Text

Technical Requirements Manual (TRM) and TRM Basis, Revision 84
	ML13043A040
Person / Time
Site:	Comanche Peak
Issue date:	02/04/2013
From:	; Luminant Generation Co, Luminant Power
To:	; Office of Nuclear Reactor Regulation
References
	CP-201300130, TXX-13021
	Download: ML13043A040 (405)
	v • d • e

TECHNICAL REQUIREMENTS MANUAL (TRM)

FOR COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 AND 2

TABLE OF CONTENTS 11.0 USE AND APPLICATION ............................................................................11.0-1 11.1 Definitions...............................................................................................11.0-1 11.2 Logical Connectors.................................................................................11.0-1 11.3 Completion Times ..................................................................................11.0-1 11.4 Frequency ..............................................................................................11.0-1 13.0 TECHNICAL REQUIREMENT APPLICABILITY ..........................................................................................13.0-1 13.1 REACTIVITY CONTROL SYSTEMS .....................................................13.1-1 TR 13.1.31 Boration Injection System - Operating..............................................13.1-1 TR 13.1.32 Boration Injection System - Shutdown .............................................13.1-3 TR 13.1.37 Rod Group Alignment Limits and Rod Position Indicator .................13.1-6 TR 13.1.38 Control Bank Insertion Limits ...........................................................13.1-8 TR 13.1.39 Rod Position Indication - Shutdown .................................................13.1-9 13.2 POWER DISTRIBUTION LIMITS...........................................................13.2-1 TR 13.2.31 Moveable Incore Detection System..................................................13.2-1 TR 13.2.32 Axial Flux Difference (AFD) ..............................................................13.2-3 TR 13.2.33 Quadrant Power Tilt Ratio (QPTR) Alarm ........................................13.2-5 TR 13.2.34 Power Distribution Monitoring System .............................................13.2-6 13.3 INSTRUMENTATION.............................................................................13.3-1 TR 13.3.1 Reactor Trip System (RTS) Instrumentation Response Times ........13.3-1 TR 13.3.2 Engineered Safety Feature Actuation System (ESFAS)

Instrumentation Response Times...............................................13.3-4 TR 13.3.5 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation Response Times...............................................13.3-11 TR 13.3.31 Seismic Instrumentation ...................................................................13.3-13 TR 13.3.32 Source Range Neutron Flux .............................................................13.3-15 TR 13.3.33 Turbine Overspeed Protection .........................................................13.3-17 TR 13.3.34 Plant Calorimetric Measurement ......................................................13.3-21 13.4 REACTOR COOLANT SYSTEM (RCS).................................................13.4-1 TR 13.4.14 RCS Pressure Isolation Valves ........................................................13.4-1 TR 13.4.31 Loose Part Detection System ...........................................................13.4-2 TR 13.4.33 Reactor Coolant System (RCS) Chemistry ......................................13.4-3 TR 13.4.34 Pressurizer .......................................................................................13.4-7 TR 13.4.35 Reactor Coolant System (RCS) Vent Specification..........................13.4-9 13.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)............................13.5-1 TR 13.5.31 ECCS - Containment Debris ............................................................13.5-1 (continued)

CPSES - UNITS 1 AND 2 - TRM i Revision 82

TABLE OF CONTENTS (continued)

TR 13.5.32 ECCS - Pump Line Flow Rates ........................................................13.5-3 13.6 CONTAINMENT SYSTEMS...................................................................13.6-1 TR 13.6.3 Containment Isolation Valves ...........................................................13.6-1 TR 13.6.6 Containment Spray System..............................................................13.6-14 TR 13.6.7 Spray Additive System .....................................................................13.6-15 13.7 PLANT SYSTEMS..................................................................................13.7-1 TR 13.7.2 Main Steam Isolation Valves (MSIVs) ..............................................13.7-1 TR 13.7.3 Feedwater Isolation Valves (FIVs) and Feedwater Control Valves (FCVs) and Associated Bypass Valves ..........................13.7-2 TR 13.7.31 Steam Generator Atmospheric Relief Valve (ARV) -

Air Accumulator Tank .................................................................13.7-3 TR 13.7.32 Steam Generator Pressure / Temperature Limitation ......................13.7-4 TR 13.7.33 Ultimate Heat Sink - Sediment and Safe Shutdown Impoundment (SSI) Dam............................................................13.7-6 TR 13.7.34 Flood Protection ...............................................................................13.7-7 TR 13.7.35 Snubbers ..........................................................................................13.7-10 TR 13.7.36 Area Temperature Monitoring ..........................................................13.7-12 TR 13.7.37 Safety Chilled Water System - Electrical Switchgear Area Emergency Fan Coil Units..........................................................13.7-15 TR 13.7.38 Main Feedwater Isolation Valve Pressure / Temperature Limit........13.7-16 TR 13.7.39 Tornado Missile Shields ...................................................................13.7-18 TR 13.7.41 Condensate Storage Tank (CST) Make-up and Reject Line Isolation Valves...................................................................13.7-30 13.8 ELECTRICAL POWER SYSTEMS ........................................................13.8-1 TR 13.8.31 AC Sources (Diesel Generator Requirements) ................................13.8-1 TR 13.8.32 Containment Penetration Conductor Overcurrent Protection Devices......................................................................13.8-3 13.9 REFUELING OPERATIONS ..................................................................13.9-1 TR 13.9.31 Decay Time ......................................................................................13.9-1 TR 13.9.32 Refueling Operations / Communications ..........................................13.9-2 TR 13.9.33 Refueling Machine............................................................................13.9-3 TR 13.9.34 Refueling - Crane Travel - Spent Fuel Storage Areas......................13.9-5 TR 13.9.35 Water Level, Reactor Vessel, Control Rods .....................................13.9-6 TR 13.9.36 Fuel Storage Area Water Level ........................................................13.9-7 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAM ....................................................................13.10-1 TR 13.10.31 Explosive Gas Monitoring Instrumentation .......................................13.10-1 TR 13.10.32 Gas Storage Tanks ..........................................................................13.10-5 TR 13.10.33 Liquid Holdup Tanks.........................................................................13.10-7 TR 13.10.34 Explosive Gas Mixture......................................................................13.10-9 (continued)

CPSES - UNITS 1 AND 2 - TRM ii Revision 82

TABLE OF CONTENTS (continued) 15.0 ADMINISTRATIVE CONTROLS ............................................................15.0-1 15.5 Programs and Manuals ..........................................................................15.0-1 TR 15.5.17 TRM - Administrative Control Process .............................................15.0-1 TR 15.5.21 Surveillance Frequency Control Program ........................................15.0-2 TR 15.5.31 Snubber Augmented Inservice Inspection Program .........................15.0-16 CPSES - UNITS 1 AND 2 - TRM iii Revision 82

Use and Application TR 11.0 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:

Technical Requirement Technical Specifications Technical Requirement (TR) Technical Specifications (TS) or Specification(s)

Technical Requirement Surveillance Surveillance Requirement (SR)

(TRS) 11.1 Definitions The definitions contained in the Technical Specifications Section 1.1, Definitions apply to the Technical Requirements contained in this manual.

11.2 Logical Connectors The 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.

11.3 Completion Times The 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.

11.4 Frequency The 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.

CPSES - UNITS 1 AND 2 - TRM 11.0-1 Revision 56

TR Applicability TR 13.0 13.0 TECHNICAL REQUIREMENT APPLICABILITY The 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:

Technical Requirement Section Technical Specification Section TR LCO 13.0.1 LCO 3.0.1 TR LCO 13.0.2 LCO 3.0.2 N/A (See Note 1 below) LCO 3.0.3 TR LCO 13.0.4 LCO 3.0.4 TR LCO 13.0.5 LCO 3.0.5 N/A (See Note 2 below) LCO 3.0.6 TR LCO 13.0.7 LCO 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 (continued)

CPSES- UNITS 1 AND 2 - TRM 13.0-1 Revision 56

TR Applicability TR 13.0 13.0 TR APPLICABILITY (continued)

- 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).

CPSES - UNITS 1 AND 2 - TRM 13.0-2 Revision 56

Boration Injection System - Operating TR 13.1.31 13.1 REACTIVITY CONTROL SYSTEMS TR 13.1.31 Boration Injection System - Operating TR LCO 13.1.31 Two 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 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 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 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One boration injection A.1 Restore boration injection 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months subsystem inoperable subsystem to OPERABLE status.

(except due to required charging pump inoperable).

B. One charging pump B.1 Restore charging pump to 7 days inoperable. OPERABLE status.

C. Two boration injection C.1 Initiate action to restore at least Immediately subsystems inoperable. one boration injection subsystem to OPERABLE status.

OR AND Required Actions and associated Completion C.2 Initiate Engineering Evaluation to Immediately Times not met. identify compensatory actions to be completed in a timely manner.

CPSES - UNITS 1 AND 2 - TRM 13.1-1 Revision 82

Boration Injection System - Operating TR 13.1.31 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.1.31.1 Verify that the temperature of the flow path from the 7 days required boric acid storage tanks (including the tank solution temperature) is greater than or equal to 65°F.

TRS 13.1.31.2 Verify the boron concentration of the required boric acid 7 days storage tank has a minimum boron concentration of 7000 ppm.

TRS 13.1.31.3 Verify a minimum indicated borated water level of 50% 7 days of the required boric acid storage tank.

TRS 13.1.31.4 Verify that each valve (manual, power-operated, or 31 days automatic) in the required flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

TRS 13.1.31.5 Verify that the flow path from the boric acid tanks 18 months delivers at least 30 gpm to the RCS.

TRS 13.1.31.6 Demonstrate the required centrifugal charging pump(s) In accordance with OPERABLE by testing in accordance with the Inservice the Inservice Testing Plan. Testing Plan TRS 13.1.31.7 Demonstrate the required positive displacement In accordance with charging pump OPERABLE by performing TRS TRS 13.1.31.5 13.1.31.5.

CPSES - UNITS 1 AND 2 - TRM 13.1-2 Revision 82

Boration Injection System - Shutdown TR 13.1.32 13.1 REACTIVITY CONTROL SYSTEMS TR 13.1.32 Boration Injection System - Shutdown TR LCO 13.1.32 One boration injection subsystem shall be OPERABLE and capable of being powered from an OPERABLE emergency power source.

APPLICABILITY: MODES 5 and 6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Required boration injection A.1 Suspend all operations involving Immediately subsystem inoperable. positive reactivity additions that could result in loss of required OR SDM or boron concentration.

Required boration injection subsystem not capable of being powered from an OPERABLE emergency power source.

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.

CPSES - UNITS 1 AND 2 - TRM 13.1-3 Revision 82

Boration Injection System - Shutdown TR 13.1.32 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY 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 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of 40°F.

TRS 13.1.32.2 Verify that the temperature of the flow path and boric 7 days acid storage tank solution temperature is greater than or equal to 65°F.

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

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

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

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

TRS 13.1.32.7 Verify a minimum indicated borated water level of 24% 7 days when using the RWST.

TRS 13.1.32.8 For the required flow path, verify that each valve 31 days (manual, power-operated, or automatic) in the flow path that is not locked, sealed, or otherwise secured in position, is in its correct position.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.1-4 Revision 82

Boration Injection System - Shutdown TR 13.1.32 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY TRS 13.1.32.9 Demonstrate the required positive displacement 18 months 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.

TRS 13.1.32.10 Demonstrate the required centrifugal charging pump is In accordance with OPERABLE by verifying, on recirculation flow, that a the Inservice differential pressure across the pump of greater than or Testing Program equal to 2370 psid is developed.

TRS 13.1.32.11 Demonstrate the required safety injection pump is In accordance with operable by verifying, on recirculation flow, the the Inservice requirements of the IST Program are met for developed Testing Program head.

CPSES - UNITS 1 AND 2 - TRM 13.1-5 Revision 82

Rod Group Alignment Limits and Rod Position Indicator TR 13.1.37 13.1 REACTIVITY CONTROL SYSTEMS TR 13.1.37 Rod Group Alignment Limits and Rod Position Indicator TR LCO 13.1.37 The Rod Position Deviation Monitor shall be OPERABLE.

APPLICABILITY: MODES 1 and 2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more rods not within A.1 Enter the applicable Condition(s) Immediately alignment limits. of TS 3.1.4 B. One or more rod position B.1 Enter the applicable Condition(s) Immediately indications inoperable. of TS 3.1.7 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 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 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months limit per Technical Specification SR 3.1.4.1.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.1-6 Revision 82

Rod Group Alignment Limits and Rod Position Indicator TR 13.1.37 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY 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 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 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.

CPSES - UNITS 1 AND 2 - TRM 13.1-7 Revision 82

Control Bank Insertion Limits TR 13.1.38 13.1 REACTIVITY CONTROL SYSTEMS TR 13.1.38 Control Bank Insertion Limits TR LCO 13.1.38 The Control Bank Insertion Limit Monitor shall be OPERABLE.

APPLICABILITY: MODE 1, MODE 2 with keff t 1.0 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Control bank insertion limits A.1 Enter the applicable Condition(s) Immediately not met. of TS 3.1.6.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 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 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months insertion limit by verifying the individual rod positions per Technical Specification SR 3.1.6.2.

CPSES - UNITS 1 AND 2 - TRM 13.1-8 Revision 82

Rod Position Indication - Shutdown TR 13.1.39 13.1 REACTIVITY CONTROL SYSTEMS TR 13.1.39 Rod Position Indication - Shutdown TR LCO 13.1.39 One 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.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Less than the above A.1 Place the Rod Control System in Immediately required rod position a condition incapable of rod indicator(s) OPERABLE. withdrawal.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.1-9 Revision 82

Rod Position Indication - Shutdown TR 13.1.39 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Action and B.1 Action shall be initiated to place 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time of the unit in a lower MODE.

Condition A not met.

AND B.2 Be in MODE 4 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months AND B.3 Be in MODE 5 31 hours3.587963e-4 days 0.00861 hours 5.125661e-5 weeks 1.17955e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.1.39.1 Verify each DRPI agrees within 12 steps of the group Once prior to demand position when the rods are stationary and increasing Keff within 24 steps of the group demand position during rod above 0.95 after motion over the full indicated range of rod travel. each removal of the reactor vessel head.

CPSES - UNITS 1 AND 2 - TRM 13.1-10 Revision 82

Moveable Incore Detection System TR 13.2.31 13.2 POWER DISTRIBUTION LIMITS TR 13.2.31 Moveable Incore Detection System TR LCO 13.2.31 The 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, or

b. Monitoring the QUADRANT POWER TILT RATIO, or N

c. Measurement of F 'H , FQ(Z) and Fxy.

ACTIONS

- NOTE -

TR LCO 13.0.4.c is applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Restore the movable incore Prior to using the system movable incore detection detection system to OPERABLE for the above listed system component(s) status. monitoring and inoperable. calibration functions.

CPSES - UNITS 1 AND 2 - TRM 13.2-1 Revision 79

Moveable Incore Detection System TR 13.2.31 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.2.31.1 Verify Movable Incore Detection System OPERABILITY Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months by irradiating each required detector and determining prior to using the the acceptability of its voltage curve. system for the above listed monitoring and calibration functions.

CPSES - UNITS 1 AND 2 - TRM 13.2-2 Revision 79

Axial Flux Difference TR 13.2.32 13.2 POWER DISTRIBUTION LIMITS TR 13.2.32 Axial Flux Difference (AFD)

TR LCO 13.2.32 The Axial Flux Difference (AFD) Monitor Alarm shall be OPERABLE.

APPLICABILITY: MODE 1 with THERMAL POWER > 50% RTP.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. AFD Monitor Alarm A.1 Perform TRS 13.2.32.1. Immediately inoperable.

CPSES - UNITS 1 AND 2 - TRM 13.2-3 Revision 79

Axial Flux Difference TR 13.2.32 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 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 Once within 30 each OPERABLE excore channel. minutes AND 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months thereafter CPSES - UNITS 1 AND 2 - TRM 13.2-4 Revision 79

QPTR Alarm TR 13.2.33 13.2 POWER DISTRIBUTION LIMITS TR 13.2.33 Quadrant Power Tilt Ratio (QPTR) Alarm TR LCO 13.2.33 The Quadrant Power Tilt Ratio (QPTR) Alarm shall be OPERABLE.

APPLICABILITY: MODE 1 with THERMAL POWER > 50% RATED THERMAL POWER.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. QPTR not within limit. A.1 Enter the applicable Condition(s) Immediately of TS 3.2.4.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 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 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Specification SR 3.2.4.1.

CPSES - UNITS 1 AND 2 - TRM 13.2-5 Revision 79

Power Distribution Monitoring System TR 13.2.34 13.2 POWER DISTRIBUTION LIMITS TR 13.2.34 Power Distribution Monitoring System TR LCO 13.2.34 The 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 System

b. Monitoring the QUADRANT POWER TILT RATIO, or N

c. Measurement of F 'H , FQ(Z) and Fxy.

ACTIONS

- NOTE -

TR LCO 13.0.4.c is applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more PDMS A.1 Restore the required PDMS Prior to using the PDMS components or required components and plant computer for the above listed plant computer inputs inputs to OPERABLE status. monitoring and inoperable. calibration functions.

CPSES - UNITS 1 AND 2 - TRM 13.2-6 Revision 79

Power Distribution Monitoring System TR 13.2.34 SURVEILLANCE REQUIREMENTSS SURVEILLANCE FREQUENCY TRS 13.2.34.1 Perform a CHANNEL CHECK. Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to using the PDMS for the above listed monitoring and calibration functions.

TRS 13.2.34.2 Verify the PDMS has been calibrated within the Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months required frequency. 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 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months within the required frequency. prior to using the PDMS for the above listed monitoring and calibration functions.

TRS 13.2.34.4 Verify CHANNEL FUNCTIONAL TEST has been Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months performed within the required frequency. prior to using the PDMS for the above listed monitoring and calibration functions.

CPSES - UNITS 1 AND 2 - TRM 13.2-7 Revision 79

Power Distribution Monitoring System TR 13.2.34 Table 13.2.34-1 Power Distribution Monitoring System Instrumentation FUNCTION REQUIRED CHANNEL TECHNICAL INPUTS REQUIREMENTS SURVEILLANCE

1. Control Bank Position 4 TRS 13.2.34.1 TRS 13.2.34.4

2. RCS Cold Leg Temperature, 2 TRS 13.2.34.1 Tcold TRS 13.2.34.3

3. Reactor Power Level 1 TRS 13.2.34.1 TRS 13.2.34.3

4. NIS Power Range Excore 6 TRS 13.2.34.1 Detector Section Signals TRS 13.2.34.3

5. Core Exit Thermocouple 13 TRS 13.2.34.1 Temperatures with > 2 per quadrant TRS 13.2.34.3 CPSES - UNITS 1 AND 2 - TRM 13.2-8 Revision 79

RTS Instrumentation Response Times TR 13.3.1 13.3 INSTRUMENTATION TR 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.

CPSES - UNITS 1 AND 2 - TRM 13.3-1 Revision 74

RTS Instrumentation Response Times TR 13.3.1 Table 13.3.1-1 (Page 1 of 2)

Reactor Trip System (RTS) Instrumentation Response Time Limits INITIATION SIGNAL RESPONSE TIME IN SECONDS

1. Manual Reactor Trip N.A.

2. Power Range Neutron Flux

a. High Setpoint d0.5 (1)

b. Low Setpoint d0.5 (1)

3. Power Range Neutron Flux High Positive Rate d.65 (1)

4. Intermediate Range Neutron Flux N.A.

5. Source Range Neutron Flux N.A.

6. Overtemperature N-16 d 3.3 (1,2)

7. Overpower N-16 d 2 (1)

8. Pressurizer Pressure

a. Pressurizer Pressure Low d2

b. Pressurizer Pressure High d2

9. Pressurizer Water Level High N.A.

10. Reactor Coolant Flow Low d 1 (3)

11. Not Used N.A.

12. Undervoltage - Reactor Coolant Pumps d1.1 (4)

(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 d 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 RCP breaker until voltage reaches the undervoltage set-point provides an overall time d 1.5 seconds CPSES - UNITS 1 AND 2 - TRM 13.3-2 Revision 74

RTS Instrumentation Response Times TR 13.3.1 Table 13.3.1-1 (Page 2 of 2)

Reactor Trip System (RTS) Instrumentation Response Time Limits INITIATION SIGNAL RESPONSE TIME IN SECONDS

13. Underfrequency - Reactor Coolant Pumps d 0.6

14. Steam Generator Water Level Low-Low d2

15. Not Used N.A.

16. Turbine Trip

a. Low Fluid Oil Pressure N.A.

b. Turbine Stop Valve Closure N.A.

17. Safety Injection Input from ESFAS N.A.

18. Reactor Trip System Interlocks

a. Intermediate Range Neutron Flux, P-6 N.A.

b. Low Power Reactor Trips Block, P-7 N.A.

c. Power Range Neutron Flux, P-8 N.A.

d. Power Range Neutron Flux, P-9 N.A.

e. Power Range Neutron Flux, P-10 N.A.

f. Turbine First Stage Pressure, P-13 N.A.

19. Reactor Trip Breakers N.A.

20. Reactor Trip Breaker Undervoltage and Shunt Trip N.A.

Mechanisms

21. Automatic Trip Logic N.A.

CPSES - UNITS 1 AND 2 - TRM 13.3-3 Revision 74

ESFAS Instrumentation Response Times TR 13.3.2 13.3 INSTRUMENTATION TR 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.

CPSES - UNITS 1 AND 2 - TRM 13.3-4 Revision 74

ESFAS Instrumentation Response Times TR 13.3.2 Table 13.3.2-1 (Page 1 of 6)

Engineered Safety Features Actuation System Instrumentation Response Time Limits FUNCTIONAL UNIT AND INITIATION SIGNAL RESPONSE TIME IN SECONDS

1. Safety Injection

a. Manual Initiation N.A.

b. Automatic Actuation Logic and Actuation Relays N.A

c. Containment Pressure High 1

1. ECCS d 27 (1,5,8) / 27 (4,6,8)

2. Reactor Trip d2 (15)

3. Containment Ventilation Isolation N.A.

4. Station Service Water N.A.

5. Component Cooling Water N.A.

6. Essential Ventilation Systems N.A.

7. Emergency Diesel Generator Operation d12

8. Control Room Emergency Recirculation N.A.

9. Containment Spray d32 (7)

(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.

CPSES - UNITS 1 AND 2 - TRM 13.3-5 Revision 74

ESFAS Instrumentation Response Times TR 13.3.2 Table 13.3.2-1 (Page 2 of 6)

Engineered Safety Features Actuation System Instrumentation Response Time Limits FUNCTIONAL UNIT AND INITIATION SIGNAL RESPONSE TIME IN SECONDS

1. Safety Injection (continued)

d. Pressurizer Pressure Low

1. ECCS d 27 (1,5,8) / 27 (4,6,8)

2. Reactor Trip d 2 (15)

3. Containment Ventilation Isolation d 5 (16)

4. Station Service Water N.A.

5. Component Cooling Water N.A.

6. Essential Ventilation Systems N.A.

7. Emergency Diesel Generator Operation d12

8. Control Room Emergency Recirculation N.A.

9. Containment Spray N.A.

(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.

CPSES - UNITS 1 AND 2 - TRM 13.3-6 Revision 74

ESFAS Instrumentation Response Times TR 13.3.2 Table 13.3.2-1 (Page 3 of 6)

Engineered Safety Features Actuation System Instrumentation Response Time Limits FUNCTIONAL UNIT AND INITIATION SIGNAL RESPONSE TIME IN SECONDS

1. Safety Injection (continued)

e. Steam Line Pressure Low

1. ECCS d 37 (3,6,8) / 27 (4,6,8)

2. Reactor Trip d 2 (15)

3. Containment Ventilation Isolation N.A.

4. Station Service Water N.A.

5. Component Cooling Water N.A.

6. Essential Ventilation Systems N.A.

7. Emergency Diesel Generator Operation d12

8. Control Room Emergency Recirculation N.A.

9. Containment Spray N.A.

2. Containment Spray

a. Manual Initiation N.A.

b. Automatic Actuation Logic and Actuation Relays N.A.

c. Containment Pressure High 3 d119(9)

(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.

CPSES - UNITS 1 AND 2 - TRM 13.3-7 Revision 74

ESFAS Instrumentation Response Times TR 13.3.2 Table 13.3.2-1 (Page 4 of 6)

Engineered Safety Features Actuation System Instrumentation Response Time Limits FUNCTIONAL UNIT AND INITIATION SIGNAL RESPONSE TIME IN SECONDS

3. Containment Isolation

a. Phase A Isolation

1. Manual Initiation N.A

2. Automatic Actuation Logic and Actuation Relays N.A.

3. Safety Injection d 17 (2,10) / 27 (1,10)

b. Phase B Isolation

1. Manual Initiation N.A.

2. Automatic Actuation Logic and Actuation Relays N.A.

3. Containment Pressure High 3 N.A.

4. Steam Line Isolation

a. Manual Initiation N.A.

b. Automatic Actuation Logic and Actuation Relays N.A.

c. Containment Pressure High 2 d7

d. Steam Line Pressure

1. Steam Line Pressure Low d7

2. Steam Line Pressure Negative Rate High d7 (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.

CPSES - UNITS 1 AND 2 - TRM 13.3-8 Revision 74

ESFAS Instrumentation Response Times TR 13.3.2 Table 13.3.2-1 (Page 5 of 6)

Engineered Safety Features Actuation System Instrumentation Response Time Limits FUNCTIONAL UNIT AND INITIATION SIGNAL RESPONSE TIME IN SECONDS

5. Turbine Trip and Feedwater Isolation

a. Automatic Actuation Logic and Actuation Relays N.A.

b. Steam Generator Water Level High-High, P-14 d 11 (11)

c. Safety Injection d 7 (10,11)

6. Auxiliary Feedwater

a. Automatic Actuation Logic and Actuation Relays N.A.

b. Not Used N.A.

c. Steam Generator Water Level Low-Low d 60 (12) / 85 (13)

d. Safety Injection d 60 (1,10,12)

e. Loss of Offsite Power d 58 (1,14)

f. Not Used N.A.

g. Trip of all Main Feedwater Pumps N.A.

h. Not Used N.A.

(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.

CPSES - UNITS 1 AND 2 - TRM 13.3-9 Revision 74

ESFAS Instrumentation Response Times TR 13.3.2 Table 13.3.2-1 (Page 6 of 6)

Engineered Safety Features Actuation System Instrumentation Response Time Limits FUNCTIONAL UNIT AND INITIATION SIGNAL RESPONSE TIME IN SECONDS

7. Automatic Switchover to Containment Sump

a. Automatic Actuation Logic and Actuation Relays N.A.

b. Refueling Water Storage Tank Level Low-Low d30 Coincident with Safety Injection

8. ESFAS Interlocks

a. Reactor Trip, P-4 N.A.

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

CPSES - UNITS 1 AND 2 - TRM 13.3-10 Revision 74

LOP DG Start Instrumentation Response Times TR 13.3.5 13.3 INSTRUMENTATION TR 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.

CPSES - UNITS 1 AND 2 - TRM 13.3-11 Revision 74

LOP DG Start Instrumentation Response Times TR 13.3.5 Table 13.3.5-1 Loss of Power Diesel Generator Start Instrumentation Response Time Limits INITIATION SIGNAL AND FUNCTION RESPONSE TIME IN SECONDS

1. Automatic Actuation Logic and Actuation Relays N.A.

2. Preferred Offsite Source bus UV d 1(1)

3. Alternate Offsite Source bus UV d 1(1)

4. 6.9 KV Class 1E Bus Undervoltage d 2 (2)

5. 6.9 KV Degraded Voltage ! 6 (5) & d 10 (5, 3) / d 60(4)

6. 480 V Class 1E Bus Low Grid Undervoltage ! 45 (6)

7. 480V Class 1E Bus Degraded Voltage ! 6 (5) & d 10 (5, 3) / d 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.

CPSES - UNITS 1 AND 2 - TRM 13.3-12 Revision 74 (Sup 1)

Seismic Instrumentation TR 13.3.31 13.3 INSTRUMENTATION TR 13.3.31 Seismic Instrumentation TR LCO 13.3.31 The seismic monitoring instrumentation shall be OPERABLE.

APPLICABILITY: At all times ACTIONS

- NOTE -

TR LCO 13.0.4.c is applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A. Seismic monitoring A.1 Restore seismic monitoring 30 days instrument inoperable. instrument to OPERABLE status.

CPSES - UNITS 1 AND 2 - TRM 13.3-13 Revision 74

Seismic Instrumentation TR 13.3.31 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.3.31.1 Perform a CHANNEL CHECK. 31 days TRS 13.3.31.2 Perform a CHANNEL CALIBRATION. 18 months TRS 13.3.31.3 --------------------------------------------------------------------------

- NOTE -

Setpoint verification is not required.

Perform a CHANNEL OPERATIONAL TEST. 184 days CPSES - UNITS 1 AND 2 - TRM 13.3-14 Revision 74

Source Range Neutron Flux TR 13.3.32 13.3 INSTRUMENTATION TR 13.3.32 Source Range Neutron Flux TR LCO 13.3.32 2 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 CONDITION REQUIRED ACTION COMPLETION TIME A. One required Source A.1 Restore channel to OPERABLE 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Range Neutron Flux status.

channel inoperable.

OR A.2 Suspend all operations involving 49 hours5.671296e-4 days 0.0136 hours 8.101852e-5 weeks 1.86445e-5 months positive reactivity changes.

B. Both required Source B.1 Restore one channel to 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Range Neutron Flux OPERABLE status.

channels inoperable.

OR B.2 Suspend all operations involving 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months positive reactivity changes.

CPSES - UNITS 1 AND 2 - TRM 13.3-15 Revision 74

Source Range Neutron Flux TR 13.3.32 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.3.32.1 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 CPSES - UNITS 1 AND 2 - TRM 13.3-16 Revision 74

Turbine Overspeed Protection TR 13.3.33 13.3 INSTRUMENTATION TR 13.3.33 Turbine Overspeed Protection TR LCO 13.3.33 At 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.

CONDITION REQUIRED ACTION COMPLETION TIME A. One stop valve or one A.1 Restore the inoperable valve(s) 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months control valve per high to OPERABLE status.

pressure turbine steam line inoperable. OR A.2 Close at least one valve in the 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months affected steam line(s).

OR A.3 Isolate the turbine from the steam 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months supply.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.3-17 Revision 74

Turbine Overspeed Protection TR 13.3.33 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. One stop valve or one B.1 Restore the inoperable valve(s) 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months control valve per low to OPERABLE status.

pressure turbine steam line inoperable. OR B.2 Close at least one valve in the 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months affected steam line(s).

OR B.3 Isolate the turbine from the steam 78 hours9.027778e-4 days 0.0217 hours 1.289683e-4 weeks 2.9679e-5 months supply.

C. Both Overspeed Protection C.1 Isolate the turbine from the steam 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Sub-systems inoperable. supply.

D. Required Actions and D.1 Initiate action to place the unit in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months associated Completion a lower MODE.

Times not met.

AND D.2 Be in MODE 3. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months AND D.3 Be in MODE 4. 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months CPSES - UNITS 1 AND 2 - TRM 13.3-18 Revision 74

Turbine Overspeed Protection TR 13.3.33 SURVEILLANCE REQUIREMENTS

- NOTE -

The provisions of TRS 13.0.4 are not applicable.

SURVEILLANCE FREQUENCY TRS 13.3.33.1 Test the Turbine Trip Block using the Automatic Turbine 14 days Tester (ATT).

TRS 13.3.33.2 Cycle each of the following valves through at least one 26 weeks 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, and

d. Four low pressure turbine control valves.

TRS 13.3.33.3 Deleted TRS 13.3.33.4 Disassemble at least one high pressure turbine stop 40 months 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.

TRS 13.3.33.5 Visually inspect the disks and accessible portions of the 40 months 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.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.3-19 Revision 74

Turbine Overspeed Protection TR 13.3.33 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY TRS 13.3.33.6 Test the Hardware Overspeed Sub-system 2 of 3 relay 18 months logic and output relays.

CPSES - UNITS 1 AND 2 - TRM 13.3-20 Revision 74

Plant Calorimetric Measurement TR 13.3.34 13.3 INSTRUMENTATION TR 13.3.34 Plant Calorimetric Measurement TR LCO 13.3.34 The Leading Edge Flow Meter (LEFM) shall be used for the completion of SR 3.3.1.2.

APPLICABILITY: MODE 1 > 15% RTP ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. LEFM not available A.1 Restore LEFM to available status Prior to performance of SR 3.3.1.2 B. Required Action or B.1 Ensure THERMAL POWER Prior to performance of Completion Time of d 98.6% RTP. SR 3.3.1.2 Condition A not met AND B.2 Perform SR 3.3.1.2 using As required by feedwater venturis SR 3.3.1.2 AND B.3 Maintain THERMAL POWER Until LEFM is restored to d 98.6% RTP. available status and SR 3.3.1.2 is performed using LEFM.

CPSES - UNITS 1 AND 2 - TRM 13.3-21 Revision 74

Plant Calorimetric Measurement TR 13.3.34 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.3.34.1 Verify availability of LEFM using self-diagnostics Prior to performance of SR 3.3.1.2 CPSES - UNITS 1 AND 2 - TRM 13.3-22 Revision 74

RCS Pressure Isolation Valves TR 13.4.14 13.4 REACTOR COOLANT SYSTEM (RCS)

TR 13.4.14 RCS Pressure Isolation Valves This Technical Requirement contains a listing of the RCS Pressure Isolation Valves (PIVs) subject to Technical Specification 3.4.14.

Table 13.4.14-1 Reactor Coolant System Pressure Isolation Valves VALVE NUMBER FUNCTION 8948 A, B, C, D Accumulator Tank Discharge 8956 A, B, C, D Accumulator Tank Discharge 8905 A, B, C, D SI Hot Leg Injection 8949 A, B, C, D SI Hot Leg Injection 8818 A, B, C, D RHR Cold Leg Injection 8819 A, B, C, D SI Cold Leg Injection 8701 A, B RHR Suction Isolation 8702 A, B RHR Suction Isolation 8841 A, B RHR Hot Leg Injection 8815 CCP Cold Leg Injection 8900 A, B, C, D CCP Cold Leg Injection CPSES - UNITS 1 AND 2 - TRM 13.4-1 Revision 56

Loose Part Detection System TR 13.4.31 13.4 REACTOR COOLANT SYSTEM TR 13.4.31 Loose Part Detection System TR LCO 13.4.31 The Loose-Part Detection System shall be OPERABLE.

APPLICABILITY: MODES 1 and 2 ACTIONS

- NOTE -

TR LCO 13.0.4.c is applicable.

CONDITION REQUIRED ACTION COMPLETION TIME A. With one or more required A.1 Restore required channels to 30 days Loose-Part Detection Operable status.

System channels inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.4.31.1 Perform a CHANNEL CHECK. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months TRS 13.4.31.2 -------------------------------------------------------------------------

- NOTE -

Setpoint verification is not required.

Perform a CHANNEL OPERATIONAL TEST. 31 days TRS 13.4.31.3 Perform a CHANNEL CALIBRATION. 18 months CPSES - UNITS 1 AND 2 - TRM 13.4-2 Revision 56

RCS Chemistry TR 13.4.33 13.4 REACTOR COOLANT SYSTEM TR 13.4.33 Reactor Coolant System (RCS) Chemistry TR LCO 13.4.33 The Reactor Coolant System chemistry shall be maintained within the limits specified in Table 13.4.33-1.

APPLICABILITY: At all times.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME

- NOTE -

Only applicable in MODES 1, 2, 3 and 4.

A. One or more chemistry A.1 Restore parameter to within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months parameters in excess of its Steady-State limit.

Steady-State Limit but within its Transient Limit.

- NOTE -

Only applicable in MODES 1, 2, 3 and 4.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Time of Condition A not AND met.

B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months OR One or more chemistry parameters in excess of its Transient Limit.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.4-3 Revision 56

RCS Chemistry TR 13.4.33 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME

- NOTE -

Applicable in all conditions other than MODES 1, 2, 3 and 4.

C. Concentration of chloride C.1 Restore concentration of chloride 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or floride in the RCS in and floride to within its Steady-excess of its Steady-State State limit.

Limit.

- 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 D.1 Initiate action to reduce the Immediately associated Completion pressurizer pressure to d 500 Time of Condition C not psig.

met.

AND OR D.2 Perform an engineering Prior to increasing the Concentration of chloride or evaluation to determine the pressurizer pressure fluoride in the RCS in effects of the out-of-limit condition > 500 psig.

excess of its Transient on the structural integrity of the Limit. RCS; determine that the RCS AND remains acceptable for continued operation. Prior to proceeding to MODE 4.

CPSES - UNITS 1 AND 2 - TRM 13.4-4 Revision 56

RCS Chemistry TR 13.4.33 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.4.33.1 --------------------------------------------------------------------------

- NOTES -

1. Not required to be performed for dissolved oxygen when Tavg d 250°F.

2. Not required to be met for Chloride and Fluoride until 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after entry into MODE 6 from a defueled state.

Verify the RCS chemistry within the limits by analysis of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months parameter specified in Table 13.4.33-1.

CPSES - UNITS 1 AND 2 - TRM 13.4-5 Revision 56

RCS Chemistry TR 13.4.33 Table 13.4.33-1 Reactor Coolant System Chemistry Limits STEADY-STATE TRANSIENT PARAMETER LIMIT LIMIT Dissolved Oxygen (a) d 0.10 ppm d1.00 ppm Chloride (b) d 0.15 ppm d1.50 ppm Fluoride (b) d 0.15 ppm d1.50 ppm (a) Limit not applicable with Tavg less than or equal to 250 °F.

(b) Limit not applicable when Reactor Coolant System is defueled.

CPSES - UNITS 1 AND 2 - TRM 13.4-6 Revision 56

Pressurizer TR 13.4.34 13.4 REACTOR COOLANT SYSTEM TR 13.4.34 Pressurizer TR LCO 13.4.34 The pressurizer temperature shall be limited to:

a. A maximum heatup of 100°F in any 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period, and

b. A maximum cooldown of 200°F in any 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period.

APPLICABILITY: At all times.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. ------------------------------------ A.1 Restore pressurizer temperature 30 minutes

- NOTE - to within limits.

All Required Actions must be completed whenever AND this Condition is entered.

A.2 Perform an engineering As assigned by the Shift evaluation to determine that the Manager, commensurate Pressurizer temperature in effects of the out-of-limit condition with safety.

excess of the required on the structural integrity of the limits. pressurizer remains acceptable for continued operation.

B. Required Actions and B.1 Be in at least MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Times of Condition A not AND met.

B.2 Reduce pressurizer pressure to 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months

< 500 psig.

C. Required Actions and C.1 Be in MODE 4. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Times of Condition B not AND met.

C.2 Be in MODE 5. 30 hours3.472222e-4 days 0.00833 hours 4.960317e-5 weeks 1.1415e-5 months CPSES - UNITS 1 AND 2 - TRM 13.4-7 Revision 56

Pressurizer TR 13.4.34 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.4.34.1 ------------------------------------------------------------------------

- NOTE -

Only required to be performed during system heatup and cooldown.

Verify the pressurizer temperatures to be within the 30 minutes limits.

CPSES - UNITS 1 AND 2 - TRM 13.4-8 Revision 56

RCS Vents TR 13.4.35 13.4 REACTOR COOLANT SYSTEM TR 13.4.35 Reactor Coolant System (RCS) Vent Specification TR LCO 13.4.35 At 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.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One Reactor Coolant A.1 Close the inoperable vent path Immediately System vent path and remove power from the valve inoperable. actuators of all the vent valves in the inoperable vent path.

AND A.2 Restore the inoperable vent path 30 days to OPERABLE status.

B. Both Reactor Coolant B.1 Close the inoperable vent paths Immediately System vent paths and remove power from the valve inoperable. actuators of all the vent valves in the inoperable vent paths.

AND B.2 Restore at least one of the vent 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months paths to OPERABLE status.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.4-9 Revision 56

RCS Vents TR 13.4.35 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required Actions and C.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Times of Condition A or B AND not met.

C.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.4.35.1 Verify all manual isolation valves in each vent path are 18 months locked in the open position.

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

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

CPSES - UNITS 1 AND 2 - TRM 13.4-10 Revision 56

ECCS - Containment Debris TR 13.5.31 13.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

TR 13.5.31 ECCS - Containment Debris TR LCO 13.5.31 Pursuant 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 CONDITION REQUIRED ACTION COMPLETION TIME A. Loose debris left in A.1 Enter the applicable Condition(s) Immediately containment which could of TS 3.5.2 or 3.5.3 for affected restrict, during a LOCA, the ECCS train(s) inoperable.

pump suctions for the ECCS train(s) required to be OPERABLE.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 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 Once prior to containment to verify that no loose debris (rags, trash, entering MODE 4 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.

CPSES - UNITS 1 AND 2 - TRM 13.5-1 Revision 56

ECCS - Containment Debris TR 13.5.31 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY 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 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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.

CPSES - UNITS 1 AND 2 - TRM 13.5-2 Revision 56

ECCS - Pump Line Flow Rates TR 13.5.32 13.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

TR 13.5.32 ECCS - Pump Line Flow Rates TR LCO 13.5.32 Pursuant 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.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Pump lines for the ECCS A.1 Enter the applicable Condition(s) Immediately train(s) required to be of TS 3.5.2 and 3.5.3 for affected OPERABLE do not meet ECCS train(s) inoperable.

required flow rates.

CPSES - UNITS 1 AND 2 - TRM 13.5-3 Revision 56

ECCS - Pump Line Flow Rates TR 13.5.32 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.5.32.1 Performing a flow balance test, during shutdown, and Once following verify that: completion of modifications to the

a. For centrifugal charging pump lines, with a ECCS subsystems single pump running: that alter the subsystem flow

1. The sum of the injection line flow rates, characteristics.

excluding the highest flow rate, is t 245 gpm, and

2. The total pump flow rate is d560 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 t 400 gpm, and

2. The total pump flow rate is d 675 gpm.

c. For RHR pump lines, with a single pump running, the sum of the cold leg injection line flow rates is t 4652 gpm.

CPSES - UNITS 1 AND 2 - TRM 13.5-4 Revision 56

Containment Isolation Valves TR 13.6.3 13.6 CONTAINMENT SYSTEMS TR 13.6.3 Containment Isolation Valves This 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.

CPSES - UNITS 1 AND 2 - TRM 13.6-1 Revision 70

Containment Isolation Valves TR 13.6.3 Table 13.6.3-1 (Page 1 of 12)

Containment Isolation Valves MAXIMUM FSAR TABLE ISOLATION NOTES AND REFERENCE TIME LEAK TEST VALVE NO. NO.* LINE OR SERVICE (SECONDS) REQUIREMENTS

1. Phase A Isolation Valves HV-2154 20 Feedwater Sample (FW to Stm Gen #1) 5 N.A., Note 9 HV-2155 22 Feedwater Sample (FW to Stm Gen #2) 5 N.A., Note 9 HV-2399 27 Blowdown From Steam Generator #3 5 N.A.

HV-2398 28 Blowdown From Steam Generator #2 5 N.A.

HV-2397 29 Blowdown From Steam Generator #1 5 N.A.

HV-2400 30 Blowdown From Steam Generator #4 5 N.A 8152 32 Letdow Line to Letdown Heat Exchanger 10 C 8160 32 Letdow Line to Letdown Heat Exchanger 10 C 8890A 35 RHR to Cold Leg Loops #1 & #2 Test Line 15 N.A.

8890B 36 RHR to Cold Leg Loops #3 & #4 Test Line 15 N.A.

8047 41 Reactor Makeup Water to Pressure Relief Tank & RC 10 C Pump Stand Pipe 8843 42 SI to RC System Cold Leg Loops #1, #2, #3, & #4 Test 10 N.A.

Line 8881 43 SI to RC System Hot Leg Loops #2 & #3 Test Line 10 N.A.

8824 44 SI to RC System Hot Leg Loops #1 & #4 Test Line 10 N.A.

8823 45 SI to RC System Cold Leg Loops #1, #2, #3, & #4 Test 10 N.A.

Line 8100 51 Seal Water Return and Excess Letdown 10 C 8112 51 Seal Water Return and Excess Letdown 10 C 7136 52 RCDT Heat Exchanger to Waste Hold up Tank 10 C LCV-1003 52 RCDT Heat Exchanger to Waste Hold up Tank 10 C HV-5365 60 Demineralized Water Supply 10 C HV-5366 60 Demineralized Water Supply 10 C HV-5157 61 Containment Sump Pump Discharge 5 C HV-5158 61 Containment Sump Pump 5 C CPSES - UNITS 1 AND 2 - TRM 13.6-2 Revision 70

Containment Isolation Valves TR 13.6.3 Table 13.6.3-1 (Page 2 of 12)

Containment Isolation Valves MAXIMUM FSAR TABLE ISOLATION NOTES AND REFERENCE TIME LEAK TEST VALVE NO. NO.* LINE OR SERVICE (SECONDS) REQUIREMENTS HV-3487 62 Instrument Air to Containment 5 C 8825 63 RHR to Hot Leg Loops #2 & #3 Test Line 15 N.A.

HV-2405 73 Sample from Steam Generator #1 5 N.A.

HV-4170 74 RC Sample from Hot Legs 5 C HV-4168 74 RC Sample from Hot Leg #1 5 C HV-4169 74 RC Sample from Hot Leg #4 5 C HV-2406 76 Sample from Steam Generator #2 5 N.A.

HV-4167 77 Pressurizer Liquid Space Sample 5 C HV-4166 77 Pressurizer Liquid Space Sample 5 C HV-4176 78 Pressurizer Steam Space Sample 5 C HV-4165 78 Pressurizer Steam Space Sample 5 C HV-2407 79 Sample from Steam Generator #3 5 N.A.

HV-4175 80 Accumulators 5 C HV-4171 80 Sample From Accumulator #1 5 C HV-4172 80 Sample From Accumulator #2 5 C HV-4173 80 Sample From Accumulator #3 5 C HV-4174 80 Sample From Accumulator #4 5 C HV-7311 81 RC PASS Sample Discharge to RCDT 5 C HV-7312 81 RC PASS Sample Discharge to RCDT 5 C HV-2408 82 Sample from Steam Generator #4 5 N.A.

8871 83 Accumulator Test and Fill 10 C 8888 83 Accumulator Test and Fill 10 C 8964 83 Accumulator Test and Fill 10 C HV-5556 84 Containment Air PASS Return 5 C HV-5557 84 Containment Air PASS Return 5 C HV-5544 94 Radiation Monitoring Sample 5 C HV-5545 94 Radiation Monitoring Sample 5 C CPSES - UNITS 1 AND 2 - TRM 13.6-3 Revision 70

Containment Isolation Valves TR 13.6.3 Table 13.6.3-1 (Page 2 of 12)

Containment Isolation Valves MAXIMUM FSAR TABLE ISOLATION NOTES AND REFERENCE TIME LEAK TEST VALVE NO. NO.* LINE OR SERVICE (SECONDS) REQUIREMENTS HV-5558 97 Containment Air PASS Inlet 5 C HV-5559 97 Containment Air PASS Inlet 5 C HV-5560 100 Containment Air PASS Inlet 5 C HV-5561 100 Containment Air PASS Inlet 5 C HV-5546 102 Radiation Monitoring Sample Return 5 C HV-5547 102 Radiation Monitoring Sample Return 5 C 8880 104 N2 Supply to Accumulators 10 C 7126 105 H2 Supply to RC Drain Tank 10 C 7150 105 H2 Supply to RC Drain Tank 10 C HV-4710 111 CCW Supply to Excess Letdown & RC Drain Tank 5 N.A.

Heat Exchanger HV-4711 112 CCW Return to Excess Letdown & RC Drain Tank Heat 5 N.A.

Exchanger HV-3486 113 Service Air to Containment 5 C HV-4725 114 Containment CCW Drain Tank Pumps Discharge 10 C HV-4726 114 Containment CCW Drain Tank Pumps Discharge 10 C 8027 116 Nitrogen Supply to PRT 10 C 8026 116 Nitrogen Supply to PRT 10 C HV-6084 120 Chilled Water Supply to Containment Coolers 15 C HV-6082 121 Chilled Water Return to Containment Coolers 15 C HV-6083 121 Chilled Water Return to Containment Coolers 15 C HV-4075B 124 Fire Protection System Isolation 10 C HV-4075C 124 Fire Protection System Isolation 10 C

2. Phase B Isolation Valves HV-4708 117 CCW Return From RCPs Motors 30 C HV-4701 117 CCW Return From RCPs Motors 30 C HV-4700 118 CCW Supply To RCPs Motors 30 C CPSES - UNITS 1 AND 2 - TRM 13.6-4 Revision 70

Containment Isolation Valves TR 13.6.3 Table 13.6.3-1 (Page 2 of 12)

Containment Isolation Valves MAXIMUM FSAR TABLE ISOLATION NOTES AND REFERENCE TIME LEAK TEST VALVE NO. NO.* LINE OR SERVICE (SECONDS) REQUIREMENTS HV-4709 119 CCW Return From RCPs Thermal Barrier 15 C HV-4696 119 CCW Return From RCPs Thermal Barrier 15 C

3. Containment Ventilation Isolation Valves HV-5542 58 Hydrogen Purge Supply N.A. C HV-5543 58 Hydrogen Purge Supply N.A. C HV-5563 58 Hydrogen Purge Supply N.A. C HV-5540 59 Hydrogen Purge Exhaust N.A. C HV-5541 59 Hydrogen Purge Exhaust N.A. C HV-5562 59 Hydrogen Purge Exhaust N.A. C HV-5536 109 Containment Purge Air Supply N.A. C HV-5537 109 Containment Purge Air Supply N.A. C HV-5538 110 Containment Purge Air Exhaust N.A. C HV-5539 110 Containment Purge Air Exhaust N.A. C HV-5548 122 Containment Pressure Relief 5 C Note 8 HV-5549 122 Containment Pressure Relief 5 C Note 8

4. Manual Valves MS-711# 4a TDAFW Pump Bypass Warm-up Valve N.A. N.A.

MS-390 5a N2 Supply to Steam Generator #1 N.A. N.A.

MS-387 9a N2 Supply to Steam Generator #2 N.A. N.A.

MS-384 13a N2 Supply to Steam Generator #3 N.A. N.A.

MS-712# 17a TDAFW Pump Bypass Warm-up Valve N.A. N.A.

MS-393 18a N2 Supply to Steam Generator #4 N.A. N.A.

FW-116 20 Feedwater Sample (FW to Stm Gen #1) N.A. N.A., Note 9 FW-113 22 Feedwater Sample (FW to Stm Gen #2) N.A. N.A., Note 9 FW-106 20b N2 Supply to Steam Generator #1 N.A. N.A.

CPSES - UNITS 1 AND 2 - TRM 13.6-5 Revision 70

Containment Isolation Valves TR 13.6.3 Table 13.6.3-1 (Page 2 of 12)

Containment Isolation Valves MAXIMUM FSAR TABLE ISOLATION NOTES AND REFERENCE TIME LEAK TEST VALVE NO. NO.* LINE OR SERVICE (SECONDS) REQUIREMENTS FW-104 22b N2 Supply to Steam Generator #2 N.A. N.A.

FW-102 24b N2 Supply to Steam Generator #3 N.A. N.A.

FW-108 26b N2 Supply to Steam Generator #4 N.A. N.A.

7135# 52 RCDT Heat Exchanger to Waste Holdup Tank N.A. C MS-101 4 TDAFWP Steam Supply N.A. N.A.

MS-128 17 TDAFWP Steam Supply N.A. N.A.

SF-011 56 Refueling Water Purification to Refueling Cavity N.A. C SF-012 56 Refueling Water Purification to Refueling Cavity N.A. C SF-021 67 Refueling Cavity to Refueling Water Purification N.A. C SF-022 67 Refueling Cavity to Refueling Water Purification N.A. C 1SF-053 71 Refueling Cavity Skimmer Pump Discharge N.A. C 2SF-0055 1SF-054 71 Refueling Cavity Skimmer Pump Discharge N.A. C 2SF-0056 SI-8961# 83 Accumulator Test and Fill N.A. N.A.

HV-2333B# 2 MSIV Bypass from Steam Generator #1 N.A. Note 1 HV-2334B# 7 MSIV Bypass from Steam Generator #2 N.A. Note 1 HV-2335B# 11 MSIV Bypass from Steam Generator #3 N.A. Note 1 HV-2336B# 15 MSIV Bypass from Steam Generator #4 N.A. Note 1 1BS-0016# 130 Airlock Hydraulic System N.A. N.A.

1BS-0017# 130 Airlock Hydraulic System N.A. N.A.

1BS-0030# 131 Airlock Hydraulically Operated Equalization N.A. Notes 5, 6, 7 1BS-0025# 131 Airlock Hydraulically Operated Equalization N.A. Notes 5, 6, 7 1BS-0056# 131a Airlock Manual Equalization N.A. Notes 5, 6 1BS-0044# 131a Airlock Manual Equalization N.A. Notes 5, 6 1BS-0029# 131a Airlock Manual Equalization N.A. Notes 5, 6 1BS-0015# 131a Airlock Manual Equalization N.A. Notes 5, 6 CPSES - UNITS 1 AND 2 - TRM 13.6-6 Revision 70

Containment Isolation Valves TR 13.6.3 Table 13.6.3-1 (Page 2 of 12)

Containment Isolation Valves MAXIMUM FSAR TABLE ISOLATION NOTES AND REFERENCE TIME LEAK TEST VALVE NO. NO.* LINE OR SERVICE (SECONDS) REQUIREMENTS BS-0202# 132 Airlock Manual Equalization N.A. Notes 5, 6, 7 BS-0203# 132 Airlock Manual Equalization N.A. Notes 5, 6, 7 2BS-0016# 133 Airlock Hydraulic System N.A. Notes 5, 6 2BS-0017# 133 Airlock Hydraulic System N.A. Notes 5, 6 2BS-0039# 133 Airlock Hydraulic System N.A. Notes 5, 6 2BS-0040# 133 Airlock Hydraulic System N.A. Notes 5, 6 2BS-0030# 134 Airlock Hydraulically Operated Equalization N.A. Notes 5, 6, 7 2BS-0025# 134 Airlock Hydraulically Operated Equalization N.A. Notes 5, 6, 7 2BS-0056# 134a Airlock Manual Equalization N.A. Notes 5, 6 2BS-0044# 134a Airlock Manual Equalization N.A. Notes 5, 6 2BS-0029# 134a Airlock Manual Equalization N.A. Notes 5, 6 2BS-0015# 134a Airlock Manual Equalization N.A. Notes 5, 6

5. Power-Operated Isolation Valves HV-2452-1 4 Main Steam to Aux. FPT From Steam Line # 4 N.A. N.A PV-2325 5 Atmospheric Relief Steam Generator N.A. Note 3 PV-2326 9 Atmospheric Relief Steam Generator N.A. Note 3 PV-2327 13 Atmospheric Relief Steam Generator N.A. Note 3 HV-2452-2 17 Main Steam to Aux. FPT From Steam Line # 1 N.A. N.A.

PV-2328 18 Atmospheric Relief Steam Generator N.A. Note 3 HV-2491A 20a Auxiliary Feedwater to Steam Generator #1 N.A. N.A.

HV-2491B 20a Auxiliary Feedwater to Steam Generator #1 N.A. N.A.

HV-2492A 22a Auxiliary Feedwater to Steam Generator #2 N.A. N.A.

HV-2492B 22a Auxiliary Feedwater to Steam Generator #2 N.A. N.A.

HV-2493A 24a Auxiliary Feedwater to Steam Generator #3 N.A. N.A.

HV-2493B 24a Auxiliary Feedwater to Steam Generator #3 N.A. N.A.

HV-2494A 26a Auxiliary Feedwater to Steam Generator #4 N.A. N.A.

HV-2494B 26a Auxiliary Feedwater to Steam Generator #4 N.A. N.A.

CPSES - UNITS 1 AND 2 - TRM 13.6-7 Revision 70

Containment Isolation Valves TR 13.6.3 Table 13.6.3-1 (Page 2 of 12)

Containment Isolation Valves MAXIMUM FSAR TABLE ISOLATION NOTES AND REFERENCE TIME LEAK TEST VALVE NO. NO.* LINE OR SERVICE (SECONDS) REQUIREMENTS 8701B 33 RHR From Hot Leg Loop #4 N.A. N.A.

8701A 34 RHR From Hot Leg Loop #1 N.A. N.A.

8809A 35 RHR From Cold Leg Loops #1 and #2 N.A. N.A.

8809B 36 RHR From Cold Leg Loops #3 and #4 N.A. N.A.

8801A 42 Safety Injection to Cold Leg Loops #1, #2, #3, and #4 N.A. N.A.

8801B 42 Safety Injection to Cold Leg Loops #1, #2, #3, and #4 N.A. N.A.

8802A 43 SI Injection to RCS Hot Leg Loops #2 and #3 N.A. N.A.

8802B 44 SI Injection to RCS Hot Leg Loops #1 and #4 N.A. N.A.

8835 45 SI Injection to RCS Cold Leg Loops #1, #2, #3, and #4 N.A. N.A.

8351A 47 Seal Injection to RC Pump (Loop #1) N.A. N.A.

8351B 48 Seal Injection to RC Pump (Loop #2) N.A. N.A.

8351C 49 Seal Injection to RC Pump (Loop #3) N.A. N.A.

8351D 50 Seal Injection to RC Pump (Loop #4) N.A. N.A.

HV-4777 54 Containment Spray to Spray Header (Train B) N.A. N.A.

HV-4776 55 Containment Spray to Spray Header (Train A) N.A. N.A.

8840 63 RHR to Hot Leg Loops #2 and #3 N.A. N.A.

8811A 125 Containment Recirc. Sump to RHR Pumps (Train A) N.A. N.A.

8811B 126 Containment Recirc. Sump to RHR Pumps (Train B) N.A. N.A.

HV-4782 127 Containment Recirc. to Spray Pumps (Train A) N.A. N.A.

HV-4783 128 Containment Recirc. to Spray Pumps (Train B) N.A. N.A.

6. Check Valves 8818A 35 RHR to Cold Leg Loop #1 N.A. N.A.

8818B 35 RHR to Cold Leg Loop #2 N.A. N.A.

8818C 36 RHR to Cold Leg Loop #3 N.A. N.A.

8818D 36 RHR to Cold Leg Loop #4 N.A. N.A.

8046 41 Reactor Makeup Water to Pressurizer Relief Tank and N.A. C RC Pump Stand Pipe CPSES - UNITS 1 AND 2 - TRM 13.6-8 Revision 70

Containment Isolation Valves TR 13.6.3 Table 13.6.3-1 (Page 2 of 12)

Containment Isolation Valves MAXIMUM FSAR TABLE ISOLATION NOTES AND REFERENCE TIME LEAK TEST VALVE NO. NO.* LINE OR SERVICE (SECONDS) REQUIREMENTS 8815 42 High Head Safety Injection to Cold Leg Loops #1, #2, N.A. N.A.

3, and #4 SI-8905B 43 SI to RC System Hot Leg Loop #2 N.A. N.A.

SI-8905C 43 SI to RC System Hot Leg Loop #3 N.A. N.A.

SI-8905A 44 SI to RC System Hot Leg Loop #1 N.A. N.A.

SI-8905D 44 SI to RC System Hot Leg Loop #4 N.A. N.A.

SI-8819A 45 SI to RC System Cold Leg Loop #1 N.A. N.A.

SI-8819B 45 SI to RC System Cold Leg Loop #2 N.A. N.A.

SI-8819C 45 SI to RC System Cold Leg Loop #3 N.A. N.A.

SI-8819D 45 SI to RC System Cold Leg Loop #4 N.A. N.A.

8381 46 Charging Line to Regenerative Heat Exchanger N.A. C CS-8368A 47 Seal Injection to RC Pump (Loop #1) N.A. N.A.

CS-8368B 48 Seal Injection to RC Pump (Loop #2) N.A. N.A.

CS-8368C 49 Seal Injection to RC Pump (Loop #3) N.A. N.A.

CS-8368D 50 Seal Injection to RC Pump (Loop #4) N.A. N.A.

CS-8180 51 Seal Water Return and Excess Letdown N.A. C CT-145 54 Containment Spray to Spray Header (Tr. B) N.A. N.A.

CT-142 55 Containment Spray to Spray Header (Tr. A) N.A. N.A.

CI-030 62 Instrument Air to Containment N.A. C 8841A 63 RHR to Hot Leg Loop #2 N.A. N.A.

8841B 63 RHR to Hot Leg Loop #3 N.A. N.A.

SI-8968 104 N2 Supply to Accumulators N.A. C CA-016 113 Service Air to Containment N.A. C CC-629 117 CC Return From RCPs Motors N.A. C CC-713 118 CC Supply to RCPs Motors N.A. C CC-831 119 CC Return From RCPs Thermal Barrier N.A. C CH-024 120 Chilled Water Supply to Containment Coolers N.A. C CPSES - UNITS 1 AND 2 - TRM 13.6-9 Revision 70

Containment Isolation Valves TR 13.6.3 Table 13.6.3-1 (Page 2 of 12)

Containment Isolation Valves MAXIMUM FSAR TABLE ISOLATION NOTES AND REFERENCE TIME LEAK TEST VALVE NO. NO.* LINE OR SERVICE (SECONDS) REQUIREMENTS

7. Steam Line Isolation Signal HV-2333A 1 Main Steam From Steam Generator #1 5 Notes 2 & 3 HV-2409 3 Drain From Main Steam Line #1 5 N.A.

HV-2334A 6 Main Steam From Steam Generator #2 5 Notes 2 & 3 HV-2410 8 Drain From Main Steam Line #2 5 N.A.

HV-2335A 10 Main Steam From Steam Generator #3 5 Notes 2 & 3 HV-2411 12 Drain From Main Steam Line #3 5 N.A.

HV-2336A 14 Main Steam From Steam Generator #4 5 Notes 2 & 3 HV-2412 16 Drain From Main Steam Line #4 5 N.A.

8. Feedwater Isolation Signal HV-2134 19 Feedwater to Steam Generator #1 5 Note 3 2-FV-2193 20c Feedwater Preheat Bypass Line S.G. #1 5 Note 3 HV- 2185 20d Feedwater Bypass Line S.G #1 5 Note 3 HV-2135 21 Feedwater to Steam Generator #2 5 Note 3 2-FV-2194 22c Feedwater Preheat Bypass Line S.G. #2 5 Note 3 HV-2186 22d Feedwater Bypass Line S.G #2 5 Note 3 HV-2136 23 Feedwater to Steam Generator #3 5 Note 3 2-FV-2195 24c Feedwater Preheat Bypass Line S.G. #3 5 Note 3 HV-2187 24d Feedwater Bypass Line S.G #3 5 Note 3 HV-2137 25 Feedwater to Steam Generator #4 5 Note 3 2-FV-2196 26c Feedwater Preheat Bypass Line S.G. #4 5 Note 3 HV-2188 26d Feedwater Bypass Line S.G #4 5 Note 3

9. Safety Injection Actuation Isolation 8105 46 Charging Line to Regenerative Heat Exchanger 10 C

10. Relief Valves 8708B 33 RHR From Hot Leg Loop #4 N.A. N.A.

8708A 34 RHR From Hot Leg Loop #1 N.A. N.A.

CPSES - UNITS 1 AND 2 - TRM 13.6-10 Revision 70

Containment Isolation Valves TR 13.6.3 Table 13.6.3-1 (Page 2 of 12)

Containment Isolation Valves MAXIMUM FSAR TABLE ISOLATION NOTES AND REFERENCE TIME LEAK TEST VALVE NO. NO.* LINE OR SERVICE (SECONDS) REQUIREMENTS MS-021 5b Main Steam Safety Valve S.G. #1 N.A. Note 3 MS-022 5b Main Steam Safety Valve S.G. #1 N.A. Note 3 MS-023 5b Main Steam Safety Valve S.G. #1 N.A. Note 3 MS-024 5b Main Steam Safety Valve S.G. #1 N.A. Note 3 MS-025 5b Main Steam Safety Valve S.G. #1 N.A. Note 3 MS-058 9b Main Steam Safety Valve S.G. #2 N.A. Note 3 MS-059 9b Main Steam Safety Valve S.G. #2 N.A. Note 3 MS-060 9b Main Steam Safety Valve S.G. #2 N.A. Note 3 MS-061 9b Main Steam Safety Valve S.G. #2 N.A. Note 3 MS-062 9b Main Steam Safety Valve S.G. #2 N.A. Note 3 MS-093 13b Main Steam Safety Valve S.G. #3 N.A. Note 3 MS-094 13b Main Steam Safety Valve S.G. #3 N.A. Note 3 MS-095 13b Main Steam Safety Valve S.G. #3 N.A. Note 3 MS-096 13b Main Steam Safety Valve S.G. #3 N.A. Note 3 MS-097 13b Main Steam Safety Valve S.G. #3 N.A. Note 3 MS-129 18b Main Steam Safety Valve S.G. #4 N.A. Note 3 MS-130 18b Main Steam Safety Valve S.G. #4 N.A. Note 3 MS-131 18b Main Steam Safety Valve S.G. #4 N.A. Note 3 MS-132 18b Main Steam Safety Valve S.G. #4 N.A. Note 3 MS-133 18b Main Steam Safety Valve S.G. #4 N.A. Note 3 RC-036 41a Penetration Thermal Relief N.A. C WP-7176 52a Penetration Thermal Relief N.A. C DD-430 60a Penetration Thermal Relief N.A. C 1VD-907 61a Penetration Thermal Relief N.A. C 2VD-896 PS-503 74a Penetration Thermal Relief N.A. C PS-501 77a Penetration Thermal Relief N.A. C CPSES - UNITS 1 AND 2 - TRM 13.6-11 Revision 70

Containment Isolation Valves TR 13.6.3 Table 13.6.3-1 (Page 2 of 12)

Containment Isolation Valves MAXIMUM FSAR TABLE ISOLATION NOTES AND REFERENCE TIME LEAK TEST VALVE NO. NO.* LINE OR SERVICE (SECONDS) REQUIREMENTS PS-502 78a Penetration Thermal Relief N.A. C PS-500 80a Penetration Thermal Relief N.A. C WP-7177 81a Penetration Thermal Relief N.A. C 1SI-8972 83a Penetration Thermal Relief N.A. C 2SI-8983 1CC-1067 114a Penetration Thermal Relief N.A. C 2CC-1090 1CH-0271 120a Penetration Thermal Relief N.A. C 2CH-0281 1CH-0272 121a Penetration Thermal Relief N.A. C 2CH-0282 SI-0182 125 Pressure Relief for Bonnet of MOV 8811A N.A. N.A.

SI-0183 126 Pressure Relief for Bonnet of MOV 8811B N.A. N.A.

CT-0309 127 Pressure Relief for Bonnet of MOV HV-4782 N.A. N.A.

CT-0310 128 Pressure Relief for Bonnet of MOV HV-4783 N.A. N.A.

CPSES - UNITS 1 AND 2 - TRM 13.6-12 Revision 70

Containment Isolation Valves TR 13.6.3 Table 13.6.3-1 (Page 12 of 12)

Containment Isolation Valves MAXIMUM FSAR TABLE ISOLATION NOTES AND REFERENCE TIME LEAK TEST VALVE NO. NO.* LINE OR SERVICE (SECONDS) REQUIREMENTS Table 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 Specification 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.

CPSES - UNITS 1 AND 2 - TRM 13.6-13 Revision 70

Containment Spray System TR 13.6.6 13.6 CONTAINMENT SYSTEMS TR 13.6.6 Containment Spray System The 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.

CPSES - UNITS 1 AND 2 - TRM 13.6-14 Revision 70

Spray Additive System TR 13.6.7 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 REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.6.7.1 Verify each spray additive manual, power operated, and 31 days automatic valve in the flow path that is not locked, sealed, or otherwise secured in position is in the correct position.

TRS 13.6.7.2 Verify spray additive tank solution level is > 91% and 184 days

< 94%.

TRS 13.6.7.3 Verify spray additive tank NaOH solution concentration 184 days is > 28% and < 30% by weight.

TRS 13.6.7.4 Verify each spray additive automatic valve in the flow 18 months path that is not locked, sealed, or otherwise secured in position, actuates to the correct position on an actual or simulated actuation signal.

TRS 13.6.7.5 Verify spray additive flow from each solutions flow 5 years path.

CPSES - UNITS 1 AND 2 - TRM 13.6-15 Revision 70

MSIVs TR 13.7.2 13.7 PLANT SYSTEMS TR 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 Valves VALVE NUMBER ISOLATION TIME (SECONDS)

HV-2333A d5 HV-2334A d5 HV-2335A d5 HV-2336A d5 CPSES - UNITS 1 AND 2 - TRM 13.7-1 Revision 83

FIVs and FCVs and Associated Bypass Valves TR 13.7.3 13.7 PLANT SYSTEMS TR 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 13.7.3-1 Feedwater Isolation Valves and Feedwater Control Valves and Associated Bypass Valves VALVE NUMBER ISOLATION TIME (SECONDS)

HV-2134 d5 HV-2135 d5 HV-2136 d5 HV-2137 d5 HV-2185 d5 HV-2186 d5 HV-2187 d5 HV-2188 d5 FCV-0510 d5 FCV-0520 d5 FCV-0530 d5 FCV-0540 d5 LV-2162 d5 LV-2163 d5 LV-2164 d5 LV-2165 d5 CPSES - UNITS 1 AND 2 - TRM 13.7-2 Revision 83

ARV - Air Accumulator Tank TR 13.7.4 TR 13.7.4 PLANT SYSTEMS TR 13.7.31 Steam Generator Atmospheric Relief Valve (ARV) - Air Accumulator Tank TR LCO 13.7.31 Pursuant 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 CONDITION REQUIRED ACTION COMPLETION TIME A. Air accumulator tank(s) A.1 Enter the applicable Condition(s) Immediately pressure not within limits. of TS 3.7.4 for affected ARV(s) inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.7.31.1 Verify that the air accumulator tank pressure is within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months limits.

CPSES - UNITS 1 AND 2 - TRM 13.7-3 Revision 83

Steam Generator Pressure / Temperature Limitation TR 13.7.32 13.7 PLANT SYSTEMS TR 13.7.32 Steam Generator Pressure / Temperature Limitation TR LCO 13.7.32 The 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.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Pressure / Temperature A.1 Reduce the steam generator 30 minutes Limitations not met. pressure of the applicable sides to less than or equal to 200 psig.

AND A.2 Perform an engineering Prior to increasing steam evaluation to determine the effect generator coolant of the overpressurization on the temperatures above structural integrity of the steam 200 °F generator. Determine that the steam generator remains acceptable for continued operation.

CPSES - UNITS 1 AND 2 - TRM 13.7-4 Revision 83

Steam Generator Pressure / Temperature Limitation TR 13.7.32 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.7.32.1 --------------------------------------------------------------------------

- 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 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months generator is less than 200 psig.

TRS 13.7.32.2 --------------------------------------------------------------------------

- 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 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months established for the associated steam generator.

CPSES - UNITS 1 AND 2 - TRM 13.7-5 Revision 83

Ultimate Heat Sink - Sediment and SSI Dam TR 13.7.33 13.7 PLANT SYSTEMS TR 13.7.33 Ultimate Heat Sink - Sediment and Safe Shutdown Impoundment (SSI) Dam TR LCO 13.7.33 The 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 CONDITION REQUIRED ACTION COMPLETION TIME A. With the average sediment A.1 Initiate action in accordance with Immediately depth in the service water the Corrective Action Program to intake channel greater than remove sediment from the 1.5 feet. service water intake channel.

B. The SSI dam has abnormal B.1 Enter the applicable Condition(s) Immediately degradation or erosion. of TS 3.7.9 for SSI inoperable due to a degraded dam.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.7.33.1 Visually inspect the SSI dam and verify no abnormal 12 months degradation or erosion.

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

CPSES - UNITS 1 AND 2 - TRM 13.7-6 Revision 83

Flood Protection TR 13.7.34 13.7 PLANT SYSTEMS TR 13.7.34 Flood Protection TR LCO 13.7.34 Flood 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.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. ------------------------------------ A.1 Initiate action to place the unit in 1 hours1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months

- NOTE - a lower MODE.

Only applicable in MODES 1, 2, 3 and 4. AND A.2 Be in MODE 3. 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months Required flood protection measure(s) not in place. AND A.3 Be in MODE 4. 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months AND A.4 Be in MODE 5. 37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months CPSES - UNITS 1 AND 2 - TRM 13.7-7 Revision 83

Flood Protection TR 13.7.34 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 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 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months the limits.

TRS 13.7.34.2 --------------------------------------------------------------------------

- NOTE -

Only required to be performed when SCR water level is t 776 feet.

Verify the water level of SCR is measured to be within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months the limits.

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 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 790 feet.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.7-8 Revision 83

Flood Protection TR 13.7.34 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY 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 Once within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months verifying that any equipment which is to be opened or is after SCR water open for maintenance is isolated from the SCR by level > 777.5 feet isolation valves, or stop gates, or is at an elevation above 790 feet. AND Prior to opening any equipment for maintenance CPSES - UNITS 1 AND 2 - TRM 13.7-9 Revision 83

Snubbers TR 13.7.35 13.7 PLANT SYSTEMS TR 13.7.35 Snubbers TR LCO 13.7.35 All 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 LCOs 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.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more snubbers A.1 Enter the operability Immediately inoperable. determination process for attached system(s).

AND A.2 Perform an engineering 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months evaluation in accordance with the approved snubber augmented inservice inspection program on the attached component.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.7-10 Revision 83

Snubbers TR 13.7.35 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.7.35.1 Each required snubber shall be demonstrated Per snubber OPERABLE by performance of the requirements of the inservice testing/

approved snubber inservice testing/inspection program inspection program.

in TR 15.5.31.

CPSES - UNITS 1 AND 2 - TRM 13.7-11 Revision 83

Area Temperature Monitoring TR 13.7.36 13.7 PLANT SYSTEMS TR 13.7.36 Area Temperature Monitoring TR LCO 13.7.36 The 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 0.00222 hours 1.322751e-5 weeks 3.044e-6 months 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.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more areas exceeds ---------------------------------------------------

the maximum temperature - NOTE -

limit(s) for normal Required Action must be completed conditions shown in whenever Condition A is entered.

Table 13.7.36-1 for more ---------------------------------------------------

than 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months .

A.1 Initiate action in accordance with Immediately 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.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.7-12 Revision 83

Area Temperature Monitoring TR 13.7.36 ACTIONS (continued)

B. One or more areas exceeds B.1.1 Restore the area(s) to within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months the maximum temperature the maximum temperature limit(s) for abnormal limit(s) for abnormal conditions.

conditions shown in Table 13.7.36-1. OR B.1.2.1 Enter the appropriate 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Condition(s) of the appropriate TS(s) for the equipment in the affected area(s) inoperable.

OR B.1.2.2.1 Perform a review of the 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months qualification envelope for the affected equipment.

AND B.1.2.2.2 Declare INOPERABLE any 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months affected equipment in a qualification envelope that has been exceeded.

OR B.1.3 Perform an analysis that 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months justifies continued operation.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.7.36.1 Verify the temperature in each of the areas shown in 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Table 13.7.36-1 to be within limit(s).

CPSES - UNITS 1 AND 2 - TRM 13.7-13 Revision 83

Area Temperature Monitoring TR 13.7.36 Table 13.7.36-1 Area Temperature Monitoring MAXIMUM AREA TEMPERATURE LIMIT

(°F)

NORMAL ABNORMAL CONDITIONS CONDITIONS

1. Electrical and Control Building Normal Areas 104 131 Control Room Main Level (El. 830'-0") 80 104 Control Room Technical Support Area (El. 840'-6") 104 104 UPS/Battery Rooms 104 113 Chiller Equipment Areas 122 131

2. Fuel Building Normal Areas 104 131 Spent Fuel Pool Cooling Pump Rooms 122 131

3. Safeguards Buildings Normal Areas 104 131 AFW, RHR, SI, Containment Spray Pump Rooms 122 131 RHR Valve and Valve Isolation Tank Rooms 122 131 RHR/CT Heat Exchanger Rooms 122 131 Diesel Generator Area 122 131 Diesel Generator Equipment Rooms 130 131 Day Tank Room 122 131

4. Auxiliary Building 127 131 Normal Areas 104 131 CCW, CCP Pump Rooms 122 131 CCW Heat Exchanger Area 122 131 CVCS Valve and Valve Operating Rooms 122 131 Auxiliary Steam Drain Tank Equip. Room 122 131 Waste Gas Tank Valve Operating Room 122 131

5. Service Water Intake Structure 127 131

6. Containment Buildings General Areas 120 129 Reactor Cavity Exhaust 150 190 CRDM Shroud Exhaust 163 172 CPSES - UNITS 1 AND 2 - TRM 13.7-14 Revision 83

Safety Chilled Water System - Electrical Switchgear Area Emergency Fan Coil Units TR 13.7.37 13.7 PLANT SYSTEMS TR 13.7.37 Safety Chilled Water System - Electrical Switchgear Area Emergency Fan Coil Units TR LCO 13.7.37 The safety chilled water system electrical switchgear area emergency fan coil units shall be OPERABLE.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Declare Safety Chilled Water Immediately electrical switchgear area train(s) inoperable (TS 3.7.19).

emergency fan coil unit(s) inoperable. OR A.2 Declare affected fan coil unit(s) Immediately and their supported equipment inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.7.37.1 Verify electrical switchgear area emergency fan coil 18 months on a units start on an actual or simulated Safety Injection STAGGERED TEST actuation signal. BASIS CPSES - UNITS 1 AND 2 - TRM 13.7-15 Revision 83

Main Feedwater Isolation Valve Pressure / Temperature Limit TR 13.7.38 13.7 PLANT SYSTEMS TR 13.7.38 Main Feedwater Isolation Valve Pressure / Temperature Limit TR LCO 13.7.38 The 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.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more main A.1 Restore main feedwater isolation 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months feedwater isolation valves valve(s) pressure and/or outside of the required temperature to within limits.

limits.

AND A.2 ------------------------------------------

- NOTE -

Required Action A.2 must be completed whenever Condition A is entered.

Perform an engineering 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.7-16 Revision 83

Main Feedwater Isolation Valve Pressure / Temperature Limit TR 13.7.38 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. Required Actions and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Times of Condition A not AND met.

B.2 Be in MODE 4. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 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 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months determined to be greater than or equal to 90°F.

CPSES - UNITS 1 AND 2 - TRM 13.7-17 Revision 83

Tornado Missile Shields TR 13.7.39 13.7 PLANT SYSTEMS TR 13.7.39 Tornado Missile Shields TR LCO 13.7.39 Required 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.

CONDITION REQUIRED ACTION COMPLETION TIME A. Allowances of A.1 Declare equipment supported by Immediately Table 13.7.39-1 not met for affected missile shield(s) one or more missile shields. inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.7.39.1 Verify allowances of Table 13.7.39-1 are satisfied. Prior to removal of any missile shield CPSES - UNITS 1 AND 2 - TRM 13.7-18 Revision 83

Tornado Missile Shields TR 13.7.39 Table 13.7.39-1 Missile Shield Allowances Shields: 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months provided:

a. Units 1 and 2 enter LCO 3.7.12 CONDITION B, and

b. It is continuously manned, with direct communications established to the control room, and

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.

CPSES - UNITS 1 AND 2 - TRM 13.7-19 Revision 83

Tornado Missile Shields TR 13.7.39 Table 13.7.39-1 Missile Shield Allowances Shields: 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months provided:

a. Units 1 and 2 enter LCO 3.7.12 CONDITION B, and

b. It is continuously manned, with direct communications established to the control room, and CPSES - UNITS 1 AND 2 - TRM 13.7-20 Revision 83

Tornado Missile Shields TR 13.7.39 Table 13.7.39-1 Missile Shield Allowances

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 Area Related 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months provided:

a. It is continuously manned, with direct communications established to the control room, and CPSES - UNITS 1 AND 2 - TRM 13.7-21 Revision 83

Tornado Missile Shields TR 13.7.39 Table 13.7.39-1 Missile Shield Allowances

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 Area Related 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months provided:

a. It is continuously manned, with direct communications established to the control room, and CPSES - UNITS 1 AND 2 - TRM 13.7-22 Revision 83

Tornado Missile Shields TR 13.7.39 Table 13.7.39-1 Missile Shield Allowances

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. Corridor Related 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, or

b. 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 operability CPSES - UNITS 1 AND 2 - TRM 13.7-23 Revision 83

Tornado Missile Shields TR 13.7.39 Table 13.7.39-1 Missile Shield Allowances Shields: Access Cover Plates (4) El. 852' 6", above Unit 2 Safeguard Bldg. Corridor Related 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, or

b. 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 operability CPSES - UNITS 1 AND 2 - TRM 13.7-24 Revision 83

Tornado Missile Shields TR 13.7.39 Table 13.7.39-1 Missile Shield Allowances Shields: E-40A Door, Control Room Related Specifications: 3.7.10 Allowance:

In all MODES may be open under administrative control for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months provided:

a. It is continuously manned, with direct communications established to the control room, and

b. 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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.

CPSES - UNITS 1 AND 2 - TRM 13.7-25 Revision 83

Tornado Missile Shields TR 13.7.39 Table 13.7.39-1 Missile Shield Allowances 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 0.01 hours 5.952381e-5 weeks 1.3698e-5 months 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after initial loosening (disengagement) of the middle panels 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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, CPSES - UNITS 1 AND 2 - TRM 13.7-26 Revision 83

Tornado Missile Shields TR 13.7.39 Table 13.7.39-1 Missile Shield Allowances

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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months period the hinged middle panel is breached/opened to ensure emergent severe weather conditions do not develop or are anticipated for the area and

h. 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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.

CPSES - UNITS 1 AND 2 - TRM 13.7-27 Revision 83

Tornado Missile Shields TR 13.7.39 Table 13.7.39-1 Missile Shield Allowances Shields: Related Specifications:

Access Cover Plate, Unit 1 Diesel FO Truck Fill Station 3.8.1, 3.8.2 Access Cover, Unit 1 RWST None Access Cover, Unit 1 CST 3.7.6 Access Cover, Unit 1 RMWST None 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, 3.8.2 Access Cover, Unit 2 RWST None Access Cover, Unit 2 CST 3.7.6 Access Cover, Unit 2 RMWST None Allowance:

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.

CPSES - UNITS 1 AND 2 - TRM 13.7-28 Revision 83

Tornado Missile Shields TR 13.7.39 Table 13.7.39-1 Missile Shield Allowances Shields: Related Specifications:

Cover Plates (2), Unit 1 Diesel FO Storage Tanks 3.8.1, 3.8.2 Access Cover Plates (2), Unit 1 Diesel FO Storage Tanks 3.8.1, 3.8.2 Removable 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 3.7.8 Manhole Cover, MH#E1A1, Unit 1 SW Train A 3.7.8 Manhole Cover, MH#E1A2, Unit 1 SW Train A 3.7.8 Manhole Cover, MH#E1B1, Unit 1 SW Train B 3.7.8 Manhole Cover; MH#E1B2, Unit 1 SW Train B 3.7.8 Cover Plates (2), Unit 2 Diesel FO Storage Tanks 3.8.1, 3.8.2 Access 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 3.7.8 Manhole Cover, MH#E2A1, Unit 2 SW Train A 3.7.8 Manhole Cover, MH#E2A2, Unit 2 SW Train A 3.7.8 Manhole Cover, MH#E2A3, Unit 2 SW Train A 3.7.8 Manhole Cover, MH#E2A4, Unit 2 SW Train A 3.7.8 Manhole Cover, MH#E2A5, Unit 2 SW Train A 3.7.8 Manhole Cover, MH#E2B1, Unit 2 SW Train B 3.7.8 Manhole Cover, MH#E2B2, Unit 2 SW Train B 3.7.8 Manhole Cover, MH#E2B3, Unit 2 SW Train B 3.7.8 Manhole Cover, MH#E2B4, Unit 2 SW Train B 3.7.8 Manhole Cover, MH#E2B5, Unit 2 SW Train B 3.7.8 Allowance:

May be removed under administrative control for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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, and

b. No more than one OPERABLE train per unit of a system shall have its missile shields removed at one time.

CPSES - UNITS 1 AND 2 - TRM 13.7-29 Revision 83

CST Make-up and Reject Line Isolation Valves TR 13.7.41 13.7 PLANT SYSTEMS TR 13.7.41 Condensate Storage Tank (CST) Make-up and Reject Line Isolation Valves TR LCO 13.7.41 Two 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.

CONDITION REQUIRED ACTION COMPLETION TIME A. One CST make-up and A.1 Isolate the make-up and reject 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months reject line isolation valve line.

inoperable.

AND A.2 Verify the flowpath is isolated. Once per 31 days B. Two CST make-up and B.1 Isolate the make-up and reject 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months reject line isolation valves line.

inoperable.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.7-30 Revision 83

CST Make-up and Reject Line Isolation Valves TR 13.7.41 ACTIONS (continued)

C. Required Actions and C.1 Verify by administrative means 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion OPERABILITY of backup water Times for Conditions A or B supply. AND not met.

Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND C.2 Restore both affected valves to 7 days OPERABLE.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.7.41.1 Verify each CST make-up and reject line isolation valve 18 months actuates to the isolation position on an actual or simulated actuation signal.

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

CPSES - UNITS 1 AND 2 - TRM 13.7-31 Revision 83

AC Sources (Diesel Generator Requirements)

TR 13.8.31 13.8 ELECTRICAL POWER SYSTEMS TR 13.8.31 AC Sources (Diesel Generator Requirements)

TR LCO 13.8.31 Pursuant 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 CONDITION REQUIRED ACTION COMPLETION TIME A. One or more of the A.1 Enter the applicable Condition(s) Immediately following surveillances not of TS 3.8.1 or 3.8.2 for the met for required DG(s). effected DG(s) inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.8.31.1 Verify diesel generator is aligned to provide standby 31 days power to the associated emergency busses.

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 18 months procedures prepared in conjunction with the diesel owners groups preventive maintenance program.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.8-1 Revision 83

AC Sources (Diesel Generator Requirements)

TR 13.8.31 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY 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 18 months on a generator do not exceed the continuous rating of 7,000 STAGGERED TEST kW. 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 18 months features prevent diesel generator from starting:

a. Barring device engaged, or

b. Maintenance Lockout Mode.

TRS 13.8.31.5 Pump out each fuel oil storage tank, remove 10 Years accumulated sediment and clean the tank using a sodium hypochlorite solution or equivalent.

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

CPSES - UNITS 1 AND 2 - TRM 13.8-2 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 13.8 ELECTRICAL POWER SYSTEMS TR 13.8.32 Containment Penetration Conductor Overcurrent Protection Devices TR LCO 13.8.32 All 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.

CPSES - UNITS 1 AND 2 - TRM 13.8-3 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more of the A.1.1.1 Verify the circuit(s) 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months containment penetration de-energized by racked out, conductor overcurrent locked open, or removed AND protective device(s) inoperable protective inoperable. device(s). Once per 31 days thereafter AND A.1.1.2 Tripping/ removing the 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months associated protective device(s).

OR A.1.2.1 Verify the circuit(s) de- 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months energized by tripped/removed associated protective AND device(s).

Once per 7 days OR thereafter A.1.2.2 Verify the circuit(s) de- 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months energized by racked out, locked open, or removed AND inoperable protective device(s). Once per 7 days thereafter AND A.2 Declare the affected system(s) or 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months component(s) inoperable.

B. Required Actions and B.1 Be in MODE 3. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months associated Completion Times not met. AND B.2 Be in MODE 5. 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months CPSES - UNITS 1 AND 2 - TRM 13.8-4 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.8.32.1 Verify that the medium voltage 6.9 kV and low voltage 72 months 480V switchgear circuit breakers are OPERABLE by:

AND

a. A CHANNEL CALIBRATION of the associated At least 10% of the protective relays, breakers of a group tested every 18

b. An integrated system functional test which months includes simulated automatic actuation of the system and verifying that each relay and associated circuit breakers and control circuits function as designed, and

c. 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.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.8-5 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY TRS 13.8.32.2 Verify that the 480V and lower voltage molded case 72 months circuit breakers are OPERABLE by performing the following: AND

a. Inverse time overcurrent trip test to verify that At least 10% of the the test trip time does not exceed the maximum breakers tested trip time per the breaker time-current every 18 months for characteristics. breaker groups with t4 breakers

b. Instantaneous overcurrent trip test.

OR

c. Circuit breakers found inoperable during functional testing shall be replaced by At least 1 breaker OPERABLE breakers prior to resuming tested every 36 operation. months for breakers groups with 2 or 3

d. For each circuit breaker found inoperable during breakers.

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.

TRS 13.8.32.3 Subject each medium voltage 6.9kv switchgear circuit 60 months breaker to an inspection and preventive maintenance in accordance with procedures prepared in conjunction with its manufacturers recommendations.

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

TRS 13.8.32.5 Subject each 480V and lower voltage molded case 72 months switchgear circuit breaker to an inspection and preventive maintenance in accordance with procedures prepared in conjunction with its manufacturers recommendations.

CPSES - UNITS 1 AND 2 - TRM 13.8-6 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 1 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

1. 6.9 KVAC from Switchgears

a. Switchgear Bus 1A1 RCP #11

1) Primary Breaker 1PCPX1 a) Relay 50M1-51 b) Relay 86M

2) Backup Breakers 1A1-1 or 1A1-2 a) Relay 51M3 b) Relay 51 for 1A1-1 c) Relay 51 for 1A1-2 d) Relay 86/1A1

b. Switchgear Bus 1A2 RCP #12

1) Primary Breaker 1PCPX2 a) Relay 50M1-51 b) Relay 86M

2) Backup Breakers 1A2-1 or 1A2-2 a) Relay 51M3 b) Relay 51 for 1A2-1 c) Relay 51 for 1A2-2 d) Relay 86/1A2 CPSES - UNITS 1 AND 2 - TRM 13.8-7 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 2 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

c. Switchgear Bus 1A3 RCP #13

1) Primary Breaker 1PCPX3 a) Relay 50M1-51 b) Relay 86M

2) Backup Breakers 1A3-1 or 1A3-2 a) Relay 51M3 b) Relay 51 for 1A3-1 c) Relay 51 for 1A3-2 d) Relay 86/1A3

d. Switchgear Bus 1A4 RCP #14

1) Primary Breaker 1PCPX4 a) Relay 50M1-51 b) Relay 86M

2) Backup Breaker 1A4-1 or 1A4-2 a) Relay 51M3 b) Relay 51 for 1A4-1 c) Relay 51 for 1A4-2 d) Relay 86/1A4 CPSES - UNITS 1 AND 2 - TRM 13.8-8 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 3 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

2. 480 VAC from Switchgears 2.1 480V Switchgear 1EB1

1. Compartment 3B Containment Recirc Fan CP1-VAFNAV-01 a) Primary Breaker 1FNAV1

1) Relay: Amptector Trip Unit of Breaker 1FNAV1 b) Backup Breakers 1EB1-1 and BT-1EB13 50 - 51

1) Long Time and Instantaneous Relay ------------------------

1FNAV1 62 - 1

2) Time Delay Relay ------------------------

1FNAV1 2.2 480V Switchgear 1EB2

1. Compartment 3B Containment Recirc Fan CP1-VAFNAV-02 a) Primary Breaker 1FNAV2

1) Relay: Amptector Trip Unit of Breaker 1FNAV2 b) Backup Breakers 1EB2-1 and BT-1EB24 50 - 51

1) Long Time and Instantaneous Relay ------------------------

1FNAV2 62 - 1

2) Time Delay Relay ------------------------

1FNAV2 2.3 480V Switchgear 1EB3

1. Compartment 8B CRDM Vent Fan CP1-VAFNCB-01 a) Primary Breaker 1FNCB1

1) Relay: Amptector Trip Unit of Breaker 1FNCB1 b) Backup Breakers 1EB3-1 and BT-1EB13 50 - 51

1) Long Time and Instantaneous Relay ------------------------

1FNCB1 62 - 1

2) Time Delay Relay ------------------------

1FNCB1 CPSES - UNITS 1 AND 2 - TRM 13.8-9 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 4 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

2. Compartment 9B Containment Recirc Fan CP1-VAFNAV-03 a) Primary Breaker 1FNAV3

1) Relay: Amptector Trip Unit of Breaker 1FNAV3 b) Backup Breakers 1EB3-1 and BT-1EB13 50 - 51

1) Long Time and Instantaneous Relay ------------------------

1FNAV3 62 - 1

2) Time Delay Relay ------------------------

1FNAV3 2.4 480V Switchgear 1EB4

1. Compartment 8B CRDM Vent Fan CP1-VAFNCB-02 a) Primary Breaker 1FNCB2

1) Relay: Amptector Trip Unit of Breaker 1FNCB2 b) Backup Breakers 1EB4-1 and BT-1EB24 50 - 51

1) Long Time and Instantaneous Relay ------------------------

1FNCB2 62 - 1

2) Time Delay Relay ------------------------

1FNCB2

2. Compartment 9B Containment Recirc Fan CP1-VAFNAV-04 a) Primary Breaker 1FNAV4

1) Relay: Amptector Trip Unit of Breaker 1FNAV4 b) Backup Breakers 1EB4-1 and BT-1EB24 50 - 51

1) Long Time and Instantaneous Relay ------------------------

1FNAV4 62 - 1

2) Time Delay Relay ------------------------

1FNAV4 CPSES - UNITS 1 AND 2 - TRM 13.8-10 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 5 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

3. 480VAC from Motor Control Centers 3.1 Device Location - MCC 1EB1-2 Compartment Numbers listed below.

Primary and - Both primary and backup breakers have identical trip ratings and Backup Breakers are in the same MCC Compt. These breakers are General Electric type THED with thermal-magnetic trip elements.

MCC 1EB1-2 G.E.

COMPT. NO. BKR. TYPE SYSTEM POWERED 4G THED Motor Operated Valve 1-TV-4691 4M THED Motor Operated Valve 1-TV-4693 3F THED Containment Drain Tank Pump-03 9H THED Reactor Cavity Sump Pump-01 9M THED Reactor Cavity Sump Pump-02 7H THED Containment Sump #1 Pump-01 7M THED Containment Sump #1 Pump-02 6H THED RCP #11 Motor Space Heater-01 6M THED RCP #13 Motor Space Heater-03 8B THED Incore Detector Drive "A" 8D THED Incore Detector Drive "B" 7B THED Incore Detector Drive "F" 3B THED Stud Tensioner Hoist Outlet-01 7D THED Hydraulic Deck Lift-01 4B THED Reactor Coolant Pump Motor Hoist Receptacle-42 8H THED RC Pipe Penetration Cooling Unit-01 8M THED RC Pipe Penetration Cooling Unit-02 5H THED RCP #11 Oil Lift Pump-01 5M THED RCP #13 Oil Lift Pump-03 10B THED Preaccess Filter Train Package Receptacle-17 12H THED Containment Ltg. XFMR-28 (PNL C11 & C12) 2M THED RC Drain Tank Pump No. 1 2F THED Containment Ltg. XFMR-16 (PNL C7 & C9) 1M THED Containment Ltg. XFMR-12 (PNL C1 & C5) 3M THED Preaccess Fan No. 11 CPSES - UNITS 1 AND 2 - TRM 13.8-11 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 6 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED 3.2 Device Location - MCC 1EB2-2 Compartment Numbers listed below.

Primary and Backup - Both primary and backup breakers have identical trip ratings and are Breakers located in the same MCC compt. These breakers are General Electric type THED with thermal-magnetic trip elements.

MCC 1EB2-2 G.E.

COMPT. NO. BKR. TYPE SYSTEM POWERED 4G THED Motor Operated Valve 1-TV-4692 4M THED Motor Operated Valve 1-TV-4694 3F THED Containment Drain Tank Pump-04 7H THED Containment Sump No. 2 Pump-03 7M THED Containment Sump No. 2 Pump-04 6H THED RCP #12 Motor Space Heater-02 6M THED RCP #14 Motor Space Heater-04 5B THED Incore Detector Drive "C" 2B THED Incore Detector Drive "D" 7B THED Incore Detector Drive "E" 5D THED Containment Fuel Storage Crane-01 3B THED Stud Tensioner Hoist Outlet-02 4B THED Containment Solid Rad Waste Compactor-01 10B THED RCC Change Fixture Hoist Drive-01 10F THED Refueling Cavity Skimmer Pump-01 12B THED Power Receptacles (Cont. E1. 841')

8H THED RC Pipe Penetration Fan-03 8M THED RC Pipe Penetration Fan-04 5H THED RCP #12 Oil Lift Pump-02 5M THED RCP #14 Oil Lift Pump-04 12H THED Preaccess Filter Train Package Receptacles - 18 6D THED Containment Auxiliary Upper Crane-01 (a) 2F THED Containment Ltg. XFMR-13 (PNL C2) 2D THED Containment Access Rotating Platform-01 2M THED Reactor Coolant Drain Tank Pump-02 9F THED Containment Ltg. XFMR-17(PNL C8 & C10) 9M THED Containment Ltg. XFMR-15 (PNL C4 & C6) 3M THED Preaccess 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.

CPSES - UNITS 1 AND 2 - TRM 13.8-12 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 7 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED 3.3 Device Location - MCC 1EB3-2 Compartment numbers listed below.

Primary and - Unless noted otherwise, both primary and backup breakers 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 1EB3-2 G.E.

COMPT. NO. BKR. TYPE SYSTEM POWERED 8RF THED JB-1S-10050, Altern. Feed to Motor Operated Valve 1-8702A 1G THED Motor Operated Valve 1-8112 9G THED Motor Operated Valve 1-8701A 9M THED Motor Operated Valve 1-8701B 5M THED Motor Operated Valve 1-8000A 5G THED Motor Operated Valve 1-HV-6074 4G THED Motor Operated Valve 1-HV-6076 4M THED (a) Motor Operated Valve 1-HV-6078 2G THED Motor Operated Valve 1-HV-4696 2M THED Motor Operated Valve 1-HV-4701 3G THED (a) Motor Operated Valve 1-HV-5541 (a) 3M THED Motor Operated Valve 1-HV-5543 1M THED Motor Operated Valve 1-HV-6083 6F THED Motor Operated Valve 1-8808A 6M THED Motor Operated Valve 1-8808C 7M THED Containment Ltg. XFMR-18 (PNL SC1 & SC3) 8M THED Neutron Detector Well Fan-09 8RM THED Motor Operated Valve 1-HV-4075C (a) Primary protection is provided by Gould Tronic TR5 fusible switch with 3.2A fuse.

CPSES - UNITS 1 AND 2 - TRM 13.8-13 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 8 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED 3.4 Device Location - MCC 1EB4-2 Compartment numbers listed below.

Primary and - Unless noted otherwise, both primary and backup breakers 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 1EB4-2 G.E.

COMPT. NO. BKR. TYPE SYSTEM POWERED 1M THED JB-1S-1230G, Altern. Feed to Motor Operated Valve 1-8701B 8G THED Motor Operated Valve 1-8702A 8M THED Motor Operated Valve 1-8702B 4M THED Motor Operated Valve 1-8000B 4G THED Motor Operated Valve 1-HV-6075 3G THED Motor Operated Valve 1-HV-6077 3M THED (a) Motor Operated Valve 1-HV-6079 2G THED Motor Operated Valve 1-HV-5562 2M THED (a) Motor Operated Valve 1-HV-5563 5F THED Motor Operated Valve 1-8808B 5M THED Motor Operated Valve 1-8808D 6M THED Containment Ltg. XFMR-19(PNL SC2 & SC4) 7M THED Neutron Detector Well Fan-10 (a) Primary protection is provided by Gould Tronic TR5 fusible switch with 3.2A fuse.

CPSES - UNITS 1 AND 2 - TRM 13.8-14 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 9 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

4. 480VAC From Panelboards 4.1 Pressurizer 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.

4.2 Pressurizer Heater group C

a. 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.

CPSES - UNITS 1 AND 2 - TRM 13.8-15 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 10 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED 4.3 480VAC From Plant Support Power System Panelboards Both 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 Type System Powered Ckt 2 FC Containment Elevator CP1-MEELRB-01 Ckt 4 KH Welding Receptacles Distribution Panel 1B11-1-1-1 Ckt 6 LH Containment Polar Crane CP1-MESCCP-01 b) Panelboard 1B11-1-2 Device Location Breaker Type System Powered Ckt 2 FC Fuel Transfer System Rx Side Cont. Pnl for TBX-FHSTTS-02 Ckt 14 FC Containment Lighting Xfmr CP1-ELTRNT-14 Ckt 16 FC Manipulator Crane 1-01 TBX-FHSCMC-01 CPSES - UNITS 1 AND 2 - TRM 13.8-16 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 11 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

5. 120V Space Heater Circuits from Containment Recirc. Fan and CRDM Vent 480V Switchgears Fan Motor Space Heaters

a. Primary Devices - N/A (Fuse)

b. Backup Breakers BKR. LOCATION WESTINGHOUSE

& NUMBER BKR. TYPE Swgr. 1EB1, EB1010 Cubicle 3A, CP1-VAFNAV-01 Space Heater Bkr.

Swgr. 1EB2, EB1010 Cubicle 3A, CP1-VAFNAV-02 Space Heater Bkr.

Swgr. 1EB3, EB1010 Cubicle 9A, CP1-VAFNAV-03 Space Heater Bkr.

Swgr. 1EB4, EB1010 Cubicle 9A, CP1-VAFNAV-04 Space Heater Bkr.

Swgr. 1EB3, EB1010 Cubicle 8A, CP1-VAFNCB-01 Space Heater Bkr.

Swgr. 1EB4, EB1010 Cubicle 8A, CP1-VAFNCB-02 Space Heater Bkr.

CPSES - UNITS 1 AND 2 - TRM 13.8-17 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 12 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

6. 125V DC Control Power Various

a. Primary Devices - N/A (Fuse)

b. Backup Breakers GENERAL ELECTRIC PANELBOARD NO. CKT.NO. BREAKER TYPE XED1-1 1,6 TED XED2-1 3,6 TED XD2-3 8 TED 1ED2-1 14,17 TED 1D2-3 10 TED 1ED3-1 5 TED 1ED1-2 7 TED TBX-WPXILP-01 Main(LBK3) FB(Westinghouse)

7. 120V AC Control Power from Isolation XFMR TXEC3 & TXEC4

a. 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 TB4-13

2) Panel Board B, Ckt. Bkr. connected at TB6-7

8. 120V AC Power for Personnel and Emergency Airlocks

a. Primary Devices - N/A (Fuse)

b. Backup Breakers GENERAL ELECTRIC PANELBOARD NO. CKT.NO. BREAKER TYPE XEC2 34 TED XEC1-2 2 TED CPSES - UNITS 1 AND 2 - TRM 13.8-18 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1a (Page 13 of 13)

Unit 1 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

9. 118V AC Control Power

a. Primary Devices - N/A (Fuse)

b. Backup Breakers GENERAL ELECTRIC PANELBOARD NO. CKT.NO. BREAKER TYPE 1EC5 8 TED 1EC6 3 TED

10. Emergency Evacuation System Warning Lights Power

a. Primary Devices - N/A (Fuse)

b. Backup Breakers SQUARE D PANELBOARD NO. CKT.NO. BREAKER TYPE XEC3-3 9,10 FY

11. DRPI Data Cabinet Power Supplies

a. Primary Breakers SQUARE D PANELBOARD NO. CKT.NO. BREAKER TYPE 1C14 1,2 FA

b. Backup Breakers SQUARE D PANELBOARD NO. CKT.NO. BREAKER TYPE 1C14 Main Pnl. Bkrs. FA CPSES - UNITS 1 AND 2 - TRM 13.8-19 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 1 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

1. 6.9 KVAC from Switchgears

a. Switchgear Bus 2A1 RCP #21

1) Primary Breaker 2PCPX1 a) Relay 50M1-51 b) Relay 86M

2) Backup Breakers 2A1-1 or 2A1-2 a) Relay 51M3 b) Relay 51 for 2A1-1 c) Relay 51 for 2A1-2 d) Relay 86/2A1

b. Switchgear Bus 2A2 RCP #22

1) Primary Breaker 2PCPX2 a) Relay 50M1-51 b) Relay 86M

2) Backup Breakers 2A2-1 or 2A2-2 a) Relay 51M3 b) Relay 51 for 2A2-1 c) Relay 51 for 2A2-2 d) Relay 86/2A2 CPSES - UNITS 1 AND 2 - TRM 13.8-20 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 2 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

c. Switchgear Bus 2A3 RCP #23

1) Primary Breaker 2PCPX3 a) Relay 50M1-51 b) Relay 86M

2) Backup Breakers 2A3-1 or 2A3-2 a) Relay 51M3 b) Relay 51 for 2A3-1 c) Relay 51 for 2A3-2 d) Relay 86/2A3

d. Switchgear Bus 2A4 RCP #24

1) Primary Breaker 2PCPX4 a) Relay 50M1-51 b) Relay 86M

2) Backup Breaker 2A4-1 or 2A4-2 a) Relay 51M3 b) Relay 51 for 2A4-1 c) Relay 51 for 2A4-2 d) Relay 86/2A4 CPSES - UNITS 1 AND 2 - TRM 13.8-21 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 3 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

2. 480 VAC from Switchgears 2.1 480V Switchgear 2EB1

1. Compartment 3B Containment Recirc Fan CP2-VAFNAV-01 a) Primary Breaker 2FNAV1

1) Relay: Amptector Trip Unit of Breaker 2FNAV1 b) Backup Breakers 2EB1-1 and BT-2EB13 50 - 51

1) Long Time and Instantaneous Relay ------------------------

2FNAV1 62 - 1

2) Time Delay Relay ------------------------

2FNAV1 2.2 480V Switchgear 2EB2

1. Compartment 3B Containment Recirc Fan CP2-VAFNAV-02 a) Primary Breaker 2FNAV2

1) Relay: Amptector Trip Unit of Breaker 2FNAV2 b) Backup Breakers 2EB2-1 and BT-2EB24 50 - 51

1) Long Time and Instantaneous Relay ------------------------

2FNAV2 62 - 1

2) Time Delay Relay ------------------------

2FNAV2 2.3 480V Switchgear 2EB3

1. Compartment 8B CRDM Vent Fan CP2-VAFNCB-01 a) Primary Breaker 2FNCB1

1) Relay: Amptector Trip Unit of Breaker 2FNCB1 b) Backup Breakers 1EB3-1 and BT-1EB13 50 - 51

1) Long Time and Instantaneous Relay ------------------------

2FNCB1 62 - 1

2) Time Delay Relay ------------------------

2FNCB1

2. Compartment 9B Containment Recirc Fan CP2-VAFNAV-03 a) Primary Breaker 2FNAV3

1) Relay: Amptector Trip Unit of Breaker 2FNAV3 b) Backup Breakers 2EB3-1 and BT-2EB13 50 - 51

1) Long Time and Instantaneous Relay ------------------------

2FNAV3 62 - 1

2) Time Delay Relay ------------------------

2FNAV3 CPSES - UNITS 1 AND 2 - TRM 13.8-22 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 4 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED 2.4 480V Switchgear 2EB4

1. Compartment 8B CRDM Vent Fan CP2-VAFNCB-02 a) Primary Breaker 2FNCB2

1) Relay: Amptector Trip Unit of Breaker 2FNCB2 b) Backup Breakers 2EB4-1 and BT-2EB24 50 - 51

1) Long Time and Instantaneous Relay ------------------------

2FNCB2 62 - 1

2) Time Delay Relay ------------------------

2FNCB2

2. Compartment 9B Containment Recirc Fan CP2-VAFNAV-04 a) Primary Breaker 2FNAV4

1) Relay: Amptector Trip Unit of Breaker 2FNAV4 b) Backup Breakers 2EB4-1 and BT-2EB24 50 - 51

1) Long Time and Instantaneous Relay ------------------------

2FNAV4 62 - 1

2) Time Delay Relay ------------------------

2FNAV4 CPSES - UNITS 1 AND 2 - TRM 13.8-23 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 5 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

3. 480VAC from Motor Control Centers 3.1 Device Location - MCC 2EB1-2 Compartment Numbers listed below.

Primary and - Both primary and backup breakers have identical trip ratings and Backup Breakers are in the same MCC Compt. These breakers are General Electric type THED with thermal-magnetic trip elements.

MCC 2EB1-2 G.E.

COMPT. NO. BKR. TYPE SYSTEM POWERED 4G THED Motor Operated Valve 2-TV-4691 4M THED Motor Operated Valve 2-TV-4693 3F THED Containment Drain Tank Pump-03 9H THED Reactor Cavity Sump Pump-01 9M THED Reactor Cavity Sump Pump-02 7H THED Containment Sump #1 Pump-01 7M THED Containment Sump #1 Pump-02 6H THED RCP #21 Motor Space Heater-01 6M THED RCP #23 Motor Space Heater-03 8B THED Incore Detector Drive "A" 8D THED Incore Detector Drive "B" 7B THED Incore Detector Drive "F" 3B THED Stud Tensioner Hoist Outlet-01 7D THED Hydraulic Deck Lift-01 4B THED Reactor Coolant Pump Motor Hoist Receptacle-42 8H THED RC Pipe Penetration Cooling Unit-01 8M THED RC Pipe Penetration Cooling Unit-02 5H THED RCP #21 Oil Lift Pump-01 5M THED RCP #23 Oil Lift Pump-03 10B THED Preaccess Filter Train Package Receptacle-17 10F THED S.G. Wet Layup Circ. Pump 01 (CP2-CFAPRP-01) 12M THED S.G. Wet Layup Circ. Pump 03 (CP2-CFAPRP-03) 12H THED Containment Ltg. XFMR-28 (PNL 2C11 & 2C12) 12B THED Personnel Air Lock Hydraulic Unit #2 (CP2-BSAPPA-02M) 2M THED RC Drain Tank Pump No. 1 2F THED Containment Ltg. XFMR-16 (PNL 2C7 & 2C9) 1M THED Containment Ltg. XFMR-12 (PNL 2LPC1 & 2LPC5) 3M THED Preaccess Fan No. 11 CPSES - UNITS 1 AND 2 - TRM 13.8-24 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 6 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED 3.2 Device Location - MCC 2EB2-2 Compartment Numbers listed below.

Primary and Backup - Both primary and backup breakers have identical trip ratings and are Breakers located in the same MCC compt. These breakers are General Electric type THED with thermal-magnetic trip elements.

MCC 2EB2-2 G.E.

COMPT. NO. BKR. TYPE SYSTEM POWERED 4G THED Motor Operated Valve 2-TV-4692 4M THED Motor Operated Valve 2-TV-4694 3F THED Containment Drain Tank Pump-04 7H THED Containment Sump No. 2 Pump-03 7M THED Containment Sump No. 2 Pump-04 6H THED RCP #22 Motor Space Heater-02 6M THED RCP #24 Motor Space Heater-04 5B THED Incore Detector Drive "C" 2B THED Incore Detector Drive "D" 7B THED Incore Detector Drive "E" 5D THED Containment Fuel Storage Crane-01 3B THED Stud Tensioner Hoist Outlet-02 10B THED RCC Change Fixture Hoist Drive-01 10F THED Refueling Cavity Skimmer Pump-01 12B THED Power Receptacles (Cont. E1. 841')

1M THED S.G. Wet Layup Circ. Pump 02 (CP2-CFAPRP-02) 12M THED S.G. Wet Layup Circ. Pump 04 (CP2-CFAPRP-04) 8H THED RC Pipe Penetration Fan-03 8M THED RC Pipe Penetration Fan-04 5H THED RCP #22 Oil Lift Pump-02 5M THED RCP #24 Oil Lift Pump-04 12H THED Preaccess Filter Train Package Receptacles - 18 6D THED Containment Auxiliary Upper Crane-01 (a) 2F THED Containment Ltg. XFMR-13 (PNL 2LPC2) 2D THED Containment Access Rotating Platform-01 2M THED Reactor Coolant Drain Tank Pump-02 9F THED Containment Ltg. XFMR-17 (PNL 2C8 & 2C10) 9M THED Containment Ltg. XFMR-15 (PNL 2LPC4 & 2LPC6) 3M THED Preaccess 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.

CPSES - UNITS 1 AND 2 - TRM 13.8-25 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 7 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED 3.3 Device 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 2EB3-2 G.E.

COMPT. NO. BKR. TYPE SYSTEM POWERED 8RF THED Altern. Feed to Motor Operated Valve 2-8702A 1G THED Motor Operated Valve 2-8112 9G THED Motor Operated Valve 2-8701A 9M THED Motor Operated Valve 2-8701B 5M THED Motor Operated Valve 2-8000A 5G THED Motor Operated Valve 2-HV-6074 4G THED Motor Operated Valve 2-HV-6076 4M THED (a) Motor Operated Valve 2-HV-6078 2G THED Motor Operated Valve 2-HV-4696 2M THED Motor Operated Valve 2-HV-4701 3G THED Motor Operated Valve 2-HV-5541 3M THED Motor Operated Valve 2-HV-5543 1M THED Motor Operated Valve 2-HV-6083 6F THED Motor Operated Valve 2-8808A 6M THED Motor Operated Valve 2-8808C 7M THED Containment Ltg. XFMR-18 (PNL 2SC1 & 2SC3) 8M THED Neutron Detector Well Fan-09 8RM THED Motor Operated Valve 2-HV-4075C (a) Primary protection is provided by Gould Tronic TR5 fusible switch with 3.2A fuse.

CPSES - UNITS 1 AND 2 - TRM 13.8-26 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 8 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED 3.4 Device 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 2EB4-2 G.E.

COMPT. NO. BKR. TYPE SYSTEM POWERED 1M THED Altern. Feed to Motor Operated Valve 2-8701B 8G THED Motor Operated Valve 2-8702A 8M THED Motor Operated Valve 2-8702B 4M THED Motor Operated Valve 2-8000B 4G THED Motor Operated Valve 2-HV-6075 3G THED Motor Operated Valve 2-HV-6077 3M THED (a) Motor Operated Valve 2-HV-6079 (a) 2G THED Motor Operated Valve 2-HV-5562 (a) Motor Operated Valve 2-HV-5563 2M THED 5F THED Motor Operated Valve 2-8808B 5M THED Motor Operated Valve 2-8808D 6M THED Containment Ltg. XFMR-19 (PNL 2SC2 & 2SC4) 7M THED Neutron Detector Well Fan-10 (a) Primary protection is provided by Gould Tronic TR5 fusible switch with 3.2A fuse.

CPSES - UNITS 1 AND 2 - TRM 13.8-27 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 9 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

4. 480VAC From Panelboards 4.1 Pressurizer 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.

4.2 Pressurizer Heater group C

a. 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.

CPSES - UNITS 1 AND 2 - TRM 13.8-28 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 10 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED 4.3 480VAC From Plant Support Power System Panelboards Both 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 Type System Powered Ckt 2 FH Containment Elevator CP2-MEELRB-01 Ckt 4 KH Containment Welding Receptacles Ckt 6 LH Containment Polar Crane CP2-MESCCP-01 Ckt 1 / Bkr-1 LH Containment Jib Crane CP2-MEMECA-16 Disconnect Switches CP2-ECDSNC-15&16 b) Panelboard 2B10-1-1-1 Device Location Breaker Type System Powered Ckt 4 (b) FH Personnel Airlock Hydraulic Unit #2 (CP2-BSAPPA-02M)

Ckt 6 FH Fuel Transfer System Rx Side Cont. Pnl for TCX-FHSTTS-02 Ckt 10 FH Containment Lighting Xfmr CP2-ELTRNT-14 Ckt 8 FH Manipulator Crane 1-01 TXC-FHSCMC-01 c) Panelboard 2B10-1-2a Device Location Breaker Type System Powered Ckt 1/Bkr-2 FA Containment Jib Crane CP2-MEMECA-16 Disconnect 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.

CPSES - UNITS 1 AND 2 - TRM 13.8-29 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 11 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

5. 120V Space Heater Circuits from 480V Containment Recirc. Fan and CRDM Vent Switchgears Fan Motor Space Heaters

a. Primary Devices - N/A (Fuse)

b. Backup Breakers BKR. LOCATION WESTINGHOUSE

& NUMBER BKR. TYPE Swgr. 2EB1, EB1010 Cubicle 3A, CP2-VAFNAV-01 Space Heater Bkr.

Swgr. 2EB2, EB1010 Cubicle 3A, CP2-VAFNAV-02 Space Heater Bkr.

Swgr. 2EB3, EB1010 Cubicle 9A, CP2-VAFNAV-03 Space Heater Bkr.

Swgr. 2EB4, EB1010 Cubicle 9A, CP2-VAFNAV-04 Space Heater Bkr.

Swgr. 2EB3, EB1010 Cubicle 8A, CP2-VAFNCB-01 Space Heater Bkr.

Swgr. 2EB4, EB1010 Cubicle 8A, CP2-VAFNCB-02 Space Heater Bkr.

CPSES - UNITS 1 AND 2 - TRM 13.8-30 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 12 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

6. 125V DC Control Power Various

a. Primary Devices - N/A (Fuse)

b. Backup Breakers GENERAL ELECTRIC PANELBOARD NO. CKT. NO. BREAKER TYPE XED1-1 6 (c) TED (c)

XED2-1 6 TED 2ED2-1 11,17 TED 2ED1-1 11 TED 2D2-3 6,10,11 TED (a) 2D2-2 9 TED (a) 2ED2-2 12 TED (a) 2ED3-1 5 TED 2ED1-2 7,8 TED (a)

TBX-WPXILP-01 Main(LBK3) (c) FB(Westinghouse)

7. 120V AC Control Power from Isolation XFMR TXEC3 & TXEC4

a. 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 TB3-5

2) 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.

CPSES - UNITS 1 AND 2 - TRM 13.8-31 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 13 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

8. 120 AC Power for Personnel and Emergency Airlocks

a. Primary Devices - N/A (Fuse)

b. Backup Breakers GENERAL ELECTRIC PANELBOARD NO. CKT. NO. BREAKER TYPE XEC1 12 TED XEC2-2 3 TED

9. 118V AC Control Power

a. Primary Devices - N/A (Fuse)

b. Backup Breakers GENERAL ELECTRIC PANELBOARD NO. CKT. NO. BREAKER TYPE 2C2 22 TED (a) 2PC1 10 TED (a) 2PC4 10 TED (a) 2EC1 7 TED (a) 2EC2 4,7 TED(a) 2EC5 8 TED 2EC6 3,8 TED (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.

CPSES - UNITS 1 AND 2 - TRM 13.8-32 Revision 83

Containment Penetration Conductor Overcurrent Protection Devices TR 13.8.32 Table 13.8.32-1b (Page 14 of 14)

Unit 2 Containment Penetration Conductor Overcurrent Protective Devices DEVICE NUMBER SYSTEM AND LOCATION POWERED

10. Emergency Evacuation System Warning Lights Power

a. Primary Devices - N/A (Fuse)

b. Backup Breakers SQUARE D PANELBOARD NO. CKT. NO. BREAKER TYPE XEC4-3 9,10 FY

11. DRPI Data Cabinet Power Supplies

a. Primary Breakers SQUARE D PANELBOARD NO. CKT. NO. BREAKER TYPE 2C14 1,2 FA

b. Backup Breakers SQUARE D PANELBOARD NO. CKT. NO. BREAKER TYPE 2C14 Main Pnl. Bkrs. FA CPSES - UNITS 1 AND 2 - TRM 13.8-33 Revision 83

Decay Time TR 13.9.31 13.9 REFUELING OPERATIONS TR 13.9.31 Decay Time TR LCO 13.9.31 The reactor shall be subcritical for at least 75 hours8.680556e-4 days 0.0208 hours 1.240079e-4 weeks 2.85375e-5 months .

APPLICABILITY: During movement of irradiated fuel in the reactor vessel.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Reactor subcritical for less A.1 Suspend all operations involving Immediately than 75 hours8.680556e-4 days 0.0208 hours 1.240079e-4 weeks 2.85375e-5 months . movement of irradiated fuel in the reactor vessel.

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

CPSES - UNITS 1 AND 2 - TRM 13.9-1 Revision 77

Refueling Operations / Communications TR 13.9.32 13.9 REFUELING OPERATIONS TR 13.9.32 Refueling Operations / Communications TR LCO 13.9.32 Direct communications shall be maintained between the control room and personnel at the refueling station.

APPLICABILITY: During CORE ALTERATIONS.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. No direct communications A.1 Suspend all CORE Immediately between the control room and ALTERATIONS.

personnel at the refueling station.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.9.32.1 Verify direct communications between the control room Once within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and personnel at the refueling station. prior to the start of CORE ALTERATIONS AND 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months CPSES - UNITS 1 AND 2 - TRM 13.9-2 Revision 77

Refueling Machine TR 13.9.33 13.9 REFUELING OPERATIONS TR 13.9.33 Refueling Machine TR LCO 13.9.33 The 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, and

2. 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.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Requirements for hoist A.1 Suspend use of any inoperable Immediately OPERABILITY not hoist from operations involving satisfied. the movement of fuel assemblies and/or latching, unlatching or movement of control rod drive shafts within the reactor vessel.

CPSES - UNITS 1 AND 2 - TRM 13.9-3 Revision 77

Refueling Machine TR 13.9.33 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.9.33.1 The refueling machine main hoist used for movement of Once within 100 fuel assemblies within the reactor vessel shall be hours prior to the demonstrated OPERABLE by performing a load test of start of such at least 2850 pounds and demonstrating an automatic operations load cutoff when the main hoist load exceeds 2800 pounds.

TRS 13.9.33.2 The auxiliary monorail hoist and other hoists and Once within 100 associated load indicators used for latching, unlatching hours prior to the or movement of control rod drive shafts within the start of such reactor vessel shall be demonstrated OPERABLE by operations performing a load test of at least 610 pounds.

CPSES - UNITS 1 AND 2 - TRM 13.9-4 Revision 77

Refueling - Crane Travel - Spent Fuel Storage Areas TR 13.9.34 13.9 REFUELING OPERATIONS TR 13.9.34 Refueling - Crane Travel - Spent Fuel Storage Areas TR LCO 13.9.34 Loads 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 CONDITION REQUIRED ACTION COMPLETION TIME A. Technical Requirement not A.1. Place the crane load in a safe Immediately met. condition.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 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 7 days OPERABLE by performing a load test of at least 2200 pounds.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.9-5 Revision 77

Refueling - Crane Travel - Spent Fuel Storage Areas TR 13.9.34 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY 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 6 months only one trolley-hoist assembly to be operated at a time shall be verified.

CPSES - UNITS 1 AND 2 - TRM 13.9-6 Revision 77

Water Level, Reactor Vessel, Control Rods TR 13.9.35 13.9 REFUELING OPERATIONS TR 13.9.35 Water Level, Reactor Vessel, Control Rods TR LCO 13.9.35 At 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 CONDITION REQUIRED ACTION COMPLETION TIME A. Technical Requirement not A.1 Suspend all operations involving Immediately met. movement of control rods within the reactor vessel.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.9.35.1 The water level shall be determined to be at least its 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months minimum required depth.

AND Once within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months prior to the movement of control rods in MODE 6 CPSES - UNITS 1 AND 2 - TRM 13.9-7 Revision 77

Fuel Storage Area Water Level TR 13.9.36 13.9 REFUELING OPERATIONS TR 13.9.36 Fuel Storage Area Water Level TR LCO 13.9.36 The fuel storage area water level shall be t 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 CONDITION REQUIRED ACTION COMPLETION TIME A. Fuel storage area water A.1 Suspend crane operations with 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months level < 23 feet above loads in the affected fuel storage irradiated fuel assemblies areas and restore the water level seated in the storage racks. to within its limit.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.9.36.1 Verify the fuel storage area water level t 23 ft above the 7 days irradiated fuel assemblies seated in the storage racks.

CPSES - UNITS 1 AND 2 - TRM 13.9-8 Revision 77

Explosive Gas Monitoring Instrumentation TR 13.10.31 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAM TR 13.10.31 Explosive Gas Monitoring Instrumentation TR LCO 13.10.31 Pursuant 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 TR 13.10.34 are not exceeded.

APPLICABILITY: During Waste Gas Holdup System operation on the inservice recombiner.

ACTIONS

- NOTE -

Separate Condition entry is allowed for each recombiner.

CONDITION REQUIRED ACTION COMPLETION TIME A. An explosive gas A.1 Declare channel inoperable. Immediately monitoring instrumentation channel Alarm/Trip Setpoint less conservative than required.

B. Any required channel B.1 Restore the inoperable channel 30 days inoperable. to OPERABLE status.

C. No inlet oxygen monitor C.1 Verify the associated inlet Immediately channel OPERABLE on the hydrogen monitor(s) OPERABLE.

inservice recombiner.

(continued)

CPSES - UNITS 1 AND 2 - TRM 13.10-1 Revision 65

Explosive Gas Monitoring Instrumentation TR 13.10.31 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D. No outlet oxygen monitor D.1 Suspend operation of the Waste Immediately channel OPERABLE on the Gas Holdup System.

inservice recombiner.

OR D.2 Take and analyze grab samples Once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months while maintaining oxygen < 1%

by volume.

E. Less than the required E.1 Suspend oxygen supply to the Immediately hydrogen monitor Channels affected recombiner(s).

OPERABLE on the inservice recombiner. AND OR E.2.1 Suspend addition of waste gas Immediately to the system.

No inlet oxygen monitor channel and no outlet OR oxygen monitor channel OPERABLE on the E.2.2 Take and analyze grab Once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months during inservice recombiner. samples while maintaining degassing oxygen < 1% by volume.

OR OR No inlet oxygen monitor Once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months channel and no inlet during other operations hydrogen monitor channel OPERABLE on the inservice recombiner.

CPSES - UNITS 1 AND 2 - TRM 13.10-2 Revision 65

Explosive Gas Monitoring Instrumentation TR 13.10.31 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.10.31.1 Perform a CHANNEL CHECK of each explosive gas Once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months monitoring instrumentation channel shown in during Waste Gas Table 13.10.31-1. Holdup System operation AND Once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months prior to Waste Gas Holdup System operation.

TRS 13.10.31.2 Perform a CHANNEL OPERATIONAL TEST of each 31 days explosive gas monitoring instrumentation channel shown in Table 13.10.31-1.

TRS 13.10.31.3 Perform a CHANNEL CALIBRATION of each explosive 92 days gas monitoring instrumentation channel shown in Table 13.10.31-1. This shall include the use of standard gas samples in accordance with the manufacturers recommendations.

CPSES - UNITS 1 AND 2 - TRM 13.10-3 Revision 65

Explosive Gas Monitoring Instrumentation TR 13.10.31 Table 13.10.31-1 Explosive Gas Monitoring Instrumentation

INSTRUMENT REQUIRED CHANNELS

1. Waste Gas Holdup System Explosive Gas Monitoring System

a. Hydrogen Monitors 1 per recombiner

b. Oxygen Monitors 2 per recombiner

One hydrogen and two oxygen monitors are required to be OPERABLE for the operating recombiner during Waste Gas HOLDUP System operation CPSES - UNITS 1 AND 2 - TRM 13.10-4 Revision 65

Gas Storage Tanks TR 13.10.32 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAM TR 13.10.32 Gas Storage Tanks TR LCO 13.10.32 Pursuant to TS 5.5.12b, the quantity of radioactivity contained in each gas storage tank shall be d 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.

CONDITION REQUIRED ACTION COMPLETION TIME A. Radioactivity in one or more A.1 Suspend all additions of Immediately storage tank(s) not within radioactive material to the limit. tank(s).

AND A.2 Reduce radioactivity in tank(s) to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months within limit.

AND A.3 ------------------------------------------

- NOTE -

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

Describe events leading to Per TS 5.6.3 exceeding limits in Radioactive Effluent Release Report.

CPSES - UNITS 1 AND 2 - TRM 13.10-5 Revision 65

Gas Storage Tanks TR 13.10.32 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 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 Once within 92 days gas storage tank to verify within limit. after the addition of radioactive material being added to the tank, but not more often than 92 days CPSES - UNITS 1 AND 2 - TRM 13.10-6 Revision 65

Liquid Holdup Tanks TR 13.10.33 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAM TR 13.10.33 Liquid Holdup Tanks TR LCO 13.10.33 Pursuant to TS 5.5.12c, the quantity of radioactive material in each outdoor unprotected tank shall be limited to d10 Curies, excluding tritium and dissolved or entrained noble gases.

APPLICABILITY: At all times.

ACTIONS

- NOTE -

Separate Condition entry allowed for each tank.

CONDITION REQUIRED ACTION COMPLETION TIME A. Quantity of radioactive A.1 Suspend all additions of Immediately.

material in one or more radioactive material to the tanks exceeds limits. tank(s).

AND A.2 Reduce quantity of radioactive 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months material in tank(s) to within limits.

AND A.3 -------------------------------------------

- NOTE -

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

Describe events leading to Per TS 5.6.3 exceeding limits in Radioactive Effluent Release Report.

CPSES - UNITS 1 AND 2 - TRM 13.10-7 Revision 65

Liquid Holdup Tanks TR 13.10.33 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 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 tanks 7 days contents to verify within limits.

CPSES - UNITS 1 AND 2 - TRM 13.10-8 Revision 65

Explosive Gas Mixture TR 13.10.34 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAM TR 13.10.34 Explosive Gas Mixture TR LCO 13.10.34 Pursuant to TS 5.5.12a, the concentration of oxygen in the Waste Gas Holdup system shall be d 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.

CONDITION REQUIRED ACTION COMPLETION TIME A. Oxygen concentration in A.1 Reduce oxygen concentration to 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Waste Gas Holdup system within limits.

> 3% by volume and d 4%

by volume.

B. Oxygen concentration in B.1 Suspend all additions of waste Immediately Waste Gas Holdup System gases to the system.

> 4% by volume.

AND B.2 Reduce oxygen concentration to Immediately d4% by volume.

CPSES - UNITS 1 AND 2 - TRM 13.10-9 Revision 65

Explosive Gas Mixture TR 13.10.34 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY TRS 13.10.34.1 Monitor the hydrogen and oxygen in the Waste Gas As specified in Holdup Systems as specified by TR 13.10.31. TR 13.10.31 CPSES - UNITS 1 AND 2 - TRM 13.10-10 Revision 65

Programs and Manuals 15.5 15.0 ADMINISTRATIVE CONTROLS 15.5 Programs and Manuals TR 15.5.17 TRM - Administrative Control Process

a. 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 Control The 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 Distribution The TRM is considered a controlled document and distribution is controlled by site wide procedures for licensing basis document control.

(continued)

CPSES - UNITS 1 AND 2 - TRM 15.0-1 Revision 83

Programs and Manuals 15.5

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 TRM Changes 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 / Deletions Changes 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 15.5.21 Surveillance Frequency Control Program 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.

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)

CPSES - UNITS 1 AND 2 - TRM 15.0-2 Revision 83

Programs and Manuals 15.5 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)

CPSES - UNITS 1 AND 2 - TRM 15.0-3 Revision 83

Programs and Manuals 15.5 Table 15.5.21-1 (Sheet 1 of 12)

Technical Specification Surveillance Requirement Frequency SURVEILLANCE FREQUENCY SR 3.1.1.1 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 3.1.4.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.1.4.2 92 days SR 3.1.5.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.1.6.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.1.6.3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.1.8.2 30 minutes SR 3.1.8.3 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months SR 3.1.8.4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.2.1.1 [Once after each refueling prior to THERMAL POWER exceeding 75% RTP AND Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after achieving equilibrium conditions after exceeding, by t 20% RTP, the THERMAL POWER at which FQC Z was last verified AND]

31 EFPD thereafter CPSES - UNITS 1 AND 2 - TRM 15.0-4 Revision 83

Programs and Manuals 15.5 Table 15.5.21-1 (Sheet 2 of 12)

Technical Specification Surveillance Requirement Frequency SURVEILLANCE FREQUENCY SR 3.2.1.2 [Once after each refueling prior to THERMAL POWER exceeding 75% RTP AND Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after achieving equilibrium conditions after exceeding, by t20% RTP, the THERMAL POWER at which F QC Z 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.1.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.3.1.2 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 CPSES - UNITS 1 AND 2 - TRM 15.0-5 Revision 83

Programs and Manuals 15.5 Table 15.5.21-1 (Sheet 3 of 12)

Technical Specification Surveillance Requirement Frequency SURVEILLANCE FREQUENCY 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 CPSES - UNITS 1 AND 2 - TRM 15.0-6 Revision 83

Programs and Manuals 15.5 Table 15.5.21-1 (Sheet 4 of 12)

Technical Specification Surveillance Requirement Frequency SURVEILLANCE FREQUENCY 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 t 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and if not performed in previous 92 days SR 3.3.5.2 Prior to entering MODE 4 when in MODE 5 for t 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 CPSES - UNITS 1 AND 2 - TRM 15.0-7 Revision 83

Programs and Manuals 15.5 Table 15.5.21-1 (Sheet 5 of 12)

Technical Specification Surveillance Requirement Frequency SURVEILLANCE FREQUENCY SR 3.3.7.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.1.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.1.3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.1.4 18 months SR 3.4.2.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.3.1 30 minutes SR 3.4.4.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.5.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.5.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.5.3 7 days SR 3.4.6.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.6.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.6.3 7 days SR 3.4.7.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.7.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.7.3 7 days SR 3.4.8.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.8.2 7 days SR 3.4.9.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.9.2 18 months CPSES - UNITS 1 AND 2 - TRM 15.0-8 Revision 83

Programs and Manuals 15.5 Table 15.5.21-1 (Sheet 6 of 12)

Technical Specification Surveillance Requirement Frequency SURVEILLANCE FREQUENCY SR 3.4.11.1 92 days SR 3.4.11.2 18 months SR 3.4.12.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.12.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.12.3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.12.4 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months SR 3.4.12.5 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months SR 3.4.12.8 31 days SR 3.4.12.9 18 months SR 3.4.13.1 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months SR 3.4.13.2 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.4.15.2 92 days CPSES - UNITS 1 AND 2 - TRM 15.0-9 Revision 83

Programs and Manuals 15.5 Table 15.5.21-1 (Sheet 7 of 12)

Technical Specification Surveillance Requirement Frequency SURVEILLANCE FREQUENCY 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 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after a THERMAL POWER change of t 15% RTP within a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period]

SR 3.5.1.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.5.1.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.5.1.3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.5.1.4 31 days

[AND

NOTE---------------------------------

Only required to be performed for affected accumulators Once within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after each solution volume increase of t 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 CPSES - UNITS 1 AND 2 - TRM 15.0-10 Revision 83

Programs and Manuals 15.5 Table 15.5.21-1 (Sheet 8 of 12)

Technical Specification Surveillance Requirement Frequency SURVEILLANCE FREQUENCY SR 3.5.4.1 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.6.5.1 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 CPSES - UNITS 1 AND 2 - TRM 15.0-11 Revision 83

Programs and Manuals 15.5 Table 15.5.21-1 (Sheet 9 of 12)

Technical Specification Surveillance Requirement Frequency SURVEILLANCE FREQUENCY 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 3.7.9.2 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 CPSES - UNITS 1 AND 2 - TRM 15.0-12 Revision 83

Programs and Manuals 15.5 Table 15.5.21-1 (Sheet 10 of 12)

Technical Specification Surveillance Requirement Frequency SURVEILLANCE FREQUENCY 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 CPSES - UNITS 1 AND 2 - TRM 15.0-13 Revision 83

Programs and Manuals 15.5 Table 15.5.21-1 (Sheet 11 of 12)

Technical Specification Surveillance Requirement Frequency SURVEILLANCE FREQUENCY 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 t100% 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months SR 3.9.2.1 31 days SR 3.9.3.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months CPSES - UNITS 1 AND 2 - TRM 15.0-14 Revision 83

Programs and Manuals 15.5 Table 15.5.21-1 (Sheet 12 of 12)

Technical Specification Surveillance Requirement Frequency SURVEILLANCE FREQUENCY SR 3.9.6.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 3.9.6.2 7 days SR 3.9.7.1 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months CPSES - UNITS 1 AND 2 - TRM 15.0-15 Revision 83

Programs and Manuals 15.5 TR 15.5.31 Snubber Inservice Testing/Inspection Program The 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 10CFR Part 50.59.

CPSES - UNITS 1 AND 2 - TRM 15.0-16 Revision 83

CPSES/TRM COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 & 2 TECHNICAL REQUIREMENTS MANUAL (TRM)

EFFECTIVE LISTING FOR SECTIONS Revision Record:

Original Submitted July 21, 1989 Revision 1 September 15, 1989 Revision 2 January 15, 1990 Revision 3 July 20, 1990 Revision 4 April 24, 1991 Revision 5 September 6, 1991 Revision 6 November 22, 1991 Revision 7 March 18, 1992 Revision 8 June 30, 1992 Revision 9 December 18, 1992 Revision 10 January 22, 1993 Revision 11 February 3, 1993 Revision 12 July 15, 1993 Revision 13 September 14, 1993 Revision 14 November 30, 1993 Revision 15 April 15, 1994 Revision 16 May 11, 1994 Revision 17 February 24, 1995 Revision 18 April 14, 1995 Revision 19 May 15, 1995 Revision 20 June 30, 1995 Revision 21 January 24, 1996 Revision 22 February 24, 1997 Revision 23 March 13, 1997 Revision 24 June 26, 1997 Revision 25 July 31, 1997 Revision 26 February 24, 1998 Revision 27 April 14, 1999 Revision 28 April 16, 1999 Revision 29 July 27, 1999 Revision 30 July 27, 1999 Revision 31 August 5, 1999 Revision 32 September 24, 1999 Revision 33 October 7, 1999 Revision 34 June 29, 2000 Revision 35 September 30, 2000 Revision 36 May 30, 2001 Revision 37 August 14, 2001 Revision 38 October 16, 2001 Revision 39 March 27, 2002 Revision 40 August 15, 2002 Revision 41 September 24, 2002 Revision 42 October 11, 2002 CPSES - UNITS 1 AND 2 - TRM EL-1 Revision 84

CPSES/TRM COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 & 2 TECHNICAL REQUIREMENTS MANUAL (TRM)

EFFECTIVE LISTING FOR SECTIONS Revision Record:

Revision 43 January 23, 2003 Revision 44 February 4, 2003 Revision 45 October 7, 2003 Revision 46 February 17, 2004 Revision 47 March 23, 2004 Revision 48 April 23, 2004 Revision 49 September 28, 2004 Revision 50 July 22, 2005 Revision 51 August 4, 2005 Revision 52 September 27, 2005 Revision 53 October 27, 2005 Revision 54 December 29, 2005 Revision 55 February 28, 2006 Revision 56 June 1, 2006 Revision 57 July 27, 2006 Revision 58 September 20, 2006 Revision 59 October 20, 2006 Revision 60 January 18, 2007 Revision 61 January 31, 2007 Revision 62 February 26, 2007 Revision 63 April 11, 2007 Revision 64 June 21, 2007 Revision 65 December 19, 2007 Revision 66 February 28, 2008 Revision 67 March 13, 2008 Revision 68 April 4, 2008 Revision 69 September 11, 2008 Revision 70 November 13, 2008 Revision 71 May 20, 2009 Revision 72 September 29, 2009 Revision 73 March 2, 2010 Revision 74 October 7, 2010 Revision 75 November 30, 2010 Revision 76 February 7, 2011 Revision 77 April 18, 2011 Revision 78 June 9, 2011 Revision 79 December 22, 2011 Revision 80 June 18, 2012 Revision 81 July 24, 2012 Revision 82 September 11, 2012 Revision 83 October 2, 2012 Revision 84 October 30, 2012 CPSES - UNITS 1 AND 2 - TRM EL-2 Revision 84

CPSES/TRM COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 & 2 TECHNICAL REQUIREMENTS MANUAL (TRM)

EFFECTIVE LISTING FOR SECTIONS TRM TOC Revision 82 Section 11.0 Revision 56 Section 13.0 Revision 56 Section 13.1 Revision 82 Section 13.2 Revision 79 Section 13.3 Revision 74 Section 13.4 Revision 56 Section 13.5 Revision 56 Section 13.6 Revision 70 Section 13.7 Revision 83 Section 13.8 Revision 83 Section 13.9 Revision 77 Section 13.10 Revision 65 Section 15.0 Revision 83 CPSES - UNITS 1 AND 2 - TRM EL-3 Revision 84

CPSES/TRM COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 & 2 TECHNICAL REQUIREMENTS MANUAL (TRM)

EFFECTIVE LISTING FOR SECTIONS TRM Bases TOC Revision 84 Section B 13.0 Revision 56 Section B 13.1 Revision 82 Section B 13.2 Revision 79 Section B 13.3 Revision 74 Section B 13.4 Revision 56 Section B 13.5 Revision 84 Section B 13.6 Revision 70 Section B 13.7 Revision 83 Section B 13.8 Revision 83 Section B 13.9 Revision 77 Section B 13.10 Revision 56 Section B 15.0 Revision 83 EL-1 Revision 84 EL-2 Revision 84 EL-3 Revision 84 EL-4 Revision 84 CPSES - UNITS 1 AND 2 - TRM EL-4 Revision 84

Technical 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: All Tables Revised: All Figures 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 - TRM DOC-1 Revision 84

Technical Requirements Manual - Description of Changes REVISION 57 (continued)

LDCR-TR-2006-9 (EVAL-2004-000501-1) (TJE) (continued):

b.) Devise Location Ckt 6, change Breaker Type from F4 to FH Correct 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 manufactures 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 groups 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 vendors 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 diesels preventative maintenance program is commensurate for nuclear standby service, which takes into consideration the following factors: manufacturers recommendations, diesel owners groups 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 vendors 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 - TRM DOC-2 Revision 84

Technical 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:

BACKGROUND This 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 - TRM DOC-3 Revision 84

Technical Requirements Manual - Description of Changes REVISION 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 - TRM DOC-4 Revision 84

Technical Requirements Manual - Description of Changes REVISION 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 - TRM DOC-5 Revision 84

Technical Requirements Manual - Description of Changes REVISION 59 (continued)

APPLICABLE SAFETY ANALYSIS The 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.

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

hydraulic pistons The 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 pistons Individual 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 - TRM DOC-6 Revision 84

Technical Requirements Manual - Description of Changes REVISION 59 (continued)

APPLICABILITY 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.

ACTIONS A.1, A.2, and A.3 This 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months requires that compensatory action be taken within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to ensure that the affected steam line is isolated by other means.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 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.3 This 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months requires that compensatory action be taken within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to ensure that the affected steam line is isolated by other means.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 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 - TRM DOC-7 Revision 84

Technical Requirements Manual - Description of Changes REVISION 59 (continued)

C.1 If 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 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to isolate the turbine from the steam supply.

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 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 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 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 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to place the unit in MODE 4 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 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 SURVEILLANCE The TRS 13.3.33 requirements are modified by a Note that specifies that the provisions of TRS 13.0.4 are not applicable.

TRS 13.3.33.1 This 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 - TRM DOC-8 Revision 84

Technical Requirements Manual - Description of Changes REVISION 59 (continued)

TRS 13.3.33.2 This 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 13.3.33.4 This 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 13.3.33.5 This 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 13.3.33.6 This 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 CPSES - UNITS 1 AND 2 - TRM DOC-9 Revision 84

Technical Requirements Manual - Description of Changes REVISION 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 10.2.3.6

7. 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (or 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months delay. Deletion of the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months delay is consistent with the NRC's expectations as stated in 70FR23252.

CPSES - UNITS 1 AND 2 - TRM DOC-10 Revision 84

Technical Requirements Manual - Description of Changes REVISION 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 - TRM DOC-11 Revision 84

Technical Requirements Manual - Description of Changes REVISION 61 (continued) 4.) Replace the Completion Time of "24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 - TRM DOC-12 Revision 84

Technical Requirements Manual - Description of Changes REVISION 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 CCP Unit Mode BAT Temperature Required BAT Level 1 1-4 "<or=" 110 degree F 63 percent 1 1-4 "<or=" 95 degree F 56 percent 1 1-4 "<or=" 80 degree F 53 percent CPSES - UNITS 1 AND 2 - TRM DOC-13 Revision 84

Technical Requirements Manual - Description of Changes REVISION 64 (continued)

LDCR-TR-2004-9 (EVAL-2003-001212-04) (TJE) (continued):

2 1-4 "<or=" 110 degree F 95 percent 2 1-4 "<or=" 95 degree F 89 percent 2 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 CCP Unit Mode BAT Temperature Required BAT Level 1 1-4 "<or=" 110 degree F 63 percent 1 1-4 "<or=" 95 degree F 56 percent 1 1-4 "<or=" 80 degree F 53 percent 2 1-4 "<or=" 110 degree F 95 percent 2 1-4 "<or=" 95 degree F 89 percent 2 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 - TRM DOC-14 Revision 84

Technical Requirements Manual - Description of Changes REVISION 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 CCP Unit Mode BAT Temperature Required BAT Level 1 1-4 "<or=" 110 degree F 63 percent 1 1-4 "<or=" 95 degree F 56 percent 1 1-4 "<or=" 80 degree F 53 percent 2 1-4 "<or=" 110 degree F 95 percent 2 1-4 "<or=" 95 degree F 89 percent 2 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 CCP Unit Mode BAT Temperature Required BAT Level 1 1-4 "<or=" 110 degree F 63 percent 1 1-4 "<or=" 95 degree F 56 percent 1 1-4 "<or=" 80 degree F 53 percent 2 1-4 "<or=" 110 degree F 95 percent 2 1-4 "<or=" 95 degree F 89 percent 2 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 - TRM DOC-15 Revision 84

Technical Requirements Manual - Description of Changes REVISION 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 - TRM DOC-16 Revision 84

Technical Requirements Manual - Description of Changes REVISION 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 - TRM DOC-17 Revision 84

Technical Requirements Manual - Description of Changes REVISION 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 - TRM DOC-18 Revision 84

Technical 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 0.0278 hours 1.653439e-4 weeks 3.805e-5 months to 75 hours8.680556e-4 days 0.0208 hours 1.240079e-4 weeks 2.85375e-5 months in TR LCO 13.9.31, Condition A, and in TRS 13.9.31.1 Replace 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 - TRM DOC-19 Revision 84

Technical 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 3 2.) 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 - TRM DOC-20 Revision 84

Technical 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 section 2.) Required Actions B.1 and B.3, delete "(3411 MWth), and CPSES - UNITS 1 AND 2 - TRM DOC-21 Revision 84

Technical 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 - TRM DOC-22 Revision 84

Technical 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 - TRM DOC-23 Revision 84

Technical 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 - TRM DOC-24 Revision 84

Technical 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 - TRM DOC-25 Revision 84

Technical 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 - TRM DOC-26 Revision 84

Technical 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 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 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 - TRM DOC-27 Revision 84

Technical 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 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 - TRM DOC-28 Revision 84

Technical 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 17.2.17.2.13 Technical 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-13.7.35.1 Description 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 - TRM DOC-29 Revision 84

Technical 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 - TRM DOC-30 Revision 84

Technical 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 - TRM DOC-31 Revision 84

Technical Requirements Manual - Description of Changes REVISION 83 LDCR-TR-2012-005 (EV-CR-2012-009618-1) (CBC):

Thefrequencyfortheintegratedtestsequence/lossofoffsitepowertestingisrevised

from"18months"to"18monthsonaSTAGGEREDTESTBASIS".AsdocumentedinEV CR201100218621,thischangewasevaluatedandapprovedinaccordancewithTS

5.5.21.

SurveillanceRequirementSource,Number(s)&Description(s):

TechnicalSpecificationsSRslocatedinTRMTable15.5.211:

SRNo.Description

3.5.2.5ECCSFlowpathValveActuationonSafetyInjection

3.5.2.6ECCSPumpActuationonSafetyInjection

3.6.3.8PhaseAValveActuationonSafetyInjection(18152only)

3.7.5.3AFWValveAutomaticActuationonLossofOffsitePower

3.7.5.4MDAFWPumpActuationonSafetyInjection

3.7.7.3CCWPumpActuationonSafetyInjection

3.7.8.3SSWPumpActuationonSafetyInjection

3.7.10.3ControlRoomEmergencyRecirculationonLossofOffsitePower

3.7.12.3PrimaryPlantVentilationActuationonSafetyInjection

3.7.19.2SafetyChilledWaterPumpandChillerandSwitchgearAreaEmergencyFan

CoilUnitActuationonSafetyInjection

3.7.20.3UPSA/CTrainActuationonSafetyInjection

3.8.1.9SingleLargestLoadRejection

3.8.1.10FullLoadRejection

3.8.1.11EmergencyBusLoadShed,DGStart,SequenceandRunonLossofOffsite

Power

3.8.1.13DGNonEmergencyTripSignalsBypassedonLossofOffsitePowerandSafety

Injection

3.8.1.15DGHotRestart

3.8.1.16DGSynchronizationandLoadTransfer

3.8.1.17DGSafetyInjectionOverrideTest

3.8.1.19EmergencyBusLoadShed,DGStart,SequenceandRunonSafetyInjectionin

ConjunctionwithLossofOffsitePower

TechnicalRequirementsManual:

TRSNumberDescription

13.7.37.1SafetyChilledWaterPumpandChillerandSwitchgearAreaEmergencyFan

CoilUnitActuationonSafetyInjection

13.8.31.3Diesel7000KWLoadLimit

TheassociatedTRMBasesarealsoupdated.

CPSES - UNITS 1 AND 2 - TRM DOC-32 Revision 84

Technical 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).

CPSES - UNITS 1 AND 2 - TRM DOC-33 Revision 84

TECHNICAL REQUIREMENTS MANUAL (TRM) BASES FOR COMANCHE PEAK STEAM ELECTRIC STATION UNITS 1 AND 2

Table of Contents B 13.0 TECHNICAL REQUIREMENT APPLICABILITY ..........................................B 13.0-1 B 13.1 REACTIVITY CONTROL SYSTEMS .....................................................B 13.1-1 TRB 13.1.31 Boration Injection System - Operating..............................................B 13.1-1 TRB 13.1.32 Boration Injection System - Shutdown .............................................B 13.1-8 TRB 13.1.37 Rod Group Alignment Limits and Rod Position Indicator .................B 13.1-13 TRB 13.1.38 Control Bank Insertion Limits ...........................................................B 13.1-14 TRB 13.1.39 Rod Position Indication - Shutdown .................................................B 13.1-15 B 13.2 POWER DISTRIBUTION LIMITS...........................................................B 13.2-1 TRB 13.2.31 Moveable Incore Detection System..................................................B 13.2-1 TRB 13.2.32 Axial Flux Difference (AFD) ..............................................................B 13.2-2 TRB 13.2.33 Quadrant Power Tilt Ratio (QPTR) Alarm ........................................B 13.2-3 TRB 13.2.34 Power Distribution Monitoring System .............................................B 13.2-4 B 13.3 INSTRUMENTATION.............................................................................B 13.3-1 TRB 13.3.1 Reactor Trip System (RTS) Instrumentation Response Times ........B 13.3-1 TRB 13.3.2 Engineered Safety Features Actuation System (ESFAS)

Instrumentation Response Times...............................................B 13.3-2 TRB 13.3.5 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation Response Times...............................................B 13.3-3 TRB 13.3.31 Seismic Instrumentation ...................................................................B 13.3-4 TRB 13.3.32 Source Range Neutron Flux .............................................................B 13.3-5 TRB 13.3.33 Turbine Overspeed Protection .........................................................B 13.3-7 TRB 13.3.34 Plant Calorimetric Measurement ......................................................B 13.3-10 B 13.4 REACTOR COOLANT SYSTEM............................................................B 13.4-1 TRB 13.4.14 Reactor Coolant System (RCS) Pressure Isolation Valves ..............B 13.4-1 TRB 13.4.31 Loose Parts Detection System .........................................................B 13.4-2 TRB 13.4.33 Reactor Coolant System (RCS) Chemistry ....................................B 13.4-3 TRB 13.4.34 Pressurizer .......................................................................................B 13.4-4 TRB 13.4.35 Reactor Coolant System (RCS) Vents Specification ........................B 13.4-5 B 13.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)............................B 13.5-1 TRB 13.5.31 ECCS - Containment Debris ............................................................B 13.5-1 TRB 13.5.32 ECCS - Pump Line Flow Rates ........................................................B 13.5-2 B 13.6 CONTAINMENT SYSTEMS...................................................................B 13.6-1 TRB 13.6.3 Containment Isolation Valves ...........................................................B 13.6-1 TRB 13.6.6 Containment Spray System..............................................................B 13.6-2 TRB 13.6.7 Spray Additive System .....................................................................B 13.6-3 B 13.7 PLANT SYSTEMS..................................................................................B 13.7-1 TRB 13.7.2 Main Steam Isolation Valves (MSIVs) ..............................................B 13.7-1 TRB 13.7.3 Feedwater Isolation Valves (FIVs) and Feedwater Control Valves (FCVs) and Associated Bypass Valves ..........................B 13.7-2 TRB 13.7.31 Steam Generator Atmospheric Relief Valve (ARV) -

Air Accumulator Tank .................................................................B 13.7-3 (continued)

CPSES - UNITS 1 AND 2 - TRM Bi Revision 84

Table of Contents (continued)

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

TR LCO and TRS Applicability TRB 13.0 B 13.0 TECHNICAL REQUIREMENT (TR)

LIMITING CONDITION FOR OPERABILITY (TR LCO)

AND TECHNICAL REQUIREMENT SURVEILLANCE (TRS) APPLICABILITY BASES Related information is located in Technical Specification Bases 3.0.

CPSES - UNITS 1 AND 2 - TRM B 13.0-1 Revision 56

Boration Injection System - Operating TRB 13.1.31 B 13.1 REACTIVITY CONTROL SYSTEMS TRB 13.1.31 Boration Injection System - Operating BASES BACKGROUND The 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)

CPSES - UNITS 1 AND 2 - TRM B 13.1-1 Revision 82

Boration Injection System - Operating TRB 13.1.31 BASES BACKGROUND As listed below, the required indicated levels for the boric acid storage (continued) 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.

Tank MODES Ind. Unusable Required Measurement Margin Other Level Volume Volume Uncertainty (gal) (gal) (gal) (gal)

RWST 1, 2, 3, 4 95% 45,494 70,702 4% of span N/A 357,535*

BAT 1, 2, 3, 4 50% 3,221 15,700 6% of span N/A N/A

Additional volume required to meet Technical Specification 3.5.4.

APPLICABLE The Boration Injection System is not assumed to be OPERABLE to SAFETY ANALYSES 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 7000 ppm 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)

CPSES - UNITS 1 AND 2 -TRM B 13.1-2 Revision 82

Boration Injection System - Operating TRB 13.1.31 BASES LCO Two 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 Mode 4), 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 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 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 TS 3.5.2, "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.

APPLICABILITY The 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)

CPSES - UNITS 1 AND 2 -TRM B 13.1-3 Revision 82

Boration Injection System - Operating TRB 13.1.31 BASES ACTIONS A.1 If 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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.1 If 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.2 If 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)

CPSES - UNITS 1 AND 2 -TRM B 13.1-4 Revision 82

Boration Injection System - Operating TRB 13.1.31 BASES LCO C.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 TRS 13.1.31.1 REQUIREMENTS SURVEILLANCE This 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 13.1.31.2 This 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 13.1.31.3 This surveillance requires verification that the BAT boron solution volume is at least 50%. The minimum boron solution volume, along with the (continued)

CPSES - UNITS 1 AND 2 -TRM B 13.1-5 Revision 82

Boration Injection System - Operating TRB 13.1.31 BASES TECHNICAL TRS 13.1.31.3 (continued)

REQUIREMENTS SURVEILLANCE 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 7 day 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 13.1.31.4 Verifying 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 13.1.31.5 Verification 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)

CPSES - UNITS 1 AND 2 -TRM B 13.1-6 Revision 82

Boration Injection System - Operating TRB 13.1.31 BASES TECHNICAL TRS 13.1.31.6 REQUIREMENTS SURVEILLANCE Periodic surveillance testing of CCPs to detect gross degradation caused (continued) 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 13.1.31.7 Periodic 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.

CPSES - UNITS 1 AND 2 -TRM B 13.1-7 Revision 82

Boration Injection System - Shutdown TRB 13.1.32 B 13.1 REACTIVITY CONTROL SYSTEMS TRB 13.1.32 Boration Injection System - Shutdown BASES BACKGROUND 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 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.

Tank MODES Ind. Unusable Required Measurement Margin Other Level Volume Volume Uncertainty (gal) (gal) (gal) (gal)

RWST 5, 6 24% 98,900 7,113 4% of span 10,293 N/A BAT 5, 6 10% 3,221 1,100 6% of span N/A N/A 5, 6 20% 3,221 1,100 6% of span 3,679 N/A (gravity feed)

APPLICABLE The boration subsystem is not assumed to be OPERABLE to mitigate the SAFETY ANALYSES 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)

CPSES - UNITS 1 AND 2 - TRM B 13.1-8 Revision 82

Boration Injection System - Shutdown TRB 13.1.32 BASES APPLICABLE boron concentration, there is no unique requirement that must be SAFETY ANALYSES satisfied. Since it is imperative to raise the boron concentration of the (continued) 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.

LCO In 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)

CPSES - UNITS 1 AND 2 -TRM B 13.1-9 Revision 82

Boration Injection System - Shutdown TRB 13.1.32 BASES LCO b. Either a centrifugal charging pump or positive displacement (continued) charging pump or a safety injection pump (in Mode 6 with the reactor head removed only), and

c. 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.

APPLICABILITY In 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."

ACTIONS A. 1 With 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)

CPSES - UNITS 1 AND 2 -TRM B 13.1-10 Revision 82

Boration Injection System - Shutdown TRB 13.1.32 BASES TECHNICAL TRS 13.1.32.1 REQUIREMENTS SURVEILLANCE This 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 13.1.32.2 See Bases for TRS 13.1.31.1 TRS 13.1.32.3 See Bases for TRS 13.1.31.2 TRS 13.1.32.4 and TRS 13.1.32.5 This 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 7 day 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 13.1.32.7 This 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 7 day 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)

CPSES - UNITS 1 AND 2 -TRM B 13.1-11 Revision 82

Boration Injection System - Shutdown TRB 13.1.32 BASES TECHNICAL TRS 13.1.32.8 REQUIREMENTS SURVEILLANCE See Bases for TRS 13.1.31.4 (continued)

TRS 13.1.32.9 See Bases for TRS 13.1.31.7 TRS 13.1.32.10 See Bases for TRS 13.1.31.6 TRS 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.

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 -TRM B 13.1-12 Revision 82

Rod Group Alignment Limits and Rod Position Indicator TRB 13.1.37 B 13.1 REACTIVITY CONTROL SYSTEMS TRB 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.

CPSES - UNITS 1 AND 2 - TRM B 13.1-13 Revision 82

Control Bank Insertion Limits TRB 13.1.38 B 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.

CPSES - UNITS 1 AND 2 - TRM B 13.1-14 Revision 82

Rod Position Indication - Shutdown TRB 13.1.39 B 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, and

3. 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 d 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 d 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.

CPSES - UNITS 1 AND 2 - TRM B 13.1-15 Revision 82

Moveable Incore Detection System TRB 13.2.31 B 13.2 POWER DISTRIBUTION LIMITS TRB 13.2.31 Moveable Incore Detection System BASES The 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 N

curve. For the purpose of measuring FQ(Z) or F 'H 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.

CPSES - UNITS 1 AND 2 - TRM B 13.2-1 Revision 79

AFD TRB 13.2.32 B 13.2 POWER DISTRIBUTION LIMITS TRB 13.2.32 Axial Flux Difference (AFD)

BASES Related information is located in Technical Specification Bases Section 3.2.3 In 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 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 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.

CPSES - UNITS 1 AND 2 - TRM B 13.2-2 Revision 79

QPTR Alarm TRB 13.2.33 B 13.2 POWER DISTRIBUTION LIMITS TRB 13.2.33 Quadrant Power Tilt Ratio (QPTR) Alarm BASES Related information is located in Technical Specification Bases Section 3.2.4 CPSES - UNITS 1 AND 2 - TRM B 13.2-3 Revision 79

Power Distribution Monitoring System TRB 13.2.34 B 13.2 POWER DISTRIBUTION LIMITS TRB 13.2.34 Power Distribution Monitoring System BASES BACKGROUND The 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 N

to determine the most limiting core peaking factors, F 'H and FQ(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 The PDMS is used for periodic measurement of the core power distribution SAFETY to confirm operation within the design limit, and periodic calibration of the ANALYSES 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).

LCO The 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)

CPSES - UNITS 1 AND 2 - TRM B 13.2-4 Revision 79

Power Distribution Monitoring System TRB 13.2.34 BASES (continued)

APPLICABILITY In 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.

ACTIONS A.1 With 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 TRS 13.2.34.1 REQUIREMENTS SURVEILLANCE Performance 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)

CPSES - UNITS 1 AND 2 -TRM B 13.2-5 Revision 79

Power Distribution Monitoring System TRB 13.2.34 BASES TECHNICAL TRS 13.2.34.1 (continued)

REQUIREMENTS SURVEILLANCE 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 13.2.34.2 Upon 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 knights move.

TRS 13.2.34.3 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)

CPSES - UNITS 1 AND 2 -TRM B 13.2-6 Revision 79

Power Distribution Monitoring System TRB 13.2.34 BASES TECHNICAL TRS 13.2.34.3 and 13.2.34.4 (continued)

REQUIREMENTS SURVEILLANCE 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.

CPSES - UNITS 1 AND 2 -TRM B 13.2-7 Revision 79

RTS Instrumentation Response Times TRB 13.3.1 B 13.3 INSTRUMENTATION TRB 13.3.1 Reactor Trip System (RTS) Instrumentation Response Times BASES The 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.

CPSES - UNITS 1 AND 2 - TRM B 13.3-1 Revision 74

ESFAS Instrumentation Response Times TRB 13.3.2 B 13.3 INSTRUMENTATION TRB 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.

CPSES - UNITS 1 AND 2 - TRM B 13.3-2 Revision 74

LOP DG Start Instrumentation Response Times TRB 13.3.5 B 13.3 INSTRUMENTATION TRB 13.3.5 Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation Response Times 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.

CPSES - UNITS 1 AND 2 - TRM B 13.3-3 Revision 74

Seismic Instrumentation TRB 13.3.31 B 13.3 INSTRUMENTATION TRB 13.3.31 Seismic Instrumentation BASES 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.

CPSES - UNITS 1 AND 2 - TRM B 13.3-4 Revision 74

RTS Instrumentation - Source Range Neutron Flux TRB 13.3.32 B 13.3 INSTRUMENTATION TRB 13.3.32 Reactor Trip System (RTS) Instrumentation - Source Range Neutron Flux BASES Technical 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 TS 3.3.1, 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 BF3 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 both are qualified to Class 1E standards.

(continued)

CPSES - UNITS 1 AND 2 - TRM B 13.3-5 Revision 74

RTS Instrumentation - Source Range Neutron Flux TRB 13.3.32 BASES (continued)

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 CPSES - UNITS 1 AND 2 -TRM B 13.3-6 Revision 74

Turbine Overspeed Protection TRB 13.3.33 B 13.3 INSTRUMENTATION TRB 13.3.33 Turbine Overspeed Protection BASES BACKGROUND This 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)

CPSES - UNITS 1 AND 2 - TRM B 13.3-7 Revision 74

Turbine Overspeed Protection TRB 13.3.33 BASES BACKGROUND

The Turbine AG-95F Digital Protection System consists of three (continued) 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)

CPSES - UNITS 1 AND 2 -TRM B 13.3-8 Revision 74

Turbine Overspeed Protection TRB 13.3.33 BASES BACKGROUND As a backup, the three dedicated Hardware Overspeed Sub-system (continued) 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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)

CPSES - UNITS 1 AND 2 -TRM B 13.3-9 Revision 74

Turbine Overspeed Protection TRB 13.3.33 BASES BACKGROUND System in a manner that precludes two speed channels from being (continued) 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 of a fault/failure is detected during the execution of any of the aforementioned tests.

APPLICABLE The Overspeed Protection System is required to be OPERABLE to SAFETY ANALYSES 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.

LCO The 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)

CPSES - UNITS 1 AND 2 -TRM B 13.3-10 Revision 74

Turbine Overspeed Protection TRB 13.3.33 BASES LCO The minimum operability requirements for the Software Overspeed Sub-(continued) 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 pistons Individual 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.

ACTIONS A.1, A.2, and A.3 This 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months requires that compensatory action be taken within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to ensure that the affected steam line is isolated by other means.

(continued)

CPSES - UNITS 1 AND 2 -TRM B 13.3-11 Revision 74

Turbine Overspeed Protection TRB 13.3.33 BASES ACTIONS A.1, A.2, and A.3 (continued)

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 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.3 This 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months requires that compensatory action be taken within the following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to ensure that the affected steam line is isolated by other means.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 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.1 If 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 0.00167 hours 9.920635e-6 weeks 2.283e-6 months to isolate the turbine from the steam supply.

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 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)

CPSES - UNITS 1 AND 2 -TRM B 13.3-12 Revision 74

Turbine Overspeed Protection TRB 13.3.33 BASES ACTIONS D.1, D.2, and D.3 (continued)

In the event that the aforementioned ACTIONS and associated Completion Times cannot be satisfied, action must be initiated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 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 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to place the unit in MODE 4 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months 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 The TRS 13.3.33 requirements are modified by a Note that specifies that REQUIREMENTS the provisions of TRS 13.0.4 are not applicable.

SURVEILLANCE TRS 13.3.33.1 This 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 13.3.33.2 This 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)

CPSES - UNITS 1 AND 2 -TRM B 13.3-13 Revision 74

Turbine Overspeed Protection TRB 13.3.33 BASES TECHNICAL TRS 13.3.33.3 REQUIREMENTS SURVEILLANCE This TRS has been deleted.

(continued)

TRS 13.3.33.4 This 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 13.3.33.5 This 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 13.3.33.6 This 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)

CPSES - UNITS 1 AND 2 -TRM B 13.3-14 Revision 74

Turbine Overspeed Protection TRB 13.3.33 BASES

REFERENCES:

5. CT-27331, Revision 5, Missile Probability Analysis Methodology (continued) for 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.

CPSES - UNITS 1 AND 2 -TRM B 13.3-15 Revision 74

Plant Calorimetric Measurement TRB 13.3.34 B 13.3 INSTRUMENTATION TRB 13.3.34 Plant Calorimetric Measurement BASES BACKGROUND The 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 MWth 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 MWth. (The accident analyses were performed at a NSSS power of 3650 MWth, including ~16 MWth 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 MWth (100% RTP), and the core power should be reduced to 3411 MWth (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)

CPSES - UNITS 1 AND 2 - TRM B 13.3-16 Revision 74

Plant Calorimetric Measurement TRB 13.3.34 BASES BACKGROUND Nuclear Instrumentation System (NIS) and N-16 Power Monitor channel (continued) 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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)

CPSES - UNITS 1 AND 2 -TRM B 13.3-17 Revision 74

Plant Calorimetric Measurement TRB 13.3.34 BASES (continued)

APPLICABLE The setpoints for those functions of the Reactor Protection System that SAFETY ANALYSES 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.

LCO The 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.

APPLICABILITY The 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.

ACTIONS A.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.3 If 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 SR 3.3.1.2), 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 plants design bases immediately upon performance of SR 3.3.1.2.

(continued)

CPSES - UNITS 1 AND 2 -TRM B 13.3-18 Revision 74

Plant Calorimetric Measurement TRB 13.3.34 BASES ACTIONS B.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 TRS 13.3.34.1 requires that the availability of the LEFM be verified prior REQUIREMENTS to its use for the performance of SR 3.3.1.2. The self-diagnostics SURVEILLANCE 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.

REFERENCES 1. 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 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, 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.

CPSES - UNITS 1 AND 2 -TRM B 13.3-19 Revision 74

RCS Pressure Isolation Valves TRB 13.4.14 B 13.4 REACTOR COOLANT SYSTEM TRB 13.4.14 Reactor Coolant System (RCS) Pressure Isolation Valves BASES Related information is located in Technical Specification Bases 3.4.14.

CPSES - UNITS 1 AND 2 - TRM B 13.4-1 Revision 56

Loose Parts Detection System TRB 13.4.31 B 13.4 REACTOR COOLANT SYSTEM TRB 13.4.31 Loose Parts Detection System BASES The 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.

CPSES - UNITS 1 AND 2 - TRM B 13.4-2 Revision 56

RCS Chemistry TRB 13.4.33 B 13.4 REACTOR COOLANT SYSTEM TRB 13.4.33 Reactor Coolant System (RCS) Chemistry BASES The 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.

CPSES - UNITS 1 AND 2 - TRM B 13.4-3 Revision 56

Pressurizer TRB 13.4.34 B 13.4 REACTOR COOLANT SYSTEM TRB 13.4.34 Pressurizer BASES The 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, Appendix G 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.

CPSES - UNITS 1 AND 2 - TRM B 13.4-4 Revision 56

RCS Vents Specification TRB 13.4.35 B 13.4 REACTOR COOLANT SYSTEM TRB 13.4.35 Reactor Coolant System (RCS) Vents Specification BASES Reactor 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.

CPSES - UNITS 1 AND 2 - TRM B 13.4-5 Revision 56

ECCS - Containment Debris TRB 13.5.31 B 13.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

TRB 13.5.31 ECCS - Containment Debris BASES Related 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.

CPSES - UNITS 1 AND 2 - TRM B 13.5-1 Revision 84

ECCS - Pump Line Flow Rates TRB 13.5.32 B 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, and

2. There is confirmation that the cold leg and hot leg injection line resistances have not changed since the last flow balance test.

CPSES - UNITS 1 AND 2 - TRM B 13.5-2 Revision 84

Containment Isolation Valves TRB 13.6.3 B 13.6 CONTAINMENT SYSTEMS TRB 13.6.3 Containment Isolation Valves BASES The 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 VALVES The 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 10/26/1990

2) Evaluation SE-91-104, approved 11/13/1991 (Includes evaluation of Tech Spec Applicability to Airlock Valves)

3) LDCR TR-90-010, approved 11/20/1991

4) TUE Conference Memorandum TCO-91019, dated 6/10/1991

5) EVAL-2004-003317-01, re: LCO applicability to airlock boundary penetration valves CPSES - UNITS 1 AND 2 - TRM B 13.6-1 Revision 70

Containment Spray System TRB 13.6.6 B 13.6 CONTAINMENT SYSTEMS TRB 13.6.6 Containment Spray System BASES Related information is located in Technical Specification Bases 3.6.6.

CPSES - UNITS 1 AND 2 - TRM B 13.6-2 Revision 70

Spray Additive System TRB 13.6.7 B 13.6 CONTAINMENT SYSTEMS TRB 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 13.6.7.1 This 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 13.6.7.2 To 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 13.6.7.3 This 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)

CPSES - UNITS 1 AND 2 - TRM B 13.6-3 Revision 70

Spray Additive System TRB 13.6.7 BASES TRS 13.6.7.4 This 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.

CPSES - UNITS 1 AND 2 -TRM B 13.6-4 Revision 70

MSIVs TRB 13.7.2 B 13.7 PLANT SYSTEMS TRB 13.7.2 Main Steam Isolation Valves BASES Related information is located in Technical Specification Bases Section 3.7.2.

CPSES - UNITS 1 AND 2 - TRM B 13.7-1 Revision 83

FIVs and FCVs and Associated Bypass Valves TRB 13.7.3 B 13.7 PLANT SYSTEMS TRB 13.7.3 Feedwater Isolation Valves (FIVs) and Feedwater Control Valves (FCVs) and Associated Bypass Valves BASES Related information is located in Technical Specification Bases Section 3.7.3.

CPSES - UNITS 1 AND 2 - TRM B 13.7-2 Revision 83

Steam Generator ARV - Air Accumulator Tank TRB 13.7.31 B 13.7 PLANT SYSTEMS TRB 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.

CPSES - UNITS 1 AND 2 - TRM B 13.7-3 Revision 83

Steam Generator Pressure / Temperature Limitation TRB 13.7.32 B 13.7 PLANT SYSTEMS TRB 13.7.32 Steam Generator Pressure / Temperature Limitation BASES The limitation on steam generator pressure and temperature ensures that the pressure-induced stresses in the steam generators do not exceed the maximum allowable fracture toughness stress limits. The limitations of 70ºF 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.

CPSES - UNITS 1 AND 2 - TRM B 13.7-4 Revision 83

Ultimate Heat Sink - Sediment and SSI Dam TRB 13.7.33 B 13.7 PLANT SYSTEMS TRB 13.7.33 Ultimate Heat Sink - Sediment and Safe Shutdown Impoundment (SSI) Dam BASES The 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.

CPSES - UNITS 1 AND 2 - TRM B 13.7-5 Revision 83

Flood Protection TRB 13.7.34 B 13.7 PLANT SYSTEMS TRB 13.7.34 Flood Protection BASES The 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.

CPSES - UNITS 1 AND 2 - TRM B 13.7-6 Revision 83

Snubbers TRB 13.7.35 B 13.7 PLANT SYSTEMS TRB 13.7.35 Snubbers BASES 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.

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.

CPSES - UNITS 1 AND 2 - TRM B 13.7-7 Revision 83

Area Temperature Monitoring TRB 13.7.36 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)

Area Normal Abnormal Area Monitored Conditions Conditions CRDM Platform Barrier 140 149 General Area CRDM Shroud Exhaust (Unit 2 Only)

CRDM Air Handling Unit Inlet (Unit 1 Only)

Reactor Cavity 135 175 Reactor Cavity Exhaust Detector Well R.C. Pipe Penetration 200 209 General Areas Reactor Cavity Exhaust (N-16 Exhaust Detectors)

CPSES - UNITS 1 AND 2 - TRM B 13.7-8 Revision 83

Safety Chilled Water System - Electrical Switchgear Area Emergency Fan Coil Units TRB 13.7.37 B 13.7 PLANT SYSTEMS TRB 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.

CPSES - UNITS 1 AND 2 - TRM B 13.7-9 Revision 83

Main Feedwater Isolation Valve Pressure / Temperature Limit TRB 13.7.38 B 13.7 PLANT SYSTEMS TRB 13.7.38 Main Feedwater Isolation Valve Pressure / Temperature Limit BASES The fracture toughness requirements are satisfied with a metal temperature of 90ºF 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 90ºF 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 < 90ºF) should be limited to no more than 20% of the valve hydrostatic test pressure (3375 psig X 20% = 675 psig).

CPSES - UNITS 1 AND 2 - TRM B 13.7-10 Revision 83

Tornado Missile Shields TRB 13.7.39 B 13.7 PLANT SYSTEMS TRB 13.7.39 Tornado Missile Shields BASES The 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)

CPSES - UNITS 1 AND 2 - TRM B 13.7-11 Revision 83

Tornado Missile Shields TRB 13.7.39 BASES 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 CPSES - UNITS 1 AND 2 -TRM B 13.7-12 Revision 83

CST Make-up and Reject Line Isolation Valves TRB 13.7.41 B 13.7 PLANT SYSTEMS TRB 13.7.41 Condensate Storage Tank (CST) Make-up and Reject Line Isolation Valves BASES BACKGROUND The 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 The CST provides cooling water to remove decay heat and to cool down SAFETY ANALYSES 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)

CPSES - UNITS 1 AND 2 - TRM B 13.7-13 Revision 83

CST Make-up and Reject Line Isolation Valves TRB 13.7.41 BASES LCO The LCO requires that two CST make-up and reject line isolation valves be OPERABLE to ensure that the valves function to protect the CST.

APPLICABILITY In 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.

ACTIONS A.1 and A.2 With 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and to verify the flowpath isolated every 31 days. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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.1 With 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 0.00111 hours 6.613757e-6 weeks 1.522e-6 months or to isolate the make-up and reject flowpath. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months completion time is reasonable given the low probability of a condenser surge occurring during this time period.

C.1 and C.2 With the completion time of Condition A or B not met, a backup water supply must be determined to be available by administrative means within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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)

CPSES - UNITS 1 AND 2 -TRM B 13.7-14 Revision 83

CST Make-up and Reject Line Isolation Valves TRB 13.7.41 BASES ACTIONS C.1 and C.2 (continued)

(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 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 TRS 13.7.41.1 REQUIREMENTS SURVEILLANCE The 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 13.7.41.2 The surveillance requirement verifies that a make-up and reject line isolation actuation signal is initiated on CST HI-HI level.

CPSES - UNITS 1 AND 2 -TRM B 13.7-15 Revision 83

Decay Time TRB 13.9.31 B 13.9 REFUELING OPERATIONS TRB 13.9.31 Decay Time BASES The 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).

REFERENCES 1. Regulatory Guide 1.195, May 2003

2. Technical Specifications

3. 10CFR100

4. Appendix A to 10CFR50, General Design Criteria 19

5. FSAR Section 15.7.4 CPSES - UNITS 1 AND 2 - TRM B 13.9-1 Revision 77

Refueling Operations / Communications TRB 13.9.32 B 13.9 REFUELING OPERATIONS TRB 13.9.32 Refueling Operations / Communications BASES The 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.

CPSES - UNITS 1 AND 2 - TRM B 13.9-2 Revision 77

Refueling Machine TRB 13.9.33 B 13.9 REFUELING OPERATIONS TRB 13.9.33 Refueling Machine BASES The 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.

CPSES - UNITS 1 AND 2 - TRM B 13.9-3 Revision 77

Refueling - Crane Travel - Spent Fuel Storage Areas TRB 13.9.34 B 13.9 REFUELING OPERATIONS TRB 13.9.34 Refueling - Crane Travel - Spent Fuel Storage Areas BASES LCO The 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.

TECHNICAL TRS 13.9.34.2 REQUIREMENTS SURVEILLANCE 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 - TRM B 13.9-4 Revision 77

Water Level, Reactor Vessel, Control Rods TRB 13.9.35 B 13.9 REFUELING OPERATIONS TRB 13.9.35 Water Level, Reactor Vessel, Control Rods BASES The 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.

CPSES - UNITS 1 AND 2 - TRM B 13.9-5 Revision 77

Fuel Storage Area Water Level TRB 13.9.36 B 13.9 REFUELING OPERATIONS TRB 13.9.36 Fuel Storage Area Water Level BASES The 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.

CPSES - UNITS 1 AND 2 - TRM B 13.9-6 Revision 77

Explosive Gas Monitoring Instrumentation TRB 13.10.31 B 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAM TRB 13.10.31 Explosive Gas Monitoring Instrumentation BASES The 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.

CPSES - UNITS 1 AND 2 - TRM B 13.10-1 Revision 56

Gas Storage Tanks TRB 13.10.32 B 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAM TRB 13.10.32 Gas Storage Tanks BASES The 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.

CPSES - UNITS 1 AND 2 - TRM B 13.10-2 Revision 56

Liquid Holdup Tanks TRB 13.10.33 B 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAM TRB 13.10.33 Liquid Holdup Tanks BASES The 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 10 CFR 20.1001 - 20.2402, at the nearest potable water supply and the nearest surface water supply in an UNRESTRICTED AREA.

CPSES - UNITS 1 AND 2 - TRM B 13.10-3 Revision 56

Explosive Gas Mixture TRB 13.10.34 B 13.10 EXPLOSIVE GAS AND STORAGE TANK RADIOACTIVITY MONITORING PROGRAM TRB 13.10.34 Explosive Gas Mixture BASES This 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.

CPSES - UNITS 1 AND 2 - TRM B 13.10-4 Revision 56

Surveillance Frequency Control Program TRB 15.5.21 B 15.5 PROGRAMS AND MANUALS TRB 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)

CPSES - UNITS 1 AND 2 - TRM B 15.0-1 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 1 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.1.1.1 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months LA 156 BASES:

The Frequency of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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:

SR 3.1.2.1 [Once prior to entering MODE 1 after each LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-2 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 2 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.1.4.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

Verification that individual rod positions are within alignment limits at a Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 0.00111 hours 6.613757e-6 weeks 1.522e-6 months 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:

SR 3.1.4.2 92 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-3 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 3 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.1.5.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is adequate to ensure that they are within their insertion limits. Also, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency takes into account other information available in the control room for the purpose of monitoring the status of shutdown rods.

Revised BASES:

SR 3.1.6.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

Verification of the control bank insertion limits at a Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

Revised BASES:

SR 3.1.6.3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

A Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is consistent with the insertion limit check above in SR 3.1.6.2.

Revised BASES CPSES - UNITS 1 AND 2 - TRM B 15.0-4 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 4 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.1.8.2 30 minutes LA 156 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:

SR 3.1.8.3 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months LA 156 BASES:

Verification of the THERMAL POWER at a Frequency of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months during the performance of the PHYSICS TESTS will ensure that the initial conditions of the safety analyses are not violated.

Revised BASES:

SR 3.1.8.4 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months LA 156 BASES:

The Frequency of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-5 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 5 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.2.1.1 [Once after each refueling prior to LA 156 THERMAL POWER exceeding 75% RTP AND Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after achieving equilibrium conditions after exceeding, by >

20% RTP, the THERMAL POWER at which C

FQ Z 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 CPSES - UNITS 1 AND 2 - TRM B 15.0-6 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 6 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.2.1.2 [Once after each refueling prior to LA 156 THERMAL POWER exceeding 75% RTP AND Once within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after achieving equilibrium conditions after exceeding, by >

20% RTP, the THERMAL POWER at which C

FQ Z 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 FQ(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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-7 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 7 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.2.2.1 [Once after each refueling prior to LA 156 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 N

enough that the F 'H limit cannot be exceeded for any significant period of operation.

Revised BASES:

SR 3.2.3.1 7 days LA 156 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:

SR 3.2.4.1 7 days LA 156 BASES:

The Frequency of 7 days takes into account other information and alarms available to the operator in the control room.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-8 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 8 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.2.4.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

Performing SR3.2.4.2 at a Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months provides an accurate alternative means for ensuring that any tilt remains within its limits.

Revised BASES:

SR 3.3.1.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-9 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 9 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.1.2 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months LA 156 BASES:

The Frequency of every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period.

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

Revised BASES:

SR 3.3.1.3 31 effective full power days (EFPD) LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-10 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 10 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.1.4 62 days on a STAGGERED TEST BASIS LA 156 BASES:

The Frequency of every 62 days on a STAGGERED TEST BASIS is justified in Reference 12.

Revised BASES:

SR 3.3.1.5 92 days on a STAGGERED TEST BASIS LA 156 BASES:

The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 12.

Revised BASES:

SR 3.3.1.6 92 EFPD LA 156 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:

SR 3.3.1.7 184 days LA 156 BASES:

The Frequency of 184 days is justified in Reference 12.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-11 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 11 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.1.8 [-------------------------NOTE------------------------ LA 156 Only required when not performed within previous] 184 days

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

Prior to reactor startup AND 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

SR 3.3.1.9 92 days LA 156 BASES:

SR3.3.1.9 is the performance of a TADOT and is performed every 92 days, as justified in Reference 5.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-12 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 12 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.1.10 18 months LA 156 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:

SR 3.3.1.11 18 months LA 156 BASES:

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

Revised BASES:

SR 3.3.1.13 18 months LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-13 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 13 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.1.14 18 months LA 156 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:

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

Not stated.

Revised BASES:

SR 3.3.1.16 18 months on a STAGGERED TEST BASIS LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-14 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 14 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.2.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 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:

SR 3.3.2.2 92 days on a STAGGERED TEST BASIS LA 156 BASES:

The Frequency of every 92 days on a STAGGERED TEST BASIS is justified in Reference 13.

Revised BASES:

SR 3.3.2.4 92 days on a STAGGERED TEST BASIS LA 156 BASES:

The Frequency of 92 days on a STAGGERED TEST BASIS is justified in Reference 13.

Revised BASES:

SR 3.3.2.5 184 days LA 156 BASES:

The Frequency of 184 days is justified in Reference 13.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-15 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 15 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.2.6 92 days LA 156 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:

SR 3.3.2.7 31 days LA 156 BASES:

The Frequency is adequate. It is based on industry operating experience, considering instrument reliability and operating history data.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-16 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 16 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.2.8 18 months LA 156 BASES:

The Frequency is adequate, based on industry operating experience and is consistent with the typical refueling cycle.

Revised BASES:

SR 3.3.2.9 18 months LA 156 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:

SR 3.3.2.10 18 months on a STAGGERED TEST BASIS LA 156 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:

SR 3.3.2.11 18 months LA 156 BASES:

This Frequency is based on operating experience.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-17 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 17 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.3.1 31 days LA 156 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:

SR 3.3.3.3 18 months LA 156 BASES:

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

Revised BASES:

SR 3.3.4.1 31 days LA 156 BASES:

The Frequency of 31 days is based upon operating experience which demonstrates that channel failure is rare.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-18 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 18 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.4.2 18 months LA 156 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:

SR 3.3.4.3 18 months LA 156 BASES:

The Frequency of 18 months is based upon operating experience and consistency with the typical industry refueling cycle.

Revised BASES:

SR 3.3.5.1 Prior to entering MODE 4 when in MODE 5 LA 156 for t72 hours 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-19 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 19 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.5.2 Prior to entering MODE 4 when in MODE 5 LA 156 for t72 hours 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:

SR 3.3.5.3 18 months LA 156 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:

SR 3.3.5.4 18 months on a STAGGERED TEST BASIS LA 156 BASES:

Not stated.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-20 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 20 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.6.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency is based on operating experience that demonstrates channel failure is rare.

Revised BASES:

SR 3.3.6.2 92 days on a STAGGERED TEST BASIS LA 156 BASES:

The Surveillance interval is justified in Reference 4.

Revised BASES:

SR 3.3.6.3 92 days on a STAGGERED TEST BASIS LA 156 BASES:

The Surveillance interval is justified in Reference 4.

Revised BASES:

SR 3.3.6.4 92 days LA 156 BASES:

The Frequency is based on the staff recommendation for increasing the availability of radiation monitors according to NUREG-1366 (Ref.2).

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-21 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 21 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.6.5 92 days LA 156 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 experienceThe (18 month)

Frequency is based on the slave relay reliability assessment presented in Reference 3.

Revised BASES:

SR 3.3.6.7 18 months LA 156 BASES:

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

Revised BASES:

SR 3.3.7.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency is based on operating experience that demonstrates channel failure is rare.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-22 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 22 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.3.7.2 92 days LA 156 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:

SR 3.3.7.6 18 months LA 156 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:

SR 3.3.7.7 18 months LA 156 BASES:

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

Revised BASES:

SR 3.4.1.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-23 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 23 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.1.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

SR 3.4.1.3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

SR 3.4.1.4 18 months LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-24 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 24 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.2.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The SR to verify operating RCS loop average temperatures every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

SR 3.4.3.1 30 minutes LA 156 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:

SR 3.4.4.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient considering other indications and alarms available to the operator in the control room to monitor RCS loop performance.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-25 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 25 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.5.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient considering other indications and alarms available to the operator in the control room to monitor RCS loop performance.

Revised BASES:

SR 3.4.5.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room to alert the operator to a loss of SG level.

Revised BASES:

SR 3.4.5.3 7 days LA 156 BASES:

Not stated.

Revised BASES:

SR 3.4.6.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient considering other indications and alarms available to the operator in the control room to monitor RCS and RHR loop performance.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-26 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 26 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.6.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room to alert the operator to the loss of SG level.

Revised BASES:

SR 3.4.6.3 7 days LA 156 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:

SR 3.4.7.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient considering other indications and alarms available to the operator in the control room to monitor RHR loop performance.

Revised BASES:

SR 3.4.7.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room to alert the operator to the loss of SG level.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-27 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 27 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.7.3 7 days LA 156 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:

SR 3.4.8.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient considering other indications and alarms available to the operator in the control room to monitor RHR loop performance.

Revised BASES:

SR 3.4.8.2 7 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-28 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 28 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.9.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

SR 3.4.9.2 18 months LA 156 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:

SR 3.4.11.1 92 days LA 156 BASES:

The basis for the Frequency of 92 days is the ASME Code (Ref.3).

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-29 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 29 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.11.2 18 months LA 156 BASES:

The Frequency of 18 months is based on a typical refueling cycle and industry accepted practice.

Revised BASES:

SR 3.4.12.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

SR 3.4.12.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-30 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 30 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.12.3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

SR 3.4.12.4 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months LA 156 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:

SR 3.4.12.5 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for unlocked open vent valve(s) LA 156 AND 31 days for locked open vent valve(s)

BASES:

Not stated.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-31 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 31 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.12.6 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months LA 156 BASES:

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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:

SR 3.4.12.8 31 days LA 156 BASES:

Not stated.

Revised BASES:

SR 3.4.12.9 18 months LA 156 BASES:

Not stated.

Revised BASES:

SR 3.4.13.1 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months LA 156 BASES:

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is a reasonable interval to trend LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-32 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 32 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.13.2 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months LA 156 BASES:

The Surveillance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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:

SR 3.4.14.1 In accordance with the Inservice Testing LA 156 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 CPSES - UNITS 1 AND 2 - TRM B 15.0-33 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 33 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.14.2 18 months LA 156 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:

SR 3.4.15.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is based on instrument reliability and is reasonable for detecting off normal conditions.

Revised BASES:

SR 3.4.15.2 92 days LA 156 BASES:

The Frequency of 92 days considers instrument reliability, and operating experience has shown that it is proper for detecting degradation.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-34 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 34 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.15.3 18 months LA 156 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:

SR 3.4.15.4 18 months LA 156 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:

SR 3.4.15.5 18 months LA 156 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:

SR 3.4.16.1 7 days LA 156 BASES:

The 7 day Frequency considers the unlikelihood of a gross fuel failure during the time.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-35 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 35 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.4.16.2 14 days LA 156

[AND Between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after a THERMAL POWER change of t15% RTP within a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 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:

SR 3.5.1.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

This Frequency is considered reasonable in view of other administrative controls that ensure a mispositioned isolation valve is unlikely.

Revised BASES:

SR 3.5.1.2 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-36 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 36 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.5.1.3 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

SR 3.5.1.4 31 days LA 156

[AND

NOTE-----------------------

Only required to be performed for affected accumulators Once within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after each solution volume increase of t 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-37 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 37 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.5.1.5 31 days LA 156 BASES:

Since power is removed under administrative control, the 31 day Frequency will provide adequate assurance that power is removed.

Revised BASES:

SR 3.5.2.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES: A 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered reasonable in view of other administrative controls that will ensure a mispositioned valve is unlikely.

Revised BASES:

SR 3.5.2.2 31 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-38 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 38 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.5.2.5 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month Frequency is based on the LA 156 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 EV-CR-2011-002186-21 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.

CPSES - UNITS 1 AND 2 - TRM B 15.0-39 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 39 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.5.2.6 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month Frequency is based on the LA 156 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 EV-CR-2011-002186-21 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.

SR 3.5.2.7 18 months LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-40 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 40 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.5.2.8 18 months LA 156 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:

SR 3.5.4.1 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months LA 156 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:

SR 3.5.4.2 7 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-41 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 41 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.5.4.3 7 days LA 156 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:

SR 3.5.5.1 31 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-42 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 42 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.6.2.2 24 months LA 156 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:

SR 3.6.3.1 31 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-43 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 43 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.6.3.3 31 days LA 156 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:

SR 3.6.3.7 18 months LA 156 BASES:

Not stated.

Revised BASES:

SR 3.6.3.8 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

Operating experience has shown that these LA 156 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 EV-CR-2011-002186-21 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.

CPSES - UNITS 1 AND 2 - TRM B 15.0-44 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 44 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.6.4.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency of this SR was developed based on operating experience related to trending of containment pressure variations during the applicable MODES.

Furthermore, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal containment pressure condition.

Revised BASES:

SR 3.6.5.1 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months LA 156 BASES:

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal containment temperature condition.

Revised BASES:

SR 3.6.6.1 31 days LA 156 BASES:

Not stated.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-45 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 45 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.6.6.5 18 months LA 156 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:

SR 3.6.6.6 18 months LA 156 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:

SR 3.7.2.2 18 months LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-46 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 46 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.7.3.2 18 months LA 156 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:

SR 3.7.5.1 31 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-47 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 47 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.7.5.3 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month Frequency is based on the LA 156 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 EV-CR-2011-002186-21 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.

CPSES - UNITS 1 AND 2 - TRM B 15.0-48 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 48 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.7.5.4 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month Frequency is based on the LA 156 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 EV-CR-2011-002186-21 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.

SR 3.7.6.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-49 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 49 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.7.7.1 31 days LA 156 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:

SR 3.7.7.2 18 months LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-50 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 50 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.7.7.3 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month Frequency is based on the LA 156 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 EV-CR-2011-002186-21 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.

SR 3.7.8.1 31 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-51 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 51 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.7.8.2 92 days LA 156 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:

SR 3.7.8.3 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month Frequency is based on the LA 156 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 EV-CR-2011-002186-21 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.

CPSES - UNITS 1 AND 2 - TRM B 15.0-52 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 52 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.7.9.1 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months LA 156 BASES:

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.

Revised BASES:

SR 3.7.9.2 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months LA 156 BASES:

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.

Revised BASES:

SR 3.7.10.1 31 days LA 156 BASES:

The 31 day Frequency is based on the reliability of the equipment and the two train redundancy.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-53 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 53 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.7.10.3 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The Frequency of 18 months is based on LA 156 industry operating experience and is consistent with the typical refueling cycle.

Revised BASES: The frequency for the EV-CR-2011-002186-21 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.

SR 3.7.11.1 18 months LA 156 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:

SR 3.7.12.1 31 days LA 156 BASES:

The 31 day Frequency is based on the known reliability of equipment and the two train redundancy available.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-54 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 54 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.7.12.3 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month Frequency is consistent with LA 156 that specified in Reference 4.

Revised BASES:

The frequency for the integrated test EV-CR-2011-002186-21 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.

SR 3.7.12.4 18 months on a STAGGERED TEST BASIS LA 156 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:

SR 3.7.12.6 18 months LA 156 BASES:

A frequency of 18 months is consistent with SR 3.7.12.3.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-55 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 55 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.7.15.1 7 days LA 156 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:

SR 3.7.16.1 7 days LA 156 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:

SR 3.7.18.1 31 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-56 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 56 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.7.19.1 31 days LA 156 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:

SR 3.7.19.2 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

Operating experience has shown that these LA 156 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 EV-CR-2011-002186-21 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.

SR 3.7.20.1 31 days LA 156 BASES:

Not stated.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-57 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 57 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.7.20.2 31 days LA 156 BASES:

Not stated.

Revised BASES:

SR 3.7.20.3 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month frequency is consistent with LA 156 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 EV-CR-2011-002186-21 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.

SR 3.8.1.1 7 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-58 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 58 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.1.2 31 days LA 156 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:

SR 3.8.1.3 31 days LA 156 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:

SR 3.8.1.4 31 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-59 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 59 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.1.5 31 days LA 156 BASES:

The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref.10). This SR is for preventative maintenance.

Revised BASES:

SR 3.8.1.6 92 days LA 156 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:

SR 3.8.1.7 184 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-60 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 60 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.1.8 18 months LA 156 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:

SR 3.8.1.9 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month Frequency is consistent with LA 156 the recommendation of Regulatory Guide 1.108 (Ref. 9).

Revised BASES:

The frequency for the integrated test EV-CR-2011-002186-21 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.

CPSES - UNITS 1 AND 2 - TRM B 15.0-61 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 61 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.1.10 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month Frequency is consistent with LA 156 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 EV-CR-2011-002186-21 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.

SR 3.8.1.11 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The Frequency of 18 months is consistent LA 156 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 EV-CR-2011-002186-21 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.

CPSES - UNITS 1 AND 2 - TRM B 15.0-62 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 62 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.1.12 18 months LA 156 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:

SR 3.8.1.13 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month Frequency is based on LA 156 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 EV-CR-2011-002186-21 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.

CPSES - UNITS 1 AND 2 - TRM B 15.0-63 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 63 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.1.14 18 months LA 156 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:

SR 3.8.1.15 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month Frequency is consistent with LA 156 the recommendations of Regulatory Guide 1.9 (Ref.3).

Revised BASES:

The frequency for the integrated test EV-CR-2011-002186-21 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.

CPSES - UNITS 1 AND 2 - TRM B 15.0-64 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 64 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.1.16 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The Frequency of 18 months is consistent LA 156 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 EV-CR-2011-002186-21 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.

SR 3.8.1.17 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The 18 month Frequency is consistent with LA 156 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 EV-CR-2011-002186-21 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.

CPSES - UNITS 1 AND 2 - TRM B 15.0-65 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 65 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.1.18 18 months LA 156 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:

SR 3.8.1.19 18 months on a STAGGERED TEST BASIS EV-CR-2011-002186-21 BASES:

The Frequency of 18 months takes into LA 156 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 EV-CR-2011-002186-21 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.

SR 3.8.1.20 10 years LA 156 BASES:

The 10 year Frequency is consistent with the recommendations of Regulatory Guide 1.108 (Ref. 9).

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-66 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 66 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.1.21 18 months LA 156 BASES:

Not stated.

Revised BASES:

SR 3.8.1.22 31 days on a STAGGERED TEST BASIS LA 156 BASES:

Not stated.

Revised BASES:

SR 3.8.3.1 31 days LA 156 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:

SR 3.8.3.2 31 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-67 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 67 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.3.4 31 days LA 156 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:

SR 3.8.3.5 31 days LA 156 BASES:

The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 2).

Revised BASES:

SR 3.8.4.1 7 days LA 156 BASES:

The 7 day Frequency is consistent with manufacturer recommendations and IEEE-450 (Ref. 8).

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-68 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 68 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.4.2 18 months LA 156 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:

SR 3.8.4.3 18 months LA 156 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:

SR 3.8.6.1 7 days LA 156 BASES:

The 7 day Frequency is consistent with IEEE-450 (Ref. 4).

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-69 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 69 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.6.2 31 days LA 156 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:

SR 3.8.6.3 31 days LA 156 BASES:

The Frequency is consistent with IEEE-450 (Ref. 4).

Revised BASES:

SR 3.8.6.4 31 days LA 156 BASES:

The Frequency is consistent with IEEE-450 (Ref. 4).

Revised BASES:

SR 3.8.6.5 92 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-70 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 70 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.6.6 60 months LA 156

[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 t100% of manufacturer's rating]

BASES:

This frequency is consistent with the recommendations in IEEE-450 (Ref. 4).

Revised BASES:

SR 3.8.7.1 7 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-71 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 71 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.8.8.1 7 days LA 156 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:

SR 3.8.9.1 7 days LA 156 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:

SR 3.8.10.1 7 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-72 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 72 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.9.1.1 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months LA 156 BASES:

A minimum Frequency of once every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months 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 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to be adequate.

Revised BASES:

SR 3.9.2.1 31 days LA 156 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:

SR 3.9.3.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is consistent with the CHANNEL CHECK Frequency specified similarly for the same instruments in LCO 3.3.1.

Revised BASES:

CPSES - UNITS 1 AND 2 - TRM B 15.0-73 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 73 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.9.3.2 18 months LA 156 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:

SR 3.9.4.1 7 days LA 156 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-74 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 74 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.9.4.2 7 days LA 156 BASES:

The Surveillance interval is selected to be commensurate with the normal duration of time to complete the fuel handling operationsThe 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:

SR 3.9.4.3 18 months LA 156 BASES:

The 18 month Frequency maintains consistency with other similar instrumentation and valve testing requirements.

Revised BASES:

SR 3.9.5.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-75 Revision 83

Surveillance Frequency Control Program TRB 15.5.21 Table B 15.5.21-1 (Sheet 75 of 75)

Technical Specification Surveillance Requirement Frequencies SURVEILLANCE FREQUENCY REFERENCE SR 3.9.6.1 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months LA 156 BASES:

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months 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:

SR 3.9.6.2 7 days LA 156 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:

SR 3.9.7.1 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months LA 156 BASES:

The Frequency of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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:

CPSES - UNITS 1 AND 2 - TRM B 15.0-76 Revision 83