords the opportunity to test the equipment while the unit is shutdown. This test Frequency is judged to be acceptable based on the reliability of the equipment.

REFERENCES:

1.CPSES FSAR, Section 10.2.2.7.2.CPSES FSAR, Section 3.5.1.3.

3.Engineering Report No. ER-504, Probability of Turbine Missiles from 1800 R/MIN Nuclear Steam Turbine-Generators with 44

-Inch Last Stage Turbine Blades, Allis-Chalmers (Siemens)Power Systems, Inc, October 1975.4.Deleted.

(continued)

Turbine Overspeed ProtectionTRB 13.3.33 BASESCPSES - UNITS 1 AND 2 -TRMB 13.3-15Revision 74

REFERENCES:

(continued)5.CT-27331, Revision 5, Missile Probability Analysis Methodologyfor TXU Generation Company LP, Comanche Peak Units 1 and 2 with Siemens Retrofit Turbines, Siemens Westinghouse Power Corporation, January 18, 2007.6.CPSES FSAR, Section 10.2.3.6.

Plant Calorimetric MeasurementTRB 13.3.34CPSES - UNITS 1 AND 2 - TRMB 13.3-16Revision 74B 13.3 INSTRUMENTATION TRB 13.3.34 Plant Calorimetric Measurement BASESBACKGROUNDThe predominant contribution to the secondary plant calorimetric measurement uncertainty is the uncertainty associated with the feedwater flow measurement. Traditionally, a differential pressure (P) transmitter across a venturi in each main feedwater line has been used

to provide the feedwater flow. However, the venturis are subject to corrosion or fouling and the uncertainty associated with the flow derived from the P indication can be large and increases as the flow deviates from the "optimum" conditions for which the P transmitter was calibrated.More recently, leading edge flow meters (LEFMs) have been used to provide the feedwater flow input to the secondary plant calorimetric measurement. The uncertainty associated with the LEFM is relatively small and is independent of the actual feedwater flow.

The power calorimetric uncertainty associated with the use of the feedwater venturis is less than +2.0% RATED THERMAL POWER (RTP) for a measurement taken near full power. The uncertainty associated with the LEFM instrumentation is +

0.6% RTP.The accident analyses are performed at a nominal RTP of 3612 MW th plus an uncertainty allowance of +0.6% RTP based on the availability of the LEFM instrument. If the LEFM is unavailable, the uncertainties associated with the feedwater venturi-based measurement (+

2% RTP) must be used to ensure compliance with the safety analysis value of the core power. This reduced power level is 3562 MW th. (The accident analyses were performed at a NSSS power of 3650 MW th , including

~16 MW th net RCP heat addition and a calorimetric power uncertainty of

+0.6% RTP.)

For Cycle 13 of U1 and for Cycle 11 of U2, the RATED THERMAL POWER is 3458 MW th (100% RTP), and the core power should be reduced to 3411 MW th (98.6% RTP) if the LEFM is unavailable.

Surveillance Requirement SR 3.3.1.2 requires the performance of a comparison of the results of the calorimetric heat balance calculation to (continued)

Plant Calorimetric MeasurementTRB 13.3.34 BASESCPSES - UNITS 1 AND 2 -TRMB 13.3-17Revision 74 BACKGROUND (continued)Nuclear Instrumentation System (NIS) and N-16 Power Monitor channel output. SR 3.3.1.2 requires that the NIS Power Range channels be adjusted if the calorimetric heat balance calculation results exceed the NIS Power Range indication by more than +2% RTP, and the N-16 Power Monitor channels be adjusted if the calorimetric heat balance calculation results exceed the N-16 Power Monitor indication by more

than +2% RTP.

SR 3.3.1.2 is required to be performed every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (daily). At that time, the NIS and N-16 power indications must be normalized to indicate within at least +2% RTP of the calorimetric measurement. The plant may then be run for the next 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period, using these normalized NIS and

N-16 power indications, such that the calorimetric power does not exceed 100% RTP. Although the calorimetric power indication may be monitored continuously for control of the unit power, the calorimetric power indication is not required to be consulted again until the daily calorimetric comparisons of the NIS and N-16 power indications are performed.The following general guidance is provided for operation of CPSES Units 1 and 2:1.When the LEFM is available, the plant should be operated in a manner consistent with the LEFM-based calorimetric measurement and at 100% RTP.2.If the LEFM is unavailable, the plant may be operated at 100% RTP using the NIS and N-16 power indications until the next performance of SR 3.3.1.2 is due.3.If the LEFM-based calorimetric measurement is unavailable at the time SR 3.3.1.2 is due, the feedwater venturi-based calorimetric measurement should be used for the performance of SR 3.3.1.2. However, to maintain consistency with the uncertainty analyses, the maximum allowable power should be reduced to 98.6% RTP. Either the NIS and N-16 power indications or the feedwater venturi-based calorimetric power indications may be used to control the unit power.(continued)

Plant Calorimetric MeasurementTRB 13.3.34 BASES (continued)CPSES - UNITS 1 AND 2 -TRMB 13.3-18Revision 74 APPLICABLE SAFETY ANALYSESThe setpoints for those functions of the Reactor Protection System that are based on a percentage of power (i.e., the NIS, overpower N-16 and overtemperature N-16 trip functions) have been calculated based on

analytical margins available at 100% RTP. Operation at lower power levels does not require these setpoints to be adjusted.LCOThe LCO requires the LEFM to be used for the completion of the daily secondary plant calorimetric measurement required in SR 3.3.1.2. The use of the LEFM ensures that the basis for operation at 100% RATED THERMAL POWER is maintained.APPLICABILITYThe requirement to use the LEFM for the performance of the secondary plant calorimetric measurement required by SR 3.3.1.2 is applicable to MODE 1 > 15% RTP.ACTIONSA.1 If the LEFM becomes unavailable during the intervals between performance of SR 3.3.1.2, plant operation may continue using the power indications from the NIS and N-16 systems. However, in order to remain in compliance with the bases for operation at 100% RATED THERMAL POWER, the LEFM must be returned to service prior to performance of SR 3.3.1.2

.B.1, B.2, and B.3If the Required Action or Completion Time of Condition A is not met (i.e., the LEFM has not been returned to service prior to the performance of SR3.3.1.2), Condition B is entered. Required Action B.1 requires that the reactor power be reduced to, or maintained at, a power level less than or equal to 98.6% RTP. This power reduction is performed prior to performing SR 3.3.1.2 in order to remain within the plant's design bases immediately upon performance of SR 3.3.1.2

.(continued)

Plant Calorimetric MeasurementTRB 13.3.34 BASESCPSES - UNITS 1 AND 2 -TRMB 13.3-19Revision 74ACTIONSB.1, B.2, and B.3 (contiinued)Required Action B.2 directs the performance of SR 3.3.1.2 using the feedwater venturi indications of feedwater flow. Once SR 3.3.1.2 is performed using the feedwater venturi indications of feedwater flow, the required power uncertainty is 2% RTP. In order to maintain compliance with the safety analyses, it is necessary to operate the plant at a maximum core thermal power of less than or equal to 98.6% RTP.Required Action B.3 serves as a reminder that the core power is to be maintained at a value less than or equal to 98.6% RTP until the LEFM is returned to service and SR 3.3.1.2 has been performed using the LEFM indication of feedwater flow. Once SR 3.3.1.2 has been performed, then the plant can again be operated at RTP.

TECHNICAL REQUIREMENTS SURVEILLANCE TRS 13.3.34.1 requires that the availability of the LEFM be verified prior to its use for the performance of SR 3.3.1.2. The self-diagnostics features of the LEFM should be used for this surveillance. If the LEFM indications are in the normal or alert status it is considered operable.REFERENCES1.License Amendment Request 01-005, Increase the licensed power for operation of CPSES Units 1 and 2 to 3458 MWth, Docket Nos. 50-445 and 50-446, CPSES.2.License Amendment Request (LAR)07-004, Revision to the Operating License and Technical Specifications 1.0, "Use and Application" and 3.7.17, "Spent Fuel Assembly Storage" to Revise Rated Thermal Power from 3458 MW th to 3612 MW th. Docket Nos. 50-445 and 50-446, CPSES.3.WCAP-16840-P, Rev. 0, Comanche Peak Nuclear Power Plant Stretch Power Uprate Licensing Report.4.License Amendment 146, Revison to the Operating License and Technical Specifications 1.0, "Use and Application" to Revise Rated Thermal Power from 3458 MWth to 3612 MWth. Docket Nos. 50-445 and 50-446, CPSES.

RCS Pressure Isolation Valves TRB 13.4.14CPSES - UNITS 1 AND 2 - TRMB 13.4-1Revision 56 B 13.4 REACTOR COOLANT SYSTEMTRB 13.4.14 Reactor Coolant System (RCS) Pressure Isolation Valves BASESRelated information is located in Technical Specification Bases 3.4.14

.

Loose Parts Detection SystemTRB 13.4.31CPSES - UNITS 1 AND 2 - TRMB 13.4-2Revision 56 B 13.4 REACTOR COOLANT SYSTEM TRB 13.4.31 Loose Parts Detection System BASESThe OPERABILITY of the Loose-Part Detection System ensures that sufficient capability is available to detect loose metallic parts in the Reactor System and avoid or mitigate damage to Reactor System components. The allowable out-of-service times and surveillance requirements are consistent with the recommendations of Regulatory Guide 1.133, "Loose-Part Detection Program for the Primary System of Light-Water-Cooled Reactors," May 1981.

RCS Chemistry TRB 13.4.33CPSES - UNITS 1 AND 2 - TRMB 13.4-3Revision 56 B 13.4 REACTOR COOLANT SYSTEMTRB 13.4.33 Reactor Coolant System (RCS) Chemistry BASESThe limitations on Reactor Coolant System chemistry ensure that corrosion of the Reactor Coolant System is minimized and reduces the potential for Reactor Coolant System leakage or failure due to stress corrosion. Maintaining the chemistry within the Steady-State Limits provides adequate corrosion protection to ensure the structural integrity of the Reactor Coolant System over the life of the plant. The associated effects of exceeding the oxygen, chloride, and fluoride limits are time and temperature dependent. Corrosion studies show that operation may be continued with contaminant concentration levels in excess of the Steady-State Limits, up to the Transient Limits, for the specified limited time intervals without having a significant effect on the structural integrity of the Reactor Coolant System. The time interval permitting continued operation within the restrictions of the Transient Limits provides time for taking corrective actions to restore the contaminant concentrations to within the Steady-State Limits.The Surveillance Requirements provide adequate assurance that concentrations in excess of the limits will be detected in sufficient time to take corrective action.

PressurizerTRB 13.4.34CPSES - UNITS 1 AND 2 - TRMB 13.4-4Revision 56 B 13.4 REACTOR COOLANT SYSTEMTRB 13.4.34 Pressurizer BASESThe temperature and pressure changes during heatup and cooldown are limited to be consistent with the requirements given in the ASME Boiler and Pressure Vessel Code,Section III, AppendixG and 10CFR50, Appendix G.a.The pressurizer heatup and cooldown rates shall not exceed 100ºF/h and 200ºF/h, respectively.b.System preservice hydrotests and in-service leak and hydrotests shall be performed at pressures in accordance with the requirements of ASME Boiler and Pressure Vessel Code,Section XI.Although the pressurizer operates in temperature ranges above those for which there is reason for concern of nonductile failure, operating limits are provided to assure compatibility of operation with the fatigue analysis performed in accordance with the ASME Code requirements.

RCS Vents Specification TRB 13.4.35CPSES - UNITS 1 AND 2 - TRMB 13.4-5Revision 56 B 13.4 REACTOR COOLANT SYSTEMTRB 13.4.35 Reactor Coolant System (RCS) Vents Specification BASESReactor Coolant System vents are provided to exhaust noncondensible gases and/or steam from the Reactor Coolant System that could inhibit natural circulation core cooling. The OPERABILITY of at least one Reactor Coolant System vent path from the reactor vessel head, and the pressurizer steam space, ensures that the capability exists to perform this function.The valve redundancy of the Reactor Coolant System vent paths serves to minimize the probability of inadvertent or irreversible actuation while ensuring that a single failure of a vent valve, power supply, or control system does not prevent isolation of the vent path.The function, capabilities, and testing requirements of the Reactor Coolant System vents are consistent with the requirements of Item II.B.1 of NUREG-0737, "Clarification of TMI Action Plan

Requirements," November 1980.

ECCS - Containment DebrisTRB 13.5.31CPSES - UNITS 1 AND 2 - TRMB 13.5-1Revision 84B 13.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

TRB 13.5.31 ECCS - Containment Debris BASESRelated information is located in Technical Specification Bases 3.5.2 and 3.5.3.TRS 13.5.31.1 requires an inspection of accessible areas of containment to verify that no loose debris are present. For inspection purposes the definition of "Accessible areas" is clarified as follows. Areas which are physically restricted for the entire outage such as a bolted manway are considered "not accessible" for inspection purposes. Areas where access is restricted by a process control (e.g., RWP locked area) for the entire outage are considered "not accessible" for inspection purposes. It is the responsibility of the person(s) performing the close out inspections to verify whether or not the exception areas previously noted above have been accessed at any time during the outage.Exception areas which have been accessed during the outage should have a close out debris inspection at the time access is once again restricted by either physical means or process controls. It is not necessary to re-inspect this exception area at the final close out inspection since an inspection was previously performed and access controlled.

ECCS - Pump Line Flow RatesTRB 13.5.32CPSES - UNITS 1 AND 2 - TRMB 13.5-2Revision 84B 13.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

TRB 13.5.32 ECCS - Pump Line Flow Rates BASES"Surveillance Requirements for throttle valve position stops and flow balance testing provide assurance that proper ECCS flows will be maintained in the event of a LOCA. Maintenance of proper flow resistance and pressure drop in the piping system to each injection point is necessary to: (1) prevent total pump flow from exceeding runout conditions when the system is in its minimum resistance configuration, (2) provide the proper flow split between injection points in accordance with the assumptions used in the ECCS-LOCA analyses, and (3) provide an acceptable level of total ECCS flow to all injection points equal to or above that assumed in the

ECCS-LOCA analyses."TRS 13.5.32.1 Frequency states, "Once following completion of modifications to the ECCS subsystems that alter the subsystem flow characteristics.""Modifications to the ECCS subsystems that alter the subsystem flow characteristics" would include changes in the design or operation of any of the centrifugal charging (high head), safety injection (intermediate head), or residual heat removal (RHR) (low head) subsystems that changes either the subsystem pump performance, or the flow resistance and pressure drop in the piping system to each injection point such that conditions (1), (2) or (3) described above may

not be met.For example, if an ECCS subsystem pump has been refurbished/replaced, the flow balance test for the subsystem does not need to be repeated due to replacement of the pump, as long as the required IST Pump Tests have been performed for the installed configuration, and the following conditions are met:1.Pump performance is within the range of the minimum and maximum pump curves used in the safety analysis of record, and2.There is confirmation that the cold leg and hot leg injection line resistances have not changed since the last flow balance test.

Containment Isolation ValvesTRB 13.6.3CPSES - UNITS 1 AND 2 - TRMB 13.6-1Revision 70 B 13.6 CONTAINMENT SYSTEMS TRB 13.6.3 Containment Isolation Valves BASESThe OPERABILITY of the containment isolation valves ensures that the containment atmosphere will be isolated from the outside environment in the event of a release of radioactive material to the containment atmosphere or pressurization of the containment and is consistent with the requirements of General Design Criteria 54 through 57 of 10CFR50, Appendix A. Containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a LOCA.AIRLOCK VALVES CREDITED AS CONTAINMENT ISOLATION VALVESThe following discussion is provided to clarify the bases for the application of TS LCO 3.6.2 to the airlock valves so designated in TRM Table 13.6.3-1 that are also credited as Containment Isolation Valves.These airlock penetration isolation valves are located in penetrations that are required to be closed during accident conditions and are included in the TRM table of Containment Isolation Valves for completeness. These valves are manual valves secured in their closed position

except when open under administrative controls as provided in the TRM.The designated airlock valves, including the airlock test connection isolation valves, are part of the airlock leak tight boundaries and directly affect the requirements for Containment Air Lock OPERABILITY as defined by the TS Bases. Therefore, they are subject to the controls of Specification 3.6.2. As such, the requirements of Specification 3.6.3 do not apply.Both Note 6 and the corresponding statements applicable to the airlock test connections included in the Table Notation for the local vent, drain, and test connections (TVDs), provide that the airlock valves are included in the table of Containment Isolation Valves for completeness and that the requirements of Specification 3.6.3 do not apply. Instead, the airlock valves are considered an integral part of the airlock and are therefore subject to the controls of Specification 3.6.2.

References:

1)Evaluation SE-90-222, approved 10/26/19902)Evaluation SE-91-104, approved 11/13/1991 (Includes evaluation of "Tech Spec Applicability to Airlock Valves")3)LDCR TR-90-010, approved 11/20/19914)TUE Conference Memorandum TCO-91019, dated 6/10/19915)EVAL-2004-003317-01, re: LCO applicability to airlock boundary penetration valves Containment Spray SystemTRB 13.6.6CPSES - UNITS 1 AND 2 - TRMB 13.6-2Revision 70 B 13.6 CONTAINMENT SYSTEMS TRB 13.6.6 Containment Spray System BASESRelated information is located in Technical Specification Bases 3.6.6.

Spray Additive SystemTRB 13.6.7CPSES - UNITS 1 AND 2 - TRMB 13.6-3Revision 70 B 13.6 CONTAINMENT SYSTEMSTRB 13.6.7 Spray Additive System BASES The performance test requirements for the Spray Additive System subject to SR 3.6.7.1 ensures that the available buffering agent is sufficient to ensure that the equilibrium containment sump pH

is greater than or equal to 7.1.

TRS 13.6.7.1This entails verifying the correct alignment of Spray Additive System manual, power operated, and automatic valves in the spray additive flow path provides assurance that the system is able to provide additive to the Containment Spray System in the event of a DBA. This performance test requirement does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing.This performance test requirement does not require any testing or valve manipulation. Rather, it involves verification through a system walkdown (which may include the use of local or remote indicators), that those valves outside containment and capable of potentially being mispositioned

are in the correct position.

TRS 13.6.7.2To provide effective iodine removal, the containment spray must be an alkaline solution. Since the RWST contents are normally acidic, the volume of the spray additive tank must provide a sufficient volume of spray additive to adjust pH for all water injected. This performance test

requirement is performed to verify the availability of sufficient NaOH solution in the Spray Additive System. The required volume may be verified using an indicated level bank of 91% to 94% for the Spray Additive Tank which corresponds to an analytical limit band of 4900 gallons to 5314 gallons, respectively, and includes a 3.36% measurement uncertainty. The 184 day Frequency was developed based on the low probability of an undetected change in tank volume occurring during the performance test requirement interval (the tank is isolated during normal unit operations). Tank level is also indicated and alarmed in the control room, so that there is high confidence that a substantial change in level would be detected.

TRS 13.6.7.3This performance test requirement provides verification of the NaOH concentration in the spray additive tank and is sufficient to ensure that the spray solution being injected into containment is at the correct pH level. The 184 day Frequency is sufficient to ensure that the concentration level of NaOH in the spray additive tank remains within the established limits. This is based on the low likelihood of an uncontrolled change in concentration (the tank is normally isolated) and the probability that any substational variance in tank volume will be detected.(continued)

Spray Additive SystemTRB 13.6.7 BASESCPSES - UNITS 1 AND 2 -TRMB 13.6-4Revision 70 TRS 13.6.7.4This performance test requirement provides verification that each automatic valve in the Spray Additive System flow path actuates to its correct position on a Containment Spray Actuation signal. This performance tests is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The 18 month Frequency is based on the need to perform this test under the conditions that apply during a plant outage and the potential for an unplanned transient if the performance test were performed with the reactor at power. Operating experience has shown that these components usually pass the performance test when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

TRS 13.6.7.5 To ensure correct operation of the Spray Additive System, flow through the Spray Additive System eductors is verified once every 5 years. Flow of between 50 and 100 gpm through the eductor test loops (supplied from the RWST) simulates flow from the Chemical Additive Tank.

Due to the passive nature of the spray additive flow controls, the 5 year Frequency is sufficient to identify component degradation that may affect flow.

MSIVsTRB 13.7.2CPSES - UNITS 1 AND 2 - TRMB 13.7-1Revision 83 B 13.7 PLANT SYSTEMSTRB 13.7.2 Main Steam Isolation Valves BASESRelated information is located in Technical Specification Bases Section 3.7.2

.

FIVs and FCVs and Associated Bypass ValvesTRB 13.7.3CPSES - UNITS 1 AND 2 - TRMB 13.7-2Revision 83 B 13.7 PLANT SYSTEMSTRB 13.7.3 Feedwater Isolation Valves (FIVs) and Feedwater Control Valves (FCVs) and Associated Bypass Valves BASESRelated information is located in Technical Specification Bases Section 3.7.3

.

Steam Generator ARV - Air Accumulator TankTRB 13.7.31CPSES - UNITS 1 AND 2 - TRMB 13.7-3Revision 83 B 13.7 PLANT SYSTEMSTRB 13.7.31 Steam Generator Atmospheric Relief Valve (ARV) - Air Accumulator Tank BASES Related requirements/information is located in Technical Specification Bases Section 3.7.4

.

Steam Generator Pressure / Temperature LimitationTRB 13.7.32CPSES - UNITS 1 AND 2 - TRMB 13.7-4Revision 83 B 13.7 PLANT SYSTEMS TRB 13.7.32 Steam Generator Pressure / Temperature Limitation BASES The limitation on steam generator pressure and tem perature ensures that the pressure-induced stresses in the steam generators do not exceed the maximum allowable fracture toughness stress limits. The limitations of 70

ºF and 200 psig are based on a steam generator RTNDT of 60ºF and are sufficient to prevent brittle fracture. The pressure limit is applicable whenever the primary or secondary systems can be pressurized to the limit of 200 psig. For surveillance 13.7.32.1, the primary and secondary systems are considered no longer capable of being pressurized following depressurization to atmospheric conditions and when at least a 4 inch diameter vent path for the primary system and at least a 3 inch diameter vent path for the secondary system on the associated steam generator are established and administratively maintained (e.g., reactor vessel head removed for the primary system and all steam generator manways removed for the secondary system). If the primary and secondary vent path are being used to meet the LCO then surveillance 13.7.32.2 verifies the vent paths remain established.

Ultimate Heat Sink - Sediment and SSI Dam TRB 13.7.33CPSES - UNITS 1 AND 2 - TRMB 13.7-5Revision 83 B 13.7 PLANT SYSTEMSTRB 13.7.33 Ultimate Heat Sink - Sediment and Safe Shutdown Impoundment (SSI) Dam BASESThe limitations on the SSI Dam ensure that sufficient cooling capacity is available in the event of an SSE.The limitation on average sediment depth is based on the possible excessive sediment buildup in the service water intake channel.

Flood Protection TRB 13.7.34CPSES - UNITS 1 AND 2 - TRMB 13.7-6Revision 83 B 13.7 PLANT SYSTEMSTRB 13.7.34 Flood Protection BASESThe limitation of flood protection ensures that facility protective actions will be taken in the event of flood conditions. The only credible flood condition that endangers safety related equipment is from water entry into the turbine building via the circulating water system from Squaw Creek Reservoir and then only if the level is above 778 feet Mean Sea Level. This corresponds to the elevation at which water could enter the electrical and control building endangering the safety chilled water system. The surveillance requirements are designed to implement level monitoring of Squaw Creek Reservoir should it reach an abnormally high level above 776 feet. The Limiting Condition for Operation is designed to implement flood protection, by ensuring no open flow path via the Circulating Water System exists, prior to reaching the postulated flood level.Due to the access opening in the operating deck of the circulating water discharge structure, the stop gates isolate the CW tunnels for lake levels below 778 feet only. Any opening in the CW system at an elevation below the probable maximum flood level of 789.7 feet must be closed or isolated in order to isolate the lake levels above 778 from the open pathway that could lead to flooding of the turbine building and lower level of the electrical & control building on elevation 778.

Snubbers TRB 13.7.35CPSES - UNITS 1 AND 2 - TRMB 13.7-7Revision 83 B 13.7 PLANT SYSTEMS TRB 13.7.35 Snubbers BASESAll snubbers are required OPERABLE to ensure that the structural integrity of the Reactor Coolant System and all other safety-related systems is maintained during and following a seismic or other event initiating dynamic loads.Snubbers are classified and grouped by design and manufacturer but not by size. For example, mechanical snubbers utilizing the same design features of the 2-kip, 10-kip and 100-kip capacity manufactured by Company "A" are of the same type. The same design mechanical snubbers manufactured by Company "B" for the purposes of this Technical Specification would be of a different type, as would hydraulic snubbers from either manufacturer.A list of individual snubbers with detailed information of snubber location and size and of system affected shall be available at the plant in accordance with 10CFR50.71(c). The accessibility of each snubber shall be determined and approved by the Station Operation Review Committee (SORC). The determination shall be based upon the existing radiation levels and the expected

time to perform a visual inspection in each snubber location as well as other factors associated with accessibility during plant operations (e.g., temperature, atmosphere, location, etc.), and the recommendations of Regulatory Guides 8.8 and 8.10. The addition or deletion of any hydraulic or mechanical snubber shall be made in accordance with 10CFR50.59.Surveillance to demonstrate OPERABILITY is by performance of the requirements of an approved inservice inspection program.Permanent or other exemptions from the surveillance program for individual snubbers may be granted by the Commission if a justifiable basis for exemption is presented and, if applicable, snubber life destructive testing was performed to qualify the snubbers for the applicable design conditions at either the completion of their fabrication or at a subsequent date. Snubbers so exempted shall be listed in the list of individual snubbers indicating the extent of the exemptions.The service life of a snubber is established via manufacturer input and information through consideration of the snubber service conditions and associated installation and maintenance records (newly installed snubbers, seal replaced, spring replaced, in high radiation area, in high temperature area, etc.). The requirement to monitor the snubber service life is included to ensure that the snubbers periodically undergo a performance evaluation in view of their age and operating conditions. These records will provide statistical bases for future consideration of snubber service life.

Area Temperature MonitoringTRB 13.7.36CPSES - UNITS 1 AND 2 - TRMB 13.7-8Revision 83 B 13.7 PLANT SYSTEMS TRB 13.7.36 Area Temperature Monitoring BASES The limitations on nominal area temperatures ensure that safety-related equipment will not be subjected to temperatures that would impact their environmental qualification temperatures. Exposure to temperatures in excess of the maximum temperature for normal conditions for extended periods of time could reduce the qualified life or design life of that equipment.

Exposure to temperatures in excess of the maximum abnormal temperature could degrade the OPERABILITY of that equipment.Normal and abnormal temperature limits for the following areas are assured by monitoring other areas with a correlated temperature relationship:TEMPERATURE LIMIT (°F)AreaNormalConditions AbnormalConditions Area MonitoredCRDM Platform Barrier140149General Area CRDM Shroud Exhaust (Unit 2 Only)

CRDM Air Handling Unit Inlet (Unit 1 Only)

Reactor Cavity Detector Well135175Reactor Cavity Exhaust R.C. Pipe Penetration Exhaust (N-16 Detectors)200209General Areas Reactor Cavity Exhaust Safety Chilled Water System - Electrical Switchgear Area Emergency Fan Coil Units TRB 13.7.37CPSES - UNITS 1 AND 2 - TRMB 13.7-9Revision 83 B 13.7 PLANT SYSTEMSTRB 13.7.37 Safety Chilled Water System - Electrical Switchgear Area Emergency Fan Coil Units BASES Related requirements/information is located in Technical Specification Bases Section 3.7.19

.Inoperable electrical switchgear area emergency fan coil units should not require actions more severe than the loss of the entire associated Safety Chilled Water System Train. Therefore, where one or more electrical switchgear area electrical fan coil units are inoperable it is acceptable to declare the associated Safety Chilled Water System Train inoperable and enter

Technical Specifications 3.7.19

.The frequency for the integrated test sequence/loss of offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

Main Feedwater Isolation Valve Pressure / Temperature LimitTRB 13.7.38CPSES - UNITS 1 AND 2 - TRMB 13.7-10Revision 83 B 13.7 PLANT SYSTEMSTRB 13.7.38 Main Feedwater Isolation Valve Pressure / Temperature Limit BASESThe fracture toughness requirements are satisfied with a metal temperature of 90

ºF for the main feedwater isolation valve body and neck, therefore, these portions will be maintained at or above this temperature prior to pressurization of these valves above 675 psig. Minimum temperature limitations are imposed on the valve body and neck of main feedwater isolation valves HV-2134, HV-2135, HV-2136 and HV-2137. These valves do not need to be verified at or above 90

ºF when in MODES 4, 5, or 6 (except during special pressure testing) since Tavg < 350ºF which corresponds to a pressure at the valves of 140-150 psig or less. The maximum pressurization during cold conditions (valve temperature < 90

ºF) should be limited to no more than 20% of the valve hydrostatic test pressure (3375 psig X 20% = 675 psig).

Tornado Missile ShieldsTRB 13.7.39CPSES - UNITS 1 AND 2 - TRMB 13.7-11Revision 83 B 13.7 PLANT SYSTEMSTRB 13.7.39 Tornado Missile Shields BASESThe purpose of tornado missile shields is to protect equipment from tornado generated missiles, and given the fact that adequate warning is available for tornado conditions, it is not necessary to consider protected equipment inoperable solely due to its missile shield being removed. This TRM provides conservative pre-planned allowances for control of missile shields without further consideration of equipment OPERABILITY. Removal of missile shields not contained herein, or exceeding the bounds of these allowances require additional assessment of equipment OPERABILITY. The conservative option to declare affected equipment inoperable and comply with the provisions of Technical Specifications is always available.The following allowances have considered the impact on HVAC pressure boundaries, but do not address Security and Fire Protection requirements.The capability to immediately re-install missile shields as used in the TRM allowances is deemed to exist when the necessary equipment to perform the installation is located on site and is

available for use. Personnel necessary to operate the equipment shall be onsite and available when weather conditions exist such that a potential for a Tornado Watch or Warning exists. If weather conditions pose no immediate potential for adverse weather, then personnel associated

with the operation of the equipment shall be available and within 90 minutes of the site, with the exception of the EDG Missile Shield barriers where such personnel shall be available on site for the duration of the allowed opening time due to the complexity of shield restoration, the more stringent controls required to limit opening time and the more critical importance of the protected equipment. The shield shall also be in such condition and location to support reinstallation.Removal and installation of missile shields shall be conducted in accordance with approved plant procedures.

Installation of each removed shield shall begin immediately upon the associated notification (Tornado Watch, Tornado Warning, etc.) otherwise the affected system(s) shall be declared inoperable.(continued)

Tornado Missile ShieldsTRB 13.7.39 BASESCPSES - UNITS 1 AND 2 -TRMB 13.7-12Revision 83 DEFINITIONS*:1.Primary Plant Ventilation Pressure Boundary - An established physical boundary, within the confines of the Fuel, Auxiliary and Safeguards buildings, which has been demonstrated via surveillance testing to provide the negative pressure envelope required by LCO 3.7.12

.2.Direct Communication - The condition of having a known flow path, from the building through the Primary Plant Ventilation Pressure Boundary into the negative pressure envelope, that does not contain barriers which have been proven to adequately maintain the negative pressure envelope required by LCO 3.7.12.

• These definitions are used with the confines of this TRM specification only.

REFERENCE:

TE-SE-90-615 (As supplemented by EV-CR-2010-004974-4) EV-CR-2010-004974-4 CST Make-up and Reject Line Isolation Valves TRB 13.7.41CPSES - UNITS 1 AND 2 - TRMB 13.7-13Revision 83 B 13.7 PLANT SYSTEMSTRB 13.7.41 Condensate Storage Tank (CST) Make-up and Reject Line Isolation Valves BASESBACKGROUNDThe CST provides a safety grade source of water to the steam generators for removing decay and sensible heat from the Reactor Coolant System (RCS) to cool down the unit following all events in the accident analysis as discussed in the, FSAR Chapter 15. The CST provides a passive flow of water, by gravity, to the Auxiliary Feedwater (AFW) System (TS 3.7.5). The CST also provides makeup and surge capacity for secondary system inventory changes caused by different

operational conditions, thermal effects, and the draining and recharging of any part of the system.The CST is isolated from its non-safety-related users by automatically closing motor-operated valves in the make-up reject line when the motor-driven or turbine-driven auxiliary feedwater pumps start. The make-up and reject line tap is located above the safety related CST volume; therefore, closure is not a required safety function to prevent the outflow of CST water. The active safety function of the valves in the make-up and reject line is to prevent inflow which could adversely affect CST and

AFW operability. The condensate make-up and reject line is also isolated by automatically closing motor operated valves HV-2484 and HV-2485 when the condensate storage tank reaches a HI-HI level.

Automatic closure of these isolation valves is required to protect the CST from overpressurization or damage to the floating diaphragm which could result from a condenser surge. Overpressure of the tank could lead to failure. Damage to the liner could lead to common mode failure of all AFW pumps.The valves can also be operated manually from local control board switches.A description of the CST is found in the FSAR Section 9.2.6

.APPLICABLE SAFETY ANALYSESThe CST provides cooling water to remove decay heat and to cool down the unit during normal operation and following design bases events as discussed in the safety analyses in FSAR Chapters 3 , 5 , 6 , 7 , 9 and 15. The CST make-up and reject line isolation valves ensure the availability of the cooling water supply by protecting the CST.(continued)

CST Make-up and Reject Line Isolation Valves TRB 13.7.41 BASESCPSES - UNITS 1 AND 2 -TRMB 13.7-14Revision 83 LCOThe LCO requires that two CST make-up and reject line isolation valves be OPERABLE to ensure that the valves function to protect the CST.APPLICABILITYIn MODES 1, 2, and 3, the CST make-up and reject line isolation valves are required to be OPERABLE except when the CST make-up and reject line is isolated by a closed and de-activated isolation valve. When the CST make-up and reject line is isolated by a closed and de-activated isolation valve the safety function to protect the CST from overpressurization is already being met.ACTIONSA.1 and A.2With one of the required make-up and reject line isolation valves inoperable in MODE 1, 2, or 3, except when the CST make-up and reject line is isolated by a closed and de-activated isolation valve, action must be taken to restore the valve to OPERABLE status or to isolate the make-up and reject flowpath within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and to verify the flowpath isolated every 31days. The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time and 31 day surveillance interval are reasonable, based on capabilities afforded by the design with a redundant valve, time needed for repairs, and the low probability of a condenser surge occurring during this time period.

B.1With both of the required make-up and reject line isolation valves inoperable in MODE 1, 2, or 3, except when the CST make-up and reject line is isolated by a closed and de-activated isolation valve, action must be taken to restore a make-up and reject line isolation valve to OPERABLE status within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or to isolate the make-up and reject flowpath. The 4hour completion time is reasonable given the low probability of a condenser surge occurring during this time period.

C.1 and C.2With the completion time of Condition A or B not met, a backup water supply must be determined to be available by administrative means within 4hours and once every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter. OPERABILITY of the backup water supply must include verification that the flow paths from the backup water supply to the AFW pumps are OPERABLE, and that the SSWS is Operable. In addition, each motor operated valve between the SSWS and each Operable AFW pump must be OPERABLE. If isolation of the makeup and reject line is not possible then both make-up and (continued)

CST Make-up and Reject Line Isolation Valves TRB 13.7.41 BASESCPSES - UNITS 1 AND 2 -TRMB 13.7-15Revision 83 ACTIONS (continued)

C.1 and C.2 (continued)reject line isolation valves must be restored to OPERABLE status within 7 days, because the backup supply is not automatic. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Completion Time is reasonable, based on operating experience, to verify the OPERABILITY of the backup water supply. Additionally, verifying the backup water supply every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is adequate to ensure the backup

water supply continues to be available. The 7 day Completion Time is reasonable, based on an OPERABLE backup water supply being available, and the low probability of an event occurring during this time period requiring the CST.

TECHNICAL REQUIREMENTS SURVEILLANCE TRS 13.7.41.1The surveillance requirement verifies the operability of the make-up and reject line valves and their actuation circuitry on an actual or simulated HI-HI CST level signal or an SI signal to ensure the protection of the CST and floating diaphragm from overpressurization.TRS 13.7.41.2The surveillance requirement verifies that a make-up and reject line isolation actuation signal is initiated on CST HI-HI level.

AC Sources (Diesel Generator Requirements)

TRB 13.8.31CPSES - UNITS 1 AND 2 - TRMB 13.8-1Revision 83 B 13.8 ELECTRICAL POWER SYSTEMSTRB 13.8.31 AC Sources (Diesel Generator Requirements)

BASES Related requirements/information is located in Technical Specification Bases Section 3.8.1.These surveillance requirements reflect normal design, maintenance or line-up activities/descriptions rather than features specifically needed to successfully mitigate a DBA or design transient.The diesel's preventative maintenance program is commensurate for nuclear standby service, which takes into consideration the following factors: manufacturer's recommendations, diesel owners group's recommendations, engine run time, equipment performance, calendar time, and plant preventative maintenance programs.The frequency for the integrated test sequence/loss of offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

Containment Penetration Conductor Overcurrent Protection Devices TRB 13.8.32CPSES - UNITS 1 AND 2 - TRMB 13.8-2Revision 83 B 13.8 ELECTRICAL POWER SYSTEMS TRB 13.8.32 Containment Penetration Conductor Overcurrent Protection Devices BASESContainment electrical penetrations and penetration conductors are protected by either deenergizing circuits not required during reactor operation or by demonstrating the OPERABILITY of primary and backup overcurrent protection circuit breakers during periodic surveillance. This is based on the recommendations of Regulatory Guide 1.63, Revision 2, July1978, "Electric Penetration Assemblies in Containment Structures for Light-Water-Cooled Nuclear Power Plants."The Surveillance Requirements applicable to lower voltage circuit breakers provide assurance of breaker reliability by testing at least 10% of each manufacturer's brand of circuit breaker. Each manufacturer's molded case and metal case circuit breakers are grouped into representative samples which are then tested on a rotating basis to ensure that all breakers are tested. If a wide variety exists within any manufacturer's brand of circuit breakers, it is necessary to divide that manufacturer's breakers into groups and treat each group as a separate type of breaker for surveillance purposes.All Class 1E motor-operated valves' motor starters are provided with thermal overload protection which is permanently bypassed and provides an alarm function only at Comanche Peak Steam

Electric Station. Therefore, there are no OPERABILITY or Surveillance Requirements for these devices, since they will not prevent safety-related valves from performing their function (refer to Regulatory Guide 1.106, "Thermal Overload Protection for Electric Motors on Motor Operated

Valves," Revision 1, March 1977).

Decay TimeTRB 13.9.31CPSES - UNITS 1 AND 2 - TRMB 13.9-1Revision 77B 13.9 REFUELING OPERATIONS TRB 13.9.31 Decay Time BASESThe minimum required time for reactor subcriticality prior to movement of irradiated fuel assemblies within the reactor vessel ensures sufficient radioactive decay of those fission products that contribute to the radiological consequences of a postulated fuel handling accident.

Per Regulatory Guide 1.195, these fission products include xenon, krypton and iodine whose activity is assumed to be instantaneously released to the refueling cavity during the accident. The fraction of iodine retained within the cavity is determined by the water depth above the damaged fuel assembly as specified in Technical Specifications LCO 3.9.7, "Refueling Cavity Water Level." Retention of noble gases within the cavity is negligible. Release of fission products from the refueling cavity to the environment occurs over a 2-hour time period.The required decay time and the water level requirement of Technical Specifications LCO 3.9.7 ensure the control room, exclusion area boundary, and low population zone dose limits of References 1, 3 and 4 are met following a fuel handling accident within containment. The assumptions for a fuel handling accident occurring within the fuel building are similar and the radiological consequences are equivalent. The required decay time is consistent with the assumptions used in the safety analysis (Ref. 5).REFERENCES1.Regulatory Guide 1.195, May 20032.Technical Specifications 3.10CFR1004.Appendix A to 10CFR50, General Design Criteria 195.FSAR Section 15.7.4 Refueling Operations / CommunicationsTRB 13.9.32CPSES - UNITS 1 AND 2 - TRMB 13.9-2Revision 77B 13.9 REFUELING OPERATIONS TRB 13.9.32 Refueling Operations / Communications BASESThe requirement for communications capability ensures that refueling station personnel can be promptly informed of significant changes in the facility status or core reactivity conditions during CORE ALTERATIONS.

Refueling MachineTRB 13.9.33CPSES - UNITS 1 AND 2 - TRMB 13.9-3Revision 77B 13.9 REFUELING OPERATIONS TRB 13.9.33 Refueling Machine BASESThe OPERABILITY requirements for the refueling machine main hoist and auxiliary monorail hoist ensure that: (1) the main hoist will be used for movement of fuel assemblies, (2) the auxiliary monorail hoist will typically be used for latching, unlatching and movement of control rod drive shafts, (3) the main hoist has sufficient load capacity to lift a fuel assembly (with control rods), (4)the auxiliary monorail hoist has sufficient load capacity to latch, unlatch and move the control rod drive shafts, and (5) the core internals and reactor vessel are protected from excessive lifting force in the event they are inadvertently engaged during lifting operations. The LCO is modified by a note which provides for the use for additional hoists and load indicators for special planned evolutions such as a bent control rod drive shaft.

Refueling - Crane Travel - Spent Fuel Storage AreasTRB 13.9.34CPSES - UNITS 1 AND 2 - TRMB 13.9-4Revision 77B 13.9 REFUELING OPERATIONSTRB 13.9.34 Refueling - Crane Travel - Spent Fuel Storage Areas BASESLCOThe restriction on movement of loads in excess of the nominal weight of a fuel and control rod assembly and associated handling tool over other fuel assemblies in a storage pool ensures that in the event this load is dropped: (1) the activity release will be limited to that contained in a single fuel assembly, and (2) any possible distortion of fuel in the storage racks will not result in a critical array. This assumption is consistent with the activity release assumed in the safety analyses.TECHNICALTRS 13.9.34.2 REQUIREMENTSSURVEILLANCEIn order to prevent more than a single fuel assembly being moved over other fuel assemblies in a storage pool, interlocks prevent control of a trolley-hoist assembly unless the opposite trolley-hoist assembly has the hook unloaded and completely up, and the trolley located in the far east end parking area.

Water Level, Reactor Vessel, Control RodsTRB 13.9.35CPSES - UNITS 1 AND 2 - TRMB 13.9-5Revision 77B 13.9 REFUELING OPERATIONS TRB 13.9.35 Water Level, Reactor Vessel, Control Rods BASESThe restrictions on minimum water level ensure that sufficient water depth is available to remove 99% of the assumed 10% iodine gap activity released from the rupture of an irradiated fuel assembly. The minimum water depth is consistent with the assumptions of the safety analysis.

Fuel Storage Area Water LevelTRB 13.9.36CPSES - UNITS 1 AND 2 - TRMB 13.9-6Revision 77B 13.9 REFUELING OPERATIONSTRB 13.9.36 Fuel Storage Area Water Level BASESThe requirement to suspend crane operations over the spent fuel pool in the event pool water level is < 23 feet provides for conservative plant operations consistent with the accident analysis. The bounding design basis fuel handling accident in the spent fuel pool assumes 23 feet of water above the damaged fuel assembly in the spent fuel pool which mitigates the radiological

consequences.

Crane operations that could adversely affect fuel stored in the spent fuel pool are controlled in accordance with plant procedures as analyzed in the review of heavy loads movements. Administrative controls are employed to prevent the handling of loads that have a greater potential energy than those which have been analyzed. This Technical Requirement further ensures, for loads < 2150 pounds, that the water level is greater than that assumed in the analysis.

REFERENCE:

NRC Bulletin 96-02, "Movement of Heavy Loads Over Spent Fuel, Over Fuel in the Reactor Core, or Over Safety-Related Equipment."

Explosive Gas Monitoring InstrumentationTRB 13.10.31CPSES - UNITS 1 AND 2 - TRMB 13.10-1Revision 56B 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAMTRB 13.10.31 Explosive Gas Monitoring Instrumentation BASESThe explosive gas instrumentation is provided to monitor and control, the concentrations of potentially explosive gas mixtures in the WASTE GAS HOLDUP SYSTEM. The OPERABILITY and use of this instrumentation is consistent with the requirements of General Design Criteria 63, and 64 of 10 CFR 50, Appendix A. One hydrogen and two oxygen monitors are required to be OPERABLE for the operating recombiner during WASTE GAS HOLDUP SYSTEM (WGHS) operation. The following discussion provides clarification of "WGHS operation" and "degassing".For the purpose of this specification, with no input gases allowed to the WGHS, recirculation of the WGHS as well as sampling, recirculation, storage, and discharge of a waste gas decay tank are not considered as WGHS operation.

Degassing operation (which is a type of WGHS operation) is defined as purging the RCS of residual gases during unit shutdown.

Gas Storage TanksTRB 13.10.32CPSES - UNITS 1 AND 2 - TRMB 13.10-2Revision 56B 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAMTRB 13.10.32 Gas Storage Tanks BASESThe tanks included in this specification are those tanks for which the quantity of radioactivity contained is not limited directly or indirectly by another Technical Specification. Restricting the quantity of radioactivity contained in each gas storage tank provides assurance that in the event of an uncontrolled release of the tank's contents, the resulting whole body exposure to a MEMBER OF THE PUBLIC at the nearest SITE BOUNDARY will not exceed 0.5 rem. This is consistent with Standard Review Plan 11.3, Branch Technical Position ETSB 11-5, "Postulated Radioactive Releases Due to a Waste Gas System Leak or Failure," in NUREG-0800, July 1981.

Liquid Holdup TanksTRB 13.10.33CPSES - UNITS 1 AND 2 - TRMB 13.10-3Revision 56B 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAMTRB 13.10.33 Liquid Holdup Tanks BASESThe tanks listed in this specification include all those unprotected outdoor tanks both permanent and temporary that are not surrounded by liners, dikes, or walls capable of holding the tank contents and that do not have tank overflows and surrounding area drains connected to the Liquid Radwaste Treatment System.

Restricting the quantity of radioactive material contained in the specified tanks provides assurance that in the event of an uncontrolled release of the tank's contents, the resulting concentrations would be less than the values given in Appendix B, Table 2, Column 2, to 10CFR20.1001 - 20.2402, at the nearest potable water supply and the nearest surface water supply in an UNRESTRICTED AREA.

Explosive Gas MixtureTRB 13.10.34CPSES - UNITS 1 AND 2 - TRMB 13.10-4Revision 56B 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAMTRB 13.10.34 Explosive Gas Mixture BASESThis specification is provided to ensure that the concentration of potentially explosive gas mixtures contained in the WASTE GAS HOLDUP SYSTEM is maintained below the flammability limits of hydrogen and oxygen. Automatic control features are included in the system to prevent the hydrogen and oxygen concentrations from reaching these flammability limits. These automatic control features include isolation of the source of hydrogen and/or oxygen. Maintaining the concentration of hydrogen and oxygen below their flammability limits provides assurance that the releases of radioactive materials will be controlled in conformance with the requirements of General Design Criterion 60 of 10CFR50 Appendix A.

Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-1Revision 83 B 15.5 PROGRAMS AND MANUALSTRB 15.5.5.21 Surveillance Frequency Control Program BASES The Technical Specification Surveillance Requirement Frequencies subject to the provisions of TS 5.5.21, "Surveillance Frequency Control Program" are listed in Table 5.5.21-1, "Technical Specification Surveillance Requirement Frequencies." The Frequencies were relocated from the Technical Specifications to Technical Requirement 15.5.21 upon implementation of License Amendment 156 to the CPNPP Operating License. Changes to these Frequencies may only be made in accordance with NEI 04-10, "Risk-Informed Method for Control of Surveillance Frequencies," Revision 1 and Technical Requirement 15.5.17.

Table B 15.5.21-1 provides the SR Frequencies and the Bases that were relocated from the Technical Specifications, the revised Bases for those Frequencies that have since been revised in accordance with Technical Specification 5.5.21, "Surveillance Frequency Control Program" and that are currently located in TRM Table 15.5.21-1, and a reference to the documentation

which provides the evaluation for the revised Frequency. Note: Bracketed text in the Frequency is NOT subject to the Surveillance Frequency Control Program. The bracketed text is repeated from the Technical Specifications for completeness.(continued)

Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-2Revision 83 Table B 15.5.21-1 (Sheet 1 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCESR 3.1.1.124 hours0.00144 days <br />0.0344 hours <br />2.050265e-4 weeks <br />4.7182e-5 months <br /> BASES:

The Frequency of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is based on the generally slow change in required boron concentration and the low probability of an accident occurring without the required SDM. This allows time for the operator to collect the required data, which includes performing a boron concentration analysis, and complete the calculation.

Revised BASES:

LA 156SR 3.1.2.1[Once prior to entering MODE 1 after each refueling AND ----------------NOTE--------------- Only required after 60 EFPD

---

]

31 EFPD thereafter BASES:

The required subsequent Frequency of 31 EFPD, following the initial 60 EFPD after

entering MODE 1, is acceptable, based on the slow rate of core changes due to fuel depletion and the presence of other indicators (QPTR, AFD, etc.) for prompt indication of an anomaly.

Revised BASES:

LA 156 Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-3Revision 83 SR 3.1.4.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: Verification that individual rod positions are within alignment limits at a Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> provides a history that allows the operator to detect a rod that is beginning to deviate from its expected position. If the rod position deviation monitor is inoperable, the Frequency is increased to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> per TRM

requirement TRS 13.1.37.1 which accomplishes the same goal. The specified Frequency takes into account other rod

position information that is continuously available to the operator in the control room, so that during actual rod motion, deviations can immediately be detected.

Revised BASES:

LA 156SR 3.1.4.292 days BASES: Exercising each individual control rod every 92 days provides increased confidence that all rods continue to be OPERABLE without exceeding the alignment limit, even if they

are not regularly tripped. Moving each control rod by 10 steps will not cause radial or axial power tilts, or oscillations, to occur.

The 92 day Frequency takes into consideration other information available to the operator in the control room and SR 3.1.4.1, which is performed more frequently and adds to the determination of OPERABILITY of the rods.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 2 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-4Revision 83 SR 3.1.5.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: Since the shutdown banks are positioned manually by the control room operator, a verification of shutdown bank position at a Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is adequate to ensure that they are within their insertion limits. Also, the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency takes into account other information available in the control room for the purpose of monitoring the status of shutdown rods.

Revised BASES:

LA 156SR 3.1.6.212 hours0.00245 days <br />0.0589 hours <br />3.505291e-4 weeks <br />8.0666e-5 months <br /> BASES:

Verification of the control bank insertion limits at a Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient to ensure OPERABILITY and to detect control banks that may be approaching the insertion limits since, normally, very little rod motion occurs in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

Revised BASES:

LA 156SR 3.1.6.312 hours0.00361 days <br />0.0867 hours <br />5.15873e-4 weeks <br />1.18716e-4 months <br /> BASES: A Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is consistent with the insertion limit check above in SR 3.1.6.2.

Revised BASES LA 156Table B 15.5.21-1 (Sheet 3 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-5Revision 83 SR 3.1.8.230 minutes BASES: Verification of the RCS temperature at a Frequency of 30 minutes during the performance of the PHYSICS TESTS will ensure that the initial conditions of the safety analyses are not violated.

Revised BASES:

LA 156SR 3.1.8.31 hour3.587963e-4 days <br />0.00861 hours <br />5.125661e-5 weeks <br />1.17955e-5 months <br /> BASES: Verification of the THERMAL POWER at a Frequency of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> during the performance of the PHYSICS TESTS will ensure that the initial conditions of the safety analyses are not violated.

Revised BASES:

LA 156SR 3.1.8.424 hours0.00491 days <br />0.118 hours <br />7.010582e-4 weeks <br />1.61332e-4 months <br /> BASES: The Frequency of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is based on the generally slow change in required boron concentration and on the low probability of an accident occurring without the required SDM. Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 4 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-6Revision 83 SR 3.2.1.1[Once after each refueling prior to THERMAL POWER exceeding 75% RTP AND Once within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after achieving equilibrium conditions after exceeding, by > 20% RTP, the THERMAL POWER at which was last verified AND] 31 EFPD thereafter

BASES: The Frequency of 31 EFPD is adequate to monitor the change of power distribution with core burnup because such changes are slow and well controlled when the plant is operated in accordance with the Technical Specifications (TS).

Revised BASES LA 156Table B 15.5.21-1 (Sheet 5 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE F Q C Z Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-7Revision 83 SR 3.2.1.2[Once after each refueling prior to THERMAL POWER exceeding 75% RTP AND Once within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after achieving equilibrium conditions after exceeding, by > 20% RTP, the THERMAL POWER at which was last verified AND] 31 EFPD thereafter

BASES: The Surveillance Frequency of 31 EFPD is adequate to monitor the change of power distribution with core burnup. The Surveillance may be done more frequently if required by the results of F Q(Z) evaluations. The Frequency of 31 EFPD is adequate to monitor the change of power distribution

because such a change is sufficiently slow, when the plant is operated in accordance with the TS, to preclude adverse peaking

factors between 31 day surveillances.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 6 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE F Q C Z Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-8Revision 83 SR 3.2.2.1'[Once after each refueling prior to THERMAL POWER exceeding 75% RTP AND] 31 EFPD thereafter BASES:

The 31 EFPD Frequency is acceptable because the power distribution changes relatively slowly over this amount of fuel burnup. Accordingly, this Frequency is short enough that the limit cannot be exceeded for any significant period of operation.

Revised BASES:

LA 156SR 3.2.3.17 days BASES:

The Surveillance Frequency of 7 days is adequate because the AFD is controlled by the operator and monitored by the process computer. Furthermore, any deviations of the AFD from requirements that is not alarmed should be readily noticed.

Revised BASES:

LA 156SR 3.2.4.17 days BASES: The Frequency of 7 days takes into account other information and alarms available to the operator in the control room.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 7 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE F NH Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-9Revision 83 SR 3.2.4.212 hours0.00245 days <br />0.0589 hours <br />3.505291e-4 weeks <br />8.0666e-5 months <br /> BASES: Performing SR3.2.4.2 at a Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> provides an accurate alternative means for ensuring that any tilt remains within its limits.

Revised BASES:

LA 156SR 3.3.1.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: The Frequency is based on operating experience that demonstrates channel

failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the LCO required channels.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 8 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-10Revision 83 SR 3.3.1.224 hours0.00259 days <br />0.0622 hours <br />3.703704e-4 weeks <br />8.5232e-5 months <br /> BASES: The Frequency of every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is adequate. It is based on unit operating experience, considering instrument reliability and operating history data for instrument drift. Together these factors demonstrate that a difference of more than +2% RTP between the calorimetric heat balance calculation and NIS Power Range channel output or N-16 Power Monitor output is not expected in any 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period.

In addition, control room operators periodically monitor redundant indications and alarms to detect deviations in channel

outputs.

Revised BASES:

LA 156SR 3.3.1.331 effective full power days (EFPD)

BASES: The Frequency of every 31 EFPD is adequate. It is based on unit operating experience, considering instrument reliability and operating history data for instrument drift. Also, the slow changes in neutron flux during the fuel cycle can be detected during

this interval.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 9 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-11Revision 83 SR 3.3.1.462 days on a STAGGERED TEST BASIS BASES: The Frequency of every 62 days on a STAGGERED TEST BASIS is justified in Reference 12.

Revised BASES:

LA 156SR 3.3.1.592 days on a STAGGERED TEST BASIS BASES: The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 12.

Revised BASES:

LA 156SR 3.3.1.692 EFPD BASES: The Frequency of 92 EFPD is adequate. It is based on industry operating experience, considering instrument reliability and operating history data for instrument drift.

Revised BASES:

LA 156SR 3.3.1.7184 days BASES: The Frequency of 184 days is justified in Reference 12.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 10 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-12Revision 83 SR 3.3.1.8[-------------------------NOTE------------------------ Only required when not performed within

previous] 184 days

[----------------------------------------------------------

Prior to reactor startup AND 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after reducing power below P-10 for power and intermediate instrumentation AND Four hours after reducing power below P-6 for source range instrumentation AND] Every 184 days thereafter BASES: The Frequency of 184 days is justified in Reference 12.

Revised BASES:

LA 156SR 3.3.1.992 days BASES: SR3.3.1.9 is the performance of a TADOT and is performed every 92 days, as justified in Reference 5.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 11 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-13Revision 83 SR 3.3.1.1018 months BASES: The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint methodology.

Revised BASES:

LA 156SR 3.3.1.1118 months BASES: Operating experience has shown these components usually pass the Surveillance when performed on the 18 month Frequency.

Revised BASES:

LA 156SR 3.3.1.1318 months BASES: The Frequency is based on the known reliability of the interlocks and the multichannel redundancy available, and has been shown to be acceptable through operating experience.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 12 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-14Revision 83 SR 3.3.1.1418 months BASES: The Frequency is based on the known reliability of the Functions and the multichannel redundancy available, and has been shown to be acceptable through operating experience.

Revised BASES:

LA 156SR 3.3.1.15Prior to exceeding the P-9 interlock whenever the unit has been in MODE 3, if not performed in previous 31 days BASES:

Not stated.

Revised BASES:

LA 156SR 3.3.1.1618 months on a STAGGERED TEST BASIS BASES:

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.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 13 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-15Revision 83 SR 3.3.2.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: The Frequency is based on operating experience that demonstrates channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the LCO required channels.

Revised BASES:

LA 156SR 3.3.2.292 days on a STAGGERED TEST BASIS BASES:

The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in

Reference 13.

Revised BASES:

LA 156SR 3.3.2.492 days on a STAGGERED TEST BASIS BASES: The Frequency of 92 days on a STAGGERED TEST BASIS is justified in Reference 13.

Revised BASES:

LA 156SR 3.3.2.5184 days BASES: The Frequency of 184 days is justified in Reference 13.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 14 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-16Revision 83 SR 3.3.2.692 days OR 18 months for Westinghouse type AR relays with AC coils BASES:

This test is performed every 92 days. The Frequency is adequate, based on industry operating experience, considering instrument reliability and operating history data. For ESFAS slave relays and auxiliary relays which are Westinghouse type AR relays, the SLAVE RELAY TEST is performed every 18 months. The Frequency is based on the slave relay reliability assessment presented in Reference 10.

Revised BASES:

LA 156SR 3.3.2.731 days BASES: The Frequency is adequate. It is based on industry operating experience, considering instrument reliability and operating history data. Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 15 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-17Revision 83 SR 3.3.2.818 months BASES: The Frequency is adequate, based on industry operating experience and is consistent with the typical refueling cycle.

Revised BASES:

LA 156SR 3.3.2.918 months BASES: The Frequency of 18 months is based on the assumption of an 18 month calibration interval in the determination of the

magnitude of equipment drift in the setpoint methodology.

Revised BASES:

LA 156SR 3.3.2.1018 months on a STAGGERED TEST BASIS BASES:

The 18 month Frequency is consistent with the typical refueling cycle and is based on

unit operating experience, which shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent occurrences.

Revised BASES:

LA 156SR 3.3.2.1118 months BASES:

This Frequency is based on operating experience.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 16 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-18Revision 83 SR 3.3.3.131 days BASES: The Frequency of 31 days is based on operating experience that demonstrates that channel failure is rare. The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the LCO required channels.

Revised BASES:

LA 156SR 3.3.3.318 months BASES:

The Frequency is based on operating experience and consistency with the typical industry refueling cycle.

Revised BASES:

LA 156SR 3.3.4.131 days BASES: The Frequency of 31 days is based upon operating experience which demonstrates that channel failure is rare.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 17 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-19Revision 83 SR 3.3.4.218 months BASES: 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 unplanned transient if the Surveillance were performed with the reactor at power. (However, this Surveillance is not required to be performed only during a unit outage.) Operating experience demonstrates that remote shutdown control channels usually pass the Surveillance test when performed at the 18

month Frequency.

Revised BASES:

LA 156SR 3.3.4.318 months BASES: The Frequency of 18 months is based upon operating experience and consistency with the typical industry refueling cycle.

Revised BASES:

LA 156SR 3.3.5.1Prior to entering MODE 4 when in MODE 5 for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and if not performed in previous 92 days BASES:

The 92 days is based on industry operating experience, considering instrument reliability and operating history data.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 18 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-20Revision 83 SR 3.3.5.2Prior to entering MODE 4 when in MODE 5 for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and if not performed in previous 92 days BASES:

The Frequency is based on the known reliability of the relays and controls and the multichannel redundancy available, and has been shown to be acceptable through operating experience.

Revised BASES:

LA 156SR 3.3.5.318 months BASES:

The Frequency of 18 months is based on operating experience and consistency with the typical industry refueling cycle and is justified by the assumption of an 18 month calibration interval in the determination of

the magnitude of equipment drift in the setpoint analysis.

Revised BASES:

LA 156SR 3.3.5.418 months on a STAGGERED TEST BASIS BASES:

Not stated.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 19 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-21Revision 83 SR 3.3.6.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: The Frequency is based on operating experience that demonstrates channel failure is rare.

Revised BASES:

LA 156SR 3.3.6.292 days on a STAGGERED TEST BASIS BASES: The Surveillance interval is justified in Reference 4.

Revised BASES:

LA 156SR 3.3.6.392 days on a STAGGERED TEST BASIS BASES:

The Surveillance interval is justified in Reference 4.

Revised BASES:

LA 156SR 3.3.6.492 days BASES: The Frequency is based on the staff recommendation for increasing the availability of radiation monitors according to NUREG-1366 (Ref.2).

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 20 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-22Revision 83 SR 3.3.6.592 days OR 18 months for Westinghouse type AR relays with AC coils BASES:

The (92 day) Frequency is acceptable based on instrument reliability and industry operating experience-The (18 month) Frequency is based on the slave relay reliability assessment presented in Reference 3.

Revised BASES:

LA 156SR 3.3.6.718 months BASES: The Frequency is based on operating experience and is consistent with the typical industry refueling cycle.

Revised BASES:

LA 156SR 3.3.7.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES:

The Frequency is based on operating experience that demonstrates channel

failure is rare.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 21 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-23Revision 83 SR 3.3.7.292 days BASES: The Frequency is based on the known reliability of the monitoring equipment and has been shown to be acceptable through operating experience.

Revised BASES:

LA 156SR 3.3.7.618 months BASES: The Frequency is based on the known reliability of the Function and the

redundancy available, and has been shown to be acceptable through operating experience.

Revised BASES:

LA 156SR 3.3.7.718 months BASES: The Frequency is based on operating experience and is consistent with the typical industry refueling cycle.

Revised BASES:

LA 156SR 3.4.1.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES:

The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> interval has been shown by operating practice to be sufficient to

regularly assess for potential degradation and to verify operation is within safety analysis assumptions.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 22 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-24Revision 83 SR 3.4.1.212 hours0.00245 days <br />0.0589 hours <br />3.505291e-4 weeks <br />8.0666e-5 months <br /> BASES: The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> interval has been shown by operating practice to be sufficient to regularly assess for potential degradation and to verify operation is within safety analysis assumptions.

Revised BASES:

LA 156SR 3.4.1.312 hours0.00361 days <br />0.0867 hours <br />5.15873e-4 weeks <br />1.18716e-4 months <br /> BASES: The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> interval has been shown by operating practice to be sufficient to regularly assess potential degradation and to verify operation within safety analysis assumptions.

Revised BASES:

LA 156SR 3.4.1.418 months BASES: The Frequency of 18 months reflects the importance of verifying flow after a refueling outage when the core has been altered, which may have caused an alteration of flow resistance.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 23 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-25Revision 83 SR 3.4.2.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: The SR to verify operating RCS loop average temperatures every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> takes into account indications and alarms that are continuously available to the operator in the control room and is consistent with other routine Surveillances which are typically performed once per shift.

Revised BASES:

LA 156SR 3.4.3.130 minutes BASES:

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 for minor deviations within a reasonable time.

Revised BASES:

LA 156SR 3.4.4.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES:

The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient considering other indications and alarms available to the operator in the control room to monitor RCS loop performance.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 24 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-26Revision 83 SR 3.4.5.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient considering other indications and alarms available to the operator in the control room to monitor RCS loop performance.

Revised BASES:

LA 156SR 3.4.5.212 hours0.00245 days <br />0.0589 hours <br />3.505291e-4 weeks <br />8.0666e-5 months <br /> BASES: The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is considered adequate in view of other indications available in the control room to alert the operator to a loss of SG level.

Revised BASES:

LA 156SR 3.4.5.37 days BASES:

Not stated.

Revised BASES:

LA 156SR 3.4.6.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES:

The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient considering other indications and alarms

available to the operator in the control room to monitor RCS and RHR loop performance.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 25 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-27Revision 83 SR 3.4.6.212 hours0.00245 days <br />0.0589 hours <br />3.505291e-4 weeks <br />8.0666e-5 months <br /> BASES: The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is considered adequate in view of other indications available in the control room to alert the operator to the loss of SG level. Revised BASES:

LA 156SR 3.4.6.37 days BASES: The Frequency of 7 days is considered reasonable in view of other administrative controls available and has been shown to be acceptable by operating experience.

Revised BASES:

LA 156SR 3.4.7.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES:

The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient considering other indications and alarms

available to the operator in the control room to monitor RHR loop performance.

Revised BASES:

LA 156SR 3.4.7.212 hours0.00245 days <br />0.0589 hours <br />3.505291e-4 weeks <br />8.0666e-5 months <br /> BASES:

The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is considered adequate in view of other indications available in the control room to alert the operator to the loss of SG level.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 26 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-28Revision 83 SR 3.4.7.37 days BASES: The Frequency of 7 days is considered reasonable in view of other administrative controls available and has been shown to be acceptable by operating experience.

Revised BASES:

LA 156SR 3.4.8.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient considering other indications and alarms

available to the operator in the control room to monitor RHR loop performance.

Revised BASES:

LA 156SR 3.4.8.27 days BASES:

The Frequency of 7 days is considered reasonable in view of other administrative controls available and has been shown to be acceptable by operating experience.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 27 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-29Revision 83 SR 3.4.9.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> interval has been shown by operating practice to be sufficient to regularly assess level for any deviation and verify that operation is consistent with the safety analyses assumptions of ensuring that a steam bubble exists in the pressurizer. Alarms are also available for early detection

of abnormal level indications.

Revised BASES:

LA 156SR 3.4.9.218 months BASES: The Frequency of 18 months is considered adequate to detect heater degradation and has been shown by operating experience to be acceptable. The heater design and

operation is consistent with the basis for an 18 month surveillance described in Section 6.6 of Ref. 3.

Revised BASES:

LA 156SR 3.4.11.192 days BASES: The basis for the Frequency of 92 days is the ASME Code (Ref.3).

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 28 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-30Revision 83 SR 3.4.11.218 months BASES: The Frequency of 18 months is based on a typical refueling cycle and industry accepted practice.

Revised BASES:

LA 156SR 3.4.12.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient, considering other indications and alarms available to the operator in the control room, to verify the required status of the equipment.

Revised BASES:

LA 156SR 3.4.12.212 hours0.00245 days <br />0.0589 hours <br />3.505291e-4 weeks <br />8.0666e-5 months <br /> BASES:

The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient, considering other indications and alarms available to the operator in the control room, to verify the required status of the equipment.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 29 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-31Revision 83 SR 3.4.12.312 hours0.00361 days <br />0.0867 hours <br />5.15873e-4 weeks <br />1.18716e-4 months <br /> BASES: The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient, considering other indications and alarms available to the operator in the control room, to verify the required status of the equipment.

Revised BASES:

LA 156SR 3.4.12.472 hours0.00546 days <br />0.131 hours <br />7.804233e-4 weeks <br />1.79596e-4 months <br /> BASES: The Frequency is considered adequate in view of other administrative controls such as valve status indications available to the operator in the control room that verify the

RHR suction valve remains open.

Revised BASES:

LA 156SR 3.4.12.512 hours0.00593 days <br />0.142 hours <br />8.465608e-4 weeks <br />1.94816e-4 months <br /> for unlocked open vent valve(s)

AND 31 days for locked open vent valve(s)

BASES:

Not stated.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 30 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-32Revision 83 SR 3.4.12.672 hours0.00778 days <br />0.187 hours <br />0.00111 weeks <br />2.55696e-4 months <br /> BASES: The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Frequency is considered adequate in view of other administrative controls available to the operator in the control room, such as valve position indication, that verify that the PORV block valve remains open.

Revised BASES:

LA 156SR 3.4.12.831 days BASES: Not stated.

Revised BASES:

LA 156SR 3.4.12.918 months BASES: Not stated.

Revised BASES:

LA 156SR 3.4.13.172 hours0.00199 days <br />0.0478 hours <br />2.843915e-4 weeks <br />6.5446e-5 months <br /> BASES: The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 31 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-33Revision 83 SR 3.4.13.272 hours0.00315 days <br />0.0756 hours <br />4.497354e-4 weeks <br />1.03496e-4 months <br /> BASES: The Surveillance Frequency of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

Revised BASES:

LA 156SR 3.4.14.1In accordance with the Inservice Testing Program, and] 18 months

[AND Prior to entering MODE 2 whenever the unit has been in MODE 5 for 7 days or more, and if leakage testing has not been performed in

the previous 9 months except for valves 8701A, 8701B, 8702A and 8702B AND Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following check valve actuation due to flow through the valve]

BASES:

The 18 month Frequency is consistent with 10 CFR 50.55a(g) (Ref. 8) as contained in the Inservice Testing Program, is within frequency allowed by the American Society of Mechanical Engineers (ASME) Code (Ref. 7), and is based on the need to perform such surveillances under the conditions that apply during an outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Revised BASES LA 156Table B 15.5.21-1 (Sheet 32 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-34Revision 83 SR 3.4.14.218 months BASES: The 18 month Frequency is based on the need to perform the Surveillance under conditions that apply during a plant outage. The 18 month Frequency is also acceptable based on consideration of the design reliability (and confirming operating experience) of the equipment.

Revised BASES:

LA 156SR 3.4.15.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES:

The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is based on instrument reliability and is reasonable for

detecting off normal conditions.

Revised BASES:

LA 156SR 3.4.15.292 days BASES: The Frequency of 92 days considers instrument reliability, and operating experience has shown that it is proper for

detecting degradation.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 33 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-35Revision 83 SR 3.4.15.318 months BASES: The Frequency of 18 months is a typical refueling cycle and considers channel reliability. Again, operating experience has proven that this Frequency is acceptable.

Revised BASES:

LA 156SR 3.4.15.418 months BASES: The Frequency of 18 months is a typical refueling cycle and considers channel reliability. Again, operating experience has proven that this Frequency is acceptable.

Revised BASES:

LA 156SR 3.4.15.518 months BASES:

The Frequency of 18 months is a typical refueling cycle and considers channel reliability. Again, operating experience has proven that this Frequency is acceptable.

Revised BASES:

LA 156SR 3.4.16.17 days BASES:

The 7 day Frequency considers the unlikelihood of a gross fuel failure during the

time. Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 34 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-36Revision 83 SR 3.4.16.214 days

[AND Between 2 and 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after a THERMAL POWER change of 15% RTP within a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> period]

BASES: The 14 day Frequency is adequate to trend changes in the iodine activity level, considering noble gas activity is monitored every 7 days.

Revised BASES:

LA 156SR 3.5.1.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES:

This Frequency is considered reasonable in view of other administrative controls that ensure a mispositioned isolation valve is unlikely.

Revised BASES:

LA 156SR 3.5.1.212 hours0.00245 days <br />0.0589 hours <br />3.505291e-4 weeks <br />8.0666e-5 months <br /> BASES: This Frequency is sufficient to ensure adequate injection during a LOCA. Because

of the static design of the accumulator, a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency usually allows the operator to identify changes before limits are reached. Operating experience has shown this Frequency to be appropriate for early detection and correction of off normal trends.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 35 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-37Revision 83 SR 3.5.1.312 hours0.00361 days <br />0.0867 hours <br />5.15873e-4 weeks <br />1.18716e-4 months <br /> BASES: This Frequency is sufficient to ensure adequate injection during a LOCA. Because of the static design of the accumulator, a 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency usually allows the operator to identify changes before limits are reached. Operating experience has shown this Frequency to be appropriate for early detection and correction of off normal trends.

Revised BASES:

LA 156SR 3.5.1.431 days

[AND ---------------------------NOTE-----------------------

Only required to be performed for affected

accumulators

---

Once within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after each solution volume increase of 101 gallons that is not the result of addition from the refueling water

storage tank]

BASES:

The 31 day Frequency is adequate to identify changes that could occur from mechanisms such as stratification or

inleakage.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 36 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-38Revision 83 SR 3.5.1.531 days BASES: Since power is removed under administrative control, the 31 day Frequency will provide adequate assurance that power is removed.

Revised BASES:

LA 156SR 3.5.2.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: A 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is considered reasonable in view of other administrative controls that will ensure a mispositioned valve is unlikely.

Revised BASES:

LA 156SR 3.5.2.231 days BASES: The 31 day Frequency is appropriate because the valves are operated under administrative control, and an improper valve position would only affect a single train. This Frequency has been shown to be acceptable through operating experience.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 37 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-39Revision 83 SR 3.5.2.518 months on a STAGGERED TEST BASIS BASES: The 18 month Frequency is based on the need to perform these Surveillances under the conditions that apply during a plant outage and the potential for unplanned plant transients if the Surveillances were performed with the reactor at power. The 18 month Frequency is also acceptable based on consideration of the design reliability (and confirming operating experience) of the equipment.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21Table B 15.5.21-1 (Sheet 38 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-40Revision 83 SR 3.5.2.618 months on a STAGGERED TEST BASIS BASES: The 18 month Frequency is based on the need to perform these Surveillances under the conditions that apply during a plant outage and the potential for unplanned plant transients if the Surveillances were performed with the reactor at power. The 18 month Frequency is also acceptable based on consideration of the design reliability (and confirming operating experience) of the equipment.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21SR 3.5.2.718 months BASES: The 18 month Frequency is based on the same reasons as those stated in SR 3.5.2.5 and SR 3.5.2.6.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 39 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-41Revision 83 SR 3.5.2.818 months BASES: The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage, on the need to have access to the location, and because of the potential for an unplanned transient if the Surveillance were performed with the reactor at power. This Frequency has been found to be sufficient to detect abnormal degradation and is confirmed by operating experience.

Revised BASES:

LA 156SR 3.5.4.124 hours0.00144 days <br />0.0344 hours <br />2.050265e-4 weeks <br />4.7182e-5 months <br /> BASES:

This Frequency is sufficient to identify a temperature change that would approach

either limit and has been shown to be acceptable through operating experience.

Revised BASES:

LA 156SR 3.5.4.27 days BASES:

Since the RWST volume is normally stable and the contained volume required is protected by an alarm, a 7 day Frequency is appropriate and has been shown to be acceptable through operating experience.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 40 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-42Revision 83 SR 3.5.4.37 days BASES: Since the RWST volume is normally stable, a 7 day sampling Frequency to verify boron concentration is appropriate and has been shown to be acceptable through operating experience.

Revised BASES:

LA 156SR 3.5.5.131 days BASES: The Frequency of 31 days is based on engineering judgment and is consistent with other ECCS valve Surveillance Frequencies. The Frequency has proven to be acceptable

through operating experience.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 41 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-43Revision 83 SR 3.6.2.224 months BASES: Due to the reliable nature of this interlock, and given that the interlock mechanism is not normally challenged when the containment air lock door is used for entry and exit (procedures require strict adherence to single door opening), this test is only required to be performed every 24 months. The 24 month Frequency is based on the need to perform this surveillance under the conditions that apply during a plant outage and the potential for loss of containment OPERABILITY if the Surveillance were performed with the reactor at power. The 24 month Frequency for the interlock is justified based on generic operating experience. The Frequency is based on engineering judgement and is considered adequate given that the interlock is not challenged

during use of the airlock.

Revised BASES:

LA 156SR 3.6.3.131 days BASES: The Frequency is a result of an NRC initiative, Multi-Plant Action No. B-24 (Ref.5), related to containment purge valve use

during plant operations.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 42 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-44Revision 83 SR 3.6.3.331 days BASES: Since verification of valve position for containment isolation valves outside containment is relatively easy, the 31 day Frequency is based on engineering judgment and was chosen to provide added assurance of the correct positions.

Revised BASES:

LA 156SR 3.6.3.718 months BASES: Not stated.

Revised BASES:

LA 156SR 3.6.3.818 months on a STAGGERED TEST BASIS BASES: 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.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21Table B 15.5.21-1 (Sheet 43 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-45Revision 83 SR 3.6.4.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency of this SR was developed based on operating experience related to trending of containment pressure variations during the applicable MODES.

Furthermore, the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal containment pressure condition.

Revised BASES:

LA 156SR 3.6.5.124 hours0.00144 days <br />0.0344 hours <br />2.050265e-4 weeks <br />4.7182e-5 months <br /> BASES: 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 considered acceptable based on observed slow rates of temperature increase within

containment as a result of environmental heat sources (due to the large volume of containment). Furthermore, the 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal containment temperature condition.

Revised BASES:

LA 156SR 3.6.6.131 days BASES:

Not stated.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 44 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-46Revision 83 SR 3.6.6.518 months BASES: Operating experience has shown that these components usually pass the Surveillances when performed at the 18 month Frequency.

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

Revised BASES:

LA 156SR 3.6.6.618 months BASES: Operating experience has shown that these components usually pass the Surveillances when performed at the 18 month Frequency.

Therefore, the Frequency was concluded to

be acceptable from a reliability standpoint.

Revised BASES:

LA 156SR 3.7.2.218 months BASES: The 18 month Frequency for testing is based on the refueling cycle. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, this Frequency is acceptable from a reliability

standpoint.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 45 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-47Revision 83 SR 3.7.3.218 months BASES: The 18 month Frequency for testing is based on the refueling cycle. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, this Frequency is acceptable from a reliability standpoint.

Revised BASES:

LA 156SR 3.7.5.131 days BASES:

The 31 day Frequency is based on engineering judgment, is consistent with the

procedural controls governing valve operation, and ensures correct valve positions.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 46 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-48Revision 83 SR 3.7.5.318 months on a STAGGERED TEST BASIS BASES: The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. The 18 month Frequency is acceptable based on operating experience and the design reliability of the equipment.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21Table B 15.5.21-1 (Sheet 47 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-49Revision 83 SR 3.7.5.418 months on a STAGGERED TEST BASIS BASES: The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21SR 3.7.6.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is based on operating experience and the need for operator awareness of unit evolutions that may affect the CST inventory between checks. Also, the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Frequency is considered adequate in view of other indications in the control room, including alarms, to alert the operator to abnormal deviations in the CST level.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 48 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-50Revision 83 SR 3.7.7.131 days BASES: The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

Revised BASES:

LA 156SR 3.7.7.218 months BASES: The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient

if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass

the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability

standpoint.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 49 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-51Revision 83 SR 3.7.7.318 months on a STAGGERED TEST BASIS BASES: The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass

the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability

standpoint.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a

STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in

accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21SR 3.7.8.131 days BASES:

The 31 day Frequency is based on engineering judgment, is consistent with the

procedural controls governing valve operation, and ensures correct valve positions.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 50 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-52Revision 83 SR 3.7.8.292 days BASES: The 92 day frequency is based on the frequency in ASME XI (Ref. 7) for testing of Category A and B valves and is consistent with Generic Letter 91-13 (Ref. 4).

Revised BASES:

LA 156SR 3.7.8.318 months on a STAGGERED TEST BASIS BASES: The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 18

month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a

STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in

accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21Table B 15.5.21-1 (Sheet 51 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-53Revision 83 SR 3.7.9.124 hours0.00144 days <br />0.0344 hours <br />2.050265e-4 weeks <br />4.7182e-5 months <br /> BASES: The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.

Revised BASES:

LA 156SR 3.7.9.224 hours0.00259 days <br />0.0622 hours <br />3.703704e-4 weeks <br />8.5232e-5 months <br /> BASES: The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.

Revised BASES:

LA 156SR 3.7.10.131 days BASES:

The 31 day Frequency is based on the reliability of the equipment and the two train

redundancy.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 52 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-54Revision 83 SR 3.7.10.318 months on a STAGGERED TEST BASIS BASES: The Frequency of 18 months is based on industry operating experience and is consistent with the typical refueling cycle. Revised BASES: The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS".

As documented in EV-CR-2011-002186-21, this change was evaluated and approved in

accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21SR 3.7.11.118 months BASES: The 18 month Frequency is appropriate since significant degradation of the CRACS is slow and is not expected over this time

period. Revised BASES:

LA 156SR 3.7.12.131 days BASES: The 31 day Frequency is based on the known reliability of equipment and the two train redundancy available.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 53 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-55Revision 83 SR 3.7.12.318 months on a STAGGERED TEST BASIS BASES: The 18 month Frequency is consistent with that specified in Reference 4.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in

accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21SR 3.7.12.418 months on a STAGGERED TEST BASIS BASES:

The Frequency of 18 months is consistent with the guidance provided in NUREG-0800, Section 6.5.1 (Ref. 6). This test is conducted with the tests for filter penetration; thus, an 18 month Frequency on a STAGGERED TEST BASIS is consistent with that specified in Reference 4.

Revised BASES:

LA 156SR 3.7.12.618 months BASES: A frequency of 18 months is consistent with SR 3.7.12.3.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 54 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-56Revision 83 SR 3.7.15.17 days BASES: The 7 day Frequency is appropriate because the volume in the pool is normally stable. Water level changes are controlled by plant procedures and are acceptable based on operating experience.

Revised BASES:

LA 156SR 3.7.16.17 days BASES: The 7 day Frequency is appropriate because no major replenishment of pool water is expected to take place over such a short period of time.

Revised BASES:

LA 156SR 3.7.18.131 days BASES: The 31 day Frequency is based on the detection of increasing trends of the level of DOSE EQUIVALENT I-131, and allows for appropriate action to be taken to maintain

levels below the LCO limit.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 55 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-57Revision 83 SR 3.7.19.131 days BASES: The 31 day Frequency is based on engineering judgement, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

Revised BASES:

LA 156SR 3.7.19.218 months on a STAGGERED TEST BASIS BASES: Operating experience has shown that these components usually pass the surveillance when performed at the 18 month Frequency.

Therefore, the 18month frequency is acceptable from a reliability standpoint.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21SR 3.7.20.131 days BASES: Not stated.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 56 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-58Revision 83 SR 3.7.20.231 days BASES: Not stated.

Revised BASES:

LA 156SR 3.7.20.318 months on a STAGGERED TEST BASIS BASES: The 18 month frequency is consistent with the typical refueling cycle. Operating

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

Therefore, the Frequency is acceptable from a reliability standpoint.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21SR 3.8.1.17 days BASES: 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. Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 57 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-59Revision 83 SR 3.8.1.231 days BASES: The 31 day Frequency for SR 3.8.1.2, is consistent with Regulatory Guide 1.9 (Ref. 3) and Generic Letter 94-01 (Ref. 14)-These Frequencies provide adequate assurance of DG OPERABILITY, while minimizing degradation resulting from testing.

Revised BASES:

LA 156SR 3.8.1.331 days BASES:

The 31 day Frequency for this Surveillance is consistent with Regulatory Guide 1.9 (Ref.

3) and Generic Letter 94-01 (Ref. 14).

Revised BASES:

LA 156SR 3.8.1.431 days BASES: The 31 day Frequency is adequate to assure that a sufficient supply of fuel oil is available, since low level alarms are provided and facility operators would be aware of any large uses of fuel oil during this period.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 58 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-60Revision 83 SR 3.8.1.531 days BASES: The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref.10). This SR is for preventative maintenance.

Revised BASES:

LA 156SR 3.8.1.692 days BASES: The frequency of 92 days is adequate to verify proper automatic operation of the fuel

transfer pumps to maintain the required volume of fuel oil in the day tanks. This frequency corresponds to the testing

requirements for pumps as contained in the ASME Code (Ref. 11).

Revised BASES:

LA 156SR 3.8.1.7184 days BASES:

The 184 day Frequency for SR 3.8.1.7 is a reduction in cold testing consistent with Generic Letter 84-15 (Ref. 7). These Frequencies provide adequate assurance of DG OPERABILITY, while minimizing degradation resulting from testing.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 59 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-61Revision 83 SR 3.8.1.818 months BASES: The 18 month Frequency of the Surveillance is based on engineering judgment, taking into consideration the unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability

standpoint.

Revised BASES:

LA 156SR 3.8.1.918 months on a STAGGERED TEST BASIS BASES: The 18 month Frequency is consistent with the recommendation of Regulatory Guide 1.108 (Ref. 9).

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21Table B 15.5.21-1 (Sheet 60 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-62Revision 83 SR 3.8.1.1018 months on a STAGGERED TEST BASIS BASES: The 18 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref.3) and is intended to be consistent with expected fuel cycle lengths.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a

STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21SR 3.8.1.1118 months on a STAGGERED TEST BASIS BASES: The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.9 (Ref.3), takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a

STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in

accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21Table B 15.5.21-1 (Sheet 61 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-63Revision 83 SR 3.8.1.1218 months BASES: The Frequency of 18 months takes into consideration unit conditions required to perform the Surveillance and is intended to be consistent with the expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency.

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

Revised BASES:

LA 156SR 3.8.1.1318 months on a STAGGERED TEST BASIS BASES: The 18 month Frequency is based on engineering judgment, taking into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency.

Therefore, the Frequency was concluded to

be acceptable from a reliability standpoint.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21Table B 15.5.21-1 (Sheet 62 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-64Revision 83 SR 3.8.1.1418 months BASES: The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref.3), takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

Revised BASES:

LA 156SR 3.8.1.1518 months on a STAGGERED TEST BASIS BASES: The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref.3).

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a

STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in

accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21Table B 15.5.21-1 (Sheet 63 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-65Revision 83 SR 3.8.1.1618 months on a STAGGERED TEST BASIS BASES: The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(6), and takes into consideration unit conditions required to perform the Surveillance.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a

STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in

accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21SR 3.8.1.1718 months on a STAGGERED TEST BASIS BASES:

The 18 month Frequency is consistent with the recommendations of Regulatory Guide

1.9 (Ref.3), takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21Table B 15.5.21-1 (Sheet 64 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-66Revision 83 SR 3.8.1.1818 months BASES: The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(2), takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

Revised BASES:

LA 156SR 3.8.1.1918 months on a STAGGERED TEST BASIS BASES:

The Frequency of 18 months takes into consideration unit conditions required to

perform the Surveillance and is intended to be consistent with an expected fuel cycle length of 18 months.

Revised BASES:

The frequency for the integrated test sequence/loss if offsite power testing is revised from "18 months" to "18 months on a

STAGGERED TEST BASIS". As documented in EV-CR-2011-002186-21, this change was evaluated and approved in

accordance with TS 5.5.21.

EV-CR-2011-002186-21 LA 156 EV-CR-2011-002186-21SR 3.8.1.2010 years BASES:

The 10 year Frequency is consistent with the recommendations of Regulatory Guide

1.108 (Ref. 9).

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 65 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-67Revision 83 SR 3.8.1.2118 months BASES: Not stated.

Revised BASES:

LA 156SR 3.8.1.2231 days on a STAGGERED TEST BASIS BASES: Not stated.

Revised BASES:

LA 156SR 3.8.3.131 days BASES:

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

period. Revised BASES:

LA 156SR 3.8.3.231 days BASES: A 31 day Frequency is adequate to ensure that a sufficient lube oil supply is onsite, since DG starts and run time are closely monitored by the unit staff.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 66 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-68Revision 83 SR 3.8.3.431 days BASES: The 31 day Frequency takes into account the capacity, capability, redundancy, and diversity of the AC sources and other indications available in the control room, including alarms, to alert the operator to below normal air start pressure.

Revised BASES:

LA 156SR 3.8.3.531 days BASES: The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 2).

Revised BASES:

LA 156SR 3.8.4.17 days BASES: The 7 day Frequency is consistent with manufacturer recommendations and IEEE-450 (Ref. 8).

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 67 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-69Revision 83 SR 3.8.4.218 months BASES: The Surveillance Frequency is acceptable, given the unit conditions required to perform the test and the other administrative controls existing to ensure adequate charger performance during these 18 month intervals. In addition, this Frequency is intended to be consistent with expected fuel cycle lengths.

Revised BASES:

LA 156SR 3.8.4.318 months BASES: The Surveillance Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.32 (Ref. 9) and Regulatory Guide1.129 (Ref. 10), which state that the battery service test should be performed during refueling operations or at some other outage, with intervals between tests, not to exceed 18 months.

Revised BASES:

LA 156SR 3.8.6.17 days BASES: The 7 day Frequency is consistent with IEEE-450 (Ref. 4).

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 68 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-70Revision 83 SR 3.8.6.231 days BASES: The Frequency for cell voltage verification every 31 days for pilot cell and 92 days for each connected cell is consistent with IEEE-450 (Ref. 4).

Revised BASES:

LA 156SR 3.8.6.331 days BASES: The Frequency is consistent with IEEE-450 (Ref. 4).

Revised BASES:

LA 156SR 3.8.6.431 days BASES: The Frequency is consistent with IEEE-450 (Ref. 4).

Revised BASES:

LA 156SR 3.8.6.592 days BASES: The Frequency for cell voltage verification every 31 days for pilot cell and 92 days for each connected cell is consistent with IEEE-

450 (Ref. 4).

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 69 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-71Revision 83 SR 3.8.6.660 months

[AND 18 months when battery shows degradation or has reached 85% of expected life with capacity < 100% of manufacturer's rating AND 24 months when battery has reached 85% of the expected life with capacity 100% of manufacturer's rating]

BASES: This frequency is consistent with the recommendations in IEEE-450 (Ref. 4).

Revised BASES:

LA 156SR 3.8.7.17 days BASES: The 7 day Frequency takes into account the redundant capability of the inverters and other indications available in the control room that alert the operator to inverter

malfunctions.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 70 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-72Revision 83 SR 3.8.8.17 days BASES: The 7 day Frequency takes into account the redundant capability of the inverters and other indications available in the control room that alert the operator to inverter malfunctions.

Revised BASES:

LA 156SR 3.8.9.17 days BASES: The 7 day Frequency takes into account the redundant capability of the AC, DC, and AC vital bus electrical power distribution subsystems, and other indications available in the control room that alert the operator to subsystem malfunctions.

Revised BASES:

LA 156SR 3.8.10.17 days BASES:

The 7day Frequency takes into account the capability of the electrical power distribution subsystems, and other indications available in the control room that alert the operator to subsystem malfunctions.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 71 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-73Revision 83 SR 3.9.1.172 hours0.00199 days <br />0.0478 hours <br />2.843915e-4 weeks <br />6.5446e-5 months <br /> BASES: A minimum Frequency of once every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> is a reasonable amount of time to verify the boron concentration of representative samples. The Frequency is based on operating experience, which has shown 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to be adequate.

Revised BASES:

LA 156SR 3.9.2.131 days BASES: The 31 day Frequency is based on engineering judgment and is considered reasonable in view of other administrative

controls that will ensure that the valve opening is an unlikely possibility.

Revised BASES:

LA 156SR 3.9.3.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES:

The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is consistent with the CHANNEL CHECK Frequency specified

similarly for the same instruments in LCO

3.3.1. Revised

BASES:

LA 156Table B 15.5.21-1 (Sheet 72 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-74Revision 83 SR 3.9.3.218 months BASES: The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage. Operating experience has shown these components usually pass the Surveillance when performed at the 18 month Frequency.

Revised BASES:

LA 156SR 3.9.4.17 days BASES: The Surveillance is performed every 7 days during CORE ALTERATIONS or movement of irradiated fuel assemblies within containment. The Surveillance interval is selected to be commensurate with the normal duration of time to complete fuel

handling operations. A surveillance before the start of refueling operations will provide two or three surveillance verifications during the applicable period for this LCO. As such, this Surveillance ensures that a postulated fuel handling accident that releases fission

product radioactivity within the containment will not result in a release of fission product radioactivity to the environment.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 73 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-75Revision 83 SR 3.9.4.27 days BASES: The Surveillance interval is selected to be commensurate with the normal duration of time to complete the fuel handling operations-The 7 day Frequency is adequate considering that the hardware, tools, and equipment are dedicated to the equipment hatch and not used for any other

function.

Revised BASES:

LA 156SR 3.9.4.318 months BASES: The 18 month Frequency maintains consistency with other similar instrumentation and valve testing requirements.

Revised BASES:

LA 156SR 3.9.5.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient, considering the flow, temperature, pump control, and alarm indications available to the operator in the control room for monitoring the RHR System.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 74 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE Surveillance Frequency Control ProgramTRB 15.5.21CPSES - UNITS 1 AND 2 - TRMB 15.0-76Revision 83 SR 3.9.6.112 hours0.0013 days <br />0.0311 hours <br />1.851852e-4 weeks <br />4.2616e-5 months <br /> BASES: The Frequency of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is sufficient, considering the flow, temperature, pump control, and alarm indications available to the operator for monitoring the RHR System in the control room.

Revised BASES:

LA 156SR 3.9.6.27 days BASES: The Frequency of 7 days is considered reasonable in view of other administrative controls available and has been shown to be acceptable by operating experience.

Revised BASES:

LA 156SR 3.9.7.124 hours0.00144 days <br />0.0344 hours <br />2.050265e-4 weeks <br />4.7182e-5 months <br /> BASES: The Frequency of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is based on engineering judgment and is considered adequate in view of the large volume of water and the normal procedural controls of valve positions, which make significant unplanned level changes unlikely.

Revised BASES:

LA 156Table B 15.5.21-1 (Sheet 75 of 75)Technical Specification Surveillance Requirement FrequenciesSURVEILLANCEFREQUENCYREFERENCE CPSES - UNITS 1 AND 2 - TRMEL-1Revision 84 CPSES/TRM COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 & 2 TECHNICAL REQUIREMENTS MANUAL (TRM)EFFECTIVE LISTING FOR SECTIONS Revision Record:OriginalSubmitted July 21, 1989Revision 1September 15, 1989Revision 2January 15, 1990 Revision 3July 20, 1990Revision 4April 24, 1991Revision 5September 6, 1991 Revision 6November 22, 1991Revision 7March 18, 1992Revision 8June 30, 1992 Revision 9December 18, 1992Revision 10January 22, 1993Revision 11February 3, 1993 Revision 12July 15, 1993 Revision 13September 14, 1993Revision 14November 30, 1993Revision 15April 15, 1994 Revision 16May 11, 1994Revision 17February 24, 1995Revision 18April 14, 1995 Revision 19May 15, 1995Revision 20June 30, 1995Revision 21January 24, 1996 Revision 22February 24, 1997Revision 23March 13, 1997Revision 24June 26, 1997 Revision 25July 31, 1997Revision 26February 24, 1998Revision 27April 14, 1999 Revision 28April 16, 1999Revision 29July 27, 1999Revision 30July 27, 1999 Revision 31August 5, 1999Revision 32September 24, 1999Revision 33October 7, 1999 Revision 34June 29, 2000Revision 35September 30, 2000Revision 36May 30, 2001 Revision 37August 14, 2001Revision 38October 16, 2001Revision 39March 27, 2002 Revision 40August 15, 2002Revision 41September 24, 2002Revision 42October 11, 2002 CPSES - UNITS 1 AND 2 - TRMEL-2Revision 84 CPSES/TRM COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 & 2 TECHNICAL REQUIREMENTS MANUAL (TRM)EFFECTIVE LISTING FOR SECTIONS Revision Record:Revision 43January 23, 2003Revision 44February 4, 2003Revision 45October 7, 2003 Revision 46February 17, 2004Revision 47March 23, 2004Revision 48April 23, 2004 Revision 49September 28, 2004Revision 50July 22, 2005Revision 51August 4, 2005 Revision 52September 27, 2005Revision 53October 27, 2005Revision 54December 29, 2005 Revision 55February 28, 2006 Revision 56June 1, 2006Revision 57July 27, 2006Revision 58September 20, 2006 Revision 59October 20, 2006Revision 60January 18, 2007Revision 61January 31, 2007 Revision 62February 26, 2007Revision 63April 11, 2007Revision 64June 21, 2007 Revision 65December 19, 2007Revision 66February 28, 2008Revision 67March 13, 2008 Revision 68April 4, 2008Revision 69September 11, 2008Revision 70November 13, 2008 Revision 71May 20, 2009Revision 72September 29, 2009Revision 73March 2, 2010 Revision 74October 7, 2010Revision 75November 30, 2010Revision 76February 7, 2011 Revision 77April 18, 2011Revision 78June 9, 2011Revision 79December 22, 2011 Revision 80June 18, 2012Revision 81July 24, 2012Revision 82September 11, 2012 Revision 83October 2, 2012Revision 84October 30, 2012 CPSES - UNITS 1 AND 2 - TRMEL-3Revision 84 CPSES/TRM COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 & 2 TECHNICAL REQUIREMENTS MANUAL (TRM)EFFECTIVE LISTING FOR SECTIONSTRM TOCRevision 82Section 11.0Revision 56Section 13.0Revision 56Section 13.1Revision 82Section 13.2Revision 79Section 13.3Revision 74 Section 13.4Revision 56Section 13.5Revision 56Section 13.6Revision 70 Section 13.7Revision 83Section 13.8Revision 83Section 13.9Revision 77 Section 13.10Revision 65Section 15.0Revision 83 CPSES - UNITS 1 AND 2 - TRMEL-4Revision 84 CPSES/TRM COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 & 2 TECHNICAL REQUIREMENTS MANUAL (TRM)EFFECTIVE LISTING FOR SECTIONSTRM Bases TOCRevision 84Section B 13.0Revision 56Section B 13.1Revision 82Section B 13.2Revision 79 Section B 13.3Revision 74Section B 13.4Revision 56Section B 13.5Revision 84 Section B 13.6Revision 70Section B 13.7Revision 83Section B 13.8Revision 83 Section B 13.9Revision 77Section B 13.10Revision 56Section B 15.0Revision 83EL-1Revision 84EL-2Revision 84 EL-3Revision 84EL-4Revision 84 CPSES - UNITS 1 AND 2 - TRMDOC-1Revision 84Technical Requirements Manual - Description of Changes REVISION 56 LDCR-TR-2006-7 (EVAL-2005-005086-12) (TJE):

Administrative change for software conversion only.

The type of changes include changes such as (1) correction of spelling errors, (2) correction of inadvertent word processing errors from previous changes, and (3) style guide changes (e.g., changing from a numbered bullet list to an alphabetized bullet list and vice versa, change numbering of footnote naming scheme). The entire TRM and TRM Bases will be reissued as Revision 56. For the text and tables there will be no change bars in the page margins for the editorial changes. The list of effective pages is being replaced with a list of effective sections, tables, and figures. Sections Revised:AllTables Revised:AllFigures Revised:All REVISION 57 LDCR-TR-2006-9 (EVAL-2004-000501-1) (TJE):Correct tag number in Table 13.8.32-1b section 3.1 MCC 2EB1-2 compartment number 12B from "Personnel Air Lock Hydraulic Unit #2" to "Personnel Air Lock Hydraulic Unit #2 (CP2-BSAPPA-02M)"1.) In Table 13.8.32-1b, the last sentence in section 4.3 description, replace the existing words, "These breakers are Square D type FC, KH, and LH." with the words, "These breakers are Square D type FH, KH, FA, and LH." 2.) Correct typos in tag numbers in Table 13.8.32-1b section 4.3.a, a.) Devise Location Ckt 2, change Breaker Type from FC to FH b.) Device Location Ckt 1 / Bkr-1, under System Powered, by removing the "-" between CP and 2 in two places.3.) Corrects tag number in Table 13.8.32-1b section 4.3.b a.) Devise Location Ckt 4, "Personnel Airlock Hydraulic Units CP-2-MEMEHU-01 and 02" to "Personnel Airlock Hydraulic Unit #2 (CP2-BSAPPA-02M)"

CPSES - UNITS 1 AND 2 - TRMDOC-2Revision 84Technical Requirements Manual - Description of ChangesREVISION 57 (continued) LDCR-TR-2006-9 (EVAL-2004-000501-1) (TJE) (continued): b.) Devise Location Ckt 6, change Breaker Type from F4 to FHCorrect typo to remove a dash in Table 13.7.39-1, Shield tag number from, "Removable Slab (Hatch Cover) SW Pump, CP-1-SWAPSW-02" to "Removable Slab (Hatch Cover)

SW Pump, CP1-SWAPSW-02" REVISION 58 LDCR-TR-2006-3 (EVAL-2005-004275-02) (TJE):1.) Currently, TRS 13.8.31.2 reads, "Subject the diesel to an inspection in accordance with procedures prepared in conjunction with its manufacture's recommendations for this class of standby service." The LDCR proposes to revise the TRS 13.8.31.2 to read, "Subject the diesel to inspections in accordance with procedures prepared in conjunction with the diesel owners group's preventive maintenance program."NOTE:The revision of this SR is proposed due to changes in the PM program recommended by the Cooper Owners Group which the CPSES EDGs are included in. The PM program is not being deleted nor are the vendor's recommendations being ignored. The current PM program is being enhanced to include vendor input, predictive maintenance input, performance based input and the Cooper Owners Group input. The program changes will provide the site with the opportunity to move from a prescriptive time based program to a risk informed performance based program.At the end of this section, add the words, "The diesel's preventative maintenance program is commensurate for nuclear standby service, which takes into consideration the

following factors: manufacturer's recommendations, diesel owners group's recommendations, engine run time, equipment performance, calendar time, and plant preventative maintenance programs."NOTE:The revision of this SR is proposed due to changes in the PM program recommended by the Cooper Owners Group which the CPSES EDGs are included in. The PM program is not being deleted nor are the vendor's recommendations being ignored. The current PM program is being enhanced to include vendor input, predictive maintenance input, performance based input and the Cooper Owners Group input. The program changes will provide the site with the opportunity to move from a prescriptive time based program to a risk informed performance based program.

CPSES - UNITS 1 AND 2 - TRMDOC-3Revision 84Technical Requirements Manual - Description of Changes REVISION 59 LDCR-TR-2004-5 (EVAL-2004-001881-04) (TJE):Circuit Breaker 1ED1-1/14/BKR will be deleted from Table 13.8.32-1a under number 6.b. Backup Breakers. LDCR-TR-2005-10 (EVAL-2004-000773-05) (RAS):Revise TR LCO 13.3.33 from "At least one Turbine Overspeed Protection System shall be OPERABLE" to "At least one Turbine Overspeed Protection Sub-system shall be OPERABLE" Revise Condition C from " Turbine overspeed protection inoperable for reasons other than Condition A or B" to Both Overspeed Protection Sub-systems inoperable"Revise TRS 13.3.33.1 to replace the Unit specific surveillance statements with the following statement applicable equally to both Units:"Test the Turbine Trip Block using the Automatic Turbine Tester (ATT)." Delete TRS 13.3.33.3 and its associated frequency.Revise TRS 13.3.33.6 as follows to make it applicable to both Units:"Test the Hardware Overspeed Sub-system 2 of 3 relay logic and output relays" Delete the existing TRM Bases description and replace in its entirety with the following:

BACKGROUNDThis specification is provided to ensure that the turbine overspeed protection instrumentation and the turbine Stop and Control Valves are operable and will protect the turbine from excessive overspeed. Protection from excessive overspeed is necessary to prevent the generation of potentially damaging missiles which could impact and damage safety-related components, equipment and structures. Turbine overspeed is limited by rapid closure of the turbine Stop or Control Valves whenever turbine power exceeds generator output, as would exist immediately following a load rejection.The Electrohydraulic Control (EHC) System is the primary means of limiting the extent of an overspeed event, with the turbine Overspeed Protection System as a backup. The EHC System is designed to limit transient overspeed to less than 110% of rated speed after a full load rejection by closing both the High Pressure (HP) and Low Pressure (LP) Control Valves. This function of the EHC System is performed by the normal speed/load control logic in conjunction with additional protection logic that ensures closure of all control valves under certain load rejection scenarios (Reference 1).

CPSES - UNITS 1 AND 2 - TRMDOC-4Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)To minimize the possibility of a component failure resulting in a loss of the control function, the EHC System utilizes triple redundant speed and load inputs, dual redundant digital controller processors, and dual redundant outputs (amplifiers, proportional valves, and follow-up piston banks) to the Control Valves.In the unlikely event that the EHC System fails to limit the overspeed condition, the Overspeed Protection System will act to limit the overspeed to less than 120% of rated speed.The Overspeed Protection System is made up of the following basic component groups:Independent and redundant speed sensors and associated signal processing instrumentation, including bistables, provide individual speed channel trip signals to the Turbine AG-95F Digital Protection System and the hardware overspeed trip system (both

described below) whenever turbine speed exceeds 1980 rpm.The Turbine AG-95F Digital Protection System consists of three independent and redundant trains of equipment, including input modules, dual redundant automation processors and associated software, output modules, and output relays. The AG-95F System is a fail-safe system in that all inputs and outputs are normally energized in the non-tripped state.Each train of the AG-95F System processes the individual speed channel trip signals using 2 of 3 trip logic. When the trip logic is satisfied, the associated output relays de-

energize, each one subsequently de-energizing its associated Turbine Trip Block solenoid valve. The Relay Protection System consists of relay logic and output relays that are diverse from, and completely bypass, the AG-95F Digital Protection System described above. The logic and output relays are normally energized in the non-tripped state.The relay logic processes the individual speed channel trip signals using 2 of 3 trip logic. When the trip logic is satisfied, all three output relays de-energize, each one

subsequently de-energizing its associated Turbine Trip Block solenoid valve.The Turbine Trip Block utilizes three independent and redundant solenoid valves to actuate associated hydraulic pistons that are configured in a manner that provides a hydraulic 2 of 3 trip logic. When any two of the three solenoid valves de-energize, actuation of the associated pistons rapidly de-pressurizes the turbine Trip Fluid System, causing all turbine Stop and Control Valves to close. De-energization of a single solenoid valve will not trip the turbine.The Overspeed Protection System consists of two redundant and diverse sub-systems, the Hardware Overspeed Sub-system and the Software Overspeed Sub-system, that are configured using the component groups described above. Either of these sub-systems

can independently trip the turbine.

CPSES - UNITS 1 AND 2 - TRMDOC-5Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)The Hardware Overspeed Sub-system utilizes a set of three dedicated speed channels, each of which provides a trip signal to the Relay Protection System. Upon receipt of trip signals from any two of these speed channels, the relay logic de-energizes all three output relays which subsequently de-energize all three Turbine Trip Block solenoid valves, causing the turbine to trip.As a backup, the three dedicated Hardware Overspeed Sub-system speed channels also provide trip signals to all three of the AG-95F System protection trains. Upon receipt of trip signals from any two of these speed channels, the output relay of each protection train is de-energized, subsequently de-energizing all three Turbine Trip Block solenoid valves, causing the turbine to trip. The Software Overspeed Sub-system utilizes a second set of three dedicated speed channels which provide input to all three of AG-95F System protection trains. Upon receipt of trip signals from any two of these speed channels, the output relay of each protection train is de-energized, subsequently de-energizing all three Turbine Trip Block solenoid valves, causing the turbine to trip. The Software Overspeed System speed channels also provide speed signals to the EHC System as described above.The design of the Overspeed Protection System includes several testing features that are used to ensure OPERABILITY of the system. These features include three Automatic Turbine Tester (ATT) tests that are manually initiated by the operator. They also include a test that is automatically executed by the system to ensure OPERABILITY of the speed channel instrumentation.The ATT HP and LP Valve Tests cycle all Stop and Control Valves to ensure reliability and continuity of service. The HP and LP Stop Valve closure times are also verified to be within required response times (500 and 1500 msec, respectively). These tests cycle one pair of Stop and Control Valves at a time, so they may be performed with the plant on-line below approximately 85% power.The ATT Turbine Trip Block Test de-energizes each Turbine Trip Block solenoid valve and verifies that the associated hydraulic piston moves to the trip position. The solenoid

valve/piston pairs are sequentially tested one at a time, until all three are tested. Each pair is reset prior to testing the subsequent pair. Since only one solenoid valve/piston pair is tested at a time, the Trip Fluid System is never de-pressurized, and the turbine

does not trip.Each of the six individual speed channels (three for the Hardware Overspeed Sub-system and three for the Software Overspeed Sub-system), is automatically tested once every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> when turbine speed is >40 rpm. These tests verify that the speed channels trip when speed is simulated above 1980 rpm. The tests are initiated by the AG-95F System in a manner that precludes two speed channels from being tested at the same time. If desired, the speed channel tests may also be initiated by the operator.Alarms are provided to alert the operator in the event a fault/failure is detected during the execution of any of the aforementioned tests.

CPSES - UNITS 1 AND 2 - TRMDOC-6Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)APPLICABLE SAFETY ANALYSISThe Overspeed Protection System is required to be OPERABLE to provide sufficient protection against generation of potentially damaging missiles which could impact and damage safety-related components, equipment and structures. The turbine missile analysis is presented in Reference 2. Using References 3 through 5 as a basis, this analysis concludes that the risk for loss of an essential system due to a turbine missile event is acceptably low.The robust design of the Overspeed Protection System, with its multiple speed channels, diverse hardware and software logic, and multiple Turbine Trip Block solenoid valves/

hydraulic pistons, meets the intent of SRP 10.2 Part III for redundancy and independence.

LCOThe Turbine Overspeed Protection Sub-systems are the Hardware Overspeed Sub-system and the Software Overspeed Sub-system, one of which shall be OPERABLE.The robust design of these sub-systems allows for the failure of individual components without rendering the sub-system(s) inoperable. Specifically, the minimum operability requirements for the Hardware Overspeed Sub-system include:two OPERABLE dedicated hardware speed channels, and OPERABLE hardware relay logic with two OPERABLE output relays and associated Turbine Trip Block solenoid valves/hydraulic pistons ORtwo OPERABLE dedicated hardware speed channels and two OPERABLE AG-95F System trains, including output relays and associated Turbine Trip Block solenoid valves/

hydraulic pistonsThe minimum operability requirements for the Software Overspeed Sub-system include:two OPERABLE dedicated software speed channels and two OPERABLE AG-95F System trains, including output relays and associated Turbine Trip Block solenoid valves/

hydraulic pistonsIndividual component failures that do not render the sub-system(s) inoperable are addressed under the Corrective Action Program (CAP) with restoration times commensurate with the severity of the failure and the operational impact associated with the rework or repair.Furthermore, component failures that result in rendering only one Overspeed Protection Sub-system inoperable are also addressed under the CAP with restoration times commensurate with the severity of the failure and the operational impact associated with the rework or repair.

CPSES - UNITS 1 AND 2 - TRMDOC-7Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)

APPLICABILITYThe OPERABILITY of one Overspeed Protection Sub-system ensures that the Overspeed Protection System is available to prevent an overspeed event while the unit is operating in MODE 1, 2, and 3 with steam available to roll the turbine. The APPLICABILITY is modified by a Note specifying that Overspeed Protection Sub-system OPERABILITY is not required in MODE 2 and 3 if the turbine is isolated from the steam supply by closing all Main Steam Isolation Valves and associated bypass valves.

ACTIONSA.1, A.2, and A.3This ACTION is modified by a Note that specifies that separate Condition entries are allowed for each steam line if valves are inoperable in multiple steam lines.If an HP Stop or Control Valve is inoperable such that it is not capable of properly isolating the steam line to the turbine in response to an overspeed event, action must be taken to restore the valve(s) to OPERABLE status. Failure to restore the valve(s) to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> requires that compensatory action be taken within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to ensure that the affected steam line is isolated by other means.The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time for restoring the valve(s) takes into account the OPERABILITY of the remaining valve in the affected steam line and reasonable time for rework or repair. The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> compensatory action Completion Time is reasonable, based on operating experience, for reaching the required unit conditions from full power operation in an orderly manner and without challenging unit systems.B.1, B.2, and B.3This ACTION is modified by a Note that specifies that separate Condition entries are allowed for each steam line if valves are inoperable in multiple steam lines.If an LP Stop or Control Valve is inoperable such that it is not capable of properly isolating the steam line to the turbine in response to an overspeed event, action must be taken to restore the valve(s) to OPERABLE status. Failure to restore the valve(s) to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> requires that compensatory action be taken within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to ensure that the affected steam line is isolated by other means.The 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time for restoring the valve(s) takes into account the OPERABILITY of the remaining valve in the affected steam line and reasonable time for rework or repair. The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> compensatory action Completion Time is reasonable, based

on operating experience, for reaching the required unit conditions from full power operation in an orderly manner and without challenging unit systems.

CPSES - UNITS 1 AND 2 - TRMDOC-8Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)

C.1If both Overspeed Protection Sub-systems are inoperable, such that neither is capable of initiating a turbine trip in response to an overspeed event, action must be taken within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to isolate the turbine from the steam supply.The 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Completion Time for isolating the turbine from the steam supply is reasonable, based on operating experience, for reaching the required unit conditions from full power operation in an orderly manner and without challenging unit systems.

D.1, D.2, and D.3 In the event that the aforementioned ACTIONS and associated Completion Times cannot be satisfied, action must be initiated within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to place the unit in a lower MODE, with subsequent action to place the unit in MODE 3 within the following 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to place the unit in MODE 4 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> after entering MODE 3. The need to perform these actions would most likely result from the inability to isolate the turbine from the steam supply. Placing the unit in MODE 4 will reduce steam pressure to the point where there is insufficient motive force to overspeed the turbine, even if it is not isolated from the steam generators.The Completion Times are reasonable, based on operating experience, for reaching MODE 3 and MODE 4 from full power operation in an orderly manner and without challenging unit systems.

TECHNICAL REQUIREMENTS SURVEILLANCEThe TRS 13.3.33 requirements are modified by a Note that specifies that the provisions of TRS 13.0.4 are not applicable.

TRS 13.3.33.1This TRS specifies testing of the Turbine Trip Block using the Automatic Turbine Tester (ATT). This test de-energizes each Turbine Trip Block solenoid valve and verifies that the associated hydraulic piston moves to the trip position. The solenoid valve/piston pairs are sequentially tested one at a time, until all three are tested. Each pair is reset prior to testing the subsequent pair. Since only one solenoid valve/piston pair is tested at a time, the Trip Fluid System is never de-pressurized, and the turbine does not trip.The 14 day test Frequency is based on the assumptions in the analyses presented in References 2 and 4.

CPSES - UNITS 1 AND 2 - TRMDOC-9Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)

TRS 13.3.33.2This TRS specifies testing of the turbine HP and LP Stop and Control Valves using the ATT. These tests cycle all Stop and Control Valves to ensure reliability and continuity of service. The HP and LP Stop Valve closure times are also verified to be within required response times (500 and 1500 msec, respectively). These tests cycle one pair of Stop and Control Valves at a time, so they may be performed with the plant on-line below approximately 85% power.The 12 week test Frequency is based on the assumptions in the analyses presented in References 2 and 4.

TRS 13.3.33.3 This TRS has been deleted.

TRS 13.3.33.4This TRS requires disassembly and inspection of at least one HP Stop Valve and one HP Control Valve on a 40 month Frequency to satisfy the turbine inservice inspection requirements described in Reference 6.

TRS 13.3.33.5This TRS requires inspection of at least one LP Stop Valve and one LP Control Valve on a 40 month Frequency to satisfy the turbine inservice inspection requirements described in Reference 6.

TRS 13.3.33.6This TRS requires a test of the Hardware Overspeed Sub-system 2 of 3 relay logic and output relays to ensure that this equipment is capable of processing an overspeed turbine trip signal on demand.

This equipment cannot be tested with the unit at power because performance of the test will trip the turbine. The 18 month test Frequency is consistent with Technical Specification test Frequencies assigned to similar equipment, and it affords the opportunity to test the equipment while the unit is shutdown. This test Frequency is judged to be acceptable based on the reliability of the equipment.REFERENCES1. CPSES FSAR, Section 10.2.2.72. CPSES FSAR, Section 3.5.1.3 CPSES - UNITS 1 AND 2 - TRMDOC-10Revision 84Technical Requirements Manual - Description of ChangesREVISION 59 (continued)3. Engineering Report No. ER-504, Probability of Turbine Missiles from 1800 R/MIN Nuclear Steam Turbine-Generators with 46-Inch Last Stage Turbine Blades, Allis-Chalmers (Siemens) Power Systems, Inc, October 1975 [VL-04-001540]4. Supplement to ER-504, Comparison MTBF Evaluation Comanche Peak ST Protection and Trip System and Engineering Report No. ER-504 Probability of Turbine Missiles, Siemens Power Corporation, February 11, 2004 [VL-05-000489]5. CT-27331, Revision 4, Missile Probability Analysis Methodology for TXU Generation Company LP, Comanche Peak Units 1 and 2 with Siemens Retrofit Turbines, Siemens Westinghouse Power Corporation, October 29, 2004 [VL-05-001268]6. CPSES FSAR, Section 10.2.3.67. 59EV-2004-000774-01 and 59EV-2004-000774-02, 10CFR50.59 Evaluations for installation of the Turbine Generator Digital Protection System in Comanche Peak Unit 1 and Unit 2, respectively REVISION 60 LDCR-TR-2007-1 (EVAL-2004-001966-05) (TJE):

Change TRS 13.3.31.2 frequency to 24 months from 18 months. LDCR-TR-2006-10 (EVAL-2006-002274-01) (CBC):LDCR-TR-2006-010, EVAL-2006-002274-01: The Required Action and Completion Time for A.1.1 and A.1.2 of TRM 13.7.35, "Snubbers" are replaced with "Enter the operability determination process for attached system(s)." [Required Action] and "Immediately" [Completion Time]. Condition B and it's associated Required Action and Completion Time are deleted. TRM 13.7.35, "Snubbers" Condition A, Required Action A allows 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for an inoperable snubber (to either be repaired or replaced) before the associated system/train is declared inoperable. Although this 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provision was relocated from Technical Specifications during conversion to the Improved STS, the NRC has indicated that it is improper to allow an exception to the TS definition of Operability for this support system by way of the TRM. As a result, the industry and the NRC have developed a revision to the STS in TSTF-372. This TSTF is NRC approved and ready for adoption.

The TSTF allows 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> (or 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> for a snubber affecting both trains) for seismic snubbers before declaring the system inoperable using a risk informed approach by the addition new TS 3.0.8. Since there are no current plans to adopt TSTF-372 at Comanche Peak, TRM 13.7.35 is revised to remove the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> delay. Deletion of the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> delay is consistent with the NRC's expectations as stated in 70FR23252.

CPSES - UNITS 1 AND 2 - TRMDOC-11Revision 84Technical Requirements Manual - Description of ChangesREVISION 60 (continued)TR LCO 13.7.35 is revised to exclude certain snubbers. Those snubber(s) that have an analysis which determines that the supported TS system(s)) do not require the snubber(s) to be functional in order to support the operability of the system(s) are excluded from TR LCO 13.7.35. This is consistent with Section 4.1 of TSTF-IG-05-03, IMPLEMENTATION GUIDANCE FOR TSTF-372, REVISION 4, "ADDITION OF LCO 3.0.8, INOPERABILITY OF SNUBBERS," dated October 2005 and RIS-2005-020, REVISION TO GUIDANCE FORMERLY CONTAINED IN NRC GENERIC LETTER 91-18, INFORMATION TO LICENSEES REGARDING TWO NRC INSPECTION MANUAL

SECTIONS ON RESOLUTION OF DEGRADED AND NONCONFORMING CONDITIONS AND ON OPERABILITY," dated September 26, 2005.

REVISION 61 LDCR-TR-2006-1 (EVAL-2004-001966-03) (TJE):Justification: The use of the new Seismic Monitoring System with only free-field ground motion input will not compromise the ability of the system to determine whether or not the OBE was exceeded and subsequent shutdown of both units per Appendix A of 10CFR100. Therefore, the new Seismic Monitoring System does not present any added risk to public health or nuclear safety. The deletion of the steps for restoring the seismic monitoring system to an operable status and for the interpretation of the seismic data reflects a change in technology provided with the new system. The previous seismic monitoring system was rendered inoperable during the process of recording a seismic event. With the exception of the three triaxial accelerometers, the previous system used smoked scribe plates in the sensors that can not distinguish between different seismic events. In order to interpret the data from a seismic event and restore operability, the scribe plates had to be retrieved from the field, replaced with freshly smoked scribe plates, and then individually interpreted. The new seismic monitoring system is not rendered inoperable by a seismic event. The new system has the ability to digitally record up to 90-minutes of seismic ground motion over any number of discrete seismic events. The new seismic monitoring system will automatically; analyze the earthquake data, provide a real-time display of the data analysis and its results on the system monitor, print a hard copy of the analysis results, and if the OBE is exceeded the system will also provide Control Room annunciation. Based on the changes introduced by the new seismic monitoring as discussed above, the deletion of the steps for post-seismic event activities is acceptable. 1.) TR LCO 13.3.31 delete the words, "shown in Table 13.3.31-1" 2.) Replace Condition A, including the Note with the words, "Seismic monitoring instrument inoperable."3.) Replace Required Action A.1 with the words, "Restore seismic monitoring instrument to OPERABLE status."

CPSES - UNITS 1 AND 2 - TRMDOC-12Revision 84Technical Requirements Manual - Description of ChangesREVISION 61 (continued)4.) Replace the Completion Time of "24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />" with "30 days."5.) Delete Required Actions A.2 and A.3 and the associated Completion Times.Delete Conditions B and C and the associated Required Actions and Completion Times.1.) Delete the Note that says:"Refer to Table 13.3.31-1 to determine which TRS apply for each seismic monitoring instrument."2.) Change TRS 13.3.31.2 Frequency from 24 months to 18 months.

Delete Table 13.3.31-1 and associated foot notes Delete the entire Bases section and replace it with the following words:"The OPERABILITY of the seismic monitoring system ensures that sufficient capability is available to promptly determine whether the OBE has been exceeded and to collect information to evaluate the response of features important to safety. This capability is required pursuant to Appendix A of 10CFR100. The instrumentation provided meets the intent of Regulatory Guide 1.12, "Instrumentation for Earthquakes," April 1974, as described in the FSAR. The seismic monitoring system will record and analyze a seismic event to determine OBE exceedance in accordance with the requirements described in the FSAR." REVISION 62 LDCR-TR-2006-5 (EVAL-2004-001881-04) (TJE):Circuit Breaker 1ED1-1/14/BKR will be deleted from Table 13.8.32-1a under number 6.b. Backup Breakers.

REVISION 63 LDCR-TR-2007-2 (EVAL-2004-002710-05) (TJE):The FDA installs the Head Assembly Upgrade Package (HAUP) on the replacement reactor vessel closure head during 1RF12. The objective of the HAUP modification is to simplify the process of removal and installation of the reactor vessel closure head assembly for refueling operations (i.e., shorten the duration). Therefore, this LDCR will show unit differences.Add "(Unit 2 Only)" after "General Area CRDM Shroud Exhaust" in the Temperature Limit table under "Area Monitored." Additionally, add a second entry of "140" under "Normal Conditions" and "149" under "Abnormal Conditions" and "CRDM Air Handling Unit Inlet (Unit 1 Only)" under "Area Monitored."

CPSES - UNITS 1 AND 2 - TRMDOC-13Revision 84Technical Requirements Manual - Description of ChangesREVISION 63 (continued) LDCR-TR-2005-3 (EVAL-2005-000224-01) (TJE):Revised note 12 to include motor driven AFW pumps in Units 1 and 2 and feedwater split flow bypass valves in Unit 2 only due to deletion of split flow valves in Unit 1 as a result of the design modification to replace the SGs in Unit 1.Revised note 13 to include turbine driven AFW pumps in Units 1 and 2 and feedwater split flow bypass valves in Unit 2 only due to deletion of split flow valves in Unit 1 as a result of the design modification to replace the SGs in Unit 1.Under Feedwater Isolation Signal on Table 13.6.3-1 add "2-" in front of valve numbers FV-2193, FV-2194, FV-2195, and FV-2196.

REVISION 64 LDCR-TR-2007-8 (EVAL-2007-001391-01) (TJE):The last sentence of TRM 15.5.31.i, "Snubber Service Life Program," reads, " Part replacement shall be documented and the documentation shall be retained in accordance with Technical Specification 6.10.2." Replace the reference to "Technical Specifications 6.10.2" with "FSAR 17.2.17.2.12."LA 50/36 relocated the record retention requirements of snubbers from TS to the FSAR. This LDCR corrects the reference to the implementing document. LDCR-TR-2004-9 (EVAL-2003-001212-04) (TJE):Remove the Note and the Tables in the Background section of TRB 13.1.31 which required specific BAT levels and BAT temperatures to be maintained during startup and shutdown modes when the gravity feed path from the BAT to the CCP's was used when sparging the BAT with nitrogen. "Note: The level values for the Boric Acid Storage Tank (BAST) are non-conservative when using the gravity feed path from the BAST to the CCPs. The BAST levels are correct when using the path from the BAST to the Boric Acid Transfer Pump. The only place that it is incorrect is when using the BASTs to feed the CCPs through the gravity feed path when the BASTs have been sparged with nitrogen. This issue is being addressed in the corrective action program (SMF-2003-001212). In the interim, conservative limits for the BAST tanks levels have been identified in operations procedures. The conservative limits are: Gravity Feed to CCPUnit Mode BAT Temperature Required BAT Level1 1-4 "<or=" 110 degree F 63 percent1 1-4 "<or=" 95 degree F 56 percent1 1-4 "<or=" 80 degree F 53 percent CPSES - UNITS 1 AND 2 - TRMDOC-14Revision 84Technical Requirements Manual - Description of ChangesREVISION 64 (continued) LDCR-TR-2004-9 (EVAL-2003-001212-04) (TJE) (continued):2 1-4 "<or=" 110 degree F 95 percent2 1-4 "<or=" 95 degree F 89 percent2 1-4 "<or=" 80 degree F 86 percent"Remove the Note and the Tables in TRS 13.1.31.3 which required specific BAT levels and BAT temperatures to be maintained during startup and shutdown modes when the gravity feed path from the BAT to the CCP's was used when sparging the BAT with nitrogen. "Note: The level values for the Boric Acid Storage Tank (BAST) are non-conservative when using the gravity feed path from the BAST to the CCPs. The BAST levels are correct when using the path from the BAST to the Boric Acid Transfer Pump. The only place that it is incorrect is when using the BASTs to feed the CCPs through the gravity feed path when the BASTs have been sparged with nitrogen. This issue is being addressed in the corrective action program (SMF-2003-001212). In the interim, conservative limits for the BAST tanks levels have been identified in operations procedures. The conservative limits are: Gravity Feed to CCPUnit Mode BAT Temperature Required BAT Level1 1-4 "<or=" 110 degree F 63 percent1 1-4 "<or=" 95 degree F 56 percent1 1-4 "<or=" 80 degree F 53 percent2 1-4 "<or=" 110 degree F 95 percent 2 1-4 "<or=" 95 degree F 89 percent2 1-4 "<or=" 80 degree F 86 percent"Remove the Note and the Tables in the Background section of TRB 13.1.32 which required specific BAT levels and BAT temperatures to be maintained during startup and shutdown modes when the gravity feed path from the BAT to the CCP's was used when

sparging the BAT with nitrogen. "Note: The level values for the Boric Acid Storage Tank (BAST) are non-conservative when using the gravity feed path from the BAST to the CCPs. The BAST levels are correct when using the path from the BAST to the Boric Acid Transfer Pump. The only place that it is incorrect is when using the BASTs to feed the CCPs through the gravity feed path when the BASTs have been sparged with nitrogen. This issue is being addressed in the corrective action program (SMF-2003-001212). In the interim, conservative limits for the BAST tanks levels have been identified in operations procedures. The conservative limits are:

CPSES - UNITS 1 AND 2 - TRMDOC-15Revision 84Technical Requirements Manual - Description of ChangesREVISION 64 (continued) LDCR-TR-2004-9 (EVAL-2003-001212-04) (TJE) (continued):conservative limits for the BAST tanks levels have been identified in operations procedures. The conservative limits are: Gravity Feed to CCPUnit Mode BAT Temperature Required BAT Level1 1-4 "<or=" 110 degree F 63 percent1 1-4 "<or=" 95 degree F 56 percent1 1-4 "<or=" 80 degree F 53 percent 2 1-4 "<or=" 110 degree F 95 percent2 1-4 "<or=" 95 degree F 89 percent2 1-4 "<or=" 80 degree F 86 percent"Remove the Note and the Tables in TRS 13.1.32.4 and TRS 13.1.32.5 which required specific BAT levels and BAT temperatures to be maintained during startup and shutdown modes when the gravity feed path from the BAT to the CCP's was used when sparging

the BAT with nitrogen. "Note: The level values for the Boric Acid Storage Tank (BAST) are non-conservative when using the gravity feed path from the BAST to the CCPs. The BAST levels are correct when using the path from the BAST to the Boric Acid Transfer Pump. The only place that it is incorrect is when using the BASTs to feed the CCPs through the gravity feed path when the BASTs have been sparged with nitrogen. This issue is being addressed in the corrective action program (SMF-2003-001212). In the interim, conservative limits for the BAST tanks levels have been identified in operations procedures. The conservative limits are: Gravity Feed to CCPUnit Mode BAT Temperature Required BAT Level1 1-4 "<or=" 110 degree F 63 percent1 1-4 "<or=" 95 degree F 56 percent1 1-4 "<or=" 80 degree F 53 percent2 1-4 "<or=" 110 degree F 95 percent 2 1-4 "<or=" 95 degree F 89 percent2 1-4 "<or=" 80 degree F 86 percent" LDCR-TR-2005-6 (EVAL-2005-002551-01) (TJE):1.) In the second paragraph on page 13.3-8, replace the last sentence which reads, "SR 3.3.1.2 Note 1 requires that the NIS and N-16 Power Monitor channels be adjusted if the absolute difference is > 2% RPT."

CPSES - UNITS 1 AND 2 - TRMDOC-16Revision 84Technical Requirements Manual - Description of ChangesREVISION 64 (continued) LDCR-TR-2005-6 (EVAL-2005-002551-01) (TJE) (continued):with the words, "SR 3.3.1.2 requires that the NIS Power Range channels be adjusted if the calorimetric heat balance calculation results exceed the NIS Power Range indication by more than +2% RTP, and the N-16 Power Monitor channels be adjusted if the calorimetric heat balance calculation results exceed the N-16 Power Monitor indication by more than +2% RTP."2.) In the second sentence of the third paragraph on page 13.3-8, replace the "+-" with a "+". The sentence will be revised to read, "At that time, the NIS and N-16 power indications must be normalized to indicate within at least + 2% RTP of the calorimetric

measurement."Please note that this change makes the TRM Bases consistent with NRC License Amendment 133.

REVISION 65 LDCR-TR-1999-12 (EVAL-2006-002367-01) (TJE):Add a new paragraph to the end of the TRM Bases LCO 13.1.32 to allow the required Boric Acid Storage Tank (BAST) flowpath to be considered OPERABLE during BAST recirculation if capable of being manually realigned to the injection flowpath.When recirculating the BAST, manual action to align the required flowpath to the injection mode consists of locally closing one valve, XCS-8477A for BAST X-01 or XCS-8477B for BAST X-02. The Technical Requirement specifically credits the gravity feed path as one acceptable flowpath. The gravity feed flowpath must be manually aligned by operating valves locally. Also, other Technical Specifications (for example TS 3.5.3) provide an allowance to take credit for manually realigning required flowpaths. Providing the flexibility to take credit for the capability of manual realignment of the required flowpath will allow operation of the BA System to maintain proper chemistry control of the required borated water source when the alternate source and/or flowpath is unavailable.This change will make the TRM consistent with OPS procedure SOP-105.

Add the following words to the last paragraph of Bases LCO 13.1.31 on page B 13.1-3,"An OPERABLE Boration Injection System is required to be capable of being manually aligned when boration is required, and in all cases within 15 minutes, to establish boration flow. When local manual control is being credited, administrative controls are utilized to ensure 1) appropriate personnel are aware of the status of the Boration Injection System, and 2) specified individuals are designated and readily available to perform the valve alignment necessary to establish boration flow."

CPSES - UNITS 1 AND 2 - TRMDOC-17Revision 84Technical Requirements Manual - Description of ChangesREVISION 65 (continued) LDCR-TR-1999-12 (EVAL-2006-002367-01) (TJE) (continued):Add the following new paragraph to the end of the Bases LCO 13.1.32 on page B 13.1-10,"An OPERABLE Boration Injection System is required to be capable of being manually aligned when boration is required, and in all cases within 15 minutes, to establish boration flow. When local manual control is being credited, administrative controls are utilized to ensure 1) appropriate personnel are aware of the status of the Boration Injection System, and 2) specified individuals are designated and readily available to perform the valve alignment necessary to establish boration flow." LDCR-TR-2006-2 (EVAL-2006-000569-01) (TJE):In the Background section of the TRM Bases TRM, 13.1-1, replace the second paragraph which reads, "The components required to perform this function include: (1) borated water sources, (2) charging pumps, (3) separate flow paths, (4) boric acid transfer pumps, and (5) an emergency power supply from OPERABLE diesel generators." with the words, "The components required to perform this function in MODES 1, 2, 3, and 4 include: (1) borated water sources, (2) pumps, (3) separate flow paths, and (4) the associated train Class 1E bus power supplies."In the TRM Bases section 13.1.32, page 13.1-8, insert the following paragraph after the first paragraph in the Background section, "The components required to perform this function in MODES 5 and 6 include: (1) a borated water source, (2) pump(s), (3) a functional flow path and (4) the associated train Class 1E bus power supply." LDCR-TR-2007-9 (EVAL-2006-002367-02) (TJE):

Technical Specifications was revised via LDCR TS-2006-001 (EVAL-2006-000627 01) reflect current organizational titles per letter CPSES-200502468-01-01.TS 5.1.1, 5.2.1, 5.2.2.d, 5.5.1.b, and 5.5.17 use to specify that the Plant Manager is responsible for the designated functions described by the respective Specification with a Note stating these "Duties may be performed by the Vice President of Nuclear Operations if that organizational position is assigned." This Note was deleted from the Technical Specifications. There are no changes to the prerequisite qualifications for the position, the assigned responsibilities, or the organizational reporting relationships for the Plant Manager or the Site Vice President, formerly the Vice President, Nuclear Operations.

CPSES - UNITS 1 AND 2 - TRMDOC-18Revision 84Technical Requirements Manual - Description of ChangesREVISION 65 (continued) LDCR-TR-2007-9 (EVAL-2006-002367-02) (TJE) (continued):LDCR TR-2007-009 proposes to delete this Note in accordance with LDCR TS-2006-001 (EVAL-2006-000627-01-01) and is an administrative change which will make the TRM more accurately reflect the current, and expected future, organizational structure at CPSES.In 15.5.17.d, delete the "*" after the words "Plant Manager" and delete the note at the bottom of the page that says, "* Duties may be performed by the Vice President of Nuclear Operations if that organizational position is assigned." LDCR-TR-2007-12 (EVAL-2006-000569-02) (TJE):

Correct TRM Table number from 13.10.31-11 tp 13.10.31-1 REVISION 66 LDCR-TR-2007-5 (EVAL-2004-002063-13) (TJE):On TRM Table 13.8.32-1a, Page 7 of 13, section 3.3, delete "or THFK" from the description of the system powered and delete the following breaker information from the table:"7F THFK Electric H2 Recombiner Power Supply PNL 01" On TRM Table 13.8.32-1a, Page 8 of 13, section 3.4, delete "or THFK" from the description of the system powered and delete the following breaker information from the table:"6F THFK Elect. H2 Recombiner Power Supply PNL 02" On TRM Table 13.8.32-1b, Page 7 of 14, section 3.3, delete "or THFK" from the description of the system powered and delete the following breaker information from the table:"7F THFK Electric H2 Recombiner Power Supply PNL 01" On TRM Table 13.8.32-1b, Page 8 of 14, section 3.4, delete "or THFK" from the description of the system powered and delete the following breaker information from the table:"6F THFK Elect. H2 Recombiner Power Supply PNL 02" CPSES - UNITS 1 AND 2 - TRMDOC-19Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2007-11 (EVAL-2006-000629-02) (TJE):

Technical Justification: The primary basis for TR LCO 13.9.31 is to ensure sufficient fission product decay prior to fuel movement such that anticipated doses resulting from a postulated fuel handling accident (FHA) would not exceed regulatory limits. The proposed change is expected to increase the dose consequences of a FHA and, as a result, the accident analysis for this event was revised and is documented in WPT-16939. The revised analysis results demonstrate that calculated accident doses to personnel both offsite and in the control room at the above conditions increase slightly, however all are well within the limits specified in Regulatory Guide 1.195 and 10CFR100. The revised FHA results have been incorporated into DBD-ME-027 Rev. 9.On page 13.9-1, change 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> to 75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br /> in TR LCO 13.9.31, Condition A, and in TRS 13.9.31.1Replace the words in TRB 13.9.31, "Decay Time," which read, "The minimum requirement for reactor subcriticality prior to movement of irradiated fuel assemblies in the reactor vessel ensures that sufficient time has elapsed to allow the radioactive decay of the short-lived fission products. This decay time is consistent with the assumptions used in the safety analyses." with the words, "The minimum required time for reactor subcriticality prior to movement of irradiated fuel assemblies in the reactor vessel ensures sufficient radioactive decay of those fission products that contribute to the radiological consequences of a postulated fuel handling accident. Per Regulatory Guide 1.195, these fission products include xenon, krypton and iodine whose activity is assumed to be instantaneously released to the refueling cavity during the accident. The fraction of iodine retained within the cavity is determined by the water depth above the damaged fuel assembly as specified in Technical Specifications LCO 3.9.7, "Refueling Cavity Water Level." Retention of noble gases within the cavity is negligible. Release of fission products from the refueling cavity to the environment

occurs over a 2-hour time period. The required decay time and the water level requirement of Technical Specifications LCO 3.9.7 ensure the control room, exclusion area boundary, and low population zone dose limits of References 1, 3 and 4 are met following a fuel handling accident within containment. The assumptions for a fuel handling accident occurring within the fuel building are similar and the radiological consequences are equivalent. The required decay time is consistent with the assumptions used in the safety analysis (Ref. 5)."REFERENCES 1. Regulatory Guide 1.195, May 2003 2. Technical Specifications

3. 10CFR100 CPSES - UNITS 1 AND 2 - TRMDOC-20Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2007-11 (EVAL-2006-000629-02) (TJE) (continued): 4. Appendix A to 10CFR50, General Design Criteria 19 5. FSAR Section 15.7.4" REVISION 67 LDCR-TR-2007-3 (EVAL-2005-002580-02) (TJE):Change the frequency of TRS 13.3.33.2 from every "12" weeks to every "26" weeks as approved by NRC in License Amendment 143 issued on 2/29/08.1.) In TRS 13.3.33.1, change the words "References 2 and 4" to "Reference 2"2.) In TRS 13.3.33.2, a.) insert "manual test or the" in first sentence before ATT, and b.) change the frequency from "12" weeks to "26" weeks and change Reference "4" to "5".In the Reference section B 13.3, 1.) delete the VL number from Reference 32.) replace Reference 4 with the word "Deleted" In the Reference section B 13.3,1.) for Reference 5, change the revision from "4" to "5", change the date from "October 29, 2004" to "January 18, 2007," and delete the VL number.2.) Correct a typo by changing "59EV-2004-000774-01" to "59EV-2004-000773-01" and "59EV-2004-000774-02" to "59EV-2004-000773-02."3.) Add Reference 8, "LDCR TR-2007-003, Change TRS 13.3.33.2 Frequency from 12 weeks to 26 weeks, EVAL-2005-002580-02."In B 13.3 of the Applicable Safety analyses second sentence of first paragraph, change "Using References 3 through 5"to "Using References 3 and 5"In the Actions sections of the second paragraph, change "If an HP" to "If a HP" In the Actions section under B.1, B.2, and B.3 second paragraph, first sentence, replace "If an LP" with "If a LP" CPSES - UNITS 1 AND 2 - TRMDOC-21Revision 84Technical Requirements Manual - Description of Changes REVISION 68 LDCR-TR-2007-6 (EVAL-2006-004119-03) (TJE):The PDMS instrumentation does not change any of the key safety parameter limits or levels of margin as considered in the reference design basis evaluations.Add new TR section 13.2.34 which will read, "TR 13.2.34 Power Distribution Monitoring System 13.2-6"The PDMS instrumentation does not change any of the key safety parameter limits or levels of margin as considered in the reference design basis evaluations.

In the Applicability section of TR 13.2.32, 1.) change 15% to 50% and 2.) add a note that says, "Mode 1 with THERMAL POWER "greater than or equal to" 15%

RTP during Unit 1, Cycle 13"The PDMS instrumentation does not change any of the key safety parameter limits or levels of margin as considered in the reference design basis evaluations.1.) In TRS 13.2.32.1 Surveillance Notes, a.) In Note 1, delete the words, "and for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after restoring to OPERABLE status"b.) Add Note 3 that will read, "Only required to be performed for the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after restoring the AFD Monitor Alarm to OPERABLE status during Unit 1, Cycle 13.2.) In TRS 13.2.32.1 Frequency note, add "for Unit 1, cycle 13" after the words "Only required."The PDMS instrumentation does not change any of the key safety parameter limits or levels of margin as considered in the reference design basis evaluations.Add the new TR 13.2.34, "Power Distribution Monitoring System" REVISION 69 LDCR-TR-2008-1 (EVAL-2006-003080-16) (TJE):In TR 13.3.34,1.) Delete the "*" in the Applicability section2.) Required Actions B.1 and B.3, delete "(3411 MWth), and CPSES - UNITS 1 AND 2 - TRMDOC-22Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2008-1 (EVAL-2006-003080-16) (TJE) (continued):3.) Delete the note at the bottom of the page that says, "*This TRM requirement applies to Unit 2 only until implementation of the 1.4% uprate for Unit1 during 1RF09."Revise 13.3.34 Plant Calorimetric Measurement to show Unit differences. For Unit 2 Cycle 11, the RATED THERMAL POWER is 3458 MWth, and the core power should be reduced to 3411 MWth if the LEFMv is unavailable. For Unit 1, the RATED THERMAL POWER is 3612 MWth, and the core power should be reduced to 3562 if the LEFMv is unavailable.In the Reference sections, add the following three references:2. License Amendment Request (LAR)07-004, Revision to the Operating License and Technical Specifications 1.0, "Use and Application" and 3.7.17, "Spent Fuel Assembly Storage" to Revise Rated Thermal Power from 3458 MWth to 3612 MWth. Docket Nos.

50-445 and 50-446, CPSES.3. WCAP-16840-P, Rev. 0, Comanche Peak Nuclear Power Plant Stretch Power Uprate Licensing Report.4. License Amendment 146, Revision to the Operating License and Technical Specifications 1.0, "Use and Application" to Revise Rated Thermal Power from 3458 MWth to 3612 MWth. Docket Nos. 50-445 and 50-446, CPSES.

REVISION 70 LDCR-TR-2007-10 (EVAL-2007-002743-03) (TJE):Relocate the TS detailed technical requirements for verifying equilibrium Containment emergency sump pH commensurate with Technical Specification (TS) Surveillance Requirement SR 3.6.7.1 to the TRM 13.6.7. ACTIONS for not verifying equilibrium Containment emergency sump pH is contained in Technical Specification 3.6.7. The performance test requirements for the Spray Additive System are subject to TS SR 3.6.7.1.This change affects the Containment Spray System which is intended to respond to and mitigate the effects of a LOCA. The Containment Spray System will continue to function in a manner consistent with the plant design basis. There will be no degradation in the performance of nor an increase in the number of challenges to equipment assumed to function during an accident situation. LDCR-TR-2008-3 (EVAL-2008-003080-1) (TJE):In the TRM Bases 13.3.33, Applicable Safety Analyses section, last sentence, replace "through" with "and".In TRM Bases 13.3.33, Reference 3, change 46 to 44.

Deleted References 7 and 8 of TRM Bases 13.3.33.

CPSES - UNITS 1 AND 2 - TRMDOC-23Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2008-3 (EVAL-2008-003080-1) (TJE) (continued):In TRM 13.9.34 header, add an "a" to "Storge" to correctly spell Storage.

REVISION 71 LDCR-TR-2009-002 (EVAL-2009-001094-02) (RAS):Revises the limit for the OTN16 Reactor Trip function in Table 13.3.1-1 (item 6) to less than or equal to 3.3 seconds and footnote 2 to state "An additional 6 seconds maximum delay allowance for the RTD/thermal well response time provides an overall Overtemperature N-16 Response Time of less than or equal to 9.3 seconds for the Tcold input." REVISION 72 LDCR-TR-2009-003 (EVAL-2008-002987-03) (RAS):Replace the second NOTE for TRS 13.3.32.3 with the following "For the source range neutron detectors, performance data is obtained and evaluated."The bias curve that is described is for establishing the bias voltage to filter gamma pulses and provides no meaningful assessment of detector condition.

REVISION 73 LDCR-TR-2009-001 (EVAL-2009-000465-02) (RAS):Revise Table 13.3.1-1 to add a response time limit of </=650 msec for Positive Flux Rate Trip function to Table 13.3.1-1.

REVISION 74 LDCR-TR-2008-004 (EV-CR-2008-003510-00-5) (TJEW):Add the following words to the end of the first sentence of the fourth paragraph in TRB 13.3.5 for the discussion of the bases for LOP DG Start Instrumentation Response Times, "for continued operability of motors to perform their ESF function"Revise response times for the following signals and functions in TRM Table 13.3.5-1 (Page 1 of 1) "Loss of Power Diesel Generator Start Instrumentation Response Time Limits":A.) In number 2 and 3, replace "N/A" with "less than or equal to 1 second" and add note

"(1)" B.) In number 4, change note "(1)" to note "(2)"

CPSES - UNITS 1 AND 2 - TRMDOC-24Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2008-004 (EV-CR-2008-003510-00-5) (TJE) (continued):C.) The response times in numbers 5 and 7 currently says "less than or equal to 10" and has notes 1, 2, and 3 and "/ less than or equal to 63" with notes 1, 2, and 4.Replace response times 5 and 7 with "greater than or equal to 6 & less than or equal to 10 / less then or equal to 60". Add note 5 to the 6 seconds, notes 5 and 3 to the 10 seconds, and note 4 to the 60 seconds.D.) Delete the current response time in number 6 "less than or equal to 63" with notes 1 and 2. Replace the response time with "greater than or equal to 45" an add notes 6 and 3.E.) Replace notes 1, 2, 3, and 4 which currently say, "(1) Response time measured to output of undervoltage channel only.

(2) Two additional seconds allowable for alternate offsite source breaker trip functions.

(3) With SI (4) Without SI" with these notes below:"(1) Response time measured to output of under voltage channel providing the offsite source breaker trip signal.(2) Response time measured to output of under voltage channel providing the DG start signal.(3) An additional 3 seconds is allowed for the Alternate Offsite Source breaker trip signal and another 3 seconds is allowed for DG close permissive signal.(4) Response time measured to output of under voltage channel providing the Preferred and Alternate Offsite Source breakers trip signals after detection of degraded Voltage condition, in the absence of SIAS. "(5) Response time measured to output of under voltage channel to confirm degraded condition for providing a Preferred Offsite Source breakers trip on subsequent occurrence of SIAS.(6) Response time measured to output of under voltage channel to confirm 480V bus low grid condition for providing a Preferred Offsite Source breakers trip on subsequent occurrence of SIAS.

CPSES - UNITS 1 AND 2 - TRMDOC-25Revision 84Technical Requirements Manual - Description of Changes REVISION 75 LDCR-TR-2010-002 (EV-CR-2007-003164-00-19) (TJEW):Technical Justification: The Fuel Handling Bridge Crane can initiate the fuel-handling accident described in FSAR Section 15.7.4. This requires dropping of a spent fuel assembly in the spent fuel pool fuel storage area floor resulting in the rupture of the cladding of all the fuel rods in the assembly. This accident is based upon dropping one spent fuel assembly, since FSAR Section 9.1.4.2.3.2 states that the FHBC carries one trolley-hoist assembly, which is the design of existing FHBC.In order to maintain credibility of the fuel handling accident the FHBC must not have ability to handle more than one fuel assembly at a time. This condition is maintained because the control station is interlocked so it controls only the trolley - hoist assembly under which it is located. On the other assembly the hoist hook must be raised fully up and empty, and be moved to the extreme east end of the trolley, before the control station

can control the assembly under it is located.The Trolley - Hoist assembly location is monitored and hardwired to permissive controls bypassing the PLC. An assembly must be in the east parking location before either the trolley or hoist of the opposite assembly is allowed to operate. The surveillance must test and the bases must reference these interlocks.

On page 13.9-5 Add new Surveillance Requirement TRS 13.9.34.2, associated note, and frequency:

The note will read, "Only required to be performed when the hoist is being used to move loads over fuel assemblies in a spent fuel storage pool."The new Surveillance Requirement states, "Fuel Handling Bridge Crane interlocks which permit only one trolley-hoist assembly to be operated at a time shall be verified." The frequency will be 6 months.

On page B 13.9-4,1.) Add the header, "LCO" prior to the existing paragraph discussing TRS 13.9.34.1 2.) Indent the original paragraph next to the LCO header.3.) Next add the new TR Surveillance shown as follows:

TRS 13.9.34.2 In order to prevent more than a single fuel assembly being moved over other fuel assemblies in a storage pool, interlocks prevent control of a trolley-hoist assembly unless the opposite trolley-hoist assembly has the hook unloaded and completely up, and the trolley located in the far east end parking area.

CPSES - UNITS 1 AND 2 - TRMDOC-26Revision 84Technical Requirements Manual - Description of Changes REVISION 76 LDCR-TR-2011-001 (EV-CR-2010-004974-5) (RAS):

Adds a new section to TRM Table 13.7.39-1 to add allowances for removal of the EDG Missile Shield Barriers in rooms 1-084 (EDG CP1-MEDGEE-01), 1-085 (EDG CP1-MEDGEE-02), 2-084 (EDG CP2-MEDGEE-01), and 2-085 (EDG CP2-MEDGEE-02). The allowances establish new administrative controls for the Units 1 & 2 EDG missile resistant barriers and the associated Bases section TRB 13.7.39 to allow a section of the existing EDG missile barrier to be breached/opened for a limited time period without having to declare the respective Train of EDG INOPERABLE.

REVISION 77 LDCR-TR-2011-002 (EV-CR-2011-004788-1) (JDS):Add Note to Modify the LCO to allow the use of additional hoists for special evolutions such an the unlatching of bent control rod drive shafts. This note is necessary to allow alignment of the CRDM unlatching tool to the CRDM shaft. In addition, Condition A and the associated Required Actions were modified to apply the immediate Completion Times for all hoists where OPERABILITY may not be satisfied.

Surveillance requirement TRS 13.9.33.2 was modified to apply to other hoists and load indicators used to support unlatching of the CRDM shafts from the control rods.The Bases for TRM 13.9.33 was modified to provide a discussion regarding the note modifying the LCO to allow the use of additional hoists and load indicators for special evolutions. In addition, the text was modified to identify that the auxiliary hoist is "typically" used for unlatching of CRDM shafts from the control rods.

REVISION 78 LDCR-TR-2008-002 (EV-CR-2007-000920-20) (RAS):Justification: The breakers in the compartments listed above no longer perform overcurrent protection of containment penetration conductors. FDA-2007-000920-01 determinated the motor power leads inside MCCs 1EB1-2 and 1EB2-2 and made all affected breakers spares. FDA-2007-000920-2 ABANDON THE UNIT 1 SG CHEM FEED SYSTEM IN PLACE including these MCCs.From Table 13.8.32-1a (Page 5 of 193, FSAR page 13.8-11, remove MCC 1EB1-2 Compartment numbers 10F and 12M.Justification: The breakers in the compartments listed above no longer perform overcurrent protection of containment penetration conductors. FDA-2007-000920-01 determinated the motor power leads inside MCCs 1EB1-2 and 1EB2-2 and made all affected breakers spares.

From Table 13.8.32-1a (Page 6 of 13), FSAR page 13.8-12, remove MCC 1EB2-2 Compartment numbers 1M and 12M.

CPSES - UNITS 1 AND 2 - TRMDOC-27Revision 84Technical Requirements Manual - Description of Changes REVISION 79 LDCR-TR-2010-004 (EV-CR-2010-009959-1) (TJD):In the APPLICABILITY, replace the ">" symbol with a >

symbol.Correct the TRM 13.2.32 for AFD to be consistent with TS 3.2.3 for AFD.

Delete the entire NOTE prior to the ACTIONS section.Delete outdated information related to Constant Axial Offset Control (CAOC).Replace the existing CONDITION A with the following: "AFD Monitor Alarm inoperable."

CONDITION A is being changed to more accurately reflect the purpose of TRM 13.2.32.Replace the existing REQUIRED ACTION A.1 with the following: "Perform TRS 13.2.32.1."REQUIRED ACTION A.1 is being changed to more accurately reflect the purpose of TRM 13.2.32.Delete SURVEILLANCE NOTES 2 and 3.

Delete outdated information related to Constant Axial Offset Control (CAOC).Delete the "1." from the first NOTE in the SURVEILLANCE NOTES section.After the TRM changes, there will be only one note and the "1." is no longer needed.Delete the "S" from "-NOTES-" title in the SURVEILLANCE NOTES section.Make the NOTES title singular because after the changes there will be only one note.Delete all the text in the FREQUENCY section and replace it with the following:

"Once within 30 minutes AND 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> thereafter."

Delete outdated information related to Constant Axial Offset Control (CAOC), and replace with a Frequency consistent with the new CONDITION A AND REQUIRED ACTION A.1.Delete all text from the first paragraph of Bases 13.2.32, except for the first sentence.Delete outdated information related to Constant Axial Offset Control (CAOC).

CPSES - UNITS 1 AND 2 - TRMDOC-28Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2010-004 (EV-CR-2010-009959-1) (TJD) (continued):Delete the following text from the second sentence of the second paragraph of Bases 13.2.32: "for the calculation of AFD penalty minutes for which a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> history is required" and replace it with the following text: "to increase the frequency of documented AFD monitoring while the AFD Monitor alarm is inoperable. The Surveillance Frequency of once within 30 minutes and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> thereafter is adequate because AFD is controlled by the operator and any deviations of AFD from TS LCO 3.2.3 requirements should be readily noticed. The initial Surveillance Frequency of once within 30 minutes is to support compliance with TS LCO 3.2.3 ACTIONS"Delete outdated information related to Constant Axial Offset Control (CAOC), and replace with information consistent with the new TRS 13.2.32.1 FREQUENCY.Delete the following text from the last sentence in Bases 13.2.32, "AFD penalty minute."Delete outdated information related to Constant Axial Offset Control (CAOC).

REVISION 80 LDCR-TR-2011-003 (EV-CR-2010-005809-9) (JCH):

Referenced Section: TR-15.5.31 Description of Change: Most of TR-15.5.31 page 15.0-2 through 15.0-8 will be deleted, no longer applicable and replaced with instruction to perform Snubber Inservice Program iwa Code OM-Sub-Section ISDT as follows:

TR 15.5.31 Snubber Inservice Testing/Inspection Program All snubbers are required OPERABLE to ensure that the structural integrity of the Reactor Coolant System and all other safety-related systems is maintained during and following a seismic or other event initiating dynamic loads. The snubbers are grouped, visually examined, functionally tested, and maintained in accordance with ASME OM Code, Subsection ISTD, "Preservice and Inservice Examination and Testing of Dynamic Restraints (Snubbers) in Light-Water Reactor Nuclear Power Plants", Latest issue as mandated by 10CFR 50.55A for the current

interval. A list of individual snubbers with detailed information of snubber location and size and of system affected shall be available at the plant in the Unit-1 and Unit-2 Snubber inservice Program Plan. The addition or deletion of any hydraulic or mechanical snubber shall be made in accordance with Section 50.59 of 10 CFR Part 50. The service life of a snubber is established via manufacturer input and information through consideration of the snubber service conditions and associated installation and maintenance records (newly installed snubbers, seal replaced, spring replaced, in high radiation area, in high temperature area, etc.). The requirement to monitor the snubber service life is included to ensure that the snubbers periodically undergo a performance CPSES - UNITS 1 AND 2 - TRMDOC-29Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2011-003 (EV-CR-2010-005809-9) (JCH) (continued):evaluation in view of their age and operating conditions. These records will provide statistical bases for future consideration of snubber service life. Documentation shall be

retained in accordance with FSAR 17.2.17.2.13Technical Justification: This change is due to conversion of our TRM controlled Snubber program to Code OM Sub-Section ISTD iaw RIS-2010-6.There are no commitments affected by this change.

There are no safety concerned elevated by this change, this is an enhancement to the Snubber inservice testing/inspection program and does not change how those tests and inspections are performed, documented nor are the results of testing or inspections modified in any way. LDCR-TR-2011-004 (EV-CR-2010-005809-8) (JCH):

Referenced Section: TRS-13.7.35.1Description of Change: Delete word, "augmented" and add the word, "testing" to TRS 13.7.35.1 Page 13.7.9 of the TRM.Technical Justification: Due to conversion of our TRM controlled Snubber program to Code OM Sub-Section ISDT iaw RIS-2010-6 the Snubber program is no longer augmented. The word testing is added as a clarification that this program is a snubber inservice testing/inspection program.There are no commitments affected by this change.

There are no safety concerned elevated by this change, this is an enhancement to the Snubber inservice testing/inspection program and does not change how those tests and inspections are performed, documented nor are the results of testing or inspections modified in any way.

REVISION 81 LDCR-TR-2012-001 (EV-CR-2011-008700-6) (RAS):Add the following paragraph:"Due to the access opening in the operating deck of the circulating water discharge structure, the stop gates isolate the CW tunnels for lake levels below 778 feet only. Any opening in the CW system at an elevation below the probable maximum flood level of 789.7 feet must be closed or isolated in order to isolate the lake levels above778 from the open pathway that could lead to flooding of the Turbine Building and lower level of the Electrical & Control Building on elevation 778."

CPSES - UNITS 1 AND 2 - TRMDOC-30Revision 84Technical Requirements Manual - Description of Changes REVISION 82 LDCR-TR-2009-004 (EV-CR-2009-008637-2) (CBC):

Pages 13.7-1, 2 Pages B13.7-1, 2 The proposed License amendment would modify the TS by removing the specific isolation time for the isolation valves from the associated Technical Specification Surveillance Requirements (SR 3.7.2.1 - Main Steam Isolation Valves, SR 3.7.3.1 - Feedwater Isolation Valves (FIVs), Feedwater Control Valves (FCVs), and bypass valves).The specific isolation time required to meet the TS Surveillance Requirements will be located outside of the TS in a document subject to control by the 10 CFR 50.59 process (i.e. Technical Requirements Manual TR 13.7.2)). The SR 3.7.2.1 to verify the isolation time remains in the Technical Specifications. The changes are consistent with Nuclear Regulatory Commission (NRC) approved Industry / Technical Specification Task Force (TSTF) TSTF-491 Revision 2. The availability of this TS improvement was announced in the Federal Register on December 29, 2006 (71FR78472) as part of the consolidated line item improvement process (CLIIP). LDCR-TR-2012-004 (EV-CR-2011-002186-25) (RAS):Add new TR 5.5.21 and associated Bases to relocate the Frequency for selected TS Surveillance Requirements from the Technical Specifications to a licensee-controlled Surveillance Frequency Control Program as approved in License Amendment 156. LDCR-TR-2012-002 (EV-CR-2012-006277-2) (CBC):Add new surveillance TRS 13.1.32.11:

"TRS 13.1.32.11 Demonstrate the required Safety Injection pump is OPERABLE by verifying, on recirculation flow, the requirements of the Inservice Testing Program are met

for developed head." Frequency "In accordance with Inservice Testing Program" Basis for change:Utilization of a SI pump to fulfill the requirement to have an operable boration path in Mode 6 with thereactor head removed requires verification of the operability of the selected pump. Operability of theselected pump is based on the IST testing.

Replace the first sentence in the BACKGROUND section with the following:"A description of the CVCS Boration Injection System is provided in the Bases for TR 13.31.1, "Boration Injection System - Operating". Utilization of a SI pump for fulfillment of CPSES - UNITS 1 AND 2 - TRMDOC-31Revision 84Technical Requirements Manual - Description of Changes LDCR-TR-2012-002 (EV-CR-2012-006277-2) (CBC) (continued):TR 13.1.32 when in Mode 6 with the reactor head removed requires maintenance of a flow path from the RWST, through the selected pump, and into the RCS cold legs."Basis for Change:The existing text refers to CVCS boration paths (only) and refers back to TR 13.31.1 for a description of those flow paths.

At the end of the APPLICABLE SAFETY ANALYSES section, add (new item):"A safety injection pump and associated flow paths from the RWST and to the RCS cold legs can be utilized to fulfill TR 13.1.32 in Mode 6 with the reactor head removed. The requirements of TRS 13.1.32.1, TRS 13.1.32.6, TRS 13.1.32.7, TRS 13.1.32.8, and TRS 13.1.32.11 are applicable to this configuration. Refer to Reference 1 for details."Revise item "b." in the LCO section of TRB 13.1.32 (changed item) as follows:"Either a centrifugal charging pump or positive displacement charging pump or a safety injection pump (in Mode 6 with the reactor head removed only), and" Basis for Change" The existing text refers to CVCS boration paths (only) and the specified change simply adds the SI flow path and the associated limitation on its use.At the end of the TECHNICAL REQUIREMENTS SURVEILLLANCE section add the following (new item):"TRS 13.1.32.11 This surveillance requires verification that the selected SI pump is OPERABLE as determined by the Inservice Testing Program. This TRS is applicable only when a SI pump is being used as the required boration injection subsystem in Mode 6 with the reactor head removed. This TRS is analogous to TRS 13.1.32.10 for the centrifugal charging pump."Basis for Change:This new SR is applicable only when a SI pump is being used, i.e., in Mode 6 with the reactor head removed, and is analogous to TRS 13.1.32.10 for the centrifugal charging pump. This change to the Bases is required to support the (new) TR 13.1.32.11.Add a "REFERENCES" section to the end of the BASES for TR 13.1.32 as follows:REFERENCES 1. Westinghouse letter WPT-17618 to R. Flores, dated August 6, 2012, "LUMINANT COMANCHE PEAK NUCLEAR POWER PLANT UNIT 2, Boration Flow Path in Mode 6 with Reactor Vessel Head Removed" CPSES - UNITS 1 AND 2 - TRMDOC-32Revision 84Technical Requirements Manual - Description of Changes REVISION 83 LDCR-TR-2012-005 (EV-CR-2012-009618-1) (CBC):Thefrequencyfortheintegratedtestsequence/lossofoffsitepowertestingisrevisedfrom"18months"to"18monthsonaSTAGGEREDTESTBASIS".AsdocumentedinEV CR 201100218621,thischangewasevaluatedandapprovedinaccordancewithTS5.5.21.

SurveillanceRequirementSource,Number(s)&Description(s):TechnicalSpecificationsSRslocatedinTRMTable15.5.21 1:

SRNo.Description3.5.2.5ECCSFlowpa thValveActuationonSafetyInjection3.5.2.6ECCSPumpActuationonSafetyInjection3.6.3.8PhaseAValveActuationonSafetyInjection(1 8152only)3.7.5.3AFWValveAutomaticActuationonLossofOffsitePower3.7.5.4MDAFWPumpActuationonSafetyInjection3.7.7.3CCWPumpActuationonSafetyInjection3.7.8.3SSWPumpActuationonSafetyInjection3.7.10.3ControlRoomEmergencyRecirculationonLossofOffsitePower3.7.12.3PrimaryPlantVentilationActuationonSafetyInjection3.7.19.2SafetyChilledWaterPumpandChillerandSwitchgearAreaEmergencyFanCoilUnitActuationonSafetyInjection3.7.20.3UPSA/CTrainActuationonSafetyInjection3.8.1.9SingleLargestLoadRejection3.8.1.10FullLoadRejection3.8.1.11EmergencyBusLoadShed,DGStart,SequenceandRunonLossofOffsitePower3.8.1.13DGNonEmergencyTripSignalsBypassedonLossofOffsitePowerandSafetyInjection3.8.1.15DGHotRestart3.8.1.16DGSynchronizationandLoadTransfer3.8.1.17DGSafetyInjectionOverrideTest3.8.1.19EmergencyBusLoadShed,DGStart,SequenceandRunonSafetyInjectioninConjunctionwithLossofOffsitePower TechnicalRequirementsManual:

TRSNumberDescription13.7.37.1SafetyChilledWaterPumpandChillerandSwitchgearAreaEmergencyFanCoilUnitActuationonSafetyInjection13.8.31.3Diesel7000KWLoadLimitTheassociatedTRMBasesarealsoupdated.

CPSES - UNITS 1 AND 2 - TRMDOC-33Revision 84Technical Requirements Manual - Description of Changes REVISION 84 LDCR-TR-2012-006 (EV-CR-2012-011438-1) (CBC):The frequency for TRS 13.5.32.1 states "Once following completion of modifications to the ECCS subsystems that alter the subsystem flow characteristics." However, there is no discussion of this requirement in the TRM Bases. This change provides additional information with respect to the bases of this requirement as an enhancement. This change clarifes the basis of why this testing is performed, and when this testing frequency condition is met. The TRB number for "ECCS - Pump Line Flow Rates" is changed from

"13.5.31" to "13.5.32" (editorial correction).