NUREG-1432 

 Vol 2, Rev. 3.0 

Standard Technical Specifications 

Combustion Engineering Plants

Bases

Manuscript Completed: March 2004 

Date Published: June 2004 

Division of Regulatory Improvement Programs 

Office of Nuclear Reactor Regulation 

U.S. Nuclear Regulatory Commission 

Washington, DC 20555-0001
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CEOG STS iii Rev. 3.0, 03/31/04 

PREFACE 

This NUREG contains the improved Standard Technical Specifications (STS) for Combustion 

Engineering plants. Revision 3 incorporates the cumulative changes to Revision 1 and 2, which 

was published in April 1995 and April 2001, respectively. The changes reflected in Revision 3 

resulted from the experience gained from license amendment applications to convert to these 

improved STS or to adopt partial improvements to existing technical specifications. This 

publication is the result of extensive public technical meetings and discussions among the 

Nuclear Regulatory Commission (NRC) staff and various nuclear power plant licensees, Nuclear 

Steam Supply System (NSSS) Owners Groups, and the Nuclear Energy Institute (NEI). The 

improved STS were developed based on the criteria in the Final Commission Policy Statement 

on Technical Specifications Improvements for Nuclear Power Reactors, dated July 22, 1993 

(58 FR 39132), which was subsequently codified by changes to Section 36 of Part 50 of Title 10 

of the Code of Federal Regulations (10 CFR 50.36) (60 FR 36953). Licensees are encouraged 

to upgrade their technical specifications consistent with those criteria and conforming, to the 

practical extent, to Revision 3 to the improved STS. The Commission continues to place the 

highest priority on requests for complete conversions to the improved STS. Licensees adopting 

portions of the improved STS to existing technical specifications should adopt all related 

requirements, as applicable, to achieve a high degree of standardization and consistency. 

The Table of Contents is now a Table of Contents / Revision Summary where the revision 

number and date are listed for each specification and bases, in lieu of traditional page numbers. 

Each limiting condition for operation (LCO) starts with page 1, with a specification, e.g., "2.0" or 

bases "B 2.0" number prefix. Subsequent approved revisions to sections will be noted in the 

Table of Contents, as well as on each affected page, using a decimal number to indicate the 

number of revisions to that section, along with the date, e.g., (Rev 3.3, 04/01/04) indicates the 

third approved change and date since Revision 3.0 was published. Additionally, the final page 

of each LCO section will be a historical listing of the changes affecting that section. This 

publication will be maintained in electronic format. Subsequent revisions will not be printed in 

hard copy. Users may access the subsequent revisions to the STS in the PDF format at 

(http://www.nrc.gov/NRR/sts/sts.htm). This Web site will be updated as needed and the 

contents may differ from the last printed version. Users may print or download copies from the 

NRC Web site. 

PAPERWORK REDUCTION ACT STATEMENT 

The information collections contained in this NUREG are covered by the requirements of 

10 CFR Parts 20 and 50, which were approved by the Office of Management and Budget, 

approval numbers 3150-0014 and 0011. 

PUBLIC PROTECTION NOTIFICATION 

If a means used to impose an information collection does not display a currently valid OMB 

control number, the NRC may not conduct or sponsor, and a person is not required to respond 

to, the information collection. 
CEOG STS v Rev. 3.0, 03/31/04 

TABLE OF CONTENTS / REVISION SUMMARY Revision - Date 

B 2.0 SAFETY LIMITS (SLs) 

B 2.1.1 Reactor Core SLs (Analog) ................................................................3.0, 03/31/04 

B 2.1.2 Reactor Coolant System (RCS) Pressure SL (Analog) ......................3.0, 03/31/04 

B 2.1.1 Reactor Core SLs (Digital) .................................................................3.0, 03/31/04 

B 2.1.2 Reactor Coolant System (RCS) Pressure SL 

 (Digital) .........................................................................................3.0, 03/31/04 

B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY ..........3.0, 03/31/04 

B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY .........................3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.1 SHUTDOWN MARGIN (SDM) (Analog).............................................3.0, 03/31/04 

B 3.1.2 Reactivity Balance (Analog) ...............................................................3.0, 03/31/04 

B 3.1.3 Moderator Temperature Coefficient (MTC) (Analog)..........................3.0, 03/31/04 

B 3.1.4 Control Element Assembly (CEA) Alignment (Analog).......................3.0, 03/31/04 

B 3.1.5 Shutdown Control Element Assembly (CEA) Insertion Limits 

 (Analog)........................................................................................3.0, 03/31/04 

B 3.1.6 Regulating Control Element Assembly (CEA) Insertion Limits 

 (Analog)........................................................................................3.0, 03/31/04 

B 3.1.7 Special Test Exception (STE) - SHUTDOWN MARGIN (SDM) 

 (Analog)........................................................................................3.0, 03/31/04 

B 3.1.8 Special Test Exceptions (STE) - MODES 1 and 2 (Analog)...............3.0, 03/31/04 

B 3.1.1 SHUTDOWN MARGIN (SDM) (Digital) ..............................................3.0, 03/31/04 

B 3.1.2 Reactivity Balance (Digital) ................................................................3.0, 03/31/04 

B 3.1.3 Moderator Temperature Coefficient (MTC) (Digital)...........................3.0, 03/31/04 

B 3.1.4 Control Element Assembly (CEA) Alignment (Digital)........................3.0, 03/31/04 

B 3.1.5 Shutdown Control Element Assembly (CEA) Insertion Limits 

 (Digital) .........................................................................................3.0, 03/31/04 

B 3.1.6 Regulating Control Element Assembly (CEA) Insertion Limits 

 (Digital) .........................................................................................3.0, 03/31/04 

B 3.1.7 Part Length Control Element Assembly (CEA) Insertion Limits 

 (Digital) .........................................................................................3.0, 03/31/04 

B 3.1.8 Special Test Exceptions (STE) - SHUTDOWN MARGIN (SDM) 

 (Digital) .........................................................................................3.0, 03/31/04 

B 3.1.9 Special Test Exceptions (STE) - MODES 1 and 2 (Digital)................3.0, 03/31/04 

B 3.2 POWER DISTRIBUTION LIMITS 

B 3.2.1 Linear Heat Rate (LHR) (Analog) .......................................................3.0, 03/31/04 

B 3.2.2 Total Planar Radial Peaking Factor (FT

xy) (Analog) .............................3.0, 03/31/04 

B 3.2.3 Total Integrated Radial Peaking Factor (FT

xy) (Analog) .......................3.0, 03/31/04 

B 3.2.4 AZIMUTHAL POWER TILT (Tq) (Analog)...........................................3.0, 03/31/04 

B 3.2.5 AXIAL SHAPE INDEX (ASI) (Analog) ................................................3.0, 03/31/04 

B 3.2.1 Linear Heat Rate (LHR) (Digital) ........................................................3.0, 03/31/04 

B 3.2.2 Planar Radial Peaking Factors (Fxy) (Digital)......................................3.0, 03/31/04 
CEOG STS vi Rev. 3.0, 03/31/04 

TABLE OF CONTENTS / REVISION SUMMARY Revision - Date 

B 3.2 POWER DISTRIBUTION LIMITS (continued) 

B 3.2.3 AZIMUTHAL POWER TILT (Tq) (Digital)............................................3.0, 03/31/04 

B 3.2.4 Departure from Nucleate Boiling Ratio (DNBR) (Digital)....................3.0, 03/31/04 

B 3.2.5 AXIAL SHAPE INDEX (ASI) (Digital)..................................................3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.1 Reactor Protective System (RPS) Instrumentation - Operating 

 (Analog)........................................................................................3.0, 03/31/04 

B 3.3.2 Reactor Protective System (RPS) Instrumentation - Shutdown 

 (Analog)........................................................................................3.0, 03/31/04 

B 3.3.3 Reactor Protective System (RPS) Logic and Trip Initiation 

 (Analog)........................................................................................3.0, 03/31/04 

B 3.3.4 Engineered Safety Features Actuation System (ESFAS) 

 Instrumentation (Analog) ..............................................................3.0, 03/31/04 

B 3.3.5 Engineered Safety Features Actuation System (ESFAS) Logic 

 and Manual Trip (Analog).............................................................3.0, 03/31/04 

B 3.3.6 Diesel Generator (DG) - Loss of Voltage Start (LOVS) (Analog) .......3.0, 03/31/04 

B 3.3.7 Containment Purge Isolation Signal (CPIS) (Analog).........................3.0, 03/31/04 

B 3.3.8 Control Room Isolation Signal (CRIS) (Analog) .................................3.0, 03/31/04 

B 3.3.9 Chemical and Volume Control System (CVCS) Isolation Signal 

 (Analog)........................................................................................3.0, 03/31/04 

B 3.3.10 Shield Building Filtration Actuation Signal (SBFAS) (Analog) ............3.0, 03/31/04 

B 3.3.11 Post Accident Monitoring (PAM) Instrumentation (Analog) ................3.0, 03/31/04 

B 3.3.12 Remote Shutdown System (Analog) ..................................................3.0, 03/31/04 

B 3.3.13 [Logarithmic] Power Monitoring Channels (Analog) ...........................3.0, 03/31/04 

B 3.3.1 Reactor Protective System (RPS) Instrumentation - Operating 

 (Digital) .........................................................................................3.0, 03/31/04 

B 3.3.2 Reactor Protective System (RPS) Instrumentation - Shutdown 

 (Digital) .........................................................................................3.0, 03/31/04 

B 3.3.3 Control Element Assembly Calculators (CEACs) (Digital)..................3.0, 03/31/04 

B 3.3.4 Reactor Protective System (RPS) Logic and Trip Initiation 

 (Digital) .........................................................................................3.0, 03/31/04 

B 3.3.5 Engineered Safety Features Actuation System (ESFAS) 

 Instrumentation (Digital) ...............................................................3.0, 03/31/04 

B 3.3.6 Engineered Safety Features Actuation System (ESFAS) Logic 

 and Manual Trip (Digital) ..............................................................3.0, 03/31/04 

B 3.3.7 Diesel Generator (DG) - Loss of Voltage Start (LOVS) (Digital).........3.0, 03/31/04 

B 3.3.8 Containment Purge Isolation Signal (CPIS) (Digital)..........................3.0, 03/31/04 

B 3.3.9 Control Room Isolation Signal (CRIS) (Digital)...................................3.0, 03/31/04 

B 3.3.10 Fuel Handling Isolation Signal (FHIS) (Digital)...................................3.0, 03/31/04 

B 3.3.11 Post Accident Monitoring (PAM) Instrumentation (Digital) .................3.0, 03/31/04 

B 3.3.12 Remote Shutdown System (Digital)....................................................3.0, 03/31/04 

B 3.3.13 [Logarithmic] Power Monitoring Channels (Digital) ............................3.0, 03/31/04 
CEOG STS vii Rev. 3.0, 03/31/04 

TABLE OF CONTENTS / REVISION SUMMARY Revision - Date 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.1 RCS Pressure, Temperature, and Flow [Departure from 

 Nucleate Boiling (DNB)] Limits .....................................................3.0, 03/31/04 

B 3.4.2 RCS Minimum Temperature for Criticality..........................................3.0, 03/31/04 

B 3.4.3 RCS Pressure and Temperature (P/T) Limits.....................................3.0, 03/31/04 

B 3.4.4 RCS Loops - MODES 1 and 2............................................................3.0, 03/31/04 

B 3.4.5 RCS Loops - MODE 3 ........................................................................3.0, 03/31/04 

B 3.4.6 RCS Loops - MODE 4 ........................................................................3.0, 03/31/04 

B 3.4.7 RCS Loops - MODE 5, Loops Filled...................................................3.0, 03/31/04 

B 3.4.8 RCS Loops - MODE 5, Loops Not Filled ............................................3.0, 03/31/04 

B 3.4.9 Pressurizer .........................................................................................3.0, 03/31/04 

B 3.4.10 Pressurizer Safety Valves ..................................................................3.0, 03/31/04 

B 3.4.11 Pressurizer Power Operated Relief Valves (PORVs).........................3.0, 03/31/04 

B 3.4.12 Low Temperature Overpressure Protection (LTOP) System..............3.0, 03/31/04 

B 3.4.13 RCS Operational LEAKAGE...............................................................3.0, 03/31/04 

B 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage ....................................3.0, 03/31/04 

B 3.4.15 RCS Leakage Detection Instrumentation ...........................................3.0, 03/31/04 

B 3.4.16 RCS Specific Activity..........................................................................3.0, 03/31/04 

B 3.4.17 Special Test Exceptions (STE) RCS Loops .......................................3.0, 03/31/04 

B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 

B 3.5.1 Safety Injection Tanks (SITs) .............................................................3.0, 03/31/04 

B 3.5.2 ECCS - Operating ..............................................................................3.0, 03/31/04 

B 3.5.3 ECCS - Shutdown ..............................................................................3.0, 03/31/04 

B 3.5.4 Refueling Water Tank (RWT) .............................................................3.0, 03/31/04 

B 3.5.5 Trisodium Phosphate (TSP) ...............................................................3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.1A Containment (Atmospheric)................................................................3.0, 03/31/04 

B 3.6.1B Containment (Dual) ............................................................................3.0, 03/31/04 

B 3.6.2 Containment Air Locks (Atmospheric and Dual).................................3.0, 03/31/04 

B 3.6.3 Containment Isolation Valves (Atmospheric and Dual) ......................3.0, 03/31/04 

B 3.6.4A Containment Pressure (Atmospheric) ................................................3.0, 03/31/04 

B 3.6.4B Containment Pressure (Dual).............................................................3.0, 03/31/04 

B 3.6.5 Containment Air Temperature (Atmospheric and Dual) .....................3.0, 03/31/04 

B 3.6.6A Containment Spray and Cooling Systems (Atmospheric and 

 Dual) (Credit taken for iodine removal by the Containment 

 Spray System) ..............................................................................3.0, 03/31/04 

B 3.6.6B Containment Spray and Cooling Systems (Atmospheric and 

 Dual) (Credit not taken for iodine removal by the 

 Containment Spray System).........................................................3.0, 03/31/04 

B 3.6.7 Spray Additive System (Atmospheric and Dual).................................3.0, 03/31/04 

B 3.6.8 Shield Building Exhaust Air Cleanup System (SBEACS) (Dual) ........3.0, 03/31/04 

B 3.6.9 Hydrogen Mixing System (HMS) (Atmospheric and Dual) .................3.0, 03/31/04 

B 3.6.10 Iodine Cleanup System (ICS) (Atmospheric and Dual) ......................3.0, 03/31/04 

B 3.6.11 Shield Building (Dual).........................................................................3.0, 03/31/04 
CEOG STS viii Rev. 3.0, 03/31/04 

TABLE OF CONTENTS / REVISION SUMMARY Revision - Date 

B 3.6 CONTAINMENT SYSTEMS (continued) 

B 3.6.12 Vacuum Relief Valves (Dual) .............................................................3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.1 Main Steam Safety Valves (MSSVs)..................................................3.0, 03/31/04 

B 3.7.2 Main Steam Isolation Valves (MSIVs) ................................................3.0, 03/31/04 

B 3.7.3 Main Feedwater Isolation Valves (MFIVs) [and [MFIV] Bypass 

 Valves]..........................................................................................3.0, 03/31/04 

B 3.7.4 Atmospheric Dump Valves (ADVs).....................................................3.0, 03/31/04 

B 3.7.5 Auxiliary Feedwater (AFW) System....................................................3.0, 03/31/04 

B 3.7.6 Condensate Storage Tank (CST).......................................................3.0, 03/31/04 

B 3.7.7 Component Cooling Water (CCW) System ........................................3.0, 03/31/04 

B 3.7.8 Service Water System (SWS) ............................................................3.0, 03/31/04 

B 3.7.9 Ultimate Heat Sink (UHS)...................................................................3.0, 03/31/04 

B 3.7.10 Essential Chilled Water (ECW) System..............................................3.0, 03/31/04 

B 3.7.11 Control Room Emergency Air Cleanup System (CREACS)...............3.0, 03/31/04 

B 3.7.12 Control Room Emergency Air Temperature Control System 

 (CREATCS) ..................................................................................3.0, 03/31/04 

B 3.7.13 Emergency Core Cooling System (ECCS) Pump Room Exhaust 

 Air Cleanup System (PREACS)....................................................3.0, 03/31/04 

B 3.7.14 Fuel Building Air Cleanup System (FBACS).......................................3.0, 03/31/04 

B 3.7.15 Penetration Room Exhaust Air Cleanup System (PREACS)..............3.0, 03/31/04 

B 3.7.16 Fuel Storage Pool Water Level ..........................................................3.0, 03/31/04 

B 3.7.17 Fuel Storage Pool Boron Concentration.............................................3.0, 03/31/04 

[ B 3.7.18 Spent Fuel Assembly Storage............................................................3.0, 03/31/04 ]

B 3.7.19 Secondary Specific Activity ................................................................3.0, 03/31/04 

B 3.8 ELECTRICAL POWER SYSTEMS 

B 3.8.1 AC Sources - Operating .....................................................................3.0, 03/31/04 

B 3.8.2 AC Sources - Shutdown .....................................................................3.0, 03/31/04 

B 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air..........................................3.0, 03/31/04 

B 3.8.4 DC Sources - Operating .....................................................................3.0, 03/31/04 

B 3.8.5 DC Sources - Shutdown.....................................................................3.0, 03/31/04 

B 3.8.6 Battery Parameters ............................................................................3.0, 03/31/04 

B 3.8.7 Inverters - Operating ..........................................................................3.0, 03/31/04 

B 3.8.8 Inverters - Shutdown ..........................................................................3.0, 03/31/04 

B 3.8.9 Distribution Systems - Operating........................................................3.0, 03/31/04 

B 3.8.10 Distribution Systems - Shutdown........................................................3.0, 03/31/04 

B 3.9 REFUELING OPERATIONS 

B 3.9.1 Boron Concentration ..........................................................................3.0, 03/31/04 

B 3.9.2 Nuclear Instrumentation .....................................................................3.0, 03/31/04 

B 3.9.3 Containment Penetrations..................................................................3.0, 03/31/04 

B 3.9.4 Shutdown Cooling (SDC) and Coolant Circulation - High Water 

 Level.............................................................................................3.0, 03/31/04 
CEOG STS ix Rev. 3.0, 03/31/04 

TABLE OF CONTENTS / REVISION SUMMARY Revision - Date 

B 3.9 REFUELING OPERATIONS (continued) 

B 3.9.5 Shutdown Cooling (SDC) and Coolant Circulation - Low Water 

 Level.............................................................................................3.0, 03/31/04 

B 3.9.6 Refueling Water Level ........................................................................3.0, 03/31/04 
RCS Core SLs (Analog) 

B 2.1.1 

CEOG STS B 2.1.1-1 Rev. 3.0, 03/31/04 

B 2.0 SAFETY LIMITS (SLs) 

B 2.1.1 Reactor Core SLs (Analog) 

BASES 

BACKGROUND GDC 10 (Ref. 1) requires and SLs ensure that specified acceptable fuel 

design limits are not exceeded during steady state operation, normal 

operation transients, and anticipated operational occurrences (AOOs). 

This is accomplished by having a departure from nucleate boiling (DNB) 

design basis, which corresponds to a 95% probability at a 95% 

confidence level (95/95 DNB criterion) that DNB will not occur and by 

requiring that fuel centerline temperature stays below the melting 

temperature. 

The restrictions of this SL prevent overheating of the fuel and cladding 

and possible cladding perforation that would result in the release of 

fission products to the reactor coolant. Overheating of the fuel is 

prevented by maintaining the steady state peak linear heat rate (LHR) 

below the level at which fuel centerline melting occurs. Overheating of 

the fuel cladding is prevented by restricting fuel operation to within the 

nucleate boiling regime, where the heat transfer coefficient is large and 

the cladding surface temperature is slightly above the coolant saturation 

temperature. 

Fuel centerline melting occurs when the local LHR, or power peaking, in a 

region of the fuel is high enough to cause the fuel centerline temperature 

to reach the melting point of the fuel. Expansion of the pellet upon 

centerline melting may cause the pellet to stress the cladding to the point 

of failure, allowing an uncontrolled release of activity to the reactor 

coolant. 

Operation above the boundary of the nucleate boiling regime could result 

in excessive cladding temperature because of the onset of DNB and the 

resultant sharp reduction in heat transfer coefficient. Inside the steam 

film, high cladding temperatures are reached, and a cladding water 

(zirconium water) reaction may take place. This chemical reaction results 

in oxidation of the fuel cladding to a structurally weaker form. This 

weaker form may lose its integrity, resulting in an uncontrolled release of 

activity to the reactor coolant. 

The Reactor Protective System (RPS), in combination with the LCOs, is 

designed to prevent any anticipated combination of transient conditions 

for Reactor Coolant System (RCS) temperature, pressure, and 

THERMAL POWER level that would result in a violation of the reactor 

core SLs. 
RCS Core SLs (Analog) 

B 2.1.1 

CEOG STS B 2.1.1-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation and AOOs. The reactor core SLs are established to 

ANALYSES preclude violation of the following fuel design criteria: 

a. There must be at least 95% probability at a 95% confidence level (the 

95/95 DNB criterion) that the hot fuel rod in the core does not 

experience a DNB and 

b. The hot fuel pellet in the core must not experience fuel centerline 

melting. 

The RPS setpoints, LCO 3.3.1, "Reactor Protective System (RPS) 

Instrumentation," in combination with all the LCOs, are designed to 

prevent any anticipated combination of transient conditions for RCS 

temperature, pressure, and THERMAL POWER level that would result in 

a departure from nucleate boiling ratio (DNBR) of less than the DNBR 

limit and preclude the existence of flow instabilities. 

Automatic enforcement of these reactor core SLs is provided by the 

following functions: 

a. Pressurizer Pressure High trip, 

b. Variable High Power trip, 

c. Power Rate of Change - High trip, 

d. Reactor Coolant Flow - Low trip, 

e. Steam Generator Pressure - Low trip, 

f. Steam Generator Level - Low trip, 

g. Axial Power Distribution - High trip, 

h. Thermal Margin/Low Pressure trip, 

i. Steam Generator Pressure Difference trip, and 

j. Steam Generator Safety Valves. 

The SL represents a design requirement for establishing the RPS trip 

setpoints identified previously. LCO 3.2.1, "Linear Heat Rate (LHR)," and 

LCO 3.2.5, "AXIAL SHAPE INDEX (ASI)," or the assumed initial 

conditions of the safety analyses (as indicated in the FSAR, Ref. 2) 

provide more restrictive limits to ensure that the SLs are not exceeded. 
RCS Core SLs (Analog) 

B 2.1.1 

CEOG STS B 2.1.1-3 Rev. 3.0, 03/31/04 

BASES 

SAFETY LIMITS The curves provided in Figure B 2.1.1-1 show the loci of points of 

THERMAL POWER, pressurizer pressure, and highest operating loop 

cold leg temperature, for which the minimum DNBR is not less than the 

safety analysis limit. SL 2.1.1.2 ensures that fuel centerline temperature 

remains below melting. 

 SL 2.1.1.2 ensures that fuel centerline temperature remains below the 

fuel melt temperature of [5080]°F during normal operating conditions or 

design AOOs with adjustments for burnup and burnable poison. An 

adjustment of [58°F per 10,000 MWD/MTU] has been established in 

[Topical Report CEN-386-P-A] (Ref. 3) and adjustments for burnable 

poisons are established based on [Topical Reports CENPD-275-P] 

(Ref. 4) and [CENPD-382-P-A] (Ref.5). 

APPLICABILITY SL 2.1.1 only applies in MODES 1 and 2 because these are the only 

MODES in which the reactor is critical. Automatic protection functions are 

required to be OPERABLE during MODES 1 and 2 to ensure operation 

within the reactor core SLs. The steam generator safety valves or 

automatic protection actions serve to prevent RCS heatup to the reactor 

core SL conditions or to initiate a reactor trip function, which forces the 

unit into MODE 3. Setpoints for the reactor trip functions are specified in 

LCO 3.3.1. 

In MODES 3, 4, 5, and 6, Applicability is not required, since the reactor is 

not generating significant THERMAL POWER. 

SAFETY LIMIT The following SL violation responses are applicable to the reactor core 

VIOLATIONS SLs. 

2.2.1

If SL 2.1.1 is violated, the requirement to go to MODE 3 places the unit in 

a MODE in which this SL is not applicable. 

The allowed Completion Time of 1 hour recognizes the importance of 

bringing the unit to a MODE of operation where this SL is not applicable 

and reduces the probability of fuel damage. 
RCS Core SLs (Analog) 

B 2.1.1 

CEOG STS B 2.1.1-4 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10, 1988. 

2. FSAR, Section [ ]. 

 3. [Topical Report CEN-386-P-A, “Verification of the Acceptability of a 

1-Pin Burnup Limit of 60 MWD/kgU for Combustion Engineering 

16x16 PWR Fuel,” August 1992.] 

4. [Topical Report CENPD-275-P, Revision 1-P-A, “CE Methodology for 

Core Designs Containing Gadolini-Urania Burnable Absorbers,” 

May 1988.] 

5. [Topical Report CENPD-382-P-A, “Methodology for Core Designs 

Containing Erbium Burnable Absorbers,” August 1993.] 
RCS Core SLs (Analog) 

B 2.1.1 

CEOG STS B 2.1.1-5 Rev. 3.0, 03/31/04 
RCS Core SLs (Digital) 

B 2.1.1 

CEOG STS B 2.1.1-1 Rev. 3.0, 03/31/04 

B 2.0 SAFETY LIMITS (SLs) 

B 2.1.1 Reactor Core SLs (Digital) 

BASES 

BACKGROUND GDC 10 (Ref. 1) requires and SLs ensure that specified acceptable fuel 

design limits are not exceeded during steady state operation, normal 

operational transients, and anticipated operational occurrences (AOOs). 

This is accomplished by having a departure from nucleate boiling (DNB) 

design basis, which corresponds to a 95% probability at a 95% 

confidence level (95/95 DNB criterion) that DNB will not occur and by 

requiring that fuel centerline temperature stays below the melting 

temperature. 

The restrictions of this SL prevent overheating of the fuel and cladding 

and possible cladding perforation that would result in the release of 

fission products to the reactor coolant. Overheating of the fuel is 

prevented by maintaining the steady state, peak linear heat rate (LHR) 

below the level at which fuel centerline melting occurs. Overheating of 

the fuel cladding is prevented by restricting fuel operation to within the 

nucleate boiling regime, where the heat transfer coefficient is large and 

the cladding surface temperature is slightly above the coolant saturation 

temperature. 

Fuel centerline melting occurs when the local LHR, or power peaking, in a 

region of the fuel is high enough to cause the fuel centerline temperature 

to reach the melting point of the fuel. Expansion of the pellet upon 

centerline melting may cause the pellet to stress the cladding to the point 

of failure, allowing an uncontrolled release of activity to the reactor 

coolant. 

Operation above the boundary of the nucleate boiling regime could result 

in excessive cladding temperature because of the onset of DNB and the 

resultant sharp reduction in the heat transfer coefficient. Inside the steam 

film, high cladding temperatures are reached, and a cladding water 

(zirconium water) reaction may take place. This chemical reaction results 

in oxidation of the fuel cladding to a structurally weaker form. This 

weaker form may lose its integrity, resulting in an uncontrolled release of 

activity to the reactor coolant. 

The Reactor Protective System (RPS), in combination with the LCOs, is 

designed to prevent any anticipated combination of transient conditions 

for Reactor Coolant System (RCS) temperature, pressure, and 

THERMAL POWER level that would result in a violation of the reactor 

core SLs. 
RCS Core SLs (Digital) 

B 2.1.1 

CEOG STS B 2.1.1-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation and AOOs. The reactor core SLs are established to 

ANALYSES preclude violation of the following fuel design criteria: 

a. There must be at least a 95% probability at a 95% confidence level 

(95/95 DNB criterion) that the hot fuel rod in the core does not 

experience DNB and 

b. The hot fuel pellet in the core must not experience centerline fuel 

melting. 

The RPS setpoints, LCO 3.3.1, "Reactor Protective System (RPS) 

Instrumentation," in combination with all the LCOs, are designed to 

prevent any anticipated combination of transient conditions for RCS 

temperature, pressure, and THERMAL POWER level that would result in 

a departure from nucleate boiling ratio (DNBR) of less than the DNBR 

limit and preclude the existence of flow instabilities. 

Automatic enforcement of these reactor core SLs is provided by the 

following functions: 

a. Pressurizer Pressure - High trip, 

b. Pressurizer Pressure - Low trip, 

c. Linear Power Level - High trip, 

d. Steam Generator Pressure - Low trip, 

e. Local Power Density - High trip, 

f. DNBR - Low trip, 

g. Steam Generator Level - Low trip, 

h. Reactor Coolant Flow - Low trip, and 

i. Steam Generator Safety Valves. 

The limitation that the average enthalpy in the hot leg be less than or 

equal to the enthalpy of saturated liquid also ensures that the ∆T 

measured by instrumentation used in the protection system design as a 

measure of the core power is proportional to core power. 
RCS Core SLs (Digital) 

B 2.1.1 

CEOG STS B 2.1.1-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The SL represents a design requirement for establishing the protection 

system trip setpoints identified previously. LCO 3.2.1, "Linear Heat Rate 

(LHR)," and LCO 3.2.4, "Departure From Nucleate Boiling Ratio (DNBR)," 

or the assumed initial conditions of the safety analyses (as indicated in 

the FSAR, Ref. 2) provide more restrictive limits to ensure that the SLs 

are not exceeded. 

SAFETY LIMITS SL 2.1.1.1 and SL 2.1.1.2 ensure that the minimum DNBR is not less than 

the safety analyses limit and that fuel centerline temperature remains 

below melting. 

The minimum value of the DNBR during normal operation and design 

basis AOOs is limited to [1.19], based on a statistical combination of 

CE-1 CHF correlation and engineering factor uncertainties, and is 

established as an SL. Additional factors such as rod bow and spacer grid 

size and placement will determine the limiting safety system settings 

required to ensure that the SL is maintained. Maintaining the dynamically 

adjusted peak LHR to ≤ 21 kW/ft ensures that fuel centerline melt will not 

occur during normal operating conditions or design AOOs. 

SL 2.1.1.2 ensures that fuel centerline temperature remains below the 

fuel melt temperature of [5080]°F during normal operating conditions or 

design AOOs with adjustments for burnup and burnable poison. An 

adjustment of [58°F per 10,000 MWD/MTU] has been established in 

[Topical Report CEN-386-P-A] (Ref. 3) and adjustments for burnable 

poisons are established based on [Topical Reports CENPD-275-P] 

(Ref. 4) and [CENPD-382-P-A] (Ref.5). 

APPLICABILITY SL 2.1.1.1 and SL 2.1.1.2 only apply in MODES 1 and 2 because these 

are the only MODES in which the reactor is critical. Automatic protection 

functions are required to be OPERABLE during MODES 1 and 2 to 

ensure operation within the reactor core SLs. The steam generator safety 

valves or automatic protection actions serve to prevent RCS heatup to the 

reactor core SL conditions or to initiate a reactor trip function, which 

forces the unit into MODE 3. Setpoints for the reactor trip functions are 

specified in LCO 3.3.1. 

In MODES 3, 4, 5, and 6, Applicability is not required, since the reactor is 

not generating significant THERMAL POWER. 
RCS Core SLs (Digital) 

B 2.1.1 

CEOG STS B 2.1.1-4 Rev. 3.0, 03/31/04 

BASES 

SAFETY LIMIT The following SL violation responses are applicable to the reactor core 

VIOLATIONS SLs. If SL 2.1.1.1 or SL 2.1.1.2 is violated, the requirement to go to 

MODE 3 places the unit in a MODE in which this SL is not applicable. 

The allowed Completion Time of 1 hour recognizes the importance of 

bringing the unit to a MODE where this SL is not applicable and reduces 

the probability of fuel damage. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10, 1988. 

2. FSAR, Section [ ]. 

 3. [Topical Report CEN-386-P-A, “Verification of the Acceptability of a 

1-Pin Burnup Limit of 60 MWD/kgU for Combustion Engineering 

16x16 PWR Fuel,” August 1992.] 

4. [Topical Report CENPD-275-P, Revision 1-P-A, “CE Methodology for 

Core Designs Containing Gadolini-Urania Burnable Absorbers,” 

May 1988.] 

5. [Topical Report CENPD-382-P-A, “Methodology for Core Designs 

Containing Erbium Burnable Absorbers,” August 1993.] 
RCS Pressure SL (Analog) 

B 2.1.2 

CEOG STS B 2.1.2-1 Rev. 3.0, 03/31/04 

B 2.0 SAFETY LIMITS (SLs) 

B 2.1.2 Reactor Coolant System (RCS) Pressure SL (Analog) 

BASES 

BACKGROUND The SL on RCS pressure protects the integrity of the RCS against 

overpressurization. In the event of fuel cladding failure, fission products 

are released into the reactor coolant. The RCS then serves as the 

primary barrier in preventing the release of fission products into the 

atmosphere. By establishing an upper limit on RCS pressure, continued 

RCS integrity is ensured. According to 10 CFR 50, Appendix A, GDC 14, 

"Reactor Coolant Pressure Boundary," and GDC 15, "Reactor Coolant 

System Design" (Ref. 1), the reactor coolant pressure boundary (RCPB) 

design conditions are not to be exceeded during normal operation and 

anticipated operational occurrences (AOOs). Also, according to GDC 28 

(Ref. 1), "Reactivity Limits," reactivity accidents, including rod ejection, do 

not result in damage to the RCPB greater than limited local yielding. 

The design pressure of the RCS is 2500 psia. During normal operation 

and AOOs, the RCS pressure is kept from exceeding the design pressure 

by more than 10%, in accordance with Section III of the ASME Code 

(Ref. 2). To ensure system integrity, all RCS components are 

hydrostatically tested at 125% of design pressure, according to the ASME 

Code requirements prior to initial operation, when there is no fuel in the 

core. Following inception of unit operation, RCS components shall be 

pressure tested, in accordance with the requirements of ASME Code, 

Section XI (Ref. 3). 

Overpressurization of the RCS could result in a breach of the RCPB. If 

this occurs in conjunction with a fuel cladding failure, fission products 

could enter the containment atmosphere, raising concerns relative to 

limits on radioactive releases specified in 10 CFR 100, "Reactor Site 

Criteria" (Ref. 4). 

APPLICABLE The RCS pressurizer safety valves, the main steam safety valves 

SAFETY (MSSVs), and the Reactor Pressure - High trip have settings established 

ANALYSES to ensure that the RCS pressure SL will not be exceeded. 

The RCS pressurizer safety valves are sized to prevent system pressure 

from exceeding the design pressure by more than 10%, in accordance 

with Section III of the ASME Code for Nuclear Power Plant Components 

(Ref. 2). The transient that establishes the required relief capacity, and 
RCS Pressure SL (Analog) 

B 2.1.2 

CEOG STS B 2.1.2-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

hence the valve size requirements and lift settings, is a [complete loss of 

external load without a direct reactor trip]. During the transient, no control 

actions are assumed except that the safety valves on the secondary plant 

are assumed to open when the steam pressure reaches the secondary 

plant safety valve settings, and nominal feedwater supply is maintained. 

The Reactor Protective System (RPS) trip setpoints (LCO 3.3.1, "Reactor 

Protective System (RPS) Instrumentation"), together with the settings of 

the MSSVs (LCO 3.7.1, "Main Steam Safety Valves (MSSVs)") and the 

pressurizer safety valves, provide pressure protection for normal 

operation and AOOs. In particular, the Pressurizer Pressure - High trip 

setpoint is specifically set to provide protection against overpressurization 

(Ref. 5). Safety analyses for both the Pressure - High trip and the RCS 

pressurizer safety valves are performed, using conservative assumptions 

relative to pressure control devices. 

More specifically, no credit is taken for operation of any of the following: 

a. Pressurizer power operated relief valves (PORVs), 

b. Steam Bypass Control System, 

c. Pressurizer Level Control System, or 

d. Pressurizer Pressure Control System. 

SAFETY LIMITS The maximum transient pressure allowable in the RCS pressure vessel 

under the ASME Code, Section III, is 110% of design pressure. The 

maximum transient pressure allowable in the RCS piping, valves, and 

fittings under [USAS, Section B31.1 (Ref. 6)], is 120% of design pressure. 

The most limiting of these two allowances is the 110% of design 

pressure; therefore, the SL on maximum allowable RCS pressure is 

established at 2750 psia. 

APPLICABILITY SL 2.1.2 applies in MODES 1, 2, 3, 4, and 5 because this SL could be 

approached or exceeded in these MODES due to overpressurization 

events. The SL is not applicable in MODE 6 because the reactor vessel 

head closure bolts are not fully tightened, making it unlikely that the RCS 

can be pressurized. 
RCS Pressure SL (Analog) 

B 2.1.2 

CEOG STS B 2.1.2-3 Rev. 3.0, 03/31/04 

BASES 

SAFETY LIMIT The following SL violation responses are applicable to the RCS pressure 

VIOLATIONS SL. 

2.2.2.1

If the RCS pressure SL is violated when the reactor is in MODE 1 or 2, 

the requirement is to restore compliance and be in MODE 3 within 1 hour. 

With RCS pressure greater than the value specified in SL 2.1.2 in 

MODE 1 or 2, the pressure must be reduced to below this value. A 

pressure greater than the value specified in SL 2.1.2 exceeds 110% of 

the RCS design pressure and may challenge system integrity. 

The allowed Completion Time of 1 hour provides the operator time to 

complete the necessary actions to reduce RCS pressure by terminating 

the cause of the pressure increase, removing mass or energy from the 

RCS, or a combination of these actions, and to establish MODE 3 

conditions. 

2.2.2.2

If the RCS pressure SL is exceeded in MODE 3, 4, or 5, RCS pressure 

must be restored to within the SL value within 5 minutes. 

Exceeding the RCS pressure SL in MODE 3, 4, or 5 is potentially more 

severe than exceeding this SL in MODE 1 or 2, since the reactor vessel 

temperature may be lower and the vessel material, consequently, less 

ductile. As such, pressure must be reduced to less than the SL within 

5 minutes. This action does not require reducing MODES, since this 

would require reducing temperature, which would compound the problem 

by adding thermal gradient stresses to the existing pressure stress. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 14, GDC 15, and GDC 28. 

2. ASME, Boiler and Pressure Vessel Code, Section III, Article 

NB-7000. 

3. ASME, Boiler and Pressure Vessel Code, Section XI, 

Article IWX-5000. 

4. 10 CFR 100. 

5. FSAR, Section [ ]. 

[ 6. ASME, USAS B31.1, Standard Code for Pressure Piping, 1967. ] 
RCS Pressure SLs (Digital) 

B 2.1.2 

CEOG STS B 2.1.2-1 Rev. 3.0, 03/31/04 

B 2.0 SAFETY LIMITS (SLs) 

B 2.1.2 Reactor Coolant System (RCS) Pressure SL (Digital) 

BASES 

BACKGROUND The SL on RCS pressure protects the integrity of the RCS against 

overpressurization. In the event of fuel cladding failure, fission products 

are released into the reactor coolant. The RCS then serves as the 

primary barrier in preventing the release of fission products into the 

atmosphere. By establishing an upper limit on RCS pressure, continued 

RCS integrity is ensured. According to 10 CFR 50, Appendix A, GDC 14, 

"Reactor Coolant Pressure Boundary," and GDC 15, "Reactor Coolant 

System Design" (Ref. 1), the reactor coolant pressure boundary (RCPB) 

design conditions are not to be exceeded during normal operation and 

anticipated operational occurrences (AOOs). Also, according to GDC 28 

(Ref. 1), "Reactivity Limits," reactivity accidents, including rod ejection, do 

not result in damage to the RCPB greater than limited local yielding. 

The design pressure of the RCS is 2500 psia. During normal operation 

and AOOs, the RCS pressure is kept from exceeding the design pressure 

by more than 10%, in accordance with Section III of the ASME Code 

(Ref. 2). To ensure system integrity, all RCS components are 

hydrostatically tested at 125% of design pressure, according to the ASME 

Code requirements prior to initial operation, when there is no fuel in the 

core. Following inception of unit operation, RCS components shall be 

pressure tested, in accordance with the requirements of ASME Code, 

Section XI (Ref. 3). 

Overpressurization of the RCS could result in a breach of the RCPB. If 

this occurs in conjunction with a fuel cladding failure, fission products 

could enter the containment atmosphere, raising concerns relative to 

limits on radioactive releases specified in 10 CFR 100, "Reactor Site 

Criteria" (Ref. 4). 

APPLICABLE The RCS pressurizer safety valves, the main steam safety valves 

SAFETY (MSSVs), and the Reactor Pressure - High trip have settings established 

ANALYSES to ensure that the RCS pressure SL will not be exceeded. 

The RCS pressurizer safety valves are sized to prevent system pressure 

from exceeding the design pressure by more than 10%, in accordance 

with Section III of the ASME Code for Nuclear Power Plant Components 

(Ref. 2). The transient that establishes the required relief capacity, and 

hence the valve size requirements and lift settings, is a [complete loss of 
RCS Pressure SLs (Digital) 

B 2.1.2 

CEOG STS B 2.1.2-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

external load without a direct reactor trip]. During the transient, no control 

actions are assumed except that the safety valves on the secondary plant 

are assumed to open when the steam pressure reaches the secondary 

plant safety valve settings, and nominal feedwater supply is maintained. 

The Reactor Protective System (RPS) trip setpoints (LCO 3.3.1, "Reactor 

Protective System (RPS) Instrumentation"), together with the settings of 

the MSSVs (LCO 3.7.1, "Main Steam Safety Valves (MSSVs)") and the 

pressurizer safety valves, provide pressure protection for normal 

operation and AOOs. In particular, the Pressurizer Pressure - High Trip 

setpoint is specifically set to provide protection against overpressurization 

(Ref. 5). Safety analyses for both the Pressure - High Trip and the RCS 

pressurizer safety valves are performed, using conservative assumptions 

relative to pressure control devices. 

More specifically, no credit is taken for operation of any of the following: 

a. Pressurizer power operated relief valves (PORVs), 

b. Steam Bypass Control System, 

c. Pressurizer Level Control System, or 

d. Pressurizer Pressure Control System. 

SAFETY LIMITS The maximum transient pressure allowable in the RCS pressure vessel 

under the ASME Code, Section III, is 110% of design pressure. The 

maximum transient pressure allowable in the RCS piping, valves, and 

fittings under [USAS, Section B31.1 (Ref. 6)], is 120% of design pressure. 

The most limiting of these two allowances is the 110% of design 

pressure; therefore, the SL on maximum allowable RCS pressure is 

established at 2750 psia. 

APPLICABILITY SL 2.1.2 applies in MODES 1, 2, 3, 4, and 5 because this SL could be 

approached or exceeded in these MODES due to overpressurization 

events. The SL is not applicable in MODE 6 because the reactor vessel 

head closure bolts are not fully tightened, making it unlikely that the RCS 

can be pressurized. 
RCS Pressure SLs (Digital) 

B 2.1.2 

CEOG STS B 2.1.2-3 Rev. 3.0, 03/31/04 

BASES 

SAFETY LIMIT The following SL violation responses are applicable to the RCS pressure 

VIOLATIONS SL. 

2.2.2.1

If the RCS pressure SL is violated when the reactor is in MODE 1 or 2, 

the requirement is to restore compliance and be in MODE 3 within 1 hour. 

With RCS pressure greater than the value specified in SL 2.1.2 in 

MODE 1 or 2, the pressure must be reduced to below this value. A 

pressure greater that the value specified in SL 2.1.2 exceeds 110% of the 

RCS design pressure and may challenge system integrity. 

The allowed Completion Time of 1 hour provides the operator time to 

complete the necessary actions to reduce RCS pressure by terminating 

the cause of the pressure increase, removing mass or energy from the 

RCS, or a combination of these actions, and to establish MODE 3 

conditions. 

2.2.2.2

If the RCS pressure SL is exceeded in MODE 3, 4, or 5, RCS pressure 

must be restored to within the SL value within 5 minutes. 

Exceeding the RCS pressure SL in MODE 3, 4, or 5 is potentially more 

severe than exceeding this SL in MODE 1 or 2, since the reactor vessel 

temperature may be lower and the vessel material, consequently, less 

ductile. As such, pressure must be reduced to less than the SL within 

5 minutes. This action does not require reducing MODES, since this 

would require reducing temperature, which would compound the problem 

by adding thermal gradient stresses to the existing pressure stress. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 14, GDC 15, and GDC 28. 

2. ASME, Boiler and Pressure Vessel Code, Section III, Article 

NB-7000. 

3. ASME, Boiler and Pressure Vessel Code, Section XI, 

Article IWX-5000. 

4. 10 CFR 100. 

5. FSAR, Section [ ]. 

[ 6. ASME, USAS B31.1, Standard Code for Pressure Piping, 1967. ] 
LCO Applicability 

B 3.0 

CEOG STS B 3.0-1 Rev. 3.0, 03/31/04 

B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY 

BASES 

LCOs LCO 3.0.1 through LCO 3.0.7 establish the general requirements 

applicable to all Specifications and apply at all times unless otherwise 

stated. 

LCO 3.0.1 LCO 3.0.1 establishes the Applicability statement within each individual 

Specification as the requirement for when the LCO is required to be met 

(i.e., when the unit is in the MODES or other specified conditions of the 

Applicability statement of each Specification). 

LCO 3.0.2 LCO 3.0.2 establishes that upon discovery of a failure to meet an LCO, 

the associated ACTIONS shall be met. The Completion Time of each 

Required Action for an ACTIONS Condition is applicable from the point in 

time that an ACTIONS Condition is entered. The Required Actions 

establish those remedial measures that must be taken within specified 

Completion Times when the requirements of an LCO are not met. This 

Specification establishes that: 

a. Completion of the Required Actions within the specified Completion 

Times constitutes compliance with a Specification and 

b. Completion of the Required Actions is not required when an LCO is 

met within the specified Completion Time, unless otherwise specified. 

There are two basic types of Required Actions. The first type of Required 

Action specifies a time limit in which the LCO must be met. This time limit 

is the Completion Time to restore an inoperable system or component to 

OPERABLE status or to restore variables to within specified limits. If this 

type of Required Action is not completed within the specified Completion 

Time, a shutdown may be required to place the unit in a MODE or 

condition in which the Specification is not applicable. (Whether stated as 

a Required Action or not, correction of the entered Condition is an action 

that may always be considered upon entering ACTIONS.) The second 

type of Required Action specifies the remedial measures that permit 

continued operation of the unit that is not further restricted by the 

Completion Time. In this case, compliance with the Required Actions 

provides an acceptable level of safety for continued operation. 

Completing the Required Actions is not required when an LCO is met or 

is no longer applicable, unless otherwise stated in the individual 

Specifications. 
LCO Applicability 

B 3.0 

CEOG STS B 3.0-2 Rev. 3.0, 03/31/04 

BASES 

LCO 3.0.2 (continued) 

The nature of some Required Actions of some Conditions necessitates 

that, once the Condition is entered, the Required Actions must be 

completed even though the associated Conditions no longer exist. The 

individual LCO's ACTIONS specify the Required Actions where this is the 

case. An example of this is in LCO 3.4.3, "RCS Pressure and 

Temperature (P/T) Limits." 

The Completion Times of the Required Actions are also applicable when 

a system or component is removed from service intentionally. The 

reasons for intentionally relying on the ACTIONS include, but are not 

limited to, performance of Surveillances, preventive maintenance, 

corrective maintenance, or investigation of operational problems. 

Entering ACTIONS for these reasons must be done in a manner that 

does not compromise safety. Intentional entry into ACTIONS should not 

be made for operational convenience. Additionally, if intentional entry into 

ACTIONS would result in redundant equipment being inoperable, 

alternatives should be used instead. Doing so limits the time both 

subsystems/trains of a safety function are inoperable and limits the time 

conditions exist which may result in LCO 3.0.3 being entered. Individual 

Specifications may specify a time limit for performing an SR when 

equipment is removed from service or bypassed for testing. In this case, 

the Completion Times of the Required Actions are applicable when this 

time limit expires, if the equipment remains removed from service or 

bypassed. 

When a change in MODE or other specified condition is required to 

comply with Required Actions, the unit may enter a MODE or other 

specified condition in which another Specification becomes applicable. In 

this case, the Completion Times of the associated Required Actions 

would apply from the point in time that the new Specification becomes 

applicable and the ACTIONS Condition(s) are entered. 

LCO 3.0.3 LCO 3.0.3 establishes the actions that must be implemented when an 

LCO is not met and either: 

a. An associated Required Action and Completion Time is not met and 

no other Condition applies or 

b. The condition of the unit is not specifically addressed by the 

associated ACTIONS. This means that no combination of Conditions 

stated in the ACTIONS can be made that exactly corresponds to the 

actual condition of the unit. Sometimes, possible combinations of 

Conditions are such that entering LCO 3.0.3 is warranted; in such 

cases, the ACTIONS specifically state a Condition corresponding to 

such combinations and also that LCO 3.0.3 be entered immediately. 
LCO Applicability 

B 3.0 

CEOG STS B 3.0-3 Rev. 3.0, 03/31/04 

BASES 

LCO 3.0.3 (continued) 

This Specification delineates the time limits for placing the unit in a safe 

MODE or other specified condition when operation cannot be maintained 

within the limits for safe operation as defined by the LCO and its 

ACTIONS. It is not intended to be used as an operational convenience 

that permits routine voluntary removal of redundant systems or 

components from service in lieu of other alternatives that would not result 

in redundant systems or components being inoperable. 

Upon entering LCO 3.0.3, 1 hour is allowed to prepare for an orderly 

shutdown before initiating a change in unit operation. This includes time 

to permit the operator to coordinate the reduction in electrical generation 

with the load dispatcher to ensure the stability and availability of the 

electrical grid. The time limits specified to reach lower MODES of 

operation permit the shutdown to proceed in a controlled and orderly 

manner that is well within the specified maximum cooldown rate and 

within the capabilities of the unit, assuming that only the minimum 

required equipment is OPERABLE. This reduces thermal stresses on 

components of the Reactor Coolant System and the potential for a plant 

upset that could challenge safety systems under conditions to which this 

Specification applies. The use and interpretation of specified times to 

complete the actions of LCO 3.0.3 are consistent with the discussion of 

Section 1.3, Completion Times. 

A unit shutdown required in accordance with LCO 3.0.3 may be 

terminated and LCO 3.0.3 exited if any of the following occurs: 

a. The LCO is now met, 

b. A Condition exists for which the Required Actions have now been 

performed, or 

c. ACTIONS exist that do not have expired Completion Times. These 

Completion Times are applicable from the point in time that the 

Condition is initially entered and not from the time LCO 3.0.3 is 

exited. 

The time limits of LCO 3.0.3 allow 37 hours for the unit to be in MODE 5 

when a shutdown is required during MODE 1 operation. If the unit is in a 

lower MODE of operation when a shutdown is required, the time limit for 

reaching the next lower MODE applies. If a lower MODE is reached in 

less time than allowed, however, the total allowable time to reach 
LCO Applicability 

B 3.0 

CEOG STS B 3.0-4 Rev. 3.0, 03/31/04 

BASES 

LCO 3.0.3 (continued) 

MODE 5, or other applicable MODE, is not reduced. For example, if 

MODE 3 is reached in 2 hours, then the time allowed for reaching 

MODE 4 is the next 11 hours, because the total time for reaching 

MODE 4 is not reduced from the allowable limit of 13 hours. Therefore, if 

remedial measures are completed that would permit a return to MODE 1, 

a penalty is not incurred by having to reach a lower MODE of operation in 

less than the total time allowed. 

In MODES 1, 2, 3, and 4, LCO 3.0.3 provides actions for Conditions not 

covered in other Specifications. The requirements of LCO 3.0.3 do not 

apply in MODES 5 and 6 because the unit is already in the most 

restrictive Condition required by LCO 3.0.3. The requirements of 

LCO 3.0.3 do not apply in other specified conditions of the Applicability 

(unless in MODE 1, 2, 3, or 4) because the ACTIONS of individual 

Specifications sufficiently define the remedial measures to be taken. 

Exceptions to LCO 3.0.3 are provided in instances where requiring a unit 

shutdown, in accordance with LCO 3.0.3, would not provide appropriate 

remedial measures for the associated condition of the unit. An example 

of this is in LCO 3.7.16, "Fuel Storage Pool Water Level." LCO 3.7.16 

has an Applicability of "During movement of irradiated fuel assemblies in 

the fuel storage pool." Therefore, this LCO can be applicable in any or all 

MODES. If the LCO and the Required Actions of LCO 3.7.16 are not met 

while in MODE 1, 2, or 3, there is no safety benefit to be gained by 

placing the unit in a shutdown condition. The Required Action of 

LCO 3.7.16 of "Suspend movement of irradiated fuel assemblies in fuel 

storage pool" is the appropriate Required Action to complete in lieu of the 

actions of LCO 3.0.3. These exceptions are addressed in the individual 

Specifications. 

[ The requirement to be in MODE 4 in 13 hours is plant specific and 

depends on the ability to cool the pressurizer and degas. ] 

LCO 3.0.4 LCO 3.0.4 establishes limitations on changes in MODES or other 

specified conditions in the Applicability when an LCO is not met. It allows 

placing the unit in a MODE or other specified condition stated in that 

Applicability (e.g., the Applicability desired to be entered) when unit 

conditions are such that the requirements of the LCO would not be met, in 

accordance with LCO 3.0.4.a, LCO 3.0.4.b, or LCO 3.0.4.c. 
LCO Applicability 

B 3.0 

CEOG STS B 3.0-5 Rev. 3.0, 03/31/04 

BASES 

LCO 3.0.4 (continued) 

LCO 3.0.4.a allows entry into a MODE or other specified condition in the 

Applicability with the LCO not met when the associated ACTIONS to be 

entered permit continued operation in the MODE or other specified 

condition in the Applicability for an unlimited period of time. Compliance 

with Required Actions that permit continued operation of the unit for an 

unlimited period of time in a MODE or other specified condition provides 

an acceptable level of safety for continued operation. This is without 

regard to the status of the unit before or after the MODE change. 

Therefore, in such cases, entry into a MODE or other specified condition 

in the Applicability may be made in accordance with the provisions of the 

Required Actions. 

LCO 3.0.4.b allows entry into a MODE or other specified condition in the 

Applicability with the LCO not met after performance of a risk assessment 

addressing inoperable systems and components, consideration of the 

results, determination of the acceptability of entering the MODE or other 

specified condition in the Applicability, and establishment of risk 

management actions, if appropriate. 

The risk assessment may use quantitative, qualitative, or blended 

approaches, and the risk assessment will be conducted using the plant 

program, procedures, and criteria in place to implement 

10 CFR 50.65(a)(4), which requires that risk impacts of maintenance 

activities to be assessed and managed. The risk assessment, for the 

purposes of LCO 3.0.4.b, must take into account all inoperable Technical 

Specification equipment regardless of whether the equipment is included 

in the normal 10 CFR 50.65(a)(4) risk assessment scope. The risk 

assessments will be conducted using the procedures and guidance 

endorsed by Regulatory Guide 1.182, “Assessing and Managing Risk 

Before Maintenance Activities at Nuclear Power Plants.” Regulatory 

Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01, 

“Industry Guideline for Monitoring the Effectiveness of Maintenance at 

Nuclear Power Plants.” These documents address general guidance for 

conduct of the risk assessment, quantitative and qualitative guidelines for 

establishing risk management actions, and example risk management 

actions. These include actions to plan and conduct other activities in a 

manner that controls overall risk, increased risk awareness by shift and 

management personnel, actions to reduce the duration of the condition, 

actions to minimize the magnitude of risk increases (establishment of 

backup success paths or compensatory measures), and determination 

that the proposed MODE change is acceptable. Consideration should 

also be given to the probability of completing restoration such that the 

requirements of the LCO would be met prior to the expiration of ACTIONS 

Completion Times that would require exiting the Applicability. 
LCO Applicability 

B 3.0 

CEOG STS B 3.0-6 Rev. 3.0, 03/31/04 

BASES 

LCO 3.0.4 (continued) 

LCO 3.0.4.b may be used with single, or multiple systems and 

components unavailable. NUMARC 93-01 provides guidance relative to 

consideration of simultaneous unavailability of multiple systems and 

components. 

The results of the risk assessment shall be considered in determining the 

acceptability of entering the MODE or other specified condition in the 

Applicability, and any corresponding risk management actions. The 

LCO 3.0.4.b risk assessments do not have to be documented. 

The Technical Specifications allow continued operation with equipment 

unavailable in MODE 1 for the duration of the Completion Time. Since 

this is allowable, and since in general the risk impact in that particular 

MODE bounds the risk of transitioning into and through the applicable 

MODES or other specified conditions in the Applicability of the LCO, the 

use of the LCO 3.0.4.b allowance should be generally acceptable, as long 

as the risk is assessed and managed as stated above. However, there is 

a small subset of systems and components that have been determined to 

be more important to risk and use of the LCO 3.0.4.b allowance is 

prohibited. The LCOs governing these systems and components contain 

Notes prohibiting the use of LCO 3.0.4.b by stating that LCO 3.0.4.b is not 

applicable. 

LCO 3.0.4.c allows entry into a MODE or other specified condition in the 

Applicability with the LCO not met based on a Note in the Specification 

which states LCO 3.0.4.c is applicable. These specific allowances permit 

entry into MODES or other specified conditions in the Applicability when 

the associated ACTIONS to be entered do not provide for continued 

operation for an unlimited period of time and a risk assessment has not 

been performed. This allowance may apply to all the ACTIONS or to a 

specific Required Action of a Specification. The risk assessments 

performed to justify the use of LCO 3.0.4.b usually only consider systems 

and components. For this reason, LCO 3.0.4.c is typically applied to 

Specifications which describe values and parameters (e.g., [Containment 

Air Temperature, Containment Pressure, MCPR, Moderator Temperature 

Coefficient]), and may be applied to other Specifications based on NRC 

plant specific approval. 

The provisions of this Specification should not be interpreted as 

endorsing the failure to exercise the good practice of restoring systems or 

components to OPERABLE status before entering an associated MODE 

or other specified condition in the Applicability. 
LCO Applicability 

B 3.0 

CEOG STS B 3.0-7 Rev. 3.0, 03/31/04 

BASES 

LCO 3.0.4 (continued) 

The provisions of LCO 3.0.4 shall not prevent changes in MODES or 

other specified conditions in the Applicability that are required to comply 

with ACTIONS. In addition, the provisions of LCO 3.0.4 shall not prevent 

changes in MODES or other specified conditions in the Applicability that 

result from any unit shutdown. In this context, a unit shutdown is defined 

as a change in MODE or other specified condition in the Applicability 

associated with transitioning from MODE 1 to MODE 2, MODE 2 to 

MODE 3, MODE 3 to MODE 4, and MODE 4 to MODE 5. 

Upon entry into a MODE or other specified condition in the Applicability 

with the LCO not met, LCO 3.0.1 and LCO 3.0.2 require entry into the 

applicable Conditions and Required Actions until the Condition is 

resolved, until the LCO is met, or until the unit is not within the 

Applicability of the Technical Specification. 

Surveillances do not have to be performed on the associated inoperable 

equipment (or on variables outside the specified limits), as permitted by 

SR 3.0.1. Therefore, utilizing LCO 3.0.4 is not a violation of SR 3.0.1 or 

SR 3.0.4 for any Surveillances that have not been performed on 

inoperable equipment. However, SRs must be met to ensure 

OPERABILITY prior to declaring the associated equipment OPERABLE 

(or variable within limits) and restoring compliance with the affected LCO. 

LCO 3.0.5 LCO 3.0.5 establishes the allowance for restoring equipment to service 

under administrative controls when it has been removed from service or 

declared inoperable to comply with ACTIONS. The sole purpose of this 

Specification is to provide an exception to LCO 3.0.2 (e.g., to not comply 

with the applicable Required Action(s)) to allow the performance of 

required testing to demonstrate either: 

a. The OPERABILITY of the equipment being returned to service or 

b. The OPERABILITY of other equipment. 

The administrative controls ensure the time the equipment is returned to 

service in conflict with the requirements of the ACTIONS is limited to the 

time absolutely necessary to perform the required testing to demonstrate 

OPERABILITY. This Specification does not provide time to perform any 

other preventive or corrective maintenance. 
LCO Applicability 

B 3.0 

CEOG STS B 3.0-8 Rev. 3.0, 03/31/04 

BASES 

LCO 3.0.5 (continued) 

An example of demonstrating the OPERABILITY of the equipment being 

returned to service is reopening a containment isolation valve that has 

been closed to comply with Required Actions and must be reopened to 

perform the required testing. 

An example of demonstrating the OPERABILITY of other equipment is 

taking an inoperable channel or trip system out of the tripped condition to 

prevent the trip function from occurring during the performance of 

required testing on another channel in the other trip system. A similar 

example of demonstrating the OPERABILITY of other equipment is taking 

an inoperable channel or trip system out of the tripped condition to permit 

the logic to function and indicate the appropriate response during the 

performance of required testing on another channel in the same trip 

system. 

LCO 3.0.6 LCO 3.0.6 establishes an exception to LCO 3.0.2 for support systems that 

have an LCO specified in the Technical Specifications (TS). This 

exception is provided because LCO 3.0.2 would require that the 

Conditions and Required Actions of the associated inoperable supported 

system LCO be entered solely due to the inoperability of the support 

system. This exception is justified because the actions that are required 

to ensure the unit is maintained in a safe condition are specified in the 

support system LCO's Required Actions. These Required Actions may 

include entering the supported system's Conditions and Required Actions 

or may specify other Required Actions. 

When a support system is inoperable and there is an LCO specified for it 

in the TS, the supported system(s) are required to be declared inoperable 

if determined to be inoperable as a result of the support system 

inoperability. However, it is not necessary to enter into the supported 

systems' Conditions and Required Actions unless directed to do so by the 

support system's Required Actions. The potential confusion and 

inconsistency of requirements related to the entry into multiple support 

and supported systems' LCOs' Conditions and Required Actions are 

eliminated by providing all the actions that are necessary to ensure the 

unit is maintained in a safe condition in the support system's Required 

Actions. 

However, there are instances where a support system's Required Action 

may either direct a supported system to be declared inoperable or direct 

entry into Conditions and Required Actions for the supported system. 

This may occur immediately or after some specified delay to perform 
LCO Applicability 

B 3.0 

CEOG STS B 3.0-9 Rev. 3.0, 03/31/04 

BASES 

LCO 3.0.6 (continued) 

some other Required Action. Regardless of whether it is immediate or 

after some delay, when a support system's Required Action directs a 

supported system to be declared inoperable or directs entry into 

Conditions and Required Actions for a supported system, the applicable 

Conditions and Required Actions shall be entered in accordance with 

LCO 3.0.2. 

Specification 5.5.15, "Safety Function Determination Program (SFDP)," 

ensures loss of safety function is detected and appropriate actions are 

taken. Upon entry into LCO 3.0.6, an evaluation shall be made to 

determine if loss of safety function exists. Additionally, other limitations, 

remedial actions, or compensatory actions may be identified as a result of 

the support system inoperability and corresponding exception to entering 

supported system Conditions and Required Actions. The SFDP 

implements the requirements of LCO 3.0.6. 

Cross train checks to identify a loss of safety function for those support 

systems that support multiple and redundant safety systems are required. 

The cross train check verifies that the supported systems of the 

redundant OPERABLE support system are OPERABLE, thereby ensuring 

safety function is retained. [ A loss of safety function may exist when a 

support system is inoperable, and: 

a. A required system redundant to system(s) supported by the 

inoperable support system is also inoperable (EXAMPLE B 3.0.6-1), 

b. A required system redundant to system(s) in turn supported by the 

inoperable supported system is also inoperable (EXAMPLE 

B 3.0.6-2), or 

c. A required system redundant to support system(s) for the supported 

systems (a) and (b) above is also inoperable (EXAMPLE B 3.0.6-3). 

EXAMPLE B 3.0.6-1

If System 2 of Train A is inoperable and System 5 of Train B is 

inoperable, a loss of safety function exists in supported System 5. 

EXAMPLE B 3.0.6-2

If System 2 of Train A is inoperable, and System 11 of Train B is 

inoperable, a loss of safety function exists in System 11 which is in turn 

supported by System 5. 
LCO Applicability 

B 3.0 

CEOG STS B 3.0-10 Rev. 3.0, 03/31/04 

BASES 

LCO 3.0.6 (continued) 

EXAMPLE B 3.0.6-3

If System 2 of Train A is inoperable, and System 1 of Train B is 

inoperable, a loss of safety function exists in Systems 2, 4, 5, 8, 9, 10 and 

11. ]

If this evaluation determines that a loss of safety function exists, the 

appropriate Conditions and Required Actions of the LCO in which the loss 

of safety function exists are required to be entered. 

[ Figure B 3.0-1 

Configuration of Trains and Systems ]

This loss of safety function does not require the assumption of additional 

single failures or loss of offsite power. Since operations is being 

restricted in accordance with the ACTIONS of the support system, any 

resulting temporary loss of redundancy or single failure protection is taken 

into account. Similarly, the ACTIONS for inoperable offsite circuit(s) and 

inoperable diesel generator(s) provide the necessary restriction for cross 

train inoperabilities. This explicit cross train verification for inoperable AC 

electrical power sources also acknowledges that supported system(s) are 

not declared inoperable solely as a result of inoperability of a normal or 

emergency electrical power source (refer to the definition of 

OPERABILITY). 
LCO Applicability 

B 3.0 

CEOG STS B 3.0-11 Rev. 3.0, 03/31/04 

BASES 

LCO 3.0.6 (continued) 

When loss of safety function is determined to exist, and the SFDP requires entry into the 

appropriate Conditions and Required Actions of the LCO in which the loss of safety function 

exists, consideration must be given to the specific type of function affected. Where a loss of 

function is solely due to a single Technical Specification support system (e.g., loss of automatic 

start due to inoperable instrumentation, or loss of pump suction source due to low tank level) the 

appropriate LCO is the LCO for the 

support system. The ACTIONS for a support system LCO adequately 

addresses the inoperabilities of that system without reliance on entering 

its supported system LCO. When the loss of function is the result of 

multiple support systems, the appropriate LCO is the LCO for the 

supported system. 

LCO 3.0.7 Special tests and operations are required at various times over the unit's 

life to demonstrate performance characteristics, to perform maintenance 

activities, and to perform special evaluations. Because TS normally 

preclude these tests and operations, special test exceptions (STEs) allow 

specified requirements to be changed or suspended under controlled 

conditions. STEs are included in applicable sections of the 

Specifications. Unless otherwise specified, all other TS requirements 

remain unchanged and in effect as applicable. This will ensure that all 

appropriate requirements of the MODE or other specified condition not 

directly associated with or required to be changed or suspended to 

perform the special test or operation will remain in effect. 

The Applicability of an STE LCO represents a condition not necessarily in 

compliance with the normal requirements of the TS. Compliance with 

STE LCOs is optional. 

A special test may be performed under either the provisions of the 

appropriate STE LCO or the other applicable TS requirements. If it is 

desired to perform the special test under the provisions of the STE LCO, 

the requirements of the STE LCO shall be followed. This includes the 

SRs specified in the STE LCO. 

Some of the STE LCOs require that one or more of the LCOs for normal 

operation be met (i.e., meeting the STE LCO requires meeting the 

specified normal LCOs). The Applicability, ACTIONS, and SRs of the 

specified normal LCOs, however, are not required to be met in order to 

meet the STE LCO when it is in effect. This means that, upon failure to 

meet a specified normal LCO, the associated ACTIONS of the STE LCO 
LCO Applicability 

B 3.0 

CEOG STS B 3.0-12 Rev. 3.0, 03/31/04 

BASES 

LCO 3.0.7 (continued) 

 apply, in lieu of the ACTIONS of the normal LCO. Exceptions to the 

above do exist. There are instances when the Applicability of the 

specified normal LCO must be met, where its ACTIONS must be taken, 

where certain of its Surveillances must be performed, or where all of 

these requirements must be met concurrently with the requirements of the 

STE LCO. 

Unless the SRs of the specified normal LCOs are suspended or changed 

by the special test, those SRs that are necessary to meet the specified 

normal LCOs must be met prior to performing the special test. During the 

conduct of the special test, those Surveillances need not be performed 

unless specified by the ACTIONS or SRs of the STE LCO. 

ACTIONS for STE LCOs provide appropriate remedial measures upon 

failure to meet the STE LCO. Upon failure to meet these ACTIONS, 

suspend the performance of the special test and enter the ACTIONS for 

all LCOs that are then not met. Entry into LCO 3.0.3 may possibly be 

required, but this determination should not be made by considering only 

the failure to meet the ACTIONS of the STE LCO. 
SR Applicability 

B 3.0 

CEOG STS B 3.0-13 Rev. 3.0, 03/31/04 

B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY 

BASES 

SRs SR 3.0.1 through SR 3.0.4 establish the general requirements applicable 

to all Specifications and apply at all times, unless otherwise stated. 

SR 3.0.1 SR 3.0.1 establishes the requirement that SRs must be met during the 

MODES or other specified conditions in the Applicability for which the 

requirements of the LCO apply, unless otherwise specified in the 

individual SRs. This Specification is to ensure that Surveillances are 

performed to verify the OPERABILITY of systems and components, and 

that variables are within specified limits. Failure to meet a Surveillance 

within the specified Frequency, in accordance with SR 3.0.2, constitutes a 

failure to meet an LCO. Surveillances may be performed by means of 

any series of sequential, overlapping, or total steps provided the entire 

Surveillance is performed within the specified Frequency. Additionally, 

the definitions related to instrument testing (e.g., CHANNEL 

CALIBRATION) specify that these tests are performed by means of any 

series of sequential, overlapping, or total steps. 

Systems and components are assumed to be OPERABLE when the 

associated SRs have been met. Nothing in this Specification, however, is 

to be construed as implying that systems or components are OPERABLE 

when either: 

a. The systems or components are known to be inoperable, although 

still meeting the SRs or 

b. The requirements of the Surveillance(s) are known to be not met 

between required Surveillance performances. 

Surveillances do not have to be performed when the unit is in a MODE or 

other specified condition for which the requirements of the associated 

LCO are not applicable, unless otherwise specified. The SRs associated 

with a special test exception (STE) are only applicable when the STE is 

used as an allowable exception to the requirements of a Specification. 

Unplanned events may satisfy the requirements (including applicable 

acceptance criteria) for a given SR. In this case, the unplanned event 

may be credited as fulfilling the performance of the SR. This allowance 

includes those SRs whose performance is normally precluded in a given 

MODE or other specified condition. 

Surveillances, including Surveillances invoked by Required Actions, do 

not have to be performed on inoperable equipment because the 

ACTIONS define the remedial measures that apply. Surveillances have 

to be met and performed in accordance with SR 3.0.2, prior to returning 

equipment to OPERABLE status. 
SR Applicability 

B 3.0 

CEOG STS B 3.0-14 Rev. 3.0, 03/31/04 

BASES 

SR 3.0.1 (continued) 

Upon completion of maintenance, appropriate post maintenance testing is 

required to declare equipment OPERABLE. This includes ensuring 

applicable Surveillances are not failed and their most recent performance 

is in accordance with SR 3.0.2. Post maintenance testing may not be 

possible in the current MODE or other specified conditions in the 

Applicability due to the necessary unit parameters not having been 

established. In these situations, the equipment may be considered 

OPERABLE provided testing has been satisfactorily completed to the 

extent possible and the equipment is not otherwise believed to be 

incapable of performing its function. This will allow operation to proceed 

to a MODE or other specified condition where other necessary post 

maintenance tests can be completed. 

Some examples of this process are: 

a. Auxiliary feedwater (AFW) pump turbine maintenance during 

refueling that requires testing at steam pressures > 800 psi. 

However, if other appropriate testing is satisfactorily completed, the 

AFW System can be considered OPERABLE. This allows startup 

and other necessary testing to proceed until the plant reaches the 

steam pressure required to perform the testing. 

b. High pressure safety injection (HPSI) maintenance during shutdown 

that requires system functional tests at a specified pressure. 

Provided other appropriate testing is satisfactorily completed, startup 

can proceed with HPSI considered OPERABLE. This allows 

operation to reach the specified pressure to complete the necessary 

post maintenance testing. 

SR 3.0.2 SR 3.0.2 establishes the requirements for meeting the specified 

Frequency for Surveillances and any Required Action with a Completion 

Time that requires the periodic performance of the Required Action on a 

"once per..." interval. 

SR 3.0.2 permits a 25% extension of the interval specified in the 

Frequency. This extension facilitates Surveillance scheduling and 

considers plant operating conditions that may not be suitable for 

conducting the Surveillance (e.g., transient conditions or other ongoing 

Surveillance or maintenance activities). 
SR Applicability 

B 3.0 

CEOG STS B 3.0-15 Rev. 3.0, 03/31/04 

BASES 

SR 3.0.2 (continued) 

The 25% extension does not significantly degrade the reliability that 

results from performing the Surveillance at its specified Frequency. This 

is based on the recognition that the most probable result of any particular 

Surveillance being performed is the verification of conformance with the 

SRs. The exceptions to SR 3.0.2 are those Surveillances for which the 

25% extension of the interval specified in the Frequency does not apply. 

These exceptions are stated in the individual Specifications. The 

requirements of regulations take precedence over the TS. An example of 

where SR 3.0.2 does not apply is in the Containment Leakage Rate 

Testing Program. This program establishes testing requirements and 

Frequencies in accordance with the requirements of regulations. The TS 

cannot in and of themselves extend a test interval specified in the 

regulations. 

As stated in SR 3.0.2, the 25% extension also does not apply to the initial 

portion of a periodic Completion Time that requires performance on a 

"once per ..." basis. The 25% extension applies to each performance 

after the initial performance. The initial performance of the Required 

Action, whether it is a particular Surveillance or some other remedial 

action, is considered a single action with a single Completion Time. One 

reason for not allowing the 25% extension to this Completion Time is that 

such an action usually verifies that no loss of function has occurred by 

checking the status of redundant or diverse components or accomplishes 

the function of the inoperable equipment in an alternative manner. 

The provisions of SR 3.0.2 are not intended to be used repeatedly merely 

as an operational convenience to extend Surveillance intervals (other 

than those consistent with refueling intervals) or periodic Completion 

Time intervals beyond those specified. 

SR 3.0.3 SR 3.0.3 establishes the flexibility to defer declaring affected equipment 

inoperable or an affected variable outside the specified limits when a 

Surveillance has not been completed within the specified Frequency. A 

delay period of up to 24 hours or up to the limit of the specified 

Frequency, whichever is greater, applies from the point in time that it is 

discovered that the Surveillance has not been performed in accordance 

with SR 3.0.2, and not at the time that the specified Frequency was not 

met. 

This delay period provides adequate time to complete Surveillances that 

have been missed. This delay period permits the completion of a 

Surveillance before complying with Required Actions or other remedial 

measures that might preclude completion of the Surveillance. 
SR Applicability 

B 3.0 

CEOG STS B 3.0-16 Rev. 3.0, 03/31/04 

BASES 

SR 3.0.3 (continued) 

The basis for this delay period includes consideration of unit conditions, 

adequate planning, availability of personnel, the time required to perform 

the Surveillance, the safety significance of the delay in completing the 

required Surveillance, and the recognition that the most probable result of 

any particular Surveillance being performed is the verification of 

conformance with the requirements. 

When a Surveillance with a Frequency based not on time intervals, but 

upon specified unit conditions, operating situations, or requirements of 

regulations (e.g., prior to entering MODE 1 after each fuel loading, or in 

accordance with 10 CFR 50, Appendix J, as modified by approved 

exemptions, etc.) is discovered to not have been performed when 

specified, SR 3.0.3 allows for the full delay period of up to the specified 

Frequency to perform the Surveillance. However, since there is not a 

time interval specified, the missed Surveillance should be performed at 

the first reasonable opportunity. 

SR 3.0.3 provides a time limit for, and allowances for the performance of, 

Surveillances that become applicable as a consequence of MODE 

changes imposed by Required Actions. 

Failure to comply with specified Frequencies for SRs is expected to be an 

infrequent occurrence. Use of the delay period established by SR 3.0.3 is 

a flexibility which is not intended to be used as an operational 

convenience to extend Surveillance intervals. While up to 24 hours or the 

limit of the specified Frequency is provided to perform the missed 

Surveillance, it is expected that the missed Surveillance will be performed 

at the first reasonable opportunity. The determination of the first 

reasonable opportunity should include consideration of the impact on 

plant risk (from delaying the Surveillance as well as any plant 

configuration changes required or shutting the plant down to perform the 

Surveillance) and impact on any analysis assumptions, in addition to unit 

conditions, planning, availability of personnel, and the time required to 

perform the Surveillance. This risk impact should be managed through 

the program in place to implement 10 CFR 50.65(a)(4) and its 

implementation guidance, NRC Regulatory Guide 1.182, “Assessing and 

Managing Risk Before Maintenance Activities at Nuclear Power Plants.” 

This Regulatory Guide addresses consideration of temporary and 

aggregate risk impacts, determination of risk management action 

thresholds, and risk management action up to and including plant 
SR Applicability 

B 3.0 

CEOG STS B 3.0-17 Rev. 3.0, 03/31/04 

BASES 

SR 3.0.3 (continued) 

shutdown. The missed Surveillance should be treated as an emergent 

condition as discussed in the Regulatory Guide. The risk evaluation may 

use quantitative, qualitative, or blended methods. The degree of depth 

and rigor of the evaluation should be commensurate with the importance 

of the component. Missed Surveillances for important components 

should be analyzed quantitatively. If the results of the risk evaluation 

determine the risk increase is significant, this evaluation should be used 

to determine the safest course of action. All missed Surveillances will be 

placed in the licensee’s Corrective Action Program. 

If a Surveillance is not completed within the allowed delay period, then 

the equipment is considered inoperable or the variable is considered 

outside the specified limits and the Completion Times of the Required 

Actions for the applicable LCO Conditions begin immediately upon 

expiration of the delay period. If a Surveillance is failed within the delay 

period, then the equipment is inoperable, or the variable is outside the 

specified limits and the Completion Times of the Required Actions for the 

applicable LCO Conditions begin immediately upon the failure of the 

Surveillance. 

Completion of the Surveillance within the delay period allowed by this 

Specification, or within the Completion Time of the ACTIONS, restores 

compliance with SR 3.0.1. 

SR 3.0.4 SR 3.0.4 establishes the requirement that all applicable SRs must be met 

before entry into a MODE or other specified condition in the Applicability. 

This Specification ensures that system and component OPERABILITY 

requirements and variable limits are met before entry into MODES or 

other specified conditions in the Applicability for which these systems and 

components ensure safe operation of the unit. The provisions of this 

Specification should not be interpreted as endorsing the failure to 

exercise the good practice of restoring systems or components to 

OPERABLE status before entering an associated MODE or other 

specified condition in the Applicability. 

A provision is included to allow entry into a MODE or other specified 

condition in the Applicability when an LCO is not met due to a 

Surveillance not being met in accordance with LCO 3.0.4. 
SR Applicability 

B 3.0 

CEOG STS B 3.0-18 Rev. 3.0, 03/31/04 

BASES 

SR 3.0.4 (continued) 

However, in certain circumstances, failing to meet an SR will not result in 

SR 3.0.4 restricting a MODE change or other specified condition change. 

When a system, subsystem, division, component, device, or variable is 

inoperable or outside its specified limits, the associated SR(s) are not 

required to be performed, per SR 3.0.1, which states that surveillances do 

not have to be performed on inoperable equipment. When equipment is 

inoperable, SR 3.0.4 does not apply to the associated SR(s) since the 

requirement for the SR(s) to be performed is removed. Therefore, failing 

to perform the Surveillance(s) within the specified Frequency does not 

result in an SR 3.0.4 restriction to changing MODES or other specified 

conditions of the Applicability. However, since the LCO is not met in this 

instance, LCO 3.0.4 will govern any restrictions that may (or may not) 

apply to MODE or other specified condition changes. SR 3.0.4 does not 

restrict changing MODES or other specified conditions of the Applicability 

when a Surveillance has not been performed within the specified 

Frequency, provided the requirement to declare the LCO not met has 

been delayed in accordance with SR 3.0.3. 

The provisions of SR 3.0.4 shall not prevent entry into MODES or other 

specified conditions in the Applicability that are required to comply with 

ACTIONS. In addition, the provisions of SR 3.0.4 shall not prevent 

changes in MODES or other specified conditions in the Applicability that 

result from any unit shutdown. In this context, a unit shutdown is defined 

as a change in MODE or other specified condition in the Applicability 

associated with transitioning from MODE 1 to MODE 2, MODE 2 to 

MODE 3, MODE 3 to MODE 4, and MODE 4 to MODE 5. 

The precise requirements for performance of SRs are specified such that 

exceptions to SR 3.0.4 are not necessary. The specific time frames and 

conditions necessary for meeting the SRs are specified in the Frequency, 

in the Surveillance, or both. This allows performance of Surveillances 

when the prerequisite condition(s) specified in a Surveillance procedure 

require entry into the MODE or other specified condition in the 

Applicability of the associated LCO prior to the performance or completion 

of a Surveillance. A Surveillance that could not be performed until after 

entering the LCO’s Applicability, would have its Frequency specified such 

that it is not "due" until the specific conditions needed are met. 

Alternately, the Surveillance may be stated in the form of a Note, as not 

required (to be met or performed) until a particular event, condition, or 

time has been reached. Further discussion of the specific formats of SRs' 

annotation is found in Section 1.4, Frequency. 
SDM (Analog) 

B 3.1.1 

CEOG STS B 3.1.1-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.1 SHUTDOWN MARGIN (SDM) (Analog) 

BASES 

BACKGROUND The reactivity control systems must be redundant and capable of holding 

the reactor core subcritical when shut down under cold conditions, in 

accordance with GDC 26 (Ref. 1). Maintenance of the SHUTDOWN 

MARGIN (SDM) ensures that postulated reactivity events will not damage 

the fuel. SDM requirements provide sufficient reactivity margin to ensure 

that acceptable fuel design limits will not be exceeded for normal 

shutdown and anticipated operational occurrences (AOOs). As such, the 

SDM defines the degree of subcriticality that would be obtained 

immediately following the insertion of all control element assemblies 

(CEAs), assuming the single CEA of highest reactivity worth is fully 

withdrawn. 

The system design requires that two independent reactivity control 

systems be provided, and that one of these systems be capable of 

maintaining the core subcritical under cold conditions. These 

requirements are provided by the use of movable CEAs and soluble boric 

acid in the Reactor Coolant System (RCS). The CEA System provides 

the SDM during power operation and is capable of making the core 

subcritical rapidly enough to prevent exceeding acceptable fuel damage 

limits, assuming that the CEA of highest reactivity worth remains fully 

withdrawn. 

The soluble boron system can compensate for fuel depletion during 

operation and all xenon burnout reactivity changes, and maintain the 

reactor subcritical under cold conditions. 

During power operation, SDM control is ensured by operating with the 

shutdown CEAs fully withdrawn and the regulating CEAs within the limits 

of LCO 3.1.6, "Regulating Control Element Assembly (CEA) Insertion 

Limits." When the unit is in the shutdown and refueling modes, the SDM 

requirements are met by means of adjustments to the RCS boron 

concentration. 

APPLICABLE The minimum required SDM is assumed as an initial condition in safety 

SAFETY analysis. The safety analysis (Ref. 2) establishes an SDM that ensures 

ANALYSES specified acceptable fuel design limits are not exceeded for normal 

operation and AOOs, with the assumption of the highest worth CEA stuck 

out following a reactor trip. For MODE 5, the primary safety analysis that 

relies on the SDM limits is the boron dilution analysis. 
SDM (Analog) 

B 3.1.1 

CEOG STS B 3.1.1-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The acceptance criteria for the SDM requirements are that specified 

acceptable fuel design limits are maintained. This is done by ensuring 

that: 

a. The reactor can be made subcritical from all operating conditions, 

transients, and Design Basis Events, 

b. The reactivity transients associated with postulated accident 

conditions are controllable within acceptable limits (departure from 

nucleate boiling ratio (DNBR), fuel centerline temperature limit AOOs, 

and ≤ 280 cal/gm energy deposition for the CEA ejection accident), 

and 

c. The reactor will be maintained sufficiently subcritical to preclude 

inadvertent criticality in the shutdown condition. 

The most limiting accident for the SDM requirements are based on a main 

steam line break (MSLB), as described in the accident analysis (Ref. 2). 

The increased steam flow resulting from a pipe break in the main steam 

system causes an increased energy removal from the affected steam 

generator (SG), and consequently the RCS. This results in a reduction of 

the reactor coolant temperature. The resultant coolant shrinkage causes 

a reduction in pressure. In the presence of a negative moderator 

temperature coefficient, this cooldown causes an increase in core 

reactivity. As RCS temperature decreases, the severity of an MSLB 

decreases until the MODE 5 value is reached. The most limiting MSLB, 

with respect to potential fuel damage before a reactor trip occurs, is a 

guillotine break of a main steam line inside containment initiated at the 

end of core life. The positive reactivity addition from the moderator 

temperature decrease will terminate when the affected SG boils dry, thus 

terminating RCS heat removal and cooldown. Following the MSLB, a 

post trip return to power may occur; however, no fuel damage occurs as a 

result of the post trip return to power, and THERMAL POWER does not 

violate the Safety Limit (SL) requirement of SL 2.1.1. 

In addition to the limiting MSLB transient, the SDM requirement for 

MODES 3 and 4 must also protect against: 
SDM (Analog) 

B 3.1.1 

CEOG STS B 3.1.1-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

a. Inadvertent boron dilution, 

b. An uncontrolled CEA withdrawal from a subcritical condition, 

c. Startup of an inactive reactor coolant pump (RCP), and 

d. CEA ejection. 

Each of these events is discussed below. 

In the boron dilution analysis, the required SDM defines the reactivity 

difference between an initial subcritical boron concentration and the 

corresponding critical boron concentration. These values, in conjunction 

with the configuration of the RCS and the assumed dilution flow rate, 

directly affect the results of the analysis. This event is most limiting at the 

beginning of core life when critical boron concentrations are highest. 

The withdrawal of CEAs from subcritical conditions adds reactivity to the 

reactor core, causing both the core power level and heat flux to increase 

with corresponding increases in reactor coolant temperatures and 

pressure. The withdrawal of CEAs also produces a time dependent 

redistribution of core power. 

Depending on the system initial conditions and reactivity insertion rate, 

the uncontrolled CEA withdrawal transient is terminated by either a high 

power trip or a high pressurizer pressure trip. In all cases, power level, 

RCS pressure, linear heat rate, and the DNBR do not exceed allowable 

limits. 

The startup of an inactive RCP will not result in a "cold water" criticality, 

even if the maximum difference in temperature exists between the SG 

and the core. The maximum positive reactivity addition that can occur 

due to an inadvertent RCP start is less than half the minimum required 

SDM. An idle RCP cannot, therefore, produce a return to power from the 

hot standby condition. 

SDM satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 
SDM (Analog) 

B 3.1.1 

CEOG STS B 3.1.1-4 Rev. 3.0, 03/31/04 

BASES 

LCO The MSLB (Ref. 2) and the boron dilution (Ref. 3) accidents are the most 

limiting analyses that establish the SDM value of the LCO. For MSLB 

accidents, if the LCO is violated, there is a potential to exceed the DNBR 

limit and to exceed 10 CFR 100, "Reactor Site Criteria," limits (Ref. 4). 

For the boron dilution accident, if the LCO is violated, then the minimum 

required time assumed for operator action to terminate dilution may no 

longer be applicable. 

SDM is a core physics design condition that can be ensured through CEA 

positioning (regulating and shutdown CEA) and through the soluble boron 

concentration. 

APPLICABILITY In MODES 3, 4, and 5, the SDM requirements are applicable to provide 

sufficient negative reactivity to meet the assumptions of the safety 

analyses discussed above. In MODES 1 and 2, SDM is ensured by 

complying with LCO 3.1.5, "Shutdown Control Element Assembly (CEA) 

Insertion Limits," and LCO 3.1.6. In MODE 6, the shutdown reactivity 

requirements are given in LCO 3.9.1, "Boron Concentration." 

ACTIONS A.1

If the SDM requirements are not met, boration must be initiated promptly. 

A Completion Time of 15 minutes is adequate for an operator to correctly 

align and start the required systems and components. It is assumed that 

boration will be continued until the SDM requirements are met. 

In the determination of the required combination of boration flow rate and 

boron concentration, there is no unique requirement that must be 

satisfied. Since it is imperative to raise the boron concentration of the 

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 borated water storage tank. The operator should 

borate with the best source available for the plant conditions. 

In determining the boration flow rate, the time core life must be 

considered. For instance, the most difficult time in core life to increase 

the RCS boron concentration is at the beginning of cycle, when the boron 

concentration may approach or exceed 2000 ppm. Assuming that a value 

of 1% ∆k/k must be recovered and a boration flow rate of [ ] gpm, it is 

possible to increase the boron concentration of the RCS by 100 ppm in 

approximately 35 minutes. If a boron worth of 10 pcm/ppm is assumed, 

this combination of parameters will increase the SDM by 1% ∆k/k. These 

boration parameters of [ ] gpm and [ ] ppm represent typical values and 

are provided for the purpose of offering a specific example. 
SDM (Analog) 

B 3.1.1 

CEOG STS B 3.1.1-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.1.1.1

REQUIREMENTS 

SDM is verified by performing a reactivity balance calculation, considering 

the listed reactivity effects: 

a. RCS boron concentration, 

b. CEA positions, 

c. RCS average temperature, 

d. Fuel burnup based on gross thermal energy generation, 

e. Xenon concentration, 

f. Samarium concentration, and 

g. Isothermal temperature coefficient (ITC). 

Using the ITC accounts for Doppler reactivity in this calculation because 

the reactor is subcritical and the fuel temperature will be changing at the 

same rate as the RCS. 

The Frequency of 24 hours is based on the generally slow change in 

required boron concentration, and also allows sufficient time for the 

operator to collect the required data, which includes performing a boron 

concentration analysis, and complete the calculation. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26. 

 2. FSAR, Section [ ]. 

 3. FSAR, Section [ ]. 

 4. 10 CFR 100. 
SDM (Digital) 

B 3.1.1 

CEOG STS B 3.1.1-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.1 SHUTDOWN MARGIN (SDM) (Digital) 

BASES 

BACKGROUND The reactivity control systems must be redundant and capable of holding 

the reactor core subcritical when shutdown under cold conditions, in 

accordance with GDC 26 (Ref. 1). Maintenance of the SHUTDOWN 

MARGIN (SDM) ensures that postulated reactivity events will not damage 

the fuel. SDM requirements provide sufficient reactivity margin to ensure 

that acceptable fuel design limits will not be exceeded for normal 

shutdown and anticipated operational occurrences (AOOs). As such, the 

SDM defines the degree of subcriticality that would be obtained 

immediately following the insertion of all full length control element 

assemblies (CEAs), assuming the single CEA of highest reactivity worth 

is fully withdrawn. 

The system design requires that two independent reactivity control 

systems be provided, and that one of these systems be capable of 

maintaining the core subcritical under cold conditions. These 

requirements are provided by the use of movable CEAs and soluble boric 

acid in the Reactor Coolant System (RCS). The CEA System provides 

the SDM during power operation and is capable of making the core 

subcritical rapidly enough to prevent exceeding acceptable fuel damage 

limits, assuming that the CEA of highest reactivity worth remains fully 

withdrawn. 

The soluble boron system can compensate for fuel depletion during 

operation and all xenon burnout reactivity changes, and maintain the 

reactor subcritical under cold conditions. 

During power operation, SDM control is ensured by operating with the 

shutdown CEAs fully withdrawn and the regulating CEAs within the limits 

of LCO 3.1.6, "Regulating Control Element Assembly (CEA) Insertion 

Limits." When the unit is in the shutdown and refueling modes, the SDM 

requirements are met by means of adjustments to the RCS boron 

concentration. 

APPLICABLE The minimum required SDM is assumed as an initial condition in safety 

SAFETY analysis. The safety analysis (Ref. 2) establishes an SDM that ensures 

ANALYSES specified acceptable fuel design limits are not exceeded for normal 

operation and AOOs, with the assumption of the highest worth CEA stuck 

out following a reactor trip. For MODE 5, the primary safety analysis that 

relies on the SDM limits is the boron dilution analysis. 
SDM (Digital) 

B 3.1.1 

CEOG STS B 3.1.1-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The acceptance criteria for the SDM are that specified acceptable fuel 

design limits are maintained. This is done by ensuring that: 

a. The reactor can be made subcritical from all operating conditions, 

transients, and Design Basis Events, 

b. The reactivity transients associated with postulated accident 

conditions are controllable within acceptable limits (departure from 

nucleate boiling ratio (DNBR), fuel centerline temperature limit AOOs, 

and ≤ 280 cal/gm energy deposition for the CEA ejection accident), 

and 

c. The reactor will be maintained sufficiently subcritical to preclude 

inadvertent criticality in the shutdown condition. 

The most limiting accident for the SDM requirements are based on a main 

steam line break (MSLB), as described in the accident analysis (Ref. 2). 

The increased steam flow resulting from a pipe break in the main steam 

system causes an increased energy removal from the affected steam 

generator (SG), and consequently the RCS. This results in a reduction of 

the reactor coolant temperature. The resultant coolant shrinkage causes 

a reduction in pressure. In the presence of a negative moderator 

temperature coefficient, this cooldown causes an increase in core 

reactivity. As RCS temperature decreases, the severity of an MSLB 

decreases until the MODE 5 value is reached. The most limiting MSLB, 

with respect to potential fuel damage before a reactor trip occurs, is a 

guillotine break of a main steam line inside containment initiated at the 

end of core life. The positive reactivity addition from the moderator 

temperature decrease will terminate when the affected SG boils dry, thus 

terminating RCS heat removal and cooldown. Following the MSLB, a 

post trip return to power may occur; however, no fuel damage occurs as a 

result of the post trip return to power, and THERMAL POWER does not 

violate the Safety Limit (SL) requirement of SL 2.1.1. 

In addition to the limiting MSLB transient, the SDM requirement for 

MODES 3 and 4 must also protect against: 

a. Inadvertent boron dilution, 

b. An uncontrolled CEA withdrawal from a subcritical condition, 

c. Startup of an inactive reactor coolant pump (RCP), and 

d. CEA ejection. 
SDM (Digital) 

B 3.1.1 

CEOG STS B 3.1.1-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Each of these is discussed below. 

In the boron dilution analysis, the required SDM defines the reactivity 

difference between an initial subcritical boron concentration and the 

corresponding critical boron concentration. These values, in conjunction 

with the configuration of the RCS and the assumed dilution flow rate, 

directly affect the results of the analysis. This event is most limiting at the 

beginning of core life when critical boron concentrations are highest. 

The withdrawal of CEAs from subcritical conditions adds reactivity to the 

reactor core, causing both the core power level and heat flux to increase 

with corresponding increases in reactor coolant temperatures and 

pressure. The withdrawal of CEAs also produces a time dependent 

redistribution of core power. 

Depending on the system initial conditions and reactivity insertion rate, 

the uncontrolled CEA withdrawal transient is terminated by either a high 

power level trip or a high pressurizer pressure trip. In all cases, power 

level, RCS pressure, linear heat rate, and the DNBR do not exceed 

allowable limits. 

The startup of an inactive RCP will not result in a "cold water" criticality, 

even if the maximum difference in temperature exists between the SG 

and the core. The maximum positive reactivity addition that can occur 

due to an inadvertent RCP start is less than half the minimum required 

SDM. An idle RCP cannot, therefore, produce a return to power from the 

hot standby condition. 

The withdrawal of CEAs from subcritical or low power Conditions adds 

reactivity to the reactor core, causing both the core power level and heat 

flux to increase with corresponding increases in reactor coolant 

temperatures and pressure. The withdrawal of CEAs also produces a 

time dependent redistribution of core power. 

The SDM satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The MSLB (Ref. 2) and the boron dilution (Ref. 3) accidents are the most 

limiting analyses that establish the SDM value of the LCO. For MSLB 

accidents, if the LCO is violated, there is a potential to exceed the DNBR 

limit and to exceed 10 CFR 100, "Reactor Site Criterion," limits (Ref. 4). 

For the boron dilution accident, if the LCO is violated, then the minimum 

required time assumed for operator action to terminate dilution may no 

longer be applicable. 
SDM (Digital) 

B 3.1.1 

CEOG STS B 3.1.1-4 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

SDM is a core physics design condition that can be ensured through CEA 

positioning (regulating and shutdown CEAs) and through the soluble 

boron concentration. 

APPLICABILITY In MODES 3, 4, and 5, the SDM requirements are applicable to provide 

sufficient negative reactivity to meet the assumptions of the safety 

analyses discussed above. In MODES 1 and 2, SDM is ensured by 

complying with LCO 3.1.5, "Shutdown Control Element Assembly (CEA) 

Insertion Limits," and LCO 3.1.6. In MODE 6, the shutdown reactivity 

requirements are given in LCO 3.9.1, "Boron Concentration." 

ACTIONS A.1

If the SDM requirements are not met, boration must be initiated promptly. 

A Completion Time of 15 minutes is adequate for an operator to correctly 

align and start the required systems and components. It is assumed that 

boration will be continued until the SDM requirements are met. 

In the determination of the required combination of boration flow rate and 

boron concentration, there is no unique requirement that must be 

satisfied. Since it is imperative to raise the boron concentration of the 

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 borated water storage tank. The operator should 

borate with the best source available for the plant conditions. 

In determining the boration flow rate, the time core life must be 

considered. For instance, the most difficult time in core life to increase 

the RCS boron concentration is at the beginning of cycle, when the boron 

concentration may approach or exceed 2000 ppm. Assuming that a value 

of 1% ∆k/k must be recovered and a boration flow rate of [ ] gpm, it is 

possible to increase the boron concentration of the RCS by 100 ppm in 

approximately 35 minutes. If a boron worth of 10 pcm/ppm is assumed, 

this combination of parameters will increase the SDM by 1% ∆k/k. These 

boration parameters of [ ] gpm and [ ] ppm represent typical values and 

are provided for the purpose of offering a specific example. 
SDM (Digital) 

B 3.1.1 

CEOG STS B 3.1.1-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.1.1.1

REQUIREMENTS 

SDM is verified by performing a reactivity balance calculation, considering 

the listed reactivity effects: 

a. RCS boron concentration, 

b. CEA positions, 

c. RCS average temperature, 

d. Fuel burnup based on gross thermal energy generation, 

e. Xenon concentration, 

f. Samarium concentration, and 

g. Isothermal temperature coefficient (ITC). 

Using the ITC accounts for Doppler reactivity in this calculation because 

the reactor is subcritical, and the fuel temperature will be changing at the 

same rate as the RCS. 

The Frequency of 24 hours is based on the generally slow change in 

required boron concentration, and also allows sufficient time for the 

operator to collect the required data, which includes performing a boron 

concentration analysis, and complete the calculation. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26. 

 2. FSAR, Section [15.4.2]. 

 3. FSAR, Section [15.4.2]. 

 4. 10 CFR 100. 
Reactivity Balance (Analog) 

B 3.1.2 

CEOG STS B 3.1.2-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.2 Reactivity Balance (Analog) 

BASES 

BACKGROUND According to GDC 26, GDC 28, and GDC 29 (Ref. 1), reactivity shall be 

controllable, such that, subcriticality is maintained under cold conditions, 

and acceptable fuel design limits are not exceeded during normal 

operation and anticipated operational occurrences. Therefore, reactivity 

balance is used as a measure of the predicted versus measured core 

reactivity during power operation. The periodic confirmation of core 

reactivity is necessary to ensure that Design Basis Accident (DBA) and 

transient safety analyses remain valid. A large reactivity difference could 

be the result of unanticipated changes in fuel, control element assembly 

(CEA) worth, or operation at conditions not consistent with those 

assumed in the predictions of core reactivity, and could potentially result 

in a loss of SDM or violation of acceptable fuel design limits. Comparing 

predicted versus measured core reactivity validates the nuclear methods 

used in the safety analysis and supports the SDM demonstrations 

(LCO 3.1.1, "SHUTDOWN MARGIN (SDM)") in ensuring the reactor can 

be brought safely to cold, subcritical conditions. 

When the reactor core is critical or in normal power operation, a reactivity 

balance exists and the net reactivity is zero. A comparison of predicted 

and measured reactivity is convenient under such a balance, since 

parameters are being maintained relatively stable under steady state 

power conditions. The positive reactivity inherent in the core design is 

balanced by the negative reactivity of the control components, thermal 

feedback, neutron leakage, and materials in the core that absorb 

neutrons, such as burnable absorbers producing zero net reactivity. 

Excess reactivity can be inferred from the critical boron curve, which 

provides an indication of the soluble boron concentration in the Reactor 

Coolant System (RCS) versus cycle burnup. Periodic measurement of 

the RCS boron concentration for comparison with the predicted value with 

other variables fixed (such as CEA height, temperature, pressure, and 

power) provides a convenient method of ensuring that core reactivity is 

within design expectations, and that the calculational models used to 

generate the safety analysis are adequate. 

In order to achieve the required fuel cycle energy output, the uranium 

enrichment in the new fuel loading and in the fuel remaining from the 

previous cycle, provides excess positive reactivity beyond that required to 

sustain steady state operation throughout the cycle. When the reactor is 

critical at RTP and moderator temperature, the excess positive reactivity 

is compensated by burnable absorbers (if any), CEAs, whatever neutron 

poisons (mainly xenon and samarium) are present in the fuel, and the 

RCS boron concentration. 
Reactivity Balance (Analog) 

B 3.1.2 

CEOG STS B 3.1.2-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

When the core is producing THERMAL POWER, the fuel is being 

depleted and excess reactivity is decreasing. As the fuel depletes, the 

RCS boron concentration is reduced to decrease negative reactivity and 

maintain constant THERMAL POWER. The critical boron curve is based 

on steady state operation at RTP. Therefore, deviations from the 

predicted critical boron curve may indicate deficiencies in the design 

analysis, deficiencies in the calculational models, or abnormal core 

conditions, and must be evaluated. 

APPLICABLE Accurate prediction of core reactivity is either an explicit or implicit 

SAFETY assumption in the accident analysis evaluations. Every accident 

ANALYSES evaluation (Ref. 2) is, therefore, dependent upon accurate evaluation of 

core reactivity. In particular, SDM and reactivity transients, such as CEA 

withdrawal accidents or CEA ejection accidents, are very sensitive to 

accurate prediction of core reactivity. These accident analysis 

evaluations rely on computer codes that have been qualified against 

available test data, operating plant data, and analytical benchmarks. 

Monitoring reactivity balance additionally ensures that the nuclear 

methods provide an accurate representation of the core reactivity. 

Design calculations and safety analyses are performed for each fuel cycle 

for the purpose of predetermining reactivity behavior and the RCS boron 

concentration requirements for reactivity control during fuel depletion. 

The comparison between measured and predicted initial core reactivity 

provides a normalization for calculational models used to predict core 

reactivity. If the measured and predicted RCS boron concentrations for 

identical core conditions at beginning of cycle (BOC) do not agree, then 

the assumptions used in the reload cycle design analysis or the 

calculational models used to predict soluble boron requirements may not 

be accurate. If reasonable agreement between measured and predicted 

core reactivity exists at BOC, then the prediction may be normalized to 

the measured boron concentration. Thereafter, any significant deviations 

in the measured boron concentration from the predicted critical boron 

curve that develop during fuel depletion may be an indication that the 

calculational model is not adequate for core burnups beyond BOC, or that 

an unexpected change in core conditions has occurred. 
Reactivity Balance (Analog) 

B 3.1.2 

CEOG STS B 3.1.2-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The normalization of predicted RCS boron concentration to the measured 

value is typically performed after reaching RTP following startup from a 

refueling outage, with the CEAs in their normal positions for power 

operation. The normalization is performed at BOC conditions, so that 

core reactivity relative to predicted values can be continually monitored 

and evaluated as core conditions change during the cycle. 

The reactivity balance satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The reactivity balance limit is established to ensure plant operation is 

maintained within the assumptions of the safety analyses. Large 

differences between actual and predicted core reactivity may indicate that 

the assumptions of the DBA and transient analyses are no longer valid, or 

that the uncertainties in the nuclear design methodology are larger than 

expected. A limit on the reactivity balance of ± 1% ∆k/k has been 

established, based on engineering judgment. A 1% deviation in reactivity 

from that predicted is larger than expected for normal operation and 

should therefore be evaluated. 

When measured core reactivity is within 1% ∆k/k of the predicted value at 

steady state thermal conditions, the core is considered to be operating 

within acceptable design limits. Since deviations from the limit are 

normally detected by comparing predicted and measured steady state 

RCS critical boron concentrations, the difference between measured and 

predicted values would be approximately 100 ppm (depending on the 

boron worth) before the limit is reached. These values are well within the 

uncertainty limits for analysis of boron concentration samples, so that 

spurious violations of the limit due to uncertainty in measuring the RCS 

boron concentration are unlikely. 

APPLICABILITY The limits on core reactivity must be maintained during MODES 1 and 2 

because a reactivity balance must exist when the reactor is critical or 

producing THERMAL POWER. As the fuel depletes, core conditions are 

changing, and confirmation of the reactivity balance ensures the core is 

operating as designed. This Specification does not apply in MODES 3, 4, 

and 5 because the reactor is shut down and the reactivity balance is not 

changing. 

In MODE 6, fuel loading results in a continually changing core reactivity. 

Boron concentration requirements (LCO 3.9.1, "Boron Concentration") 

ensure that fuel movements are performed within the bounds of the safety 

analysis. An SDM demonstration is required during the first startup 

following operations that could have altered core reactivity (e.g., fuel 

movement, or CEA replacement, or shuffling). 
Reactivity Balance (Analog) 

B 3.1.2 

CEOG STS B 3.1.2-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1 and A.2

Should an anomaly develop between measured and predicted core 

reactivity, an evaluation of the core design and safety analysis must be 

performed. Core conditions are evaluated to determine their consistency 

with input to design calculations. Measured core and process parameters 

are evaluated to determine that they are within the bounds of the safety 

analysis, and safety analysis calculational models are reviewed to verify 

that they are adequate for representation of the core conditions. The 

required Completion Time of 7 days is based on the low probability of a 

DBA occurring during this period, and allows sufficient time to assess the 

physical condition of the reactor and complete the evaluation of the core 

design and safety analysis. 

Following evaluations of the core design and safety analysis, the cause of 

the reactivity anomaly may be resolved. If the cause of the reactivity 

anomaly is a mismatch in core conditions at the time of RCS boron 

concentration sampling, then a recalculation of the RCS boron 

concentration requirements may be performed to demonstrate that core 

reactivity is behaving as expected. If an unexpected physical change in 

the condition of the core has occurred, it must be evaluated and 

corrected, if possible. If the cause of the reactivity anomaly is in the 

calculation technique, then the calculational models must be revised to 

provide more accurate predictions. If any of these results are 

demonstrated, and it is concluded that the reactor core is acceptable for 

continued operation, then the boron letdown curve may be renormalized, 

and power operation may continue. If operational restrictions or 

additional SRs are necessary to ensure the reactor core is acceptable for 

continued operation, then they must be defined. 

The required Completion Time of 7 days is adequate for preparing 

whatever operating restrictions or Surveillances that may be required to 

allow continued reactor operation. 

B.1

If the core reactivity cannot be restored to within the 1% ∆k/k limit, the 

plant must be brought to a MODE in which the LCO does not apply. To 

achieve this status, the plant must be brought to at least MODE 3 within 

6 hours. If the SDM for MODE 3 is not met, then boration required by 

SR 3.1.1.1 would occur. The allowed Completion Time is reasonable, 

based on operating experience, for reaching MODE 3 from full power 

conditions in an orderly manner and without challenging plant systems. 
Reactivity Balance (Analog) 

B 3.1.2 

CEOG STS B 3.1.2-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.1.2.1

REQUIREMENTS 

Core reactivity is verified by periodic comparisons of measured and 

predicted RCS boron concentrations. The comparison is made 

considering that other core conditions are fixed or stable including CEA 

position, moderator temperature, fuel temperature, fuel depletion, xenon 

concentration, and samarium concentration. The Surveillance is 

performed prior to entering MODE 1 as an initial check on core conditions 

and design calculations at BOC. The SR is modified by three Notes. 

Note 1 in the Surveillance column indicates that the normalization of 

predicted core reactivity to the measured value must take place within the 

first 60 effective full power days (EFPD) after each fuel loading. This 

allows sufficient time for core conditions to reach steady state, but 

prevents operation for a large fraction of the fuel cycle without 

establishing a benchmark for the design calculations. 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 (e.g., QPTR, 

etc.) for prompt indication of an anomaly. A second Note, "only required 

after 60 EFPD," is added to the Frequency column to allow this. Note 2 in 

the Surveillance column indicates that the performance of SR 3.1.2.1 is 

not required prior to entering MODE 2. This Note is required to allow a 

MODE 2 entry to verify core reactivity, because LCO Applicability is for 

MODES 1 and 2. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26, GDC 28, and GDC 29. 

 2. FSAR, Section [ ]. 
Reactivity Balance (Digital) 

B 3.1.2 

CEOG STS B 3.1.2-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.2 Reactivity Balance (Digital) 

BASES 

BACKGROUND According to GDC 26, GDC 28, and GDC 29 (Ref. 1), reactivity shall be 

controllable, such that, subcriticality is maintained under cold conditions, 

and acceptable fuel design limits are not exceeded during normal 

operation and anticipated operational occurrences. Therefore, reactivity 

balance is used as a measure of the predicted versus measured core 

reactivity during power operation. The periodic confirmation of core 

reactivity is necessary to ensure that Design Basis Accident (DBA) and 

transient safety analyses remain valid. A large reactivity difference could 

be the result of unanticipated changes in fuel, control element assembly 

(CEA) worth, or operation at Conditions not consistent with those 

assumed in the predictions of core reactivity, and could potentially result 

in a loss of SDM or violation of acceptable fuel design limits. Comparing 

predicted versus measured core reactivity validates the nuclear methods 

used in the safety analysis and supports the SDM demonstrations 

(LCO 3.1.1, "SHUTDOWN MARGIN (SDM)") in ensuring the reactor can 

be brought safely to cold, subcritical conditions. 

When the reactor core is critical or in normal power operation, a reactivity 

balance exists and the net reactivity is zero. A comparison of predicted 

and measured reactivity is convenient under such a balance, since 

parameters are being maintained relatively stable under steady state 

power conditions. The positive reactivity inherent in the core design is 

balanced by the negative reactivity of the control components, thermal 

feedback, neutron leakage, and materials in the core that absorb 

neutrons, such as burnable absorbers producing zero net reactivity. 

Excess reactivity can be inferred from the critical boron curve, which 

provides an indication of the soluble boron concentration in the Reactor 

Coolant System (RCS) versus cycle burnup. Periodic measurement of 

the RCS boron concentration for comparison with the predicted value with 

other variables fixed (such as CEA height, temperature, pressure, and 

power) provides a convenient method of ensuring that core reactivity is 

within design expectations, and that the calculational models used to 

generate the safety analysis are adequate. 

In order to achieve the required fuel cycle energy output, the uranium 

enrichment in the new fuel loading and in the fuel remaining from the 

previous cycle, provides excess positive reactivity beyond that required to 

sustain steady state operation throughout the cycle. When the reactor is 

critical at RTP and moderator temperature, the excess positive reactivity 

is compensated by burnable absorbers (if any), CEAs, whatever neutron 

poisons (mainly xenon and samarium) are present in the fuel, and the 

RCS boron concentration. 
Reactivity Balance (Digital) 

B 3.1.2 

CEOG STS B 3.1.2-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

When the core is producing THERMAL POWER, the fuel is being 

depleted and excess reactivity is decreasing. As the fuel depletes, the 

RCS boron concentration is reduced to decrease negative reactivity and 

maintain constant THERMAL POWER. The critical boron curve is based 

on steady state operation at RTP. Therefore, deviations from the 

predicted boron letdown curve may indicate deficiencies in the design 

analysis, deficiencies in the calculational models, or abnormal core 

conditions, and must be evaluated. 

APPLICABLE Accurate prediction of core reactivity is either an explicit or implicit 

SAFETY assumption in the accident analysis evaluations. Every accident 

ANALYSES evaluation (Ref. 2) is, therefore, dependent upon accurate evaluation of 

core reactivity. In particular, SDM, and reactivity transients such as CEA 

withdrawal accidents or CEA ejection accidents, are very sensitive to 

accurate prediction of core reactivity. These accident analysis 

evaluations rely on computer codes that have been qualified against 

available test data, operating plant data, and analytical benchmarks. 

Monitoring reactivity balance additionally ensures that the nuclear 

methods provide an accurate representation of the core reactivity. 

Design calculations and safety analyses are performed for each fuel cycle 

for the purpose of predetermining reactivity behavior and the RCS boron 

concentration requirements for reactivity control during fuel depletion. 

The comparison between measured and predicted initial core reactivity 

provides a normalization for calculational models used to predict core 

reactivity. If the measured and predicted RCS boron concentrations for 

identical core conditions at beginning of cycle (BOC) do not agree, then 

the assumptions used in the reload cycle design analysis or the 

calculational models used to predict soluble boron requirements may not 

be accurate. If reasonable agreement between measured and predicted 

core reactivity exists at BOC, then the prediction may be normalized to 

the measured boron concentration. Thereafter, any significant deviations 

in the measured boron concentration from the predicted critical boron 

curve that develop during fuel depletion may be an indication that the 

calculational model is not adequate for core burnups beyond BOC, or that 

an unexpected change in core conditions has occurred. 
Reactivity Balance (Digital) 

B 3.1.2 

CEOG STS B 3.1.2-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The normalization of predicted RCS boron concentration to the measured 

value is typically performed after reaching RTP following startup from a 

refueling outage, with the CEAs in their normal positions for power 

operation. The normalization is performed at BOC conditions, so that 

core reactivity relative to predicted values can be continually monitored 

and evaluated as core conditions change during the cycle. 

The reactivity balance satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The reactivity balance limit is established to ensure plant operation is 

maintained within the assumptions of the safety analyses. Large 

differences between actual and predicted core reactivity may indicate that 

the assumptions of the DBA and transient analyses are no longer valid, or 

that the uncertainties in the nuclear design methodology are larger than 

expected. A limit on the reactivity balance of ± 1% ∆k/k has been 

established, based on engineering judgment. A 1% deviation in reactivity 

from that predicted is larger than expected for normal operation, and 

should therefore be evaluated. 

When measured core reactivity is within 1% ∆k/k of the predicted value at 

steady state thermal conditions, the core is considered to be operating 

within acceptable design limits. Since deviations from the limit are 

normally detected by comparing predicted and measured steady state 

RCS critical boron concentrations, the difference between measured and 

predicted values would be approximately 100 ppm (depending on the 

boron worth) before the limit is reached. These values are well within the 

uncertainty limits for analysis of boron concentration samples, so that 

spurious violations of the limit due to uncertainty in measuring the RCS 

boron concentration are unlikely. 

APPLICABILITY The limits on core reactivity must be maintained during MODES 1 and 2 

because a reactivity balance must exist when the reactor is critical or 

producing THERMAL POWER. As the fuel depletes, core conditions are 

changing, and confirmation of the reactivity balance ensures the core is 

operating as designed. This Specification does not apply in MODES 3, 4, 

and 5 because the reactor is shut down and the reactivity balance is not 

changing. 

In MODE 6, fuel loading results in a continually changing core reactivity. 

Boron concentration requirements (LCO 3.9.1, "Boron Concentration") 

ensure that fuel movements are performed within the bounds of the safety 

analysis. An SDM demonstration is required during the first startup 

following operations that could have altered core reactivity (e.g., fuel 

movement, or CEA replacement, or shuffling). 
Reactivity Balance (Digital) 

B 3.1.2 

CEOG STS B 3.1.2-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1 and A.2

Should an anomaly develop between measured and predicted core 

reactivity, an evaluation of the core design and safety analysis must be 

performed. Core conditions are evaluated to determine their consistency 

with input to design calculations. Measured core and process parameters 

are evaluated to determine that they are within the bounds of the safety 

analysis, and safety analysis calculational models are reviewed to verify 

that they are adequate for representation of the core conditions. The 

required Completion Time of 7 days is based on the low probability of a 

DBA occurring during this period, and allows sufficient time to assess the 

physical condition of the reactor and complete the evaluation of the core 

design and safety analysis. 

Following evaluations of the core design and safety analysis, the cause of 

the reactivity anomaly may be resolved. If the cause of the reactivity 

anomaly is a mismatch in core conditions at the time of RCS boron 

concentration sampling, then a recalculation of the RCS boron 

concentration requirements may be performed to demonstrate that core 

reactivity is behaving as expected. If an unexpected physical change in 

the condition of the core has occurred, it must be evaluated and 

corrected, if possible. If the cause of the reactivity anomaly is in the 

calculation technique, then the calculational models must be revised to 

provide more accurate predictions. If any of these results are 

demonstrated and it is concluded that the reactor core is acceptable for 

continued operation, then the boron letdown curve may be renormalized, 

and power operation may continue. If operational restrictions or 

additional SRs are necessary to ensure the reactor core is acceptable for 

continued operation, then they must be defined. 

The required Completion Time of 7 days is adequate for preparing 

whatever operating restrictions or Surveillances that may be required to 

allow continued reactor operation. 

B.1

If the core reactivity cannot be restored to within the 1% ∆k/k, the plant 

must be brought to a MODE in which the LCO does not apply. To 

achieve this status, the plant must be brought to at least MODE 3 within 

6 hours. If the SDM for MODE 3 is not met, then boration required by 

SR 3.1.1.1 would occur. The allowed Completion Time is reasonable, 

based on operating experience, for reaching MODE 3 from full power 

conditions in an orderly manner and without challenging plant systems. 
Reactivity Balance (Digital) 

B 3.1.2 

CEOG STS B 3.1.2-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.1.2.1

REQUIREMENTS 

Core reactivity is verified by periodic comparisons of measured and 

predicted RCS boron concentrations. The comparison is made 

considering that other core conditions are fixed or stable including CEA 

position, moderator temperature, fuel temperature, fuel depletion, xenon 

concentration, and samarium concentration. The Surveillance is 

performed prior to entering MODE 1 as an initial check on core conditions 

and design calculations at BOC. The SR is modified by three Notes. The 

first Note indicates that the normalization of predicted core reactivity to 

the measured value must take place within the first 60 effective full power 

days (EFPD) after each fuel loading. This allows sufficient time for core 

conditions to reach steady state, but prevents operation for a large 

fraction of the fuel cycle without establishing a benchmark for the design 

calculations. 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 (e.g., QPTR) for prompt indication of an anomaly. A Note, 

"only required after 60 EFPD," is added to the Frequency column to allow 

this. Another Note indicates that the performance of SR 3.1.2.1 is not 

required prior to entering MODE 2. This Note is required to allow a 

MODE 2 entry to verify core reactivity because Applicability is for 

MODES 1 and 2. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26, GDC 28, and GDC 29. 

 2. FSAR, Section [ ]. 
MTC (Analog) 

B 3.1.3 

CEOG STS B 3.1.3-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.3 Moderator Temperature Coefficient (MTC) (Analog) 

BASES 

BACKGROUND According to GDC 11 (Ref. 1), the reactor core and its interaction with the 

Reactor Coolant System (RCS) must be designed for inherently stable 

power operation, even in the possible event of an accident. In particular, 

the net reactivity feedback in the system must compensate for any 

unintended or rapid reactivity increases. 

The MTC relates a change in core reactivity to a change in reactor 

coolant temperature. A positive MTC means that reactivity increases with 

increasing moderator temperature; conversely, a negative MTC means 

that reactivity decreases with increasing moderator temperature. The 

reactor is designed to operate with a negative MTC over the largest 

possible range of fuel cycle operation. Therefore, a coolant temperature 

increase will cause a reactivity decrease, so that the coolant temperature 

tends to return toward its initial value. Reactivity increases that cause a 

coolant temperature increase will thus be self limiting, and stable power 

operation will result. The same characteristic is true when the MTC is 

positive and coolant temperature decreases occur. 

MTC values are predicted at selected burnups during the safety 

evaluation analysis and are confirmed to be acceptable by 

measurements. Both initial and reload cores are designed so that the 

beginning of cycle (BOC) MTC is less positive than that allowed by the 

LCO. The actual value of the MTC is dependent on core characteristics, 

such as fuel loading and reactor coolant soluble boron concentration. 

The core design may require additional fixed distributed poisons (lumped 

burnable poison assemblies) to yield an MTC at the BOC within the range 

analyzed in the plant accident analysis. The end of cycle (EOC) MTC is 

also limited by the requirements of the accident analysis. Fuel cycles that 

are designed to achieve high burnups or that have changes to other 

characteristics are evaluated to ensure that the MTC does not exceed the 

EOC limit. 

APPLICABLE The acceptance criteria for the specified MTC are: 

SAFETY 

ANALYSES a. The MTC values must remain within the bounds of those used in the 

accident analysis (Ref. 2) and 

b. The MTC must be such that inherently stable power operations result 

during normal operation and during accidents, such as overheating 

and overcooling events. 
MTC (Analog) 

B 3.1.3 

CEOG STS B 3.1.3-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Reference 2 contains analyses of accidents that result in both 

overheating and overcooling of the reactor core. MTC is one of the 

controlling parameters for core reactivity in these accidents. Both the 

most positive value and most negative value of the MTC are important to 

safety, and both values must be bounded. Values used in the analyses 

consider worst case conditions, such as very large soluble boron 

concentrations, to ensure the accident results are bounding (Ref. 3). 

Accidents that cause core overheating, either by decreased heat removal 

or increased power production, must be evaluated for results when the 

MTC is positive. Reactivity accidents that cause increased power 

production include the control element assembly (CEA) withdrawal 

transient from either zero or full THERMAL POWER. The limiting 

overheating event relative to plant response is based on the maximum 

difference between core power and steam generator heat removal during 

a transient. The most limiting event with respect to a positive MTC is a 

CEA withdrawal accident from zero power, also referred to as a startup 

accident (Ref. 4). 

Accidents that cause core overcooling must be evaluated for results when 

the MTC is most negative. The event that produces the most rapid 

cooldown of the RCS, and is therefore the most limiting event with 

respect to the negative MTC, is a steam line break (SLB) event. 

Following the reactor trip for the postulated EOC SLB event, the large 

moderator temperature reduction combined with the large negative MTC 

may produce reactivity increases that are as much as the shutdown 

reactivity. When this occurs, a substantial fraction of core power is 

produced with all CEAs inserted, except the most reactive one, which is 

assumed withdrawn. Even if the reactivity increase produces slightly 

subcritical conditions, a large fraction of core power may be produced 

through the effects of subcritical neutron multiplication. 

MTC values are bounded in reload safety evaluations assuming steady 

state conditions at BOC and EOC. A middle of cycle (MOC) 

measurement is conducted at conditions when the RCS boron 

concentration reaches approximately 300 ppm. The measured value may 

be extrapolated to project the EOC value, in order to confirm reload 

design predictions. 

The MTC satisfies Criterion 2 of the NRC Policy Statement. 
MTC (Analog) 

B 3.1.3 

CEOG STS B 3.1.3-3 Rev. 3.0, 03/31/04 

BASES 

LCO LCO 3.1.3 requires the MTC to be within specified limits of the COLR to 

ensure the core operates within the assumptions of the accident analysis. 

During the reload core safety evaluation, the MTC is analyzed to 

determine that its values remain within the bounds of the original accident 

analysis during operation. The limit on a positive MTC ensures that core 

overheating accidents will not violate the accident analysis assumptions. 

The negative MTC limit for EOC specified in the COLR ensures that core 

overcooling accidents will not violate the accident analysis assumptions. 

MTC is a core physics parameter determined by the fuel and fuel cycle 

design and cannot be easily controlled once the core design is fixed. 

During operation, therefore, the LCO can only be ensured through 

measurement. The surveillance checks at BOC and MOC on an MTC 

provide confirmation that the MTC is behaving as anticipated, so that the 

acceptance criteria are met. 

APPLICABILITY In MODE 1, the limits on the MTC must be maintained to ensure that any 

accident initiated from THERMAL POWER operation will not violate the 

design assumptions of the accident analysis. In MODE 2, the limits must 

also be maintained to ensure startup and subcritical accidents, such as 

the uncontrolled CEA or group withdrawal, will not violate the 

assumptions of the accident analysis. In MODES 3, 4, 5, and 6, this LCO 

is not applicable, since no Design Basis Accidents (DBAs) using the MTC 

as an analysis assumption are initiated from these MODES. However, 

the variation of the MTC, with temperature in MODES 3, 4, and 5, for 

DBAs initiated in MODES 1 and 2, is accounted for in the subject accident 

analysis. The variation of the MTC, with temperature assumed in the 

safety analysis, is accepted as valid once the BOC and MOC 

measurements are used for normalization. 

ACTIONS A.1

MTC is a function of the fuel and fuel cycle designs, and cannot be 

controlled directly once the designs have been implemented in the core. 

If MTC exceeds its limits, the reactor must be placed in MODE 3. This 

eliminates the potential for violation of the accident analysis bounds. The 

associated Completion Time of 6 hours is reasonable, considering the 

probability of an accident occurring during the time period that would 

require an MTC value within the LCO limits, and the time for reaching 

MODE 3 from full power conditions in an orderly manner and without 

challenging plant systems. 
MTC (Analog) 

B 3.1.3 

CEOG STS B 3.1.3-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.1.3.1 and SR 3.1.3.2

REQUIREMENTS 

The SRs for measurement of the MTC at the beginning and middle of 

each fuel cycle provide for confirmation of the limiting MTC values. The 

MTC changes smoothly from most positive (least negative) to most 

negative value during fuel cycle operation, as the RCS boron 

concentration is reduced to compensate for fuel depletion. The 

requirement for measurement prior to operation > 5% RTP satisfies the 

confirmatory check on the most positive (least negative) MTC value. The 

requirement for measurement, within 7 days after reaching 40 effective 

full power days and b core burnup, satisfies the confirmatory check of the 

most negative MTC value. The measurement is performed at any 

THERMAL POWER, so that the projected EOC MTC may be evaluated 

before the reactor actually reaches the EOC condition. MTC values may 

be extrapolated and compensated to permit direct comparison to the 

specified MTC limits. 

SR 3.1.3.2 is modified by a Note, which indicates that if the extrapolated 

MTC is more negative than the EOC COLR limit, the Surveillance may be 

repeated, and that shutdown must occur prior to exceeding the minimum 

allowable boron concentration at which MTC is projected to exceed the 

lower limit. An engineering evaluation is performed if the extrapolated 

value of MTC exceeds the Specification limits. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 11. 

 2. FSAR, Section [ ]. 

 3. FSAR, Section [ ]. 

 4. FSAR, Section [ ]. 
MTC (Digital) 

B 3.1.3 

CEOG STS B 3.1.3-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.3 Moderator Temperature Coefficient (MTC) (Digital) 

BASES 

BACKGROUND According to GDC 11 (Ref. 1), the reactor core and its interaction with the 

Reactor Coolant System (RCS) must be designed for inherently stable 

power operation, even in the possible event of an accident. In particular, 

the net reactivity feedback in the system must compensate for any 

unintended reactivity increases. 

The MTC relates a change in core reactivity to a change in reactor 

coolant temperature. A positive MTC means that reactivity increases with 

increasing moderator temperature; conversely, a negative MTC means 

that reactivity decreases with increasing moderator temperature. The 

reactor is designed to operate with a negative MTC over the largest 

possible range of fuel cycle operation. Therefore, a coolant temperature 

increase will cause a reactivity decrease, so that the coolant temperature 

tends to return toward its initial value. Reactivity increases that cause a 

coolant temperature increase will thus be self limiting, and stable power 

operation will result. The same characteristic is true when the MTC is 

positive and coolant temperature decreases occur. 

MTC values are predicted at selected burnups during the safety 

evaluation analysis and are confirmed to be acceptable by 

measurements. Both initial and reload cores are designed so that the 

beginning of cycle (BOC) MTC is less positive than that allowed by the 

LCO. The actual value of the MTC is dependent on core characteristics 

such as fuel loading and reactor coolant soluble boron concentration. 

The core design may require additional fixed distributed poisons (lumped 

burnable poison assemblies) to yield an MTC at the BOC within the range 

analyzed in the plant accident analysis. The end of cycle (EOC) MTC is 

also limited by the requirements of the accident analysis. Fuel cycles that 

are designed to achieve high burnups or that have changes to other 

characteristics are evaluated to ensure that the MTC does not exceed the 

EOC limit. 

APPLICABLE The acceptance criteria for the specified MTC are: 

SAFETY 

ANALYSES a. The MTC values must remain within the bounds of those used in the 

accident analysis (Ref. 2) and 

 b. The MTC must be such that inherently stable power operations result 

during normal operation and during accidents, such as overheating 

and overcooling events. 
MTC (Digital) 

B 3.1.3 

CEOG STS B 3.1.3-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Reference 2 contains analyses of accidents that result in both 

overheating and overcooling of the reactor core. MTC is one of the 

controlling parameters for core reactivity in these accidents. Both the 

most positive value and most negative value of the MTC are important to 

safety, and both values must be bounded. Values used in the analyses 

consider worst case conditions, such as very large soluble boron 

concentrations, to ensure the accident results are bounding (Ref. 3). 

Accidents that cause core overheating, either by decreased heat removal 

or increased power production, must be evaluated for results when the 

MTC is positive. Reactivity accidents that cause increased power 

production include the control element assembly (CEA) withdrawal 

transient from either zero or full THERMAL POWER. The limiting 

overheating event relative to plant response is based on the maximum 

difference between core power and steam generator heat removal during 

a transient. The most limiting event with respect to a positive MTC is a 

CEA withdrawal accident from zero power, also referred to as a startup 

accident (Ref. 4). 

Accidents that cause core overcooling must be evaluated for results when 

the MTC is most negative. The event that produces the most rapid 

cooldown of the RCS, and is therefore the most limiting event with 

respect to the negative MTC, is a steam line break (SLB) event. 

Following the reactor trip for the postulated EOC SLB event, the large 

moderator temperature reduction combined with the large negative MTC 

may produce reactivity increases that are as much as the shutdown 

reactivity. When this occurs, a substantial fraction of core power is 

produced with all CEAs inserted, except the most reactive one, which is 

assumed withdrawn. Even if the reactivity increase produces slightly 

subcritical conditions, a large fraction of core power may be produced 

through the effects of subcritical neutron multiplication. 

MTC values are bounded in reload safety evaluations assuming steady 

state conditions at BOC and EOC. A middle of cycle (MOC) 

measurement is conducted at conditions when the RCS boron 

concentration reaches approximately 300 ppm. The measured value may 

be extrapolated to project the EOC value, in order to confirm reload 

design predictions. 

The MTC satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 
MTC (Digital) 

B 3.1.3 

CEOG STS B 3.1.3-3 Rev. 3.0, 03/31/04 

BASES 

LCO LCO 3.1.3 requires the MTC to be within the specified limits of the COLR 

to ensure the core operates within the assumptions of the accident 

analysis. During the reload core safety evaluation, the MTC is analyzed 

to determine that its values remain within the bounds of the original 

accident analysis during operation. The limit on a positive MTC ensures 

that core overheating accidents will not violate the accident analysis 

assumptions. The negative MTC limit for EOC specified in the COLR 

ensures that core overcooling accidents will not violate the accident 

analysis assumptions. 

MTC is a core physics parameter determined by the fuel and fuel cycle 

design and cannot be easily controlled once the core design is fixed. 

During operation, therefore, the LCO can only be ensured through 

measurement. The surveillance checks at BOC and MOC on an MTC 

provide confirmation that the MTC is behaving as anticipated, so that the 

acceptance criteria are met. 

APPLICABILITY In MODE 1, the limits on the MTC must be maintained to ensure that any 

accident initiated from THERMAL POWER operation will not violate the 

design assumptions of the accident analysis. In MODE 2, the limits must 

also be maintained to ensure startup and subcritical accidents, such as 

the uncontrolled CEA assembly or group withdrawal, will not violate the 

assumptions of the accident analysis. In MODES 3, 4, 5, and 6, this LCO 

is not applicable, since no Design Basis Accidents (DBAs) using the MTC 

as an analysis assumption are initiated from these MODES. However, 

the variation of the MTC, with temperature in MODES 3, 4, and 5, for 

DBAs initiated in MODES 1 and 2, is accounted for in the subject accident 

analysis. The variation of the MTC, with temperature assumed in the 

safety analysis, is accepted as valid once the BOC and MOC 

measurements are used for normalization. 

ACTIONS A.1

MTC is a function of the fuel and fuel cycle designs, and cannot be 

controlled directly once the designs have been implemented in the core. 

If MTC exceeds its limits, the reactor must be placed in MODE 3. This 

eliminates the potential for violation of the accident analysis bounds. The 

associated Completion Time of 6 hours is reasonable, considering the 

probability of an accident occurring during the time period that would 

require an MTC value within the LCO limits, and the time for reaching 

MODE 3 from full power conditions in an orderly manner and without 

challenging plant systems. 
MTC (Digital) 

B 3.1.3 

CEOG STS B 3.1.3-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.1.3.1 and SR 3.1.3.2

REQUIREMENTS 

The SRs for measurement of the MTC at the beginning and middle of 

each fuel cycle provide for confirmation of the limiting MTC values. The 

MTC changes smoothly from most positive (least negative) to most 

negative value during fuel cycle operation, as the RCS boron 

concentration is reduced to compensate for fuel depletion. The 

requirement for measurement prior to operation > 5% RTP satisfies the 

confirmatory check on the most positive (least negative) MTC value. The 

requirement for measurement, within 7 days after reaching 40 effective 

full power days and a 2/3 core burnup, satisfies the confirmatory check of 

the most negative MTC value. The measurement is performed at any 

THERMAL POWER so that the projected EOC MTC may be evaluated 

before the reactor actually reaches the EOC condition. MTC values may 

be extrapolated and compensated to permit direct comparison to the 

specified MTC limits. 

SR 3.1.3.2 is modified by a Note, which indicates that if extrapolated MTC 

is more negative than the EOC COLR limit, the Surveillance may be 

repeated, and that shutdown must occur prior to exceeding the minimum 

allowable boron concentration at which MTC is projected to exceed the 

lower limit. An engineering evaluation is performed if the extrapolated 

value of MTC exceeds the Specification limits. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 11. 

 2. FSAR, Section [ ]. 

 3. FSAR, Section [ ]. 

 4. FSAR, Section [ ]. 
CEA Alignment (Analog) 

B 3.1.4 

CEOG STS B 3.1.4-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.4 Control Element Assembly (CEA) Alignment (Analog) 

BASES 

BACKGROUND The OPERABILITY (i.e., trippability) of the shutdown and regulating 

Control Element Assemblies (CEAs) is an initial assumption in all safety 

analyses that assume CEA insertion upon reactor trip. Maximum CEA 

misalignment is an initial assumption in the safety analysis that directly 

affects core power distributions and assumptions of available SDM. 

The applicable criteria for these reactivity and power distribution design 

requirements are 10 CFR 50, Appendix A, GDC 10 and GDC 26 (Ref. 1), 

and 10 CFR 50.46, "Acceptance Criteria for Emergency Core Cooling 

Systems for Light Water Nuclear Power Plants" (Ref. 2). 

Mechanical or electrical failures may cause a CEA to become inoperable 

or to become misaligned from its group. CEA inoperability or 

misalignment may cause increased power peaking, due to the 

asymmetric reactivity distribution and a reduction in the total available 

CEA worth for reactor shutdown. Therefore, CEA alignment and 

OPERABILITY are related to core operation in design power peaking 

limits and the core design requirement of a minimum SDM. 

Limits on CEA alignment and OPERABILITY have been established, and 

all CEA positions are monitored and controlled during power operation to 

ensure that the power distribution and reactivity limits defined by the 

design power peaking and SDM limits are preserved. 

CEAs are moved by their control element drive mechanisms (CEDMs). 

Each CEDM moves its CEA one step (approximately 3⁄4 inch) at a time, 

but at varying rates (steps per minute) depending on the signal output 

from the Control Element Drive Mechanism Control System (CEDMCS). 

The CEAs are arranged into groups that are radially symmetric. 

Therefore, movement of the CEAs does not introduce radial asymmetries 

in the core power distribution. The shutdown and regulating CEAs 

provide the required reactivity worth for immediate reactor shutdown upon 

a reactor trip. The regulating CEAs also provide reactivity (power level) 

control during normal operation and transients. Their movement may be 

automatically controlled by the Reactor Regulating System. 

The axial position of shutdown and regulating CEAs is indicated by two 

separate and independent systems, which are the Plant Computer CEA 

Position Indication System and the Reed Switch Position Indication 

System. 
CEA Alignment (Analog) 

B 3.1.4 

CEOG STS B 3.1.4-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The Plant Computer CEA Position Indication System counts the 

commands sent to the CEA gripper coils from the CEDM Control System 

that moves the CEAs. There is a one step counter for each group of 

CEAs. Individual CEAs in a group all receive the same signal to move 

and should, therefore, all be at the same position indicated by the group 

step counter for that group. Plant Computer CEA Position Indication 

System is considered highly precise (± 1 step or ± 3⁄4 inch). If a CEA does 

not move one step for each command signal, the step counter will still 

count the command and incorrectly reflect the position of the CEA. 

The Reed Switch Position Indication System provides a highly accurate 

indication of actual CEA position, but at a lower precision than the step 

counters. This system is based on inductive analog signals from a series 

of reed switches spaced along a tube with a center to center distance of 

1.5 inches, which is two steps. To increase the reliability of the system, 

there are redundant reed switches at each position. 

APPLICABLE CEA misalignment accidents are analyzed in the safety analysis (Ref. 3). 

SAFETY The accident analysis defines CEA misoperation as any event, with the 

ANALYSES exception of sequential group withdraws, which could result from a single 

malfunction in the reactivity control systems. For example, CEA 

misalignment may be caused by a malfunction of the CEDM, CEDMCS, 

or by operator error. A stuck CEA may be caused by mechanical 

jamming of the CEA fingers or of the gripper. Inadvertent withdrawal of a 

single CEA may be caused by the opening of the electrical circuit of the 

CEDM holding coil for a full length or part length CEA. A dropped CEA 

could be caused by an electrical failure in the CEA coil power 

programmers. 

The acceptance criteria for addressing CEA inoperability or misalignment 

are that: 

a. There shall be no violations of either: 

1. Specified acceptable fuel design limits or 

2. Reactor Coolant System (RCS) pressure boundary integrity and 

b. The core must remain subcritical after accident transients. 
CEA Alignment (Analog) 

B 3.1.4 

CEOG STS B 3.1.4-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Three types of misalignment are distinguished in the safety analysis 

(Ref. 1). During movement of a group, one CEA may stop moving while 

the other CEAs in the group continue. This condition may cause 

excessive power peaking. The second type of misalignment occurs if one 

CEA fails to insert upon a reactor trip and remains stuck fully withdrawn. 

This condition requires an evaluation to determine that sufficient reactivity 

worth is held in the remaining CEAs to meet the SDM requirement with 

the maximum worth CEA stuck fully withdrawn. If a CEA is stuck in the 

fully withdrawn position, its worth is added to the SDM requirement, since 

the safety analysis does not take two stuck CEAs into account. The third 

type of misalignment occurs when one CEA drops partially or fully into the 

reactor core. This event causes an initial power reduction followed by a 

return towards the original power, due to positive reactivity feedback from 

the negative moderator temperature coefficient. Increased peaking 

during the power increase may result in excessive local linear heat rates 

(LHRs). 

Two types of analyses are performed in regard to static CEA 

misalignment (Ref. 4). With CEA banks at their insertion limits, one type 

of analysis considers the case when any one CEA is inserted [ ] inches 

into the core. The second type of analysis considers the case of a single 

CEA withdrawn [ ] inches from a bank inserted into its insertion limit. 

Satisfying limits on departure from nucleate boiling ratio (DNBR) in both 

of these cases bounds the situation when a CEA is misaligned from its 

group by [7 inches]. 

Another type of misalignment occurs if one CEA fails to insert upon a 

reactor trip and remains stuck fully withdrawn. This condition is assumed 

in the evaluation to determine that the required SDM is met with the 

maximum worth CEA also fully withdrawn (Ref. 5). 

Since the CEA drop incidents result in the most rapid approach to 

specified acceptable fuel design limits (SAFDLs) caused by a CEA 

misoperation, the accident analysis analyzed a single full length CEA 

drop. The most rapid approach to the DNBR SAFDL may be caused by a 

single full length CEA drop or a CEA subgroup drop, depending upon 

initial conditions. 

All of the above CEA misoperations will result in an automatic reactor trip. 

In the case of the full length CEA drop, a prompt decrease in core 

average power and a distortion in radial power are initially produced, 

which, when conservatively coupled, result in a local power and heat flux 

increase, and a decrease in DNBR parameters. 
CEA Alignment (Analog) 

B 3.1.4 

CEOG STS B 3.1.4-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The results of the CEA misoperation analysis show that during the most 

limiting misoperation events, no violations of the SAFDLs, fuel centerline 

temperature, or RCS pressure occur. 

CEA alignment limits and OPERABILITY requirements satisfy Criteria 2 

and 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The limits on shutdown and regulating CEA alignments ensure that the 

assumptions in the safety analysis will remain valid. The requirements on 

CEA OPERABILITY ensure that upon reactor trip, the CEAs will be 

available and will be inserted to provide enough negative reactivity to shut 

down the reactor. The CEA OPERABILITY requirements (i.e., trippability) 

are separate from alignment requirements which ensure that the CEA 

banks maintain the correct power distribution and CEA alignment. The 

CEA OPERABILITY requirement is satisfied provided the CEA will fully 

insert in the required CEA drop time assumed in the safety analysis. CEA 

control malfunctions that result in the inability to move a CEA (e.g., CEA 

lift rod failures), but do not impact trippability, do not result in CEA 

inoperability. 

The requirement is to maintain the CEA alignment to within [7 inches] 

between any CEA and its group. The minimum misalignment assumed in 

safety analysis is [15 inches], and in some cases, a total misalignment 

from fully withdrawn to fully inserted is assumed. 

Failure to meet the requirements of this LCO may produce unacceptable 

power peaking factors and LHRs, or unacceptable SDMS, all of which 

may constitute initial conditions inconsistent with the safety analysis. 

APPLICABILITY The requirements on CEA OPERABILITY and alignment are applicable in 

MODES 1 and 2 because these are the only MODES in which neutron (or 

fission) power is generated, and the OPERABILITY (i.e., trippability) and 

alignment of CEAs have the potential to affect the safety of the plant. In 

MODES 3, 4, 5, and 6, the alignment limits do not apply because the 

CEAs are bottomed, and the reactor is shut down and not producing 

fission power. In the shutdown Modes, the OPERABILITY of the 

shutdown and regulating CEAs has the potential to affect the required 

SDM, but this effect can be compensated for by an increase in the boron 

concentration of the RCS. See LCO 3.1.1, "SHUTDOWN MARGIN 

(SDM)," for SDM in MODES 3, 4, and 5, and LCO 3.9.1, "Boron 

Concentration," for boron concentration requirements during refueling. 
CEA Alignment (Analog) 

B 3.1.4 

CEOG STS B 3.1.4-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1 and A.2

If one or more CEAs (regulating or shutdown) are misaligned by 

> [7 inches] and ≤ [15 inches], or one CEA is misaligned by > [15 inches], 

continued operation in MODES 1 and 2 may continue, provided, within 

1 hour, the power is reduced to ≤ 70% RTP, and within 2 hours CEA 

alignment is restored. Regulating CEA alignment can be restored by 

either aligning the misaligned CEA(s) to within [7 inches] of its group or 

aligning the misaligned CEA's group to within [7 inches] of the misaligned 

CEA. Shutdown CEA alignment can be restored by aligning the 

misaligned CEA(s) to within [7 inches] of its group. 

Xenon redistribution in the core starts to occur as soon as a CEA 

becomes misaligned. Reducing THERMAL POWER in accordance with 

Figure 3.1.4-1 (in the associated LCO) ensures acceptable power 

distributions are maintained (Ref. 6). For small misalignments 

(< [15 inches]) of the CEAs, there is: 

a. A small effect on the time dependent long term power distributions 

relative to those used in generating LCOs and limiting safety system 

settings (LSSS) setpoints, 

b. A negligible effect on the available SDM, and 

c. A small effect on the ejected CEA worth used in the accident 

analysis. 

With a large CEA misalignment (≥ [15 inches]), however, this 

misalignment would cause distortion of the core power distribution. This 

distortion may, in turn, have a significant effect on the time dependent, 

long term power distributions relative to those used in generating LCOs 

and LSSS setpoints. The effect on the available SDM and the ejected 

CEA worth used in the accident analysis remain small. Therefore, this 

condition is limited to a single CEA misalignment, while still allowing 

2 hours for recovery. 

In both cases, a 2 hour time period is sufficient to: 

a. Identify cause of a misaligned CEA, 

b. Take appropriate corrective action to realign the CEAs, and 

c. Minimize the effects of xenon redistribution. 
CEA Alignment (Analog) 

B 3.1.4 

CEOG STS B 3.1.4-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

If a CEA is untrippable, it is not available for reactivity insertion during a 

reactor trip. With an untrippable CEA, meeting the insertion limits of 

LCO 3.1.5 and LCO 3.1.6 does not ensure that adequate SDM exists. 

The CEA must be returned to OPERABLE status with 2 hours or 

transition to MODE 3. 

B.1, B.2.1, and B.2.2

The CEA motion inhibit permits CEA motion within the requirements of 

LCO 3.1.6, "Regulating Control Element Assembly Insertion Limits," and 

prevents regulating CEAs from being misaligned from other CEAs in the 

group. 

Performing SR 3.1.4.1 within 1 hour and every 4 hours thereafter, is 

considered acceptable in view of other information continuously available 

to the operator in the control room. 

With the CEA motion inhibit inoperable, a Completion Time of 6 hours is 

allowed for restoring the CEA motion inhibit to OPERABLE status, or 

placing and maintaining the CEA drive switch in either the "off" or 

"manual" position, fully withdrawing the CEAs in groups 3 and 4, and 

withdrawing all CEAs in group 5 to < 5% insertion. 

Placing the CEA drive switch in the "off" or "manual" position ensures the 

CEAs will not move in response to Reactor Regulating System automatic 

motion commands. Withdrawal of the CEAs to the positions required in 

the Required Action B.2.2 ensures that core perturbations in local burnup, 

perking factors, and SDM will not be more adverse than the Conditions 

assumed in the safety analyses and LCO setpoint determination (Ref. 6). 

The 6 hour Completion Time takes into account Required Action B.1, the 

protection afforded by the CEA deviation circuits, and other information 

continuously available to the operator in the control room, so that during 

actual CEA motion, deviations can be detected. 

Required Action B.2.2 is modified by a Note indicating that this Required 

Action shall not be performed when in conflict with either Required 

Action A.1, A.2, or C.1. 
CEA Alignment (Analog) 

B 3.1.4 

CEOG STS B 3.1.4-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1

When the CEA deviation circuit is inoperable, performing SR 3.1.4.1, 

within 1 hour and every 4 hours thereafter, ensures improper CEA 

alignments are identified before unacceptable flux distributions occur. 

The specified Completion Times take into account other information 

continuously available to the operator in the control room, so that during 

CEA movement, deviations can be detected, and the protection provided 

by the CEA inhibit and deviation circuit is not required. 

D.1

If the Required Action or associated Completion Time of Condition A, 

Condition B, or Condition C is not met, one or more regulating or 

shutdown CEAs are inoperable, or two or more CEAs are misaligned by 

> [15 inches], the unit is required to be brought to MODE 3. By being 

brought to MODE 3, the unit is brought outside its MODE of applicability. 

Continued operation is not allowed in the case of more than one CEA 

misaligned from any other CEA in its group by > [15 inches], or one or 

more CEAs inoperable. This is because these cases are indicative of a 

loss of SDM and power distribution, and a loss of safety function, 

respectively. 

When a Required Action cannot be completed within the required 

Completion Time, a controlled shutdown should be commenced. The 

allowed Completion Time of 6 hours is reasonable, based on operating 

experience, for reaching MODE 3 from full power conditions in an orderly 

manner and without challenging plant systems. 

SURVEILLANCE SR 3.1.4.1

REQUIREMENTS 

Verification that individual CEA positions are within [7 inches] (indicated 

reed switch positions) of all other CEAs in the group at Frequencies of 

within 1 hour of any CEA movement of > 7.5 inches and every 12 hours. 

The CEA position verification after each movement of > 7.5 inches 

ensures that the CEAs in that group are properly aligned at the time when 

CEA misalignments are most likely to have occurred. The 12 hour 

Frequency allows the operator to detect a CEA that is beginning to 

deviate from its expected position. The specified Frequency takes into 

account other CEA position information that is continuously available to 

the operator in the control room, so that during CEA movement, 

deviations can be detected, and protection can be provided by the CEA 

motion inhibit and deviation circuits. 
CEA Alignment (Analog) 

B 3.1.4 

CEOG STS B 3.1.4-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.1.4.2

Demonstrating the CEA motion inhibit OPERABLE verifies that the CEA 

motion inhibit is functional, even if it is not regularly operated. The 92 day 

Frequency takes into account other information continuously available to 

the operator in the control room, so that during CEA movement, 

deviations can be detected, and protection can be provided by the CEA 

deviation circuits. 

SR 3.1.4.3

Demonstrating the CEA deviation circuit is OPERABLE verifies the circuit 

is functional. The 92 day Frequency takes into account other information 

continuously available to the operator in the control room, so that during 

CEA movement, deviations can be detected, and protection can be 

provided by the CEA motion inhibit. 

SR 3.1.4.4

Verifying each CEA is trippable would require that each CEA be tripped. 

In MODES 1 and 2, tripping each CEA would result in radial or axial 

power tilts, or oscillations. Therefore, individual CEAs are exercised 

every 92 days to provide increased confidence that all CEAs continue to 

be trippable, even if they are not regularly tripped. A movement of 

[5 inches] is adequate to demonstrate motion without exceeding the 

alignment limit when only one CEA is being moved. The 92 day 

Frequency takes into consideration other information available to the 

operator in the control room and other surveillances being performed 

more frequently, which add to the determination of OPERABILITY of the 

CEAs. Between required performances of SR 3.1.4.4, if a CEA(s) is 

discovered to be immovable, but remains trippable, the CEA is 

considered to be OPERABLE. At any time, if a CEA(s) is immovable, a 

determination of the trippability (OPERABILITY) of the CEA(s) must be 

made, and appropriate action taken. 
CEA Alignment (Analog) 

B 3.1.4 

CEOG STS B 3.1.4-9 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.1.4.5

Performance of a CHANNEL FUNCTIONAL TEST of each reed switch 

position transmitter channel ensures the channel is OPERABLE and 

capable of indicating CEA position over the entire length of the CEA's 

travel. A successful test of the required contact(s) of a channel relay may 

be performed by the verification of the change of state of a single contact 

of the relay. This clarifies what is an acceptable CHANNEL 

FUNCTIONAL TEST of a relay. This is acceptable because all of the 

other required contacts of the relay are verified by other Technical 

Specifications and non-Technical Specifications tests at least once per 

refueling interval with applicable extensions. Since this Surveillance must 

be performed when the reactor is shut down, an 18 month Frequency to 

be coincident with refueling outage was selected. Operating experience 

has shown that these components usually pass this Surveillance when 

performed at a Frequency of once every 18 months. Furthermore, the 

Frequency takes into account other surveillances being performed at 

shorter Frequencies, which determine the OPERABILITY of the CEA 

Reed Switch Indication System. 

SR 3.1.4.6

Verification of CEA drop times determined that the maximum CEA drop 

time permitted is consistent with the assumed drop time used in that 

safety analysis (Ref. 7). Measuring drop times prior to reactor criticality, 

after reactor vessel head removal, ensures that reactor internals and 

CEDM will not interfere with CEA motion or drop time and that no 

degradation in these systems has occurred that would adversely affect 

CEA motion or drop time. Individual CEAs whose drop times are greater 

than safety analysis assumptions are not OPERABLE. This SR is 

performed prior to criticality, based on the need to perform this 

Surveillance under the conditions that apply during a unit outage and 

because of the potential for an unplanned unit transient if the Surveillance 

were performed with the reactor at power. 
CEA Alignment (Analog) 

B 3.1.4 

CEOG STS B 3.1.4-10 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10 and GDC 26. 

 2. 10 CFR 50.46. 

 3. FSAR, Section [ ]. 

 4. FSAR, Section [ ]. 

 5. FSAR, Section [ ]. 

 6. FSAR, Section [ ]. 

 7. FSAR, Section [ ]. 
CEA Alignment (Digital) 

B 3.1.4 

CEOG STS B 3.1.4-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.4 Control Element Assembly (CEA) Alignment (Digital) 

BASES 

BACKGROUND The OPERABILITY (i.e., trippability) of the shutdown and regulating 

Control Element Assemblies (CEAs) is an initial assumption in all safety 

analyses that assume CEA insertion upon reactor trip. Maximum CEA 

misalignment is an initial assumption in the safety analyses that directly 

affects core power distributions and assumptions of available SDM. 

The applicable criteria for these reactivity and power distribution design 

requirements are 10 CFR 50, Appendix A, GDC 10 and GDC 26 (Ref. 1) 

and 10 CFR 50.46, "Acceptance Criteria for Emergency Core Cooling 

Systems for Light Water Cooled Nuclear Power Plants" (Ref. 2). 

Mechanical or electrical failures may cause a CEA to become inoperable 

or to become misaligned from its group. CEA inoperability or 

misalignment may cause increased power peaking, due to the 

asymmetric reactivity distribution and a reduction in the total available 

CEA worth for reactor shutdown. Therefore, CEA alignment and 

operability are related to core operation in design power peaking limits 

and the core design requirement of a minimum SDM. 

Limits on CEA alignment and OPERABILITY have been established, and 

all CEA positions are monitored and controlled during power operation to 

ensure that the power distribution and reactivity limits defined by the 

design power peaking and SDM limits are preserved. 

CEAs are moved by their control element drive mechanisms (CEDMs). 

Each CEDM moves its CEA one step (approximately 3⁄4 inch) at a time, 

but at varying rates (steps per minute) depending on the signal output 

from the Control Element Drive Mechanism Control System (CEDMCS). 

The CEAs are arranged into groups that are radially symmetric. 

Therefore, movement of the CEAs does not introduce radial asymmetries 

in the core power distribution. The shutdown and regulating CEAs 

provide the required reactivity worth for immediate reactor shutdown upon 

a reactor trip. The regulating CEAs also provide reactivity (power level) 

control during normal operation and transients. Their movement may be 

automatically controlled by the Reactor Regulating System. Part length 

CEAs are not credited in the safety analyses for shutting down the 

reactor, as are the regulating and shutdown groups. The part length 

CEAs are used solely for ASI control. 
CEA Alignment (Digital) 

B 3.1.4 

CEOG STS B 3.1.4-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The axial position of shutdown and regulating CEAs is indicated by two 

separate and independent systems, which are the Plant Computer CEA 

Position Indication System and the Reed Switch Position Indication 

System. 

The Plant Computer CEA Position Indication System counts the 

commands sent to the CEA gripper coils from the CEDMCS that moves 

the CEAs. There is one step counter for each group of CEAs. Individual 

CEAs in a group all receive the same signal to move and should, 

therefore, all be at the same position indicated by the group step counter 

for that group. The Plant Computer CEA Position Indication System is 

considered highly precise (± one step or ± 3⁄4 inch). If a CEA does not 

move one step for each command signal, the step counter will still count 

the command and incorrectly reflect the position of the CEA. 

The Reed Switch Position Indication System provides a highly accurate 

indication of actual CEA position, but at a lower precision than the step 

counters. This system is based on inductive analog signals from a series 

of reed switches spaced along a tube with a center to center distance of 

1.5 inches, which is two steps. To increase the reliability of the system, 

there are redundant reed switches at each position. 

APPLICABLE CEA misalignment accidents are analyzed in the safety analysis (Ref. 3). 

SAFETY The accident analysis defines CEA misoperation as any event, with the 

ANALYSES exception of sequential group withdrawals, which could result from a 

single malfunction in the reactivity control systems. For example, CEA 

misalignment may be caused by a malfunction of the CEDM, CEDMCS, 

or by operator error. A stuck CEA may be caused by mechanical 

jamming of the CEA fingers or of the gripper. Inadvertent withdrawal of a 

single CEA may be caused by opening of the electrical circuit of the 

CEDM holding coil for a full length or part length CEA. A dropped CEA 

subgroup could be caused by an electrical failure in the CEA coil power 

programmers. 

The acceptance criteria for addressing CEA inoperability or misalignment 

are that: 

a. There shall be no violations of either: 

1. Specified acceptable fuel design limits or 

2. Reactor Coolant System (RCS) pressure boundary integrity and 

b. The core must remain subcritical after accident transients. 
CEA Alignment (Digital) 

B 3.1.4 

CEOG STS B 3.1.4-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Three types of misalignment are distinguished. During movement of a 

group, one CEA may stop moving while the other CEAs in the group 

continue. This condition may cause excessive power peaking. The 

second type of misalignment occurs if one CEA fails to insert upon a 

reactor trip and remains stuck fully withdrawn. This condition requires an 

evaluation to determine that sufficient reactivity worth is held in the 

remaining CEAs to meet the SDM requirement with the maximum worth 

CEA stuck fully withdrawn. If a CEA is stuck in the fully withdrawn 

position, its worth is added to the SDM requirement, since the safety 

analysis does not take two stuck CEAs into account. The third type of 

misalignment occurs when one CEA drops partially or fully into the 

reactor core. This event causes an initial power reduction followed by a 

return towards the original power due to positive reactivity feedback from 

the negative moderator temperature coefficient. Increased peaking 

during the power increase may result in excessive local linear heat rates 

(LHRs). 

Two types of analyses are performed in regard to static CEA 

misalignment (Ref. 4). With CEA banks at their insertion limits, one type 

of analysis considers the case when any one CEA is inserted [ ] inches 

into the core. The second type of analysis considers the case of a single 

CEA withdrawn [ ] inches from a bank inserted to its insertion limit. 

Satisfying limits on departure from nucleate boiling ratio (DNBR) in both 

of these cases bounds the situation when a CEA is misaligned from its 

group by [7 inches]. 

Another type of misalignment occurs if one CEA fails to insert upon a 

reactor trip and remains stuck fully withdrawn. This condition is assumed 

in the evaluation to determine that the required SDM is met with the 

maximum worth CEA also fully withdrawn (Ref. 5). 

The effect of any misoperated CEA on the core power distribution will be 

assessed by the CEA calculators, and an appropriately augmented power 

distribution penalty factor will be supplied as input to the core protection 

calculators (CPCs). As the reactor core responds to the reactivity 

changes caused by the misoperated CEA and the ensuing reactor coolant 

and Doppler feedback effects, the CPCs will initiate a low DNBR or high 

local power density trip signal if specified acceptable fuel design limits 

(SAFDLs) are approached. 
CEA Alignment (Digital) 

B 3.1.4 

CEOG STS B 3.1.4-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Since the CEA drop incidents result in the most rapid approach to 

SAFDLs caused by a CEA misoperation, the accident analysis analyzed a 

single full length CEA drop, a single part length CEA drop, and a part 

length CEA subgroup drop. The most rapid approach to the DNBR 

SAFDL may be caused by either a single full length drop or a part length 

CEA subgroup drop depending upon initial conditions. The most rapid 

approach to the fuel centerline melt SAFDL is caused by a single part 

length CEA drop. 

In the case of the full length CEA drop, a prompt decrease in core 

average power and a distortion in radial power are initially produced, 

which when conservatively coupled result in local power and heat flux 

increases, and a decrease in DNBR. For plant operation within the 

DNBR and local power density (LPD) LCOs, DNBR and LPD trips can 

normally be avoided on a dropped CEA. 

For a part length CEA subgroup drop, a distortion in power distribution, 

and a decrease in core power are produced. As the dropped part length 

CEA subgroup is detected, an appropriate power distribution penalty 

factor is supplied to the CPCs, and a reactor trip signal on low DNBR is 

generated. For the part length CEA drop, both core average power and 

three dimensional peak to average power density increase promptly. As 

the dropped part length CEA is detected, core power and an appropriately 

augmented power distribution penalty factor are supplied to the CPCs. 

CEA alignment limits and OPERABILITY requirements satisfy Criteria 2 

and 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The limits on shutdown and regulating CEA alignments ensure that the 

assumptions in the safety analysis will remain valid. The requirements on 

CEA OPERABILITY ensure that upon reactor trip, the CEAs will be 

available and will be inserted to provide enough negative reactivity to shut 

down the reactor. The CEA OPERABILITY requirements (i.e., trippability) 

are separate from the alignment requirements which ensure that the CEA 

banks maintain the correct power distribution and CEA alignment. The 

CEA OPERABILITY requirement is satisfied provided the CEA will fully 

insert in the required CEA drop time assumed in the safety analysis. CEA 

control malfunctions that result in the inability to move a CEA (e.g., CEA 

lift coil failures), but that do not impact trippability, do not result in CEA 

inoperability. 
CEA Alignment (Digital) 

B 3.1.4 

CEOG STS B 3.1.4-5 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The requirement is to maintain the CEA alignment to within [7 inches] 

between any CEA and its group. The minimum misalignment assumed in 

safety analysis is [19 inches], and in some cases, a total misalignment 

from fully withdrawn to fully inserted is assumed. 

Failure to meet the requirements of this LCO may produce unacceptable 

power peaking factors and LHRs, or unacceptable SDMs, all of which 

may constitute initial conditions inconsistent with the safety analysis. 

APPLICABILITY The requirements on CEA OPERABILITY and alignment are applicable in 

MODES 1 and 2 because these are the only MODES in which neutron (or 

fission) power is generated, and the OPERABILITY (i.e., trippability) and 

alignment of CEAs have the potential to affect the safety of the plant. In 

MODES 3, 4, 5, and 6, the alignment limits do not apply because the 

CEAs are bottomed, and the reactor is shut down and not producing 

fission power. In the shutdown modes, the OPERABILITY of the 

shutdown and regulating CEAs has the potential to affect the required 

SDM, but this effect can be compensated for by an increase in the boron 

concentration of the RCS. See LCO 3.1.1, "SHUTDOWN MARGIN 

(SDM)," for SDM in MODES 3, 4, and 5, and LCO 3.9.1, "Boron 

Concentration," for boron concentration requirements during refueling. 

ACTIONS A.1 and A.2

If one or more CEAs (regulating, shutdown or part length) are misaligned 

by [7 inches] and ≤ [19 inches], or one CEA misaligned by > [19 inches], 

continued operation in MODES 1 and 2 may continue, provided, within 

1 hour, the power is reduced in accordance with Figure 3.1.4-1, and 

within 2 hours CEA alignment is restored. 

Regulating and part length CEA alignment can be restored by either 

aligning the misaligned CEA(s) to within [7 inches] of its group or aligning 

the misaligned CEA's group to within [7 inches] of the misaligned CEA. 

Shutdown CEA alignment can be restored by aligning the misaligned 

CEA(s) to within [7 inches] of its group. 

Xenon redistribution in the core starts to occur as soon as a CEA 

becomes misaligned. Reducing THERMAL POWER in accordance with 

Figure 3.1.4-1 (in the accompanying LCO) ensures acceptable power 

distributions are maintained (Ref. 6). For small misalignments 

(< [19 inches]) of the CEAs, there is: 
CEA Alignment (Digital) 

B 3.1.4 

CEOG STS B 3.1.4-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

a. A small effect on the time dependent long term power distributions 

relative to those used in generating LCOs and limiting safety system 

settings (LSSS) setpoints, 

b. A negligible effect on the available SDM, and 

c. A small effect on the ejected CEA worth used in the accident 

analysis. 

With a large CEA misalignment (≥ [19 inches]), however, this 

misalignment would cause distortion of the core power distribution. This 

distortion may, in turn, have a significant effect on the time dependent, 

long term power distributions relative to those used in generating LCOs 

and LSSS setpoints. The effect on the available SDM and the ejected 

CEA worth used in the accident analysis remain small. Therefore, this 

condition is limited to the single CEA misalignment, while still allowing 

2 hours for recovery. In both cases, a 2 hour time period is sufficient to: 

a. Identify cause of a misaligned CEA, 

b. Take appropriate corrective action to realign the CEAs, and 

c. Minimize the effects of xenon redistribution. 

The CEA must be returned to OPERABLE status within 2 hours or 

transition to MODE 3. 

B.1

If a Required Action or associated Completion Time of Condition A is not 

met, one or more full length CEAs are inoperable, or two or more CEAs 

are misaligned by > [19 inches], the unit is required to be brought to 

MODE 3. By being brought to MODE 3, the unit is brought outside its 

MODE of applicability. This is because these cases are indicative of a 

loss of SDM and power distribution, and a loss of safety function, 

respectively. 

When a Required Action cannot be completed within the required 

Completion Time, a controlled shutdown should be commenced. The 

allowed Completion Time of 6 hours is reasonable, based on operating 

experience, for reaching MODE 3 from full power conditions in an orderly 

manner and without challenging plant systems. 
CEA Alignment (Digital) 

B 3.1.4 

CEOG STS B 3.1.4-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Continued operation is not allowed in the case of more than one CEA(s) 

misaligned from any other CEA in its group by > [19 inches], or with one 

or more full length CEAs inoperable 

SURVEILLANCE SR 3.1.4.1

REQUIREMENTS 

Verification that individual CEA positions are within [7 inches] (indicated 

reed switch positions) of all other CEAs in the group at a 12 hour 

Frequency allows the operator to detect a CEA that is beginning to 

deviate from its expected position. The specified Frequency takes into 

account other CEA position information that is continuously available to 

the operator in the control room, so that during actual CEA motion, 

deviations can immediately be detected. 

SR 3.1.4.2

OPERABILITY of at least two CEA position indicator channels is required 

to determine CEA positions, and thereby ensure compliance with the CEA 

alignment and insertion limits. The CEA full in and full out limits provide 

an additional independent means for determining the CEA positions when 

the CEAs are at either their fully inserted or fully withdrawn positions. 

SR 3.1.4.3

Verifying each full length CEA is trippable would require that each CEA 

be tripped. In MODES 1 and 2 tripping each full length CEA would result 

in radial or axial power tilts, or oscillations. Therefore individual full length 

CEAs are exercised every 92 days to provide increased confidence that 

all full length CEAs continue to be trippable, even if they are not regularly 

tripped. A movement of [5 inches] is adequate to demonstrate motion 

without exceeding the alignment limit when only one full length CEA is 

being moved. The 92 day Frequency takes into consideration other 

information available to the operator in the control room and other 

surveillances being performed more frequently, which add to the 

determination of OPERABILITY of the CEAs (Ref. 7). Between required 

performances of SR 3.1.4.3, if a CEA(s) is discovered to be immovable, 

the CEA is considered to be OPERABLE. At anytime, if a CEA(s) is 

immovable, a determination of the trippability (OPERABILITY) of that 

CEA(s) must be made, and appropriate action taken. 
CEA Alignment (Digital) 

B 3.1.4 

CEOG STS B 3.1.4-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.1.4.4

Performance of a CHANNEL FUNCTIONAL TEST of each reed switch 

position transmitter channel ensures the channel is OPERABLE and 

capable of indicating CEA position. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. Since this test 

must be performed when the reactor is shut down, an 18 month 

Frequency to be coincident with refueling outage was selected. 

Operating experience has shown that these components usually pass this 

Surveillance when performed at a Frequency of once every 18 months. 

Therefore, the Frequency was concluded to be acceptable from a 

reliability standpoint. 

SR 3.1.4.5

Verification of full length CEA drop times determines that the maximum 

CEA drop time permitted is consistent with the assumed drop time used 

in the safety analysis (Ref. 7). Measuring drop times prior to reactor 

criticality, after reactor vessel head removal, ensures the reactor internals 

and CEDM will not interfere with CEA motion or drop time, and that no 

degradation in these systems has occurred that would adversely affect 

CEA motion or drop time. Individual CEAs whose drop times are greater 

than safety analysis assumptions are not OPERABLE. This SR is 

performed prior to criticality due to the plant conditions needed to perform 

the SR and the potential for an unplanned plant transient if the 

Surveillance were performed with the reactor at power. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10 and GDC 26. 

 2. 10 CFR 50.46. 

 3. FSAR, Section [ ]. 

 4. FSAR, Section [ ]. 
CEA Alignment (Digital) 

B 3.1.4 

CEOG STS B 3.1.4-9 Rev. 3.0, 03/31/04 

BASES 

REFERENCES (continued) 

 5. FSAR, Section [ ]. 

 6. FSAR, Section [ ]. 

7. FSAR, Section [ ]. 
Shutdown CEA Insertion Limits (Analog) 

B 3.1.5 

CEOG STS B 3.1.5-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.5 Shutdown Control Element Assembly (CEA) Insertion Limits (Analog) 

BASES 

BACKGROUND The insertion limits of the shutdown Control Element Assemblies (CEAs) 

are initial assumptions in all safety analyses that assume CEA insertion 

upon reactor trip. The insertion limits directly affect core power 

distributions and assumptions of available SDM, ejected CEA worth, and 

initial reactivity insertion rate. 

The applicable criteria for these reactivity and power distribution design 

requirements are 10 CFR 50, Appendix A, GDC 10, "Reactor Design," 

and GDC 26, "Reactivity Limits" (Ref. 1), and 10 CFR 50.46, "Acceptance 

Criteria for Emergency Core Cooling Systems for Light Water Nuclear 

Power Reactors" (Ref. 2). Limits on shutdown CEA insertion have been 

established, and all CEA positions are monitored and controlled during 

power operation to ensure that the reactivity limits, ejected CEA worth, 

and SDM limits are preserved. 

The shutdown CEAs are arranged into groups that are radially symmetric. 

Therefore, movement of the shutdown CEAs does not introduce radial 

asymmetries in the core power distribution. The shutdown and regulating 

CEAs provide the required reactivity worth for immediate reactor 

shutdown upon a reactor trip. 

The design calculations are performed with the assumption that the 

shutdown CEAs are withdrawn prior to the regulating CEAs. The 

shutdown CEAs can be fully withdrawn without the core going critical. 

This provides available negative reactivity for SDM in the event of 

boration errors. The shutdown CEAs are controlled manually or 

automatically by the control room operator. During normal unit operation, 

the shutdown CEAs are fully withdrawn. The shutdown CEAs must be 

completely withdrawn from the core prior to withdrawing any regulating 

CEAs during an approach to criticality. The shutdown CEAs are then left 

in this position until the reactor is shut down. They affect core power, 

burnup distribution, and add negative reactivity to shut down the reactor 

upon receipt of a reactor trip signal. 

APPLICABLE Accident analysis assumes that the shutdown CEAs are fully withdrawn 

SAFETY any time the reactor is critical. This ensures that: 

ANALYSES 

a. The minimum SDM is maintained and 

b. The potential effects of a CEA ejection accident are limited to 

acceptable limits. 
Shutdown CEA Insertion Limits (Analog) 

B 3.1.5 

CEOG STS B 3.1.5-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

CEAs are considered fully withdrawn at 129 inches, since this position 

places them outside the active region of the core. 

On a reactor trip, all CEAs (shutdown and regulating), except the most 

reactive CEA, are assumed to insert into the core. The shutdown and 

regulating CEAs shall be at their insertion limits and available to insert the 

maximum amount of negative reactivity on a reactor trip signal. The 

regulating CEAs may be partially inserted in the core as allowed by 

LCO 3.1.6, "Regulating Control Element Assembly (CEA) Insertion 

Limits." The shutdown CEA insertion limit is established to ensure that a 

sufficient amount of negative reactivity is available to shut down the 

reactor and maintain the required SDM (see LCO 3.1.1, "SHUTDOWN 

MARGIN (SDM)") following a reactor trip from full power. The 

combination of regulating CEAs and shutdown CEAs (less the most 

reactive CEA, which is assumed to be fully withdrawn) is sufficient to take 

the reactor from full power conditions at rated temperature to zero power, 

and to maintain the required SDM at rated no load temperature (Ref. 3). 

The shutdown CEA insertion limit also limits the reactivity worth of an 

ejected shutdown CEA. 

The acceptance criteria for addressing shutdown CEA as well as 

regulating CEA insertion limits and inoperability or misalignment are that: 

a. There be no violation of either: 

1. Specified acceptable fuel design limits or 

2. Reactor Coolant System pressure boundary damage and 

b. The core remains subcritical after accident transients. 

As such, the shutdown CEA insertion limits affect safety analyses 

involving core reactivity, ejected CEA worth, and SDM (Ref. 3). 

The shutdown CEA insertion limits satisfy Criterion 2 of 

10 CFR 50.36(c)(2)(ii). 

LCO The shutdown CEAs must be within their insertion limits any time the 

reactor is critical or approaching criticality. This ensures that a sufficient 

amount of negative reactivity is available to shut down the reactor and 

maintain the required SDM following a reactor trip. 
Shutdown CEA Insertion Limits (Analog) 

B 3.1.5 

CEOG STS B 3.1.5-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY The shutdown CEAs must be within their insertion limits, with the reactor 

in MODES 1 and 2. The Applicability in MODE 2 begins anytime any 

regulating CEA is not fully inserted. This ensures that a sufficient amount 

of negative reactivity is available to shut down the reactor and maintain 

the required SDM following a reactor trip. In MODE 3, 4, 5, or 6, the 

shutdown CEAs are fully inserted in the core and contribute to the SDM. 

Refer to LCO 3.1.1, "SHUTDOWN MARGIN (SDM)," for SDM 

requirements in MODES 3, 4, and 5. LCO 3.9.1, "Boron Concentration," 

ensures adequate SDM in MODE 6. 

This LCO has been modified by a Note indicating the LCO requirement is 

suspended during SR 3.1.4.4. This SR verifies the freedom of the CEAs 

to move, and requires the shutdown CEAs to move below the LCO limits, 

which would normally violate the LCO. 

ACTIONS A.1

Prior to entering this condition, the shutdown CEAs were fully withdrawn. 

If a shutdown CEA(s) is then inserted into the core, its potential negative 

reactivity is added to the core as it is inserted. 

If the CEA(s) is not restored to within limits within 1 hour, then an 

additional 1 hour is allowed for restoring the CEA(s) to within limits. The 

2 hour total Completion Time allows the operator adequate time to adjust 

the CEA(s) in an orderly manner and is consistent with the required 

Completion Times in LCO 3.1.4, "Control Element Assembly (CEA) 

Alignment." 

B.1

When Required Action A.1 or A.2 cannot be met or completed within the 

required Completion Time, a controlled shutdown should be commenced. 

The allowed Completion Time of 6 hours is reasonable, based on 

operating experience, for reaching MODE 3 from full power conditions in 

an orderly manner and without challenging plant systems. 

SURVEILLANCE SR 3.1.5.1

REQUIREMENTS 

Verification that the shutdown CEAs are within their insertion limits prior 

to an approach to criticality ensures that when the reactor is critical, or 

being taken critical, the shutdown CEAs will be available to shut down the 

reactor, and the required SDM will be maintained following a reactor trip. 

This SR and Frequency ensure that the shutdown CEAs are withdrawn 

before the regulating CEAs are withdrawn during a unit startup. 
Shutdown CEA Insertion Limits (Analog) 

B 3.1.5 

CEOG STS B 3.1.5-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Since the shutdown CEAs are positioned manually by the control room 

operator, verification of shutdown CEA position at a Frequency of 

12 hours is adequate to ensure that the shutdown CEAs are within their 

insertion limits. Also, the 12 hour Frequency takes into account other 

information available to the operator in the control room for the purpose of 

monitoring the status of the shutdown CEAs. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10 and GDC 26. 

 2. 10 CFR 50.46. 

 3. FSAR, Section [ ]. 
Shutdown CEA Insertion Limits (Digital) 

B 3.1.5 

CEOG STS B 3.1.5-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.5 Shutdown Control Element Assembly (CEA) Insertion Limits (Digital) 

BASES 

BACKGROUND The insertion limits of the shutdown Control Element Assemblies (CEAs) 

are initial assumptions in all safety analyses that assume CEA insertion 

upon reactor trip. The insertion limits directly affect core power 

distributions and assumptions of available SDM, ejected CEA worth, and 

initial reactivity insertion rate. 

The applicable criteria for these reactivity and power distribution design 

requirements are 10 CFR 50, Appendix A, GDC 10, "Reactor Design," 

and GDC 26, "Reactivity Limits" (Ref. 1), and 10 CFR 50.46, "Acceptance 

Criteria for Emergency Core Cooling Systems for Light Water Nuclear 

Power Reactors" (Ref. 2). Limits on shutdown CEA insertion have been 

established, and all CEA positions are monitored and controlled during 

power operation to ensure that the reactivity limits, ejected CEA worth, 

and SDM limits are preserved. 

The shutdown CEAs are arranged into groups that are radially symmetric. 

Therefore, movement of the shutdown CEAs does not introduce radial 

asymmetries in the core power distribution. The shutdown and regulating 

CEAs provide the required reactivity worth for immediate reactor 

shutdown upon a reactor trip. 

The design calculations are performed with the assumption that the 

shutdown CEAs are withdrawn prior to the regulating CEAS. The 

shutdown CEAs can be fully withdrawn without the core going critical. 

This provides available negative reactivity for SDM in the event of 

boration errors. The shutdown CEAs are controlled manually or 

automatically by the control room operator. During normal unit operation, 

the shutdown CEAs are fully withdrawn. The shutdown CEAs must be 

completely withdrawn from the core prior to withdrawing regulating CEAs 

during an approach to criticality. The shutdown CEAs are then left in this 

position until the reactor is shut down. They affect core power, burnup 

distribution, and add negative reactivity to shut down the reactor upon 

receipt of a reactor trip signal. 

APPLICABLE Accident analysis assumes that the shutdown CEAs are fully withdrawn 

SAFETY any time the reactor is critical. This ensures that: 

ANALYSES 

a. The minimum SDM is maintained and 

b. The potential effects of a CEA ejection accident are limited to 

acceptable limits. 
Shutdown CEA Insertion Limits (Digital) 

B 3.1.5 

CEOG STS B 3.1.5-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

CEAs are considered fully withdrawn at 145 inches, since this position 

places them outside the active region of the core. 

On a reactor trip, all CEAs (shutdown CEAs and regulating CEAs), except 

the most reactive CEA, are assumed to insert into the core. The 

shutdown and regulating CEAs shall be at their insertion limits and 

available to insert the maximum amount of negative reactivity on a reactor 

trip signal. The regulating CEAs may be partially inserted in the core as 

allowed by LCO 3.1.6, "Regulating Control Element Assembly (CEA) 

Insertion Limits." The shutdown CEA insertion limit is established to 

ensure that a sufficient amount of negative reactivity is available to shut 

down the reactor and maintain the required SDM (see LCO 3.1.1, 

"SHUTDOWN MARGIN (SDM)") following a reactor trip from full power. 

The combination of regulating CEAs and shutdown CEAs (less the most 

reactive CEA, which is assumed to be fully withdrawn) is sufficient to take 

the reactor from full power conditions at rated temperature to zero power, 

and to maintain the required SDM at rated no load temperature (Ref. 3). 

The shutdown CEA insertion limit also limits the reactivity worth of an 

ejected shutdown CEA. 

The acceptance criteria for addressing shutdown CEA as well as 

regulating CEA insertion limits and inoperability or misalignment are that: 

a. There be no violation of either: 

1. Specified acceptable fuel design limits or 

2. Reactor Coolant System pressure boundary damage integrity 

and 

b. The core remains subcritical after accident transients. 

The shutdown CEA insertion limits satisfy Criterion 2 of 

10 CFR 50.36(c)(2)(ii). 

LCO The shutdown CEAs must be within their insertion limits any time the 

reactor is critical or approaching criticality. This ensures that a sufficient 

amount of negative reactivity is available to shut down the reactor and 

maintain the required SDM following a reactor trip. 
Shutdown CEA Insertion Limits (Digital) 

B 3.1.5 

CEOG STS B 3.1.5-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY The shutdown CEAs must be within their insertion limits, with the reactor 

in MODES 1 and 2. The Applicability in MODE 2 begins any time any 

regulating CEA is not fully inserted. This ensures that a sufficient amount 

of negative reactivity is available to shut down the reactor and maintain 

the required SDM following a reactor trip. In MODE 3, 4, 5, or 6, the 

shutdown CEAs are fully inserted in the core and contribute to the SDM. 

Refer to LCO 3.1.1, "SHUTDOWN MARGIN (SDM)," for SDM 

requirements in MODES 3, 4, and 5. LCO 3.9.1, "Boron Concentration," 

ensures adequate SDM in MODE 6. 

This LCO has been modified by a Note indicating the LCO requirement is 

suspended during SR 3.1.4.5, which verifies the freedom of the CEAs to 

move, and requires the shutdown CEAs to move below the LCO limits, 

which would normally violate the LCO. 

ACTIONS A.1

Prior to entering this Condition, the shutdown CEAs were fully withdrawn. 

If a shutdown CEA is then inserted into the core, its potential negative 

reactivity is added to the core as it is inserted. 

If the CEA(s) is not restored to within limits within 1 hour, then an 

additional 1 hour is allowed for restoring the CEA(s) to within limits. The 

2 hour total Completion Time allows the operator adequate time to adjust 

the CEA(s) in an orderly manner and is consistent with the required 

Completion Times in LCO 3.1.4, "Control Element Assembly (CEA) 

Alignment." 

B.1

When Required Action A.1 or Required Action A.2 cannot be met or 

completed within the required Completion Time, a controlled shutdown 

should be commenced. The allowed Completion Time of 6 hours is 

reasonable, based on operating experience, for reaching MODE 3 from 

full power conditions in an orderly manner and without challenging plant 

systems. 
Shutdown CEA Insertion Limits (Digital) 

B 3.1.5 

CEOG STS B 3.1.5-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.1.5.1

REQUIREMENTS 

Verification that the shutdown CEAs are within their insertion limits prior 

to an approach to criticality ensures that when the reactor is critical, or 

being taken critical, the shutdown CEAs will be available to shut down the 

reactor, and the required SDM will be maintained following a reactor trip. 

This SR and Frequency ensure that the shutdown CEAs are withdrawn 

before the regulating CEAs are withdrawn during a unit startup. 

Since the shutdown CEAs are positioned manually by the control room 

operator, verification of shutdown CEA position at a Frequency of 

12 hours is adequate to ensure that the shutdown CEAs are within their 

insertion limits. Also, the Frequency takes into account other information 

available to the operator in the control room for the purpose of monitoring 

the status of the shutdown CEAs. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10 and GDC 26. 

 2. 10 CFR 50.46. 

 3. FSAR, Section [ ]. 
Regulating CEA Insertion Limits (Analog) 

B 3.1.6 

CEOG STS B 3.1.6-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.6 Regulating Control Element Assembly (CEA) Insertion Limits (Analog) 

BASES 

BACKGROUND The insertion limits of the regulating Control Element Assemblies (CEAs) 

are initial assumptions in all safety analyses that assume CEA insertion 

upon reactor trip. The insertion limits directly affect core power 

distributions, assumptions of available SDM, and initial reactivity insertion 

rate. The applicable criteria for these reactivity and power distribution 

design requirements are 10 CFR 50, Appendix A, GDC 10, "Reactor 

Design," and GDC 26, "Reactivity Limits" (Ref. 1), and 10 CFR 50.46, 

"Acceptance Criteria for Emergency Core Cooling Systems for Light 

Water Nuclear Power Reactors" (Ref. 2). 

Limits on regulating CEA insertion have been established, and all CEA 

positions are monitored and controlled during power operation to ensure 

that the power distribution and reactivity limits defined by the design 

power peaking, ejected CEA worth, reactivity insertion rate, and SDM 

limits are preserved. 

The regulating CEA groups operate with a predetermined amount of 

position overlap, in order to approximate a linear relation between CEA 

worth and CEA position (integral CEA worth). The regulating CEA groups 

are withdrawn and operate in a predetermined sequence. The group 

sequence and overlap limits are specified in the COLR. 

The regulating CEAs are used for precise reactivity control of the reactor. 

The positions of the regulating CEAs are manually controlled. They are 

capable of adding reactivity very quickly (compared to borating or 

diluting). 

The power density at any point in the core must be limited to maintain 

specified acceptable fuel design limits, including limits that preserve the 

criteria specified in 10 CFR 50.46 (Ref. 2). Together, LCO 3.1.6, 

LCO 3.2.4, "AZIMUTHAL POWER TILT (Tq)," and LCO 3.2.5, "AXIAL 

SHAPE INDEX (ASI)," provide limits on control component operation and 

on monitored process variables to ensure the core operates within the 

linear heat rate (LCO 3.2.1, "Linear Heat Rate (LHR)"), total planar radial 

peaking factor ( T FXY ) (LCO 3.2.2, "Total Planar Radial Peaking Factor 

( T FXY )"), and total integrated radial peaking factor ( T Fr ) (LCO 3.2.3, "Total 

Integrated Radial Peaking Factor ( T Fr )") limits in the COLR. Operation 

within the LHR limits given in the COLR prevents power peaks that would 

exceed the loss of coolant accident (LOCA) limits derived by the 

Emergency Core Cooling System analysis. Operation within the T FXY and 
Regulating CEA Insertion Limits (Analog) 

B 3.1.6 

CEOG STS B 3.1.6-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

T Fr limits given in the COLR prevents departure from nucleate boiling 

(DNB) during a loss of forced reactor coolant flow accident. In addition to 

the LHR, T FXY , and FT

r limits, certain reactivity limits are preserved by 

regulating CEA insertion limits. The regulating CEA insertion limits also 

restrict the ejected CEA worth to the values assumed in the safety 

analysis and preserve the minimum required SDM in MODES 1 and 2. 

The establishment of limiting safety system settings and LCOs requires 

that the expected long and short term behavior of the radial peaking 

factors be determined. The long term behavior relates to the variation of 

the steady state radial peaking factors with core burnup and is affected by 

the amount of CEA insertion assumed, the portion of a burnup cycle over 

which such insertion is assumed, and the expected power level variation 

throughout the cycle. The short term behavior relates to transient 

perturbations to the steady state radial peaks, due to radial xenon 

redistribution. The magnitudes of such perturbations depend upon the 

expected use of the CEAs during anticipated power reductions and load 

maneuvering. Analyses are performed, based on the expected mode of 

operation of the Nuclear Steam Supply System (base loaded, 

maneuvering, etc.). From these analyses, CEA insertions are determined 

and a consistent set of radial peaking factors defined. The long term 

steady state and short term insertion limits are determined, based upon 

the assumed mode of operation used in the analyses, and provide a 

means of preserving the assumption on CEA insertions used. The long 

and short term insertion limits of LCO 3.1.6 are specified for the plant, 

which has been designed primarily for base loaded operation, but has the 

ability to accommodate a limited amount of load maneuvering. 

The regulating CEA insertion and alignment limits are process variables 

that together characterize and control the three dimensional power 

distribution of the reactor core. Additionally, the regulating bank insertion 

limits control the reactivity that could be added in the event of a CEA 

ejection accident, and the shutdown and regulating bank insertion limits 

ensure the required SDM is maintained. 

Operation within the subject LCO limits will prevent fuel cladding failures 

that would breach the primary fission product barrier and release fission 

products to the reactor coolant in the event of a LOCA, loss of flow, 

ejected CEA, or other accident requiring termination by a Reactor 

Protection System trip function. 
Regulating CEA Insertion Limits (Analog) 

B 3.1.6 

CEOG STS B 3.1.6-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation (Condition I) and anticipated operational occurrences 

ANALYSES (Condition II). The acceptance criteria for the regulating CEA insertion, 

ASI, and Tq LCOs are such as to preclude core power distributions from 

occurring that would violate the following fuel design criteria: 

a. During a large break LOCA, the peak cladding temperature must not 

exceed a limit of 2200°F, 10 CFR 50.46 (Ref. 2), 

b. During a loss of forced reactor coolant flow accident, there must be at 

least a 95% probability at a 95% confidence level (the 95/95 DNB 

criterion) that the hot fuel CEA in the core does not experience a 

DNB condition, 

c. During an ejected CEA accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. 3), and 

d. The CEAs must be capable of shutting down the reactor with a 

minimum required SDM, with the highest worth CEA stuck fully 

withdrawn, GDC 26 (Ref. 1). 

Regulating CEA position, ASI, and Tq are process variables that together 

characterize and control the three dimensional power distribution of the 

reactor core. 

Fuel cladding damage does not occur when the core is operated outside 

these LCOs during normal operation. However, fuel cladding damage 

could result, should an accident occur with simultaneous violation of one 

or more of these LCOs. Changes in the power distribution can cause 

increased power peaking and corresponding increased local LHRs. 

The SDM requirement is ensured by limiting the regulating and shutdown 

CEA insertion limits, so that the allowable inserted worth of the CEAs is 

such that sufficient reactivity is available to shut down the reactor to hot 

zero power. SDM assumes the maximum worth CEA remains fully 

withdrawn upon trip (Ref. 4). 

The most limiting SDM requirements for MODE 1 and 2 conditions at 

BOC are determined by the requirements of several transients, e.g., loss 

of flow, seized rotor, etc. However, the most limiting SDM requirements 

for MODES 1 and 2 at EOC come from just one transient, Steam Line 

Break (SLB). The requirements of the SLB event at EOC for both the full 

power and no load conditions are significantly larger than those of any 

other event at that time in cycle and, also, considerably larger than the 

most limiting requirements at BOC. 
Regulating CEA Insertion Limits (Analog) 

B 3.1.6 

CEOG STS B 3.1.6-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Although the most limiting SDM requirements at EOC are much larger 

than those at BOC, the available SDMs obtained via the scramming of the 

CEAs are also substantially larger due to the much lower boron 

concentration at EOC. To verify that adequate SDMs are available 

throughout the cycle to satisfy the changing requirements, calculations 

are performed at both BOC and EOC. It has been determined that 

calculations at these two times in cycle are sufficient since the differences 

between available SDMs and the limiting SDM requirements are the 

smallest at these times in cycle. The measurement of CEA bank worth 

performed as part of the Startup Testing Program demonstrates that the 

core has the expected shutdown capability. Consequently, adherance to 

LCOs 3.1.5 and 3.1.6 provides assurance that the available SDMs at any 

time in cycle will exceed the limiting SDM requirements at that time in 

cycle. 

Operation at the insertion limits or ASI limits may approach the maximum 

allowable linear heat generation rate or peaking factor, with the allowed 

Tq present. Operation at the insertion limit may also indicate the 

maximum ejected CEA worth could be equal to the limiting value in fuel 

cycles that have sufficiently high ejected CEA worths. 

The regulating and shutdown CEA insertion limits ensure that safety 

analyses assumptions for reactivity insertion rate, SDM, ejected CEA 

worth, and power distribution peaking factors are preserved (Ref. 5). 

The regulating CEA insertion limits satisfy Criterion 2 of 

10 CFR 50.36(c)(2)(ii). 

LCO The limits on regulating CEAs sequence, overlap, and physical insertion, 

as defined in the COLR, must be maintained because they serve the 

function of preserving power distribution, ensuring that the SDM is 

maintained, ensuring that ejected CEA worth is maintained, and ensuring 

adequate negative reactivity insertion on trip. The overlap between 

regulating banks provides more uniform rates of reactivity insertion and 

withdrawal and is imposed to maintain acceptable power peaking during 

regulating CEA motion. 

The power dependent insertion limit (PDIL) alarm circuit is required to be 

OPERABLE for notification that the CEAs are outside the required 

insertion limits. When the PDIL alarm circuit is inoperable, the verification 

of CEA positions is increased to ensure improper CEA alignment is 

identified before unacceptable flux distribution occurs. 
Regulating CEA Insertion Limits (Analog) 

B 3.1.6 

CEOG STS B 3.1.6-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY The regulating CEA sequence, overlap, and physical insertion limits shall 

be maintained with the reactor in MODES 1 and 2. These limits must be 

maintained, since they preserve the assumed power distribution, ejected 

CEA worth, SDM, and reactivity rate insertion assumptions. Applicability 

in MODES 3, 4, and 5 is not required, since neither the power distribution 

nor ejected CEA worth assumptions would be exceeded in these 

MODES. SDM is preserved in MODES 3, 4, and 5 by adjustments to the 

soluble boron concentration. 

This LCO has been modified by a Note indicating the LCO requirement is 

suspended during SR 3.1.4.4. This SR verifies the freedom of the CEAs 

to move, and requires the regulating CEAs to move below the LCO limits, 

which would normally violate the LCO. The Note also allows the LCO to 

be not applicable during reactor power cutback operation, which inserts a 

selected CEA group (usually group 5) during loss of load events. 

ACTIONS A.1 and A.2

Operation beyond the transient insertion limit may result in a loss of SDM 

and excessive peaking factors. The transient insertion limit should not be 

violated during normal operation; this violation, however, may occur 

during transients when the operator is manually controlling the CEAs in 

response to changing plant conditions. When the regulating groups are 

inserted beyond the transient insertion limits, actions must be taken to 

either withdraw the regulating groups beyond the limits or to reduce 

THERMAL POWER to less than or equal to that allowed for the actual 

CEA insertion limit. Two hours provides a reasonable time to accomplish 

this, allowing the operator to deal with current plant conditions while 

limiting peaking factors to acceptable levels. 

B.1 and B.2

If the CEAs are inserted between the long term steady state insertion 

limits and the transient insertion limits for intervals > 4 hours per 24 hour 

period, and the short term steady state insertions are exceeded, peaking 

factors can develop that are of immediate concern (Ref. 6). 

Verifying the short term steady state insertion limits are not exceeded 

ensures that the peaking factors that do develop are within those allowed 

for continued operation. Fifteen minutes provides adequate time for the 

operator to verify if the short term steady state insertion limits are 

exceeded. 
Regulating CEA Insertion Limits (Analog) 

B 3.1.6 

CEOG STS B 3.1.6-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Experience has shown that rapid power increases in areas of the core, in 

which the flux has been depressed, can result in fuel damage, as the LHR 

in those areas rapidly increases. Restricting the rate of THERMAL 

POWER increases to ≤ 5% RTP per hour, following CEA insertion beyond 

the long term steady state insertion limits, ensures the power transients 

experienced by the fuel will not result in fuel failure (Ref. 7). 

C.1

With the regulating CEAs inserted between the long term steady state 

insertion limit and the transient insertion limit, and with the core 

approaching the 5 effective full power days (EFPD) per 30 EFPD or 

14 EFPD per 365 EFPD limits, the core approaches the acceptable limits 

placed on operation with flux patterns outside those assumed in the long 

term burnup assumptions (Ref. 8). In this case, the CEAs must be 

returned to within the long term steady state insertion limits, or the core 

must be placed in a condition in which the abnormal fuel burnup cannot 

continue. A Completion Time of 2 hours is allotted to return the CEAs to 

within the long term steady state insertion limits. 

The required Completion Time of 2 hours from initial discovery of a 

regulating CEA group outside the limits until its restoration to within the 

long term steady state limits, shown on the figures in the COLR, allows 

sufficient time for borated water to enter the Reactor Coolant System from 

the chemical addition and makeup systems, and to cause the regulating 

CEAs to withdraw to the acceptable region. It is reasonable to continue 

operation for 2 hours after it is discovered that the 5 day or 14 day EFPD 

limit has been exceeded. This Completion Time is based on limiting the 

potential xenon redistribution, the low probability of an accident, and the 

steps required to complete the action. 

D.1

When the PDIL alarm circuit is inoperable, performing SR 3.1.6.1 within 

1 hour and once per 4 hours thereafter ensures improper CEA alignments 

are identified before unacceptable flux distributions occur. 
Regulating CEA Insertion Limits (Analog) 

B 3.1.6 

CEOG STS B 3.1.6-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

E.1

When a Required Action cannot be completed within the required 

Completion Time, a controlled shutdown should be commenced. The 

allowed Completion Time of 6 hours is reasonable, based on operating 

experience, for reaching MODE 3 from full power conditions in an orderly 

manner and without challenging plant systems. 

SURVEILLANCE SR 3.1.6.1

REQUIREMENTS 

With the PDIL alarm circuit OPERABLE, verification of each regulating 

CEA group position every 12 hours is sufficient to detect CEA positions 

that may approach the acceptable limits, and to provide the operator with 

time to undertake the Required Action(s) should the sequence or insertion 

limits be found to be exceeded. The 12 hour Frequency also takes into 

account the indication provided by the PDIL alarm circuit and other 

information about CEA group positions available to the operator in the 

control room. 

SR 3.1.6.1 is modified by a Note indicating that entry is allowed into 

MODE 2 for 12 hours without having performed the SR. This is 

necessary, since the unit must be in the applicable MODES in order to 

perform Surveillances that demonstrate the LCO limits are met. 

SR 3.1.6.2

Verification of the accumulated time of CEA group insertion between the 

long term steady state insertion limits and the transient insertion limits 

ensures the cumulative time limits are not exceeded. The 24 hour 

Frequency ensures the operator identifies a time limit that is being 

approached before it is reached. 

SR 3.1.6.3

Demonstrating the PDIL alarm circuit OPERABLE verifies that the PDIL 

alarm circuit is functional. The 31 day Frequency takes into account other 

Surveillances being performed at shorter Frequencies that identify 

improper CEA alignments. 
Regulating CEA Insertion Limits (Analog) 

B 3.1.6 

CEOG STS B 3.1.6-8 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10 and GDC 26. 

 2. 10 CFR 50.46 

 3. FSAR, Section [ ], Section [ ], and Section [ ]. 

 4. FSAR, Section [ ]. 

 5. FSAR, Section [ ]. 

 6. FSAR, Section [ ]. 

 7. FSAR, Section [ ]. 

 8. FSAR, Section [ ]. 
Regulating CEA Insertion Limits (Digital) 

B 3.1.6 

CEOG STS B 3.1.6-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.6 Regulating Control Element Assembly (CEA) Insertion Limits (Digital) 

BASES 

BACKGROUND The insertion limits of the regulating control element assemblies (CEAs) 

are initial assumptions in all safety analyses that assume CEA insertion 

upon reactor trip. The insertion limits directly affect core power 

distributions, assumptions of available SDM, and initial reactivity insertion 

rate. The applicable criteria for these reactivity and power distribution 

design requirements are 10 CFR 50, Appendix A, GDC 10, "Reactor 

Design," and GDC 26, "Reactivity Limits" (Ref. 1), and 10 CFR 50.46, 

"Acceptance Criteria for Emergency Core Cooling Systems for Light 

Water Nuclear Power Reactors" (Ref. 2). 

Limits on regulating CEA insertion have been established, and all CEA 

positions are monitored and controlled during power operation to ensure 

that the power distribution and reactivity limits defined by the design 

power peaking, ejected CEA worth, reactivity insertion rate, and SDM 

limits are preserved. 

The regulating CEA groups operate with a predetermined amount of 

position overlap, in order to approximate a linear relation between CEA 

worth and position (integral CEA worth). The regulating CEA groups are 

withdrawn and operate in a predetermined sequence. The group 

sequence and overlap limits are specified in the COLR. 

The regulating CEAs are used for precise reactivity control of the reactor. 

The positions of the regulating CEAs are manually controlled. They are 

capable of adding reactivity very quickly (compared to borating or 

diluting). 

The power density at any point in the core must be limited to maintain 

specified acceptable fuel design limits, including limits that preserve the 

criteria specified in 10 CFR 50.46 (Ref. 2). Together, LCO 3.1.6; 

LCO 3.2.4, "Departure from Nucleate Boiling Ratio (DNBR)," and 

LCO 3.2.5, "AXIAL SHAPE INDEX (ASI)," provide limits on control 

component operation and on monitored process variables to ensure the 

core operates within LCO 3.2.1, "Linear Heat Rate (LHR)," LCO 3.2.2, 

"Planar Radial Peaking Factor (Fxy)," and LCO 3.2.4, "Departure From 

Nucleate Boiling Ratio (DNBR)," limits in the COLR. Operation within the 

LHR limits given in the COLR prevents power peaks that would exceed 
Regulating CEA Insertion Limits (Digital) 

B 3.1.6 

CEOG STS B 3.1.6-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

the loss of coolant accident (LOCA) limits derived by the Emergency Core 

Cooling Systems analysis. Operation within the Fxy and departure from 

nucleate boiling (DNB) limits given in the COLR prevents DNB during a 

loss of forced reactor coolant flow accident. In addition to the LHR, Fxyxy, 

and DNBR limits, certain reactivity limits are preserved by regulating CEA 

insertion limits. The regulating CEA insertion limits also restrict the 

ejected CEA worth to the values assumed in the safety analyses and 

preserve the minimum required SDM in MODES 1 and 2. 

The establishment of limiting safety system settings and LCOs require 

that the expected long and short term behavior of the radial peaking 

factors be determined. The long term behavior relates to the variation of 

the steady state radial peaking factors with core burnup and is affected by 

the amount of CEA insertion assumed, the portion of a burnup cycle over 

which such insertion is assumed, and the expected power level variation 

throughout the cycle. The short term behavior relates to transient 

perturbations to the steady state radial peaks, due to radial xenon 

redistribution. The magnitudes of such perturbations depend upon the 

expected use of the CEAs during anticipated power reductions and load 

maneuvering. Analyses are performed, based on the expected mode of 

operation of the Nuclear Steam Supply System (base loaded, 

maneuvering, etc.). From these analyses, CEA insertions are determined 

and a consistent set of radial peaking factors defined. The long term 

steady state and short term insertion limits are determined, based upon 

the assumed mode of operation used in the analyses, and provide a 

means of preserving the assumptions on CEA insertions used. The long 

and short term insertion limits of LCO 3.1.6 are specified for the plant, 

which has been designed for primarily base loaded operation, but has the 

ability to accommodate a limited amount of load maneuvering. 

The regulating CEA insertion and alignment limits, ASI and Tq, are 

process variables that together characterize and control the three 

dimensional power distribution of the reactor core. Additionally, the 

regulating bank insertion limits control the reactivity that could be added 

in the event of a CEA ejection accident, and the shutdown and regulating 

bank insertion limits ensure the required SDM is maintained. 

Operation within the subject LCO limits will prevent fuel cladding failures 

that would breach the primary fission product barrier and release fission 

products to the reactor coolant in the event of a LOCA, loss of flow, 

ejected CEA, or other accident requiring termination by a Reactor 

Protection System trip function. 
Regulating CEA Insertion Limits (Digital) 

B 3.1.6 

CEOG STS B 3.1.6-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation (Condition I) and anticipated operational occurrences 

ANALYSES (Condition II). The acceptance criteria for the regulating CEA insertion, 

part length CEA insertion, ASI, and Tq LCOs preclude core power 

distributions from occurring that would violate the following fuel design 

criteria: 

a. During a large break LOCA, the peak cladding temperature must not 

exceed a limit of 2200°F, 10 CFR 50.46 (Ref. 2), 

b. During a loss of forced reactor coolant flow accident, there must be at 

least a 95% probability at a 95% confidence level (the 95/95 DNB 

criterion) that the hot fuel CEA in the core does not experience a 

DNB condition, 

c. During an ejected CEA accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. 3), and 

d. The CEAs must be capable of shutting down the reactor with a 

minimum required SDM, with the highest worth CEA stuck fully 

withdrawn, GDC 26 (Ref. 1). 

Regulating CEA position, ASI, and Tq are process variables that together 

characterize and control the three dimensional power distribution of the 

reactor core. 

Fuel cladding damage does not occur when the core is operated outside 

these LCOs during normal operation. However, fuel cladding damage 

could result, should an accident occur with simultaneous violation of one 

or more of these LCOs. Changes in the power distribution can cause 

increased power peaking and corresponding increased local LHRs. 

The SDM requirement is ensured by limiting the regulating and shutdown 

CEA insertion limits, so that the allowable inserted worth of the CEAs is 

such that sufficient reactivity is available in the CEAs to shut down the 

reactor to hot zero power with a reactivity margin that assumes the 

maximum worth CEA remains fully withdrawn upon trip (Ref. 4). 

The most limiting SDM requirements for MODE 1 and 2 conditions at 

BOC are determined by the requirements of several transients, e.g., loss 

of flow, seized rotor, etc. However, the most limiting SDM requirements 

for MODES 1 and 2 at EOC come from just one transient, steam line 

break (SLB). The requirements of the SLB event at EOC for both the full 

power and no load conditions are significantly larger than those of any 

other event at that time in cycle and, also, considerably larger than the 

most limiting requirements at BOC. 
Regulating CEA Insertion Limits (Digital) 

B 3.1.6 

CEOG STS B 3.1.6-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Although the most limiting SDM requirements at EOC are much larger 

than those at BOC, the available SDMs obtained via the scramming of the 

CEAs are also substantially larger due to the much lower boron 

concentration at EOC. To verify that adequate SDMs are available 

throughout the cycle to satisfy the changing requirements, calculations 

are performed at both BOC and EOC. It has been determined that 

calculations at these two times in cycle are sufficient since the differences 

between available SDMs and the limiting SDM requirements are the 

smallest at these times in cycle. The measurement of CEA bank worth 

performed as part of the Startup Testing Program demonstrates that the 

core has the expected shutdown capability. Consequently, adherance to 

LCOs 3.1.5 and 3.1.6 provides assurance that the available SDMs at any 

time in cycle will exceed the limiting SDM requirements at that time in 

cycle. 

Operation at the insertion limits or ASI may approach the maximum 

allowable linear heat generation rate or peaking factor, with the allowed 

Tq present. Operation at the insertion limit may also indicate the 

maximum ejected CEA worth could be equal to the limiting value in fuel 

cycles that have sufficiently high ejected CEA worths. 

The regulating and shutdown CEA insertion limits ensure that safety 

analyses assumptions for reactivity insertion rate, SDM, ejected CEA 

worth, and power distribution peaking factors are preserved (Ref. 5). 

The regulating CEA insertion limits satisfy Criterion 2 of 

10 CFR 50.36(c)(2)(ii). 

LCO The limits on regulating CEA sequence, overlap, and physical insertion, 

as defined in the COLR, must be maintained because they serve the 

function of preserving power distribution, ensuring that the SDM is 

maintained, ensuring that ejected CEA worth is maintained, and ensuring 

adequate negative reactivity insertion on trip. The overlap between 

regulating banks provides more uniform rates of reactivity insertion and 

withdrawal, and is imposed to maintain acceptable power peaking during 

regulating CEA motion. 

The power dependent insertion limit (PDIL) alarm circuit is required to be 

OPERABLE for notification that the CEAs are outside the required 

insertion limits. When the PDIL alarm circuit is inoperable, the verification 

of CEA positions is increased to ensure improper CEA alignment is 

identified before unacceptable flux distribution occurs. 
Regulating CEA Insertion Limits (Digital) 

B 3.1.6 

CEOG STS B 3.1.6-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY The regulating CEA sequence, overlap, and physical insertion limits shall 

be maintained with the reactor in MODES 1 and 2. These limits must be 

maintained, since they preserve the assumed power distribution, ejected 

CEA worth, SDM, and reactivity rate insertion assumptions. Applicability 

in MODES 3, 4, and 5 is not required, since neither the power distribution 

nor ejected CEA worth assumptions would be exceeded in these 

MODES. SDM is preserved in MODES 3, 4, and 5 by adjustments to the 

soluble boron concentration. 

This LCO is modified by a Note indicating the LCO requirement is 

suspended during SR 3.1.4.3. This SR verifies the freedom of the CEAs 

to move, and requires the regulating CEAs to move below the LCO limits, 

which would normally violate the LCO. The Note also allows the LCO to 

be not applicable during reactor power cutback operation, which inserts a 

selected CEA group (usually group 5) during loss of load events. 

ACTIONS A.1 and A.2

Operation beyond the transient insertion limit may result in a loss of SDM 

and excessive peaking factors. The transient insertion limit should not be 

violated during normal operation; this violation, however, may occur 

during transients when the operator is manually controlling the CEAs in 

response to changing plant conditions. When the regulating groups are 

inserted beyond the transient insertion limits, actions must be taken to 

either withdraw the regulating groups beyond the limits or to reduce 

THERMAL POWER to less than or equal to that allowed for the actual 

CEA insertion limit. Two hours provides a reasonable time to accomplish 

this, allowing the operator to deal with current plant conditions while 

limiting peaking factors to acceptable levels. 

B.1 and B.2

If the CEAs are inserted between the long term steady state insertion 

limits, the transient insertion limits for intervals > 4 hours per 24 hour 

period, and the short term steady state insertion limits are exceeded, 

peaking factors can develop that are of immediate concern (Ref. 6). 

Additionally, since the CEAs can be in this condition without 

misalignment, penalty factors are not inserted in the core protection 

calculators to compensate for the developing peaking factors. Verifying 

the short term steady state insertion limits are not exceeded ensures that 

the peaking factors that do develop are within those allowed for continued 

operation. Fifteen minutes provides adequate time for the operator to 

verify if the short term steady state insertion limits are exceeded. 
Regulating CEA Insertion Limits (Digital) 

B 3.1.6 

CEOG STS B 3.1.6-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Experience has shown that rapid power increases in areas of the core, in 

which the flux has been depressed, can result in fuel damage as the LHR 

in those areas rapidly increases. Restricting the rate of THERMAL 

POWER increases to ≤ 5% RTP per hour, following CEA insertion beyond 

the long term steady state insertion limits, ensures the power transients 

experienced by the fuel will not result in fuel failure (Ref. 7). 

C.1

With the regulating CEAs inserted between the long term steady state 

insertion limit and the transient insertion limit, and with the core 

approaching the 5 effective full power days (EFPD) per 30 EFPD, or 

14 EFPD per 365 EFPD limits, the core approaches the acceptable limits 

placed on operation with flux patterns outside those assumed in the long 

term burnup assumptions. In this case, the CEAs must be returned to 

within the long term steady state insertion limits, or the core must be 

placed in a condition in which the abnormal fuel burnup cannot continue. 

A Completion Time of 2 hours is a reasonable time to return the CEAs to 

within the long term steady state insertion limits. 

The required Completion Time of 2 hours from initial discovery of a 

regulating CEA group outside the limits until its restoration to within the 

long term steady state limits, shown on the figures in the COLR, allows 

sufficient time for borated water to enter the Reactor Coolant System from 

the chemical addition and makeup systems, and to cause the regulating 

CEAs to withdraw to the acceptable region. It is reasonable to continue 

operation for 2 hours after it is discovered that the 5 day or 14 day EFPD 

limit has been exceeded. This Completion Time is based on limiting the 

potential xenon redistribution, the low probability of an accident, and the 

steps required to complete the action. 

D.1 and D.2

With the Core Operating Limit Supervisory System out of service, 

operation beyond the short term steady state insertion limits can result in 

peaking factors that could approach the DNB or local power density trip 

setpoints. Eliminating this condition within 2 hours limits the magnitude of 

the peaking factors to acceptable levels (Ref. 8). Restoring the CEAs to 

within the limit or reducing THERMAL POWER to that fraction of RTP that 

is allowed by CEA group position, using the limits specified in the COLR, 

ensures acceptable peaking factors are maintained. 
Regulating CEA Insertion Limits (Digital) 

B 3.1.6 

CEOG STS B 3.1.6-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

E.1

With the PDIL circuit inoperable, performing SR 3.1.6.1 within 1 hour and 

every 4 hours thereafter ensures improper CEA alignments are identified 

before unacceptable flux distributions occur. 

F.1

When a Required Action cannot be completed within the required 

Completion Time, a controlled shutdown should be commenced. The 

allowed Completion Time of 6 hours is reasonable, based on operating 

experience, for reaching MODE 3 from full power conditions in an orderly 

manner and without challenging plant systems. 

SURVEILLANCE SR 3.1.6.1

REQUIREMENTS 

With the PDIL alarm circuit OPERABLE, verification of each regulating 

CEA group position every 12 hours is sufficient to detect CEA positions 

that may approach the acceptable limits, and provides the operator with 

time to undertake the Required Action(s) should the sequence or insertion 

limits be found to be exceeded. The 12 hour Frequency also takes into 

account the indication provided by the PDIL alarm circuit and other 

information about CEA group positions available to the operator in the 

control room. 

SR 3.1.6.1 is modified by a Note indicating that entry is allowed into 

MODE 2 for 12 hours without having performed the SR. This is 

necessary, since the unit must be in the applicable MODES in order to 

perform Surveillances that demonstrate the LCO limits are met. 

SR 3.1.6.2

Verification of the accumulated time of CEA group insertion between the 

long term steady state insertion limits and the transient insertion limits 

ensures the cumulative time limits are not exceeded. The 24 hour 

Frequency ensures the operator identifies a time limit that is being 

approached before it is reached. 
Regulating CEA Insertion Limits (Digital) 

B 3.1.6 

CEOG STS B 3.1.6-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.1.6.3

Demonstrating the PDIL alarm circuit OPERABLE verifies that the PDIL 

alarm circuit is functional. The 31 day Frequency takes into account other 

Surveillances being performed at shorter Frequencies that identify 

improper CEA alignments. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10 and GDC 26. 

 2. 10 CFR 50.46. 

 3. FSAR, Section [ ], Section [ ], and Section [ ]. 

 4. FSAR, Section [ ]. 

 5. FSAR, Section [ ]. 

 6. FSAR, Section [ ]. 

 7. FSAR, Section [ ]. 

 8. FSAR, Section [ ]. 
STE - SDM (Analog) 

B 3.1.7 

CEOG STS B 3.1.7-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.7 Special Test Exception (STE) - SHUTDOWN MARGIN (SDM) (Analog) 

BASES 

BACKGROUND The primary purpose of the SHUTDOWN MARGIN (SDM) Special Test 

Exception (STE) is to permit relaxation of existing LCOs to allow the 

performance of certain PHYSICS TESTS. These tests are constructed to 

determine the control element assembly (CEA) worth. 

Section XI of 10 CFR 50, Appendix B, "Quality Assurance Criteria for 

Nuclear Power Plants and Fuel Processing Plants" (Ref. 1), requires that 

a test program be established to ensure that structures, systems, and 

components will perform satisfactorily in service. All functions necessary 

to ensure that specified design conditions are not exceeded during 

normal operation and anticipated operational occurrences must be tested. 

Testing is required as an integral part of the design, fabrication, 

construction, and operation of the power plant. Requirements for 

notification of the NRC, for the purpose of conducting tests and 

experiments, are specified in 10 CFR 50.59, "Changes, Tests, and 

Experiments" (Ref. 2). 

The key objectives of a test program are to (Ref. 3): 

a. Ensure that the facility has been adequately designed, 

b. Validate the analytical models used in design and analysis, 

c. Verify assumptions used for predicting plant response, 

d. Ensure that installation of equipment in the facility has been 

accomplished in accordance with the design, and 

e. Verify that operating and emergency procedures are adequate. 

To accomplish these objectives, testing is required prior to initial criticality, 

after each refueling shutdown, and during startup, low power operation, 

power ascension, and at power operation. The PHYSICS TESTS 

requirements for reload fuel cycles ensure that the operating 

characteristics of the core are consistent with the design predictions, and 

that the core can be operated as designed (Ref. 4). 
STE - SDM (Analog) 

B 3.1.7 

CEOG STS B 3.1.7-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

PHYSICS TESTS procedures are written and approved in accordance 

with established formats. The procedures include all information 

necessary to permit a detailed execution of testing required to ensure that 

the design intent is met. PHYSICS TESTS are performed in accordance 

with these procedures, and test results are approved prior to continued 

power escalation and long term power operation. Examples of PHYSICS 

TESTS include determination of critical boron concentration, CEA group 

worths, reactivity coefficients, flux symmetry, and core power distribution. 

APPLICABLE It is acceptable to suspend certain LCOs for PHYSICS TESTS because 

SAFETY fuel damage criteria are not exceeded. Even if an accident occurs during 

ANALYSES PHYSICS TESTS with one or more LCOs suspended, fuel damage 

criteria are preserved because adequate limits on power distribution and 

shutdown capability are maintained during PHYSICS TESTS. 

Reference 5 defines the requirements for initial testing of the facility, 

including PHYSICS TESTS. Requirements for reload fuel cycle 

PHYSICS TESTS are defined in ANSI/ANS-19.6.1-1985 (Ref. 4). 

Although these PHYSICS TESTS are generally accomplished within the 

limits of all LCOs, conditions may occur when one or more LCOs must be 

suspended to make completion of PHYSICS TESTS possible or practical. 

This is acceptable as long as the fuel design criteria are not violated. As 

long as the linear heat rate (LHR) remains within its limit, fuel design 

criteria are preserved. 

In this test, the following LCOs are suspended: 

a. LCO 3.1.1, "SHUTDOWN MARGIN (SDM)", 

b. LCO 3.1.5, “Shutdown Control Element Assembly (CEA) Insertion 

Limits,” and 

c. LCO 3.1.6, "Regulating Control Element Assembly (CEA) Insertion 

Limits." 

Therefore, this LCO places limits on the minimum amount of CEA worth 

required to be available for reactivity control when CEA worth 

measurements are performed. 

The individual LCOs cited above govern SDM CEA group height, 

insertion, and alignment. Additionally, the LCOs governing Reactor 

Coolant System (RCS) flow, reactor inlet temperature, and pressurizer 

pressure contribute to maintaining departure from nucleate boiling (DNB) 

parameter limits. The initial condition criteria for accidents sensitive to 
STE - SDM (Analog) 

B 3.1.7 

CEOG STS B 3.1.7-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

core power distribution are preserved by the LHR and DNB parameter 

limits. The criteria for the loss of coolant accident (LOCA) are specified in 

10 CFR 50.46, "Acceptance Criteria for Emergency core Cooling Systems 

for Light Water Nuclear Power Reactors" (Ref. 6). The criteria for the loss 

of forced reactor coolant flow accident are specified in Reference 7. 

Operation within the LHR limit preserves the LOCA criteria; operation 

within the DNB parameter limits preserves the loss of flow criteria. 

SRs are conducted as necessary to ensure that LHR and DNB 

parameters remain within limits during PHYSICS TESTS. Performance of 

these SRs allows PHYSICS TESTS to be conducted without decreasing 

the margin of safety. 

Requiring that shutdown reactivity equivalent to at least the highest 

estimated CEA worth (of those CEAs actually withdrawn) be available for 

trip insertion from the OPERABLE CEA provides a high degree of 

assurance that shutdown capability is maintained for the most challenging 

postulated accident, a stuck CEA. Since LCO 3.1.1 is suspended, 

however, there is not the same degree of assurance during this test that 

the reactor would always be shut down if the highest worth CEA was 

stuck out and calculational uncertainties or the estimated highest CEA 

worth was not as expected (the single failure criterion is not met). This 

situation is judged acceptable, however, because specified acceptable 

fuel damage limits are still met. The risk of experiencing a stuck CEA and 

subsequent criticality is reduced during this PHYSICS TEST exception by 

the requirements to determine CEA positions every 2 hours; by the trip of 

each CEA to be withdrawn 24 hours prior to suspending the SDM; and by 

ensuring that shutdown reactivity is available, equivalent to the reactivity 

worth of the estimated highest worth withdrawn CEA (Ref. 5). 

PHYSICS TESTS include measurement of core parameters or exercise of 

control components that affect process variables. Among the process 

variables involved are total planar radial peaking factor, total integrated 

radial peaking factor, Tq and ASI, which represent initial condition input 

(power peaking) to the accident analysis. Also involved are the shutdown 

and regulating CEAs, which affect power peaking and are required for 

shutdown of the reactor. The limits for these variables are specified for 

each fuel cycle in the COLR. 

As described in LCO 3.0.7, compliance with Special Test Exception LCOs 

is optional, and therefore no criteria of 10 CFR 50.36(c)(2)(ii) apply. 

Special Test Exception LCOs provide flexibility to perform certain 

operations by appropriately modifying requirements of other LCOs. A 

discussion of the criteria satisfied for the other LCOs is provided in their 

respective Bases. 
STE - SDM (Analog) 

B 3.1.7 

CEOG STS B 3.1.7-4 Rev. 3.0, 03/31/04 

BASES 

LCO This LCO provides that a minimum amount of CEA worth is immediately 

available for reactivity control when CEA worth measurement tests are 

performed. The STE is required to permit the periodic verification of the 

actual versus predicted worth of the regulating and shutdown CEAs. The 

SDM requirements of LCO 3.1.1, the shutdown CEA insertion limits of 

LCO 3.1.5, and the regulating CEA insertion limits of LCO 3.1.6 may be 

suspended. 

APPLICABILITY This LCO is applicable in MODES 2 and 3. Although CEA worth testing is 

conducted in MODE 2, sufficient negative reactivity is inserted during the 

performance of these tests to result in temporary entry into MODE 3. 

Because the intent is to immediately return to MODE 2 to continue CEA 

worth measurements, the STE allows limited operation to 6 consecutive 

hours in MODE 3, as indicated by the Note, without having to borate to 

meet the SDM requirements of LCO 3.1.1. 

ACTIONS A.1

With any CEA not fully inserted and less than the minimum required 

reactivity equivalent available for insertion, or with all CEAs inserted and 

the reactor subcritical by less than the reactivity equivalent of the highest 

worth CEA, restoration of the minimum SDM requirements must be 

accomplished by increasing the RCS boron concentration. The required 

Completion Time of 15 minutes for initiating boration allows the operator 

sufficient time to align the valves and start the boric acid pumps and is 

consistent with the Completion Time of LCO 3.1.1. 

SURVEILLANCE SR 3.1.7.1

REQUIREMENTS 

Verification of the position of each partially or fully withdrawn full length or 

part length CEA is necessary to ensure that the minimum negative 

reactivity requirements for insertion on a trip are preserved. A 2 hour 

Frequency is sufficient for the operator to verify that each CEA position is 

within the acceptance criteria. 

SR 3.1.7.2

Prior demonstration that each CEA to be withdrawn from the core during 

PHYSICS TESTS is capable of full insertion, when tripped from at least a 

50% withdrawn position, ensures that the CEA will insert on a trip signal. 

The Frequency ensures that the CEAs are OPERABLE prior to reducing 

SDM to less than the limits of LCO 3.1.1. 
STE - SDM (Analog) 

B 3.1.7 

CEOG STS B 3.1.7-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The SR is modified by a Note which allows the SR to not be performed 

during initial power escalation following a refueling outage if SR 3.1.4.6 

has been met during that refueling outage. This allows the CEA drop 

time test, which also proves the CEAs are trippable, to be credited for this 

SR. 

REFERENCES 1. 10 CFR 50, Appendix B, Section XI. 

 2. 10 CFR 50.59. 

 3. Regulatory Guide 1.68, Revision 2, August 1978. 

 4. ANSI/ANS-19.6.1-1985, December 13, 1985. 

 5. FSAR, Chapter [14]. 

 6. 10 CFR 50.46. 

 7. FSAR, Chapter [15]. 
Part Length CEA Insertion Limits (Digital) 

B 3.1.7 

CEOG STS B 3.1.7-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.7 Part Length Control Element Assembly (CEA) Insertion Limits (Digital) 

BASES 

BACKGROUND The insertion limits of the part length control element assemblies (CEAs) 

are initial assumptions in all safety analyses. The insertion limits directly 

affect core power distributions. The applicable criteria for these power 

distribution design requirements are 10 CFR 50, Appendix A, GDC 10, 

"Reactor Design" (Ref. 1), and 10 CFR 50.46, "Acceptance Criteria for 

Emergency Core Cooling Systems for Light Water Nuclear Plants" 

(Ref. 2). Limits on part length CEA insertion have been established, and 

all CEA positions are monitored and controlled during power operation to 

ensure that the power distribution defined by the design power peaking 

limits is preserved. 

The regulating CEAs are used for precise reactivity control of the reactor. 

The positions of the regulating CEAs are manually controlled. They are 

capable of adding reactivity very quickly (compared to borating or 

diluting). 

The power density at any point in the core must be limited to maintain 

specified acceptable fuel design limits, including limits that preserve the 

criteria specified in 10 CFR 50.46 (Ref. 2). Together, LCO 3.1.6, 

"Regulating Control Element Assembly (CEA) Insertion Limits," 

LCO 3.1.7, LCO 3.2.4, "Departure From Nucleate Boiling Ratio (DNBR)," 

and LCO 3.2.5, "AXIAL SHAPE INDEX (ASI)," provide limits on control 

component operation and on monitored process variables to ensure the 

core operates within the linear heat rate (LHR) (LCO 3.2.1, "Linear Heat 

Rate (LHR)"), planar peaking factor (Fxy) (LCO 3.2.2, "Planar Radial 

Peaking Factors (Fxy)"), and LCO 3.2.4 limits in the COLR. 

Operation within the limits given in the COLR prevents power peaks that 

would exceed the loss of coolant accident (LOCA) limits derived by the 

Emergency Core Cooling Systems analysis. Operation within the Fxy and 

departure from nucleate boiling (DNB) limits given in the COLR prevents 

DNB during a loss of forced reactor coolant flow accident. 

The establishment of limiting safety system settings and LCOs requires 

that the expected long and short term behavior of the radial peaking 

factors be determined. The long term behavior relates to the variation of 

the steady state radial peaking factors with core burnup; it is affected by 

the amount of CEA insertion assumed, the portion of a burnup cycle over 

which such insertion is assumed, and the expected power level variation 

throughout the cycle. The short term behavior relates to transient 
Part Length CEA Insertion Limits (Digital) 

B 3.1.7 

CEOG STS B 3.1.7-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

perturbations to the steady state radial peaks due to radial xenon 

redistribution. The magnitudes of such perturbations depend upon the 

expected use of the CEAs during anticipated power reductions and load 

maneuvering. Analyses are performed, based on the expected mode of 

operation of the Nuclear Steam Supply System (base loaded, 

maneuvering, etc.). From these analyses, CEA insertions are 

determined, and a consistent set of radial peaking factors are defined. 

The long term (steady state) and short term insertion limits are 

determined, based upon the assumed mode of operation used in the 

analyses; they provide a means of preserving the assumptions on CEA 

insertions used. The long and short term insertion limits of LCO 3.1.7 are 

specified for the plant, which has been designed primarily for base loaded 

operation, but has the ability to accommodate a limited amount of load 

maneuvering. 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation (Condition I) and anticipated operational occurrences 

ANALYSES (Condition II). The regulating CEA insertion, part length CEA insertion, 

ASI, and TQ LCOs preclude core power distributions from occurring that 

would violate the following fuel design criteria: 

a. During a large break LOCA, the peak cladding temperature must not 

exceed 2200°F (Ref. 2), 

b. During a loss of forced reactor coolant flow accident, there must be at 

least a 95% probability at a 95% confidence level (the 95/95 DNB 

criterion) that the hot fuel CEA in the core does not experience a 

DNB condition, 

c. During an ejected CEA accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. 3), and 

d. The CEAs must be capable of shutting down the reactor with a 

minimum required SDM, with the highest worth CEA stuck fully 

withdrawn, GDC 26 (Ref. 1). 

Regulating CEA position, part length CEA position, ASI, and TQ are 

process variables that together characterize and control the three 

dimensional power distribution of the reactor core. 
Part Length CEA Insertion Limits (Digital) 

B 3.1.7 

CEOG STS B 3.1.7-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Fuel cladding damage does not occur when the core is operated outside 

these LCOs during normal operation. However, fuel cladding damage 

could result, should an accident occur with simultaneous violation of one 

or more of these LCOs. Changes in the power distribution can cause 

increased power peaking and corresponding increased local LHRs. 

The regulating CEA insertion limits satisfy Criterion 2 of 

10 CFR 50.36(c)(2)(ii). The part length CEAs are required due to the 

potential peaking factor violations that could occur if part length CEAs 

exceed insertion limits. 

LCO The limits on part length CEA insertion, as defined in the COLR, must be 

maintained because they serve the function of preserving power 

distribution. 

APPLICABILITY The part length insertion limits shall be maintained with the reactor in 

MODE 1 > 20% RTP. These limits must be maintained, since they 

preserve the assumed power distribution. Applicability in lower MODES 

is not required, since the power distribution assumptions would not be 

exceeded in these MODES. 

This LCO has been modified by a Note suspending the LCO requirement 

while exercising part length CEAs. Exercising part length CEAs may 

require moving them outside their insertion limits. 

ACTIONS A.1, A.2, and B.1

If the part length CEA groups are inserted beyond the transient insertion 

limit or between the long term (steady state) insertion limit and the 

transient limit for 7 or more effective full power days (EFPD) out of any 

30 EFPD period, or for 14 EFPD or more out of any 365 EFPD period, 

flux patterns begin to develop that are outside the range assumed for long 

term fuel burnup. If allowed to continue beyond this limit, the peaking 

factors assumed as initial conditions in the accident analysis may be 

invalidated (Ref. 4). Restoring the CEAs to within limits or reducing 

THERMAL POWER to that fraction of RTP that is allowed by CEA group 

position, using the limits specified in the COLR, ensures that acceptable 

peaking factors are maintained. 

Since these effects are cumulative, actions are provided to limit the total 

time the part length CEAs can be out of limits in any 30 EFPD or 

365 EFPD period. Since the cumulative out of limit times are in days, an 

additional Completion Time of 2 hours is reasonable for restoring the part 

length CEAs to within the allowed limits. 
Part Length CEA Insertion Limits (Digital) 

B 3.1.7 

CEOG STS B 3.1.7-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1

When a Required Action cannot be completed within the required 

Completion Time, a controlled shutdown should commence. A 

Completion Time of 4 hours is reasonable, based on operating 

experience, for reducing power to ≤ 20 RTP from full power conditions in 

an orderly manner and without challenging plant systems. 

SURVEILLANCE SR 3.1.7.1

REQUIREMENTS 

Verification of each part length CEA group position every 12 hours is 

sufficient to detect CEA positions that may approach the limits, and 

provide the operator with time to undertake the Required Action(s), 

should insertion limits be found to be exceeded. The 12 hour Frequency 

also takes into account the indication provided by the power dependent 

insertion limit alarm circuit and other information about CEA group 

positions available to the operator in the control room. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 10 and GDC 26. 

 2. 10 CFR 50.46. 

 3. FSAR, Section [ ]. 

 4. FSAR, Section [ ]. 
STE - MODES 1 and 2 (Analog) 

B 3.1.8 

CEOG STS B 3.1.8-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.8 Special Test Exceptions (STE) - MODES 1 and 2 (Analog) 

BASES 

BACKGROUND The primary purpose of these MODES 1 and 2 Special Test Exceptions 

(STE) is to permit relaxation of existing LCOs to allow the performance of 

certain PHYSICS TESTS. These tests are conducted to determine 

specific reactor core characteristics. 

Section XI of 10 CFR 50, Appendix B, "Quality Assurance Criteria for 

Nuclear Power Plants and Fuel Processing Plants" (Ref. 1), requires that 

a test program be established to ensure that structures, systems, and 

components will perform satisfactorily in service. All functions necessary 

to ensure that specified design conditions are not exceeded during 

normal operation and anticipated operational occurrences must be tested. 

Testing is required as an integral part of the design, fabrication, 

construction, and operation of the power plant. Requirements for 

notification of the NRC, for the purpose of conducting tests and 

experiments, are specified in 10 CFR 50.59, "Changes, Tests, and 

Experiments" (Ref. 2). 

The key objectives of a test program are to (Ref. 3): 

a. Ensure that the facility has been adequately designed, 

b. Validate the analytical models used in design and analysis, 

c. Verify assumptions used for predicting plant response, 

d. Ensure that installation of equipment in the facility has been 

accomplished in accordance with design, and 

e. Verify that operating and emergency procedures are adequate. 

To accomplish these objectives, testing is required prior to initial criticality, 

after each refueling shutdown, and during startup, low power operation, 

power ascension, and at power operation. The PHYSICS TESTS 

requirements for reload fuel cycles ensure that the operating 

characteristics of the core are consistent with the design predictions, and 

that the core can be operated as designed (Ref. 4). 
STE - MODES 1 and 2 (Analog) 

B 3.1.8 

CEOG STS B 3.1.8-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

PHYSICS TESTS procedures are written and approved in accordance 

with established formats. The procedures include all information 

necessary to permit a detailed execution of testing required to ensure that 

design intent is met. PHYSICS TESTS are performed in accordance with 

these procedures and test results are approved prior to continued power 

escalation and long term power operation. 

Examples of PHYSICS TESTS include determination of critical boron 

concentration, control element assembly (CEA) group worths, reactivity 

coefficients, flux symmetry, and core power distribution. 

APPLICABLE It is acceptable to suspend certain LCOs for PHYSICS TESTS because 

SAFETY fuel damage criteria are not exceeded. Even if an accident occurs during 

ANALYSES a PHYSICS TEST with one or more LCOs suspended, fuel damage 

criteria are preserved because the limits on power distribution and 

shutdown capability are maintained during PHYSICS TESTS. 

Reference 5 defines the requirements for initial testing of the facility, 

including PHYSICS TESTS. Requirements for reload fuel cycle 

PHYSICS TESTS are defined in ANSI/ANS-19.6.1-1985 (Ref. 4). 

Although these PHYSICS TESTS are generally accomplished within the 

limits of all LCOs, conditions may occur when one or more LCOs must be 

suspended to make completion of PHYSICS TESTS possible or practical. 

This is acceptable as long as the fuel design criteria are not violated. As 

long as the linear heat rate (LHR) remains within its limit, fuel design 

criteria are preserved. 

In this test, the following LCOs are suspended: 

LCO 3.1.3, "Moderator Temperature Coefficient (MTC)," 

LCO 3.1.4, "Control Element Assembly (CEA) Alignment," 

LCO 3.1.5, "Shutdown Control Element Assembly (CEA) Insertion 

Limits," 

LCO 3.1.6, "Regulating Control Element Assembly (CEA) Insertion 

Limits," 

LCO 3.2.2, "Total Planar Radial Peaking Factor ( T FXY )," 

LCO 3.2.3, "Total Integrated Radial Peaking Factor (FT

r )" and 

LCO 3.2.4, "AZIMUTHAL POWER TILT (Tq)." 

The safety analysis (Ref. 6) places limits on allowable THERMAL 

POWER during PHYSICS TESTS and requires the LHR and the 

departure from nucleate boiling (DNB) parameter to be maintained within 

limits. The power plateau of < 85% RTP and the associated trip setpoints 

are required to ensure [explain]. 
STE - MODES 1 and 2 (Analog) 

B 3.1.8 

CEOG STS B 3.1.8-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The individual LCOs governing CEA group height, insertion and 

alignment, ASI, T FXY , FT

r, and Tq preserve the LHR limits. Additionally, the 

LCOs governing Reactor Coolant System (RCS) flow, reactor inlet 

temperature (Tc), and pressurizer pressure contribute to maintaining DNB 

parameter limits. The initial condition criteria for accidents sensitive to 

core power distribution are preserved by the LHR and DNB parameter 

limits. The criteria for the loss of coolant accident (LOCA) are specified in 

10 CFR 50.46, "Acceptance Criteria for Emergency Core Cooling 

Systems for Light Water Nuclear Power Reactors" (Ref. 7). The criteria 

for the loss of forced reactor coolant flow accident are specified in 

Reference 7. Operation within the LHR limit preserves the LOCA criteria; 

operation within the DNB parameter limits preserves the loss of flow 

criteria. 

During PHYSICS TESTS, one or more of the LCOs that normally 

preserve the LHR and DNB parameter limits may be suspended. The 

results of the accident analysis are not adversely impacted, however, if 

LHR and DNB parameters are verified to be within their limits while the 

LCOs are suspended. Therefore, SRs are placed as necessary to ensure 

that LHR and DNB parameters remain within limits during PHYSICS 

TESTS. Performance of these Surveillances allows PHYSICS TESTS to 

be conducted without decreasing the margin of safety. 

PHYSICS TESTS include measurement of core parameters or exercise of 

control components that affect process variables. Among the process 

variables involved are T FXY , FT

r, Tq, and ASI, which represent initial 

condition input (power peaking) to the accident analysis. Also involved 

are the shutdown and regulating CEAs, which affect power peaking and 

are required for shutdown of the reactor. The limits for these variables 

are specified for each fuel cycle in the COLR. 

As described in LCO 3.0.7, compliance with Special Test Exceptions 

LCOs is optional, and therefore no criteria of 10 CFR 50.36(c)(2)(ii) apply. 

Special Test Exception LCOs provide flexibility to perform certain 

operations by appropriately modifying requirements of other LCOs. A 

discussion of the criteria satisfied for the other LCOs is provided in their 

respective Bases. 
STE - MODES 1 and 2 (Analog) 

B 3.1.8 

CEOG STS B 3.1.8-4 Rev. 3.0, 03/31/04 

BASES 

LCO This LCO permits individual CEAs to be positioned outside of their normal 

group heights and insertion limits during the performance of PHYSICS 

TESTS such as those required to: 

a. Measure CEA worth, 

b. Determine the reactor stability index and damping factor under xenon 

oscillation conditions, 

c. Determine power distributions for nonnormal CEA configurations, 

d. Measure rod shadowing factors, and 

e. Measure temperature and power coefficients. 

Additionally, it permits the center CEA to be misaligned during PHYSICS 

TESTS required to determine the isothermal temperature coefficient 

(ITC), MTC, and power coefficient. 

The requirements of LCO 3.1.3, LCO 3.1.4, LCO 3.1.5, LCO 3.1.6, 

LCO 3.2.2, LCO 3.2.3, and LCO 3.2.4 may be suspended during the 

performance of PHYSICS TESTS, provided THERMAL POWER is 

restricted to test power plateau, which shall not exceed 85% RTP. 

APPLICABILITY This LCO is applicable in MODES 1 and 2 because the reactor must be 

critical at various THERMAL POWER levels to perform the PHYSICS 

TESTS described in the LCO section. Limiting the test power plateau to 

< 85% RTP ensures that LHRs are maintained within acceptable limits. 

ACTIONS A.1

If THERMAL POWER exceeds the test power plateau, THERMAL 

POWER must be reduced to restore the additional thermal margin 

provided by the reduction. The 15 minute Completion Time ensures that 

prompt action shall be taken to reduce THERMAL POWER to within 

acceptable limits. 

B.1 and B.2

If Required Action A.1 cannot be completed within the required 

Completion Time, PHYSICS TESTS must be suspended within 1 hour. 

Allowing 1 hour for suspending PHYSICS TESTS allows the operator 

sufficient time to change any abnormal CEA configuration back to within 

the limits of LCO 3.1.4, LCO 3.1.5, and LCO 3.1.6. 
STE - MODES 1 and 2 (Analog) 

B 3.1.8 

CEOG STS B 3.1.8-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Suspension of PHYSICS TESTS exceptions requires restoration of each 

of the applicable LCOs to within specification. 

SURVEILLANCE SR 3.1.8.1

REQUIREMENTS 

Verifying that THERMAL POWER is equal to or less than that allowed by 

the test power plateau, as specified in the PHYSICS TEST procedure and 

required by the safety analysis, ensures that adequate LHR and DNB 

parameter margins are maintained while LCOs are suspended. The 

1 hour Frequency is sufficient, based on the slow rate of power change 

and increased operational controls in place during PHYSICS TESTS. 

REFERENCES 1. 10 CFR 50, Appendix B, Section XI. 

 2. 10 CFR 50.59. 

 3. Regulatory Guide 1.68, Revision 2, August 1978. 

 4. ANSI/ANS-19.6.1-1985, December 13, 1985. 

 5. FSAR, Chapter [14]. 

 6. FSAR, Section [15.3.2.1]. 

 7. 10 CFR 50.46. 
STE - SDM (Digital) 

B 3.1.8 

CEOG STS B 3.1.8-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.8 Special Test Exceptions (STE) - SHUTDOWN MARGIN (SDM) (Digital) 

BASES 

BACKGROUND The primary purpose of the SHUTDOWN MARGIN (SDM) Special Test 

Exceptions (STE) is to permit relaxation of existing LCOs to allow the 

performance of certain PHYSICS TESTS. These tests are conducted to 

determine the control element assembly (CEA) worth. 

Section XI of 10 CFR 50, Appendix B, "Quality Assurance Criteria for 

Nuclear Power Plants and Fuel Processing Plants" (Ref. 1), requires that 

a test program be established to ensure that structures, systems, and 

components will perform satisfactorily in service. All functions necessary 

to ensure that specified design conditions are not exceeded during 

normal operation and anticipated operational occurrences must be tested. 

Testing is required as an integral part of the design, fabrication, 

construction, and operation of the power plant. Requirements for 

notification of the NRC, for the purpose of conducting tests and 

experiments, are specified in 10 CFR 50.59, "Changes, Tests, and 

Experiments" (Ref. 2). 

The key objectives of a test program are to (Ref. 3): 

a. Ensure that the facility has been adequately designed, 

b. Validate the analytical models used in design and analysis, 

c. Verify assumptions used for predicting plant response, 

d. Ensure that installation of equipment in the facility has been 

accomplished in accordance with the design, and 

e. Verify that operating and emergency procedures are adequate. 

To accomplish these objectives, testing is required prior to initial criticality, 

after each refueling shutdown, and during startup, low power operation, 

power ascension, and at power operation. The PHYSICS TESTS 

requirements for reload fuel cycles ensure that the operating 

characteristics of the core are consistent with the design predictions and 

that the core can be operated as designed (Ref. 4). 
STE - SDM (Digital) 

B 3.1.8 

CEOG STS B 3.1.8-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

PHYSICS TESTS procedures are written and approved in accordance 

with established formats. The procedures include all information 

necessary to permit a detailed execution of testing required to ensure that 

the design intent is met. PHYSICS TESTS are performed in accordance 

with these procedures and test results are approved prior to continued 

power escalation and long term power operation. Examples of PHYSICS 

TESTS include determination of critical boron concentration, CEA group 

worths, reactivity coefficients, flux symmetry, and core power distribution. 

APPLICABLE It is acceptable to suspend certain LCOs for PHYSICS TESTS because 

SAFETY fuel damage criteria are not exceeded. Even if an accident occurs during 

ANALYSES PHYSICS TESTS with one or more LCOs suspended, fuel damage 

criteria are preserved because adequate limits on power distribution and 

shutdown capability are maintained during PHYSICS TESTS. 

Reference 5 defines the requirements for initial testing of the facility, 

including PHYSICS TESTS. Requirements for reload fuel cycle 

PHYSICS TESTS are defined in ANSI/ANS-19.6.1-1985 (Ref. 4). 

PHYSICS TESTS for reload fuel cycles are given in Table 1 of 

ANSI/ANS-19.6.1-1985. Although these PHYSICS TESTS are generally 

accomplished within the limits of all LCOs, conditions may occur when 

one or more LCOs must be suspended to make completion of PHYSICS 

TESTS possible or practical. This is acceptable as long as the fuel 

design criteria are not violated. As long as the linear heat rate (LHR) 

remains within its limit, fuel design criteria are preserved. 

In this test, the following LCOs are suspended: 

a. LCO 3.1.1, "SHUTDOWN MARGIN (SDM)," 

b. LCO 3.1.5, “Shutdown Control Element Assembly (CEA) Insertion 

Limits,” and 

c. LCO 3.1.6, "Regulating Control Element Assembly (CEA) Insertion 

Limits." 

Therefore, this LCO places limits on the minimum amount of CEA worth 

required to be available for reactivity control when CEA worth 

measurements are performed. 

The individual LCOs cited above govern SDM CEA group height, 

insertion, and alignment. Additionally, the LCOs governing Reactor 

Coolant System (RCS) flow, reactor inlet temperature Tc, and pressurizer 

pressure contribute to maintaining departure from nucleate boiling (DNB) 

parameter limits. The initial condition criteria for accidents sensitive to 
STE - SDM (Digital) 

B 3.1.8 

CEOG STS B 3.1.8-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

core power distribution are preserved by the LHR and DNB parameter 

limits. The criteria for the loss of coolant accident (LOCA) are specified in 

10 CFR 50.46, "Acceptance Criteria for Emergency Core Cooling 

Systems for Light Water Nuclear Power Reactors" (Ref. 6). The criteria 

for the loss of forced reactor coolant flow accidents are specified in 

Reference 7. Operation within the LHR limit preserves the LOCA criteria; 

operation within the DNB parameter limits preserves the loss of flow 

criteria. 

SRs are conducted as necessary to ensure that LHR and DNB 

parameters remain within limits during PHYSICS TESTS. Performance of 

these SRs allows PHYSICS TESTS to be conducted without decreasing 

the margin of safety. 

Requiring that shutdown reactivity equivalent to at least the highest 

estimated CEA worth (of those CEAs actually withdrawn) be available for 

trip insertion from the OPERABLE CEAs, provides a high degree of 

assurance that shutdown capability is maintained for the most challenging 

postulated accident, a stuck CEA. Since LCO 3.1.1 is suspended, 

however, there is not the same degree of assurance during this test that 

the reactor would always be shut down if the highest worth CEA was 

stuck out and calculational uncertainties or the estimated highest CEA 

worth was not as expected (the single failure criterion is not met). This 

situation is judged acceptable, however, because specified acceptable 

fuel damage limits are still met. The risk of experiencing a stuck CEA and 

subsequent criticality is reduced during this PHYSICS TEST exception by 

the requirements to determine CEA positions every 2 hours; by the trip of 

each CEA to be withdrawn within 24 hours prior to suspending the SDM; 

and by ensuring that shutdown reactivity is available, equivalent to the 

reactivity worth of the estimated highest worth withdrawn CEA (Ref. 5). 

PHYSICS TESTS include measurement of core parameters or exercise of 

control components that affect process variables. Among the process 

variables involved are total planar radial peaking factor, total integrated 

radial peaking factor, TQ, and ASI, which represent initial condition input 

(power peaking) to the accident analysis. Also involved are the shutdown 

and regulating CEAs, which affect power peaking and are required for 

shutdown of the reactor. The limits for these variables are specified for 

each fuel cycle in the COLR. 

As described in LCO 3.0.7, compliance with Special Test Exception LCOs 

is optional, and therefore no criteria of 10 CFR 50.36(c)(2)(ii) apply. 

Special Test Exception LCOs provide flexibility to perform certain 

operations by appropriately modifying requirements of other LCOs. A 

discussion of the criteria satisfied for the other LCOs is provided in their 

respective Bases. 
STE - SDM (Digital) 

B 3.1.8 

CEOG STS B 3.1.8-4 Rev. 3.0, 03/31/04 

BASES 

LCO This LCO provides that a minimum amount of CEA worth is immediately 

available for reactivity control when CEA worth measurement tests are 

performed. This STE is required to permit the periodic verification of the 

actual versus predicted worth of the regulating and shutdown CEAs. The 

SDM requirements of LCO 3.1.1, the shutdown CEA insertion limits of 

LCO 3.1.5, and the regulating CEA insertion limits of LCO 3.1.6 may be 

suspended. 

APPLICABILITY This LCO is applicable in MODES 2 and 3. Although CEA worth testing is 

conducted in MODE 2, sufficient negative reactivity is inserted during the 

performance of these tests to result in temporary entry into MODE 3. 

Because the intent is to immediately return to MODE 2 to continue CEA 

worth measurements, the STE allows limited operation to 6 consecutive 

hours in MODE 3 as indicated by the Note, without having to borate to 

meet the SDM requirements of LCO 3.1.1. 

ACTIONS A.1

With any CEA not fully inserted and less than the minimum required 

reactivity equivalent available for insertion, or with all CEAs inserted and 

the reactor subcritical by less than the reactivity equivalent of the highest 

worth withdrawn CEA, restoration of the minimum SDM requirements 

must be accomplished by increasing the RCS boron concentration. The 

required Completion Time of 15 minutes for initiating boration allows the 

operator sufficient time to align the valves and start the boric acid pumps 

and is consistent with the Completion Time of LCO 3.1.1. 

SURVEILLANCE SR 3.1.8.1

REQUIREMENTS 

Verification of the position of each partially or fully withdrawn full length or 

part length CEA is necessary to ensure that the minimum negative 

reactivity requirements for insertion on a trip are preserved. A 2 hour 

Frequency is sufficient for the operator to verify that each CEA position is 

within the acceptance criteria. 

SR 3.1.8.2

Prior demonstration that each CEA to be withdrawn from the core during 

PHYSICS TESTS is capable of full insertion, when tripped from at least a 

50% withdrawn position, ensures that the CEA will insert on a trip signal. 

The Frequency ensures that the CEAs are OPERABLE prior to reducing 

SDM to less than the limits of LCO 3.1.1. 
STE - SDM (Digital) 

B 3.1.8 

CEOG STS B 3.1.8-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The SR is modified by a Note which allows the SR to not be performed 

during initial power escalation following a refueling outage if SR 3.1.4.5 

has been met during that refueling outage. This allows the CEA drop 

time test, which also proves the CEAs are trippable, to be credited for this 

SR. 

REFERENCES 1. 10 CFR 50, Appendix B, Section XI. 

 2. 10 CFR 50.59. 

 3. Regulatory Guide 1.68, Revision 2, August 1978. 

 4. ANSI/ANS-19.6.1-1985, December 13, 1985. 

 5. FSAR, Chapter 14. 

 6. 10 CFR 50.46. 

 7. FSAR, Chapter 15. 
STE - MODES 1 and 2 (Digital) 

B 3.1.9 

CEOG STS B 3.1.9-1 Rev. 3.0, 03/31/04 

B 3.1 REACTIVITY CONTROL SYSTEMS 

B 3.1.9 Special Test Exceptions (STE) - MODES 1 and 2 (Digital) 

BASES 

BACKGROUND The primary purpose of these MODES 1 and 2 Special Test Exceptions 

(STE) is to permit relaxation of existing LCOs to allow the performance of 

certain PHYSICS TESTS. These tests are conducted to determine 

specific reactor core characteristics. 

Section XI of 10 CFR 50, Appendix B, "Quality Assurance Criteria for 

Nuclear Power Plants and Fuel Processing Plants" (Ref. 1), requires that 

a test program be established to ensure that structures, systems, and 

components will perform satisfactorily in service. All functions necessary 

to ensure that specified design conditions are not exceeded during 

normal operation and anticipated operational occurrences must be tested. 

Testing is required as an integral part of the design, fabrication, 

construction, and operation of the power plant. Requirements for 

notification of the NRC, for the purpose of conducting tests and 

experiments, are specified in 10 CFR 50.59, "Changes, Tests, and 

Experiments" (Ref. 2). 

The key objectives of a test program are to (Ref. 3): 

a. Ensure that the facility has been adequately designed, 

b. Validate the analytical models used in design and analysis, 

c. Verify assumptions used for predicting plant response, 

d. Ensure that installation of equipment in the facility has been 

accomplished in accordance with design, and 

e. Verify that operating and emergency procedures are adequate. 

To accomplish these objectives, testing is required prior to initial criticality, 

after each refueling shutdown, and during startup, low power operation, 

power ascension, and at power operation. The PHYSICS TESTS 

requirements for reload fuel cycles ensure that the operating 

characteristics of the core are consistent with the design predictions and 

that the core can be operated as designed (Ref. 4). 

PHYSICS TESTS procedures are written and approved in accordance 

with established formats. The procedures include all information 

necessary to permit a detailed execution of testing required to ensure that 

design intent is met. PHYSICS TESTS are performed in accordance with 

these procedures and test results are approved prior to continued power 

escalation and long term power operation. 
STE - MODES 1 and 2 (Digital) 

B 3.1.9 

CEOG STS B 3.1.9-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Examples of PHYSICS TESTS include determination of critical boron 

concentration, CEA group worths, reactivity coefficients, flux symmetry, 

and core power distribution. 

APPLICABLE It is acceptable to suspend certain LCOs for PHYSICS TESTS because 

SAFETY fuel damage criteria are not exceeded. Even if an accident occurs during 

ANALYSES PHYSICS TESTS with one or more LCOs suspended, fuel damage 

criteria are preserved because the limits on power distribution and 

shutdown capability are maintained during PHYSICS TESTS. 

Reference 5 defines requirements for initial testing of the facility, including 

PHYSICS TESTS. Requirements for reload fuel cycle PHYSICS TESTS 

are defined in ANSI/ANS-19.6.1-1985 (Ref. 4). Although these PHYSICS 

TESTS are generally accomplished within the limits of all LCOs, 

conditions may occur when one or more LCOs must be suspended to 

make completion of PHYSICS TESTS possible or practical. This is 

acceptable as long as the fuel design criteria are not violated. As long as 

the linear heat rate (LHR) remains within its limit, fuel design criteria are 

preserved. 

In this test, the following LCOs are suspended: 

LCO 3.1.3, "Moderator Temperature Coefficient (MTC)," 

LCO 3.1.4, "Control Element Assembly (CEA) Alignment," 

LCO 3.1.5, "Shutdown Control Element Assembly (CEA) Insertion 

Limits," 

LCO 3.1.6, "Regulating Control Element Assembly (CEA) Insertion 

Limits," 

LCO 3.1.7, "Part Length Control Element Assembly (CEA) Insertion 

Limits," 

LCO 3.2.2, "Planar Radial Peaking Factors," and 

LCO 3.2.3, "AZIMUTHAL POWER TILT (Tq)." 

The safety analysis (Ref. 6) places limits on allowable THERMAL 

POWER during PHYSICS TESTS and requires that the LHR and the 

departure from nucleate boiling (DNB) parameter be maintained within 

limits. The power plateau of < 85% RTP and the associated trip setpoints 

are required to ensure [explain]. 

The individual LCOs governing CEA group height, insertion and 

alignment, ASI, total planar radial peaking factor, total integrated radial 

peaking factor, and Tq, preserve the LHR limits. Additionally, the LCOs 

governing Reactor Coolant System (RCS) flow, reactor inlet temperature 

(Tc), and pressurizer pressure contribute to maintaining DNB parameter 
STE - MODES 1 and 2 (Digital) 

B 3.1.9 

CEOG STS B 3.1.9-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

limits. The initial condition criteria for accidents sensitive to core power 

distribution are preserved by the LHR and DNB parameter limits. The 

criteria for the loss of coolant accident (LOCA) are specified in 

10 CFR 50.46, "Acceptance Criteria for Emergency Core Cooling 

Systems for Light Water Nuclear Power Reactors" (Ref. 7). The criteria 

for the loss of forced reactor coolant flow accident are specified in 

Reference 7. Operation within the LHR limit preserves the LOCA criteria; 

operation within the DNB parameter limits preserves the loss of flow 

criteria. 

During PHYSICS TESTS, one or more of the LCOs that normally 

preserve the LHR and DNB parameter limits may be suspended. The 

results of the accident analysis are not adversely impacted, however, if 

LHR and DNB parameters are verified to be within their limits while the 

LCOs are suspended. Therefore, SRs are placed as necessary to ensure 

that LHR and DNB parameters remain within limits during PHYSICS 

TESTS. Performance of these Surveillances allows PHYSICS TESTS to 

be conducted without decreasing the margin of safety. 

PHYSICS TESTS include measurement of core parameters or exercise of 

control components that affect process variables. Among the process 

variables involved are total planar radial peaking factor, total integrated 

radial peaking factor, TQ, and ASI, which represent initial condition input 

(power peaking) to the accident analysis. Also involved are the shutdown 

and regulating CEAs, which affect power peaking and are required for 

shutdown of the reactor. The limits for these variables are specified for 

each fuel cycle in the COLR. 

As described in LCO 3.0.7, compliance with Special Test Exception LCOs 

is optional, and therefore no criteria of 10 CFR 50.36(c)(2)(ii) apply. 

Special Test Exception LCOs provide flexibility to perform certain 

operations by appropriately modifying requirements of other LCOs. A 

discussion of the criteria satisfied for the other LCOs is provided in their 

respective Bases. 

LCO This LCO permits individual CEAs to be positioned outside of their normal 

group heights and insertion limits during the performance of PHYSICS 

TESTS, such as those required to: 

a. Measure CEA worth, 

b. Determine the reactor stability index and damping factor under xenon 

oscillation conditions, 

c. Determine power distributions for nonnormal CEA configurations, 
STE - MODES 1 and 2 (Digital) 

B 3.1.9 

CEOG STS B 3.1.9-4 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

d. Measure rod shadowing factors, and 

e. Measure temperature and power coefficients. 

Additionally, it permits the center CEA to be misaligned during PHYSICS 

TESTS required to determine the isothermal temperature coefficient 

(ITC), MTC, and power coefficient. 

The requirements of LCO 3.1.3, LCO 3.1.4, LCO 3.1.5, LCO 3.1.6, 

LCO 3.1.7, LCO 3.2.2, and LCO 3.2.3 may be suspended during the 

performance of PHYSICS TESTS provided THERMAL POWER is 

restricted to test power plateau, which shall not exceed 85% RTP. 

APPLICABILITY This LCO is applicable in MODES 1 and 2 because the reactor must be 

critical at various THERMAL POWER levels to perform the PHYSICS 

TESTS described in the LCO section. Limiting the test power plateau to 

< 85% RTP ensures that LHRs are maintained within acceptable limits. 

ACTIONS A.1

If THERMAL POWER exceeds the test power plateau in MODE 1, 

THERMAL POWER must be reduced to restore the additional thermal 

margin provided by the reduction. The 15 minute Completion Time 

ensures that prompt action shall be taken to reduce THERMAL POWER 

to within acceptable limits. 

B.1 and B.2

If Required Action A.1 cannot be completed within the required 

Completion Time, PHYSICS TESTS must be suspended within 1 hour. 

Allowing 1 hour for suspending PHYSICS TESTS allows the operator 

sufficient time to change any abnormal CEA configuration back to within 

the limits of LCO 3.1.4, LCO 3.1.5, and LCO 3.1.6. 

Suspension of PHYSICS TESTS exceptions requires restoration of each 

of the applicable LCOs to within specification. 
STE - MODES 1 and 2 (Digital) 

B 3.1.9 

CEOG STS B 3.1.9-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.1.9.1

REQUIREMENTS 

Verifying that THERMAL POWER is equal to or less than that allowed by 

the test power plateau, as specified in the PHYSICS TEST procedure and 

required by the safety analysis, ensures that adequate LHR and 

departure from nucleate boiling ratio margins are maintained while LCOs 

are suspended. The 1 hour Frequency is sufficient, based upon the slow 

rate of power change and increased operational controls in place during 

PHYSICS TESTS. Monitoring LHR ensures that the limits are not 

exceeded. 

REFERENCES 1. 10 CFR 50, Appendix B, Section XI. 

 2. 10 CFR 50.59. 

 3. Regulatory Guide 1.68, Revision 2, August 1978. 

 4. ANSI/ANS-19.6.1-1985, December 13, 1985. 

 5. FSAR, Chapter [14]. 

 6. FSAR, Section [15.3.2.1]. 

 7. 10 CFR 50.46. 
LHR (Analog) 

B 3.2.1 

CEOG STS B 3.2.1-1 Rev. 3.0, 03/31/04 

B 3.2 POWER DISTRIBUTION LIMITS 

B 3.2.1 Linear Heat Rate (LHR) (Analog) 

BASES 

BACKGROUND The purpose of this LCO is to limit the core power distribution to the initial 

values assumed in the accident analyses. Operation within the limits 

imposed by this LCO either limits or prevents potential fuel cladding 

failures that could breach the primary fission product barrier and release 

fission products to the reactor coolant in the event of a loss of coolant 

accident (LOCA), loss of flow accident, ejected control element assembly 

(CEA) accident, or other postulated accident requiring termination by a 

Reactor Protection System trip function. This LCO limits the amount of 

damage to the fuel cladding during an accident by ensuring that the plant 

is operating within acceptable bounding conditions at the onset of a 

transient. 

Methods of controlling the power distribution include: 

a. Using CEAs to alter the axial power distribution, 

b. Decreasing CEA insertion by boration, thereby improving the radial 

power distribution, and 

c. Correcting off optimum conditions (e.g., a CEA drop or misoperation 

of the unit) that cause margin degradations. 

The core power distribution is controlled so that, in conjunction with other 

core operating parameters (e.g., CEA insertion and alignment limits), the 

power distribution satisfies this LCO. The limiting safety system settings 

and this LCO are based on the accident analyses (Refs. 1 and 2), so that 

specified acceptable fuel design limits are not exceeded as a result of 

anticipated operational occurrences (AOOs), and the limits of acceptable 

consequences are not exceeded for other postulated accidents. 

Limiting power distribution skewing over time also minimizes the xenon 

distribution skewing, which is a significant factor in controlling the axial 

power distribution. 

Power distribution is a product of multiple parameters, various 

combinations of which may produce acceptable power distributions. 

Operation within the design limits of power distribution is accomplished by 

generating operating limits on linear heat rate (LHR) and departure from 

nucleate boiling (DNB). 
LHR (Analog) 

B 3.2.1 

CEOG STS B 3.2.1-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The limits on LHR, Total Planar Radial Peaking Factor ( T FXY ), Total 

Integrated Radial Peaking Factor (FT

r), Tq, and ASI represent limits within 

which the LHR algorithms are valid. These limits are obtained directly 

from the core reload analysis. 

Either of the two core power distribution monitoring systems, the Excore 

Detector Monitoring System or the Incore Detector Monitoring System, 

provides adequate monitoring of the core power distribution and is 

capable of verifying that the LHR is within its limits. The Excore Detector 

Monitoring System performs this function by continuously monitoring ASI 

with the OPERABLE quadrant symmetric excore neutron flux detectors 

and verifying that the ASI is maintained within the allowable limits 

specified in the COLR. 

In conjunction with the use of the Excore Detector Monitoring System and 

in establishing ASI limits, the following assumptions are made: 

a. The CEA insertion limits of LCO 3.1.5, "Shutdown CEA Insertion 

Limits," and LCO 3.1.6, "Regulating CEA Insertion Limits," are 

satisfied, 

b. The Tq restrictions of LCO 3.2.4 are satisfied, and 

c. FT

xy is within the limits of LCO 3.2.2. 

The Incore Detector Monitoring System continuously provides a more 

direct measure of the peaking factors and alarms that have been 

established for the individual incore detector segments, ensuring that the 

peak LHRs are maintained within the limits specified in the COLR. The 

setpoints for these alarms include tolerances, set in conservative 

directions, for: 

a. A measurement calculational uncertainty factor of 1.062, 

b. An engineering uncertainty factor of 1.03, 

c. An allowance of 1.002 for axial fuel densification and thermal 

expansion, and 

d. A THERMAL POWER measurement uncertainty factor of 1.02. 
LHR (Analog) 

B 3.2.1 

CEOG STS B 3.2.1-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation (Condition 1) and AOOs (Condition 2) (Ref. 3, GDC 10). The 

ANALYSES power distribution and CEA insertion and alignment LCOs preclude core 

power distributions that violate the following fuel design criteria: 

a. During a LOCA, peak cladding temperature must not exceed 2200°F 

(Ref. 4), 

b. During a loss of flow accident, there must be at least 95% probability 

at the 95% confidence level (the 95/95 DNB criterion) that the hot fuel 

rod in the core does not experience a DNB condition (Ref. 3, 

GDC 10), 

c. During an ejected CEA accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. [ ]), and 

d. The control rods must be capable of shutting down the reactor with a 

minimum required SDM with the highest worth control rod stuck fully 

withdrawn (Ref. 3, GDC 26). 

The power density at any point in the core must be limited to maintain the 

fuel design criteria (Ref. 4). This is accomplished by maintaining the 

power distribution and reactor coolant conditions so that the peak LHR 

and DNB parameters are within operating limits supported by accident 

analyses (Ref. 1), with due regard for the correlations between measured 

quantities, the power distribution, and uncertainties in determining the 

power distribution. 

Fuel cladding failure during a LOCA is limited by restricting the maximum 

linear heat generation rate so that the peak cladding temperature does 

not exceed 2200°F (Ref. 4). High peak cladding temperatures are 

assumed to cause severe cladding failure by oxidation due to a Zircaloy 

water reaction. 

The LCOs governing LHR, ASI, and the Reactor Coolant System ensure 

that these criteria are met as long as the core is operated within the ASI, 

T FXY , T Fr , and Tq limits specified in the COLR. The latter are process 

variables that characterize the three dimensional power distribution of the 

reactor core. Operation within the limits for these variables ensures that 

their actual values are within the ranges used in the accident analyses. 
LHR (Analog) 

B 3.2.1 

CEOG STS B 3.2.1-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Fuel cladding damage does not normally occur while the unit is operating 

at conditions outside the limits of these LCOs during normal operation. 

Fuel cladding damage could result, however, if an accident or AOO 

occurs from initial conditions outside the limits of these LCOs. The 

potential for fuel cladding damage exists because changes in the power 

distribution can cause increased power peaking and can correspondingly 

increase local LHR. 

The LHR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The power distribution LCO limits are based on correlations between 

power peaking and certain measured variables used as inputs to the LHR 

and DNB ratio operating limits. The power distribution LCO limits, except 

Tq, are provided in the COLR. The limitation on the LHR ensures that, in 

the event of a LOCA, the peak temperature of the fuel cladding does not 

exceed 2200°F. 

APPLICABILITY In MODE 1, power distribution must be maintained within the limits 

assumed in the accident analysis to ensure that fuel damage does not 

result following an AOO. In other MODES, this LCO does not apply 

because there is not sufficient THERMAL POWER to require a limit on 

the core power distribution. 

ACTIONS A.1

With the LHR exceeding its limit, excessive fuel damage could occur 

following an accident. In this Condition, prompt action must be taken to 

restore the LHR to within the specified limits. One hour to restore the 

LHR to within its specified limits is reasonable and ensures that the core 

does not continue to operate in this Condition. The 1 hour Completion 

Time also allows the operator sufficient time for evaluating core 

conditions and for initiating proper corrective actions. 

B.1

If the LHR cannot be returned to within its specified limits, THERMAL 

POWER must be reduced. The change to MODE 2 provides reasonable 

assurance that the core is operating within its thermal limits and places 

the core in a conservative condition. The allowed Completion Time of 

6 hours is reasonable, based on operating experience, to reach MODE 2 

from full power MODE 1 conditions in an orderly manner and without 

challenging plant systems. 
LHR (Analog) 

B 3.2.1 

CEOG STS B 3.2.1-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE A Note was added to the SRs to require LHR to be determined by 

REQUIREMENTS either the Excore Detector Monitoring System or the Incore Detector 

Monitoring System. 

SR 3.2.1.1

Performance of this SR verifies that the Excore Detector Monitoring 

System can accurately monitor the LHR. Therefore, this SR is only 

applicable when the Excore Detector Monitoring System is being used to 

determine the LHR. The 31 day Frequency is appropriate for this SR 

because it is consistent with the requirements of SR 3.3.1.3 for calibration 

of the excore detectors using the incore detectors. 

The SR is modified by a Note that states that the SR is only required to 

be met when the Excore Detection Monitoring System is being used to 

determine LHR. The reason for the Note is that the excore detectors 

input neutron flux information into the ASI calculation. 

SR 3.2.1.2 and SR 3.2.1.3

Continuous monitoring of the LHR is provided by the Incore Detector 

Monitoring System and the Excore Detector Monitoring System. Either of 

these two core power distribution monitoring systems provides adequate 

monitoring of the core power distribution and is capable of verifying that 

the LHR does not exceed its specified limits. 

Performance of these SRs verifies that the Incore Detector Monitoring 

System can accurately monitor LHR. Therefore, they are only applicable 

when the Incore Detector Monitoring System is being used to determine 

the LHR. 

A 31 day Frequency is consistent with the historical testing frequency of 

the reactor monitoring system. The SRs are modified by two Notes. 

Note 1 allows the SRs to be met only when the Incore Detector 

Monitoring System is being used to determine LHR. Note 2 states that 

the SRs are not required to be performed when THERMAL POWER is 

< 20% RTP. The accuracy of the neutron flux information from the incore 

detectors is not reliable at THERMAL POWER < 20% RTP. 
LHR (Analog) 

B 3.2.1 

CEOG STS B 3.2.1-6 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Chapter [15]. 

 2. FSAR, Chapter [6]. 

 3. 10 CFR 50, Appendix A. 

 4. 10 CFR 50.46. 
LHR (Digital) 

B 3.2.1 

CEOG STS B 3.2.1-1 Rev. 3.0, 03/31/04 

B 3.2 POWER DISTRIBUTION LIMITS 

B 3.2.1 Linear Heat Rate (LHR) (Digital) 

BASES 

BACKGROUND The purpose of this LCO is to limit the core power distribution to the initial 

values assumed in the accident analyses. Operation within the limits 

imposed by this LCO limits or prevents potential fuel cladding failures that 

could breach the primary fission product barrier and release fission 

products to the reactor coolant in the event of a loss of coolant accident 

(LOCA), loss of flow accident, ejected control element assembly (CEA) 

accident, or other postulated accident requiring termination by a Reactor 

Protection System (RPS) trip function. This LCO limits the damage to the 

fuel cladding during an accident by ensuring that the plant is operating 

within acceptable bounding conditions at the onset of a transient. 

Methods of controlling the power distribution include: 

a. Using full or part length CEAs to alter the axial power distribution, 

b. Decreasing CEA insertion by boration, thereby improving the radial 

power distribution, and 

c. Correcting off optimum conditions (e.g., a CEA drop or misoperation 

of the unit) that cause margin degradations. 

The core power distribution is controlled so that, in conjunction with other 

core operating parameters (e.g., CEA insertion and alignment limits), the 

power distribution does not result in violation of this LCO. The limiting 

safety system settings and this LCO are based on the accident analyses 

(Refs. 1 and 2), so that specified acceptable fuel design limits are not 

exceeded as a result of anticipated operational occurrences (AOOs), and 

the limits of acceptable consequences are not exceeded for other 

postulated accidents. 

Limiting power distribution skewing over time also minimizes xenon 

distribution skewing, which is a significant factor in controlling the axial 

power distribution. 

Power distribution is a product of multiple parameters, various 

combinations of which may produce acceptable power distributions. 

Operation within the design limits of power distribution is accomplished by 

generating operating limits on the LHR and departure from nucleate 

boiling (DNB). 
LHR (Digital) 

B 3.2.1 

CEOG STS B 3.2.1-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Proximity to the DNB condition is expressed by the departure from 

nucleate boiling ratio (DNBR), defined as the ratio of the cladding surface 

heat flux required to cause DNB to the actual cladding surface heat flux. 

The minimum DNBR value during both normal operation and AOOs is 

calculated by the CE-1 Correlation (Ref. 3) and corrected for such factors 

as rod bow and grid spacers. It is accepted as an appropriate margin to 

DNB for all operating conditions. 

There are two systems that monitor core power distribution online: the 

Core Operating Limit Supervisory System (COLSS) and the core 

protection calculators (CPCs). The COLSS and CPCs that monitor the 

core power distribution are capable of verifying that the LHR and the 

DNBR do not exceed their limits. The COLSS performs this function by 

continuously monitoring the core power distribution and calculating core 

power operating limits corresponding to the allowable peak LHR and 

DNBR. The CPCs perform this function by continuously calculating an 

actual value of DNBR and local power density (LPD) for comparison with 

the respective trip setpoints. 

A DNBR penalty factor is included in both the COLSS and CPC DNBR 

calculations to accommodate the effects of rod bow. The amount of rod 

bow in each assembly is dependent upon the average burnup 

experienced by that assembly. Fuel assemblies that incur higher than 

average burnup experience a greater magnitude of rod bow. Conversely, 

fuel assemblies that receive lower than average burnup experience less 

rod bow. In design calculations for a reload core, each batch of fuel is 

assigned a penalty applied to the maximum integrated planar radial 

power peak of the batch. This penalty is correlated with the amount of 

rod bow determined from the maximum average assembly burnup of the 

batch. A single net penalty for the COLSS and CPCs is then determined 

from the penalties associated with each batch that comprises a core 

reload, accounting for the offsetting margins due to the lower radial power 

peaks in the higher burnup batches. 

The COLSS indicates continuously to the operator how far the core is 

from the operating limits and provides an audible alarm if an operating 

limit is exceeded. Such a condition signifies a reduction in the capability 

of the plant to withstand an anticipated transient, but does not necessarily 

imply an immediate violation of fuel design limits. If the margin to fuel 

design limits continues to decrease, the RPS ensures that the specified 

acceptable fuel design limits are not exceeded during AOOs by initiating 

reactor trips. 
LHR (Digital) 

B 3.2.1 

CEOG STS B 3.2.1-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The COLSS continually generates an assessment of the calculated 

margin for specified LHR and DNBR limits. The data required for these 

assessments include measured incore neutron flux, CEA positions, and 

Reactor Coolant System (RCS) inlet temperature, pressure, and flow. 

In addition to the monitoring performed by the COLSS, the RPS (via the 

CPCs) continually infers the core power distribution and thermal margins 

by processing reactor coolant data, signals from excore neutron flux 

detectors, and input from redundant reed switch assemblies that indicate 

CEA positions. In this case, the CPCs assume a minimum core power of 

20% RTP because the power range excore neutron flux detecting system 

is inaccurate below this power level. If power distribution or other 

parameters are perturbed as a result of an AOO, the high LPD or low 

DNBR trips in the RPS initiate a reactor trip prior to the exceeding of fuel 

design limits. 

The LHR and DNBR algorithms are valid within the limits on ASI, Fxy and 

TQ. These limits are obtained directly from initial core or reload analysis. 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation or AOOs (Ref. 4). 

ANALYSES 

The power distribution and CEA insertion and alignment LCOs prevent 

core power distributions from reaching levels that violate the following fuel 

design criteria: 

a. During a LOCA, peak cladding temperature must not exceed 2200°F 

(Ref. 5), 

b. During a loss of flow accident, there must be at least 95% probability 

at the 95% confidence level (the 95/95 DNB criterion) that the hot fuel 

rod in the core does not experience a DNB condition (Ref. 4), 

c. During an ejected CEA accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. [ ]), and 

d. The control rods must be capable of shutting down the reactor with a 

minimum required SDM with the highest worth control rod stuck fully 

withdrawn (GDC 26, Ref. [ ]). 
LHR (Digital) 

B 3.2.1 

CEOG STS B 3.2.1-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The power density at any point in the core must be limited to maintain the 

fuel design criteria (Refs. 4 and 5). This is accomplished by maintaining 

the power distribution and reactor coolant conditions so that the peak 

LHR and DNB parameters are within operating limits supported by the 

accident analyses (Ref. 1) with due regard for the correlations between 

measured quantities, the power distribution, and uncertainties in 

determining the power distribution. 

Fuel cladding failure during a LOCA is limited by restricting the maximum 

linear heat generation rate so that the peak cladding temperature does 

not exceed 2200°F (Ref. 5). Peak cladding temperatures exceeding 

2200°F cause severe cladding failure by oxidation due to a Zircaloy water 

reaction. 

The LCOs governing the LHR, ASI, and RCS ensure that these criteria 

are met as long as the core is operated within the ASI and Fxy limits 

specified in the COLR, and within the TQ limits. The latter are process 

variables that characterize the three dimensional power distribution of the 

reactor core. 

Operation within the limits for these variables ensures that their actual 

values are within the ranges used in the accident analyses. 

Fuel cladding damage does not normally occur from conditions outside 

the limits of these LCOs during normal operation. However, fuel cladding 

damage could result if an accident or AOO occurs from initial conditions 

outside the limits of these LCOs. This potential for fuel cladding damage 

exists because changes in the power distribution can cause increased 

power peaking and can correspondingly increase local LHR. 

The LHR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The power distribution LCO limits are based on correlations between 

power peaking and certain measured variables used as inputs to the LHR 

and DNBR operating limits. The power distribution LCO limits are 

provided in the COLR. The limitation on LHR ensures that in the event of 

a LOCA the peak temperature of the fuel cladding does not exceed 

2200°F. 
LHR (Digital) 

B 3.2.1 

CEOG STS B 3.2.1-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY Power distribution is a concern any time the reactor is critical. The power 

distribution LCOs, however, are only applicable in MODE 1 above 

20% RTP. The reasons these LCOs are not applicable below 20% RTP 

are: 

a. The incore neutron detectors that provide input to the COLSS, which 

then calculates the operating limits, are inaccurate due to the poor 

signal to noise ratios at relatively low core power levels and 

b. As a result of this inaccuracy, the CPCs assume minimum core 

power of 20% RTP when generating LPD and DNBR trip signals. 

When core power is below 20% RTP, the core is operating well 

below its thermal limits and the resultant CPC calculated LPD and 

DNBR trips are highly conservative. 

ACTIONS A.1

Operation at or below the COLSS calculated power limit based on the 

LHR ensures that the LHR limit is not exceeded. If the COLSS calculated 

core power limit based on the LHR exceeds the operating limit, restoring 

the LHR to within limit in 1 hour ensures that prompt action is taken to 

reduce LHR to below the specified limit. One hour is a reasonable time to 

return LHR to within limits when the limit is exceeded without a trip due to 

events such as a dropped CEA or an axial xenon oscillation. 

B.1, B.2.1, and B.2.2

If the COLSS is not available the OPERABLE LPD channels are 

monitored to ensure that the LHR limit is not exceeded. Operation within 

this limit ensures that in the event of a LOCA the fuel cladding 

temperature does not exceed 2200°F. Four hours is allowed for restoring 

the LHR limit to within the region of acceptable operation. This duration is 

reasonable because the COLSS allows the plant to operate with less LHR 

margin (closer to the LHR limit than when monitoring the CPCs). 

When operating with the COLSS out of service there is a possibility of a 

slow undetectable transient that degrades the LHR slowly over the 4 hour 

period and is then followed by an AOO or an accident. To remedy this, 

the CPC calculated values of LHR are monitored every 15 minutes when 

the COLSS is out of service. The 15 minute Frequency is adequate to 

allow the operator to identify an adverse trend in conditions that could 

result in an approach to the LHR limit. Also, a maximum allowable 
LHR (Digital) 

B 3.2.1 

CEOG STS B 3.2.1-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

change in the CPC calculated LHR ensures that further degradation 

requires the operators to take immediate action to restore LHR to within 

limits or reduce reactor power to comply with the Technical Specifications 

(TS). With an adverse trend, 1 hour is allowed for restoring LHR to within 

limits if the COLSS is not restored to OPERABLE status. Implementation 

of this requirement ensures that reductions in core thermal margin are 

quickly detected, and if necessary, results in a decrease in reactor power 

and subsequent compliance with the existing COLSS out of service TS 

limits. 

With no adverse trend, 4 hours is allowed to restore the LHR to within 

limits if the COLSS is not restored to OPERABLE status. This duration is 

reasonable because the Frequency of the CPC determination of LHR is 

increased and if operation is maintained steady, the likelihood of 

exceeding the LHR limit during this period is not increased. The 

likelihood of induced reactor transients from an early power reduction is 

also decreased. 

C.1

If the LHR cannot be returned to within its limit or the LHR cannot be 

determined because of the COLSS and CPC inoperability, core power 

must be reduced. Reduction of core power to < 20% RTP ensures that 

the core is operating within its thermal limits and places the core in a 

conservative condition based on the trip setpoints generated by the 

CPCs, which assume a minimum core power of 20% RTP. The allowed 

Completion Time of 6 hours is reasonable, based on operating 

experience, to reach 20% RTP in an orderly manner and without 

challenging plant systems. 

SURVEILLANCE SR 3.2.1.1

REQUIREMENTS 

With the COLSS out of service, the operator must monitor the LHR with 

each OPERABLE local power density channel. A 2 hour Frequency is 

sufficient to allow the operator to identify trends that would result in an 

approach to the LHR limits. 

This SR is modified by a Note that states that the SR is only required to 

be met when the COLSS is out of service. Continuous monitoring of the 

LHR is provided by the COLSS, which calculates core power and core 

power operating limits based on the LHR and continuously displays these 

limits to the operator. A COLSS margin alarm is annunciated in the event 

that the THERMAL POWER exceeds the core power operating limit 

based on LHR. 
LHR (Digital) 

B 3.2.1 

CEOG STS B 3.2.1-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.2.1.2

Verification that the COLSS margin alarm actuates at a THERMAL 

POWER level equal to or less than the core power operating limit based 

on the LHR in units of kilowatts per foot ensures the operator is alerted 

when conditions approach the LHR operating limit. 

The 31 day Frequency for performance of this SR is consistent with the 

historical testing frequency of reactor protection and monitoring systems. 

The Surveillance Frequency for testing protection systems was extended 

to 92 days by CEN 327. Monitoring systems were not addressed in 

CEN 327; therefore, this Frequency remains at 31 days. 

REFERENCES 1. FSAR, Section [15]. 

 2. FSAR, Section [6]. 

 3. CE-1 Correlation for DNBR. 

 4. 10 CFR 50.46, Appendix A, GDC 10. 

 5. 10 CFR 50.46. 
FT

XY (Analog) 

 B 3.2.2 

CEOG STS B 3.2.2-1 Rev. 3.0, 03/31/04 

B 3.2 POWER DISTRIBUTION LIMITS 

B 3.2.2 Total Planar Radial Peaking Factor (FT

XY) (Analog) 

BASES 

BACKGROUND The purpose of this LCO (Total Planar Radial Peaking Factor ( T FXY )) is to 

limit the core power distribution to the initial values assumed in the 

accident analyses. Operation within the limits imposed by this LCO 

decreases or prevents potential fuel cladding failures that could breach 

the primary fission product barrier and release fission products to the 

reactor coolant in the event of a loss of coolant accident (LOCA), loss of 

flow accident, ejected control element assembly (CEA) accident, or other 

postulated accident requiring termination by a Reactor Protection System 

trip function. This LCO limits damage to the fuel cladding during an 

accident by ensuring that the plant is operating within acceptable 

bounding conditions at the onset of a transient. 

Methods of controlling the power distribution include: 

a. Using CEAs to alter the axial power distribution, 

b. Decreasing CEA insertion by boration, thereby improving the radial 

power distribution, and 

c. Correcting off optimum conditions (e.g., a CEA drop or misoperation 

of the unit) that cause margin degradations. 

The core power distribution is controlled so that, in conjunction with other 

core operating parameters (e.g., CEA insertion and alignment limits), the 

power distribution does not result in violation of this LCO. The limiting 

safety system settings (LSSS) and this LCO are based on accident 

analyses (Refs. 1 and 2), so that specified acceptable fuel design limits 

are not exceeded as a result of anticipated operational occurrences 

(AOOs) and the limits of acceptable consequences are not exceeded for 

other postulated accidents. 

Limiting power distribution skewing over time also minimizes the xenon 

distribution skewing, which is a significant factor in controlling the axial 

power distribution. 

Power distribution is a product of multiple parameters, various 

combinations of which may produce acceptable power distributions. 

Operation within the design limits of power distribution is accomplished by 

generating operating limits on the linear heat rate (LHR) and departure 

from nucleate boiling (DNB). 
FT

XY (Analog) 

 B 3.2.2 

CEOG STS B 3.2.2-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The limits on LHR, T FXY , Total Integrated Radial Peaking Factor ( T Fr ), Tq, 

and ASI represent limits within which the LHR algorithms are valid. 

These limits are obtained directly from the core reload analysis. 

Either of the two core power distribution monitoring systems, the Excore 

Detector Monitoring System or the Incore Detector Monitoring System, 

provides adequate monitoring of the core power distribution and is 

capable of verifying that the LHR does not exceed its limits. The Excore 

Detector Monitoring System performs this function by continuously 

monitoring the ASI with the OPERABLE quadrant symmetric excore 

neutron flux detectors and verifying that the ASI is maintained within the 

allowable limits specified in the COLR. 

In conjunction with the use of the Excore Detector Monitoring System and 

in establishing the ASI limits, the following assumptions are made: 

a. The CEA insertion limits of LCO 3.1.5, "Shutdown CEA Insertion 

Limits," and LCO 3.1.6, "Regulating CEA Insertion Limits," are 

satisfied, 

b. The Tq restrictions of LCO 3.2.4 are satisfied, and 

c. FT

XY does not exceed the limits of this LCO. 

The Incore Detector Monitoring System continuously provides a more 

direct measure of the peaking factors, and the alarms that have been 

established for the individual incore detector segments ensure that the 

peak LHRs are maintained within the limits specified in the COLR. The 

setpoints for these alarms include tolerances, set in conservative 

directions, for: 

a. A measurement calculational uncertainty factor of 1.062, 

b. An engineering uncertainty factor of 1.03, 

c. An allowance of 1.002 for axial fuel densification and thermal 

expansion, and 

d. A THERMAL POWER measurement uncertainty factor of 1.02. 
FT

XY (Analog) 

 B 3.2.2 

CEOG STS B 3.2.2-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation (Condition 1) or AOOs (Condition 2) (Ref. 3, GDC 10). The 

ANALYSES Power Distribution and CEA Insertion and Alignment LCOs preclude core 

power distributions that violate the following fuel design criteria: 

a. During a LOCA, peak cladding temperature must not exceed 2200°F 

(Ref. 4), 

b. During a loss of flow accident, there must be at least 95% probability 

at the 95% confidence level (the 95/95 DNB criterion) that the hot fuel 

rod in the core does not experience a DNB condition (Ref. 3, 

GDC 10), 

c. During an ejected CEA accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. [ ]), and 

d. The control rods must be capable of shutting down the reactor with a 

minimum required SDM with the highest worth control rod stuck, fully 

withdrawn (Ref. 3, GDC 26). 

The power density at any point in the core must be limited to maintain the 

fuel design criteria (Ref. 4). This limiting is accomplished by maintaining 

the power distribution and reactor coolant conditions such that the peak 

LHR and DNB parameters are within operating limits supported by the 

accident analyses (Ref. 1) with due regard for the correlations between 

measured quantities, the power distribution, and the uncertainties in the 

determination of power distribution. 

Fuel cladding failure during a LOCA is limited by restricting the maximum 

linear heat generation rate so that the peak cladding temperature does 

not exceed 2200°F (Ref. 4). High peak cladding temperatures are 

assumed to cause severe cladding failure by oxidation due to a Zircaloy 

water reaction. 

The LCOs governing LHR, ASI, and the Reactor Coolant System ensure 

that these criteria are met as long as the core is operated within the ASI, 

T FXY , T Fr , and Tq limits specified in the COLR. The latter are process 

variables that characterize the three dimensional power distribution of the 

reactor core. Operation within the limits for these variables ensures that 

their actual values are within the ranges used in the accident analyses. 
FT

XY (Analog) 

 B 3.2.2 

CEOG STS B 3.2.2-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Fuel cladding damage does not normally occur while at conditions outside 

the limits of these LCOs during normal operation. Fuel cladding damage 

could result, however, should an accident or AOO occur from initial 

conditions outside the limits of these LCOs. This potential for fuel 

cladding damage exists because changes in the power distribution can 

cause increased power peaking and correspondingly increased local 

LHR. 

FT

XY satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The power distribution LCO limits are based on correlations between 

power peaking and certain measured variables used as inputs to the LHR 

and DNB ratio operating limits. The power distribution LCO limits, except 

Tq, are provided in the COLR. The limitation on LHR ensures that in the 

event of a LOCA the peak temperature of the fuel cladding does not 

exceed 2200°F. 

APPLICABILITY In MODE 1, power distribution must be maintained within the limits 

assumed in the accident analyses to ensure that fuel damage does not 

result following an AOO. In other MODES, this LCO does not apply 

because there is not sufficient THERMAL POWER to require a limit on 

the core power distribution. 

ACTIONS A.1 and A.2

A Note modifies Condition A to require Required Actions A.1 and A.2 to 

be completed if the Condition is entered. This ensures that corrective 

action is taken prior to unrestricted operation. 

The limitations on FT

XY provided in the COLR ensure that the assumptions 

used in the analysis for establishing the LHR, LCO, and LSSS remain 

valid during operation at the various allowable CEA group insertion limits. 

If T FXY exceeds its basic limitation, operation may continue under the 

additional restrictions imposed by these Required Actions (reducing 

THERMAL POWER and withdrawing CEAs to or beyond the long term 

steady state insertion limits of LCO 3.1.6), because these additional 

restrictions adequately ensure that the assumptions used in establishing 

the LHR, LCO, and LSSS remain valid (Ref. 3). Six hours to return FT

XY

to within its limit is reasonable and ensures that all CEAs meet the long 

term steady state insertion limits of LCO 3.1.6. 
FT

XY (Analog) 

 B 3.2.2 

CEOG STS B 3.2.2-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1

If T Fr cannot be returned to within its limit, THERMAL POWER must be 

reduced. A change to MODE 2 provides reasonable assurance that the 

core is operating within its thermal limits and places the core in a 

conservative condition. The allowed Completion Time of 6 hours is 

reasonable, based on operating experience, to reach MODE 2 from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE SR 3.2.2.1

REQUIREMENTS 

The periodic Surveillance to determine the calculated FT

XY ensures that T FXY remains within the range assumed in the analysis throughout the fuel 

cycle. Determining the measured T FXY after each fuel loading prior to the 

reactor exceeding 70% RTP ensures that the core is properly loaded. 

Performance of the Surveillance every 31 days of accumulated operation 

in MODE 1 provides reasonable assurance that unacceptable changes in 

the FT

XY are promptly detected. 

The power distribution map can only be obtained after THERMAL 

POWER exceeds 20% RTP because the incore detectors are not reliable 

below 20% RTP. 

The SR is modified by a Note that requires that SR 3.2.2.2 and 

SR 3.2.2.3 be completed each time SR 3.2.1.1 is completed. (Values 

computed by these SRs are required to perform SR 3.2.2.1.) The Note 

also requires that the incore detectors be used to determine T FXY by using 

them to obtain a power distribution map with all full length CEAs above 

the long term steady state insertion limits, as specified in the COLR. 

SR 3.2.2.2 and SR 3.2.2.3

Measuring the value of FXY and Tq each time a calculated value of T FXY is 

required ensures that the calculated value of T FXY accurately reflects the 

condition of the core. 
FT

XY (Analog) 

 B 3.2.2 

CEOG STS B 3.2.2-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The Frequency for these Surveillances is in accordance with the 

Frequency requirements of SR 3.2.2.1, because these SRs provide 

information to complete SR 3.2.2.1. 

REFERENCES 1. FSAR, Chapter [15]. 

 2. FSAR, Chapter [6]. 

 3. 10 CFR 50, Appendix A. 

 4. 10 CFR 50.46. 
Fxy (Digital) 

B 3.2.2 

CEOG STS B 3.2.2-1 Rev. 3.0, 03/31/04 

B 3.2 POWER DISTRIBUTION LIMITS 

B 3.2.2 Planar Radial Peaking Factors (Fxy) (Digital) 

BASES 

BACKGROUND The purpose of this LCO is to limit the core power distribution to the initial 

values assumed in the accident analyses. Operation within the limits 

imposed by this LCO either limits or prevents potential fuel cladding 

failures that could breach the primary fission product barrier and release 

fission products to the reactor coolant in the event of a loss of coolant 

accident (LOCA), loss of flow accident, ejected control element assembly 

(CEA) accident, or other postulated accident requiring termination by a 

Reactor Protection System (RPS) trip function. This LCO limits damage 

to the fuel cladding during an accident by ensuring that the plant is 

operating within acceptable conditions at the onset of a transient. 

Methods of controlling the power distribution include: 

a. Using full or part length CEAs to alter the axial power distribution, 

b. Decreasing CEA insertion by boration, thereby improving the radial 

power distribution, and 

c. Correcting off optimum conditions (e.g., a CEA drop or misoperation 

of the unit) that cause margin degradations. 

The core power distribution is controlled so that, in conjunction with other 

core operating parameters (CEA insertion and alignment limits), the 

power distribution does not result in violation of this LCO. Limiting safety 

system settings and this LCO are based on the accident analyses 

(Refs. 1 and 2), so that specified acceptable fuel design limits are not 

exceeded as a result of anticipated operational occurrences (AOOs), and 

the limits of acceptable consequences are not exceeded for other 

postulated accidents. 

Limiting power distribution skewing over time also minimizes xenon 

distribution skewing, which is a significant factor in controlling axial power 

distribution. Power distribution is a product of multiple parameters, 

various combinations of which may produce acceptable power 

distributions. Operation within the design limits of power distribution is 

accomplished by generating operating limits on linear heat rate (LHR) and 

departure from nucleate boiling (DNB). 
Fxy (Digital) 

B 3.2.2 

CEOG STS B 3.2.2-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Proximity to the DNB condition is expressed by the departure from 

nucleate boiling ratio (DNBR), defined as the ratio of the cladding surface 

heat flux required to cause DNB to the actual cladding surface heat flux. 

The minimum DNBR value during both normal operation and AOOs is [ ] 

as calculated by the CE-1 Correlation (Ref. 3) and corrected for such 

factors as rod bow and grid spacers, and it is accepted as an appropriate 

margin to DNB for all operating conditions. 

There are two systems that monitor core power distribution online: the 

Core Operating Limit Supervisory System (COLSS) and the core 

protection calculators (CPCs). The COLSS and CPCs that monitor the 

core power distribution are capable of verifying that the LHR and the 

DNBR do not exceed their limits. The COLSS performs this function by 

continuously monitoring the core power distribution and calculating core 

power operating limits corresponding to the allowable peak LHR and 

DNBR values. The CPCs perform this function by continuously 

calculating actual values of DNBR and local power density (LPD) for 

comparison with the respective trip setpoints. 

DNBR penalty factors are included in both the COLSS and CPC DNBR 

calculations to accommodate the effects of rod bow. The amount of rod 

bow in each assembly is dependent upon the average burnup 

experienced by that assembly. Fuel assemblies that incur higher than 

average burnup experience greater rod bow. Conversely, fuel 

assemblies that receive lower than average burnup experience less rod 

bow. In design calculations for a reload core, each batch of fuel is 

assigned a penalty applied to the maximum integrated planar radial 

power peak of the batch. This penalty is correlated with the amount of 

rod bow determined from the maximum average assembly burnup of the 

batch. A single net penalty for the COLSS and CPCs is then determined 

from the penalties associated with each batch that comprises a core 

reload, accounting for the offsetting margins due to the lower radial power 

peaks in the higher burnup batches. 

The COLSS indicates continuously to the operator how near the core is to 

the operating limits and provides an audible alarm if an operating limit is 

exceeded. Such a condition signifies a reduction in the capability of the 

plant to withstand an anticipated transient, but does not necessarily imply 

an immediate violation of fuel design limits. If the margin to fuel design 

limits continues to decrease, the RPS ensures that the specified 

acceptable fuel design limits are not exceeded for AOOs by initiating a 

reactor trip. 
Fxy (Digital) 

B 3.2.2 

CEOG STS B 3.2.2-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The COLSS continually generates an assessment of the calculated 

margin for LHR and DNBR specified limits. The data required for these 

assessments include measured incore neutron flux, CEA positions, and 

Reactor Coolant System (RCS) inlet temperature, pressure, and flow. 

In addition to monitoring performed by the COLSS, the RPS (via the 

CPCs) continually infers the core power distribution and thermal margins 

by processing reactor coolant data, signals from excore neutron flux 

detectors, and input from redundant reed switch assemblies that indicates 

CEA position. In this case, the CPCs assume a minimum core power of 

20% RTP. This threshold is set at 20% RTP because the power range 

excore neutron flux detecting system is inaccurate below this power level. 

If power distribution or other parameters are perturbed as a result of an 

AOO, the high LPD or low DNBR trips in the RPS initiate a reactor trip 

before fuel design limits are exceeded. 

The limits on ASI, Fxy, and TQ represent limits within which the LHR and 

DNBR algorithms are valid. These limits are obtained directly from the 

initial core or reload analysis. 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation or AOOs (Ref. 4). The power distribution and CEA insertion 

ANALYSES and alignment LCOs prevent core power distributions from reaching 

levels that violate the following fuel design criteria: 

a. During a LOCA, peak cladding temperature must not exceed 2200°F 

(Ref. 5), 

b. During a loss of flow accident, there must be at least 95% probability 

at the 95% confidence level (the 95/95 DNB criterion) that the hot fuel 

rod in the core does not experience a DNB condition (Ref. 4), 

c. During an ejected CEA accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. [ ]), and 

d. The control rods must be capable of shutting down the reactor with a 

minimum required SDM with the highest worth control rod stuck fully 

withdrawn (GDC 26, Ref. [ ]). 

The power density at any point in the core must be limited to maintain the 

fuel design criteria (Refs. 4 and 5). This result is accomplished by 

maintaining the power distribution and reactor coolant conditions so that 

the peak LHR and DNB parameters are within operating limits supported 

by the accident analyses (Ref. 1) with due regard for the correlations 

between measured quantities, the power distribution, and the 

uncertainties in the determination of power distribution. 
Fxy (Digital) 

B 3.2.2 

CEOG STS B 3.2.2-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Fuel cladding failure during a LOCA is limited by restricting the maximum 

linear heat generation rate so that the peak cladding temperature does 

not exceed 2200°F (Ref. 5). Peak cladding temperatures exceeding 

2200°F cause severe cladding failure by oxidation due to a Zircaloy water 

reaction. 

The LCOs governing LHR, ASI, and RCS ensure that these criteria are 

met as long as the core is operated within the ASI and Fxy limits specified 

in the COLR, and within the TQ limits. The latter are process variables 

that characterize the three dimensional power distribution of the reactor 

core. Operation within the limits for these variables ensures that their 

actual values are within the ranges used in the accident analyses. 

Fuel cladding damage does not normally occur because of conditions 

outside the limits of these LCOs for ASI, Fxy, and TQ during normal 

operation. However, fuel cladding damage results if an accident or AOO 

occurs from initial conditions outside the limits of these LCOs. This 

potential for fuel cladding damage exists because changes in the power 

distribution can cause increased power peaking and correspondingly 

increased LHR. 

Fxy satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The power distribution LCO limits are based on correlations between 

power peaking and certain measured variables used as inputs to the LHR 

and DNBR operating limits. The power distribution LCO limits are 

provided in the COLR. 

Limiting of the calculated Planar Radial Peaking Factors ( C FXY ) used in the 

COLSS and CPCs to values equal to or greater than the measured 

Planar Radial Peaking Factors ( M FXY ) ensures that the limits calculated by 

the COLSS and CPCs remain valid. 

APPLICABILITY Power distribution is a concern any time the reactor is critical. The power 

distribution LCOs, however, are only applicable in MODE 1 above 

20% RTP. The reasons these LCOs are not applicable below 20% RTP 

are: 

a. The incore neutron detectors that provide input to the COLSS, which 

then calculates the operating limits, are inaccurate because of the 

poor signal to noise ratio that they experience at relatively low core 

power levels and 
Fxy (Digital) 

B 3.2.2 

CEOG STS B 3.2.2-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY (continued) 

b. As a result of this inaccuracy, the CPCs assume a minimum core 

power of 20% RTP when generating the LPD and DNBR trip signals. 

When the core power is below 20% RTP, the core is operating well 

below its thermal limits, and the resultant CPC calculated LPD and 

DNBR trips are highly conservative. 

ACTIONS A.1.1 and A.1.2

When the M FXY values exceed the C FXY values used in the COLSS and 

CPCs, nonconservative operating limits and trip setpoints may be 

calculated. In this case, action must be taken to ensure that the COLSS 

operating limits and CPC trip setpoints remain valid with respect to the 

accident analysis. The operator can do this by performing the Required 

Actions A.1.1 and A.1.2. The 6 hour Completion Time provides the time 

required to calculate the required multipliers and make the necessary 

adjustments to the CPC addressable constants. During this period the 

DNBR and LHR setpoints may be slightly nonconservative but DNBR and 

LHR are still within limits. Therefore, 6 hours is an acceptable 

Completion Time to perform these actions considering the low probability 

of an accident occurring during this time period. 

A.2

As an alternative to Required Actions A.1.1 and A.1.2, the operator may 

adjust the affected values of C FXY used in the COLSS and CPCs to values 

≥ M FXY . The 6 hour Completion Time provides the time required to 

calculate the required multipliers and make the necessary adjustments to 

the CPC addressable constants. During this period the DNBR and LHR 

setpoints may be slightly nonconservative but DNBR and LHR are still 

within limits. Therefore, 6 hours is an acceptable Completion Time to 

perform these actions considering the low probability of an accident 

occurring during this time period. 
Fxy (Digital) 

B 3.2.2 

CEOG STS B 3.2.2-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

A.3

If Required Actions A.1.1 and A.1.2 or A.2 cannot be accomplished within 

6 hours, the core power must be reduced. Reduction to 20% RTP or less 

ensures that the core is operating within the specified thermal limits and 

places the core in a conservative condition based on the trip setpoints 

generated by the COLSS and CPC operating limits; these limits are 

established assuming a minimum core power of 20% RTP. Six hours is a 

reasonable time to reach 20% RTP in an orderly manner and without 

challenging plant systems. 

SURVEILLANCE SR 3.2.2.1

REQUIREMENTS 

This periodic Surveillance is for determining, using the Incore Detector 

System, that M FXY values are ≤ C FXY values used in the COLSS and CPCs. 

It ensures that the C FXY values used remain valid throughout the fuel cycle. 

A Frequency of 31 EFPD is acceptable because the power distribution 

changes only slightly with the amount of fuel burnup. Determining the M FXY

values after each fuel loading when THERMAL POWER is > 40% RTP, 

but prior to its exceeding 70% RTP, ensures that the core is properly 

loaded. 

REFERENCES 1. FSAR, Section [15]. 

 2. FSAR, Section [6]. 

 3. CE-1 Correlation for DNBR. 

 4. 10 CFR 50.46, Appendix A, GDC 10. 

 5. 10 CFR 50.46. 
 FT

XY (Analog) 

B 3.2.3 

CEOG STS B 3.2.3-1 Rev. 3.0, 03/31/04 

B 3.2 POWER DISTRIBUTION LIMITS 

B 3.2.3 Total Integrated Radial Peaking Factor (FT

XY) (Analog) 

BASES 

BACKGROUND The purpose of this LCO (Total Integrated Radial Peaking Factor (FT

r)) is 

to limit the core power distribution to the initial values assumed in the 

accident analyses. Operation within the limits imposed by this LCO either 

limits or prevents potential fuel cladding failures that could breach the 

primary fission product barrier and release fission products to the reactor 

coolant in the event of a loss of coolant accident (LOCA), loss of flow 

accident, ejected control element assembly (CEA) accident, or other 

postulated accident requiring termination by a Reactor Protection System 

trip function. This LCO limits the amount of damage to the fuel cladding 

during an accident by ensuring that the plant is operating within 

acceptable bounding conditions at the onset of a transient. 

Methods of controlling the power distribution include: 

a. The use of CEAs to alter the axial power distribution, 

b. Decreasing CEA insertion by boration, thereby improving the radial 

power distribution, and 

c. Correcting off optimum conditions (e.g., a CEA drop or misoperation 

of the unit) that cause margin degradations. 

The core power distribution is controlled so that, in conjunction with other 

core operating parameters (e.g., CEA insertion and alignment limits), the 

power distribution does not result in violation of this LCO. The limiting 

safety system settings (LSSS) and this LCO are based on the accident 

analyses (Refs. 1 and 2), so that specified acceptable fuel design limits 

are not exceeded as a result of anticipated operational occurrences 

(AOOs), and the limits of acceptable consequences are not exceeded for 

other postulated accidents. 

Limiting power distribution skewing over time also minimizes the xenon 

distribution skewing, which is a significant factor in controlling the axial 

power distribution. 

Power distribution is a product of multiple parameters, various 

combinations of which may produce acceptable power distributions. 

Operation within the design limits of power distribution is accomplished by 

generating operating limits on the linear heat rate (LHR) and departure 

from nucleate boiling (DNB). 
 FT

XY (Analog) 

B 3.2.3 

CEOG STS B 3.2.3-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The limits on LHR, Total Planar Radial Peaking Factor ( T FXY ), T Fr , Tq, and 

ASI represent limits within which the LHR algorithms are valid. These 

limits are obtained directly from the core reload analysis. 

Either of the two core power distribution monitoring systems, the Excore 

Detector Monitoring System or the Incore Detector Monitoring System, 

provide adequate monitoring of the core power distribution and are 

capable of verifying that the LHR does not exceed its limits. The Excore 

Detector Monitoring System performs this function by continuously 

monitoring the ASI with the OPERABLE quadrant symmetric excore 

neutron flux detectors and verifying that the ASI is maintained within the 

allowable limits specified in the COLR. 

In conjunction with the use of the Excore Detector Monitoring System and 

in establishing the ASI limits, the following conditions are assumed: 

a. The CEA insertion limits of LCO 3.1.5, "Shutdown CEA Insertion 

Limits," and LCO 3.1.6, "Regulating CEA Insertion Limits," are 

satisfied, 

b. The Tq restrictions of LCO 3.2.4 are satisfied, and 

c. FT

xy does not exceed the limits of LCO 3.2.2. 

The Incore Detector Monitoring System continuously provides a more 

direct measure of the peaking factors, and the alarms established for the 

individual incore detector segments ensure that the peak LHRs are 

maintained within the limits specified in the COLR. The setpoints for 

these alarms include tolerances, set in conservative directions, for: 

a. A measurement calculational uncertainty factor of 1.062, 

b. An engineering uncertainty factor of 1.03, 

c. An allowance of 1.002 for axial fuel densification and thermal 

expansion, and 

d. A THERMAL POWER measurement uncertainty factor of 1.02. 
 FT

XY (Analog) 

B 3.2.3 

CEOG STS B 3.2.3-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation (Condition 1) and AOOs (Condition 2) (Ref. 3, GDC 10). The 

ANALYSES power distribution and CEA insertion and alignment LCOs preclude core 

power distributions that violate the following fuel design criteria: 

a. During a LOCA, peak cladding temperature must not exceed 2200°F 

(Ref. 4), 

b. During a loss of flow accident, there must be at least 95% probability 

at the 95% confidence level (the 95/95 DNB criterion) that the hot fuel 

rod in the core does not experience a DNB condition (Ref. 3, 

GDC 10), 

c. During an ejected CEA accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. [ ]), and 

d. The control rods must be capable of shutting down the reactor with a 

minimum required SDM with the highest worth control rod stuck fully 

withdrawn (Ref. 3, GDC 26). 

The power density at any point in the core must be limited to maintain the 

fuel design criteria (Ref. 4). This is accomplished by maintaining the 

power distribution and reactor coolant conditions so that the peak LHR 

and DNB parameters are within operating limits supported by the accident 

analyses (Ref. 1), with due regard for the correlations between measured 

quantities, the power distribution, and uncertainties in the determination of 

power distribution. 

Fuel cladding failure during a LOCA is limited by restricting the maximum 

linear heat generation rate so that the peak cladding temperature does 

not exceed 2200°F (Ref. 4). High peak cladding temperatures are 

assumed to cause severe cladding failure by oxidation due to a Zircaloy 

water reaction. 

The LCOs governing LHR, ASI, and the Reactor Coolant System ensure 

that these criteria are met as long as the core is operated within the ASI, 

T FXY , and T Fr limits specified in the COLR, and within the Tq limits. The 

latter are process variables that characterize the three dimensional power 

distribution of the reactor core. Operation within the limits for these 

variables ensures that their actual values are within the range used in the 

accident analysis. 
 FT

XY (Analog) 

B 3.2.3 

CEOG STS B 3.2.3-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Fuel cladding damage does not normally occur while at conditions outside 

the limits of these LCOs during normal operation. Fuel cladding damage 

could result, however, if an accident or AOO occurs from initial conditions 

outside the limits of these LCOs. This potential for fuel cladding damage 

exists because changes in the power distribution cause increased power 

peaking and correspondingly increased local LHR. 

FT

r satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The LCO limits for power distribution are based on correlations between 

power peaking and measured variables used as inputs to LHR and DNB 

ratio operating limits. The LCO limits for power distribution, except Tq, are 

provided in the COLR. The limitation on the LHR ensures that, in the 

event of a LOCA, the peak temperature of the fuel cladding does not 

exceed 2200°F. 

APPLICABILITY In MODE 1, power distribution must be maintained within the limits 

assumed in the accident analysis to ensure that fuel damage does not 

result following an AOO. In other MODES, this LCO does not apply 

because there is not sufficient THERMAL POWER to require a limit on 

the core power distribution. 

ACTIONS A.1, A.2, and A.3

A Note modifying Condition A requires Required Actions A.1, A.2, and A.3 

to be completed if the Condition is entered. This ensures that corrective 

action is taken prior to unrestricted operation. 

The limitations on T Fr provided in the COLR ensure that the assumptions 

used in the analysis for establishing the ASI, LCO, and LSSS remain valid 

during operation at the various allowable CEA group insertion limits. If T Fr

exceeds its basic limitation, operation may continue under the additional 

restrictions imposed by the Required Actions (reducing THERMAL 

POWER, withdrawing CEAs to or beyond the long term steady state 

insertion limits of LCO 3.1.6, and establishing a revised upper THERMAL 

POWER limit) because these additional restrictions provide adequate 

provisions to ensure that the assumptions used in establishing the LHR, 

LCO, and LSSS remain valid. Six hours to return T Fr to within its limits by 

adjusting the ASI limits based on maximum power allowed for T FXY is 

reasonable and ensures that all CEAs meet the long term steady state 

insertion limits of LCO 3.1.6. 
 FT

XY (Analog) 

B 3.2.3 

CEOG STS B 3.2.3-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1

If T Fr cannot be returned to within its limit, THERMAL POWER must be 

reduced. A change to MODE 2 provides reasonable assurance that the 

core is operating within its thermal limits and places the core in a 

conservative condition. The allowed Completion Time of 6 hours is 

reasonable, based on operating experience, to reach MODE 2 from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE SR 3.2.3.1

REQUIREMENTS 

The periodic Surveillance to determine the calculated T Fr ensures that 

T Fr remains within the range assumed in the analysis throughout the fuel 

cycle. Determining the measured T Fr once after each fuel loading prior to 

exceeding 70% RTP ensures that the core is properly loaded. 

Performance of the Surveillance every 31 days of accumulated operation 

in MODE 1 provides reasonable assurance that unacceptable changes in 

the FT

r are promptly detected. 

The power distribution map can only be obtained after THERMAL 

POWER exceeds 20% RTP because the incore detectors are not reliable 

below 20% RTP. 

The SR is modified by a Note that requires SR 3.2.3.2 and SR 3.2.3.3 be 

completed each time SR 3.2.3.1 is completed. This procedure is required 

because the values computed by these SRs are required to perform this 

SR. 

SR 3.2.3.2 and SR 3.2.3.3

Measuring the values of T Fr and Tq each time a value of T Fr is calculated 

ensures that the calculated value of T Fr accurately reflects the condition of 

the core. 

The Frequency for these Surveillances is in accordance with the 

requirements of SR 3.2.3.1 because these SRs provide information to 

complete SR 3.2.2.1. 
 FT

XY (Analog) 

B 3.2.3 

CEOG STS B 3.2.3-6 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Chapter [15]. 

 2. FSAR, Chapter [6]. 

 3. 10 CFR 50, Appendix A. 

 4. 10 CFR 50.46. 
Tq (Digital) 

B 3.2.3 

CEOG STS B 3.2.3-1 Rev. 3.0, 03/31/04 

B 3.2 POWER DISTRIBUTION LIMITS 

B 3.2.3 AZIMUTHAL POWER TILT (TQ) (Digital) 

BASES 

BACKGROUND The purpose of this LCO is to limit the core power distribution to the initial 

values assumed in the accident analyses. Operation within the limits 

imposed by this LCO either limits or prevents potential fuel cladding 

failures that could breach the primary fission product barrier and release 

fission products to the reactor coolant in the event of a loss of coolant 

accident (LOCA), loss of flow accident, ejected control element assembly 

(CEA) accident, or other postulated accident requiring termination by a 

Reactor Protection System (RPS) trip function. This LCO limits the 

amount of damage to the fuel cladding during an accident by ensuring 

that the plant is operating within acceptable conditions at the onset of a 

transient. 

Methods of controlling the power distribution include: 

a. Using full or part length CEAs to alter the axial power distribution, 

b. Decreasing CEA insertion by boration, thereby improving the radial 

power distribution, and 

c. Correcting off optimum conditions, (e.g., a CEA drop or misoperation 

of the unit) that cause margin degradations. 

The core power distribution is controlled so that, in conjunction with other 

core operating parameters (e.g., CEA insertion and alignment limits), the 

power distribution does not result in violation of this LCO. The limiting 

safety system settings and this LCO are based on the accident analyses 

(Refs. 1 and 2), so that specified acceptable fuel design limits are not 

exceeded as a result of anticipated operational occurrences (AOOs) and 

the limits of acceptable consequences are not exceeded for other 

postulated accidents. 

Limiting power distribution skewing over time also minimizes xenon 

distribution skewing, which is a significant factor in controlling axial power 

distribution. 

Power distribution is a product of multiple parameters, various 

combinations of which may produce acceptable power distributions. 

Operation within the design limits of power distribution is accomplished by 

generating operating limits on the linear heat rate (LHR) and the 

departure from nucleate boiling (DNB). 
Tq (Digital) 

B 3.2.3 

CEOG STS B 3.2.3-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Proximity to the DNB condition is expressed by the departure from 

nucleate boiling ratio (DNBR), defined as the ratio of the cladding surface 

heat flux required to cause DNB to the actual cladding surface heat flux. 

The minimum DNBR value during both normal operation and AOOs is 

calculated by the CE-1 Correlation (Ref. 3) and corrected for such factors 

as rod bow and grid spacers, and it is accepted as an appropriate margin 

to DNB for all operating conditions. 

There are two systems that monitor core power distribution online: the 

Core Operating Limit Supervisory System (COLSS) and the core 

protection calculators (CPCs). The COLSS and CPCs that monitor the 

core power distribution are capable of verifying that the LHR and the 

DNBR do not exceed their limits. The COLSS performs this function by 

continuously monitoring the core power distribution and calculating core 

power operating limits corresponding to the allowable peak LHR and 

DNBR. The CPCs perform this function by continuously calculating 

actual values of DNBR and local power density (LPD) for comparison with 

the respective trip setpoints. 

A DNBR penalty factor is included in the COLSS and CPC DNBR 

calculation to accommodate the effects of rod bow. The amount of rod 

bow in each assembly is dependent upon the average burnup 

experienced by the assembly. Fuel assemblies that incur higher than 

average burnup experience greater magnitude of rod bow. Conversely, 

fuel assemblies that receive lower than average burnup experience less 

rod bow. In design calculations for a reload core, each batch of fuel is 

assigned a penalty applied to the maximum integrated planar radial 

power peak of the batch. This penalty is correlated with the amount of 

rod bow that is determined from the maximum average assembly burnup 

of the batch. A single net penalty for the COLSS and CPCs is then 

determined from the penalties associated with each batch that comprises 

a core reload, accounting for the offsetting margins caused by the lower 

radial power peaks in the higher burnup batches. 

The COLSS indicates continuously to the operator how far the core is 

from the operating limits and provides an audible alarm if an operating 

limit is exceeded. Such a condition signifies a reduction in the capability 

of the plant to withstand an anticipated transient, but does not necessarily 

imply an immediate violation of fuel design limits. If the margin to fuel 

design limits continues to decrease, the RPS ensures that the specified 

acceptable fuel design limits are not exceeded for AOOs by initiating a 

reactor trip. 
Tq (Digital) 

B 3.2.3 

CEOG STS B 3.2.3-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The COLSS continually generates an assessment of the calculated 

margin for LHR and DNBR specified limits. The data required for these 

assessments include measured incore neutron flux data, CEA positions, 

and Reactor Coolant System (RCS) inlet temperature, pressure, and flow. 

In addition to the monitoring performed by the COLSS, the RPS (via the 

CPCs) continually infers the core power distribution and thermal margins 

by processing reactor coolant data, signals from excore neutron flux 

detectors, and input from redundant reed switch assemblies that indicates 

CEA position. In this case, the CPCs assume a minimum core power of 

20% RTP. This threshold is set at 20% RTP because the power range 

excore neutron flux detection system is inaccurate below this power level. 

If power distribution or other parameters are perturbed as a result of an 

AOO, the high local power density or low DNBR trips in the RPS initiate a 

reactor trip prior to exceeding fuel design limits. 

The limits on the ASI, Fxy, and TQ represent limits within which the LHR 

and DNBR algorithms are valid. These limits are obtained directly from 

the initial core or reload analysis. 

APPLICABLE The fuel cladding must not sustain damage as a result of operation and 

SAFETY AOOs (Ref. 4). The power distribution and CEA insertion and alignment 

ANALYSES LCOs preclude core power distributions that violate the following fuel 

design criteria: 

a. During a LOCA, peak cladding temperature must not exceed 2200°F 

(Ref. 5), 

b. During a loss of flow accident, there must be at least 95% probability 

at the 95% confidence level (the 95/95 DNB criterion) that the hot fuel 

rod in the core does not experience a DNB condition (Ref. 4), 

c. During a CEA ejection accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. [5]), and 

d. The control rods must be capable of shutting down the reactor with a 

minimum required SDM with the highest worth control rod stuck fully 

withdrawn (Ref. [6]). 
Tq (Digital) 

B 3.2.3 

CEOG STS B 3.2.3-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The power density at any point in the core must be limited to maintain the 

fuel design criteria (Ref. 1). This result is accomplished by maintaining 

the power distribution and reactor coolant conditions so that the peak 

LHR and DNB parameters are within operating limits supported by the 

accident analysis (Ref. 2) with due regard for the correlations between 

measured quantities, the power distribution, and uncertainties in the 

determination of power distribution. 

Fuel cladding failure during a LOCA is limited by restricting the maximum 

linear heat generation rate (LHGR) so that the peak cladding temperature 

does not exceed 2200°F (Ref. 1). Peak cladding temperatures exceeding 

2200°F cause severe cladding failure by oxidation due to a Zircaloy water 

reaction. 

The LCOs governing LHR, ASI, and RCS ensure that these criteria are 

met as long as the core is operated within the ASI and Fxy limits specified 

in the COLR, and within the TQ limits. The latter are process variables 

that characterize the three dimensional power distribution of the reactor 

core. Operation within the limits of these variables ensures that their 

actual values are within the range used in the accident analyses. 

Fuel cladding damage does not normally occur from conditions outside 

the limits of these LCOs during normal operation. However, fuel cladding 

damage could result if an accident or AOO occurs due to initial conditions 

outside the limits of these LCOs. The potential for fuel cladding damage 

exists because changes in the power distribution can cause increased 

power peaking and correspondingly increased local LHRs. 

TQ satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The power distribution LCO limits are based on correlations between 

power peaking and certain measured variables used as inputs to the LHR 

and DNBR operating limits. The power distribution LCO limits are 

provided in the COLR. 

The limitations on the TQ are provided to ensure that design operating 

margins are maintained. TQ > 0.10 is not expected. If it occurs, the 

actions to be taken ensure that operation is restricted to only those 

conditions required to identify the cause of the tilt. It is necessary to 

explicitly account for power asymmetries because the radial peaking 

factors used in the core power distribution calculations are based on an 

untilted power distribution. 
Tq (Digital) 

B 3.2.3 

CEOG STS B 3.2.3-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY Power distribution is a concern any time the reactor is critical. The power 

distribution LCOs, however, are only applicable in MODE 1 above 

20% RTP. The reasons these LCOs are not applicable below 20% RTP 

are: 

a. The incore neutron detectors that provide input to the COLSS, which 

then calculates the operating limits, are inaccurate due to the poor 

signal to noise ratio that they experience at relatively low core power 

levels. 

b. As a result of this inaccuracy, the CPCs assume a minimum core 

power of 20% RTP when generating LPD and DNBR trip signals. 

When the core power is below this level, the core is operating well 

below its thermal limits and the resultant CPC calculated LPD and 

DNBR trips are highly conservative. 

ACTIONS A.1 and A.2

If the measured TQ is greater than the TQ allowance used in the CPCs but 

≤ 0.10, nonconservative trip setpoints may be calculated. Required 

Action A.1 restores TQ to within its specified limits by repositioning the 

CEAs, and the reactor may return to normal operation. A Completion 

Time of 2 hours is sufficient time to allow the operator to reposition the 

CEAs because significant radial xenon redistribution does not occur 

within this time. 

If the TQ cannot be restored within 2 hours, the TQ allowance in the CPCs 

must be adjusted, per Required Action A.2, to be equal to or greater than 

the measured value of TQ to ensure that the design safety margins are 

maintained. 

B.1, B.2, and B.3

Required Actions B.1, B.2, and B.3 are modified by a Note that requires 

all subsequent actions be performed if power reduction commences prior 

to restoring TQ ≤ 0.10. This requirement ensures that corrective action is 

taken before unrestricted power operation resumes. 

If the measured TQ > 0.10, THERMAL POWER is reduced to ≤ 50% RTP 

within 4 hours. The 4 hours allows enough time to take action to restore 

TQ prior to reducing power and limits the probability of operation with a 

power distribution out of limits. Such actions include performing 

SR 3.2.3.2, which provides a value of TQ that can be used in subsequent 

actions. 
Tq (Digital) 

B 3.2.3 

CEOG STS B 3.2.3-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Also in the case of a tilt generated by a CEA misalignment, the 4 hours 

allows recovery of the CEA misalignment, because a measured TQ > 0.10 

is not expected. If it occurs, continued operation of the reactor may be 

necessary to discover the cause of the tilt. Operation then is restricted to 

only those conditions required to identify the cause of the tilt. It is 

necessary to explicitly account for power asymmetries because the radial 

power peaking factors used in the core power distribution calculation are 

based on an untilted power distribution. 

If the measured TQ is not restored to within its specified limits, the reactor 

continues to operate with an axial power distribution mismatch. 

Continued operation in this configuration may induce an axial xenon 

oscillation, which results in increased LHGRs when the xenon 

redistributes. If the measured TQ cannot be restored to within its limit 

within 4 hours, reactor power must be reduced. Reducing THERMAL 

POWER to < 50% RTP within 4 hours provides an acceptable level of 

protection from increased power peaking due to potential xenon 

redistribution while maintaining a power level sufficiently high enough to 

allow the tilt to be analyzed. 

The Linear Power Level - High trip setpoints are reduced to ≤ 55% RTP to 

ensure that the assumptions of the accident analysis regarding power 

peaking are maintained. After power has been reduced to ≤ 50% RTP, 

the rate and magnitude of changes in the core flux are greatly reduced. 

Therefore, 16 hours is an acceptable time period to allow for reduction of 

the Linear Power Level - High trip setpoints, Required Action B.2. The 

16 hour Completion Time allowed to reduce the Linear Power Level - 

High trip setpoints is required to perform the actions necessary to reset 

the trip setpoints. 

THERMAL POWER is restricted to 50% RTP until the measured TQ is 

restored to within its specified limit by correcting the out of limit condition. 

This action prevents the operator from increasing THERMAL POWER 

above the conservative limit when a significant TQ has existed, but allows 

the unit to continue operation for diagnostic purposes. 

The Completion Time of Required Action B.3 is modified by a Note 

governing subsequent power increases. After a THERMAL POWER 

increase following restoration of TQ, operation may proceed provided the 

measured TQ is determined to remain within its specified limit at the 

increased THERMAL POWER level. 
Tq (Digital) 

B 3.2.3 

CEOG STS B 3.2.3-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

The provision to allow discontinuation of the Surveillance after verifying 

that TQ ≤ 0.10 is within its specified limit at least once per hour for 

12 hours or until TQ is verified to be within its specified limit at a 

THERMAL POWER ≥ 95% RTP provides an acceptable exit from this 

action after the measured TQ has been returned to an acceptable value. 

C.1

If the measured TQ cannot be restored or determined within its specified 

limit, core power must be reduced. Reduction of core power to 

< 20% RTP ensures that the core is operating within its thermal limits and 

places the core in a conservative condition based on the trip setpoints 

generated by the CPCs, which assume a minimum core power of 

20% RTP. Six hours is a reasonable time to reach 20% RTP in an 

orderly manner and without challenging plant systems. 

SURVEILLANCE SR 3.2.3.1

REQUIREMENTS 

Continuous monitoring of the measured TQ by the incore nuclear 

detectors is provided by the COLSS. A COLSS alarm is annunciated in 

the event that the measured TQ exceeds the value used in the CPCs. 

With the COLSS out of service, the operator must calculate TQ and verify 

that it is within its specified limits. The 12 hour Frequency is sufficient to 

identify slowly developing TQ's before they exceed the limits of this LCO. 

Also, the 12 hour Frequency prevents significant xenon redistribution. 

SR 3.2.3.2

Verification that the COLSS TQ alarm actuates at a value less than the 

value used in the CPCs ensures that the operator is alerted if TQ

approaches its operating limit. The 31 day Frequency for performance of 

this SR is consistent with the historical testing frequency of reactor 

protection and monitoring systems. The Surveillance Frequency for 

testing protection systems was extended to 92 days by CEN 327. 

Monitoring systems were not addressed in CEN 327; therefore, this 

Frequency remains at 31 days. 
Tq (Digital) 

B 3.2.3 

CEOG STS B 3.2.3-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.2.3.3

Independent confirmation of the validity of the COLSS calculated TQ

ensures that the COLSS accurately identifies TQ's. 

The 31 day Frequency for performance of this SR is consistent with the 

historical testing frequency of reactor protection and monitoring systems. 

The Surveillance Frequency for testing protection systems was extended 

to 92 days by CEN 327. Monitoring systems were not addressed in 

CEN 327; therefore, this Frequency remains at 31 days. 

REFERENCES 1. FSAR, Section [15]. 

 2. FSAR, Section [6]. 

 3. CE-1 Correlation for DNBR. 

 4. 10 CFR 50.46, Appendix A, GDC 10. 

 5. 10 CFR 50.46. 

 6. 10 CFR 50, Appendix A, GDC 26. 
Tq (Analog) 

B 3.2.4 

CEOG STS B 3.2.4-1 Rev. 3.0, 03/31/04 

B 3.2 POWER DISTRIBUTION LIMITS 

B 3.2.4 AZIMUTHAL POWER TILT (Tq) (Analog) 

BASES 

BACKGROUND The purpose of this LCO (AZIMUTHAL POWER TILT (Tq)) is to limit the 

core power distribution to the initial values assumed in the accident 

analyses. Operation within the limits imposed by this LCO limits or 

prevents potential fuel cladding failures that could breach the primary 

fission product barrier and release fission products to the reactor coolant 

in the event of a loss of coolant accident (LOCA), loss of flow accident, 

ejected control element assembly (CEA) accident, or other postulated 

accident requiring termination by a Reactor Protection System trip 

function. This LCO limits the amount of damage to the fuel cladding 

during an accident by ensuring that the plant is operating within 

acceptable bounding conditions at the onset of a transient. 

Methods of controlling the power distribution include: 

a. Using CEAs to alter the axial power distribution, 

b. Decreasing CEA insertion by boration, thereby improving the radial 

power distribution, and 

c. Correcting off optimum conditions (e.g., a CEA drop or misoperation 

of the unit) that cause margin degradations. 

The core power distribution is controlled so that, in conjunction with other 

core operating parameters (e.g., CEA insertion and alignment limits), the 

power distribution does not result in violation of this LCO. The limiting 

safety system settings and this LCO are based on the accident analyses 

(Refs. 1 and 2), so that specified acceptable fuel design limits are not 

exceeded as a result of anticipated operational occurrences (AOOs), and 

the limits of acceptable consequences are not exceeded for other 

postulated accidents. 

Limiting power distribution skewing over time also minimizes the xenon 

distribution skewing, which is a significant factor in controlling the axial 

power distribution. 

Power distribution is a product of multiple parameters, various 

combinations of which may produce acceptable power distributions. 

Operation within the design limits of power distribution is accomplished by 

generating operating limits for linear heat rate (LHR) and departure from 

nucleate boiling (DNB). 
Tq (Analog) 

B 3.2.4 

CEOG STS B 3.2.4-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The limits on LHR, Total Planar Radial Peaking Factor ( T FXY ), Total 

Integrated Radial Peaking Factor ( T Fr ), Tq, and ASI represent limits within 

which the LHR algorithms are valid. These limits are obtained directly 

from the core reload analysis. 

Either of the two core power distribution monitoring systems, the Excore 

Detector Monitoring System or the Incore Detector Monitoring System, 

provides adequate monitoring of the core power distribution and is 

capable of verifying that the LCO limits are not exceeded. The Excore 

Detector Monitoring System performs this function by continuously 

monitoring ASI with OPERABLE quadrant symmetric excore neutron 

detectors and by verifying ASI is maintained within the limits specified in 

the COLR. 

In conjunction with the use of the Excore Detector Monitoring System and 

in establishing the ASI limits, the following assumptions are made: 

a. The CEA insertion limits of LCO 3.1.5, "Shutdown CEA Insertion 

Limits," and LCO 3.1.6, "Regulating CEA Insertion Limits," are 

satisfied, 

b. The Tq restrictions of LCO 3.2.4 are satisfied, and 

c. FT

xy does not exceed the limits of LCO 3.2.2. 

The Incore Detector Monitoring System continuously provides a more 

direct measure of the peaking factors, and the alarms that have been 

established for the individual incore detector segments ensure that the 

peak LHRs are maintained within the limits specified in the COLR. The 

setpoints for these alarms include tolerances, set in conservative 

directions, for: 

a. A measurement calculational uncertainty factor of 1.062, 

b. An engineering uncertainty factor of 1.03, 

c. An allowance of 1.002 for axial fuel densification and thermal 

expansion, and 

d. A THERMAL POWER measurement uncertainty factor of 1.02. 
Tq (Analog) 

B 3.2.4 

CEOG STS B 3.2.4-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation (Condition 1) or AOOs (Condition 2) (Ref. 3, GDC 10). The 

ANALYSES power distribution and CEA insertion and alignment LCOs preclude core 

power distributions that violate the following fuel design criteria: 

a. During a LOCA, peak cladding temperature must not exceed 2200°F 

(Ref. 4), 

b. During a loss of flow accident, there must be at least 95% probability 

at the 95% confidence level (the 95/95 DNB criterion) that the hot fuel 

rod in the core does not experience a DNB condition (Ref. 3, 

GDC 10), 

c. During an ejected CEA accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. [ ]), and 

d. The control rods must be capable of shutting down the reactor with a 

minimum required SDM with the highest worth control rod stuck fully 

withdrawn (Ref. 3, GDC 26). 

The power density at any point in the core must be limited to maintain the 

fuel design criteria (Ref. 4). This process is accomplished by maintaining 

the power distribution and reactor coolant conditions so that the peak 

LHR and DNB parameters are within operating limits supported by the 

accident analysis (Ref. 1) with due regard for the correlations between 

measured quantities, the power distribution, and uncertainties in 

determining the power distribution. 

Fuel cladding failure during a LOCA is limited by restricting the maximum 

linear heat generation rate (LHGR) so that the peak cladding temperature 

does not exceed 2200°F (Ref. 4). High peak cladding temperatures are 

assumed to cause severe cladding failure by oxidation due to a Zircaloy 

water reaction. 

The LCOs governing LHR, ASI, and the Reactor Coolant System ensure 

that these criteria are met as long as the core is operated within the ASI, 

T FXY , and T Fr limits specified in the COLR, and within the Tq limits. The 

latter are process variables that characterize the three dimensional power 

distribution of the reactor core. Operation within the limits for these 

variables ensures that their actual values are within the range used in the 

accident analyses. 
Tq (Analog) 

B 3.2.4 

CEOG STS B 3.2.4-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Fuel cladding damage does not normally occur while the reactor is 

operating at conditions outside these LCOs during otherwise normal 

operation. Fuel cladding damage could result, however, if an accident or 

AOO occurs from initial conditions outside the limits of these LCOs. 

Changes in the power distribution cause increased power peaking and 

correspondingly increased local LHRs. 

The Tq satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The power distribution LCO limits are based on correlations between 

power peaking and the measured variables used as inputs to the LHR 

and DNB operating limits. The power distribution LCO limits, except Tq, 

are provided in the COLR. The limits on LHR ensure that in the event of 

a LOCA, the peak temperature of the fuel cladding does not exceed 

2200°F. 

APPLICABILITY In MODE 1 with THERMAL POWER > 50% RTP, Tq must be maintained 

within the limits assumed in accident analysis to ensure that fuel damage 

does not result following an AOO. In other MODES, this LCO does not 

apply because THERMAL POWER is not sufficient to require a limit 

on Tq. 

ACTIONS A.1 and A.2

If the measured Tq is > [0.03] and < 0.10, the calculation of Tq may be 

nonconservative. Tq must be restored within 2 hours or T FXY and T Fr must 

be determined to be within the limits of LCO 3.2.2 and LCO 3.2.3, and 

determined to be within these limits every 8 hours thereafter, as long as 

Tq is out of limits. Two hours is sufficient time to allow the operator to 

reposition CEAs, and significant radial xenon redistribution cannot occur 

within this time. The 8 hour Completion Time ensures changes in T FXY and 

T Fr can be identified before the limits of LCO 3.2.2 and LCO 3.2.3, 

respectively, are exceeded. 

B.1

If Required Actions and associated Completion Times of Condition A are 

not met, THERMAL POWER must be reduced to ≤ 50% RTP. This 

requirement provides reasonable assurance that the core is operating 

within its thermal limits and places the core in a conservative condition. 

Four hours is a reasonable time to reach 50% RTP in an orderly manner 

and without challenging plant systems. 
Tq (Analog) 

B 3.2.4 

CEOG STS B 3.2.4-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1, C.2, and C.3

With Tq > 0.10, T FXY and T Fr must be within their specified limits to ensure 

that acceptable flux peaking factors are maintained. Based on operating 

experience, 1 hour is sufficient time for the operator to evaluate these 

factors. If T FXY and T Fr are within limits, operation may proceed for a total 

of 2 hours after the Condition is entered while attempts are made to 

restore Tq to within its limit. 

If Tq ≤ 0.10 cannot be achieved, power must be reduced to ≤ 50% RTP 

within 2 hours. If the tilt is generated due to a CEA misalignment, 

operating at ≤ 50% RTP allows for the recovery of the CEA. Except as a 

result of CEA misalignment, Tq > 0.10 is not expected; if it occurs, 

continued operation of the reactor may be necessary to discover the 

cause of the tilt. If this procedure is followed, operation is restricted to 

only those conditions required to identify the cause of the tilt. It is 

necessary to account explicitly for power asymmetries because the radial 

power peaking factors used in core power distribution calculations are 

based on an untilted power distribution. 

If Tq is not restored to within its limits, the reactor continues to operate 

with an axial power distribution mismatch. Continued operation in this 

configuration may induce an axial xenon oscillation that causes increased 

LHRs when the xenon redistributes. If Tq cannot be restored to within its 

limits within 2 hours, reactor power must be reduced. Reducing 

THERMAL POWER to ≤ 50% RTP within 2 hours provides conservative 

protection from increased peaking due to potential xenon redistribution. 

The Required Actions are modified by a Note that requires all subsequent 

actions to be performed once power reduction commences after entering 

the Condition if Tq is not restored to < 0.10. This procedure ensures 

corrective action is taken before unrestricted power operation resumes. 

Following THERMAL POWER reduction to ≤ 50% RTP, Tq must be 

restored to ≤ [0.03] before THERMAL POWER is increased (Required 

Action C.3). This Required Action prevents the operator from increasing 

THERMAL POWER above the conservative limit when the Condition, Tq

outside its limits, has existed but allows the unit to continue operation for 

diagnostic purposes. The Completion Time of Required Action C.3 is 
Tq (Analog) 

B 3.2.4 

CEOG STS B 3.2.4-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

modified with a Note to indicate that the cause of the out of limit condition 

must be corrected prior to increasing THERMAL POWER. This Note also 

indicates that subsequent power operation above 50% RTP may proceed 

provided that the measured Tq is verified ≤ [0.03] at least once per hour 

for 12 hours, or until verified at 95% RTP. This ensures that the power 

distribution is responding as predicted. The Completion Time of 12 hours 

is a historical value that allows an acceptable exit from the LCO after the 

Tq value is verified acceptable for 12 hours or until 95% RTP is reached. 

SURVEILLANCE SR 3.2.4.1

REQUIREMENTS 

Tq must be calculated at 12 hour intervals. The 12 hour Frequency 

prevents significant xenon redistribution between Surveillances. 

REFERENCES 1. FSAR, Chapter [15]. 

 2. FSAR, Chapter [6]. 

 3. 10 CFR 50, Appendix A. 

 4. 10 CFR 50. 
DNBR (Digital) 

B 3.2.4 

CEOG STS B 3.2.4-1 Rev. 3.0, 03/31/04 

B 3.2 POWER DISTRIBUTION LIMITS 

B 3.2.4 Departure from Nucleate Boiling Ratio (DNBR) (Digital) 

BASES 

BACKGROUND The purpose of this LCO is to limit the core power distribution to the initial 

value assumed in the accident analyses. Specifically, operation within 

the limits imposed by this LCO either limits or prevents potential fuel 

cladding failures that could breach the primary fission product barrier and 

release fission products to the reactor coolant in the event of a loss of 

coolant accident (LOCA), loss of flow accident, ejected control element 

assembly (CEA) accident, or other postulated accident requiring 

termination by a Reactor Protection System (RPS) trip function. This 

LCO limits the amount of damage to the fuel cladding during an accident 

by ensuring that the plant is operating within acceptable conditions at the 

onset of a transient. 

Methods of controlling the power distribution include: 

a. Using full or part length CEAs to alter the axial power distribution, 

b. Decreasing CEA insertion by boration, thereby improving the radial 

power distribution, and 

c. Correcting off optimum conditions (e.g., a CEA drop or misoperation 

of the unit) that cause margin degradations. 

The core power distribution is controlled so that, in conjunction with other 

core operating parameters (e.g., CEA insertion and alignment limits), the 

power distribution does not result in violation of this LCO. The limiting 

safety system settings and this LCO are based on the accident analysis 

(Refs. 1 and 2), so that specified acceptable fuel design limits are not 

exceeded as a result of anticipated operational occurrences (AOOs) and 

the limits of acceptable consequences are not exceeded for other 

postulated accidents. 

Limiting power distribution skewing over time also minimizes the xenon 

distribution skewing, which is a significant factor in controlling axial power 

distribution. 

Power distribution is a product of multiple parameters, various 

combinations of which may produce acceptable power distributions. 

Operation within the design limits of power distribution is accomplished by 

generating operating limits on the linear heat rate (LHR) and the 

departure from nucleate boiling (DNB). 
DNBR (Digital) 

B 3.2.4 

CEOG STS B 3.2.4-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Proximity to the DNB condition is expressed by the DNBR, defined as the 

ratio of the cladding surface heat flux required to cause DNB to the actual 

cladding surface heat flux. The minimum DNBR value during both normal 

operation and AOOs is [ ] as calculated by the CE-1 Correlation (Ref. 3) 

and corrected for such factors as rod bows and grid spacers and it is 

accepted as an appropriate margin to DNB for all operating conditions. 

There are two systems that monitor core power distribution online: the 

Core Operating Limits Supervisory System (COLSS) and the core 

protection calculators (CPCs). The COLSS and CPCs that monitor the 

core power distribution are capable of verifying that the LHR and DNBR 

do not exceed their limits. The COLSS performs this function by 

continuously monitoring the core power distribution and calculating core 

power operating limits corresponding to the allowable peak LHR and 

DNBR. The CPCs perform this function by continuously calculating an 

actual value of DNBR and LPD for comparison with the respective trip 

setpoints. 

A DNBR penalty factor is included in both the COLSS and CPC DNBR 

calculation to accommodate the effects of rod bow. The amount of rod 

bow in each assembly is dependent upon the average burnup 

experienced by that assembly. Fuel assemblies that incur higher than 

average burnup experience a greater magnitude of rod bow. Conversely, 

fuel assemblies that receive lower than average burnup experience less 

rod bow. In design calculations for a reload core, each batch of fuel is 

assigned a penalty that is applied to the maximum integrated planar radial 

power peak of the batch. This penalty is correlated with the amount of 

rod bow that is determined from the maximum average assembly burnup 

of the batch. A single net penalty for the COLSS and CPCs is then 

determined from the penalties associated with each batch that comprises 

a core reload, accounting for the offsetting margins due to the lower radial 

power peaks in the higher burnup batches. 

The COLSS indicates continuously to the operator how far the core is 

from the operating limits and provides an audible alarm when an 

operating limit is exceeded. Such a condition signifies a reduction in the 

capability of the plant to withstand an anticipated transient, but does not 

necessarily imply an immediate violation of fuel design limits. If the 

margin to fuel design limits continues to decrease, the RPS ensures that 

the specified acceptable fuel design limits are not exceeded during AOOs 

by initiating a reactor trip. 
DNBR (Digital) 

B 3.2.4 

CEOG STS B 3.2.4-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The COLSS continually generates an assessment of the calculated 

margin for LHR and DNBR specified limits. The data required for these 

assessments include measured incore neutron flux, CEA positions, and 

Reactor Coolant System (RCS) inlet temperature, pressure, and flow. 

In addition to the monitoring performed by the COLSS, the RPS (via the 

CPCs) continually infers the core power distribution and thermal margins 

by processing reactor coolant data, signals from excore neutron flux 

detectors, and input from redundant reed switch assemblies that indicates 

CEA position. In this case, the CPCs assume a minimum core power of 

20% RTP because the power range excore neutron flux detecting system 

is inaccurate below this power level. If power distribution or other 

parameters are perturbed as a result of an AOO, the high local power 

density or low DNBR trips in the RPS initiate a reactor trip prior to the 

exceeding of fuel design limits. 

The limits on ASI, Fxy, and TQ represent limits within which the LHR and 

DNBR algorithms are valid. These limits are obtained directly from the 

initial core or reload analysis. 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation or AOOs (Ref. 4). The power distribution and CEA insertion 

ANALYSES and alignment LCOs prevent core power distributions from reaching 

levels that violate the following fuel design criteria: 

a. During a LOCA, peak cladding temperature must not exceed 2200°F 

(Ref. 5), 

b. During a loss of flow accident, there must be at least 95% probability 

at the 95% confidence level (the 95/95 DNB criterion) that the hot fuel 

rod in the core does not experience a DNB condition (Ref. 4), 

c. During an ejected CEA accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. 6), and 

d. The control rods must be capable of shutting down the reactor with a 

minimum required SDM with the highest worth control rod stuck fully 

withdrawn (Ref. 7). 

The power density at any point in the core must be limited to maintain the 

fuel design criteria (Ref. 4). This is accomplished by maintaining the 

power distribution and reactor coolant conditions so that the peak LHR 

and DNB parameters are within operating limits supported by the accident 

analyses (Ref. 1) with due regard for the correlations between measured 

quantities, the power distribution, and uncertainties in the determination of 

power distribution. 
DNBR (Digital) 

B 3.2.4 

CEOG STS B 3.2.4-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Fuel cladding failure during a LOCA is limited by restricting the maximum 

linear heat generation rate so that the peak cladding temperature does 

not exceed 2200°F (Ref. 4). Peak cladding temperatures exceeding 

2200°F may cause severe cladding failure by oxidation due to a Zircaloy 

water reaction. 

The LCOs governing LHR, ASI, and RCS ensure that these criteria are 

met as long as the core is operated within the ASI and Fxy limits specified 

in the COLR, and within the TQ limits. The latter are process variables 

that characterize the three dimensional power distribution of the reactor 

core. Operation within the limits for these variables ensures that their 

actual values are within the range used in the accident analyses (Ref. 1). 

Fuel cladding damage does not normally occur from conditions outside 

the limits of these LCOs during normal operation. However, fuel cladding 

damage could result if an accident or AOO occurs from initial conditions 

outside the limits of these LCOs. This potential for fuel cladding damage 

exists because changes in the power distribution can cause increased 

power peaking and correspondingly increased local LHRs. 

DNBR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The power distribution LCO limits are based on correlations between 

power peaking and certain measured variables used as inputs to the LHR 

and DNBR operating limits. The power distribution LCO limits are 

provided in the COLR. 

With the COLSS in service and one or both of the control element 

assembly calculators (CEACs) OPERABLE, the DNBR will be maintained 

by ensuring that the core power calculated by the COLSS is equal to or 

less than the permissible core power operating limit based on DNBR 

calculated by the COLSS. In the event that the COLSS is in service but 

neither of the two CEACs is OPERABLE, the DNBR is maintained by 

ensuring that the core power calculated by the COLSS is equal to or less 

than a reduced value of the permissible core power operating limit 

calculated by the COLSS. In this condition, the calculated operating limit 

must be reduced by the allowance specified in the COLR. 
DNBR (Digital) 

B 3.2.4 

CEOG STS B 3.2.4-5 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

In instances for which the COLSS is out of service and either one or both 

of the CEACs are OPERABLE, the DNBR is maintained by operating 

within the acceptable region specified in the COLR as shown in 

Figure 3.2.4-1, in the COLR, and using any OPERABLE CPC channel. 

Alternatively, when the COLSS is out of service and neither of the two 

CEACs is OPERABLE, the DNBR is maintained by operating within the 

acceptable region specified in the COLR for this condition as shown in 

Figure 3.2.4-2, in the COLR, and using any OPERABLE CPC channel. 

With the COLSS out of service, the limitation on DNBR as a function of 

the ASI represents a conservative envelope of operating conditions 

consistent with the analysis assumptions that have been analytically 

demonstrated adequate to maintain an acceptable minimum DNBR for all 

AOOs. Of these, the postulated loss of flow transient is the most limiting. 

Operation of the core with a DNBR at or above this limit ensures that an 

acceptable minimum DNBR is maintained in the event of a loss of flow 

transient. 

APPLICABILITY Power distribution is a concern any time the reactor is critical. The power 

distribution LCOs, however, are only applicable in MODE 1 above 

20% RTP. The reasons these LCOs are not applicable below 20% RTP 

are: 

a. The incore neutron detectors that provide input to the COLSS, which 

then calculates the operating limits, are inaccurate due to the poor 

signal to noise ratio that they experience at relatively low core power 

levels. 

b. As a result of this inaccuracy, the CPCs assume a minimum core 

power of 20% RTP when generating the local power density (LPD) 

and DNBR trip signals. When the core power is below this level, the 

core is operating well below the thermal limits and the resultant CPC 

calculated LPD and DNBR trips are highly conservative. 

ACTIONS A.1

Operating at or above the minimum required value of the DNBR ensures 

that an acceptable minimum DNBR is maintained in the event of a 

postulated loss of flow transient. If the core power as calculated by the 

COLSS exceeds the core power limit calculated by the COLSS based on 

the DNBR, fuel design limits may not be maintained following a loss of 

flow, and prompt action must be taken to restore the DNBR above its 

minimum Allowable Value. With the COLSS in service, 1 hour is a 

reasonable time for the operator to initiate corrective actions to restore 

the DNBR above its specified limit, because of the low probability of a 

severe transient occurring in this relatively short time. 
DNBR (Digital) 

B 3.2.4 

CEOG STS B 3.2.4-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1, B.2.1, and B.2.2

If the COLSS is not available the OPERABLE DNBR channels are 

monitored to ensure that the DNBR is not exceeded. Maintaining the 

DNBR within this specified range ensures that no postulated accident 

results in consequences more severe than those described in the 

FSAR, Chapter 15. A 4 hour Frequency is allowed to restore the DNBR 

limit to within the region of acceptable operation. This Frequency is 

reasonable because the COLSS allows the plant to operate with less 

DNBR margin (closer to the DNBR limit) than when monitoring with the 

CPCs. 

When operating with the COLSS out of service there is a possibility of a 

slow undetectable transient that degrades the DNBR slowly over the 

4 hour period and is then followed by an anticipated operational 

occurrence or an accident. To remedy this, the CPC calculated values of 

DNBR are monitored every 15 minutes when the COLSS is out of service. 

The 15 minute Frequency is adequate to allow the operator to identify an 

adverse trend in conditions that could result in an approach to the DNBR 

limit. Also, a maximum allowable change in the CPC calculated DNBR 

ensures that further degradation requires the operators to take immediate 

action to restore DNBR to within limits or reduce reactor power to comply 

with the Technical Specifications (TS). With an adverse trend, 1 hour is 

allowed for restoring DNBR to within limits if the COLSS is not restored to 

OPERABLE status. Implementation of this requirement ensures that 

reductions in core thermal margin are quickly detected and, if necessary, 

results in a decrease in reactor power and subsequent compliance with 

the existing COLSS out of service TS limits. 

With no adverse trend, 4 hours is allowed for restoring the DNBR to within 

limits if the COLSS is not restored to OPERABLE status. This duration is 

reasonable because the Frequency of the CPC determination of DNBR 

has been increased, and, if operation is maintained steady, the likelihood 

of exceeding the DNBR limit during this period is not increased. The 

likelihood of induced reactor transients from an early power reduction is 

also decreased. 
DNBR (Digital) 

B 3.2.4 

CEOG STS B 3.2.4-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1

If the DNBR cannot be restored or determined within the allowed times of 

Conditions A and B, core power must be reduced. Reduction of core 

power to < 20% RTP ensures that the core is operating within its thermal 

limits and places the core in a conservative condition based on trip 

setpoints generated by the CPCs, which assume a minimum core power 

of 20% RTP. 

The allowed Completion Time of 6 hours is reasonable, based on 

operating experience, to reach 20% RTP from full power conditions in an 

orderly manner and without challenging plant systems. 

SURVEILLANCE SR 3.2.4.1

REQUIREMENTS 

With the COLSS out of service, the operator must monitor the DNBR as 

indicated on any of the OPERABLE DNBR channels of the CPCs to verify 

that the DNBR is within the specified limits, shown in either Figure 3.2.4-1 

or 3.2.4-2 of the COLR, as applicable. A 2 hour Frequency is adequate to 

allow the operator to identify trends in conditions that would result in an 

approach to the DNBR limit. 

This SR is modified by a Note that states that the SR is only required to 

be met when the COLSS is out of service. Continuous monitoring of the 

DNBR is provided by the COLSS, which calculates core power and core 

power operating limits based on the DNBR and continuously displays 

these limits to the operator. A COLSS margin alarm is annunciated in the 

event that the THERMAL POWER exceeds the core power operating limit 

based on the DNBR. 

SR 3.2.4.2

Verification that the COLSS margin alarm actuates at a power level equal 

to or less than the core power operating limit, as calculated by the 

COLSS, based on the DNBR, ensures that the operator is alerted when 

operating conditions approach the DNBR operating limit. The 31 day 

Frequency for performance of this SR is consistent with the historical 

testing frequency of reactor protection and monitoring systems. The 

Surveillance Frequency for testing protection systems was extended to 

92 days by CEN 327. Monitoring systems were not addressed in 

CEN 327; therefore, this Frequency remains at 31 days. 
DNBR (Digital) 

B 3.2.4 

CEOG STS B 3.2.4-8 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Chapter [15]. 

 2. FSAR, Chapter [6]. 

 3. CE-1 Correlation for DNBR. 

 4. 10 CFR 50, Appendix A, GDC 10. 

 5. 10 CFR 50.46. 

 6. FSAR, Section [ ]. 

 7. 10 CFR 50, Appendix A, GDC 26. 
ASI (Analog) 

B 3.2.5 

CEOG STS B 3.2.5-1 Rev. 3.0, 03/31/04 

B 3.2 POWER DISTRIBUTION LIMITS 

B 3.2.5 AXIAL SHAPE INDEX (ASI) (Analog) 

BASES 

BACKGROUND The purpose of this LCO (AXIAL SHAPE INDEX (ASI)) is to limit the core 

power distribution to the initial values assumed in the accident analysis. 

Operation within the limits imposed by this LCO either limits or prevents 

potential fuel cladding failures that could breach the primary fission 

product barrier and release fission products to the reactor coolant in the 

event of a loss of coolant accident (LOCA), loss of flow accident, ejected 

control element assembly (CEA) accident, or other postulated accident 

requiring termination by a Reactor Protection System trip function. This 

LCO limits the amount of damage to the fuel cladding during an accident 

by ensuring that the plant is operating within acceptable bounding 

conditions at the onset of a transient. 

Methods of controlling the power distribution include: 

a. Using CEAs to alter the axial power distribution, 

b. Decreasing CEA insertion by boration, thereby improving the radial 

power distribution, and 

c. Correcting off optimum conditions (e.g., a CEA drop or misoperation 

of the unit) that cause margin degradations. 

The core power distribution is controlled so that, in conjunction with other 

core operating parameters (e.g., CEA insertion and alignment limits), the 

power distribution does not result in violation of this LCO. The limiting 

safety system settings and this LCO are based on the accident analyses 

(Refs. 1 and 2), so that specified acceptable fuel design limits are not 

exceeded as a result of anticipated operational occurrences (AOOs), and 

the limits of acceptable consequences are not exceeded for other 

postulated accidents. 

Limiting power distribution skewing over time also minimizes the xenon 

distribution skewing, which is a significant factor in controlling the axial 

power distribution. 

Power distribution is a product of multiple parameters, various 

combinations of which may produce acceptable power distributions. 

Operation within the design limits of power distribution is accomplished by 

generating operating limits on linear heat rate (LHR) and departure from 

nucleate boiling (DNB). 
ASI (Analog) 

B 3.2.5 

CEOG STS B 3.2.5-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The limits on LHR, Total Planar Radial Peaking Factor ( T FXY ), Total 

Integrated Radial Peaking Factor ( T Fr ), Tq, and ASI represent limits within 

which the LHR algorithms are valid. These limits are obtained directly 

from the core reload analysis. 

Either of the two core power distribution monitoring systems, the Excore 

Detector Monitoring System and the Incore Detector Monitoring System, 

provide adequate monitoring of the core power distribution and are 

capable of verifying that the LHR does not exceed its limits. The Excore 

Detector Monitoring System performs this function by continuously 

monitoring the ASI with the OPERABLE quadrant symmetric excore 

neutron flux detectors and verifying that the ASI is maintained within the 

allowable limits specified in the COLR. 

In conjunction with the use of the Excore Detector Monitoring System and 

in establishing the ASI limits, the following conditions are assumed: 

a. The CEA insertion limits of LCO 3.1.5, "Shutdown CEA Insertion 

Limits," and LCO 3.1.6, "Regulating CEA Insertion Limits," are 

satisfied, 

b. The Tq restrictions of LCO 3.2.4 are satisfied, and 

c. FT

xy does not exceed the limits of LCO 3.2.2. 

The Incore Detector Monitoring System continuously provides a more 

direct measure of the peaking factors, and the alarms that have been 

established for the individual incore detector segments ensure that the 

peak LHR is maintained within the limits specified in the COLR. The 

setpoints for these alarms include tolerances, set in conservative 

directions, as follows: 

a. A measurement calculational uncertainty factor of 1.062, 

b. An engineering uncertainty factor of 1.03, 

c. An allowance of 1.002 for axial fuel densification and thermal 

expansion, and 

d. A THERMAL POWER measurement uncertainty factor of 1.02. 
ASI (Analog) 

B 3.2.5 

CEOG STS B 3.2.5-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The fuel cladding must not sustain damage as a result of normal 

SAFETY operation (Condition 1) or AOOs (Condition 2) (Ref. 3, GDC 10). The 

ANALYSES power distribution and CEA insertion and alignment LCOs prevent core 

power distributions from reaching levels that violate the following fuel 

design criteria: 

a. During a LOCA, peak cladding temperature must not exceed 2200°F 

(Ref. 4), 

b. During a loss of flow accident, there must be at least 95% probability 

at the 95% confidence level (the 95/95 DNB criterion) that the hot fuel 

rod in the core does not experience a DNB condition (Ref. 3, 

GDC 10), 

c. During an ejected CEA accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. [ ]), and 

d. The control rods must be capable of shutting down the reactor with a 

minimum required SDM with the highest worth control rod stuck fully 

withdrawn (Ref. 3, GDC 26). 

The power density at any point in the core must be limited to maintain the 

fuel design criteria (Ref. 4). This limitation is accomplished by 

maintaining the power distribution and reactor coolant conditions so that 

the peak LHR and DNB parameters are within operating limits supported 

by the accident analyses (Ref. 1) with due regard for the correlations 

among measured quantities, the power distribution, and uncertainties in 

the determination of power distribution. 

Fuel cladding failure during a LOCA is limited by restricting the maximum 

linear heat generation rate so that the peak cladding temperature does 

not exceed 2200°F (Ref. 4). High peak cladding temperatures are 

assumed to cause severe cladding failure by oxidation due to a Zircaloy 

water reaction. 

The LCOs governing LHR, ASI, and the Reactor Coolant System ensure 

that these criteria are met as long as the core is operated within the ASI, 

T FXY , and T Fr limits specified in the COLR, and within the Tq limits. The 

latter are process variables that characterize the three dimensional power 

distribution of the reactor core. Operation within the limits for these 

variables ensures that their actual values are within the ranges used in 

the accident analyses. 
ASI (Analog) 

B 3.2.5 

CEOG STS B 3.2.5-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Fuel cladding damage does not normally occur while the reactor is 

operating at conditions outside these LCOs during normal operation. 

Fuel cladding damage results, however, when an accident or AOO occurs 

from initial conditions outside the limits of these LCOs. This potential for 

fuel cladding damage exists because changes in the power distribution 

can cause increased power peaking and correspondingly increased local 

LHRs. 

The ASI satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The power distribution LCO limits are based on correlations between 

power peaking and certain measured variables used as inputs to the LHR 

and DNB operating limits. These power distribution LCO limits, except Tq, 

are provided in the COLR. The limitation on LHR ensures that in the 

event of a LOCA, the peak temperature of the fuel cladding does not 

exceed 2200°F. 

The limitation on ASI, along with the limitations of LCO 3.3.1, "Reactor 

Protection System Instrumentation," represents a conservative envelope 

of operating conditions consistent with the assumptions that have been 

analytically demonstrated adequate for maintaining an acceptable 

minimum DNBR throughout all AOOs. Of these, the loss of flow transient 

is the most limiting. Operation of the core with conditions within the 

specified limits ensures that an acceptable minimum margin from DNB 

conditions is maintained in the event of any AOO, including a loss of flow 

transient. 

APPLICABILITY In MODE 1 with THERMAL POWER > 20% RTP, power distribution must 

be maintained within the limits assumed in the accident analyses to 

ensure that fuel damage does not result following an AOO. In other 

MODES, this LCO does not apply because THERMAL POWER is not 

sufficient to require a limit on the core power distribution. Below 

20% RTP the incore detector accuracy is not reliable. 

ACTIONS A.1

Operating the core within ASI limits specified in the COLR and within the 

limits of LCO 3.3.1 ensures an acceptable margin for DNB and for 

maintaining local power density in the event of an AOO. Maintaining ASI 

within limits also ensures that the limits of 10 CFR 50.46 are not 

exceeded during accidents. The Required Actions to restore ASI must be 

completed within 2 hours to limit the duration the plant is operated outside 

the initial conditions assumed in the accident analyses. In addition, this 

Completion Time is sufficiently short that the xenon distribution in the core 

cannot change significantly. 
ASI (Analog) 

B 3.2.5 

CEOG STS B 3.2.5-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1

If the ASI cannot be restored to within its specified limits, or ASI cannot 

be determined because of Excore Detector Monitoring System 

inoperability, core power must be reduced. Reducing THERMAL 

POWER to ≤ 20% RTP provides reasonable assurance that the core is 

operating farther from thermal limits and places the core in a conservative 

condition. Four hours is a reasonable amount of time, based on 

operating experience, to reduce THERMAL POWER to ≤ 20% RTP in an 

orderly manner and without challenging plant systems. 

SURVEILLANCE SR 3.2.5.1

REQUIREMENTS 

Verifying that the ASI is within the specified limits provides reasonable 

assurance that the core is not approaching DNB conditions. A Frequency 

of 12 hours is adequate for the operator to identify trends in conditions 

that result in an approach to the ASI limits, because the mechanisms that 

affect the ASI, such as xenon redistribution or CEA drive mechanism 

malfunctions, cause the ASI to change slowly and should be discovered 

before the limits are exceeded. 

REFERENCES 1. FSAR, Chapter [15]. 

 2. FSAR, Chapter [6]. 

 3. 10 CFR 50, Appendix A. 

 4. 10 CFR 50.46. 
ASI (Digital) 

B 3.2.5 

CEOG STS B 3.2.5-1 Rev. 3.0, 03/31/04 

B 3.2 POWER DISTRIBUTION LIMITS 

B 3.2.5 AXIAL SHAPE INDEX (ASI) (Digital) 

BASES 

BACKGROUND The purpose of this LCO is to limit the core power distribution to the initial 

values assumed in the accident analysis. Operation within the limits 

imposed by this LCO either limits or prevents potential fuel cladding 

failures that could breach the primary fission product barrier and release 

fission products to the reactor coolant in the event of a loss of coolant 

accident (LOCA), loss of flow accident, ejected control element assembly 

(CEA) accident, or other postulated accident requiring termination by a 

Reactor Protection System (RPS) trip function. This LCO limits the 

amount of damage to the fuel cladding during an accident by ensuring 

that the plant is operating within acceptable conditions at the onset of a 

transient. 

Methods of controlling the power distribution include: 

a. Using full or part length CEAs to alter the axial power distribution, 

b. Decreasing CEA insertion by boration, thereby improving the radial 

power distribution, and 

c. Correcting off optimum conditions (e.g., a CEA drop or misoperation 

of the unit) that cause margin degradations. 

The core power distribution is controlled so that, in conjunction with other 

core operating parameters (CEA insertion and alignment limits), the 

power distribution does not result in violation of this LCO. The limiting 

safety system settings are based on the accident analyses (Refs. 1 

and 2), so that specified acceptable fuel design limits are not exceeded 

as a result of anticipated operational occurrences (AOOs) and the limits 

of acceptable consequences are not exceeded for other postulated 

accidents. 

Minimizing power distribution skewing over time also minimizes xenon 

distribution skewing, which is a significant factor in controlling axial power 

distribution. 

Power distribution is a product of multiple parameters, various 

combinations of which may produce acceptable power distributions. 

Operation within the design limits of power distribution is accomplished by 

generating operating limits on the linear heat rate (LHR) and the 

departure from nucleate boiling (DNB). 
ASI (Digital) 

B 3.2.5 

CEOG STS B 3.2.5-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Proximity to the DNB condition is expressed by the departure from 

nucleate boiling ratio (DNBR), defined as the ratio of the cladding surface 

heat flux required to cause DNB to the actual cladding surface heat flux. 

The minimum DNBR value during both normal operation and AOOs is [ ] 

as calculated by the CE-1 Correlation (Ref. 3), and corrected for such 

factors as rod bow and grid spacers, and it is accepted as an appropriate 

margin to DNB for all operating conditions. 

There are two systems that monitor core power distribution online: the 

Core Operating Limit Supervisory System (COLSS) or the core protection 

calculators (CPCs). The COLSS and CPCs monitor the core power 

distribution and are capable of verifying that the LHR and DNBR do not 

exceed their limits. The COLSS performs this function by continuously 

monitoring the core power distribution and calculating core power 

operating limits corresponding to the allowable peak LHR and DNBR. 

The CPCs perform this function by continuously calculating actual values 

of DNBR and local power density (LPD) for comparison with the 

respective trip setpoints. 

A DNBR penalty factor is included in both the COLSS and CPC DNBR 

calculations to accommodate the effects of rod bow. The amount of rod 

bow in each assembly is dependent upon the average burnup 

experienced by that assembly. Fuel assemblies that incur higher than 

average burnup experience greater rod bow. Conversely, fuel 

assemblies that receive lower than average burnup experience less rod 

bow. In design calculations for a reload core, each batch of fuel is 

assigned a penalty that is applied to the maximum integrated planar radial 

power peak of the batch. This penalty is correlated with the amount of 

rod bow that is determined from the maximum average assembly burnup 

of the batch. A single net penalty for the COLSS and CPC is then 

determined from the penalties associated with each batch that comprises 

a core reload, accounting for the offsetting margins due to the lower radial 

power peaks in the higher burnup batches. 

The COLSS indicates continuously to the operator how far the core is 

from the operating limits and provides an audible alarm if an operating 

limit is exceeded. Such a condition signifies a reduction in the capability 

of the plant to withstand an anticipated transient, but does not necessarily 

imply an immediate violation of fuel design limits. If the margin to fuel 

design limits continues to decrease, the RPS ensures that the specified 

acceptable fuel design limits are not exceeded for AOOs by initiating a 

reactor trip. 
ASI (Digital) 

B 3.2.5 

CEOG STS B 3.2.5-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The COLSS continually generates an assessment of the calculated 

margin for LHR and DNBR specified limits. The data required for these 

assessments include measured incore neutron flux, CEA positions, and 

Reactor Coolant System (RCS) inlet temperature, pressure, and flow. 

In addition to the monitoring performed by the COLSS, the RPS (via the 

CPCs) continually infers the core power distribution and thermal margins 

by processing reactor coolant data, signals from excore neutron flux 

detectors, and input from redundant reed switch assemblies that indicates 

CEA position. In this case, the CPCs assume a minimum core power of 

20% RTP because the power range excore neutron flux detecting system 

is inaccurate below this power level. If power distribution or other 

parameters are perturbed as a result of an AOO, the high local power 

density or low DNBR trips in the RPS initiate a reactor trip prior to the 

exceeding of fuel design limits. 

The limits on ASI, Fxy, and TQ represent limits within which the LHR and 

DNBR algorithms are valid. These limits are obtained directly from the 

initial core or reload analysis. 

APPLICABLE The fuel cladding must not sustain damage as a result of operation or 

SAFETY AOOs (Ref. 4). The power distribution and CEA insertion and alignment 

ANALYSES LCOs prevent core power distributions from reaching levels that violate 

the following fuel design criteria: 

a. During a LOCA, peak cladding temperature must not exceed 2200°F 

(Ref. 5), 

b. During a loss of flow accident, there must be at least 95% probability 

at the 95% confidence level (the 95/95 DNB criterion) that the hot fuel 

rod in the core does not experience a DNB condition (Ref. 4), 

c. During an ejected CEA accident, the fission energy input to the fuel 

must not exceed 280 cal/gm (Ref. 6), 

d. The control rods must be capable of shutting down the reactor with a 

minimum required SDM with the highest worth control rod stuck fully 

withdrawn (Ref. 7). 

The power density at any point in the core must be limited to maintain the 

fuel design criteria (Refs. 4 and 5). This is accomplished by maintaining 

the power distribution and reactor coolant conditions so that the peak 

LHR and DNB parameters are within operating limits supported by the 

accident analyses (Ref. 1) with due regard for the correlations among 

measured quantities, the power distribution, and uncertainties in the 

determination of power distribution. 
ASI (Digital) 

B 3.2.5 

CEOG STS B 3.2.5-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Fuel cladding failure during a LOCA is limited by restricting the maximum 

linear heat generation rate (LHGR) so that the peak cladding temperature 

does not exceed 2200°F (Ref. 5). Peak cladding temperatures exceeding 

2200°F may cause severe cladding failure by oxidation due to a Zircaloy 

water reaction. 

The LCOs governing LHR, ASI, and RCS ensure that these criteria are 

met as long as the core is operated within the ASI and Fxy limits specified 

in the COLR, and within the TQ limits. The latter are process variables 

that characterize the three dimensional power distribution of the reactor 

core. Operation within the limits for these variables ensures that their 

actual values are within the range used in the accident analysis. 

Fuel cladding damage does not normally occur from conditions outside 

these LCOs during normal operation. However, fuel cladding damage 

results when an accident or AOO occurs due to initial conditions outside 

the limits of these LCOs. This potential for fuel cladding damage exists 

because changes in the power distribution can cause increased power 

peaking and correspondingly increased local LHRs. 

The ASI satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The power distribution LCO limits are based on correlations between 

power peaking and certain measured variables used as inputs to LHR 

and DNBR operating limits. The power distribution LCO limits are 

provided in the COLR. 

The limitation on ASI ensures that the actual ASI value is maintained 

within the range of values used in the accident analysis. The ASI limits 

ensure that with TQ at its maximum upper limit, the DNBR does not drop 

below the DNBR Safety Limit for AOOs. 

APPLICABILITY Power distribution is a concern any time the reactor is critical. The power 

distribution LCOs, however, are only applicable in MODE 1 

above 20% RTP. The reasons these LCOs are not applicable 

below 20% RTP are: 

a. The incore neutron detectors that provide input to the COLSS, which 

then calculates the operating limits, are inaccurate due to the poor 

signal to noise ratio that they experience at relatively low core power 

levels. 
ASI (Digital) 

B 3.2.5 

CEOG STS B 3.2.5-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY (continued) 

b. As a result of this inaccuracy, the CPCs assume a minimum core 

power of 20% RTP when generating the LPD and DNBR trip signals. 

When the core power is below this level, the core is operating well 

below the thermal limits and the resultant CPC calculated LPD and 

DNBR trips are strongly conservative. 

ACTIONS A.1

The ASI limits specified in the COLR ensure that the LOCA and loss of 

flow accident criteria assumed in the accident analyses remain valid. If 

the ASI exceeds its limit, a Completion Time of 2 hours is allowed to 

restore the ASI to within its specified limit. This duration gives the 

operator sufficient time to reposition the regulating or part length CEAs to 

reduce the axial power imbalance. The magnitude of any potential xenon 

oscillation is significantly reduced if the condition is not allowed to persist 

for more than 2 hours. 

B.1

If the ASI is not restored to within its specified limits within the required 

Completion Time, the reactor continues to operate with an axial power 

distribution mismatch. Continued operation in this configuration induces 

an axial xenon oscillation, and results in increased LHGRs when the 

xenon redistributes. Reducing thermal power to ≤ 20% RTP reduces the 

maximum LHR to a value that does not exceed the fuel design limits if a 

design basis event occurs. The allowed Completion Time of 4 hours is 

reasonable, based on operating experience, to reduce power in an 

orderly manner and without challenging plant systems. 

SURVEILLANCE SR 3.2.5.1

REQUIREMENTS 

The ASI can be monitored by both the incore (COLSS) and excore (CPC) 

neutron detector systems. The COLSS provides the operator with an 

alarm if an ASI limit is approached. 

Verification of the ASI every 12 hours ensures that the operator is aware 

of changes in the ASI as they develop. A 12 hour Frequency for this 

Surveillance is acceptable because the mechanisms that affect the ASI, 

such as xenon redistribution or CEA drive mechanism malfunctions, 

cause slow changes in the ASI, which can be discovered before the limits 

are exceeded. 
ASI (Digital) 

B 3.2.5 

CEOG STS B 3.2.5-6 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Chapter [15]. 

 2. FSAR, Chapter [6]. 

 3. CE-1 Correlation for DNBR. 

 4. 10 CFR 50, Appendix A, GDC 10. 

 5. 10 CFR 50.46. 

 6. FSAR, Section [ ]. 

 7. 10 CFR 50, Appendix A, GDC 26. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.1 Reactor Protective System (RPS) Instrumentation - Operating (Analog) 

BASES 

BACKGROUND The Reactor Protective System (RPS) initiates a reactor trip to protect 

against violating the core specified acceptable fuel design limits and 

breaching the reactor coolant pressure boundary during anticipated 

operational occurrences (AOOs). By tripping the reactor, the RPS also 

assists the Engineered Safety Features systems in mitigating accidents. 

The protection and monitoring systems have been designed to ensure 

safe operation of the reactor. This is achieved by specifying limiting 

safety system settings (LSSS) in terms of parameters directly monitored 

by the RPS, as well as LCOs on other reactor system parameters and 

equipment performance. 

Technical Specifications are required by 10 CFR 50.36 to contain LSSS 

defined by the regulation as "...settings for automatic protective 

devices...so chosen that automatic protective actions will correct the 

abnormal situation before a Safety Limit (SL) is exceeded." The Analytic 

Limit is the limit of the process variable at which a safety action is 

initiated, as established by the safety analysis, to ensure that a SL is not 

exceeded. Any automatic protection action that occurs on reaching the 

Analytic Limit therefore ensures that the SL is not exceeded. However, in 

practice, the actual settings for automatic protective devices must be 

chosen to be more conservative than the Analytic Limit to account for 

instrument loop uncertainties related to the setting at which the automatic 

protective action would actually occur. 

The trip setpoint is a predetermined setting for a protective device chosen 

to ensure automatic actuation prior to the process variable reaching the 

Analytic Limit and thus ensuring that the SL would not be exceeded. As 

such, the trip setpoint accounts for uncertainties in setting the device 

(e.g., calibration), uncertainties in how the device might actually perform 

(e.g., repeatability), changes in the point of action of the device over time 

(e.g., drift during surveillance intervals), and any other factors which may 

influence its actual performance (e.g., harsh accident environments). In 

this manner, the trip setpoint plays an important role in ensuring that SLs 

are not exceeded. As such, the trip setpoint meets the definition of an 

LSSS (Ref. 1) and could be used to meet the requirement that they be 

contained in the Technical Specifications. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Technical Specifications contain values related to the OPERABILITY of 

equipment required for safe operation of the facility. OPERABLE is 

defined in Technical Specifications as "...being capable of performing its 

safety function(s)." For automatic protective devices, the required safety 

function is to ensure that a SL is not exceeded and therefore the LSSS as 

defined by 10 CFR 50.36 is the same as the OPERABILITY limit for these 

devices. However, use of the trip setpoint to define OPERABILITY in 

Technical Specifications and its corresponding designation as the LSSS 

required by 10 CFR 50.36 would be an overly restrictive requirement if it 

were applied as an OPERABILITY limit for the "as found" value of a 

protective device setting during a Surveillance. This would result in 

Technical Specification compliance problems, as well as reports and 

corrective actions required by the rule which are not necessary to ensure 

safety. For example, an automatic protective device with a setting that 

has been found to be different from the trip setpoint due to some drift of 

the setting may still be OPERABLE since drift is to be expected. This 

expected drift would have been specifically accounted for in the setpoint 

methodology for calculating the trip setpoint and thus the automatic 

protective action would still have ensured that the SL would not be 

exceeded with the "as found" setting of the protective device. Therefore, 

the device would still be OPERABLE since it would have performed its 

safety function and the only corrective action required would be to reset 

the device to the trip setpoint to account for further drift during the next 

surveillance interval. 

Use of the trip setpoint to define "as found" OPERABILITY and its 

designation as the LSSS under the expected circumstances described 

above would result in actions required by both the rule and Technical 

Specifications that are clearly not warranted. However, there is also 

some point beyond which the device would have not been able to perform 

its function due, for example, to greater than expected drift. This value 

needs to be specified in the Technical Specifications in order to define 

OPERABILITY of the devices and is designated as the Allowable Value 

which, as stated above, is the same as the LSSS. 

The Allowable Valuable specified in Table 3.3.1-1 serves as the LSSS 

such that a channel is OPERABLE if the trip setpoint is found not to 

exceed the Allowable Value during the CHANNEL FUNCTIONAL TEST 

(CFT). As such, the Allowable Value differs from the trip setpoint by an 

amount primarily equal to the expected instrument loop uncertainties, 

such as drift, during the surveillance interval. In this manner, the actual 

setting of the device will still meet the LSSS definition and ensure that a 

SL is not exceeded at any given point of time as long as the device has 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

not drifted beyond that expected during the surveillance interval. If the 

actual setting of the device is found to have exceeded the Allowable 

Value the device would be considered inoperable from a Technical 

Specification perspective. This requires corrective action including those 

actions required by 10 CFR 50.36 when automatic protective devices do 

not function as required. Note that, although the channel is "OPERABLE" 

under these circumstances, the trip setpoint should be left adjusted to a 

value within the established trip setpoint calibration tolerance band, in 

accordance with uncertainty assumptions stated in the referenced 

setpoint methodology (as-left criteria), and confirmed to be operating 

within the statistical allowances of the uncertainty terms assigned. 

During AOOs, which are those events expected to occur one or more 

times during the plant life, the acceptable limits are: 

• The departure from nucleate boiling ratio (DNBR) shall be maintained 

above the Safety Limit (SL) value to prevent departure from nucleate 

boiling, 

• Fuel centerline melting shall not occur, and 

• The Reactor Coolant System (RCS) pressure SL of 2750 psia shall 

not be exceeded. 

Maintaining the parameters within the above values ensures that the 

offsite dose will be within the 10 CFR 50 (Ref. 2) and 10 CFR 100 (Ref. 3) 

criteria during AOOs. 

Accidents are events that are analyzed even though they are not 

expected to occur during the plant life. The acceptable limit during 

accidents is that the offsite dose shall be maintained within an acceptable 

fraction of 10 CFR 100 (Ref. 3) limits. Different accident categories allow 

a different fraction of these limits based on probability of occurrence. 

Meeting the acceptable dose limit for an accident category is considered 

having acceptable consequences for that event. 

The RPS is segmented into four interconnected modules. These 

modules are: 

• Measurement channels, 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-4 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

• Bistable trip units, 

• RPS Logic, and 

• Reactor trip circuit breakers (RTCBs). 

This LCO addresses measurement channels and bistable trip units. It 

also addresses the automatic bypass removal feature for those trips with 

operating bypasses. The RPS Logic and RTCBs are addressed in 

LCO 3.3.3, "Reactor Protective System (RPS) Logic and Trip Initiation." 

The role of each of these modules in the RPS, including those associated 

with the logic and RTCBs, is discussed below. 

Measurement Channels

Measurement channels, consisting of field transmitters or process 

sensors and associated instrumentation, provide a measurable electronic 

signal based upon the physical characteristics of the parameter being 

measured. 

The excore nuclear instrumentation and the analog core protection 

calculators (CPCs) are considered components in the measurement 

channels. The wide range nuclear instruments (NIs) provide a Power 

Rate of Change - High Trip. Three RPS trips use a power level 

designated as Q power as an input. Q power is the higher of NI power 

and primary calorimetric power (∆T power) based on RCS hot leg and 

cold leg temperatures. Trips using Q power as an input include the 

Variable High Power Trip (VHPT) - High, Thermal Margin/Low Pressure 

(TM/LP), and the Axial Power Distribution (APD) - High trips. 

The analog CPCs provide the complex signal processing necessary to 

calculate the TM/LP trip setpoint, APD trip setpoint, VHPT trip setpoint, 

and Q power calculation. 

The excore NIs (wide range and power range) and the analog CPCs 

(TM/LP and APD calculators) are mounted in the RPS cabinet, with one 

channel of each in each of the four RPS bays. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-5 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Four identical measurement channels with electrical and physical 

separation are provided for each parameter used in the direct generation 

of trip signals. These are designated channels A through D. 

Measurement channels provide input to one or more RPS bistables within 

the same RPS channel. In addition, some measurement channels may 

also be used as inputs to Engineered Safety Features Actuation System 

(ESFAS) bistables, and most provide indication in the control room. 

Measurement channels used as an input to the RPS are never used for 

control functions. 

When a channel monitoring a parameter exceeds a predetermined 

setpoint, indicating an unsafe condition, the bistable monitoring the 

parameter in that channel will trip. Tripping two or more channels of 

bistables monitoring the same parameter de-energizes Matrix Logic, 

which in turn de-energizes the Initiation Logic. This causes all eight 

RTCBs to open, interrupting power to the control element assemblies 

(CEAs), allowing them to fall into the core. 

Three of the four measurement and bistable channels are necessary to 

meet the redundancy and testability of GDC 21 in 10 CFR 50, Appendix A 

(Ref. 2). The fourth channel provides additional flexibility by allowing one 

channel to be removed from service (trip channel bypass) for 

maintenance or testing while still maintaining a minimum two-out-of-three 

logic. Thus, even with a channel inoperable, no single additional failure in 

the RPS can either cause an inadvertent trip or prevent a required trip 

from occurring. 

Since no single failure will either cause or prevent a protective system 

actuation, and no protective channel feeds a control channel, this 

arrangement meets the requirements of IEEE Standard 279-1971 

(Ref. 4). 

Many of the RPS trips are generated by comparing a single measurement 

to a fixed bistable setpoint. Certain Functions, however, make use of 

more than one measurement to provide a trip. The following trips use 

multiple measurement channel inputs: 

• Steam Generator Level - Low

This trip uses the lower of the two steam generator levels as an input 

to a common bistable. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-6 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

• Steam Generator Pressure - Low

This trip uses the lower of the two steam generator pressures as an 

input to a common bistable. 

• Variable High Power Trip (VHPT) - High

The VHPT uses Q power as its only input. Q power is the higher of 

NI power and ∆T power. It has a trip setpoint that tracks power levels 

downward so that it is always within a fixed increment above current 

power, subject to a minimum value. 

On power increases, the trip setpoint remains fixed unless manually 

reset, at which point it increases to the new setpoint, a fixed 

increment above Q power at the time of reset, subject to a maximum 

value. Thus, during power escalation, the trip setpoint must be 

repeatedly reset to avoid a reactor trip. 

• Thermal Margin/Low Pressure (TM/LP) and Steam Generator 

Pressure Difference

Q power is only one of several inputs to the TM/LP trip. Other inputs 

include internal ASI and cold leg temperature based on the higher of 

two cold leg resistance temperature detectors. The TM/LP trip 

setpoint is a complex function of these inputs and represents a 

minimum acceptable RCS pressure to be compared to actual RCS 

pressure in the TM/LP trip unit. 

Steam generator pressure is also an indirect input to the TM/LP trip 

via the Steam Generator Pressure Difference. This Function 

provides a reactor trip when the secondary pressure in either steam 

generator exceeds that of the other generator by greater than a fixed 

amount. The trip is implemented by biasing the TM/LP trip setpoint 

upward so as to ensure TM/LP trip if an asymmetric steam generator 

transient is detected. 

• Axial Power Distribution (APD) - High

Q Power and ASI are inputs to the APD trip. The APD trip setpoint is 

a function of Q power, being more restrictive at higher power levels. 

It provides a reactor trip if actual ASI exceeds the APD trip setpoint. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-7 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Bistable Trip Units

Bistable trip units, mounted in the RPS cabinet, receive an analog input 

from the measurement channels, compare the analog input to trip 

setpoints, and provide contact output to the Matrix Logic. They also 

provide local trip indication and remote annunciation. 

There are four channels of bistable trip units, designated A through D, for 

each RPS Function, one for each measurement channel. Bistable output 

relays de-energize when a trip occurs. 

The contacts from these bistable relays are arranged into six coincidence 

matrices, comprising the Matrix Logic. If bistables monitoring the same 

parameter in at least two channels trip, the Matrix Logic will generate a 

reactor trip (two-out-of-four logic). 

Some of the RPS measurement channels provide contact outputs to the 

RPS, so the comparison of an analog input to a trip setpoint is not 

necessary. In these cases, the bistable trip unit is replaced with an 

auxiliary trip unit. The auxiliary trip units provide contact multiplication so 

the single input contact opening can provide multiple contact outputs to 

the coincidence logic as well as trip indication and annunciation. 

Trips employing auxiliary trip units include the Loss of Load trip and the 

APD - High trip. The Loss of Load trip is a contact input from the Electro 

Hydraulic Control System control oil pressure on each of the four high 

pressure stop valves. 

The APD trip, described above, is a complex function in which the actual 

trip comparison is performed within the CPC. Therefore the APD - High 

trip unit employs a contact input from the CPC. 

All RPS trips, with the exception of the Loss of Load trip, generate a 

pretrip alarm as the trip setpoint is approached. 

The trip setpoints used in the bistable trip units are based on the 

analytical limits stated in Reference 5. The selection of these trip 

setpoints is such that adequate protection is provided when all sensor 

and processing time delays are taken into account. To allow for 

calibration tolerances, instrumentation uncertainties, instrument drift, and 

severe environment errors - for those RPS channels that must function in 

harsh environments, as defined by 10 CFR 50.49 (Ref. 6) - Allowable 

Values specified in Table 3.3.1-1, in the accompanying LCO, are 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-8 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

conservatively adjusted with respect to the analytical limits. A detailed 

description of the methodology used to calculate the trip setpoints, 

including their explicit uncertainties, is provided in the "Plant Protection 

System Selection of Trip Setpoint Values" (Ref. 7). The nominal trip 

setpoint entered into the bistable is normally still more conservative than 

that specified by the Allowable Value, to account for changes in random 

measurement errors detectable by a CHANNEL FUNCTIONAL TEST. 

One example of such a change in measurement error is drift during the 

interval between surveillances. A channel is inoperable if its actual 

setpoint is not within its required Allowable Value. 

Setpoints in accordance with the Allowable Value will ensure that SLs of 

Chapter 2.0 are not violated during AOOs and the consequences of DBAs 

will be acceptable, providing the plant is operated from within the LCOs at 

the onset of the AOO or DBA and the equipment functions as designed. 

Note that in the accompanying LCO 3.3.1, the Allowable Values of 

Table 3.3.1-1 are the LSSS. 

RPS Logic

The RPS Logic, addressed in LCO 3.3.3, consists of both Matrix and 

Initiation Logic and employs a scheme that provides a reactor trip when 

bistables in any two out of the four channels sense the same input 

parameter trip. This is called a two-out-of-four trip logic. This logic and 

the RTCB configuration are shown in Figure B 3.3.1-1. 

Bistable relay contact outputs from the four channels are configured into 

six logic matrices. Each logic matrix checks for a coincident trip in the 

same parameter in two bistable channels. The matrices are designated 

the AB, AC, AD, BC, BD, and CD matrices to reflect the bistable channels 

being monitored. Each logic matrix contains four normally energized 

matrix relays. When a coincidence is detected, consisting of a trip in the 

same Function in the two channels being monitored by the logic matrix, 

all four matrix relays de-energize. 

The matrix relay contacts are arranged into trip paths, with one of the four 

matrix relays in each matrix opening contacts in one of the four trip paths. 

Each trip path provides power to one of the four normally energized 

RTCB control relays (K1, K2, K3, and K4). The trip paths thus each have 

six contacts in series, one from each matrix, and perform a logical OR

function, opening the RTCBs if any one or more of the six logic matrices 

indicate a coincidence condition. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-9 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Each trip path is responsible for opening one set of two of the eight 

RTCBs. The RTCB control relays (K-relays), when de-energized, 

interrupt power to the breaker undervoltage trip attachments and 

simultaneously apply power to the shunt trip attachments on each of the 

two breakers. Actuation of either the undervoltage or shunt trip 

attachment is sufficient to open the RTCB and interrupt power from the 

motor generator (MG) sets to the control element drive mechanisms 

(CEDMs). 

When a coincidence occurs in two RPS channels, all four matrix relays in 

the affected matrix de-energize. This in turn de-energizes all four RTCB 

control relays, which simultaneously de-energize the undervoltage and 

energize the shunt trip attachments in all eight RTCBs, tripping them 

open. 

Matrix Logic refers to the matrix power supplies, trip channel bypass 

contacts, and interconnecting matrix wiring between bistable and auxiliary 

trip units, up to but not including the matrix relays. Contacts in the 

bistable and auxiliary trip units are excluded from the Matrix Logic 

definition, since they are addressed as part of the measurement channel. 

The Initiation Logic consists of the trip path power source, matrix relays 

and their associated contacts, all interconnecting wiring, and solid state 

(auxiliary) relays through the K-relay contacts in the RTCB control 

circuitry. 

It is possible to change the two-out-of-four RPS Logic to a two-out-ofthree logic for a given input parameter in one channel at a time by trip 

channel bypassing select portions of the Matrix Logic. Trip channel 

bypassing a bistable effectively shorts the bistable relay contacts in the 

three matrices associated with that channel. Thus, the bistables will 

function normally, producing normal trip indication and annunciation, but a 

reactor trip will not occur unless two additional channels indicate a trip 

condition. Trip channel bypassing can be simultaneously performed on 

any number of parameters in any number of channels, providing each 

parameter is bypassed in only one channel at a time. An interlock 

prevents simultaneous trip channel bypassing of the same parameter in 

more than one channel. Trip channel bypassing is normally employed 

during maintenance or testing. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-10 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

For those plants that have demonstrated sufficient channel to channel 

independence, two-out-of-three logic is the minimum that is required to 

provide adequate plant protection, since a failure of one channel still 

ensures a reactor trip would be generated by the two remaining 

OPERABLE channels. Two-out-of-three logic also prevents inadvertent 

trips caused by any single channel failure in a trip condition. 

In addition to the trip channel bypasses, there are also operating 

bypasses on select RPS trips. Some of these bypasses are enabled 

manually, others automatically, in all four RPS channels when plant 

conditions do not warrant the specific trip protection. All operating 

bypasses are automatically removed when enabling bypass conditions 

are no longer satisfied. Trips with operating bypasses include Power 

Rate of Change - High, Reactor Coolant Flow - Low, Steam Generator 

Pressure - Low, APD - High, TM/LP, and Steam Generator Pressure 

Difference. [The Loss of Load trip, Power Rate of Change - High, and 

APD - High operating bypasses are automatically enabled and disabled.] 

Reactor Trip Circuit Breakers (RTCBs)

The reactor trip switchgear, addressed in LCO 3.3.3 and shown in 

Figure B 3.3.1-1, consists of eight RTCBs, which are operated in four sets 

of two breakers (four channels). Power input to the reactor trip 

switchgear comes from two full capacity MG sets operated in parallel 

such that the loss of either MG set does not de-energize the CEDMs. 

There are two separate CEDM power supply buses, each bus powering 

half of the CEDMs. Power is supplied from the MG sets to each bus via 

two redundant paths (trip legs). Trip legs 1A and 1B supply power to 

CEDM bus 1. Trip legs 2A and 2B supply power to CEDM bus 2. This 

ensures that a fault or the opening of a breaker in one trip leg (i.e., for 

testing purposes) will not interrupt power to the CEDM buses. 

Each of the four trip legs consists of two RTCBs in series. The two 

RTCBs within a trip leg are actuated by separate initiation circuits. 

The eight RTCBs are operated as four sets of two breakers (four 

channels). For example, if a breaker receives an open signal in trip leg A 

(for CEDM bus 1), an identical breaker in trip leg B (for CEDM bus 2) will 

also receive an open signal. This arrangement ensures that power is 

interrupted to both CEDM buses, thus preventing trip of only half of the 

CEAs (a half trip). Any one inoperable breaker in a channel will make the 

entire channel inoperable. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-11 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Each set of RTCBs is operated by either a Manual Trip push button or an 

RPS actuated K-relay. There are four Manual Trip push buttons, 

arranged in two sets of two, as shown in Figure B 3.3.1-1. Depressing 

both push buttons in either set will result in a reactor trip. 

When a Manual Trip is initiated using the control room push buttons, the 

RPS trip paths and K-relays are bypassed, and the RTCB undervoltage 

and shunt trip attachments are actuated independent of the RPS. 

Manual Trip circuitry includes the push button and interconnecting wiring 

to both RTCBs necessary to actuate both the undervoltage and shunt trip 

attachments but excludes the K-relay contacts and their interconnecting 

wiring to the RTCBs, which are considered part of the Initiation Logic. 

Functional testing of the entire RPS, from bistable input through the 

opening of individual sets of RTCBs, can be performed either at power or 

shutdown and is normally performed on a quarterly basis. 

FSAR, Section [7.2] (Ref. 8), explains RPS testing in more detail. 

APPLICABLE Each of the analyzed accidents and transients can be detected by one 

SAFETY or more RPS Functions. The accident analysis contained in Reference 5 

ANALYSES takes credit for most RPS trip Functions. Functions not specifically 

credited in the accident analysis are part of the NRC approved licensing 

basis for the plant. These Functions may provide protection for 

conditions that do not require dynamic transient analysis to demonstrate 

Function performance. Other Functions, such as the Loss of Load trip, 

are purely equipment protective, and their use minimizes the potential for 

equipment damage. 

The specific safety analyses applicable to each protective Function are 

identified below: 

1. Variable High Power Trip (VHPT) - High

The VHPT provides reactor core protection against positive reactivity 

excursions that are too rapid for a Pressurizer Pressure - High or 

TM/LP trip to protect against. The following events require VHPT 

protection: 

• Uncontrolled CEA withdrawal event, 

• Excess load, 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-12 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

• Excess feedwater heat removal event, 

• CEA ejection event, and 

• Main steam line break (MSLB) (outside containment). 

The first three events are AOOs, and fuel integrity is maintained. The 

fourth and fifth are accidents, and limited fuel damage may occur. 

2. Power Rate of Change - High

The Power Rate of Change - High trip is used to trip the reactor when 

excore [logarithmic] power indicates an excessive rate of change. 

The Power Rate of Change - High Function minimizes transients for 

events such as a continuous CEA withdrawal or a boron dilution 

event from low power levels. The trip may be bypassed when 

THERMAL POWER is < 1E-4% RTP, when poor counting statistics 

may lead to erroneous indication. It is also bypassed at > 15% RTP, 

where moderator temperature coefficient and fuel temperature 

coefficient make high rate of change of power unlikely. With the 

RTCBs open, the Power Rate of Change - High trip is not required to 

be OPERABLE; however, the indication and alarm Functions of at 

least two channels are required by LCO 3.3.13, "[Logarithmic] Power 

Monitoring Channels," to be OPERABLE. LCO 3.3.13 ensures the 

[logarithmic] channels are available to detect and alert the operator to 

a boron dilution event. 

3. Reactor Coolant Flow - Low

The Reactor Coolant Flow - Low trip provides protection during the 

following events: 

• Loss of RCS flow, 

• Loss of nonemergency AC power, 

• Reactor coolant pump (RCP) seized shaft, 

• RCP sheared shaft, and 

• Certain MSLB events. 

The loss of RCS flow and of nonemergency AC power events are AOOs where fuel integrity is 

maintained. The RCP seized shaft, sheared shaft, and MSLBs are accidents where fuel 

damage may result.
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-13 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

4. Pressurizer Pressure - High

The Pressurizer Pressure - High trip, in conjunction with pressurizer 

safety valves and main steam safety valves (MSSVs), provides 

protection against overpressure conditions in the RCS during the 

following events: 

• Loss of condenser vacuum with a concurrent loss of offsite 

power, 

• Loss of condenser vacuum with a concurrent loss of one 6.9 kV 

bus, 

• Isolation of turbine at 102% power, 

• Feedwater System pipe breaks between the steam generator 

and check valve, 

• CEA withdrawal, and 

• Loss of feedwater flow. 

5. Containment Pressure - High

The Containment Pressure - High trip prevents exceeding the 

containment design pressure during certain loss of coolant accidents 

(LOCAs) or feedwater line break accidents. It ensures a reactor trip 

prior to, or concurrent with, a LOCA, thus assisting the ESFAS in the 

event of a LOCA or MSLB. Since these are accidents, SLs may be 

violated. However, the consequences of the accident will be 

acceptable. 

6. Steam Generator Pressure - Low

The Steam Generator Pressure - Low trip provides protection against 

an excessive rate of heat extraction from the steam generators, 

which would result in a rapid uncontrolled cooldown of the RCS. This 

trip is needed to shut down the reactor and assist the ESFAS in the 

event of an MSLB. Since these are accidents, SLs may be violated. 

However, the consequences of the accident will be acceptable. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-14 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

7.a, 7.b. Steam Generator A and B Level - Low

The Steam Generator A Level - Low and Steam Generator B Level - 

Low trips are required for the following events: 

• Steam System piping failures, 

• Feedwater System pipe breaks, 

• Inadvertent opening of a steam generator atmospheric dump 

valve (ADV), 

• Loss of normal feedwater, and 

• Asymmetric loss of feedwater. 

The Steam Generator Level - Low trip ensures that low DNBR, high 

local power density, and the RCS pressure SLs are maintained 

during normal operation and AOOs, and, in conjunction with the 

ESFAS, the consequences of the Feedwater System pipe break 

accident will be acceptable. 

8. Axial Power Distribution (APD) - High

The APD - High trip ensures that excessive axial peaking, such as 

that due to axial xenon oscillations, will not cause fuel damage. It 

ensures that neither a DNBR less than the SL nor a peak linear heat 

rate that corresponds to the temperature for fuel centerline melting 

will occur. This trip is the primary protection against fuel centerline 

melting. 

9. Thermal Margin

a. Thermal Margin/Low Pressure (TM/LP)

The TM/LP trip prevents exceeding the DNBR SL during AOOs 

and aids the ESFAS during certain accidents. The following 

events require TM/LP protection: 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-15 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

• Excess load (inadvertent opening of a steam generator 

ADV), 

• RCS depressurization (inadvertent safety or power operated 

relief valves (PORVs) opening), 

• Steam generator tube rupture, and 

• LOCA accident. 

The first two events are AOOs, and fuel integrity is maintained. 

The third and fourth are accidents, and limited fuel damage may 

occur although only the LOCA is expected to result in fuel 

damage. The trip is initiated whenever the RCS pressure signal 

drops below a minimum value (Pmin) or a computed value (Pvar) 

as described below, whichever is higher. The computed value is 

a Function Q power, ASI, as determined from the axially split 

excore detectors, reactor inlet (cold leg) temperature, and the 

number of RCPs operating. 

The minimum value of reactor coolant flow rate, the maximum 

TQ, and the maximum CEA deviation permitted for continuous 

operation are assumed in the generation of this trip Function. In 

addition, CEA group sequencing in accordance with LCO 3.1.6, 

"Regulating Control Element Assembly (CEA) Insertion Limits," 

is assumed. Finally, the maximum insertion of CEA banks that 

can occur during any AOO prior to a VHPT is assumed. 

b. Steam Generator Pressure Difference

The Steam Generator Pressure Difference provides protection 

for those AOOs associated with secondary system malfunctions 

that result in asymmetric primary coolant temperatures. The 

most limiting event is closure of a single main steam isolation 

valve. Steam Generator Pressure Difference is provided by 

comparing the secondary pressure in both steam generators in 

the TM/LP calculator. If the pressure in either exceeds that in 

the other by the trip setpoint, a TM/LP trip will result. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-16 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

10. Loss of Load

The Loss of Load (turbine stop valve (TSV) control oil pressure) trip 

is anticipatory for the loss of heat removal capabilities of the 

secondary system following a turbine trip. The Loss of Load trip 

prevents lifting the pressurizer safety valves, PORVs, and MSSVs in 

the event of a turbine generator trip. Thus, the trip minimizes the 

pressure and temperature transients on the reactor by initiating a trip 

well before reaching the Pressurizer Pressure - High trip and 

pressurizer safety valve setpoints. The four RPS Loss of Load 

reactor trip channels receive their input from sensors mounted on the 

high pressure TSV actuators. Since there are four high pressure 

TSVs, one actuator per valve and one sensor per actuator, each 

sensor sends its signal to a different RPS channel. When the turbine 

trips, control oil is dumped from the high pressure TSVs. When the 

control oil pressure drops to the appropriate setpoint, a reactor trip 

signal is generated. 

Interlocks/Bypasses

The bypasses and their Allowable Values are addressed in footnotes to 

Table 3.3.1-1. They are not otherwise addressed as specific Table 

entries. 

The automatic bypass removal features must function as a backup to 

manual actions for all safety related trips to ensure the trip Functions are 

not operationally bypassed when the safety analysis assumes the 

Functions are not bypassed. The RPS operating bypasses are: 

Zero power mode bypass (ZPMB) removal on the TM/LP, Steam 

Generator Pressure Difference, and reactor coolant low flow trips when 

THERMAL POWER is < 1E-4% RTP. This bypass is manually enabled 

below the specified setpoint to permit low power testing. The wide range 

NI Level 1 bistable in the wide range drawer permits manual bypassing 

below the setpoint and removes the bypass above the setpoint. 

Power rate of change bypass removal. The Power Rate of Change - High 

trip is automatically bypassed at < 1E-4% RTP, as sensed by the wide 

range NI Level 2 bistable, and at > 12% RTP by the power range 

NI Level 1 bistable, mounted in their respective NI drawers. Automatic 

bypass removal is also effected by these bistables when conditions are 

no longer satisfied. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-17 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Loss of Load and APD - High bypass removal. The Loss of Load and 

APD - High trips are automatically bypassed when at < 15% RTP as 

sensed by the power range NI Level 1 bistable. The bypass is 

automatically removed by this bistable above the setpoint. This same 

bistable is used to bypass the Power Rate of Change - High trip. 

Steam Generator Pressure - Low bypass removal. The Steam Generator 

Pressure - Low trip is manually enabled below the pretrip setpoint. The 

permissive is removed, and the bypass automatically removed, when the 

Steam Generator Pressure - Low pretrip clears. 

The RPS instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The LCO requires all instrumentation performing an RPS Function to be 

OPERABLE. Failure of any required portion of the instrument channel 

renders the affected channel(s) inoperable and reduces the reliability of 

the affected Functions. The specific criteria for determining channel 

OPERABILITY differ slightly between Functions. These criteria are 

discussed on a Function by Function basis below. 

Actions allow maintenance (trip channel) bypass of individual channels, 

but the bypass activates interlocks that prevent operation with a second 

channel in the same Function bypassed. Plants are restricted to 48 hours 

in a trip channel bypass condition before either restoring the Function to 

four channel operation (two-out-of-four logic) or placing the channel in trip 

(one-out-of-three logic). At plants where adequate channel to channel 

independence has been demonstrated, specific exceptions may be 

approved by the NRC staff to permit one of the two-out-of-four channels 

to be bypassed for an extended period of time. 

Only the Allowable Values are specified for each RPS trip Function in the 

LCO. Nominal trip setpoints are specified in the plant specific setpoint 

calculations. The nominal setpoints are selected to ensure the setpoints 

measured by CHANNEL FUNCTIONAL TESTS do not exceed the 

Allowable Value if the bistable is performing as required. Operation with 

a trip setpoint less conservative than the nominal trip setpoint, but within 

its Allowable Value, is acceptable, provided that operation and testing are 

consistent with the assumptions of the plant specific setpoint calculations. 

Each Allowable Value specified is more conservative than the analytical 

limit assumed in the safety analysis in order to account for instrument 

uncertainties appropriate to the trip Function. These uncertainties are 

defined in the "Plant Protection System Selection of Trip Setpoint Values" 

(Ref. 7). 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-18 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The following Bases for each trip Function identify the above RPS trip 

Function criteria items that are applicable to establish the trip Function 

OPERABILITY. 

1. Variable High Power Trip (VHPT) - High

This LCO requires all four channels of the VHPT to be OPERABLE in 

MODES 1 and 2. 

The Allowable Value is high enough to provide an operating envelope 

that prevents unnecessary Linear Power Level - High reactor VHPT - 

High trips during normal plant operations. The Allowable Value is low 

enough for the system to maintain a margin to unacceptable fuel 

cladding damage should a CEA ejection accident occur. 

The VHPT setpoint is operator adjustable and can be set at a fixed 

increment above the indicated THERMAL POWER level. Operator 

action is required to increase the trip setpoint as THERMAL POWER 

is increased. The trip setpoint is automatically decreased as 

THERMAL POWER decreases. The trip setpoint has a maximum 

and a minimum setpoint. 

Adding to this maximum value the possible variation in trip setpoint 

due to calibration and instrument errors, the maximum actual steady 

state THERMAL POWER level at which a trip would be actuated is 

112% RTP, which is the value used in the safety analyses. 

To account for these errors, the safety analysis minimum value is 

40% RTP. The 10% step is a maximum value assumed in the safety 

analysis. There is no uncertainty applied to the step. 

2. Power Rate of Change - High

This LCO requires four channels of Power Rate of Change - High to 

be OPERABLE in MODES 1 and 2, as well as in MODES 3, 4, and 5 

when the RTCBs are closed and the CEA Drive System is capable of 

CEA withdrawal. 

The high power rate of change trip serves as a backup to the 

administratively enforced startup rate limit. The Function is not 

credited in the accident analyses; therefore, the Allowable Value for 

the trip or bypass Functions is not derived from analytical limits. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-19 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

3. Reactor Coolant Flow - Low

This LCO requires four channels of Reactor Coolant Flow - Low to be 

OPERABLE in MODES 1 and 2. 

The trip may be manually bypassed when THERMAL POWER falls 

below 1E-4% RTP. This bypass is part of the ZPMB circuitry, which 

also bypasses the TM/LP trip and provides a ∆T power block signal 

to the Q power select logic. This ZPMB allows low power physics 

testing at reduced RCS temperatures and pressures. It also allows 

heatup and cooldown with shutdown CEAs withdrawn. 

This trip is set high enough to maintain fuel integrity during a loss of 

flow condition. The setting is low enough to allow for normal 

operating fluctuations from offsite power. To account for analysis 

uncertainty, the value in the safety analysis is 93% RTP. 

4. Pressurizer Pressure - High

This LCO requires four channels of Pressurizer Pressure - High to be 

OPERABLE in MODES 1 and 2. 

The Allowable Value is set high enough to allow for pressure 

increases in the RCS during normal operation (i.e., plant transients) 

not indicative of an abnormal condition. The setting is below the lift 

setpoint of the pressurizer safety valves and low enough to initiate a 

reactor trip when an abnormal condition is indicated. The difference 

between the Allowable Value and the analysis setpoint of 2470 psia 

includes allowance for harsh environment. 

The Pressurizer Pressure - High trip concurrent with PORV operation 

avoids unnecessary operation of the pressurizer safety valves. 

5. Containment Pressure - High

This LCO requires four channels of Containment Pressure - High to 

be OPERABLE in MODES 1 and 2. 

The Allowable Value is high enough to allow for small pressure 

increases in containment expected during normal operation (i.e., 

plant heatup) that are not indicative of an abnormal condition. The 

setting is low enough to initiate a reactor trip to prevent containment 

pressure from exceeding design pressure following a DBA. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-20 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

6. Steam Generator Pressure - Low

This LCO requires four channels of Steam Generator Pressure - Low 

per steam generator to be OPERABLE in MODES 1 and 2. 

The Allowable Value is sufficiently below the full load operating value 

for steam pressure so as not to interfere with normal plant operation, 

but still high enough to provide the required protection in the event of 

excessive steam demand. Since excessive steam demand causes 

the RCS to cool down, resulting in positive reactivity addition to the 

core, a reactor trip is required to offset that effect. 

The difference between the Allowable Value and the safety analysis 

value of 600 psia includes harsh environment uncertainties. 

The Function may be manually bypassed as steam generator 

pressure is reduced during controlled plant shutdowns. This bypass 

is permitted at a preset steam generator pressure. The bypass, in 

conjunction with the ZPMB, allows testing at low temperatures and 

pressures, and heatup and cooldown with the shutdown CEAs 

withdrawn. From a bypass condition the trip will be reinstated 

automatically as steam generator pressure increases above the 

preset pressure. 

7.a, 7.b. Steam Generator Level – Low

This LCO requires four channels of Steam Generator Level - Low per 

steam generator to be OPERABLE in MODES 1 and 2. 

The Allowable Value is sufficiently below the normal operating level 

for the steam generators so as not to cause a reactor trip during 

normal plant operations. The trip setpoint is high enough to ensure a 

reactor trip signal is generated before water level drops below the top 

of the feed ring. The difference between the Allowable Value and the 

measurement value includes 10 inches of measurement uncertainty. 

The specified setpoint ensures there will be sufficient water inventory 

to provide a 10 minute margin before auxiliary feedwater is required 

for the removal of decay heat. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-21 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

8. Axial Power Distribution (APD) - High

This LCO requires four channels of APD - High to be OPERABLE in 

MODE 1 ≥ 15% RTP. 

The Allowable Value curve was derived from an analysis of many 

axial power shapes with allowances for instrumentation inaccuracies 

and the uncertainty associated with the excore to incore ASI 

relationship. 

The APD trip is automatically bypassed at < 15% RTP, where it is not 

required for reactor protection. 

9. Thermal Margin

a. Thermal Margin/Low Pressure (TM/LP)

This LCO requires four channels of TM/LP to be OPERABLE in 

MODES 1 and 2. 

The Allowable Value includes allowances for equipment 

response time, measurement uncertainties, processing error, 

and a further allowance to compensate for the time delay 

associated with providing effective termination of the occurrence 

that exhibits the most rapid decrease in margin to the SL. 

This trip may be manually bypassed when THERMAL POWER 

falls below 1E-4% RTP. This bypass is part of the ZPMB 

circuitry, which also bypasses the Reactor Coolant Flow - Low 

trip and provides a ∆T power block signal to the Q power select 

logic. This ZPMB allows low power physics testing at reduced 

RCS temperatures and pressures. It also allows heatup and 

cooldown with shutdown CEAs withdrawn. 

b. Steam Generator Pressure Difference

This LCO requires four channels of Steam Generator Pressure 

Difference to be OPERABLE in MODES 1 and 2. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-22 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The Allowable Value is high enough to avoid trips caused by 

normal operation and minor transients, but ensures DNBR 

protection in the event of Design Basis Events. The difference 

between the Allowable Value and the 175 psia analysis setpoint 

allows for 40 psia of measurement uncertainty. 

The trip may be bypassed when THERMAL POWER falls below 

1E-4% RTP. The Steam Generator Pressure Difference is 

subject to the ZPMB, since it is an input to the TM/LP trip and is 

not required for protection at low power levels. 

10. Loss of Load

The LCO requires four Loss of Load trip channels to be OPERABLE 

in MODE 1 ≥ 15% RTP. 

The Loss of Load trip may be bypassed when THERMAL POWER 

falls below 15%, since it is no longer needed to prevent lifting of the 

pressurizer safety valves, steam generator safety valves, or PORVs 

in the event of a Loss of Load. The Nuclear Steam Supply System 

and the Steam Dump System are capable of accommodating the 

Loss of Load without requiring the use of the above equipment. 

Interlocks/Bypasses

The LCO on bypass permissive removal channels requires that the 

automatic bypass removal feature of all four operating bypass channels 

be OPERABLE for each RPS Function with an operating bypass in the 

MODES addressed in the specific LCO for each Function. All four bypass 

removal channels must be OPERABLE to ensure that none of the four 

RPS channels are inadvertently bypassed. 

The LCO applies to the bypass removal feature only. If the bypass 

enable Function is failed so as to prevent entering a bypass condition, 

operation may continue. 

The interlock Allowable Values are based on analysis requirements for 

the bypassed functions. These are discussed above as part of the LCO 

discussion for the affected Functions. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-23 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY This LCO is applicable in accordance with Table 3.3.1-1. Most RPS trips 

are required to be OPERABLE in MODES 1 and 2 because the reactor is 

critical in these MODES. The trips are designed to take the reactor 

subcritical, maintaining the SLs during AOOs and assisting the ESFAS in 

providing acceptable consequences during accidents. Exceptions are 

addressed in footnotes to the table. Exceptions to this APPLICABILITY 

are: 

• The APD - High Trip and Loss of Load are only applicable in MODE 1 

≥ 15% RTP because they may be automatically bypassed at 

< 15% RTP, where they are no longer needed. 

• The Power Rate of Change - High trip, RPS Logic, RTCBs, and 

Manual Trip are also required in MODES 3, 4, and 5, with the RTCBs 

closed, to provide protection for boron dilution and CEA withdrawal 

events. The Power Rate of Change - High trip in these lower 

MODES is addressed in LCO 3.3.2, "Reactor Protective System 

(RPS) Instrumentation - Shutdown." The RPS Logic in MODES 1, 2, 

3, 4, and 5 is addressed in LCO 3.3.3. 

Most trips are not required to be OPERABLE in MODES 3, 4, and 5. In 

MODES 3, 4, and 5, the emphasis is placed on return to power events. 

The reactor is protected in these MODES by ensuring adequate SDM. 

ACTIONS The most common causes of channel inoperability are outright failure or 

drift of the bistable or process module sufficient to exceed the tolerance 

allowed by the plant specific setpoint analysis. Typically, the drift is found 

to be small and results in a delay of actuation rather than a total loss of 

function. This determination is generally made during the performance of 

a CHANNEL FUNCTIONAL TEST when the process instrument is set up 

for adjustment to bring it to within specification. If the trip setpoint is less 

conservative than the Allowable Value in Table 3.3.1-1, the channel is 

declared inoperable immediately, and the appropriate Condition(s) must 

be entered immediately. 

In the event a channel's trip setpoint is found nonconservative with 

respect to the Allowable Value, or the transmitter, instrument loop, signal 

processing electronics, or RPS bistable trip unit is found inoperable, then 

all affected Functions provided by that channel must be declared 

inoperable, and the plant must enter the Condition for the particular 

protection Function affected. 

When the number of inoperable channels in a trip Function exceeds that 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 is 

immediately entered if applicable in the current MODE of operation. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-24 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

A Note has been added to the ACTIONS to clarify the application of the 

Completion Time rules. The Conditions of this Specification may be 

entered independently for each Function. The Completion Times of each 

inoperable Function will be tracked separately for each Function, starting 

from the time the Condition was entered. 

A.1, A.2.1, and A.2.2

Condition A applies to the failure of a single channel in any RPS 

automatic trip Function. RPS coincidence logic is normally two-out-offour. 

If one RPS bistable trip unit or associated instrument channel is 

inoperable, startup or power operation is allowed to continue, providing 

the inoperable trip unit is placed in bypass or trip within 1 hour (Required 

Action A.1). With one channel in bypass, no additional random failure of 

a single channel could spuriously trip the reactor and a valid trip signal 

can still trip the reactor. With one channel in trip, an additional random 

failure of a single channel could spuriously trip the reactor. Therefore, it 

is preferable to place an inoperable channel in bypass rather than trip. 

The Completion Time of 1 hour allotted to restore, bypass, or trip the 

channel is sufficient to allow the operator to take all appropriate actions 

for the failed channel while ensuring that the risk involved in operating 

with the failed channel is acceptable. 

The failed channel is restored to OPERABLE status or is placed in trip 

within [48] hours (Required Action A.2.1 or Required Action A.2.2). 

Required Action A.2.1 restores the full capability of the Function. 

[ Required Action A.2.2 places the Function in a one-out-of-three 

configuration. In this configuration, common cause failure of dependent 

channels cannot prevent trip. ]

The Completion Time of [48] hours is based on operating experience, 

which has demonstrated that a random failure of a second channel 

occurring during the [48] hour period is a low probability event. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-25 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1 and B.2

Condition B applies to the failure of two channels in any RPS automatic 

trip Function. 

Required Action B.1 provides for placing one inoperable channel in 

bypass and the other channel in trip within the Completion Time of 1 hour. 

This Completion Time is sufficient to allow the operator to take all 

appropriate actions for the failed channels while ensuring that the risk 

involved in operating with the failed channels is acceptable. With one 

channel of protective instrumentation bypassed, the RPS is in a two-outof-three logic; but with another channel failed, the RPS may be operating 

in a two-out-of-two logic. This is outside the assumptions made in the 

analyses and should be corrected. To correct the problem, the second 

channel is placed in trip. This places the RPS in a one-out-of-two logic. If 

any of the other OPERABLE channels receives a trip signal, the reactor 

will trip. 

One channel should be restored to OPERABLE status within [48] hours 

for reasons similar to those stated under Condition A. After one channel 

is restored to OPERABLE status, the provisions of Condition A still apply 

to the remaining inoperable channel. Therefore, the channel that is still 

inoperable after completion of Required Action B.2 must be placed in trip 

if more than [48] hours have elapsed since the initial channel failure. 

C.1 and C.2

The excore detectors are used to generate the internal ASI used as an 

input to the TM/LP and APD - High trips. Incore detectors provide a more 

accurate measurement of ASI. If one or more excore detectors cannot be 

calibrated to match incore detectors, power is restricted or reduced during 

subsequent operations because of increased uncertainty associated with 

using uncalibrated excore detectors. 

The Completion Time of 24 hours is adequate to perform the SR while 

minimizing the risk of operating in an unsafe condition. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-26 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

D.1, D.2.1, D.2.2.1, and D.2.2.2

Condition D applies to one automatic bypass removal channel inoperable. 

If the bypass removal channel for any operating bypass cannot be 

restored to OPERABLE status, the associated RPS channel may be 

considered OPERABLE only if the bypass is not in effect. Otherwise, the 

affected RPS channel must be declared inoperable, as in Condition A, 

and the bypass either removed or the bypass removal channel repaired. 

The Bases for Required Actions and Completion Times are the same as 

discussed for Condition A. 

E.1, E.2.1, and E.2.2

Condition E applies to two inoperable automatic bypass removal 

channels. If the bypass removal channels cannot be restored to 

OPERABLE status, the associated RPS channel may be considered 

OPERABLE only if the bypass is not in effect. Otherwise, the affected 

RPS channels must be declared inoperable, as in Condition B, and the 

bypass either removed or the bypass removal channel repaired. Also, 

Required Action E.2.2 provides for the restoration of the one affected 

automatic trip channel to OPERABLE status within the rules of 

Completion Time specified under Condition B. Completion Times are 

consistent with Condition B. 

F.1

Condition F is entered when the Required Action and associated 

Completion Time of Conditions A, B, C, D, or E are not met for the Axial 

Power Distribution and Loss of Load Trip Functions. 

If the Required Actions associated with these Conditions cannot be 

completed within the required Completion Times, the reactor must be 

brought to a MODE in which the Required Actions do not apply. The 

allowed Completion Time of 6 hours to reduce THERMAL POWER to 

< 15% RTP is reasonable, based on operating experience, to decrease 

power to < 15% RTP from full power conditions in an orderly manner and 

without challenging plant systems. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-27 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

G.1

Condition G is entered when the Required Action and associated 

Completion Time of Conditions A, B, C, D, E, or F are not met. 

If the Required Actions associated with these Conditions cannot be 

completed within the required Completion Times, the reactor must be 

brought to a MODE in which the Required Actions do not apply. The 

allowed Completion Time of 6 hours to be in MODE 3 is reasonable, 

based on operating experience, for reaching the required MODE from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE The SRs for any particular RPS Function are found in the SR column of 

REQUIREMENTS Table 3.3.1-1 for that Function. Most Functions are subject to CHANNEL 

CHECK, CHANNEL FUNCTIONAL TEST, CHANNEL CALIBRATION, 

and response time testing. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

In order for a plant to take credit for topical reports as the basis for 

justifying Frequencies, topical reports must be supported by an NRC staff 

SER that establishes the acceptability of each topical report for that plant 

(Ref. 9). 

-------------------------------------------------------------------------------------------------- 

SR 3.3.1.1

Performance of the CHANNEL CHECK once every 12 hours ensures that 

gross failure of instrumentation 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 or of something even more serious. CHANNEL 

CHECK will detect gross channel failure; thus, it is key to verifying that 

the instrumentation continues to operate properly between each 

CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the transmitter or the signal processing equipment has drifted outside 

its limits. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-28 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The Frequency, about once every shift, is based on operating experience 

that demonstrates the rarity of channel failure. Since the probability of 

two random failures in redundant channels in any 12 hour period is 

extremely low, the CHANNEL CHECK minimizes the chance of loss of 

protective function due to failure of redundant channels. The CHANNEL 

CHECK supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of the displays associated 

with the LCO required channels. 

SR 3.3.1.2

A daily calibration (heat balance) is performed when THERMAL POWER 

is ≥ 20%. The daily calibration shall consist of adjusting the "nuclear 

power calibrate" potentiometers to agree with the calorimetric calculation 

if the absolute difference is > 1.5%. The "∆T power calibrate" 

potentiometers are then used to null the "nuclear power - ∆T power" 

indicators on the RPS Reactor Power Calibration and Indication panel. 

Performance of the daily calibration ensures that the two inputs to the 

Q power measurement are indicating accurately with respect to the much 

more accurate secondary calorimetric calculation. 

The Frequency of 24 hours is based on plant operating experience and 

takes into account indications and alarms located in the control room to 

detect deviations in channel outputs. The Frequency is modified by a 

Note indicating this Surveillance must be performed within 12 hours after 

THERMAL POWER is ≥ 20% RTP. The secondary calorimetric is 

inaccurate at lower power levels. The 12 hours allows time requirements 

for plant stabilization, data taking, and instrument calibration. 

A second Note indicates the daily calibration may be suspended during 

PHYSICS TESTS. This ensures that calibration is proper preceding and 

following physics testing at each plateau, recognizing that during testing, 

changes in power distribution and RCS temperature may render the 

calorimetric inaccurate. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-29 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.1.3

It is necessary to calibrate the excore power range channel upper and 

lower subchannel amplifiers such that the internal ASI used in the TM/LP 

and APD - High trips reflects the true core power distribution as 

determined by the incore detectors. A Note to the Frequency indicates 

the Surveillance is required within 12 hours after THERMAL POWER is 

≥ [20]% RTP. Uncertainties in the excore and incore measurement 

process make it impractical to calibrate when THERMAL POWER is 

< [20]% RTP. The Completion Time of 12 hours allows time for plant 

stabilization, data taking, and instrument calibration. If the excore 

detectors are not properly calibrated to agree with the incore detectors, 

power is restricted during subsequent operations because of increased 

uncertainty associated with using uncalibrated excore detectors. The 

31 day Frequency is adequate, based on operating experience of the 

excore linear amplifiers and the slow burnup of the detectors. The excore 

readings are a strong function of the power produced in the peripheral 

fuel bundles and do not represent an integrated reading across the core. 

Slow changes in neutron flux during the fuel cycle can also be detected at 

this Frequency. 

SR 3.3.1.4

A CHANNEL FUNCTIONAL TEST is performed on each RPS instrument 

channel, except Loss of Load and Power Rate of Change, every [92] days 

to ensure the entire channel will perform its intended function when 

needed. A successful test of the required contact(s) of a channel relay 

may be performed by the verification of the change of state of a single 

contact of the relay. This clarifies what is an acceptable CHANNEL 

FUNCTIONAL TEST of a relay. This is acceptable because all of the 

other required contacts of the relay are verified by other Technical 

Specifications and non-Technical Specifications tests at least once per 

refueling interval with applicable extensions. 

In addition to power supply tests, The RPS CHANNEL FUNCTIONAL 

TEST consists of three overlapping tests as described in Reference 8. 

These tests verify that the RPS is capable of performing its intended 

function, from bistable input through the RTCBs. They include: 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-30 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Bistable Tests

The bistable setpoint must be found to trip within the Allowable Values 

specified in the LCO and left set consistent with the assumptions of the 

plant specific setpoint analysis (Ref. 7). As found and as left values must 

also be recorded and reviewed for consistency with the assumptions of 

the frequency extension analysis. The requirements for this review are 

outlined in Reference 10. 

A test signal is superimposed on the input in one channel at a time to 

verify that the bistable trips within the specified tolerance around the 

setpoint. This is done with the affected RPS channel trip channel 

bypassed. Any setpoint adjustment shall be consistent with the 

assumptions of the current plant specific setpoint analysis. 

Matrix Logic Tests

Matrix Logic tests are addressed in LCO 3.3.3. This test is performed 

one matrix at a time. It verifies that a coincidence in the two input 

channels for each Function removes power from the matrix relays. 

During testing, power is applied to the matrix relay test coils and prevents 

the matrix relay contacts from assuming their de-energized state. This 

test will detect any short circuits around the bistable contacts in the 

coincidence logic, such as may be caused by faulty bistable relay or trip 

channel bypass contacts. 

Trip Path Tests

Trip Path (Initiation Logic) tests are addressed in LCO 3.3.3. These tests 

are similar to the Matrix Logic tests, except that test power is withheld 

from one matrix relay at a time, allowing the initiation circuit to deenergize, opening the affected set of RTCBs. The RTCBs must then be 

closed prior to testing the other three initiation circuits, or a reactor trip 

may result. 

The Frequency of [92] days is based on the reliability analysis presented 

in topical report CEN-327, "RPS/ESFAS Extended Test Interval 

Evaluation" (Ref. 10). 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-31 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.1.5

A CHANNEL CALIBRATION of the excore power range channels every 

92 days ensures that the channels are reading accurately and within 

tolerance. The Surveillance verifies that the channel responds to a 

measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive tests. CHANNEL 

CALIBRATIONS must be performed consistent with the plant specific 

setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the frequency extension analysis. 

The requirements for this review are outlined in Reference [10]. 

A Note is added stating that the neutron detectors are excluded from 

CHANNEL CALIBRATION because they are passive devices with 

minimal drift and because of the difficulty of simulating a meaningful 

signal. Slow changes in detector sensitivity are compensated for by 

performing the daily calorimetric calibration (SR 3.3.1.2) and the monthly 

linear subchannel gain check (SR 3.3.1.3). In addition, associated control 

room indications are continuously monitored by the operators. 

The Frequency of 92 days is acceptable, based on plant operating 

experience, and takes into account indications and alarms available to the 

operator in the control room. 

SR 3.3.1.6

A CHANNEL FUNCTIONAL TEST on the Loss of Load and Power Rate 

of Change channels is performed prior to a reactor startup to ensure the 

entire channel will perform its intended function if required. A successful 

test of the required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. The Loss of Load pressure sensor cannot be tested during 

reactor operation without closing the high pressure TSV, which would 

result in a turbine trip or reactor trip. The Power Rate of Change - High 

trip Function is required during startup operation and is bypassed when 

shut down or > 15% RTP. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-32 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.1.7

SR 3.3.1.7 is a CHANNEL FUNCTIONAL TEST similar to SR 3.3.1.4, 

except SR 3.3.1.7 is applicable only to bypass Functions and is 

performed once within 92 days prior to each startup. A successful test of 

the required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. Proper operation of bypass permissives is critical during 

plant startup because the bypasses must be in place to allow startup 

operation and must be removed at the appropriate points during power 

ascent to enable certain reactor trips. Consequently, the appropriate time 

to verify bypass removal function OPERABILITY is just prior to startup. 

The allowance to conduct this test within 92 days of startup is based on 

the reliability analysis presented in topical report CEN-327, "RPS/ESFAS 

Extended Test Interval Evaluation" (Ref. 10). Once the operating 

bypasses are removed, the bypasses must not fail in such a way that the 

associated trip Function gets inadvertently bypassed. This feature is 

verified by the trip Function CHANNEL FUNCTIONAL TEST, SR 3.3.1.4. 

Therefore, further testing of the bypass function after startup is 

unnecessary. 

SR 3.3.1.8

SR 3.3.1.8 is the performance of a CHANNEL CALIBRATION every 

[18] months. 

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the sensor. The Surveillance verifies that the channel responds 

to a measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive tests. CHANNEL 

CALIBRATIONS must be performed consistent with the plant specific 

setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the frequency extension analysis. 

The requirements for this review are outlined in Reference [10]. 

The Frequency is based upon the assumption of an 18 month calibration 

interval for the determination of the magnitude of equipment drift. 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-33 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The Surveillance is modified by a Note to indicate that the neutron 

detectors are excluded from CHANNEL CALIBRATION because they are 

passive devices with minimal drift and because of the difficulty of 

simulating a meaningful signal. Slow changes in detector sensitivity are 

compensated for by performing the daily calorimetric calibration 

(SR 3.3.1.2) and the monthly linear subchannel gain check (SR 3.3.1.3). 

SR 3.3.1.9

This SR ensures that the RPS RESPONSE TIMES are verified to be less 

than or equal to the maximum values assumed in the safety analysis. 

Individual component response times are not modeled in the analyses. 

The analyses model the overall or total elapsed time from the point at 

which the parameter exceeds the trip setpoint value at the sensor to the 

point at which the RTCBs open. Response times are conducted on an 

[18] month STAGGERED TEST BASIS. This results in the interval 

between successive surveillances of a given channel of n x 18 months, 

where n is the number of channels in the function. The Frequency of 

[18] months is based upon operating experience, which has shown that 

random failures of instrumentation components causing serious response 

time degradation, but not channel failure, are infrequent occurrences. 

Also, response times cannot be determined at power, since equipment 

operation is required. Testing may be performed in one measurement or 

in overlapping segments, with verification that all components are tested. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Applicable portions of the following TS Bases are applicable to plants 

adopting CEOG Topical Report CE NPSD-1167-1, "Elimination of 

Pressure Sensor Response Time Testing Requirements." 

-------------------------------------------------------------------------------------------------- 

Response time may be verified by any series of sequential, overlapping 

or total channel measurements, including allocated sensor response time, 

such that the response time is verified. Allocations for sensor response 

times may be obtained from records of test results, vendor test data, or 

vendor engineering specifications. Topical Report CE NPSD-1167-A, 

"Elimination of Pressure Sensor Response Time Testing Requirements," 

(Ref. 11) provides the basis and methodology for using allocated sensor 

response times in the overall verification of the channel response time for 

specific sensors identified in the Topical Report. Response time 

verification for other sensor types must be demonstrated by test. The 

allocation of sensor response times must be verified prior to placing a 

new component in operation and reverified after maintenance that may 

adversely affect the sensor response time.
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-34 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

A Note is added to indicate that the neutron detectors are excluded from 

RPS RESPONSE TIME testing because they are passive devices with 

minimal drift and because of the difficulty of simulating a meaningful 

signal. Slow changes in detector sensitivity are compensated for by 

performing the daily calorimetric calibration (SR 3.3.1.2). 

REFERENCES 1. Regulatory Guide 1.105, Revision 3, "Setpoints for Safety-Related 

Instrumentation." 

 2. 10 CFR 50, Appendix A, GDC 21. 

 3. 10 CFR 100. 

4. IEEE Standard 279-1971, April 5, 1972. 

 5. FSAR, Chapter [14]. 

 6. 10 CFR 50.49. 

 7. "Plant Protection System Selection of Trip Setpoint Values." 

 8. FSAR, Section [7.2]. 

 9. NRC Safety Evaluation Report, [Date]. 

 10. CEN-327, June 2, 1986, including Supplement 1, March 3, 1989. 

11. CEOG Topical Report CE NPSD-1167-A, "Elimination of Pressure 

Sensor Response Time Testing Requirements." 
RPS Instrumentation - Operating (Analog) 

B 3.3.1 

CEOG STS B 3.3.1-35 Rev. 3.0, 03/31/04 

BASES 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.1 Reactor Protective System (RPS) Instrumentation - Operating (Digital) 

BASES 

BACKGROUND The RPS initiates a reactor trip to protect against violating the core 

specified acceptable fuel design limits and breaching the reactor coolant 

pressure boundary (RCPB) during anticipated operational occurrences 

(AOOs). By tripping the reactor, the RPS also assists the Engineered 

Safety Features (ESF) systems in mitigating accidents. 

The protection and monitoring systems have been designed to ensure 

safe operation of the reactor. This is achieved by specifying limiting 

safety system settings (LSSS) in terms of parameters directly monitored 

by the RPS, as well as LCOs on other reactor system parameters and 

equipment performance. 

Technical Specifications are required by 10 CFR 50.36 to contain LSSS 

defined by the regulation as "...settings for automatic protective 

devices...so chosen that automatic protective actions will correct the 

abnormal situation before a Safety Limit (SL) is exceeded." The Analytic 

Limit is the limit of the process variable at which a safety action is 

initiated, as established by the safety analysis, to ensure that a SL is not 

exceeded. Any automatic protection action that occurs on reaching the 

Analytic Limit therefore ensures that the SL is not exceeded. However, in 

practice, the actual settings for automatic protective devices must be 

chosen to be more conservative than the Analytic Limit to account for 

instrument loop uncertainties related to the setting at which the automatic 

protective action would actually occur. 

The trip setpoint is a predetermined setting for a protective device chosen 

to ensure automatic actuation prior to the process variable reaching the 

Analytic Limit and thus ensuring that the SL would not be exceeded. As 

such, the trip setpoint accounts for uncertainties in setting the device 

(e.g., calibration), uncertainties in how the device might actually perform 

(e.g., repeatability), changes in the point of action of the device over time 

(e.g., drift during surveillance intervals), and any other factors which may 

influence its actual performance (e.g., harsh accident environments). In 

this manner, the trip setpoint plays an important role in ensuring that SLs 

are not exceeded. As such, the trip setpoint meets the definition of an 

LSSS (Ref. 1) and could be used to meet the requirement that they be 

contained in the Technical Specifications. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Technical Specifications contain values related to the OPERABILITY of 

equipment required for safe operation of the facility. OPERABLE is 

defined in Technical Specifications as "...being capable of performing its 

safety function(s)." For automatic protective devices, the required safety 

function is to ensure that a SL is not exceeded and therefore the LSSS as 

defined by 10 CFR 50.36 is the same as the OPERABILITY limit for these 

devices. However, use of the trip setpoint to define OPERABILITY in 

Technical Specifications and its corresponding designation as the LSSS 

required by 10 CFR 50.36 would be an overly restrictive requirement if it 

were applied as an OPERABILITY limit for the "as found" value of a 

protective device setting during a Surveillance. This would result in 

Technical Specification compliance problems, as well as reports and 

corrective actions required by the rule which are not necessary to ensure 

safety. For example, an automatic protective device with a setting that 

has been found to be different from the trip setpoint due to some drift of 

the setting may still be OPERABLE since drift is to be expected. This 

expected drift would have been specifically accounted for in the setpoint 

methodology for calculating the trip setpoint and thus the automatic 

protective action would still have ensured that the SL would not be 

exceeded with the "as found" setting of the protective device. Therefore, 

the device would still be OPERABLE since it would have performed its 

safety function and the only corrective action required would be to reset 

the device to the trip setpoint to account for further drift during the next 

surveillance interval. 

Use of the trip setpoint to define "as found" OPERABILITY and its 

designation as the LSSS under the expected circumstances described 

above would result in actions required by both the rule and Technical 

Specifications that are clearly not warranted. However, there is also 

some point beyond which the device would have not been able to perform 

its function due, for example, to greater than expected drift. This value 

needs to be specified in the Technical Specifications in order to define 

OPERABILITY of the devices and is designated as the Allowable Value 

which, as stated above, is the same as the LSSS. 

The Allowable Valuable specified in Table 3.3.1-1 serves as the LSSS 

such that a channel is OPERABLE if the trip setpoint is found not to 

exceed the Allowable Value. As such, the Allowable Value differs from 

the trip setpoint by an amount primarily equal to the expected instrument 

loop uncertainties, such as drift, during the surveillance interval. In this 

manner, the actual setting of the device will still meet the LSSS definition 

and ensure that a SL is not exceeded at any given point of time as long 

as the device has not drifted beyond that expected during the 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

surveillance interval. If the actual setting of the device is found to have 

exceeded the Allowable Value the device would be considered inoperable 

from a Technical Specification perspective. This requires corrective 

action including those actions required by 10 CFR 50.36 when automatic 

protective devices do not function as required. Note that, although the 

channel is "OPERABLE" under these circumstances, the trip setpoint 

should be left adjusted to a value within the established trip setpoint 

calibration tolerance band, in accordance with uncertainty assumptions 

stated in the referenced setpoint methodology (as-left criteria), and 

confirmed to be operating within the statistical allowances of the 

uncertainty terms assigned. 

During AOOs, which are those events expected to occur one or more 

times during the plant life, the acceptable limits are: 

• The departure from nucleate boiling ratio (DNBR) shall be maintained 

above the Safety Limit (SL) value to prevent departure from nucleate 

boiling (DNB), 

• Fuel centerline melting shall not occur, and 

• The Reactor Coolant System (RCS) pressure SL of 2750 psia shall 

not be exceeded. 

Maintaining the parameters within the above values ensures that the 

offsite dose will be within the 10 CFR 50 (Ref. 2) and 10 CFR 100 (Ref. 3) 

criteria during AOOs. 

Accidents are events that are analyzed even though they are not 

expected to occur during the plant life. The acceptable limit during 

accidents is that the offsite dose shall be maintained within an acceptable 

fraction of 10 CFR 100 (Ref. 3) limits. Different accident categories allow 

a different fraction of these limits based on probability of occurrence. 

Meeting the acceptable dose limit for an accident category is considered 

having acceptable consequences for that event. 

The RPS is segmented into four interconnected modules. These 

modules are: 

• Measurement channels, 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-4 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

• Bistable trip units, 

• RPS Logic, and 

• Reactor trip circuit breakers (RTCBs). 

This LCO addresses measurement channels and bistable trip units. It 

also addresses the automatic bypass removal feature for those trips with 

operating bypasses. The RPS Logic and RTCBs are addressed in 

LCO 3.3.4, "Reactor Protective System (RPS) Logic and Trip Initiation." 

The CEACs are addressed in LCO 3.3.3, "Control Element Assembly 

Calculators (CEACs)." 

Measurement Channels

Measurement channels, consisting of field transmitters or process 

sensors and associated instrumentation, provide a measurable electronic 

signal based upon the physical characteristics of the parameter being 

measured. 

The excore nuclear instrumentation, the core protection calculators 

(CPCs), and the CEACs, though complex, are considered components in 

the measurement channels of the Linear Power Level - High, Logarithmic 

Power Level - High, DNBR - Low, and Local Power Density (LPD) - High 

trips. 

Four identical measurement channels, designated channels A through D, 

with electrical and physical separation, are provided for each parameter 

used in the generation of trip signals, with the exception of the control 

element assembly (CEA) position indication used in the CPCs. Each 

measurement channel provides input to one or more RPS bistables within 

the same RPS channel. In addition, some measurement channels may 

also be used as inputs to Engineered Safety Features Actuation System 

(ESFAS) bistables, and most provide indication in the control room. 

Measurement channels used as an input to the RPS are not used for 

control functions. 

When a channel monitoring a parameter exceeds a predetermined 

setpoint, indicating an unsafe condition, the bistable monitoring the 

parameter in that channel will trip. Tripping bistables monitoring the same 

parameter in two or more channels will de-energize Matrix Logic, which in 

turn de-energizes the Initiation Logic. This causes all eight RTCBs to 

open, interrupting power to the CEAs, allowing them to fall into the core. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-5 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Three of the four measurement and bistable channels are necessary to 

meet the redundancy and testability of 10 CFR 50, Appendix A, GDC 21 

(Ref. 2). The fourth channel provides additional flexibility by allowing one 

channel to be removed from service (trip channel bypass) for 

maintenance or testing while still maintaining a minimum two-out-of-three 

logic. Thus, even with a channel inoperable, no single additional failure in 

the RPS can either cause an inadvertent trip or prevent a required trip 

from occurring. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

In order to take full advantage of the four channel design, adequate 

channel to channel independence must be demonstrated and approved 

by the NRC staff. Plants not currently licensed so as to credit four 

channel independence and that desire this capability must have approval 

of the NRC staff documented by an NRC Safety Evaluation Report (SER) 

(Ref. 4). 

-------------------------------------------------------------------------------------------------- 

Adequate channel to channel independence includes physical and 

electrical independence of each channel from the others. This allows 

operation in two-out-of-three logic with one channel removed from service 

until following the next MODE 5 entry. Since no single failure will either 

cause or prevent a protective system actuation, and no protective channel 

feeds a control, this arrangement meets the requirements of 

IEEE Standard 279-1971 (Ref. 5). 

The CPCs perform the calculations required to derive the DNBR and LPD 

parameters and their associated RPS trips. Four separate CPCs perform 

the calculations independently, one for each of the four RPS channels. 

The CPCs provide outputs to drive display indications (DNBR margin, 

LPD margin, and calibrated neutron flux power levels) and provide DNBR 

- Low and LPD - High pretrip and trip signals. The CPC channel outputs 

for the DNBR - Low and LPD - High trips operate contacts in the Matrix 

Logic in a manner identical to the other RPS trips. 

Each CPC receives the following inputs: 

• Hot leg and cold leg temperatures, 

• Pressurizer pressure, 

• Reactor coolant pump speed, 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-6 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

• Excore neutron flux levels, 

• Target CEA positions, and 

• CEAC penalty factors. 

Each CPC is programmed with "addressable constants." These are 

various alignment values, correction factors, etc., that are required for the 

CPC computations. They can be accessed for display or for the purpose 

of changing them as necessary. 

The CPCs use this constant and variable information to perform a number 

of calculations. These include the calculation of CEA group and 

subgroup deviations (and the assignment of conservative penalty factors), 

correction and calculation of average axial power distribution (APD) 

(based on excore flux levels and CEA positions), calculation of coolant 

flow (based on pump speed), and calculation of calibrated average power 

level (based on excore flux levels and ∆T power). 

The DNBR calculation considers primary pressure, inlet temperature, 

coolant flow, average power, APD, radial peaking factors, and CEA 

deviation penalty factors from the CEACs to calculate the state of the 

limiting (hot) coolant channel in the core. A DNBR - Low trip occurs when 

the calculated value reaches the minimum DNBR trip setpoint. 

The LPD calculation considers APD, average power, radial peaking 

factors (based upon target CEA position), and CEAC penalty factors to 

calculate the current value of compensated peak power density. An LPD 

- High trip occurs when the calculated value reaches the trip setpoint. 

The four CPC channels provide input to the four DNBR - Low and four 

LPD - High RPS trip channels. They effectively act as the sensor (using 

many inputs) for these trips. 

The CEACs perform the calculations required to determine the position of 

CEAs within their subgroups for the CPCs. Two independent CEACs 

compare the position of each CEA to its subgroup position. If a deviation 

is detected by either CEAC, an annunciator sounds and appropriate 

"penalty factors" are transmitted to all CPCs. These penalty factors 

conservatively adjust the effective operating margins to the DNBR - Low 

and LPD - High trips. Each CEAC also drives a single cathode ray tube 

(CRT), which is switchable between CEACs. The CRT displays individual 

CEA positions and current values of the penalty factors from the selected 

CEAC. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-7 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Each CEA has two separate reed switch assemblies mounted outside the 

RCPB. Each of the two CEACs receives CEA position input from one of 

the two reed switch position transmitters on each CEA, so that the 

position of all CEAs is independently monitored by both CEACs. 

CEACs are addressed in LCO 3.3.3. 

Bistable Trip Units

Bistable trip units, mounted in the Plant Protection System (PPS) cabinet, 

receive an analog input from the measurement channels. They compare 

the analog input to trip setpoints and provide contact output to the Matrix 

Logic. They also provide local trip indication and remote annunciation. 

There are four channels of bistables, designated A, B, C, and D, for each 

RPS parameter, one for each measurement channel. Bistables deenergize when a trip occurs, in turn de-energizing bistable relays 

mounted in the PPS relay card racks. 

The contacts from these bistable relays are arranged into six coincidence 

matrices, comprising the Matrix Logic. If bistables monitoring the same 

parameter in at least two channels trip, the Matrix Logic will generate a 

reactor trip (two-out-of-four logic). 

Some measurement channels provide contact outputs to the PPS. In 

these cases, there is no bistable card, and opening the contact input 

directly de-energizes the associated bistable relays. These include the 

Loss of Load trip and the CPC generated DNBR - Low and LPD - High 

trips. 

The trip setpoints used in the bistables are based on the analytical limits 

derived from the accident analysis (Ref. 6). The selection of these trip 

setpoints is such that adequate protection is provided when all sensor 

and processing time delays are taken into account. To allow for 

calibration tolerances, instrumentation uncertainties, instrument drift, and 

severe environment errors for those RPS channels that must function in 

harsh environments as defined by 10 CFR 50.49 (Ref. 7), Allowable 

Values specified in Table 3.3.1-1, in the accompanying LCO, are 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-8 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

conservatively adjusted with respect to the analytical limits. A detailed 

description of the methodology used to calculate the trip setpoints, 

including their explicit uncertainties, is provided in "Plant Protection 

System Selection of Trip Setpoint Values" (Ref. 8). The nominal trip 

setpoint entered into the bistable is normally still more conservative than 

that specified by the Allowable Value to account for changes in random 

measurement errors detectable by a CHANNEL FUNCTIONAL TEST. 

One example of such a change in measurement error is drift during the 

interval between surveillances. A channel is inoperable if its actual 

setpoint is not within its Allowable Value. 

Setpoints in accordance with the Allowable Value will ensure that SLs of 

Chapter 2.0, "SAFETY LIMITS (SLs)," are not violated during AOOs, and 

the consequences of DBAs will be acceptable, providing the plant is 

operated from within the LCOs at the onset of the AOO or DBA and the 

equipment functions as designed. 

Note that in LCO 3.3.1, the Allowable Values of Table 3.3.1-1 are the 

LSSS. 

Functional testing of the entire RPS, from bistable input through the 

opening of individual sets of RTCBs, can be performed either at power or 

shutdown and is normally performed on a quarterly basis. Nuclear 

instrumentation, the CPCs, and the CEACs can be similarly tested. 

FSAR, Section [7.2] (Ref. 9), provides more detail on RPS testing. 

Processing transmitter calibration is normally performed on a refueling 

basis. 

RPS Logic

The RPS Logic, addressed in LCO 3.3.4, consists of both Matrix and 

Initiation Logic and employs a scheme that provides a reactor trip when 

bistables in any two of the four channels sense the same input parameter 

trip. This is called a two-out-of-four trip logic. 

Bistable relay contact outputs from the four channels are configured into 

six logic matrices. Each logic matrix checks for a coincident trip in the 

same parameter in two bistable channels. The matrices are designated 

the AB, AC, AD, BC, BD, and CD matrices to reflect the bistable channels 

being monitored. Each logic matrix contains four normally energized 

matrix relays. When a coincidence is detected, consisting of a trip in the 

same Function in the two channels being monitored by the logic matrix, 

all four matrix relays de-energize. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-9 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The matrix relay contacts are arranged into trip paths, with one of the four 

matrix relays in each matrix opening contacts in one of the four trip paths. 

Each trip path provides power to one of the four normally energized 

RTCB control relays (K1, K2, K3, and K4). The trip paths thus each have 

six contacts in series, one from each matrix, and perform a logical OR

function, opening the RTCBs if any one or more of the six logic matrices 

indicate a coincidence condition. 

Each trip path is responsible for opening one set of two of the eight 

RTCBs. The RTCB control relays (K-relays), when de-energized, 

interrupt power to the breaker undervoltage trip attachments and 

simultaneously apply power to the shunt trip attachments on each of the 

two breakers. Actuation of either the undervoltage or shunt trip 

attachment is sufficient to open the RTCB and interrupt power from the 

motor generator (MG) sets to the control element drive mechanisms 

(CEDMs). 

When a coincidence occurs in two RPS channels, all four matrix relays in 

the affected matrix de-energize. This in turn de-energizes all four breaker 

control relays, which simultaneously de-energize the undervoltage and 

energize the shunt trip attachments in all eight RTCBs, tripping them 

open. 

Matrix Logic refers to the matrix power supplies, trip channel bypass 

contacts, and interconnecting matrix wiring between bistable relay cards, 

up to but not including the matrix relays. Matrix contacts on the bistable 

relay cards are excluded from the Matrix Logic definition, since they are 

addressed as part of the measurement channel. 

The Initiation Logic consists of the trip path power source, matrix relays 

and their associated contacts, all interconnecting wiring, and solid state 

(auxiliary) relays through the K-relay contacts in the RTCB control 

circuitry. 

It is possible to change the two-out-of-four RPS Logic to a two-out-ofthree logic for a given input parameter in one channel at a time by trip 

channel bypassing select portions of the Matrix Logic. Trip channel 

bypassing a bistable effectively shorts the bistable relay contacts in the 

three matrices associated with that channel. Thus, the bistables will 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-10 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

function normally, producing normal trip indication and annunciation, but a 

reactor trip will not occur unless two additional channels indicate a trip 

condition. Trip channel bypassing can be simultaneously performed on 

any number of parameters in any number of channels, providing each 

parameter is bypassed in only one channel at a time. An interlock 

prevents simultaneous trip channel bypassing of the same parameter in 

more than one channel. Trip channel bypassing is normally employed 

during maintenance or testing. 

Two-out-of-three logic also prevents inadvertent trips caused by any 

single channel failure in a trip condition. 

In addition to the trip channel bypasses, there are also operating 

bypasses on select RPS trips. These bypasses are enabled manually in 

all four RPS channels when plant conditions do not warrant the specific 

trip protection. All operating bypasses are automatically removed when 

enabling bypass conditions are no longer satisfied. Operating bypasses 

are normally implemented in the bistable, so that normal trip indication is 

also disabled. Trips with operating bypasses include Pressurizer 

Pressure - Low, Logarithmic Power Level - High, Reactor Coolant Flow - 

Low, and CPC (DNBR - Low and LPD - High). 

The Loss of Load trip bypass is automatically enabled and disabled. 

Reactor Trip Circuit Breakers (RTCBs)

The reactor trip switchgear, addressed in LCO 3.3.4, consists of eight 

RTCBs, which are operated in four sets of two breakers (four channels). 

Power input to the reactor trip switchgear comes from two full capacity 

MG sets operated in parallel, such that the loss of either MG set does not 

de-energize the CEDMs. There are two separate CEDM power supply 

buses, each bus powering half of the CEDMs. Power is supplied from the 

MG sets to each bus via two redundant paths (trip legs). Trip legs 1A and 

1B supply power to CEDM bus 1. Trip legs 2A and 2B supply power to 

CEDM bus 2. This ensures that a fault or the opening of a breaker in one 

trip leg (i.e., for testing purposes) will not interrupt power to the CEDM 

buses. 

Each of the four trip legs consists of two RTCBs in series. The two 

RTCBs within a trip leg are actuated by separate initiation circuits. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-11 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The eight RTCBs are operated as four sets of two breakers (four 

channels). For example, if a breaker receives an open signal in trip leg A 

(for CEDM bus 1), an identical breaker in trip leg B (for CEDM bus 2) will 

also receive an open signal. This arrangement ensures that power is 

interrupted to both CEDM buses, thus preventing trip of only half of the 

CEAs (a half trip). Any one inoperable breaker in a channel will make the 

entire channel inoperable. 

Each set of RTCBs is operated by either a manual reactor trip push 

button or an RPS actuated K-relay. There are four Manual Trip push 

buttons, arranged in two sets of two. Depressing both push buttons in 

either set will result in a reactor trip. 

When a Manual Trip is initiated using the control room push buttons, the 

RPS trip paths and K-relays are bypassed, and the RTCB undervoltage 

and shunt trip attachments are actuated independent of the RPS. 

Manual Trip circuitry includes the push button and interconnecting wiring 

to both RTCBs necessary to actuate both the undervoltage and shunt trip 

attachments but excludes the K-relay contacts and their interconnecting 

wiring to the RTCBs, which are considered part of the Initiation Logic. 

Functional testing of the entire RPS, from bistable input through the 

opening of individual sets of RTCBs, can be performed either at power or 

shutdown and is normally performed on a quarterly basis. FSAR, 

Section [7.2] (Ref. 9), explains RPS testing in more detail. 

APPLICABLE Design Basis Definition

SAFETY 

ANALYSES The RPS is designed to ensure that the following operational criteria are 

met: 

• The associated actuation will occur when the parameter monitored by 

each channel reaches its setpoint and the specific coincidence logic 

is satisfied, 

• Separation and redundancy are maintained to permit a channel to be 

out of service for testing or maintenance while still maintaining 

redundancy within the RPS instrumentation network. 

Each of the analyzed accidents and transients can be detected by one or 

more RPS Functions. The accident analysis takes credit for most of the 

RPS trip Functions. Those functions for which no credit is taken, termed 

equipment protective functions, are not needed from a safety perspective. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-12 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Each RPS setpoint is chosen to be consistent with the function of the 

respective trip. The basis for each trip setpoint falls into one of three 

general categories: 

Category 1: To ensure that the SLs are not exceeded during AOOs, 

Category 2: To assist the ESFAS during accidents, and 

Category 3: To prevent material damage to major plant components 

(equipment protective). 

The RPS maintains the SLs during AOOs and mitigates the 

consequences of DBAs in all MODES in which the RTCBs are closed. 

Each of the analyzed transients and accidents can be detected by one or 

more RPS Functions. Functions not specifically credited in the accident 

analysis are part of the NRC staff approved licensing basis for the plant. 

Noncredited Functions include the Loss of Load. This trip is purely 

equipment protective, and its use minimizes the potential for equipment 

damage. 

The specific safety analysis applicable to each protective function are 

identified below: 

1. Linear Power Level - High

The Linear Power Level - High trip provides protection against core 

damage during the following events: 

• Uncontrolled CEA Withdrawal From Low Power (AOO), 

• Uncontrolled CEA Withdrawal at Power (AOO), and 

• CEA Ejection (Accident). 

2. Logarithmic Power Level - High

The Logarithmic Power Level - High trip protects the integrity of the 

fuel cladding and helps protect the RCPB in the event of an 

unplanned criticality from a shutdown condition. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-13 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

In MODES 2, 3, 4, and 5, with the RTCBs closed and the CEA Drive 

System capable of CEA withdrawal, protection is required for CEA 

withdrawal events originating when logarithmic power is < 1E-4%. 

For events originating above this power level, other trips provide 

adequate protection. 

MODES 3, 4, and 5, with the RTCBs closed, are addressed in 

LCO 3.3.2, "Reactor Protective System (RPS) Instrumentation - 

Shutdown." 

In MODES 3, 4, or 5, with the RTCBs open or the CEAs not capable 

of withdrawal, the Logarithmic Power Level - High trip does not have 

to be OPERABLE. However, the indication and alarm portion of two 

logarithmic channels must be OPERABLE to ensure proper indication 

of neutron population and to indicate a boron dilution event. The 

indication and alarm functions are addressed in LCO 3.3.13, 

"[Logarithmic] Power Monitoring Channels." 

3. Pressurizer Pressure - High

The Pressurizer Pressure - High trip provides protection for the high 

RCS pressure SL. In conjunction with the pressurizer safety valves 

and the main steam safety valves (MSSVs), it provides protection 

against overpressurization of the RCPB during the following events: 

• Loss of Electrical Load Without a Reactor Trip Being Generated 

by the Turbine Trip (AOO), 

• Loss of Condenser Vacuum (AOO), 

• CEA Withdrawal From Low Power Conditions (AOO), 

• Chemical and Volume Control System Malfunction (AOO), and 

• Main Feedwater System Pipe Break (Accident). 

4. Pressurizer Pressure - Low

The Pressurizer Pressure - Low trip is provided to trip the reactor to 

assist the ESF System in the event of loss of coolant accidents 

(LOCAs). During a LOCA, the SLs may be exceeded; however, the 

consequences of the accident will be acceptable. A Safety Injection 

Actuation Signal (SIAS) and a Containment Isolation Actuation Signal 

(CIAS) are initiated simultaneously. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-14 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

5. Containment Pressure - High

The Containment Pressure - High trip prevents exceeding the 

containment design pressure psig during a design basis LOCA or 

main steam line break (MSLB) accident. During a LOCA or MSLB 

the SLs may be exceeded; however, the consequences of the 

accident will be acceptable. An SIAS and CIAS are initiated 

simultaneously. 

6, 7. Steam Generator Pressure - Low

The Steam Generator #1 Pressure - Low and Steam Generator #2 

Pressure - Low trips provide protection against an excessive rate of 

heat extraction from the steam generators and resulting rapid, 

uncontrolled cooldown of the RCS. This trip is needed to shut down 

the reactor and assist the ESF System in the event of an MSLB or 

main feedwater line break accident. A main steam isolation signal 

(MSIS) is initiated simultaneously. 

8, 9. Steam Generator Level – Low

The Steam Generator #1 Level - Low and Steam Generator #2 Level 

- Low trips ensure that a reactor trip signal is generated for the 

following events to help prevent exceeding the design pressure of the 

RCS due to the loss of the heat sink: 

• Inadvertent Opening of a Steam Generator Atmospheric Dump 

Valve (AOO), 

• Loss of Normal Feedwater Event (AOO), and 

• Feedwater System Pipe Break (Accident). 

10, 11. Reactor Coolant Flow – Low

The Reactor Coolant Flow, Steam Generator #1 - Low and Reactor 

Coolant Flow, Steam Generator #2 - Low trips provides protection 

against an RCP Sheared Shaft Event. The DNBR limit may be 

exceeded during this event; however, the trip ensures the 

consequences are acceptable. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-15 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

12. Loss of Load

The Loss of Load (turbine stop valve control oil pressure) is 

anticipatory for the loss of heat removal capabilities for the secondary 

system following a turbine trip. The Loss of Load trip prevents lifting 

the pressurizer safety valves and the main steam line safety valves in 

the event of a turbine generator trip. Thus, the trip minimizes the 

pressure or temperature transient on the reactor by initiating a trip 

well before the Pressurizer Pressure - High and safety valve 

setpoints are reached. 

The RPS Loss of Load reactor trip channels receive their input from 

sensors mounted on high pressure turbine stop valve (TSV) 

actuators. Since there are four TSVs, one actuator per TSV and one 

sensor per actuator, each sensor sends its signal to a different RPS 

channel. When the control oil pressure drops to the appropriate 

setpoint, a reactor trip signal is generated. 

13. Local Power Density – High

The CPCs perform the calculations required to derive the DNBR and 

LPD parameters and their associated RPS trips. The DNBR - Low 

and LPD - High trips provide plant protection during the following 

AOOs and assist the ESF systems in the mitigation of the following 

accidents. 

The LPD - High trip provides protection against fuel centerline 

melting due to the occurrence of excessive local power density peaks 

during the following AOOs: 

• Decrease in Feedwater Temperature, 

• Increase in Feedwater Flow, 

• Increased Main Steam Flow (not due to the steam line rupture) 

Without Turbine Trip, 

• Uncontrolled CEA Withdrawal From Low Power, 

• Uncontrolled CEA Withdrawal at Power, and 

• CEA Misoperation; Single Part Length CEA Drop. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-16 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

For the events listed above (except CEA Misoperation; Single Part 

Length CEA Drop), DNBR - Low will trip the reactor first, since DNB 

would occur before fuel centerline melting would occur. 

14. Departure from Nucleate Boiling Ratio (DNBR) - Low

The CPCs perform the calculations required to derive the DNBR and 

LPD parameters and their associated RPS trips. The DNBR - Low 

and LPD - High trips provide plant protection during the following 

AOOs and assist the ESF systems in the mitigation of the following 

accidents. 

The DNBR - Low trip provides protection against core damage due to 

the occurrence of locally saturated conditions in the limiting (hot) 

channel during the following events and is the primary reactor trip 

(trips the reactor first) for these events: 

• Decrease in Feedwater Temperature, 

• Increase in Feedwater Flow, 

• Increased Main Steam Flow (not due to steam line rupture) 

Without Turbine Trip, 

• Increased Main Steam Flow (not due to steam line rupture) With 

a Concurrent Single Failure of an Active Component, 

• Steam Line Break With Concurrent Loss of Offsite AC Power, 

• Loss of Normal AC Power, 

• Partial Loss of Forced Reactor Coolant Flow, 

• Total Loss of Forced Reactor Coolant Flow, 

• Single Reactor Coolant Pump (RCP) Shaft Seizure, 

• Uncontrolled CEA Withdrawal From Low Power, 

• Uncontrolled CEA Withdrawal at Power, 

• CEA Misoperation; Full Length CEA Drop, 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-17 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

• CEA Misoperation; Part Length CEA Subgroup Drop, 

• Primary Sample or Instrument Line Break, and 

• Steam Generator Tube Rupture. 

In the above list, only the steam generator tube rupture, the RCP 

shaft seizure, and the sample or instrument line break are accidents. 

The rest are AOOs. 

Interlocks/Bypasses

The bypasses and their Allowable Values are addressed in footnotes to 

Table 3.3.1-1. They are not otherwise addressed as specific Table 

entries. 

The automatic bypass removal features must function as a backup to 

manual actions for all safety related trips to ensure the trip Functions are 

not operationally bypassed when the safety analysis assumes the 

Functions are not bypassed. The basis for each of the operating 

bypasses is discussed under individual trips in the LCO section: 

a. Loss of Load, 

b. Logarithmic Power Level - High, 

c. Reactor Coolant Flow - Low, 

d. DNBR - Low and LPD - High, and 

e. Pressurizer Pressure - Low. 

The RPS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-18 Rev. 3.0, 03/31/04 

BASES 

LCO The LCO requires all instrumentation performing an RPS Function to be 

OPERABLE. Failure of any required portion of the instrument channel 

renders the affected channel(s) inoperable and reduces the reliability of 

the affected Functions. 

Actions allow maintenance (trip channel) bypass of individual channels, 

but the bypass activates interlocks that prevent operation with a second 

channel in the same Function bypassed. With one channel in each 

Function trip channel bypassed, this effectively places the plant in a twoout-of-three logic configuration in those Functions. 

Only the Allowable Values are specified for each RPS trip Function in the 

LCO. Nominal trip setpoints are specified in the plant specific setpoint 

calculations. The nominal setpoints are selected to ensure the setpoints 

measured by CHANNEL FUNCTIONAL TESTS do not exceed the 

Allowable Value if the bistable is performing as required. Operation with 

a trip setpoint less conservative than the nominal trip setpoint, but within 

its Allowable Value, is acceptable, provided that operation and testing are 

consistent with the assumptions of the plant specific setpoint calculations. 

A channel is inoperable if its actual trip setpoint is not within its required 

Allowable Value. Each Allowable Value specified is more conservative 

than the analytical limit assumed in the safety analysis in order to account 

for instrument uncertainties appropriate to the trip Function. These 

uncertainties are defined in the "Plant Protection System Selection of Trip 

Setpoint Values" (Ref. 8). 

The Bases for the individual Function requirements are as follows: 

1. Linear Power Level - High

This LCO requires all four channels of Linear Power Level - High to 

be OPERABLE in MODES 1 and 2. 

The Allowable Value is high enough to provide an operating envelope 

that prevents unnecessary Linear Power Level - High reactor trips 

during normal plant operations. The Allowable Value is low enough 

for the system to maintain a margin to unacceptable fuel cladding 

damage should a CEA ejection accident occur. 

2. Logarithmic Power Level - High

This LCO requires all four channels of Logarithmic Power Level - 

High to be OPERABLE in MODE 2, and in MODE 3, 4, or 5 when the 

RTCBs are shut and the CEA Drive System is capable of CEA 

withdrawal. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-19 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The MODES 3, 4, and 5 Condition is addressed in LCO 3.3.2. 

The Allowable Value is high enough to provide an operating envelope 

that prevents unnecessary Logarithmic Power Level - High reactor 

trips during normal plant operations. The Allowable Value is low 

enough for the system to maintain a margin to unacceptable fuel 

cladding damage should a CEA withdrawal event occur. 

The Logarithmic Power Level - High trip may be bypassed when 

logarithmic power is above 1E-4% to allow the reactor to be brought 

to power during a reactor startup. This bypass is automatically 

removed when logarithmic power decreases below 1E-4%. Above 

1E-4%, the Linear Power Level - High and Pressurizer Pressure - 

High trips provide protection for reactivity transients. 

The trip may be manually bypassed during physics testing pursuant 

to LCO 3.4.17, "RCS Loops - Test Exceptions." During this testing, 

the Linear Power Level - High trip and administrative controls provide 

the required protection. 

3. Pressurizer Pressure - High

This LCO requires four channels of Pressurizer Pressure - High to be 

OPERABLE in MODES 1 and 2. 

The Allowable Value is set below the nominal lift setting of the 

pressurizer code safety valves, and its operation avoids the 

undesirable operation of these valves during normal plant operation. 

In the event of a complete loss of electrical load from 100% power, 

this setpoint ensures the reactor trip will take place, thereby limiting 

further heat input to the RCS and consequent pressure rise. The 

pressurizer safety valves may lift to prevent overpressurization of the 

RCS. 

4. Pressurizer Pressure - Low

This LCO requires four channels of Pressurizer Pressure - Low to be 

OPERABLE in MODES 1 and 2. 

The Allowable Value is set low enough to prevent a reactor trip 

during normal plant operation and pressurizer pressure transients. 

However, the setpoint is high enough that with a LOCA, the reactor 

trip will occur soon enough to allow the ESF systems to perform as 

expected in the analyses and mitigate the consequences of the 

accident. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-20 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The trip setpoint may be manually decreased to a minimum value of 

300 psia as pressurizer pressure is reduced during controlled plant 

shutdowns, provided the margin between the pressurizer pressure 

and the setpoint is maintained < 400 psia. This allows for controlled 

depressurization of the RCS while still maintaining an active trip 

setpoint until the time is reached when the trip is no longer needed to 

protect the plant. Since the same Pressurizer Pressure - Low 

bistable is also shared with the SIAS, an inadvertent SIAS actuation 

is also prevented. The setpoint increases automatically as 

pressurizer pressure increases, until the trip setpoint is reached. 

The Pressurizer Pressure - Low trip and the SIAS Function may be 

simultaneously bypassed when RCS pressure is below 500 psia, 

when neither the reactor trip nor an inadvertent SIAS actuation are 

desirable and these Functions are no longer needed to protect the 

plant. The bypass is automatically removed as RCS pressure 

increases above 500 psia. 

5. Containment Pressure - High

The LCO requires four channels of Containment Pressure - High to 

be OPERABLE in MODES 1 and 2. 

The Allowable Value is set high enough to allow for small pressure 

increases in containment expected during normal operation (i.e., 

plant heatup) and is not indicative of an abnormal condition. It is set 

low enough to initiate a reactor trip when an abnormal condition is 

indicated. 

6, 7. Steam Generator Pressure - Low

This LCO requires four channels of Steam Generator #1 Pressure - 

Low and Steam Generator #2 Pressure - Low to be OPERABLE in 

MODES 1 and 2. 

This Allowable Value is sufficiently below the full load operating value 

for steam pressure so as not to interfere with normal plant operation, 

but still high enough to provide the required protection in the event of 

excessive steam demand. Since excessive steam demand causes 

the RCS to cool down, resulting in positive reactivity addition to the 

core, a reactor trip is required to offset that effect. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-21 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The trip setpoint may be manually decreased as steam generator 

pressure is reduced during controlled plant cooldown, provided the 

margin between steam generator pressure and the setpoint is 

maintained < 200 psia. This allows for controlled depressurization of 

the secondary system while still maintaining an active reactor trip 

setpoint and MSIS setpoint, until the time is reached when the 

setpoints are no longer needed to protect the plant. The setpoint 

increases automatically as steam generator pressure increases until 

the specified trip setpoint is reached. 

8, 9. Steam Generator Level – Low

This LCO requires four channels of Steam Generator #1 Level - Low 

and Steam Generator #2 Level - Low for each steam generator to be 

OPERABLE in MODES 1 and 2. 

The Allowable Value is sufficiently below the normal operating level 

for the steam generators so as not to cause a reactor trip during 

normal plant operations. The same bistable providing the reactor trip 

also initiates emergency feedwater to the affected generator via the 

Emergency Feedwater Actuation Signals (EFAS). The minimum 

setpoint is governed by EFAS requirements. The reactor trip will 

remove the heat source (except decay heat), thereby conserving the 

reactor heat sink. 

This trip may be manually bypassed when cold leg temperature is 

below the specified limit to allow for CEA withdrawal during testing. 

The bypass is automatically removed when cold leg temperature 

reaches 200°F. 

10, 11. Reactor Coolant Flow – Low 

This LCO requires four channels of Reactor Coolant Flow, Steam 

Generator #1 - Low and Reactor Coolant Flow, Steam Generator #2 -

Low to be OPERABLE in MODES 1 and 2. The Allowable Value is 

set low enough to allow for slight variations in reactor coolant flow 

during normal plant operations while providing the required 

protection. Tripping the reactor ensures that the resultant power to 

flow ratio provides adequate core cooling to maintain DNBR under 

the expected pressure conditions for this event. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-22 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The Reactor Coolant Flow - Low trip may be manually bypassed 

when logarithmic power is less than 1E-4%. This allows for deenergization of one or more RCPs (e.g., for plant cooldown), while 

maintaining the ability to keep the shutdown CEA banks withdrawn 

from the core if desired. 

LCO 3.4.5, "RCS Loops - MODE 3," LCO 3.4.6, "RCS Loops - 

MODE 4," and LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled," 

ensure adequate RCS flow rate is maintained. The bypass is 

automatically removed when logarithmic power increases above 

1E-4%, as sensed by the wide range (logarithmic) nuclear 

instrumentation. When below the power range, the Reactor Coolant 

Flow - Low is not required for plant protection. 

12. Loss of Load

This LCO requires four channels of Loss of Load trip to be 

OPERABLE in MODES 1 and 2. 

The Steam Bypass Control System is capable of passing 45% of the 

full power main steam flow (45% RTP bypass capability) directly to 

the condenser without causing the MSSVs to lift. The Nuclear Steam 

Supply System is capable of absorbing a 10% step change in power 

when a primary to secondary system energy mismatch occurs, 

without causing the pressurizer safety valves to lift. This means that 

the plant can sustain a turbine trip without causing the pressurizer 

safety valves or the MSSV to lift, provided power is ≤ 55% RTP. 

Therefore, the Loss of Load trip may be bypassed when reactor 

power is ≤ 55% RTP, as sensed by the power range nuclear 

instrumentation. Both the bypass and bypass removal, when above 

55% power, are automatically performed. 

Loss of Load trip is equipment protective and not credited in the 

accident analysis. As such, the 55% bypass power permissive is a 

nominal value and does not include any instrument uncertainties. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-23 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

13. Local Power Density – High

This LCO requires four channels of LPD - High to be OPERABLE. 

The LCO on the CPCs ensures that the SLs are maintained during all 

AOOs and the consequences of accidents are acceptable. 

A CPC is not considered inoperable if CEAC inputs to the CPC are 

inoperable. The Required Actions required in the event of CEAC 

channel failures ensure the CPCs are capable of performing their 

safety Function. 

The CPC channels may be manually bypassed below 1E-4%, as 

sensed by the logarithmic nuclear instrumentation. This bypass is 

enabled manually in all four CPC channels when plant conditions do 

not warrant the trip protection. The bypass effectively removes the 

DNBR - Low and LPD - High trips from the RPS Logic circuitry. The 

operating bypass is automatically removed when enabling bypass 

conditions are no longer satisfied. 

This operating bypass is required to perform a plant startup, since 

both CPC generated trips will be in effect whenever shutdown CEAs 

are inserted. It also allows system tests at low power with 

Pressurizer Pressure - Low or RCPs off. 

During special testing pursuant to LCO 3.4.17, the CPC channels 

may be manually bypassed when THERMAL POWER is below 

5% RTP to allow special testing without generating a reactor trip. 

The Linear Power Level - High trip setpoint is reduced, so as to 

provide protection during testing. 

14. Departure from Nucleate Boiling Ratio (DNBR) – Low

This LCO requires four channels of DNBR - Low to be OPERABLE. 

The LCO on the CPCs ensures that the SLs are maintained during all 

AOOs and the consequences of accidents are acceptable. 

A CPC is not considered inoperable if CEAC inputs to the CPC are 

inoperable. The Required Actions required in the event of CEAC 

channel failures ensure the CPCs are capable of performing their 

safety Function. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-24 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The CPC channels may be manually bypassed below 1E-4%, as 

sensed by the logarithmic nuclear instrumentation. This bypass is 

enabled manually in all four CPC channels when plant conditions do 

not warrant the trip protection. The bypass effectively removes the 

DNBR - Low and LPD - High trips from the RPS logic circuitry. The 

operating bypass is automatically removed when enabling bypass 

conditions are no longer satisfied. 

This operating bypass is required to perform a plant startup, since 

both CPC generated trips will be in effect whenever shutdown CEAs 

are inserted. It also allows system tests at low power with 

Pressurizer Pressure - Low or RCPs off. 

During special testing pursuant to LCO 3.4.17, the CPC channels 

may be manually bypassed when THERMAL POWER is below 

5% RTP to allow special testing without generating a reactor trip. 

The Linear Power Level - High trip setpoint is reduced, so as to 

provide protection during testing. 

Interlocks/Bypasses

The LCO on bypass permissive removal channels requires that the 

automatic bypass removal feature of all four operating bypass channels 

be OPERABLE for each RPS Function with an operating bypass in the 

MODES addressed in the specific LCO for each Function. All four bypass 

removal channels must be OPERABLE to ensure that none of the four 

RPS channels are inadvertently bypassed. 

This LCO applies to the bypass removal feature only. If the bypass 

enable Function is failed so as to prevent entering a bypass condition, 

operation may continue. In the case of the Logarithmic Power Level - 

High trip (Function 2), the absence of a bypass will limit maximum power 

to below the trip setpoint. 

The interlock function Allowable Values are based upon analysis of 

functional requirements for the bypassed Functions. These are 

discussed above as part of the LCO discussion for the affected Functions. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-25 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY Most RPS trips are required to be OPERABLE in MODES 1 and 2 

because the reactor is critical in these MODES. The reactor trips are 

designed to take the reactor subcritical, which maintains the SLs during 

AOOs and assists the ESFAS in providing acceptable consequences 

during accidents. Most trips are not required to be OPERABLE in 

MODES 3, 4, and 5. In MODES 3, 4, and 5, the emphasis is placed on 

return to power events. The reactor is protected in these MODES by 

ensuring adequate SDM. Exceptions to this are: 

• The Logarithmic Power Level - High trip, RPS Logic RTCBs, and 

Manual Trip are required in MODES 3, 4, and 5, with the RTCBs 

closed, to provide protection for boron dilution and CEA withdrawal 

events. 

The Logarithmic Power Level - High trip in these lower MODES is 

addressed in LCO 3.3.2. The Logarithmic Power Level - High trip is 

bypassed prior to MODE 1 entry and is not required in MODE 1. The 

RPS Logic in MODES 1, 2, 3, 4, and 5 is addressed in LCO 3.3.4. 

ACTIONS The most common causes of channel inoperability are outright failure or 

drift of the bistable or process module sufficient to exceed the tolerance 

allowed by the plant specific setpoint analysis. Typically, the drift is found 

to be small and results in a delay of actuation rather than a total loss of 

function. This determination is generally made during the performance of 

a CHANNEL FUNCTIONAL TEST when the process instrument is set up 

for adjustment to bring it to within specification. If the trip setpoint is less 

conservative than the Allowable Value in Table 3.3.1-1, the channel is 

declared inoperable immediately, and the appropriate Condition(s) must 

be entered immediately. 

 In the event a channel's trip setpoint is found nonconservative with 

respect to the Allowable Value, or the transmitter, instrument loop, signal 

processing electronics, or RPS bistable trip unit is found inoperable, then 

all affected functions provided by that channel must be declared 

inoperable, and the unit must enter the Condition for the particular 

protection Function affected. 

When the number of inoperable channels in a trip Function exceeds that 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 is 

immediately entered if applicable in the current MODE of operation. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-26 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

A Note has been added to the ACTIONS. The Note has been added to 

clarify the application of the Completion Time rules. The Conditions of 

this Specification may be entered independently for each Function. The 

Completion Times of each inoperable Function will be tracked separately 

for each Function, starting from the time the Condition was entered for 

that Function. 

A.1 and A.2

Condition A applies to the failure of a single trip channel or associated 

instrument channel inoperable in any RPS automatic trip Function. RPS 

coincidence logic is two-out-of-four. 

If one RPS channel is inoperable, startup or power operation is allowed to 

continue, providing the inoperable channel is placed in bypass or trip in 

1 hour (Required Action A.1). The 1 hour allotted to bypass or trip the 

channel is sufficient to allow the operator to take all appropriate actions 

for the failed channel and still ensures that the risk involved in operating 

with the failed channel is acceptable. The failed channel must be 

restored to OPERABLE status prior to entering MODE 2 following the 

next MODE 5 entry. With a channel in bypass, the coincidence logic is 

now in a two-out-of-three configuration. 

The Completion Time of prior to entering MODE 2 following the next 

MODE 5 entry is based on adequate channel to channel independence, 

which allows a two-out-of-three channel operation since no single failure 

will cause or prevent a reactor trip. 

B.1

Condition B applies to the failure of two channels in any RPS automatic 

trip Function. 

Required Action B.1 provides for placing one inoperable channel in 

bypass and the other channel in trip within the Completion Time of 1 hour. 

This Completion Time is sufficient to allow the operator to take all 

appropriate actions for the failed channels while ensuring the risk involved 

in operating with the failed channels is acceptable. With one channel of 

protective instrumentation bypassed, the RPS is in a two-out-of-three 

logic; but with another channel failed, the RPS may be operating in a twoout-of-two logic. This is outside the assumptions made in the analyses 

and should be corrected. To correct the problem, the second channel is 

placed in trip. This places the RPS in a one-out-of-two logic. If any of the 

other OPERABLE channels receives a trip signal, the reactor will trip. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-27 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

One of the two inoperable channels will need to be restored to operable 

status prior to the next required CHANNEL FUNCTIONAL TEST, 

because channel surveillance testing on an OPERABLE channel requires 

that the OPERABLE channel be placed in bypass. However, it is not 

possible to bypass more than one RPS channel, and placing a second 

channel in trip will result in a reactor trip. Therefore, if one RPS channel 

is in trip and a second channel is in bypass, a third inoperable channel 

would place the unit in LCO 3.0.3. 

C.1, C.2.1, and C.2.2

Condition C applies to one automatic bypass removal channel inoperable. 

If the inoperable bypass removal channel for any bypass channel cannot 

be restored to OPERABLE status within 1 hour, the associated RPS 

channel may be considered OPERABLE only if the bypass is not in effect. 

Otherwise, the affected RPS channel must be declared inoperable, as in 

Condition A, and the affected automatic trip channel placed in bypass or 

trip. The bypass removal channel and the automatic trip channel must be 

repaired prior to entering MODE 2 following the next MODE 5 entry. The 

Bases for the Required Actions and required Completion Times are 

consistent with Condition A. 

D.1 and D.2

Condition D applies to two inoperable automatic bypass removal 

channels. If the bypass removal channels for two operating bypasses 

cannot be restored to OPERABLE status within 1 hour, the associated 

RPS channel may be considered OPERABLE only if the bypass is not in 

effect. Otherwise, the affected RPS channels must be declared 

inoperable, as in Condition B, and the bypass either removed or one 

automatic trip channel placed in bypass and the other in trip within 1 hour. 

The restoration of one affected bypassed automatic trip channel must be 

completed prior to the next CHANNEL FUNCTIONAL TEST, or the plant 

must shut down per LCO 3.0.3 as explained in Condition B. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-28 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

E.1

Condition E applies if any CPC cabinet receives a high temperature 

alarm. There is one temperature sensor in each of the four CPC bays. 

Since CPC bays B and C also house CEAC calculators 1 and 2, 

respectively, a high temperature in either of these bays may also indicate 

a problem with the associated CEAC. CEAC OPERABILITY is addressed 

in LCO 3.3.3. 

If a CPC cabinet high temperature alarm is received, it is possible for the 

CPC to be affected and not be completely reliable. Therefore, a 

CHANNEL FUNCTIONAL TEST must be performed within 12 hours. The 

Completion Time of 12 hours is adequate considering the low probability 

of undetected failure, the consequences of a single channel failure, and 

the time required to perform a CHANNEL FUNCTIONAL TEST. 

F.1

Condition F applies if an OPERABLE CPC has three or more autorestarts 

in a 12 hour period. 

CPCs and CEACs will attempt to autorestart if they detect a fault 

condition, such as a calculator malfunction or loss of power. A successful 

autorestart restores the calculator to operation; however, excessive 

autorestarts might be indicative of a calculator problem. 

If a nonbypassed CPC has three or more autorestarts, it may not be 

completely reliable. Therefore, a CHANNEL FUNCTIONAL TEST must 

be performed on the CPC to ensure it is functioning properly. Based on 

plant operating experience, the Completion Time of 24 hours is adequate 

and reasonable to perform the test while still keeping the risk of operating 

in this condition at an acceptable level, since overt channel failure will 

most likely be indicated and annunciated in the control room by CPC 

online diagnostics. 

G.1

Condition G is entered when the Required Action and associated 

Completion Time of Condition A, B, C, D, E, or F are not met. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-29 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

If the Required Actions associated with these Conditions cannot be 

completed within the required Completion Time, the reactor must be 

brought to a MODE where the Required Actions do not apply. The 

allowed Completion Time of 6 hours is reasonable, based on operating 

experience, for reaching the required MODE from full power conditions in 

an orderly manner and without challenging plant systems. 

SURVEILLANCE The SRs for any particular RPS Function are found in the SR column of 

REQUIREMENTS Table 3.3.1-1 for that Function. Most Functions are subject to CHANNEL 

CHECK, CHANNEL FUNCTIONAL TEST, CHANNEL CALIBRATION, 

and response time testing. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

In order for a plant to take credit for topical reports as the basis for 

justifying Frequencies, topical reports must be supported by an NRC staff 

SER that establishes the acceptability of each topical report for that unit. 

-------------------------------------------------------------------------------------------------- 

SR 3.3.1.1

Performance of the CHANNEL CHECK once every 12 hours ensures that 

gross failure of instrumentation 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 or of something even more serious. CHANNEL 

CHECK will detect gross channel failure; thus, it is key to verifying that 

the instrumentation continues to operate properly between each 

CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the transmitter or the signal processing equipment has drifted outside 

its limits. 

The Frequency, about once every shift, is based on operating experience that demonstrates the 

rarity of channel failure. Since the probability of two random failures in redundant channels in 

any 12 hour period is extremely low, the CHANNEL CHECK minimizes the chance of loss of 

protective function due to failure of redundant channels. The CHANNEL CHECK supplements 

less formal, but more frequent, checks of channel OPERABILITY during normal operational use 

of the displays associated with the LCO required channels. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-30 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

In the case of RPS trips with multiple inputs, such as the DNBR and LPD 

inputs to the CPCs, a CHANNEL CHECK must be performed on all 

inputs. 

SR 3.3.1.2

The RCS flow rate indicated by each CPC is verified, as required by a 

Note, to be less than or equal to the actual RCS total flow rate every 

12 hours when THERMAL POWER is ≥ 70% RTP. The 12 hours after 

reaching 70% RTP is for plant stabilization, data taking, and flow 

verification. This check (and if necessary, the adjustment of the CPC 

addressable constant flow coefficients) ensures that the DNBR setpoint is 

conservatively adjusted with respect to actual flow indications, as 

determined by the Core Operating Limits Supervisory System (COLSS). 

SR 3.3.1.3

The CPC autorestart count is checked every 12 hours to monitor the CPC 

and CEAC for normal operation. If three or more autorestarts of a 

nonbypassed CPC occur within a 12 hour period, the CPC may not be 

completely reliable. Therefore, the Required Action of Condition F must 

be performed. The Frequency is based on operating experience that 

demonstrates the rarity of more than one channel failing within the same 

12 hour interval. 

SR 3.3.1.4

A daily calibration (heat balance) is performed when THERMAL POWER 

is ≥ 20%. The Linear Power Level signal and the CPC addressable 

constant multipliers are adjusted to make the CPC ∆T power and nuclear 

power calculations agree with the calorimetric calculation if the absolute 

difference is ≥ 2%. The value of 2% is adequate because this value is 

assumed in the safety analysis. These checks (and, if necessary, the 

adjustment of the Linear Power Level signal and the CPC addressable 

constant coefficients) are adequate to ensure that the accuracy of these 

CPC calculations is maintained within the analyzed error margins. The 

power level must be > 20% RTP to obtain accurate data. At lower power 

levels, the accuracy of calorimetric data is questionable. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-31 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The Frequency of 24 hours is based on plant operating experience and 

takes into account indications and alarms located in the control room to 

detect deviations in channel outputs. The Frequency is modified by a 

Note indicating this Surveillance need only be performed within 12 hours 

after reaching 20% RTP. The 12 hours after reaching 20% RTP is 

required for plant stabilization, data taking, and flow verification. The 

secondary calorimetric is inaccurate at lower power levels. A second 

Note in the SR indicates the SR may be suspended during PHYSICS 

TESTS. The conditional suspension of the daily calibrations under strict 

administrative control is necessary to allow special testing to occur. 

SR 3.3.1.5

The RCS flow rate indicated by each CPC is verified to be less than or 

equal to the RCS total flow rate every 31 days. The Note indicates the 

Surveillance is performed within 12 hours after THERMAL POWER is 

≥ 70% RTP. This check (and, if necessary, the adjustment of the CPC 

addressable flow constant coefficients) ensures that the DNBR setpoint is 

conservatively adjusted with respect to actual flow indications as 

determined by a calorimetric calculation. Operating experience has 

shown the specified Frequency is adequate, as instrument drift is minimal 

and changes in actual flow rate are minimal over core life. 

SR 3.3.1.6

The three vertically mounted excore nuclear instrumentation detectors in 

each channel are used to determine APD for use in the DNBR and LPD 

calculations. Because the detectors are mounted outside the reactor 

vessel, a portion of the signal from each detector is from core sections not 

adjacent to the detector. This is termed shape annealing and is 

compensated for after every refueling by performing SR 3.3.1.12, which 

adjusts the gains of the three detector amplifiers for shape annealing. 

SR 3.3.1.6 ensures that the preassigned gains are still proper. Power 

must be > 15% because the CPCs do not use the excore generated 

signals for axial flux shape information at low power levels. The Note 

allowing 12 hours after reaching 15% RTP is required for plant 

stabilization and testing. 

The 31 day Frequency is adequate because the demonstrated long term 

drift of the instrument channels is minimal. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-32 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.1.7

A CHANNEL FUNCTIONAL TEST on each channel except Loss of Load, 

power range neutron flux, and logarithmic power level channels is 

performed every 92 days to ensure the entire channel will perform its 

intended function when needed. The SR is modified by two Notes. 

Note 1 is a requirement to verify the correct CPC addressable constant 

values are installed in the CPCs when the CPC CHANNEL FUNCTIONAL 

TEST is performed. Note 2 allows the CHANNEL FUNCTIONAL TEST 

for the Logarithmic Power Level - High channels to be performed 2 hours 

after logarithmic power drops below 1E-4% and is required to be 

performed only if the RTCBs are closed. 

In addition to power supply tests, the RPS CHANNEL FUNCTIONAL 

TEST consists of three overlapping tests as described in Reference 9. 

These tests verify that the RPS is capable of performing its intended 

function, from bistable input through the RTCBs. They include: 

Bistable Tests

A test signal is superimposed on the input in one channel at a time to 

verify that the bistable trips within the specified tolerance around the 

setpoint. This is done with the affected RPS channel trip channel 

bypassed. Any setpoint adjustment shall be consistent with the 

assumptions of the current plant specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the interval between surveillance 

interval extension analysis. The requirements for this review are outlined 

in Reference [10]. 

Matrix Logic Tests

Matrix Logic tests are addressed in LCO 3.3.4. This test is performed 

one matrix at a time. It verifies that a coincidence in the two input 

channels for each Function removes power from the matrix relays. 

During testing, power is applied to the matrix relay test coils and prevents 

the matrix relay contacts from assuming their de-energized state. This 

test will detect any short circuits around the bistable contacts in the 

coincidence logic, such as may be caused by faulty bistable relay or trip 

channel bypass contacts. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-33 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Trip Path Tests

Trip path (Initiation Logic) tests are addressed in LCO 3.3.4. These tests 

are similar to the Matrix Logic tests, except that test power is withheld 

from one matrix relay at a time, allowing the initiation circuit to deenergize, thereby opening the affected set of RTCBs. The RTCBs must 

then be closed prior to testing the other three initiation circuits, or a 

reactor trip may result. 

The Frequency of 92 days is based on the reliability analysis presented in 

topical report CEN-327, "RPS/ESFAS Extended Test Interval Evaluation" 

(Ref. 10). 

The CPC and CEAC channels and excore nuclear instrumentation 

channels are tested separately. 

The excore channels use preassigned test signals to verify proper 

channel alignment. The excore logarithmic channel test signal is inserted 

into the preamplifier input, so as to test the first active element 

downstream of the detector. 

The power range excore test signal is inserted at the drawer input, since 

there is no preamplifier. 

The quarterly CPC CHANNEL FUNCTIONAL TEST is performed using 

software. This software includes preassigned addressable constant 

values that may differ from the current values. Provisions are made to 

store the addressable constant values on a computer disk prior to testing 

and to reload them after testing. A Note is added to the Surveillance 

Requirements to verify that the CPC CHANNEL FUNCTIONAL TEST 

includes the correct values of addressable constants. A successful test of 

the required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-34 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.1.8

A Note indicates that neutron detectors are excluded from CHANNEL 

CALIBRATION. A CHANNEL CALIBRATION of the power range neutron 

flux channels every 92 days ensures that the channels are reading 

accurately and within tolerance (Ref. 10). The Surveillance verifies that 

the channel responds to a measured parameter within the necessary 

range and accuracy. CHANNEL CALIBRATION leaves the channel 

adjusted to account for instrument drift between successive calibrations to 

ensure that the channel remains operational between successive tests. 

CHANNEL CALIBRATIONS must be performed consistent with the plant 

specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the interval between surveillance 

interval extension analysis. The requirements for this review are outlined 

in Reference 10. Operating experience has shown this Frequency to be 

satisfactory. The detectors are excluded from CHANNEL CALIBRATION 

because they are passive devices with minimal drift and because of the 

difficulty of simulating a meaningful signal. Slow changes in detector 

sensitivity are compensated for by performing the daily calorimetric 

calibration (SR 3.3.1.4) and the monthly linear subchannel gain check 

(SR 3.3.1.6). In addition, the associated control room indications are 

monitored by the operators. 

[ SR 3.3.1.9

The characteristics and Bases for this Surveillance are as described for 

SR 3.3.1.7. This Surveillance differs from SR 3.3.1.7 only in that the 

CHANNEL FUNCTIONAL TEST on the Loss of Load functional unit is 

only required above 55% RTP. When above 55% and the trip is in effect, 

the CHANNEL FUNCTIONAL TEST will ensure the channel will perform 

its equipment protective function if needed. A successful test of the 

required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. The Note allowing 2 hours after reaching 55% RTP is 

necessary for Surveillance performance. This Surveillance cannot be 

performed below 55% RTP, since the trip is bypassed. ]
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-35 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.1.10

SR 3.3.1.10 is the performance of a CHANNEL CALIBRATION every 

[18] months. 

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the sensor. The Surveillance verifies that the channel responds 

to a measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive tests. CHANNEL 

CALIBRATIONS must be performed consistent with the plant specific 

setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [10]. 

The Frequency is based upon the assumption of an [18] month calibration 

interval for the determination of the magnitude of equipment drift in the 

setpoint analysis as well as operating experience and consistency with 

the typical [18] month fuel cycle. 

The Surveillance is modified by a Note to indicate that the neutron 

detectors are excluded from CHANNEL CALIBRATION because they are 

passive devices with minimal drift and because of the difficulty of 

simulating a meaningful signal. Slow changes in detector sensitivity are 

compensated for by performing the daily calorimetric calibration 

(SR 3.3.1.4) and the monthly linear subchannel gain check (SR 3.3.1.6). 

SR 3.3.1.11

Every [18] months, a CHANNEL FUNCTIONAL TEST is performed on the 

CPCs. The CHANNEL FUNCTIONAL TEST shall include the injection of 

a signal as close to the sensors as practicable to verify OPERABILITY 

including alarm and trip Functions. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-36 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The basis for the [18] month Frequency is that the CPCs perform a 

continuous self monitoring function that eliminates the need for frequent 

CHANNEL FUNCTIONAL TESTS. This CHANNEL FUNCTIONAL TEST 

essentially validates the self monitoring function and checks for a small 

set of failure modes that are undetectable by the self monitoring function. 

Operating experience has shown that undetected CPC or CEAC failures 

do not occur in any given [18] month interval. 

SR 3.3.1.12

The three excore detectors used by each CPC channel for axial flux 

distribution information are far enough from the core to be exposed to flux 

from all heights in the core, although it is desired that they only read their 

particular level. The CPCs adjust for this flux overlap by using the 

predetermined shape annealing matrix elements in the CPC software. 

After refueling, it is necessary to re-establish or verify the shape 

annealing matrix elements for the excore detectors based on more 

accurate incore detector readings. This is necessary because refueling 

could possibly produce a significant change in the shape annealing matrix 

coefficients. 

Incore detectors are inaccurate at low power levels. THERMAL POWER 

should be significant but < 70% to perform an accurate axial shape 

calculation used to derive the shape annealing matrix elements. 

By restricting power to ≤ 70% until shape annealing matrix elements are 

verified, excessive local power peaks within the fuel are avoided. 

Operating experience has shown this Frequency to be acceptable. 

SR 3.3.1.13

SR 3.3.1.13 is a CHANNEL FUNCTIONAL TEST similar to SR 3.3.1.7, 

except SR 3.3.1.13 is applicable only to bypass functions and is 

performed once within 92 days prior to each startup. A successful test of 

the required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-37 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Specifications tests at least once per refueling interval with applicable 

extensions. Proper operation of bypass permissives is critical during 

plant startup because the bypasses must be in place to allow startup 

operation and must be removed at the appropriate points during power 

ascent to enable certain reactor trips. Consequently, the appropriate time 

to verify bypass removal function OPERABILITY is just prior to startup. 

The allowance to conduct this Surveillance within 92 days of startup is 

based on the reliability analysis presented in topical report CEN-327, 

"RPS/ESFAS Extended Test Interval Evaluation" (Ref. 10). Once the 

operating bypasses are removed, the bypasses must not fail in such a 

way that the associated trip Function gets inadvertently bypassed. This 

feature is verified by the trip Function CHANNEL FUNCTIONAL TEST, 

SR 3.3.1.7 or SR 3.3.1.9. Therefore, further testing of the bypass function 

after startup is unnecessary. 

SR 3.3.1.14

This SR ensures that the RPS RESPONSE TIMES are verified to be less 

than or equal to the maximum values assumed in the safety analysis. 

Individual component response times are not modeled in the analyses. 

The analyses model the overall or total elapsed time, from the point at 

which the parameter exceeds the trip setpoint value at the sensor to the 

point at which the RTCBs open. Response times are conducted on an 

[18] month STAGGERED TEST BASIS. This results in the interval 

between successive surveillances of a given channel of n x 18 months, 

where n is the number of channels in the function. The Frequency of 

[18] months is based upon operating experience, which has shown that 

random failures of instrumentation components causing serious response 

time degradation, but not channel failure, are infrequent occurrences. 

Also, response times cannot be determined at power, since equipment 

operation is required. Testing may be performed in one measurement or 

in overlapping segments, with verification that all components are tested. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Applicable portions of the following TS Bases are applicable to plants 

adopting CEOG Topical Report CE NPSD-1167-1, "Elimination of 

Pressure Sensor Response Time Testing Requirements." 

-------------------------------------------------------------------------------------------------- 
RPS Instrumentation - Operating (Digital) 

B 3.3.1 

CEOG STS B 3.3.1-38 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Response time may be verified by any series of sequential, overlapping 

or total channel measurements, including allocated sensor response time, 

such that the response time is verified. Allocations for sensor response 

times may be obtained from records of test results, vendor test data, or 

vendor engineering specifications. Topical Report CE NPSD-1167-A, 

"Elimination of Pressure Sensor Response Time Testing Requirements," 

(Ref. 11) provides the basis and methodology for using allocated sensor 

response times in the overall verification of the channel response time for 

specific sensors identified in the Topical Report. Response time 

verification for other sensor types must be demonstrated by test. The 

allocation of sensor response times must be verified prior to placing a 

new component in operation and reverified after maintenance that may 

adversely affect the sensor response time. 

A Note is added to indicate that the neutron detectors are excluded from 

RPS RESPONSE TIME testing because they are passive devices with 

minimal drift and because of the difficulty of simulating a meaningful 

signal. Slow changes in detector sensitivity are compensated for by 

performing the daily calorimetric calibration (SR 3.3.1.4). 

REFERENCES 1. Regulatory Guide 1.105, Revision 3, "Setpoints for Safety-Related 

Instrumentation." 

 2. 10 CFR 50, Appendix A, GDC 21. 

 3. 10 CFR 100. 

 4. NRC Safety Evaluation Report. 

 5. IEEE Standard 279-1971, April 5, 1972. 

 6. FSAR, Chapter [14]. 

 7. 10 CFR 50.49. 

 8. "Plant Protection System Selection of Trip Setpoint Values." 

 9. FSAR, Section [7.2]. 

 10. CEN-327, June 2, 1986, including Supplement 1, March 3, 1989. 

 11. CEOG Topical Report CE NPSD-1167-A, "Elimination of Pressure 

Sensor Response Time Testing Requirements." 
RPS Instrumentation - Shutdown (Analog) 

B 3.3.2 

CEOG STS B 3.3.2-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.2 Reactor Protective System (RPS) Instrumentation - Shutdown (Analog) 

BASES 

BACKGROUND The RPS initiates a reactor trip to protect against violating the core 

specified acceptable fuel design limits and reactor coolant pressure 

boundary integrity during anticipated operational occurrences (AOOs). 

By tripping the reactor, the RPS also assists the Engineered Safety 

Features systems in mitigating accidents. 

The protection and monitoring systems have been designed to ensure 

safe operation of the reactor. This is achieved by specifying limiting 

safety system settings (LSSS) in terms of parameters directly monitored 

by the RPS, as well as LCOs on other reactor system parameters and 

equipment performance. 

The LSSS, defined in this Specification as the Allowable Value, in 

conjunction with the LCOs, establish the threshold for protective system 

action to prevent exceeding acceptable limits during Design Basis 

Accidents. 

During AOOs, which are those events expected to occur one or more 

times during the plant life, the acceptable limits are: 

• The departure from nucleate boiling ratio shall be maintained above 

the Safety Limit (SL) value to prevent departure from nucleate 

boiling, 

• Fuel centerline melting shall not occur, and 

• The Reactor Coolant System pressure SL of 2750 psia shall not be 

exceeded. 

Maintaining the parameters within the above values ensures that the 

offsite dose will be within the 10 CFR 50 (Ref. 1) and 10 CFR 100 (Ref. 2) 

criteria during AOOs. 

Accidents are events that are analyzed even though they are not 

expected to occur during the plant life. The acceptable limit during 

accidents is that the offsite dose shall be maintained within an acceptable 

fraction of 10 CFR 100 (Ref. 2) limits. Different accident categories allow 

a different fraction of these limits based on probability of occurrence. 

Meeting the acceptable dose limit for an accident category is considered 

having acceptable consequences for that event. 
RPS Instrumentation - Shutdown (Analog) 

B 3.3.2 

CEOG STS B 3.3.2-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The RPS is segmented into four interconnected modules. These 

modules are: 

• Measurement channels, 

• Bistable trip units, 

• RPS Logic, and 

• Reactor trip circuit breakers (RTCBs). 

This LCO applies only to the Power Rate of Change - High trip Functions 

and associated instrument channels in MODES 3, 4, and 5 with any of the 

RTCBs closed and any Control Element Assembly (CEA) capable of 

being withdrawn. In MODES 1 and 2, this trip Function is addressed in 

LCO 3.3.1, "Reactor Protective System (RPS) Instrumentation - 

Operating." LCO 3.3.13, "[Logarithmic] Power Monitoring Channels," 

applies when the RTCBs are open or CEA Drive System is not capable of 

CEA withdrawal. In the case of LCO 3.3.13, the logarithmic power 

instrumentation channels are required for monitoring neutron flux, 

although the trip Function is not required. 

Measurement Channels and Trip Units

The measurement channels providing input to the Power Rate of Change 

- High Function consist of wide range nuclear instrumentation channels 

using neutron flux leakage from the reactor vessel. 

Other aspects of the Power Rate of Change - High trip are similar to the 

other measurement channels and bistable trip units. These are 

addressed in the Background section of LCO 3.3.1. 

APPLICABLE Each of the analyzed accidents and transients can be detected by one or 

SAFETY more RPS Functions. The accident analysis contained in Reference 3 

ANALYSES takes credit for most RPS trip Functions. Functions not specifically 

credited in the accident analysis were qualitatively credited in the safety 

analysis and the NRC staff approved licensing basis for the plant. These 

Functions may provide protection for conditions that do not require 

dynamic transient analysis to demonstrate Function performance. Other 

Functions, such as the Loss of Load trip, are purely equipment protective, 

and their use minimizes the potential for equipment damage. 
RPS Instrumentation - Shutdown (Analog) 

B 3.3.2 

CEOG STS B 3.3.2-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The Power Rate of Change - High trip is used to trip the reactor when 

excore wide range power indicates an excessive rate of change. 

The Power Rate of Change - High trip is not required for protection. It 

serves as a backup to the administratively enforced startup rate limit. 

The Power Rate of Change - High Function minimizes transients for 

events such as a continuous CEA withdrawal or a boron dilution event 

from low power levels. The Power Rate of Change - High trip is 

automatically bypassed at < 1E-4% RTP, as sensed by the wide range 

nuclear instrument (NI) Level 2 bistable, when poor counting statistics 

may lead to erroneous indication. It is also bypassed at > 12% RTP, 

where moderator temperature coefficient and fuel temperature coefficient 

make high rate of change of power unlikely. This bypass is effected by 

the power range NI Level 1 bistable. Automatic bypass removal is also 

effected by these bistables. With the RTCBs open, the Power Rate of 

Change - High trip is not required to be OPERABLE; however, the 

indication and alarm Functions of at least two channels are required to be 

OPERABLE. LCO 3.3.13 ensures the wide range channels are available 

to detect and alert the operator to a boron dilution event. 

The RPS instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The LCO requires all instrumentation performing an RPS Function to be 

OPERABLE. Failure of any required portion of the instrument channel or 

bypass removal channel renders the affected channel(s) inoperable and 

reduces the reliability of the affected Functions. 

Actions allow maintenance (trip channel) bypass of individual channels, 

but the bypass activates interlocks that prevent operation with a second 

channel in the same Function bypassed. Plants are restricted to 48 hours 

in a trip channel bypass condition before either restoring the Function to 

four channel operation (two-out-of-four logic) or placing the channel in trip 

(one-out-of-three logic). At plants where adequate channel to channel 

independence has been demonstrated, specific exceptions have been 

approved by the NRC staff to permit one of the two-out-of-four channels 

to be bypassed for an extended period of time. 

This LCO requires four channels of Power Rate of Change - High to be 

OPERABLE in MODES 3, 4, and 5, when the RTCBs are closed and the 

CEA Drive System is capable of CEA withdrawal. MODE 1 and 2 

requirements are addressed in LCO 3.3.1. This trip is not credited in the 

safety analysis. Therefore, the Allowable Value specified in SR 3.3.4.2 is 

not derived from an analytical limit. 
RPS Instrumentation - Shutdown (Analog) 

B 3.3.2 

CEOG STS B 3.3.2-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY This LCO is applicable to the Power Rate of Change - High reactor trip in 

MODES 3, 4 and 5. MODES 1 and 2 are addressed in LCO 3.3.1. 

The power rate of change trip is required in MODES 3, 4, and 5, with the 

RTCBs closed and a CEA capable of being withdrawn to provide backup 

protection for boron dilution and CEA withdrawal events. The power rate 

of change trip is not credited in the safety analysis, but is part of the NRC 

approved licensing basis for the plant. 

The power rate of change trip has operating bypasses discussed in the 

LCO section. In MODES 3, 4, and 5, the emphasis is placed on return to 

power events. The reactor is protected in these MODES by ensuring 

adequate SDM. 

ACTIONS The most common causes of channel inoperability are outright failure or 

drift of the bistable or process module sufficient to exceed the tolerance 

allowed by the plant specific setpoint analysis. Typically, the drift is found 

to be small and results in a delay of actuation rather than a total loss of 

function. This determination is generally made during the performance of 

a CHANNEL FUNCTIONAL TEST when the process instrument is set up 

for adjustment to bring it to within specification. If the trip setpoint is less 

conservative than the Allowable Value in Table 3.3.1-1, the channel is 

declared inoperable immediately, and the appropriate Condition(s) must 

be entered immediately. 

In the event a channel's trip setpoint is found nonconservative with 

respect to the Allowable Value, or the transmitter, instrument loop, signal 

processing electronics, or RPS bistable is found inoperable, then all 

affected Functions provided by that channel must be declared inoperable 

and the plant must enter the Condition for the particular protection 

Function affected. 

When the number of inoperable channels in a trip Function exceeds that 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 is 

immediately entered if applicable in the current MODE of operation. 

A.1, A.2.1, and A.2.2

Condition A applies to the failure of a single channel of the Power Rate of 

Change - High RPS automatic trip Function. 
RPS Instrumentation - Shutdown (Analog) 

B 3.3.2 

CEOG STS B 3.3.2-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

RPS coincidence logic is normally two-out-of-four. If one RPS bistable 

trip unit or associated instrument channel is inoperable, startup or power 

operation is allowed to continue, providing the inoperable trip unit is 

placed in bypass or trip within 1 hour (Required Action A.1). With one 

channel in bypass, no additional random failure of a single channel could 

spuriously trip the reactor and a valid trip signal can still trip the reactor. 

With one channel in trip, an additional random failure of a single channel 

could spuriously trip the reactor. Therefore, it is preferable to place an 

inoperable channel in bypass rather than trip. 

The Completion Time of 1 hour allotted to restore, bypass, or trip the 

channel is sufficient to allow the operator to take all appropriate actions 

for the failed channel, while ensuring that the risk involved in operating 

with the failed channel is acceptable. 

For plants that have not demonstrated sufficient channel to channel 

independence, the failed channel is restored to OPERABLE status or is 

placed in trip within 48 hours (Required Action A.2.1 or Required 

Action A.2.2). Required Action A.2.1 restores the full capability of the 

Function. Required Action A.2.2 places the Function in a one-out-of-three 

configuration. In this configuration, common cause failure of dependent 

channels cannot prevent trip. 

The [48] hour Completion Time is based on operating experience, which 

has demonstrated that a random failure of a second channel occurring 

during the [48] hour period is a low probability event. 

B.1 and B.2

Condition B applies to the failure of two channels in the Power Rate of 

Change - High RPS automatic trip Function. 

Required Action B.1 provides for placing one inoperable channel in 

bypass and the other channel in trip within the Completion Time of 1 hour. 

This Completion Time is sufficient to allow the operator to take all 

appropriate actions for the failed channels, while ensuring the risk 

involved in operating with the failed channels is acceptable. With one 

channel of protective instrumentation bypassed, the RPS is in a two-outof-three logic; but with another channel failed, the RPS may be operating 

in a two-out-of-two logic. This is outside the assumptions made in the 

analyses and should be corrected. To correct the problem, the second 

channel is placed in trip. This places the RPS in a one-out-of-two logic. If 

any of the other OPERABLE channels receives a trip signal, the reactor 

will trip. 
RPS Instrumentation - Shutdown (Analog) 

B 3.3.2 

CEOG STS B 3.3.2-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

[ The bypassed channel should be restored to OPERABLE status within 

48 hours for reasons similar to those stated under Condition A. After one 

channel is restored to OPERABLE status, the provisions of Condition A 

still apply to the remaining inoperable channel. Therefore, the channel 

that is still inoperable after completion of Required Action B.2 shall be 

placed in trip if more than 48 hours have elapsed since the initial channel 

failure. ]

C.1, C.2.1, C.2.2.1, and C.2.2.2

Condition C applies to one automatic bypass removal channel inoperable. 

If the bypass removal channel cannot be restored to OPERABLE status, 

the associated Power Rate of Change - High RPS channel may be 

considered OPERABLE only if the bypass is not in effect. Otherwise, the 

affected RPS channel must be declared inoperable, as in Condition A, 

and the bypass either removed or the bypass removal channel repaired. 

The Bases for the Required Actions and Completion Times are the same 

as discussed for Condition A. 

D.1, D.2.1, and D.2.2

Condition D applies to two inoperable automatic bypass removal 

channels. If the bypass removal channels cannot be restored to 

OPERABLE status, the associated Power Rate of Change - High RPS 

channel may be considered OPERABLE only if the bypass is not in effect. 

Otherwise, the affected RPS channels must be declared inoperable, as in 

Condition B, and the bypass either removed or the bypass removal 

channel repaired. Also, Required Action D.2.2 provides for the 

restoration of the one affected automatic trip channel to OPERABLE 

status within the rules of Completion Time specified under Condition B. 

Completion Times are consistent with Condition B. 

E.1

Condition E is entered when the Required Actions and associated 

Completion Times of Condition A, B, C, or D are not met. 
RPS Instrumentation - Shutdown (Analog) 

B 3.3.2 

CEOG STS B 3.3.2-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

If Required Actions associated with these Conditions cannot be completed within the required 

Completion Time, opening the RTCBs brings the reactor to a MODE where the LCO does not 

apply and ensures no CEA withdrawal will occur. The basis for the Completion Time of 6 hours 

is that it is adequate to complete the Required Actions without challenging plant systems, 

including the insertion of CEAs for plants that normally maintain CEAs withdrawn when shut 

down. 

SURVEILLANCE -----------------------------------REVIEWER’S NOTE----------------------------------- 

REQUIREMENTS In order for a plant to take credit for topical reports as the basis for 

justifying Frequencies, topical reports must be supported by an NRC staff 

Safety Evaluation Report that establishes the acceptability of each topical 

report for that plant. 

 -------------------------------------------------------------------------------------------------- 

SR 3.3.2.1

Performance of the CHANNEL CHECK on each wide range channel once 

every 12 hours ensures that gross failure of instrumentation has not 

occurred. A CHANNEL CHECK is normally a comparison of the 

parameter indicated on one channel to a similar parameter on another 

channel. 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 or of 

something even more serious. CHANNEL CHECK will detect gross 

channel failure; thus, it is key to verifying that the instrumentation 

continues to operate properly between each CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including isolation, 

indication, and readability. If a channel is outside the criteria, it may be 

an indication that the transmitter or the signal processing equipment has 

drifted outside its limits. 

The Frequency, about once every shift, is based on operating experience 

that demonstrates the rarity of channel failure. Since the probability of 

two random failures in redundant channels in any 12 hour period is 

extremely low, the CHANNEL CHECK minimizes the chance of loss of 

protective function due to failure of redundant channels. The CHANNEL 

CHECK supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of the displays associated 

with the LCO required channels. 
RPS Instrumentation - Shutdown (Analog) 

B 3.3.2 

CEOG STS B 3.3.2-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.2.2

A CHANNEL FUNCTIONAL TEST on the power rate of change channels 

is performed once every 92 days to ensure the entire channel will perform 

its intended function if required. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. The Power Rate of 

Change - High trip Function is required during startup operation and is 

bypassed when shut down or > 15% RTP. Additionally, operating 

experience has shown that these components usually pass the 

Surveillance when performed at a Frequency of once every 92 days prior 

to each reactor startup. 

SR 3.3.2.3

SR 3.3.2.3 is a CHANNEL FUNCTIONAL TEST similar to SR 3.3.2.2, 

except SR 3.3.2.3 is applicable only to bypass Functions and is 

performed once within 92 days prior to each startup. A successful test of 

the required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. 

Proper operation of bypass permissives is critical during plant startup 

because the bypasses must be in place to allow startup operation and 

must be removed at the appropriate points during power ascent to enable 

certain reactor trips. Consequently, the appropriate time to verify bypass 

removal function OPERABILITY is just prior to startup. The allowance to 

conduct this Surveillance within 92 days of startup is based on the 

reliability analysis presented in topical report CEN-327, "RPS/ESFAS 

Extended Test Interval Evaluation" (Ref. 5). Once the operating bypasses 

are removed, the bypasses must not fail in such a way that the 

associated trip Function gets inadvertently bypassed. This feature is 

verified by the trip Function CHANNEL FUNCTIONAL TEST, SR 3.3.2.2. 

Therefore, further testing of the bypass function after startup is 

unnecessary. 
RPS Instrumentation - Shutdown (Analog) 

B 3.3.2 

CEOG STS B 3.3.2-9 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.2.4

SR 3.3.2.4 is the performance of a CHANNEL CALIBRATION every 

[18] months. 

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the sensor. The Surveillance verifies that the channel responds 

to a measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive tests. CHANNEL 

CALIBRATIONS must be performed consistent with the plant specific 

setpoint analysis. 

Only the Allowable Values are specified for each RPS trip Function. 

Nominal trip setpoints are specified in the plant specific setpoint 

calculations. The nominal setpoints are selected to ensure the setpoints 

measured by CHANNEL FUNCTIONAL TESTS do not exceed the 

Allowable Value if the bistable is performing as required. Operation with 

a trip setpoint less conservative than the nominal trip setpoint, but within 

its Allowable Value, is acceptable, provided that operation and testing are 

consistent with the assumptions of the plant specific setpoint calculations. 

Each Allowable Value specified is more conservative than the analytical 

limit assumed in the safety analysis in order to account for instrument 

uncertainties appropriate to the trip Function. These uncertainties are 

defined in the "Plant Protection System Selection of Trip Setpoint Values" 

(Ref. 4). 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference 5. 

The Frequency is based upon the assumption of an [18] month calibration 

interval in the determination of the magnitude of equipment drift. 

The Surveillance is modified by a Note to indicate that the neutron 

detectors are excluded from CHANNEL CALIBRATION because they are 

passive devices with minimal drift and because of the difficulty of 

simulating a meaningful signal. 
RPS Instrumentation - Shutdown (Analog) 

B 3.3.2 

CEOG STS B 3.3.2-10 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. 10 CFR 50, Appendix A. 

 2. 10 CFR 100. 

 3. FSAR, Chapter [14]. 

 4. "Plant Protection System Selection of Trip Setpoint Values." 

 5. CEN-327, June 2, 1986, including Supplement 1, March 3, 1989. 
RPS Instrumentation - Shutdown (Digital) 

B 3.3.2 

CEOG STS B 3.3.2-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.2 Reactor Protective System (RPS) Instrumentation - Shutdown (Digital) 

BASES 

BACKGROUND The RPS initiates a reactor trip to protect against violating the core fuel 

design limits and reactor coolant pressure boundary (RCPB) integrity 

during anticipated operational occurrences (AOOs). By tripping the 

reactor, the RPS also assists the Engineered Safety Features systems in 

mitigating accidents. 

The protection and monitoring systems have been designed to ensure 

safe operation of the reactor. This is achieved by specifying limiting 

safety system settings (LSSS) in terms of parameters directly monitored 

by the RPS, as well as LCOs on other reactor system parameters and 

equipment performance. 

The LSSS, defined in this Specification as the Allowable Value, in 

conjunction with the LCOs, establish the threshold for protective system 

action to prevent exceeding acceptable limits during Design Basis 

Accidents (DBAs). 

During AOOs, which are those events expected to occur one or more 

times during the plant life, the acceptable limits are: 

• The departure from nucleate boiling ratio shall be maintained above 

the Safety Limit (SL) value to prevent departure from nucleate 

boiling, 

• Fuel centerline melting shall not occur, and 

• The Reactor Coolant System pressure SL of 2750 psia shall not be 

exceeded. 

Maintaining the parameters within the above values ensures that the 

offsite dose will be within the 10 CFR 50 (Ref. 1) and 10 CFR 100 (Ref. 2) 

criteria during AOOs. 

Accidents are events that are analyzed even though they are not 

expected to occur during the plant life. The acceptable limit during 

accidents is that the offsite dose shall be maintained within an acceptable 

fraction of 10 CFR 100 (Ref. 2) limits. Different accident categories allow 

a different fraction of these limits based on probability of occurrence. 

Meeting the acceptable dose limit for an accident category is considered 

having acceptable consequences for that event. 
RPS Instrumentation - Shutdown (Digital) 

B 3.3.2 

CEOG STS B 3.3.2-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The RPS is segmented into four interconnected modules. These 

modules are: 

• Measurement channels, 

• Bistable trip units, 

• RPS Logic, and 

• Reactor trip circuit breakers (RTCBs). 

This LCO applies only to the Logarithmic Power Level - High trip in 

MODES 3, 4, and 5 with the RTCBs closed. In MODES 1 and 2, this trip 

Function is addressed in LCO 3.3.1, "Reactor Protective System (RPS) 

Instrumentation - Operating." LCO 3.3.13, "[Logarithmic] Power 

Monitoring Channels," applies when the RTCBs are open. In the case of 

LCO 3.3.13, the logarithmic channels are required for monitoring neutron 

flux, although the trip Function is not required. 

Measurement Channels and Bistable Trip Units

The measurement channels providing input to the Logarithmic Power 

Level - High trip consist of the four logarithmic nuclear instrumentation 

channels detecting neutron flux leakage from the reactor vessel. Other 

aspects of the Logarithmic Power Level - High trip are similar to the other 

measurement channels and bistables. These are addressed in the 

Background section of LCO 3.3.1. 

Functional testing of the entire RPS, from bistable input through the 

opening of individual sets of RTCBs, can be performed either at power or 

shutdown and is normally performed on a quarterly basis. Nuclear 

instrumentation can be similarly tested. FSAR, Section [7.2] (Ref. 3), 

provides more detail on RPS testing. 

APPLICABLE The RPS functions to maintain the SLs during AOOs and mitigates the 

SAFETY consequence of DBAs in all MODES in which the RTCBs are closed. 

ANALYSES 

 Each of the analyzed transients and accidents can be detected by one or 

more RPS Functions. Functions not specifically credited in the accident 

analysis were qualitatively credited in the safety analysis and the NRC 

staff approved licensing basis for the plant. Noncredited Functions 

include the Loss of Load. The Loss of Load trip is purely equipment 

protective, and its use minimizes the potential for equipment damage. 
RPS Instrumentation - Shutdown (Digital) 

B 3.3.2 

CEOG STS B 3.3.2-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The Logarithmic Power Level - High trip protects the integrity of the fuel 

cladding and helps protect the RCPB in the event of an unplanned 

criticality from a shutdown condition. 

In MODES 2, 3, 4, and 5, with the RTCBs closed, and the Control 

Element Assembly (CEA) Drive System capable of CEA withdrawal, 

protection is required for CEA withdrawal events originating when 

logarithmic power is < 1E-4%. For events originating above this power 

level, other trips provide adequate protection. 

MODES 3, 4, and 5, with the RTCBs closed, are addressed in this LCO. 

MODE 2 is addressed in LCO 3.3.1. 

In MODES 3, 4, or 5, with the RTCBs open or the CEAs not capable of 

withdrawal, the Logarithmic Power Level - High trip does not have to be 

OPERABLE. However, the indication and alarm portion of two 

logarithmic channels must be OPERABLE to ensure proper indication of 

neutron population and to indicate a boron dilution event. The indication 

and alarm functions are addressed in LCO 3.3.13. 

The RPS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The LCO requires the Logarithmic Power Level - High RPS Function to 

be OPERABLE. Failure of any required portion of the instrument channel 

renders the affected channel(s) inoperable and reduces the reliability of 

the affected Function. 

Actions allow maintenance (trip channel) bypass of individual channels, 

but the bypass activates interlocks that prevent operation with a second 

channel in the same Function bypassed. With one channel in each 

Function trip channel bypassed, this effectively places the plant in a twoout-of-three logic configuration in those Functions. Plants are restricted 

to 48 hours in a trip channel bypass condition before either restoring the 

function to four channel operation (two-out-of-four logic) or placing the 

channel in trip (one-out-of-three logic). 

This LCO requires all four channels of the Logarithmic Power Level - High 

to be OPERABLE in MODE 2, and in MODE 3, 4, or 5 when the RTCBs 

are closed and the CEA Drive System is capable of CEA withdrawal. 
RPS Instrumentation - Shutdown (Digital) 

B 3.3.2 

CEOG STS B 3.3.2-4 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The Allowable Value specified in SR 3.3.2.4 is high enough to provide an 

operating envelope that prevents unnecessary Logarithmic Power Level - 

High reactor trips during normal plant operations. The Allowable Value is 

low enough for the system to maintain a safety margin for unacceptable 

fuel cladding damage should a CEA withdrawal event occur. 

The Logarithmic Power Level - High trip may be bypassed when 

logarithmic power is above 1E-4% to allow the reactor to be brought to 

power during a reactor startup. This bypass is automatically removed 

when logarithmic power decreases below 1E-4%. Above 1E-4%, the 

Linear Power Level - High and Pressurizer Pressure - High trips provide 

protection for reactivity transients. 

The trip may be manually bypassed during physics testing pursuant to 

LCO 3.4.17, "RCS Loops - Test Exceptions." During this testing, the 

Linear Power Level - High trip and administrative controls provide the 

required protection. 

APPLICABILITY Most RPS trips are required to be OPERABLE in MODES 1 and 2 

because the reactor is critical in these MODES. The trips are designed to 

take the reactor subcritical, which maintains the SLs during AOOs and 

assists the Engineered Safety Features Actuation System (ESFAS) in 

providing acceptable consequences during accidents. Most trips are not 

required to be OPERABLE in MODES 3, 4, and 5. In MODES 3, 4, 

and 5, the emphasis is placed on return to power events. The reactor is 

protected in these MODES by ensuring adequate SDM. Exceptions to 

this are: 

• The Logarithmic Power Level - High trip, RPS Logic RTCBs, and 

Manual Trip are required in MODES 3, 4, and 5, with the RTCBs 

closed, to provide protection for boron dilution and CEA withdrawal 

events. The Logarithmic Power Level - High trip in these lower 

MODES is addressed in this LCO. The RPS Logic in MODES 1, 2, 3, 

4, and 5 is addressed in LCO 3.3.4, "Reactor Protective System 

(RPS) Logic and Trip Initiation." 

The Applicability is modified by a Note that allows the trip to be bypassed 

when logarithmic power is > 1E-4%, and the bypass is automatically 

removed when logarithmic power is ≤ 1E-4%. 
RPS Instrumentation - Shutdown (Digital) 

B 3.3.2 

CEOG STS B 3.3.2-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS The most common causes of channel inoperability are outright failure or 

drift of the bistable or process module sufficient to exceed the tolerance 

allowed by the plant specific setpoint analysis. Typically, the drift is found 

to be small and results in a delay of actuation rather than a total loss of 

function. This determination is generally made during the performance of 

a CHANNEL FUNCTIONAL TEST when the process instrument is set up 

for adjustment to bring it to within specification. If the trip setpoint is less 

conservative than the Allowable Value stated in the LCO, the channel is 

declared inoperable immediately, and the appropriate Condition(s) must 

be entered immediately. 

In the event a channel's trip setpoint is found nonconservative with 

respect to the Allowable Value, or the excore logarithmic power channel 

or RPS bistable trip unit is found inoperable, then all affected Functions 

provided by that channel must be declared inoperable and the unit must 

enter the Condition for the particular protection Function affected. 

When the number of inoperable channels in a trip Function exceeds that 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 is 

immediately entered, if applicable in the current MODE of operation. 

A.1, and A.2

Condition A applies to the failure of a single Logarithmic Power Level - 

High trip channel or associated instrument channel. 

The Logarithmic Power Level - High coincidence logic is two-out-of-four. 

If one channel is inoperable, operation in MODES 3, 4, and 5 is allowed 

to continue, providing the inoperable channel is placed in bypass or trip in 

1 hour (Required Action A.1). 

The 1 hour allotted to bypass or trip the channel is sufficient to allow the 

operator to take all appropriate actions for the failed channel while 

ensuring that the risk involved in operating with the failed channel is 

acceptable. 

The failed channel must be restored to OPERABLE status prior to 

entering MODE 2 following the next MODE 5 entry. With a channel 

bypassed, the coincidence logic is now in a two-out-of-three 

configuration. The Completion Time is based on adequate channel to 

channel independence, which allows a two-out-of-three channel operation 

since no single failure will cause or prevent a reactor trip. 
RPS Instrumentation - Shutdown (Digital) 

B 3.3.2 

CEOG STS B 3.3.2-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1

Condition B applies to the failure of two Logarithmic Power Level - High 

trip channels or associated instrument channels. Required Action B.1 

provides for placing one inoperable channel in bypass and the other 

channel in trip within the Completion Time of 1 hour. This Completion 

Time is sufficient to allow the operator to take all appropriate actions for 

the failed channels and still ensures the risk involved in operating with the 

failed channels is acceptable. With one channel of protective 

instrumentation bypassed, the RPS is in a two-out-of-three logic; but with 

another channel failed, the RPS may be operating in a two-out-of-two 

logic. This is outside the assumptions made in the analyses and should 

be corrected. To correct the problem, the second channel is placed in 

trip. This places the RPS in a one-out-of-two logic. If any of the other 

OPERABLE channels receives a trip signal, the reactor will trip. 

One of the two inoperable channels will need to be restored to 

OPERABLE status prior to the next required CHANNEL FUNCTIONAL 

TEST because channel surveillance testing on an OPERABLE channel 

requires that the OPERABLE channel be placed in bypass. However, it is 

not possible to bypass more than one RPS channel, and placing a 

second channel in trip will result in a reactor trip. Therefore, if one RPS 

channel is in trip and a second channel is in bypass, a third inoperable 

channel would place the unit in LCO 3.0.3. 

C.1, C.2.1, and C.2.2

Condition C applies to one automatic bypass removal channel inoperable. 

If the bypass removal channel for the high logarithmic power level 

operating bypass cannot be restored to OPERABLE status within 1 hour, 

the associated RPS channel may be considered OPERABLE only if the 

bypass is not in effect. Otherwise, the affected RPS channel must be 

declared inoperable, as in Condition A, and the bypass either removed or 

the affected automatic channel placed in trip or bypass. Both the bypass 

removal channel and the associated automatic trip channel must be 

repaired prior to entering MODE 2 following the next MODE 5 entry. The 

Bases for the Required Actions and required Completion Times are 

consistent with Condition A. 
RPS Instrumentation - Shutdown (Digital) 

B 3.3.2 

CEOG STS B 3.3.2-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

D.1 and D.2

Condition D applies to two inoperable automatic bypass removal 

channels. If the bypass removal channels for two operating bypasses 

cannot be restored to OPERABLE status within 1 hour, the associated 

RPS channel may be considered OPERABLE only if the bypass is not in 

effect. Otherwise, the affected RPS channels must be declared 

inoperable, as in Condition B, and the bypass either removed or one 

automatic trip channel placed in bypass and the other in trip within 1 hour. 

The restoration of one affected bypassed automatic trip channel must be 

completed prior to the next CHANNEL FUNCTIONAL TEST or the plant 

must shut down per LCO 3.0.3, as explained in Condition B. Completion 

Times are consistent with Condition B. 

E.1

Condition E is entered when the Required Actions and associated 

Completion Times of Condition A, B, C, or D are not met. 

If Required Actions associated with these Conditions cannot be 

completed within the required Completion Time, all RTCBs must be 

opened, placing the plant in a condition where the logarithmic power trip 

channels are not required to be OPERABLE. A Completion Time of 

1 hour is a reasonable time to perform the Required Action, which 

maintains the risk at an acceptable level while having one or two 

channels inoperable. 

SURVEILLANCE The SRs for the Logarithmic Power Level - High trip are an extension of 

REQUIREMENTS those listed in LCO 3.3.1, listed here because of their Applicability in 

these MODES. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

In order for a unit to take credit for topical reports as the basis for 

justifying Frequencies, topical reports must be supported by an NRC staff 

Safety Evaluation Report that establishes the acceptability of each topical 

report for that unit (Ref. 5). 

-------------------------------------------------------------------------------------------------- 
RPS Instrumentation - Shutdown (Digital) 

B 3.3.2 

CEOG STS B 3.3.2-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.2.1

SR 3.3.2.1 is the performance of a CHANNEL CHECK of each 

logarithmic power channel. This SR is identical to SR 3.3.1.1. Only the 

Applicability differs. 

Performance of the CHANNEL CHECK once every 12 hours ensures that 

gross failure of instrumentation has not occurred. A CHANNEL CHECK 

is normally a comparison of the parameter indicated on one channel to a 

similar parameter on another channel. 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 or of something even more serious. CHANNEL 

CHECK will detect gross channel failure; thus, it is key to verifying that 

the instrumentation continues to operate properly between each 

CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the sensor or the signal processing equipment has drifted outside its 

limits. 

The Frequency, about once every shift, is based on operating experience 

that demonstrates the rarity of channel failure. Since the probability of 

two random failures in redundant channels in any 12 hour period is 

extremely low, the CHANNEL CHECK minimizes the chance of loss of 

protective function due to failure of redundant channels. The CHANNEL 

CHECK supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of the displays associated 

with the LCO required channels. 
RPS Instrumentation - Shutdown (Digital) 

B 3.3.2 

CEOG STS B 3.3.2-9 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.2.2

A CHANNEL FUNCTIONAL TEST on each channel, except Loss of Load 

and power range neutron flux, is performed every 92 days to ensure the 

entire channel will perform its intended function when needed. This SR is 

identical to SR 3.3.1.7. Only the Applicability differs. A successful test of 

the required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. 

In addition to power supply tests, the RPS CHANNEL FUNCTIONAL 

TEST consists of three overlapping tests as described in the FSAR, 

Section [7.2] (Ref. 3). These tests verify that the RPS is capable of 

performing its intended function, from bistable input through the RTCBs. 

They include: 

Bistable Tests

A test signal is superimposed on the input in one channel at a time to 

verify that the bistable trips within the specified tolerance around the 

setpoint. This is done with the affected RPS channel trip channel 

bypassed. Any setpoint adjustment shall be consistent with the 

assumptions of the current plant specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [6]. 

Matrix Logic Tests

Matrix Logic Tests are addressed in LCO 3.3.4. This test is performed 

one matrix at a time. It verifies that a coincidence in the two input 

channels for each Function removes power from the matrix relays. 

During testing, power is applied to the matrix relay test coils and prevents 

the matrix relay contacts from assuming their de-energized state. This 

test will detect any short circuits around the bistable contacts in the 

coincidence logic, such as may be caused by faulty bistable relay or trip 

channel bypass contacts. 
RPS Instrumentation - Shutdown (Digital) 

B 3.3.2 

CEOG STS B 3.3.2-10 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Trip Path Test

Trip path (Initiation Logic) tests are addressed in LCO 3.3.4. These tests 

are similar to the Matrix Logic tests except that test power is withheld 

from one matrix relay at a time, allowing the initiation circuit to deenergize, opening the affected set of RTCBs. The RTCBs must then be 

closed prior to testing the other three initiation circuits, or a reactor trip 

may result. 

The Frequency of 92 days is based on the reliability analysis presented in 

topical report CEN-327, "RPS/ESFAS Extended Test Interval Evaluation" 

(Ref. 6). The excore channels use preassigned test signals to verify 

proper channel alignment. The excore logarithmic channel test signal is 

inserted into the preamplifier input, so as to test the first active element 

downstream of the detector. 

SR 3.3.2.3

SR 3.3.2.3 is a CHANNEL FUNCTIONAL TEST similar to SR 3.3.2.2, 

except SR 3.3.2.3 is applicable only to bypass functions and is performed 

once within 92 days prior to each startup. This SR is identical to 

SR 3.3.1.13. Only the Applicability differs. A successful test of the 

required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. 

Proper operation of bypass permissives is critical during plant startup 

because the bypasses must be in place to allow startup operation and 

must be removed at the appropriate points during power ascent to enable 

certain reactor trips. Consequently, the appropriate time to verify bypass 

removal function OPERABILITY is just prior to startup. The allowance to 

conduct this Surveillance within 92 days of startup is based on the 

reliability analysis presented in topical report CEN-327, "RPS/ESFAS 

Extended Test Interval Evaluation" (Ref. 6). Once the operating 

bypasses are removed, the bypasses must not fail in such a way that the 

associated trip Function gets inadvertently bypassed. This feature is 

verified by the trip Function CHANNEL FUNCTIONAL TEST, SR 3.3.2.2. 

Therefore, further testing of the bypass function after startup is 

unnecessary. 
RPS Instrumentation - Shutdown (Digital) 

B 3.3.2 

CEOG STS B 3.3.2-11 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.2.4

SR 3.3.2.4 is the performance of a CHANNEL CALIBRATION every 

18 months. This SR is identical to SR 3.3.1.10. Only the Applicability 

differs. 

CHANNEL CALIBRATION is a complete check of the instrument channel 

excluding the sensor. The Surveillance verifies that the channel responds 

to a measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive tests. CHANNEL 

CALIBRATIONS must be performed consistent with the plant specific 

setpoint analysis. 

Only the Allowable Values are specified for this RPS trip Function. 

Nominal trip setpoints are specified in the plant specific setpoint 

calculations. The nominal setpoint is selected to ensure the setpoint 

measured by CHANNEL FUNCTIONAL TESTS does not exceed the 

Allowable Value if the bistable is performing as required. Operation with 

a trip setpoint less conservative than the nominal trip setpoint, but within 

its Allowable Value, is acceptable provided that operation and testing are 

consistent with the assumptions of the plant specific setpoint calculations. 

Each Allowable Value specified is more conservative than the analytical 

limit assumed in the safety analysis in order to account for instrument 

uncertainties appropriate to the trip Function. These uncertainties are 

defined in the "Plant Protection System Selection of Trip Setpoint Values" 

(Ref. 4). A channel is inoperable if its actual trip setpoint is not within its 

required Allowable Value. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [3]. 

The Frequency is based upon the assumption of an [18] month calibration 

interval for the determination of the magnitude of equipment drift in the 

setpoint analysis and includes operating experience and consistency with 

the typical [18] month fuel cycle. 

The Surveillance is modified by a Note to indicate that the neutron 

detectors are excluded from CHANNEL CALIBRATION because they are 

passive devices with minimal drift and because of the difficulty of 

simulating a meaningful signal. Slow changes in detector sensitivity are 

compensated for by performing the daily calorimetric calibration 

(SR 3.3.1.4). 
RPS Instrumentation - Shutdown (Digital) 

B 3.3.2 

CEOG STS B 3.3.2-12 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.2.5

This SR ensures that the RPS RESPONSE TIMES are verified to be less 

than or equal to the maximum values assumed in the safety analysis. 

Individual component response times are not modeled in the analyses. 

The analyses model the overall or total elapsed time, from the point at 

which the parameter exceeds the trip setpoint value at the sensor to the 

point at which the RTCBs open. Response times are conducted on an 

[18] month STAGGERED TEST BASIS. This results in the interval 

between successive tests of a given channel of n x 18 months, where n is 

the number of channels in the Function. The [18] month Frequency is 

based upon operating experience, which has shown that random failures 

of instrumentation components causing serious response time 

degradation, but not channel failure, are infrequent occurrences. Also, 

response times cannot be determined at power, since equipment 

operation is required. Testing may be performed in one measurement or 

in overlapping segments, with verification that all components are tested. 

REFERENCES 1. 10 CFR 50. 

 2. 10 CFR 100. 

 3. FSAR, Section [7.2]. 

 4. "Plant Protection System Selection of Trip Setpoint Values." 

 5. NRC Safety Evaluation Report. 

 6. CEN-327, June 2, 1986, including Supplement 1, March 3, 1989. 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.3 Reactor Protective System (RPS) Logic and Trip Initiation (Analog) 

BASES 

BACKGROUND The RPS initiates a reactor trip to protect against violating the core 

specified acceptable fuel design limits and reactor coolant pressure 

boundary integrity during anticipated operational occurrences (AOOs). 

By tripping the reactor, the RPS also assists the Engineered Safety 

Features (ESF) systems in mitigating accidents. 

The protection and monitoring systems have been designed to ensure 

safe operation of the reactor. This is achieved by specifying limiting 

safety system settings (LSSS) in terms of parameters directly monitored 

by the RPS, as well as LCOs on other reactor system parameters and 

equipment performance. 

The LSSS, defined in this Specification as the Allowable Value, in 

conjunction with the LCOs, establish the threshold for protective system 

action to prevent exceeding acceptable limits during Design Basis 

Accidents. 

During AOOs, which are those events expected to occur one or more 

times during the plant life, the acceptable limits are: 

• The departure from nucleate boiling ratio shall be maintained above 

the Safety Limit (SL) value to prevent departure from nucleate 

boiling, 

• Fuel centerline melting shall not occur, and 

• The Reactor Coolant System pressure SL of 2750 psia shall not be 

exceeded. 

Maintaining the parameters within the above values ensures that the 

offsite dose will be within the 10 CFR 50 (Ref. 1) and 10 CFR 100 (Ref. 2) 

criteria during AOOs. 

Accidents are events that are analyzed even though they are not 

expected to occur during the plant life. The acceptable limit during 

accidents is that the offsite dose shall be maintained within an acceptable 

fraction of 10 CFR 100 (Ref. 2) limits. Different accident categories allow 

a different fraction of these limits based on probability of occurrence. 

Meeting the acceptable dose limit for an accident category is considered 

having acceptable consequences for that event. 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The RPS is segmented into four interconnected modules. These 

modules are: 

• Measurement channels, 

• Bistable trip units, 

• RPS Logic, and 

• Reactor trip circuit breakers (RTCBs). 

This LCO addresses the RPS Logic and RTCBs, including Manual Trip 

capability. LCO 3.3.1, "Reactor Protective System (RPS) Instrumentation 

- Operating," provides a description of the role of this equipment in the 

RPS. This is summarized below: 

RPS Logic

The RPS Logic, consisting of Matrix and Initiation Logic, employs a 

scheme that provides a reactor trip when bistables in any two of the four 

channels sense the same input parameter trip. This is called a two-outof-four trip logic. This logic and the RTCB configuration are shown in 

Figure B 3.3.1-1. 

Bistable relay contact outputs from the four channels are configured into 

six logic matrices. Each logic matrix checks for a coincident trip in the 

same parameter in two bistable channels. The matrices are designated 

the AB, AC, AD, BC, BD, and CD matrices to reflect the bistable channels 

being monitored. Each logic matrix contains four normally energized 

matrix relays. When a coincidence is detected, consisting of a trip in the 

same Function in the two channels being monitored by the logic matrix, 

all four matrix relays de-energize. 

The matrix relay contacts are arranged into trip paths, with one of the four 

matrix relays in each matrix opening contacts in one of the four trip paths. 

Each trip path provides power to one of the four normally energized 

RTCB control relays (K1, K2, K3, and K4). The trip paths thus each have 

six contacts in series, one from each matrix, and perform a logical OR

function, opening the RTCBs if any one or more of the six logic matrices 

indicate a coincidence condition. 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Each trip path is responsible for opening one set of two of the eight 

RTCBs. The RTCB control relays (K-relays), when de-energized, 

interrupt power to the breaker undervoltage trip attachments and 

simultaneously apply power to the shunt trip attachments on each of the 

two breakers. Actuation of either the undervoltage or shunt trip 

attachment is sufficient to open the RTCB and interrupt power from the 

motor generator (MG) sets to the control element drive mechanisms 

(CEDMs). 

When a coincidence occurs in two RPS channels, all four matrix relays in 

the affected matrix de-energize. This in turn de-energizes all four breaker 

control relays, which simultaneously de-energize the undervoltage and 

energize the shunt trip attachments in all eight RTCBs, tripping them 

open. 

The Initiation Logic consists of the trip path power source, matrix relays 

and their associated contacts, all interconnecting wiring, and solid state 

(auxiliary) relays through the K-relay contacts in the RTCB control 

circuitry. 

It is possible to change the two-out-of-four RPS Logic to a two-out-ofthree logic for a given input parameter in one channel at a time by trip 

channel bypassing select portions of the matrix logic. Trip channel 

bypassing a bistable effectively shorts the bistable relay contacts in the 

three matrices associated with that channel. Thus, the bistables will 

function normally, producing normal trip indication and annunciation, but a 

reactor trip will not occur unless two additional channels indicate a trip 

condition. Trip channel bypassing can be simultaneously performed on 

any number of parameters in any number of channels, providing each 

parameter is bypassed in only one channel at a time. An interlock 

prevents simultaneous trip channel bypassing of the same parameter in 

more than one channel. Trip channel bypassing is normally employed 

during maintenance or testing. 

Reactor Trip Circuit Breakers (RTCBs)

The reactor trip switchgear, shown in Figure B 3.3.1-1, consists of eight 

RTCBs, which are operated in four sets of two breakers (four channels). 

Power input to the reactor trip switchgear comes from two full capacity 

MG sets operated in parallel such that the loss of either MG set does not 

de-energize the CEDMs. There are two separate CEDM power supply 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-4 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

buses, each bus powering half of the CEDMs. Power is supplied from the 

MG sets to each bus via two redundant paths (trip legs). Trip legs 1A 

and 1B supply power to CEDM bus 1. Trip legs 2A and 2B supply power 

to CEDM bus 2. This ensures that a fault or the opening of a breaker in 

one trip leg (i.e., for testing purposes) will not interrupt power to the 

CEDM buses. 

Each of the four trip legs consists of two RTCBs in series. The two 

RTCBs within a trip leg are actuated by separate initiation circuits. 

The eight RTCBs are operated as four sets of two breakers (four 

channels). For example, if a breaker receives an open signal in trip leg A 

(for CEDM bus 1), an identical breaker in trip leg B (for CEDM bus 2) will 

also receive an open signal. This arrangement ensures that power is 

interrupted to both CEDM buses, thus preventing trip of only half of the 

control element assemblies (CEAs) (a half trip). Any one inoperable 

breaker in a channel will make the entire channel inoperable. 

Each set of RTCBs is operated by either a Manual Trip push button or an 

RPS actuated K-relay. There are four Manual Trip push buttons, 

arranged in two sets of two, as shown in Figure B 3.3.1-1. Depressing 

both push buttons in either set will result in a reactor trip. 

When a Manual Trip is initiated using the control room push buttons, the 

RPS trip paths and K-relays are bypassed, and the RTCB undervoltage 

and shunt trip attachments are actuated independent of the RPS. 

Manual Trip circuitry includes the push button and interconnecting wiring 

to both RTCBs necessary to actuate both the undervoltage and shunt trip 

attachments, but excludes the K-relay contacts and their interconnecting 

wiring to the RTCBs, which are considered part of the Initiation Logic. 

Functional testing of the entire RPS, from bistable input through the 

opening of individual sets of RTCBs, can be performed either at power or 

shutdown and is normally performed on a quarterly basis. FSAR, 

Section [7.2] (Ref. 3), explains RPS testing in more detail. 

APPLICABLE Reactor Protective System (RPS) Logic

SAFETY 

ANALYSES The RPS Logic provides for automatic trip initiation to maintain the SLs 

during AOOs and assist the ESF systems in ensuring acceptable 

consequences during accidents. All transients and accidents that call for 

a reactor trip assume the RPS Logic is functioning as designed. 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Reactor Trip Circuit Breakers (RTCBs)

All of the transient and accident analyses that call for a reactor trip 

assume that the RTCBs operate and interrupt power to the CEDMs. 

Manual Trip

There are no accident analyses that take credit for the Manual Trip; 

however, the Manual Trip is part of the RPS circuitry. It is used by the 

operator to shut down the reactor whenever any parameter is rapidly 

trending toward its trip setpoint. A Manual Trip accomplishes the same 

results as any one of the automatic trip Functions. 

The RPS Logic and initiation satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Reactor Protective System (RPS) Logic

Failures of individual bistable relays and their contacts are addressed in 

LCO 3.3.1. This Specification addresses failures of the Matrix Logic not 

addressed in the above, such as the failure of matrix relay power supplies 

or the failure of the trip channel bypass contact in the bypass condition. 

Loss of a single vital bus will de-energize one of the two power supplies in 

each of three matrices. This will result in four RTCBs opening; however, 

the remaining four closed RTCBs will prevent a reactor trip. For the 

purposes of this LCO, de-energizing up to three matrix power supplies 

due to a single failure is to be treated as a single channel failure, 

providing the affected matrix relays de-energize as designed, opening the 

affected RTCBs. 

Each of the four Initiation Logic channels opens one set of RTCBs if any 

of the six coincidence matrices de-energize their associated matrix relays. 

They thus perform a logical OR function. Each Initiation Logic channel 

has its own power supply and is independent of the others. An Initiation 

Logic channel includes the matrix relay through to the K-relay contacts, 

which open the RTCB. 

It is possible for two Initiation Logic channels affecting the same trip leg to 

de-energize if a matrix power supply or vital instrument bus fails. This will 

result in opening the two affected sets of RTCBs. 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-6 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

If one set of RTCBs has been opened in response to a single RTCB 

channel, Initiation Logic channel, or Manual Trip channel failure, the 

affected set of RTCBs may be closed for up to 1 hour for Surveillance on 

the OPERABLE Initiation Logic, RTCB, and Manual Trip channels. In this 

case, the redundant set of RTCBs will provide protection if a trip should 

be required. It is unlikely that a trip will be required during the 

Surveillance, coincident with a failure of the remaining series RTCB 

channel. If a single matrix power supply or vital bus failure has opened 

two sets of RTCBs, Manual Trip and RTCB testing on the closed breakers 

cannot be performed without causing a trip. 

1. Matrix Logic

This LCO requires six channels of Matrix Logic to be OPERABLE in 

MODES 1 and 2, and in MODES 3, 4, and 5 when any RTCB is 

closed and any CEA is capable of being withdrawn. 

2. Initiation Logic

This LCO requires four channels of Initiation Logic to be OPERABLE 

in MODES 1 and 2, and in MODES 3, 4, and 5 when any RTCB is 

closed and any CEA is capable of being withdrawn. 

3. Reactor Trip Circuit Breakers (RTCBs)

The LCO requires four RTCB channels to be OPERABLE in 

MODES 1 and 2, as well as in MODES 3, 4, and 5 when any RTCB 

is closed and any CEA is capable of being withdrawn. 

Each channel consists of two breakers operated in a single set by the 

Initiation Logic or Manual Trip circuitry. This ensures that power is 

interrupted at identical locations in the trip legs for both CEDM buses, 

thus preventing power removal to only one CEDM bus (a half trip). 

Failure of a single breaker affects the entire channel, and both 

breakers in the set must be opened. Without reliable RTCBs and 

associated support circuitry, a reactor trip cannot occur whether 

initiated automatically or manually. 

Each channel of RTCBs starts at the contacts actuated by the 

K-relay, and the contacts actuated by the Manual Trip, for each set of 

breakers. The K-relay actuated contacts and the upstream circuitry 

are considered to be RPS Logic. Manual Trip contacts and upstream 

circuitry are considered to be Manual Trip circuitry. 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-7 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

A Note associated with the ACTIONS states that if one set of RTCBs 

has been opened in response to a single RTCB channel, Initiation 

Logic channel, or Manual Trip channel failure, the affected set of 

RTCBs may be closed for up to 1 hour for Surveillance on the 

OPERABLE Initiation Logic, RTCB, and Manual Trip channels. In 

this case, the redundant set of RTCBs will provide protection. If a 

single matrix power supply or vital bus failure has opened two sets of 

RTCBs, Manual Trip and RTCB testing on the closed breakers 

cannot be performed without causing a trip. This Note is not 

applicable to Condition A, with one Matrix Logic channel inoperable. 

4. Manual Trip

The LCO requires all four Manual Trip channels to be OPERABLE in 

MODES 1 and 2, and MODES 3, 4, and 5 when any RTCB is closed 

and any CEA is capable of being withdrawn. 

Two independent sets of two adjacent push buttons are provided at 

separate locations. Each push button is considered a channel and 

operates two of the eight RTCBs. Depressing both push buttons in 

either set will cause an interruption of power to the CEDMs, allowing 

the CEAs to fall into the core. This design ensures that no single 

failure in any push button circuit can either cause or prevent a reactor 

trip. 

APPLICABILITY The RPS Matrix Logic, RTCBs, and Manual Trip are required to be 

OPERABLE in any MODE when any CEA is capable of being withdrawn 

from the core (i.e., RTCBs closed and power available to the CEDMs). 

This ensures the reactor can be tripped when necessary, but allows for 

maintenance and testing when the reactor trip is not needed. 

In MODES 3, 4, and 5 with all the RTCBs open, the CEAs are not 

capable of withdrawal and these Functions do not have to be 

OPERABLE. However, two [logarithmic] power level channels must be 

OPERABLE to ensure proper indication of neutron population and to 

indicate a boron dilution event. This is addressed in LCO 3.3.13, 

"[Logarithmic] Power Monitoring Channels." 

ACTIONS When the number of inoperable channels in a trip Function exceeds that 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 is 

immediately entered if applicable in the current MODE of operation. 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-8 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

A.1

Condition A applies if one Matrix Logic channel is inoperable or three 

Matrix Logic channels are inoperable due to a common power source 

failure de-energizing three matrix power supplies, in any applicable 

MODE. Loss of a single vital instrument bus will de-energize one of the 

two matrix power supplies in up to three matrices. This is considered a 

single matrix failure, providing the matrix relays associated with the failed 

power supplies de-energize as required. 

Failure of the matrix relays to de-energize in all three affected matrices 

could, when combined with trip channel bypassing of bistable relay 

contacts in the other matrices, result in loss of RPS function. 

The channel must be restored to OPERABLE status within 48 hours. The 

Completion Time of 48 hours provides the operator time to take 

appropriate actions and still ensures that any risk involved in operating 

with a failed channel is acceptable. Operating experience has 

demonstrated that the probability of a random failure of a second Matrix 

Logic channel is low during any given 48 hour interval. If the channel 

cannot be restored to OPERABLE status within 48 hours, Condition E is 

entered. 

B.1

Condition B applies to one Initiation Logic channel, RTCB channel, or 

Manual Trip channel in MODES 1 and 2, since they have the same 

actions. MODES 3, 4, and 5, with the RTCBs shut, are addressed in 

Condition C. These Required Actions require opening the affected 

RTCBs. This removes the need for the affected channel by performing its 

associated safety function. With the RTCB open, the affected Functions 

are in one-out-of-two logic, which meets redundancy requirements, but 

testing on the OPERABLE channels cannot be performed without causing 

a reactor trip unless the RTCBs in the inoperable channels are closed to 

permit testing. 

Required Action B.1 provides for opening the RTCBs associated with the 

inoperable channel within a Completion Time of 1 hour. This Required 

Action is conservative, since depressing the Manual Trip push button 

associated with either set of breakers in the other trip leg will cause a 

reactor trip. With this configuration, a single channel failure will not 

prevent a reactor trip. The allotted Completion Time is adequate to open 

the affected RTCBs while maintaining the risk of having them closed at an 

acceptable level. 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-9 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1

Condition C applies to the failure of one Initiation Logic channel, RTCB 

channel, or Manual Trip channel affecting the same trip leg in MODE 3, 4, 

or 5 with the RTCBs closed. The channel must be restored to 

OPERABLE status within 48 hours. If the inoperable channel cannot be 

restored to OPERABLE status within 48 hours, the affected RTCBs must 

be opened. In some cases, this condition may effect all of the RTCBs. 

This removes the need for the affected channel by performing its 

associated safety function. With the RTCBs open, the affected functions 

are in a one-out-of-two logic, which meets redundancy requirements. 

The Completion Time of 48 hours is consistent with that of other RPS 

instrumentation and should be adequate to repair most failures. 

Testing on the OPERABLE channels cannot be performed without 

causing a reactor trip unless the RTCBs in the inoperable channels are 

closed to permit testing. 

D.1

Condition D applies to the failure of both Manual Trip or Initiation Logic 

channels affecting the same trip leg. Since this will open two channels of 

RTCBs, this Condition is also applicable to the two affected channels of 

RTCBs. This Condition allows for loss of a single vital instrument bus or 

matrix power supply, which will de-energize both Initiation Logic channels 

in the same trip leg. This will open both sets of RTCBs in the affected trip 

leg, satisfying the Required Action of opening the affected RTCBs. 

Of greater concern is the failure of the initiation circuit in a nontrip 

condition (e.g., due to two initiation K-relay failures). With only one 

Initiation Logic channel failed in a nontrip condition, there is still the 

redundant set of RTCBs in the trip leg. With both failed in a nontrip 

condition, the reactor will not trip automatically when required. In either 

case, the affected RTCBs must be opened immediately by using the 

appropriate Manual Trip push buttons, since each of the four push 

buttons opens one set of RTCBs, independent of the initiation circuitry. 

Caution must be exercised, since depressing the wrong push buttons 

may result in a reactor trip. 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-10 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

If two Manual Trip channels are inoperable and affecting the same trip 

leg, the associated RTCBs must be opened immediately to ensure 

Manual Trip capability is maintained. With the affected RTCBs open, any 

one of two Manual Trip push buttons being depressed will result in a 

reactor trip. 

If the affected RTCB(s) cannot be opened, Condition E is entered. This 

would only occur if there is a failure in the Manual Trip circuitry or the 

RTCB(s). 

E.1 and E.2

Condition E is entered if Required Actions associated with Condition A, B, 

or D are not met within the required Completion Time or if for one or more 

Functions more than one Manual Trip, Matrix Logic, Initiation Logic, or 

RTCB channel is inoperable for reasons other than Condition A or D. 

If the RTCBs associated with the inoperable channel cannot be opened, 

the reactor must be shut down within 6 hours and all the RTCBs opened. 

A Completion Time of 6 hours is reasonable, based on operating 

experience, to reach the required MODE from full power conditions in an 

orderly manner and without challenging plant systems and to open 

RTCBs. All RTCBs should then be opened, placing the plant in a MODE 

where the LCO does not apply and ensuring no CEA withdrawal occurs. 

SURVEILLANCE -----------------------------------REVIEWER’S NOTE----------------------------------- 

REQUIREMENTS In order for a plant to take credit for topical reports as the basis for 

justifying Frequencies, topical reports must be supported by an NRC staff 

Safety Evaluation Report that establishes the acceptability of each topical 

report for that unit (Ref. 4). 

-------------------------------------------------------------------------------------------------- 

SR 3.3.3.1

A CHANNEL FUNCTIONAL TEST is performed on each RTCB channel 

every 31 days. This verifies proper operation of each RTCB. The RTCB 

must then be closed prior to testing the other RTCBs, or a reactor trip 

may result. The Frequency of 31 days is based on the reliability analysis 

presented in Topical Report CEN-327, "RPS/ESFAS Extended Test 

Interval Evaluation," (Ref. 5). 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-11 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.3.2

A CHANNEL FUNCTIONAL TEST on each RPS Logic channel is 

performed every [92] days to ensure the entire channel will perform its 

intended function when needed. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 

In addition to power supply tests, the RPS CHANNEL FUNCTIONAL 

TEST consists of three overlapping tests as described in Reference 3. 

These tests verify that the RPS is capable of performing its intended 

function, from bistable input through the RTCBs. The first test, the 

bistable test, is addressed by SR 3.3.1.4 in LCO 3.3.1. 

This SR addresses the two tests associated with the RPS Logic: Matrix 

Logic and Trip Path. 

Matrix Logic Tests

These tests are performed one matrix at a time. They verify that a 

coincidence in the two input channels for each Function removes power 

from the matrix relays. During testing, power is applied to the matrix relay 

test coils and prevents the matrix relay contacts from assuming their deenergized state. The Matrix Logic tests will detect any short circuits 

around the bistable contacts in the coincidence logic such as may be 

caused by faulty bistable relay or trip channel bypass contacts. 

Trip Path Tests

These tests are similar to the Matrix Logic tests, except that test power is 

withheld from one matrix relay at a time, allowing the initiation circuit to 

de-energize, opening the affected set of RTCBs. The RTCBs must then 

be closed prior to testing the other three initiation circuits, or a reactor trip 

may result. 

The Frequency of [92] days is based on the reliability analysis presented 

in topical report CEN-327, "RPS/ESFAS Extended Test Interval 

Evaluation" (Ref. 5). 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-12 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.3.3

A CHANNEL FUNCTIONAL TEST on the Manual Trip channels is 

performed prior to a reactor startup to ensure the entire channel will 

perform its intended function if required. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. The Manual Trip 

Function can be tested either at power or shutdown. However, the 

simplicity of this circuitry and the absence of drift concern makes this 

Frequency adequate. Additionally, operating experience has shown that 

these components usually pass the Surveillance when performed once 

within 7 days prior to each reactor startup. 

[ SR 3.3.3.4

Each RTCB is actuated by an undervoltage coil and a shunt trip coil. The 

system is designed so that either de-energizing the undervoltage coil or 

energizing the shunt trip coil will cause the circuit breaker to open. When 

an RTCB is opened, either during an automatic reactor trip or by using 

the manual push buttons in the control room, the undervoltage coil is deenergized and the shunt trip coil is energized. This makes it impossible to 

determine if one of the coils or associated circuitry is defective. 

Therefore, once every 18 months, a CHANNEL FUNCTIONAL TEST is 

performed that individually tests all four sets of undervoltage coils and all 

four sets of shunt trip coils. During undervoltage coil testing, the shunt 

trip coils shall remain de-energized, preventing their operation. 

Conversely, during shunt trip coil testing, the undervoltage coils shall 

remain energized, preventing their operation. This Surveillance ensures 

that every undervoltage coil and every shunt trip coil is capable of 

performing its intended function and that no single active failure of any 

RTCB component will prevent a reactor trip. A successful test of the 

required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 
RPS Logic and Trip Initiation (Analog) 

B 3.3.3 

CEOG STS B 3.3.3-13 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Specifications tests at least once per refueling interval with applicable 

extensions. 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. Operating experience has shown 

these components usually pass the Surveillance when performed at the 

Frequency of once every 18 months. 

If one set of RTCBs has been opened in response to a single RTCB 

channel, Initiation Logic channel, or Manual Trip channel failure, the 

affected set of RTCBs may be closed for up to 1 hour for Surveillance on 

the OPERABLE Initiation Logic, RTCB, and Manual Trip channels. In this 

case, the redundant set of RTCBs will provide protection if a trip should 

be required. It is unlikely that a trip will be required during the 

Surveillance, coincident with a failure of the remaining series RTCB 

channel. If a single matrix power supply or vital bus failure has opened 

two sets of RTCBs, Manual Trip and RTCB testing on the closed breakers 

cannot be performed without causing a trip. ] 

REFERENCES 1. 10 CFR 50, Appendix A. 

 2. 10 CFR 100. 

 3. FSAR, Section [7.2]. 

 4. NRC Safety Evaluation Report, [Date]. 

 5. CEN-327, June 2, 1986, including Supplement 1, March 3, 1989. 
CEACs (Digital) 

B 3.3.3 

CEOG STS B 3.3.3-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.3 Control Element Assembly Calculators (CEACs) (Digital) 

BASES 

BACKGROUND The Reactor Protective System (RPS) initiates a reactor trip to protect 

against violating the core specified acceptable fuel design limits 

(SAFDLs) and breaching the reactor coolant pressure boundary (RCPB) 

during anticipated operational occurrences (AOOs). By tripping the 

reactor, the RPS also assists the Engineered Safety Features systems in 

mitigating accidents. 

The protection and monitoring systems have been designed to ensure 

safe operation of the reactor. This is achieved by specifying limiting 

safety system settings (LSSS) in terms of parameters directly monitored 

by the RPS, as well as LCOs on other reactor system parameters and 

equipment performance. 

The LSSS (defined in this Specification as the Allowable Value), in 

conjunction with the LCOs, establish the thresholds for protective system 

action to prevent exceeding acceptable limits during Design Basis 

Accidents. 

During AOOs, which are those events expected to occur one or more 

times during the plant life, the acceptable limits are: 

• The departure from nucleate boiling ratio (DNBR) shall be maintained 

above the Safety Limit (SL) value to prevent departure from nucleate 

boiling, 

• Fuel centerline melting shall not occur, and 

• The Reactor Coolant System pressure SL of 2750 psia shall not be 

exceeded. 

Maintaining the parameters within the above values ensures that the 

offsite dose will be within the 10 CFR 50 (Ref. 1) and 10 CFR 100 (Ref. 2) 

criteria during AOOs. 

Accidents are events that are analyzed even though they are not 

expected to occur during the plant life. The acceptable limit during 

accidents is that the offsite dose shall be maintained within an acceptable 

fraction of 10 CFR 100 (Ref. 2) limits. Different accident categories allow 

a different fraction of these limits based on probability of occurrence. 

Meeting the acceptable dose limit for an accident category is considered 

having acceptable consequences for that event. 
CEACs (Digital) 

B 3.3.3 

CEOG STS B 3.3.3-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The RPS is segmented into four interconnected modules. These 

modules are: 

• Measurement channels, 

• Bistable trip units, 

• RPS Logic, and 

• Reactor trip circuit breakers (RTCBs). 

This LCO addresses the CEACs. LCO 3.3.1, "Reactor Protective System 

(RPS) Instrumentation - Operating," provides a description of this 

equipment in the RPS. 

The excore nuclear instrumentation, the core protection calculators 

(CPCs), and the CEACs are considered components in the measurement 

channels of the Linear Power Level - High, Logarithmic Power Level - 

High, DNBR - Low, and Local Power Density (LPD) - High trips. The 

CEACs are addressed by this Specification. 

All four CPCs receive control element assembly (CEA) deviation penalty 

factors from each CEAC and use the larger of the power factors from the 

two CEACs in the calculation of DNBR and LPD. CPCs are further 

described in the Background section of LCO 3.3.1. 

The CEACs perform the calculations required to determine the position of 

CEAs within their subgroups for the CPCs. Two independent CEACs 

compare the position of each CEA to its subgroup position. If a deviation 

is detected by either CEAC, an annunciator sounds and appropriate 

"penalty factors" are transmitted to all CPCs. These penalty factors 

conservatively adjust the effective operating margins to the DNBR - Low 

and LPD - High trips. Each CEAC also drives a single cathode ray tube 

(CRT), which is switchable between CEACs. The CRT displays individual 

CEA positions and current values of the penalty factors from the selected 

CEAC. 

Each CEA has two separate reed switch assemblies mounted outside the 

RCPB. Each of the two CEACs receives CEA position input from one of 

the two reed switch position transmitters on each CEA, so that the 

position of all CEAs is independently monitored by both CEACs. 
CEACs (Digital) 

B 3.3.3 

CEOG STS B 3.3.3-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Functional testing of the entire RPS, from bistable input through the 

opening of individual sets of RTCBs, can be performed either at power or 

shutdown and is normally performed on a quarterly basis. Nuclear 

instrumentation, the CPCs, and the CEACs can be similarly tested. 

FSAR, Section [7.2] (Ref. 3), provides more detail on RPS testing. 

Process transmitter calibration is normally performed on a refueling basis. 

APPLICABLE Each of the analyzed transients and accidents can be detected by one or 

SAFETY more RPS Functions. 

ANALYSES 

The effect of any misoperated CEA within a subgroup on the core power 

distribution is assessed by the CEACs, and an appropriately augmented 

power distribution penalty factor will be supplied as input to the CPCs. As 

the reactor core responds to the reactivity changes caused by the 

misoperated CEA and the ensuing reactor coolant and doppler feedback 

effects, the CPCs will initiate a DNBR - Low or LPD - High trip signal if 

SAFDLs are approached. Each CPC also directly monitors one "target 

CEA" from each subgroup and uses this information to account for 

excessive radial peaking factors for events involving CEA groups out of 

sequence and subgroup deviations within a group, without the need for 

CEACs. 

Therefore, although the CEACs do not provide a direct reactor trip 

Function, their input to the CPCs is taken credit for in the CEA 

misoperation analysis. 

The CEACs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO This LCO on the CEACs ensures that the CPCs are either informed of 

individual CEA position within each subgroup, using one or both CEACs, 

or that appropriate conservatism is included in the CPC calculations to 

account for anticipated CEA deviations. Each CEAC provides an 

identical input into all four CPC channels. Each CPC uses the higher of 

the two CEAC transmitted CEA deviation penalty factors. Thus, only one 

OPERABLE CEAC is required to provide CEA deviation protection. This 

LCO requires both CEACs to be OPERABLE so that no single CEAC 

failure can prevent a required reactor trip from occurring. 
CEACs (Digital) 

B 3.3.3 

CEOG STS B 3.3.3-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY Most RPS trips are required to be OPERABLE in MODES 1 and 2 

because the reactor is critical in these MODES. The trips are designed to 

take the reactor subcritical, which maintains the SLs during AOOs and 

assists the Engineered Safety Features Actuation System in providing 

acceptable consequences during accidents. Most trips are not required 

to be OPERABLE in MODES 3, 4, and 5. In MODES 3, 4, and 5, the 

emphasis is placed on return to power events. The reactor is protected in 

these MODES by ensuring adequate SDM. 

Because CEACs provide the inputs to the DNBR - Low and LPD - High 

trips, they are required to be OPERABLE in the same MODES as those 

trips for the same reasons. 

ACTIONS A.1 and A.2

Condition A applies to the failure of a single CEAC channel. There are 

only two CEACs, each providing CEA deviation input into all four CPC 

channels. The CEACs include complex diagnostic software, making it 

unlikely that a CEAC will fail without informing the CPCs of its failed 

status. With one failed CEAC, the CPC will receive CEA deviation 

penalty factors from the remaining OPERABLE CEAC. If the second 

CEAC should fail (Condition B), the CPC will use large preassigned 

penalty factors. The specific Required Actions allowed are as follows: 

With one CEAC inoperable, the second CEAC still provides a 

comprehensive set of comparison checks on individual CEAs within 

subgroups, as well as outputs to all CPCs, CEA deviation alarms, and 

position indication for display. Verification every 4 hours that each CEA is 

within 7 inches of the other CEAs in its group provides a check on the 

position of all CEAs and provides verification of the proper operation of 

the remaining CEAC. An OPERABLE CEAC will not generate penalty 

factors until deviations of > 7 inches within a subgroup are encountered. 

The Completion Time of once per 4 hours is adequate based on 

operating experience, considering the low probability of an undetected 

CEA deviation coincident with an undetected failure in the remaining 

CEAC within this limited time frame. 

As long as Required Action A.1 is accomplished as specified, the 

inoperable CEAC can be restored to OPERABLE status within 7 days. 

The Completion Time of 7 days is adequate for most repairs, while 

minimizing risk, considering that dropped CEAs are detectable by the 

redundant CEAC, and other LCOs specify Required Actions necessary to 

maintain DNBR and LPD margin. 
CEACs (Digital) 

B 3.3.3 

CEOG STS B 3.3.3-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1, B.2, B.3, B.4, and B.5

Condition B applies if the Required Action and associated Completion 

Time of Required Action A are not met, or if both CEACs are inoperable. 

Actions associated with this Condition involve disabling the Control 

Element Drive Mechanism Control System (CEDMCS), while providing 

increased assurance that CEA deviations are not occurring and informing 

all OPERABLE CPC channels, via a software flag, that both CEACs are 

failed. This will ensure that the large penalty factor associated with two 

CEAC failures will be applied to CPC calculations. The penalty factor for 

two failed CEACs is sufficiently large that power must be maintained 

significantly < 100% RTP if CPC generated reactor trips are to be 

avoided. The Completion Time of 4 hours is adequate to accomplish 

these actions while minimizing risks. 

The Required Actions are as follows: 

B.1

Meeting the DNBR margin requirements of LCO 3.2.5, "AXIAL SHAPE 

INDEX (ASI)," ensures that power level and ASI are within a conservative 

region of operation based on actual core conditions. In addition to the 

above actions, the Reactor Power Cutback (RPCB) System must be 

disabled. This ensures that CEA position will not be affected by RPCB 

operation. 

B.2

The "full out" CEA reed switches provide acceptable indication of CEA 

position. Therefore, the CEAs will remain fully withdrawn, except as 

required for specified testing or flux control via group #6. This verification 

ensures that undesired perturbations in local fuel burnup are prevented. 

B.3

The "RSPT/CEAC Inoperable" addressable constant in each of the CPCs 

is set to indicate that both CEACs are inoperable. This provides a 

conservative penalty factor to ensure that a conservative effective margin 

is maintained by the CPCs in the computation of DNBR and LPD trips. 
CEACs (Digital) 

B 3.3.3 

CEOG STS B 3.3.3-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.4

The CEDMCS is placed and maintained in "OFF," except during CEA 

motion permitted by Required Action B.2, to prevent inadvertent motion 

and possible misalignment of the CEAs. 

B.5

A comprehensive set of comparison checks on individual CEAs within 

groups must be made within 4 hours. Verification that each CEA is within 

7 inches of other CEAs in its group provides a check that no CEA has 

deviated from its proper position within the group. 

C.1

Condition C applies if the CPC channel B or C cabinet receives a high 

temperature alarm. There is one temperature sensor in each of the four 

CPC bays. Since CPC bays B and C also house CEAC calculators 1 

and 2, respectively, a high temperature in either of these bays may also 

indicate a problem with the associated CEAC. 

If a CPC channel B or C cabinet high temperature alarm is received, it is 

possible for the CEAC to be affected and not be completely reliable. 

Therefore, a CHANNEL FUNCTIONAL TEST must be performed within 

12 hours. The Completion Time of 12 hours is adequate, considering the 

low probability of undetected failure, the consequences of failure, and the 

time required to perform a CHANNEL FUNCTIONAL TEST. 

D.1

Condition D applies if an OPERABLE CEAC has three or more 

autorestarts in a 12 hour period. 

CPCs and CEACs will attempt to autorestart if they detect a fault 

condition such as a calculator malfunction or loss of power. A successful 

autorestart restores the calculator to operation; however, excessive 

autorestarts might be indicative of a calculator problem. 
CEACs (Digital) 

B 3.3.3 

CEOG STS B 3.3.3-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

If a nonbypassed CEAC has three or more autorestarts, it may not be 

completely reliable. Therefore, a CHANNEL FUNCTIONAL TEST must 

be performed on the CEAC to ensure it is functioning properly. Based on 

plant operating experience, the Completion Time of 24 hours is adequate 

and reasonable to perform the test while still keeping the risk of operating 

in this condition at an acceptable level, since overt channel failure will 

most likely be indicated and annunciated by CPC online diagnostics. 

E.1

Condition E is entered when the Required Action and associated 

Completion Time of Condition B, C, or D are not met. 

If the Required Actions associated with these Conditions cannot be 

completed within the required Completion Time, the reactor must be 

brought to a MODE where the Required Actions do not apply. The 

Completion Time of 6 hours is reasonable, based on operating 

experience, for reaching the required plant conditions from full power 

conditions in an orderly manner and without challenging plant systems. 

SURVEILLANCE -----------------------------------REVIEWER’S NOTE----------------------------------- 

REQUIREMENTS In order for a plant to take credit for topical reports as the basis for 

justifying Frequencies, topical reports must be supported by an NRC staff 

Safety Evaluation Report that establishes the acceptability of each topical 

report for that plant (Ref. 4). 

-------------------------------------------------------------------------------------------------- 

SR 3.3.3.1

Performance of the CHANNEL CHECK once every 12 hours ensures that 

gross failure of instrumentation has not occurred. A CHANNEL CHECK 

is normally a comparison of the parameter indicated on one channel to a 

similar parameter on another channel. 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 or of 

something even more serious. CHANNEL CHECK will detect gross 

channel failure; thus, it is key to verifying that the instrumentation 

continues to operate properly between each CHANNEL CALIBRATION. 
CEACs (Digital) 

B 3.3.3 

CEOG STS B 3.3.3-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Agreement criteria are determined by the plant staff, based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the sensor or the signal processing equipment has drifted outside its 

limits. 

The Frequency, about once every shift, is based on operating experience 

that demonstrates the rarity of channel failure. Since the probability of 

two random failures in redundant channels in any 12 hour period is 

extremely low, the CHANNEL CHECK minimizes the chance of loss of 

protective function due to failure of redundant channels. The CHANNEL 

CHECK supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of the displays associated 

with the LCO required channels. 

SR 3.3.3.2

The CEAC autorestart count is checked every 12 hours to monitor the 

CPC and CEAC for normal operation. If three or more autorestarts of a 

nonbypassed CPC occur within a 12 hour period, the CPC may not be 

completely reliable. Therefore, the Required Action of Condition D must 

be performed. The Frequency is based on operating experience that 

demonstrates the rarity of more than one channel failing within the same 

12 hour interval. 

SR 3.3.3.3

A CHANNEL FUNCTIONAL TEST on each CEAC channel is performed 

every 92 days to ensure the entire channel will perform its intended 

function when needed. The quarterly CHANNEL FUNCTIONAL TEST is 

performed using test software. The Frequency of 92 days is based on the 

reliability analysis presented in topical report CEN-327, "RPS/ESFAS 

Extended Test Interval Evaluation" (Ref. 5). A successful test of the 

required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. 
CEACs (Digital) 

B 3.3.3 

CEOG STS B 3.3.3-9 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.3.4

SR 3.3.3.4 is the performance of a CHANNEL CALIBRATION every 

[18] months. 

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the sensor. The Surveillance verifies that the channel responds 

to a measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive surveillances. 

CHANNEL CALIBRATIONS must be performed consistent with the plant 

specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [5]. 

The Frequency is based upon the assumption of an [18] month calibration 

interval in the determination of the magnitude of equipment drift in the 

setpoint analysis and includes operating experience and consistency with 

the typical [18] month fuel cycle. 

SR 3.3.3.5

Every [18] months, a CHANNEL FUNCTIONAL TEST is performed on the 

CEACs. The CHANNEL FUNCTIONAL TEST shall include the injection 

of a signal as close to the sensors as practicable to verify OPERABILITY, 

including alarm and trip Functions. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 

The basis for the [18] month Frequency is that the CEACs perform a 

continuous self monitoring function that eliminates the need for frequent 

CHANNEL FUNCTIONAL TESTS. This CHANNEL FUNCTIONAL TEST 

essentially validates the self monitoring function and checks for a small 

set of failure modes that are undetectable by the self monitoring function. 

Operating experience has shown that undetected CPC or CEAC failures 

do not occur in any given [18] month interval. 
CEACs (Digital) 

B 3.3.3 

CEOG STS B 3.3.3-10 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.3.6

The isolation characteristics of each CEAC CEA position isolation 

amplifier and each optical isolator for CEAC to CPC data transfer are 

verified once per refueling to ensure that a fault in a CEAC or a CPC 

channel will not render another CEAC or CPC channel inoperable. The 

CEAC CEA position isolation amplifiers, mounted in CPC cabinets A 

and D, prevent a CEAC fault from propagating back to CPC A or D. The 

optical isolators for CPC to CEAC data transfer prevent a fault originating 

in any CPC channel from propagating back to any CEAC through this 

data link. 

The Frequency is based on plant operating experience with regard to 

channel OPERABILITY, which demonstrates the failure of a channel in 

any [18] month interval is rare. 

REFERENCES 1. 10 CFR 50. 

 2. 10 CFR 100. 

 3. FSAR, Section [7.2]. 

 4. NRC Safety Evaluation Report, [Date]. 

 5. CEN-327, June 2, 1986, including Supplement 1, March 3, 1989. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.4 Engineered Safety Features Actuation System (ESFAS) Instrumentation (Analog) 

BASES 

BACKGROUND The ESFAS initiates necessary safety systems, based upon the values of 

selected unit parameters, to protect against violating core design limits 

and the Reactor Coolant System (RCS) pressure boundary and to 

mitigate accidents. 

The ESFAS contains devices and circuitry that generate the following 

signals when the monitored variables reach levels that are indicative of 

conditions requiring protective action: 

1. Safety Injection Actuation Signal (SIAS), 

2. Containment Spray Actuation Signal (CSAS), 

3. Containment Isolation Actuation Signal (CIAS), 

4. Main Steam Isolation Signal (MSIS), 

5. Recirculation Actuation Signal (RAS), and 

6. Auxiliary Feedwater Actuation Signal (AFAS). 

Equipment actuated by each of the above signals is identified in the 

FSAR (Ref. 1). 

Each of the above ESFAS actuation systems is segmented into four 

sensor subsystems and two actuation subsystems. Each sensor 

subsystem includes measurement channels and bistables. The actuation 

subsystems include two logic subsystems for sequentially loading the 

diesel generators. 

Each of the four sensor subsystem channels monitors redundant and 

independent process measurement channels. Each sensor is monitored 

by at least one bistable. The bistable associated with each ESFAS 

Function will trip when the monitored variable exceeds the trip setpoint. 

When tripped, the sensor subsystems provide outputs to the two 

actuation subsystems. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The two independent actuation subsystems compare the four sensor 

subsystem outputs. If a trip occurs in the same parameter in two or more 

sensor subsystem channels, the two-out-of-four logic in each actuation 

subsystem will initiate one train of ESFAS. Each train can provide 

protection to the public in the case of a Design Basis Event. Actuation 

Logic is addressed in LCO 3.3.5, "Engineered Safety Features Actuation 

System (ESFAS) Logic and Manual Trip." 

Each of the four sensor subsystems is mounted in a separate cabinet, 

excluding the sensors and field wiring. 

The role of the sensor subsystem (measurement channels and bistables) 

is discussed below; actuation subsystems are discussed in LCO 3.3.5. 

Measurement Channels

Measurement channels, consisting of field transmitters or process 

sensors and associated instrumentation, provide a measurable electronic 

signal based upon the physical characteristics of the parameter being 

measured. 

Four identical measurement channels with electrical and physical 

separation are provided for each parameter used in the generation of trip 

signals. These are designated Channels A through D. Measurement 

channels provide input to ESFAS bistables within the same ESFAS 

channel. In addition, some measurement channels may also be used as 

inputs to Reactor Protective System (RPS) bistables, and most provide 

indication in the control room. Measurement channels used as an input 

to the RPS or ESFAS are not used for control Functions. 

When a channel monitoring a parameter indicates an unsafe condition, 

the bistable monitoring the parameter in that channel will trip. Tripping 

two or more channels of bistables monitoring the same parameter will deenergize both channels of Actuation Logic of the associated Engineered 

Safety Features (ESF) equipment. 

Three of the four measurement and bistable channels are necessary to 

meet the redundancy and testability of GDC 21 in Appendix A to 

10 CFR 50 (Ref. 2). The fourth channel provides additional flexibility by 

allowing one channel to be removed from service (trip channel bypass) 

for maintenance or testing while still maintaining a minimum two-out-ofthree logic. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

In order to take full advantage of the four channel design, adequate 

channel to channel independence must be demonstrated, and approved 

by the NRC staff. Plants not currently licensed as to credit four channel 

independence that may desire this capability must have approval of the 

NRC staff documented by an NRC Safety Evaluation Report (Ref. 3). 

Adequate channel to channel independence includes physical and 

electrical independence of each channel from the others. Furthermore, 

each channel must be energized from separate inverters and station 

batteries. Plants not demonstrating four channel independence may 

operate in a two-out-of-three logic configuration for 48 hours. 

Since no single failure will either cause or prevent a protective system 

actuation and no protective channel feeds a control channel, this 

arrangement meets the requirements of IEEE Standard 79-1971 (Ref. 4). 

Bistable Trip Units

Bistable trip units receive an analog input from the measurement 

channels, compare the analog input to trip setpoints, and provide contact 

output to the Actuation Logic. They also provide local trip indication and 

remote annunciation. 

There are four channels of bistables, designated A through D, for each 

ESF Function, one for each measurement channel. In cases where two 

ESF Functions share the same input and trip setpoint (e.g., containment 

pressure input to CSAS, CIAS, and SIAS and a Pressurizer Pressure - 

Low input to the RPS and SIAS), the same bistable may be used to 

satisfy both Functions. 

The trip setpoints and Allowable Values used in the bistables are based 

on the analytical limits stated in Reference 5. The selection of these trip 

setpoints is such that adequate protection is provided when all sensor 

and processing time delays are taken into account. To allow for 

calibration tolerances, instrumentation uncertainties, instrument drift, and 

severe environment effects, for those ESFAS channels that must function 

in harsh environments as defined by 10 CFR 50.49 (Ref. 6), Allowable 

Values specified in Table 3.3.4-1, in the accompanying LCO, are 

conservatively adjusted with respect to the analytical limits. A detailed 

description of the method used to calculate the trip setpoints, including 

their explicit uncertainties, is provided in the "Plant Protection System 

Selection of Trip Setpoint Values" (Ref. 7). The actual nominal trip 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-4 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

setpoint entered into the bistable is normally still more conservative than 

that specified by the Allowable Value to account for changes in random 

measurement errors detectable by a CHANNEL FUNCTIONAL TEST. If 

the measured setpoint does not exceed the Allowable Value, the bistable 

is considered OPERABLE. 

Setpoints in accordance with the Allowable Value will ensure that Safety 

Limits of Chapter 2.0, "SAFETY LIMITS (SLs)," are not violated during 

anticipated operational occurrences (AOOs) and that the consequences 

of Design Basis Accidents (DBAs) will be acceptable, providing the plant 

is operated from within the LCOs at the onset of the AOO or DBA and the 

equipment functions as designed. 

ESFAS Logic

It is possible to change the two-out-of-four ESFAS logic to a two-out-ofthree logic for a given input parameter in one channel at a time by 

disabling one channel input to the logic. Thus, the bistables will function 

normally, producing normal trip indication and annunciation, but ESFAS 

actuation will not occur since the bypassed channel is effectively removed 

from the coincidence logic. Trip channel bypassing can be 

simultaneously performed on any number of parameters in any number of 

channels, providing each parameter is bypassed in only one channel at a 

time. At some plants an interlock prevents simultaneous trip channel 

bypassing of the same parameter in more than one channel. Trip 

channel bypassing is normally employed during maintenance or testing. 

ESFAS Logic is addressed in LCO 3.3.5. 

APPLICABLE Each of the analyzed accidents can be detected by one or more ESFAS 

SAFETY Functions. One of the ESFAS Functions is the primary actuation signal 

ANALYSES for that accident. An ESFAS Function may be the primary actuation 

signal for more than one type of accident. An ESFAS Function may also 

be a secondary, or backup, actuation signal for one or more other 

accidents. Functions such as Manual Initiation, not specifically credited in 

the accident analysis, serve as backups to Functions and are part of the 

NRC approved licensing basis for the plant. 

ESFAS protective Functions are as follows: 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

1. Safety Injection Actuation Signal

The SIAS ensures acceptable consequences during loss of coolant 

accident (LOCA) events, including steam generator tube rupture, and 

main steam line breaks (MSLBs) or feedwater line breaks (FWLBs) 

(inside containment). To provide the required protection, either a 

high containment pressure or a low pressurizer pressure signal will 

initiate SIAS. SIAS initiates the Emergency Core Cooling Systems 

(ECCS), control room isolation, and several other Functions, such as 

starting the emergency diesel generators. 

2. Containment Spray Actuation Signal

The CSAS initiates containment spray, preventing containment 

overpressurization during a LOCA or MSLB. At some plants, both a 

high containment pressure signal and an SIAS have to actuate to 

provide the required protection. This configuration reduces the 

likelihood of inadvertent containment spray. 

3. Containment Isolation Actuation Signal

The CIAS actuates the Containment Isolation System, ensuring 

acceptable consequences during LOCAs and MSLBs or FWLBs 

(inside containment). To provide protection, a high containment 

pressure signal will initiate CIAS at the same setpoint at which an 

SIAS is generated. 

4. Main Steam Isolation Signal

The MSIS ensures acceptable consequences during an MSLB or 

FWLB by isolating both steam generators if either generator indicates 

a low steam generator pressure. The MSIS, concurrent with or 

following a reactor trip, minimizes the rate of heat extraction and 

subsequent cooldown of the RCS during these events. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-6 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

5. Recirculation Actuation Signal

At the end of the injection phase of a LOCA, the refueling water tank 

(RWT) will be nearly empty. Continued cooling must be provided by 

the ECCS to remove decay heat. The source of water for the ECCS 

pumps is automatically switched to the containment recirculation 

sump. Switchover from RWT to the containment sump must occur 

before the RWT empties to prevent damage to the ECCS pumps and 

a loss of core cooling capability. For similar reasons, switchover 

must not occur before there is sufficient water in the containment 

sump to support pump suction. Furthermore, early switchover must 

not occur to ensure sufficient borated water is injected from the RWT 

to ensure the reactor remains shut down in the recirculation mode. 

An RWT Level - Low signal initiates the RAS. 

6. Auxiliary Feedwater Actuation Signal

An AFAS initiates feedwater flow to both steam generators if a low 

level is indicated in either steam generator, unless the generator is 

ruptured. 

The AFAS maintains a steam generator heat sink during the following 

events: 

• MSLB, 

• FWLB, 

• Inadvertent opening of a steam generator atmospheric dump 

valve, and 

• Loss of feedwater. 

A low steam generator water level signal will initiate auxiliary feed to 

the affected steam generator. 

Secondary steam generator (SG) differential pressure (SG-A > SG-B) 

or (SG-B > SG-A) inhibits auxiliary feed to a generator identified as 

being ruptured. This input to the AFAS logic prevents loss of the 

intact generator while preventing feeding a ruptured generator during 

MSLBs and FWLBs. This prevents containment overpressurization 

during these events. 

The ESFAS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-7 Rev. 3.0, 03/31/04 

BASES 

LCO The LCO requires all channel components necessary to provide an 

ESFAS actuation to be OPERABLE. 

The Bases for the LCO on ESFAS Functions are: 

1. Safety Injection Actuation Signal

a. Containment Pressure - High

This LCO requires four channels of SIAS Containment Pressure 

- High to be OPERABLE in MODES 1, 2, and 3. 

The Allowable Value for this trip is set high enough to allow for 

small pressure increases in containment expected during normal 

operation (i.e., plant heatup) and is not indicative of an offnormal 

condition. The setting is low enough to initiate the ESF 

Functions when an offnormal condition is indicated. This allows 

the ESF systems to perform as expected in the accident 

analyses to mitigate the consequences of the analyzed 

accidents. 

b. Pressurizer Pressure - Low

This LCO requires four channels of SIAS Pressurizer Pressure - 

Low to be OPERABLE in MODES 1, 2, and 3. 

The Allowable Value for this trip is set low enough to prevent 

actuating the SIAS during normal plant operation and pressurizer 

pressure transients. The setting is high enough that with a 

LOCA or MSLB it will actuate to perform as expected, mitigating 

the consequences of the accidents. 

The Pressurizer Pressure - Low trip may be blocked when 

pressurizer pressure is reduced during controlled plant 

shutdowns. This block is permitted below 1800 psia, and block 

permissive responses are annunciated in the control room. This 

allows for a controlled depressurization of the RCS, while 

maintaining administrative control of ESF protection. From a 

blocked condition, the block will be automatically removed as 

pressurizer pressure increases above 1800 psia, as sensed by 

two of the four sensor subsystems, in accordance with the 

bypass philosophy of removing bypasses when the enabling 

conditions are no longer satisfied. 

This LCO requires four channels of the bypass permissive 

removal for SIAS Pressurizer Pressure - Low to be OPERABLE 

in MODES 1, 2, and 3. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-8 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The bypass permissive channels consist of four sensor 

subsystems and two actuation subsystems. This LCO applies to 

failures in the four sensor subsystems, including sensors, 

bistables, and associated equipment. Failures in the actuation 

subsystems, including the manual bypass key switches, are 

considered Actuation Logic failures and are addressed in 

LCO 3.3.5. 

This LCO applies to the bypass removal feature only. If the 

bypass enable Function is failed so as to prevent entering a 

bypass condition, operation may continue. 

The block permissive is set low enough so as not to be enabled 

during normal plant operation, but high enough to allow blocking 

prior to reaching the trip setpoint. 

2. Containment Spray Actuation Signal

CSAS is initiated either manually or automatically. At many plants, it 

is also necessary to have an automatic or manual SIAS for complete 

actuation. The SIAS opens the containment spray valves, whereas 

the CSAS actuates other required components. The SIAS 

requirement should always be satisfied on a legitimate CSAS, since 

the Containment Pressure - High signal setpoint used in the SIAS is 

the same setpoint used in the CSAS. At many plants, the 

transmitters used to initiate CSAS are independent of those used in 

the SIAS to prevent inadvertent containment spray due to failures in 

two sensor channels. 

a. Containment Pressure - High

This LCO requires four channels of CSAS Containment Pressure 

- High to be OPERABLE in MODES 1, 2, and 3. 

The Allowable Value is set high enough to allow for small 

pressure increases in containment expected during normal 

operation (i.e., plant heatup) and is not indicative of an offnormal 

condition. The setting is low enough to initiate the ESF 

Functions when an offnormal condition is indicated. This allows 

the ESF systems to perform as expected in the accident 

analyses to mitigate the consequences of the analyzed 

accidents. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-9 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The Containment Pressure - High setpoint is the same in the 

SIAS (Function 1), CSAS (Function 2), and CIAS (Function 3). 

However, different sensors and logic are used in each of these 

Functions. 

3. Containment Isolation Actuation Signal

a. Containment Pressure - High

This LCO requires four channels of CIAS Containment Pressure 

- High to be OPERABLE in MODES 1, 2, and 3. 

The Allowable Value is set high enough to allow for small 

pressure increases in containment expected during normal 

operation (i.e., plant heatup) and is not indicative of an offnormal 

condition. The setting is low enough to initiate the ESF 

Functions when an offnormal condition is indicated. This allows 

the ESF systems to perform as expected in the accident 

analyses to mitigate the consequences of the analyzed 

accidents. 

The Containment Pressure - High setpoint is the same in the 

SIAS (Function 1), CSAS (Function 2), and CIAS (Function 3). 

However, different sensors and logic are used in each of these 

Functions. 

b. Containment Radiation - High

This LCO requires four channels of CIAS Containment Radiation 

- High to be OPERABLE in MODES 1, 2, and 3. 

The Allowable Value is high enough to avoid unnecessary 

actuation, but adequate to provide diverse actuation of the CIAS 

in the event of a LOCA. 

4. Main Steam Isolation Signal

The MSIS is required to be OPERABLE in MODES 1, 2, and 3 

except when all associated valves are closed and de-activated. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-10 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

a. Steam Generator Pressure - Low

This LCO requires four channels of MSIS Steam Generator 

Pressure - Low for each steam generator to be OPERABLE in 

MODES 1, 2, and 3. 

The Allowable Value is set below the full load operating value for 

steam pressure so as not to interfere with normal plant 

operation. However, the setting is high enough to provide the 

required protection for excessive steam demand. An excessive 

steam demand causes the RCS to cool down, resulting in a 

positive reactivity addition to the core. An MSIS is required to 

prevent the excessive cooldown. 

This Function may be manually blocked when steam generator 

pressure is reduced during controlled plant cooldowns. The 

block is permitted below 785 psia, and block permissive 

responses are annunciated in the control room. This allows a 

controlled depressurization of the secondary system, while 

maintaining administrative control of ESF protection. From a 

blocked condition, the block will be removed automatically as 

steam generator pressure increases above 785 psia, as sensed 

by two of the four sensor subsystems, in accordance with the 

bypass philosophy of removing bypasses when the enabling 

conditions are no longer satisfied. 

This LCO requires four channels per steam generator of the 

bypass removal for MSIS Steam Generator Pressure - Low to be 

OPERABLE in MODES 1, 2, and 3. 

The bypass removal channels consist of four sensor subsystems 

and two actuation subsystems. This LCO applies to failures in 

the four sensor subsystems, including sensors, bistables, and 

associated equipment. Failures in the actuation subsystems, 

including the manual bypass key switches, are considered 

Actuation Logic failures and are addressed in LCO 3.3.5. 

This LCO applies to the bypass removal feature only. If the 

bypass enable Function is failed so as to prevent entering a 

bypass condition, operation may continue. 

The block permissive is set low enough so as not to be enabled 

during normal plant operation, but high enough to allow blocking 

prior to reaching the trip setpoint. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-11 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

5. Recirculation Actuation Signal

a. Refueling Water Tank Level - Low

This LCO requires four channels of RWT Level - Low to be 

OPERABLE in MODES 1, 2, and 3. 

The upper limit on the Allowable Value for this trip is set low 

enough to ensure RAS does not initiate before sufficient water is 

transferred to the containment sump. Premature recirculation 

could impair the reactivity control Function of safety injection by 

limiting the amount of boron injection. Premature recirculation 

could also damage or disable the recirculation system if 

recirculation begins before the sump has enough water to 

prevent air containment in the suction. The lower limit on the 

RWT Level - Low trip Allowable Value is high enough to transfer 

suction to the containment sump prior to emptying the RWT. 

6. Auxiliary Feedwater Actuation Signal

The AFAS logic actuates auxiliary feedwater (AFW) to a steam 

generator on low level in that generator unless it has been identified 

as being ruptured. 

A low level in either generator, as sensed by a two-out-of-four 

coincidence of four wide range sensors for any generator, will 

generate an AFAS start signal, which starts both trains of AFW 

pumps and feeds both steam generators. The AFAS also monitors 

the secondary differential pressure in both steam generators and 

initiates an AFAS block signal to a ruptured generator, if the pressure 

in that generator is lower than that in the other generator by the 

differential pressure setpoint. 

a. Steam Generator A/B Level - Low

This LCO requires four channels for each steam generator of 

Steam Generator Level - Low to be OPERABLE in MODES 1, 2, 

and 3. 

The Allowable Value ensures adequate time exists to initiate 

AFW while the steam generators can function as a heat sink. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-12 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

b. Steam Generator Pressure Difference - High

(SG-A > SG-B) or (SG-B > SG-A)

This LCO requires four channels per steam generator of Steam 

Generator Pressure Difference - High to be OPERABLE in 

MODES 1, 2, and 3. 

The Allowable Value for this trip is high enough to allow for small 

pressure differences and normal instrumentation errors between 

the steam generator channels during normal operation without 

an actuation. The setting is low enough to detect and inhibit 

feeding of a ruptured steam generator in the event of an MSLB 

or FWLB, while permitting the feeding of the intact steam 

generator. 

APPLICABILITY All ESFAS Functions are required to be OPERABLE in MODES 1, 2, 

and 3. In MODES 1, 2, and 3 there is sufficient energy in the primary and 

secondary systems to warrant automatic ESF System responses to: 

• Close the main steam isolation valves to preclude a positive reactivity 

addition, 

• Actuate AFW to preclude the loss of the steam generators as a heat 

sink (in the event the normal feedwater system is not available), 

• Actuate ESF systems to prevent or limit the release of fission product 

radioactivity to the environment by isolating containment and limiting 

the containment pressure from exceeding the containment design 

pressure during a design basis LOCA or MSLB, and 

• Actuate ESF systems to ensure sufficient borated inventory to permit 

adequate core cooling and reactivity control during a design basis 

LOCA or MSLB accident. 

In MODES 4, 5, and 6, automatic actuation of ESFAS Functions is not 

required because adequate time is available for plant operators to 

evaluate plant conditions and respond by manually operating the ESF 

components, if required, as addressed by LCO 3.3.5. In LCO 3.3.5, 

manual capability is required for Functions other than AFAS in MODE 4, 

even though automatic actuation is not required. Because of the large 

number of components actuated on each ESFAS, actuation is simplified 

by the use of the Manual Trip push buttons. Manual Trip of AFAS is not 

required in MODE 4 because AFW or shutdown cooling will already be in 

operation in this MODE. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-13 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY (continued) 

The ESFAS Actuation Logic must be OPERABLE in the same MODES as 

the automatic and Manual Trip. In MODE 4, only the portion of the 

ESFAS logic responsible for the required Manual Trip must be 

OPERABLE. 

In MODES 5 and 6, ESFAS initiated systems are either reconfigured or 

disabled for shutdown cooling operation. Accidents in these MODES are 

slow to develop and would be mitigated by manual operation of individual 

components. 

ACTIONS The most common cause of channel inoperability is outright failure or drift 

of the bistable or process module sufficient to exceed the tolerance 

allowed by the plant specific setpoint analysis. 

Typically, the drift is small and results in a delay of actuation rather than a 

total loss of function. Determination of setpoint drift is generally made 

during the performance of a CHANNEL FUNCTIONAL TEST when the 

process instrument is set up for adjustment to bring it to within 

specification. If the actual trip setpoint is not within the Allowable Value in 

Table 3.3.4-1, the channel is inoperable and the appropriate Condition(s) 

are entered. 

In the event a channel's trip setpoint is found nonconservative with 

respect to the Allowable Value in Table 3.3.4-1, or the sensor, instrument 

loop, signal processing electronics, or ESFAS bistable is found 

inoperable, then all affected Functions provided by that channel must be 

declared inoperable and the plant must enter the Condition statement for 

the particular protection Function affected. 

When the number of inoperable channels in a trip Function exceeds those 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 should 

be immediately entered if applicable in the current MODE of operation. 

A Note has been added to clarify the application of the Completion Time 

rules. The Conditions of this Specification may be entered independently 

for each Function in Table 3.3.4-1. Completion Times for the inoperable 

channel of a Function will be tracked separately. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-14 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

[ A.1

Condition A applies to one CSAS Containment Pressure - High channel 

inoperable. CSAS logic is identical to that of the other ESFAS Functions; 

however, the inadvertent actuation of a CSAS is undesirable, since it may 

damage equipment inside containment. For this reason, placing the 

inoperable channel in trip is not an option as it is in Conditions B and C. ]

[ For those plants in which the SIAS is required for a complete CSAS 

actuation, Condition B for one ESFAS channel inoperable and 

Condition C for two ESFAS channels inoperable may be preferable to 

Condition A. 

If one CSAS channel is inoperable, operation is allowed to continue, 

providing the inoperable channel is placed in bypass within 1 hour. The 

Completion Time of 1 hour allotted to bypass the channel is sufficient to 

allow the operator to take all appropriate actions for the failed channel 

and still ensures that the risk involved in operating with the failed channel 

is acceptable. ]

B.1, B.2.1, and B.2.2

Condition B applies to the failure of a single channel of one or more input 

parameters in the following ESFAS Functions: 

1. Safety Injection Actuation Signal 

 Containment Pressure - High 

Pressurizer Pressure – Low 

3. Containment Isolation Actuation Signal 

Containment Pressure - High 

Containment Radiation - High 

4. Main Steam Isolation Signal 

Steam Generator Pressure - Low 

5. Recirculation Actuation Signal 

Refueling Water Tank Level - Low 

6. Auxiliary Feedwater Actuation Signal 

Steam Generator Level - Low 

Steam Generator Pressure Difference - High 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-15 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

ESFAS coincidence logic is normally two-out-of-four. If one ESFAS 

channel is inoperable, startup or power operation is allowed to continue 

as long as action is taken to restore the design level of redundancy. 

If one ESFAS channel is inoperable, startup or power operation is allowed 

to continue, providing the inoperable channel is placed in bypass or trip 

within 1 hour (Required Action B.1). With one channel in bypass, no 

additional random failure of a single channel could spuriously trip the 

reactor and a valid trip signal can still trip the reactor. With one channel 

in trip, an additional random failure of a single channel could spuriously 

trip the reactor. Therefore, it is preferable to place an inoperable channel 

in bypass rather than trip. 

The Completion Time of 1 hour allotted to bypass or trip the channel is 

sufficient to allow the operator to take all appropriate actions for the failed 

channel and still ensures that the risk involved in operating with the failed 

channel is acceptable. 

One failed channel is restored to OPERABLE status or is placed in trip 

within [48] hours (Required Action B.2.1 or B.2.2). Required Action B.2.1 

restores the full capability of the function. Required Action B.2.2 places 

the function in a one-out-of-three configuration. In this configuration, 

common cause failure of the dependent channel cannot prevent ESFAS 

actuation. The [48] hour Completion Time is based upon operating 

experience, which has demonstrated that a random failure of a second 

channel occurring during the [48] hour period is a low probability event. 

C.1 and C.2

Condition C applies to the failure of two channels in any of the following 

ESFAS functions: 

1. Safety Injection Actuation Signal 

Containment Pressure - High 

Pressurizer Pressure - Low 

3. Containment Isolation Actuation Signal 

Containment Pressure - High 

Containment Radiation - High 

4. Main Steam Isolation Signal 

Steam Generator Pressure - Low 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-16 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

5. Recirculation Actuation Signal 

Refueling Water Tank Level - Low 

6. Auxiliary Feedwater Actuation Signal 

Steam Generator Level - Low 

Steam Generator Pressure Difference - High 

With two inoperable channels, one channel should be placed in bypass, 

and the other channel should be placed in trip within the 1 hour 

Completion Time. With one channel of protective instrumentation 

bypassed, the ESFAS Function is in two-out-of-three logic, but with 

another channel failed the ESFAS may be operating with a two-out-of-two 

logic. This is outside the assumptions made in the analyses and should 

be corrected. To correct the problem, the second channel is placed in 

trip. This places the ESFAS in a one-out-of-two logic. If any of the other 

OPERABLE channels receives a trip signal, ESFAS actuation will occur. 

One of the failed channels should be restored to OPERABLE status 

within [48] hours, for reasons similar to those stated under Condition B. 

After one channel is restored to OPERABLE status, the provisions of 

Condition B still apply to the remaining inoperable channel. Therefore, 

the channel that is still inoperable after completion of Required Action C.2 

must be placed in trip if more than [48] hours has elapsed since the initial 

channel failure. 

D.1, D.2.1, D.2.2.1, and D.2.2.2

Condition D applies to the failure of one bypass removal channel. 

The bypass removal channels consist of four sensor subsystems and two 

actuation subsystems. Condition D applies to failures in one of the four 

sensor subsystems, including sensors, bistables, and associated 

equipment. Failures in the actuation subsystems, including the manual 

bypass key switches, are considered Actuation Logic failures and are 

addressed in LCO 3.3.5. 

In Condition D, it is permissible to continue operation with one bypass 

permissive removal channel failed, providing the bypass is disabled 

(Required Action D.1). This can be accomplished by removing the 

bypass with the manual bypass key switch, which disables the bypass in 

both trains. Since the bypass Function must be manually enabled, the 

bypass permissive Function will not by itself cause an undesired bypass 

insertion. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-17 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Alternatively, the bypass may be disabled by defeating the bypass 

permissive input in one of the four channels to the two-out-of-four bypass 

removal logic, placing the bypass removal feature in one-out-of-three 

logic. Thus, any of the remaining three channels is capable of removing 

the bypass feature when the bypass enable conditions are no longer 

valid. 

If the bypass removal feature in the inoperable channel cannot be 

defeated, actions to address the inoperability of the affected automatic 

trip channel must be taken. Required Action D.2.1, Required 

Action D.2.2.1, and Required Action D.2.2.2 are equivalent to the 

Required Actions for a single automatic trip channel failure (Condition B). 

The 1 hour and [48] hour Completion Times have the same bases as 

discussed for Condition B. 

E.1, E.2.1, and E.2.2

Condition E applies to two inoperable bypass removal channels. The 

bypass removal channels consist of four sensor subsystems and two 

actuation subsystems. This Condition applies to failures in two of the four 

sensor subsystems. With two of the four sensor subsystems failed in a 

nonconservative direction (enabling the bypass Function), the bypass 

removal feature is in two-out-of-two logic. Failures in the actuation 

subsystems, including the manual bypass key switches, are considered 

Actuation Logic failures and are addressed in LCO 3.3.5. 

In Condition E, it is permissible to continue operation with two bypass 

permissive channels failed, providing the bypasses are disabled in a 

similar manner as discussed for Condition D. 

If the failed bypasses cannot be disabled, actions to address the 

inoperability of the affected automatic trip channels must be taken. 

Required Action E.2.1 and Required Action E.2.2 are equivalent to the 

Required Actions for a two automatic trip channel failure (Condition C). 

Also similar to Condition C, after one set of inoperable channels is 

restored, the provisions of Condition D still apply to the remaining 

inoperable channel, with the Completion Time measured from the point of 

the initial bypass channel failure. The 1 hour and [48] hour Completion 

Times have the same bases as discussed for Condition C. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-18 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

F.1 and F.2

If the Required Actions and associated Completion Times of Condition A, 

B, C, D, or E are not met, the plant must be brought to a MODE in which 

the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 4 within 

[12] hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE The SRs for any particular ESFAS Function are found in the SRs column 

REQUIREMENTS of Table 3.3.4-1 for that Function. Most functions are subject to 

CHANNEL CHECK, CHANNEL FUNCTIONAL TEST, CHANNEL 

CALIBRATION, and response time testing. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

In order for a unit to take credit for topical reports as the basis for 

justifying Frequencies, topical reports should be supported by an NRC 

staff Safety Evaluation Report that establishes the acceptability of each 

topical report for that unit. 

-------------------------------------------------------------------------------------------------- 

SR 3.3.4.1

Performance of the CHANNEL CHECK once every 12 hours ensures that 

a gross failure of instrumentation 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 instrument 

channels could be an indication of excessive instrument drift in one of the 

channels or of something even more serious. CHANNEL CHECK will 

detect gross channel failure; thus, it is key to verifying the instrumentation 

continues to operate properly between each CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the sensor or the signal processing equipment has drifted outside its 

limit. If the channels are within the criteria, it is an indication that the 

channels are OPERABLE. If the channels are normally off scale during 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-19 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

times when Surveillance is required, the CHANNEL CHECK will only 

verify that they are off scale in the same direction. Offscale low current 

loop channels are verified to be reading at the bottom of the range and 

not failed downscale. 

The Frequency of about once every shift is based on operating 

experience that demonstrates channel failure is rare. Since the 

probability of two random failures in redundant channels in any 12 hour 

period is extremely low, the CHANNEL CHECK minimizes the chance of 

loss of protective function due to failure of redundant channels. The 

CHANNEL CHECK supplements less formal, but more frequent, checks 

of CHANNEL OPERABILITY during normal operational use of displays 

associated with the LCO required channels. 

SR 3.3.4.2

A CHANNEL FUNCTIONAL TEST is performed every [92] days to ensure 

the entire channel will perform its intended function when needed. A 

successful test of the required contact(s) of a channel relay may be 

performed by the verification of the change of state of a single contact of 

the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL 

TEST of a relay. This is acceptable because all of the other required 

contacts of the relay are verified by other Technical Specifications and 

non-Technical Specifications tests at least once per refueling interval with 

applicable extensions. 

The CHANNEL FUNCTIONAL TEST tests the individual sensor 

subsystems using an analog test input to each bistable. 

A test signal is superimposed on the input in one channel at a time to 

verify that the bistable trips within the specified tolerance around the 

setpoint. Any setpoint adjustment shall be consistent with the 

assumptions of the current plant specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [8]. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-20 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.4.3

SR 3.3.4.3 is a CHANNEL FUNCTIONAL TEST similar to SR 3.3.4.2, 

except 3.3.4.3 is performed within 92 days prior to startup and is only 

applicable to bypass Functions. These include the Pressurizer Pressure - 

Low bypass and the MSIS Steam Generator Pressure - Low bypass. A 

successful test of the required contact(s) of a channel relay may be 

performed by the verification of the change of state of a single contact of 

the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL 

TEST of a relay. This is acceptable because all of the other required 

contacts of the relay are verified by other Technical Specifications and 

non-Technical Specifications tests at least once per refueling interval with 

applicable extensions. 

The CHANNEL FUNCTIONAL TEST for proper operation of the bypass 

removal Functions is critical during plant heatups because the bypasses 

may be in place prior to entering MODE 3 but must be removed at the 

appropriate points during plant startup to enable the ESFAS Function. 

Consequently, just prior to startup is the appropriate time to verify bypass 

removal Function OPERABILITY. Once the bypasses are removed, the 

bypasses must not fail in such a way that the associated ESFAS Function 

is inappropriately bypassed. This feature is verified by the appropriate 

ESFAS Function CHANNEL FUNCTIONAL TEST. 

The allowance to conduct this Surveillance within 92 days of startup is 

based upon the reliability analysis presented in topical report CEN-327, 

"RPS/ESFAS Extended Test Interval Evaluation" (Ref. 9). 

SR 3.3.4.4

CHANNEL CALIBRATION is a complete check of the instrument channel, 

including the sensor. The Surveillance verifies that the channel responds 

to a measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive surveillances. 

CHANNEL CALIBRATIONS must be performed consistent with the plant 

specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the extension analysis. The 

requirements for this review are outlined in Reference [8]. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-21 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The Frequency is based upon the assumption of an [18] month calibration 

interval for the determination of the magnitude of equipment drift in the 

setpoint analysis. 

SR 3.3.4.5

This Surveillance ensures that the train actuation response times are the 

maximum values assumed in the safety analyses. Individual component 

response times are not modeled in the analyses. The analysis models 

the overall or total elapsed time, from the point at which the parameter 

exceeds the trip setpoint value at the sensor to the point at which the 

equipment in both trains reaches the required functional state (e.g., 

pumps at rated discharge pressure, valves in full open or closed position). 

Response time testing acceptance criteria are included in Reference 3. 

The test may be performed in one measurement or in overlapping 

segments, with verification that all components are measured. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Applicable portions of the following TS Bases are applicable to plants 

adopting CEOG Topical Report CE NPSD-1167-1, "Elimination of 

Pressure Sensor Response Time Testing Requirements." 

-------------------------------------------------------------------------------------------------- 

Response time may be verified by any series of sequential, overlapping 

or total channel measurements, including allocated sensor response time, 

such that the response time is verified. Allocations for sensor response 

times may be obtained from records of test results, vendor test data, or 

vendor engineering specifications. Topical Report CE NPSD-1167-A, 

"Elimination of Pressure Sensor Response Time Testing Requirements," 

(Ref. 10) provides the basis and methodology for using allocated sensor 

response times in the overall verification of the channel response time for 

specific sensors identified in the Topical Report. Response time 

verification for other sensor types must be demonstrated by test. The 

allocation of sensor response times must be verified prior to placing a 

new component in operation and reverified after maintenance that may 

adversely affect the sensor response time. 
ESFAS Instrumentation (Analog) 

B 3.3.4 

CEOG STS B 3.3.4-22 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

ESF RESPONSE TIME tests are conducted on a STAGGERED TEST 

BASIS of once every [18] months. This results in the interval between 

successive tests of a given channel of n x 18 months, where n is the 

number of channels in the Function. Surveillance of the final actuation 

devices, which make up the bulk of the response time, is included in the 

testing of each channel. Therefore, staggered testing results in response 

time verification of these devices every [18] months. The [18] month 

STAGGERED TEST BASIS Frequency is based upon plant operating 

experience, which shows that random failures of instrumentation 

components causing serious response time degradation, but not channel 

failure, are infrequent occurrences. 

REFERENCES 1. FSAR, Section [7.3]. 

 2. 10 CFR 50, Appendix A. 

 3. NRC Safety Evaluation Report, [Date]. 

 4. IEEE Standard 279-1971. 

 5. FSAR, Chapter [14]. 

 6. 10 CFR 50.49. 

7. "Plant Protection System Selection of Trip Setpoint Values." 

 8. FSAR, Section [7.2]. 

 9. CEN-327, June 2, 1986, including Supplement 1, March 3, 1989. 

 10. CEOG Topical Report CE NPSD-1167-A, "Elimination of Pressure 

Sensor Response Time Testing Requirements." 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.4 Reactor Protective System (RPS) Logic and Trip Initiation (Digital) 

BASES 

BACKGROUND The RPS initiates a reactor trip to protect against violating the core fuel 

design limits and reactor coolant pressure boundary integrity during 

anticipated operational occurrences (AOOs). By tripping the reactor, the 

RPS also assists the Engineered Safety Features (ESF) systems in 

mitigating accidents. 

The protection and monitoring systems have been designed to ensure 

safe operation of the reactor. This is achieved by specifying limiting 

safety system settings (LSSS) in terms of parameters directly monitored 

by the RPS, as well as LCOs on other reactor system parameters and 

equipment performance. 

The LSSS, defined in this Specification as the Allowable Value, in 

conjunction with the LCOs, establish the threshold for protective system 

action to prevent exceeding acceptable limits during Design Basis 

Accidents. 

During AOOs, which are those events expected to occur one or more 

times during the plant life, the acceptable limits are: 

• The departure from nucleate boiling ratio shall be maintained above 

the Safety Limit (SL) value to prevent departure from nucleate 

boiling, 

• Fuel centerline melting shall not occur, and 

• The Reactor Coolant System pressure SL of 2750 psia shall not be 

exceeded. 

Maintaining the parameters within the above values ensures that the 

offsite dose will be within the 10 CFR 50 (Ref. 1) and 10 CFR 100 (Ref. 2) 

criteria during AOOs. 

Accidents are events that are analyzed even though they are not 

expected to occur during the plant life. The acceptable limit during 

accidents is that the offsite dose shall be maintained within an acceptable 

fraction of 10 CFR 100 (Ref. 2) limits. Different accident categories allow 

a different fraction of these limits based on probability of occurrence. 

Meeting the acceptable dose limit for an accident category is considered 

having acceptable consequences for that event. 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The RPS is segmented into four interconnected modules. These 

modules are: 

• Measurement channels, 

• Bistable trip units, 

• RPS Logic, and 

• Reactor trip circuit breakers (RTCBs). 

This LCO addresses the RPS Logic and RTCBs, including Manual Trip 

capability. LCO 3.3.1, "Reactor Protective System (RPS) Instrumentation 

- Operating," provides a description of the role of this equipment in the 

RPS. This is summarized below: 

RPS Logic

The RPS Logic, consisting of Matrix and Initiation Logic, employs a 

scheme that provides a reactor trip when bistables in any two of the four 

channels sense the same input parameter trip. This is called a two-outof-four trip logic. 

Bistable relay contact outputs from the four channels are configured into 

six logic matrices. Each logic matrix checks for a coincident trip in the 

same parameter in two bistable channels. The matrices are designated 

the AB, AC, AD, BC, BD, and CD matrices to reflect the bistable channels 

being monitored. Each logic matrix contains four normally energized 

matrix relays. When a coincidence is detected, consisting of a trip in the 

same Function in the two channels being monitored by the logic matrix, 

all four matrix relays de-energize. 

The matrix relay contacts are arranged into trip paths, with one of the four 

matrix relays in each matrix opening contacts in one of the four trip paths. 

Each trip path provides power to one of the four normally energized 

RTCB control relays (K1, K2, K3, and K4). The trip paths thus each have 

six contacts in series, one from each matrix, and perform a logical OR

function, opening the RTCBs if any one or more of the six logic matrices 

indicate a coincidence condition. 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Each trip path is responsible for opening one set of two of the eight 

RTCBs. The RTCB control relays (K-relays), when de-energized, 

interrupt power to the breaker undervoltage trip attachments and 

simultaneously apply power to the shunt trip attachments on each of the 

two breakers. Actuation of either the undervoltage or shunt trip 

attachment is sufficient to open the RTCB and interrupt power from the 

motor generator (MG) sets to the control element drive mechanisms 

(CEDMs). 

When a coincidence occurs in two RPS channels, all four matrix relays in 

the affected matrix de-energize. This in turn de-energizes all four breaker 

control relays, which simultaneously de-energize the undervoltage and 

energize the shunt trip attachments in all eight RTCBs, tripping them 

open. 

Matrix Logic refers to the matrix power supplies, trip channel bypass 

contacts, and interconnecting matrix wiring between bistable relay cards, 

up to but not including the matrix relays. Matrix contacts on the bistable 

relay cards are excluded from the Matrix Logic definition, since they are 

addressed as part of the measurement channel. 

The Initiation Logic consists of the trip path power source, matrix relays 

and their associated contacts, all interconnecting wiring, and solid state 

(auxiliary) relays through the K-relay contacts in the RTCB control 

circuitry. 

It is possible to change the two-out-of-four RPS Logic to a two-out-ofthree logic for a given input parameter in one channel at a time by trip 

channel bypassing select portions of the Matrix Logic. Trip channel 

bypassing a bistable effectively shorts the bistable relay contacts in the 

three matrices associated with that channel. Thus, the bistables will 

function normally, producing normal trip indication and annunciation, but a 

reactor trip will not occur unless two additional channels indicate a trip 

condition. Trip channel bypassing can be simultaneously performed on 

any number of parameters in any number of channels, providing each 

parameter is bypassed in only one channel at a time. An interlock 

prevents simultaneous trip channel bypassing of the same parameter in 

more than one channel. Trip channel bypassing is normally employed 

during maintenance or testing. 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-4 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Reactor Trip Circuit Breakers (RTCBs)

The reactor trip switchgear consists of eight RTCBs, which are operated 

in four sets of two breakers (four channels). Power input to the reactor 

trip switchgear comes from two full capacity MG sets operated in parallel 

such that the loss of either MG set does not de-energize the CEDMs. 

There are two separate CEDM power supply buses, each bus powering 

half of the CEDMs. Power is supplied from the MG sets to each bus via 

two redundant paths (trip legs). Trip legs 1A and 1B supply power to 

CEDM bus 1. Trip legs 2A and 2B supply power to CEDM bus 2. This 

ensures that a fault or the opening of a breaker in one trip leg (i.e., for 

testing purposes) will not interrupt power to the CEDM buses. 

Each of the four trip legs consists of two RTCBs in series. The two 

RTCBs within a trip leg are actuated by separate initiation circuits. 

The eight RTCBs are operated as four sets of two breakers (four 

channels). For example, if a breaker receives an open signal in trip leg A 

(for CEDM bus 1), an identical breaker in trip leg B (for CEDM bus 2) will 

also receive an open signal. This arrangement ensures that power is 

interrupted to both CEDM buses, thus preventing trip of only half of the 

control element assemblies (CEAs) (a half trip). Any one inoperable 

breaker in a channel will make the entire channel inoperable. 

Each set of RTCBs is operated by either a Manual Trip push button or an 

RPS actuated K-relay. There are four Manual Trip push buttons, 

arranged in two sets of two. Depressing both push buttons in either set 

will result in a reactor trip. 

When a Manual Trip is initiated using the control room push buttons, the 

RPS trip paths and K-relays are bypassed, and the RTCB undervoltage 

and shunt trip attachments are actuated independent of the RPS. 

Manual Trip circuitry includes the push button and interconnecting wiring 

to both RTCBs necessary to actuate both the undervoltage and shunt trip 

attachments, but excludes the K-relay contacts and their interconnecting 

wiring to the RTCBs, which are considered part of the Initiation Logic. 

Functional testing of the entire RPS, from bistable input through the 

opening of the individual sets of RTCBs, can be performed either at 

power or shutdown and is normally performed on a quarterly basis. 

FSAR, Section [7.2] (Ref. 3), explains RPS testing in more detail. 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE Reactor Protective System (RPS) Logic

SAFETY 

ANALYSES The RPS Logic provides for automatic trip initiation to maintain the SLs 

during AOOs and assist the ESF systems in ensuring acceptable 

consequences during accidents. All transients and accidents that call for 

a reactor trip assume the RPS Logic is functioning as designed. 

Reactor Trip Circuit Breakers (RTCBs)

All of the transient and accident analyses that call for a reactor trip 

assume that the RTCBs operate and interrupt power to the CEDMs. 

Manual Trip

There are no accident analyses that take credit for the Manual Trip; 

however, the Manual Trip is part of the RPS circuitry. It is used by the 

operator to shut down the reactor whenever any parameter is rapidly 

trending toward its trip setpoint. A Manual Trip accomplishes the same 

results as any one of the automatic trip Functions. 

The RPS instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Reactor Protective System (RPS) Logic

The LCO on the RPS Logic channels ensures that each of the following 

requirements are met: 

• A reactor trip will be initiated when necessary, 

• The required protection system coincidence logic is maintained 

(minimum two-out-of-three, normal two-out-of-four), and 

• Sufficient redundancy is maintained to permit a channel to be out of 

service for testing or maintenance. 

Failures of individual bistable relays and their contacts are addressed in 

LCO 3.3.1. This Specification addresses failures of the Matrix Logic not 

addressed in the above, such as the failure of matrix relay power supplies 

or the failure of the trip channel bypass contact in the bypass condition. 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-6 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

Loss of a single vital bus will de-energize one of the two power supplies in 

each of three matrices. This will result in four RTCBs opening; however, 

the remaining four closed RTCBs will prevent a reactor trip. For the 

purposes of this LCO, de-energizing up to three matrix power supplies 

due to a single failure is to be treated as a single channel failure, 

providing the affected matrix relays de-energize as designed, opening the 

affected RTCBs. 

Each of the four Initiation Logic channels opens one set of RTCBs if any 

of the six coincidence matrices de-energize their associated matrix relays. 

They thus perform a logical OR function. Each Initiation Logic channel 

has its own power supply and is independent of the others. An Initiation 

Logic channel includes the matrix relay through to the K-relay contacts, 

which open the RTCB. 

It is possible for two Initiation Logic channels affecting the same trip leg to 

de-energize if a matrix power supply or vital instrument bus fails. This will 

result in opening the two affected sets of RTCBs. 

If one set of RTCBs has been opened in response to a single RTCB 

channel, Initiation Logic channel, or Manual Trip channel failure, the 

affected set of RTCBs may be closed for up to 1 hour for Surveillance on 

the OPERABLE Initiation Logic, RTCB, and Manual Trip channels. In this 

case, the redundant set of RTCBs will provide protection if a trip should 

be required. It is unlikely that a trip will be required during the 

Surveillance, coincident with a failure of the remaining series RTCB 

channel. If a single matrix power supply or vital bus failure has opened 

two sets of RTCBs, Manual Trip and RTCB testing on the closed breakers 

cannot be performed without causing a trip. 

1. Matrix Logic

This LCO requires six channels of Matrix Logic to be OPERABLE in 

MODES 1 and 2, and in MODES 3, 4, and 5 when any RTCBs are 

closed and any CEA is capable of being withdrawn. 

2. Initiation Logic

This LCO requires four channels of Initiation Logic to be OPERABLE 

in MODES 1 and 2, and in MODES 3, 4, and 5 when the RTCBs are 

closed and any CEA is capable of being withdrawn. 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-7 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

3. Reactor Trip Circuit Breakers

The LCO requires four RTCB channels to be OPERABLE in 

MODES 1 and 2, as well as in MODES 3, 4, and 5 when the RTCBs 

are closed and any CEA is capable of being withdrawn. 

Each channel consists of two breakers operated in a single set by the 

Initiation Logic or Manual Trip circuitry. This ensures that power is 

interrupted at identical locations in the trip legs for both CEDM buses, 

thus preventing power removal to only one CEDM bus (a half trip). 

Failure of a single breaker affects the entire channel, and both 

breakers in the set must be opened. Without reliable RTCBs and 

associated support circuitry, a reactor trip cannot occur whether 

initiated automatically or manually. 

Each channel of RTCBs starts at the contacts that are actuated by 

the K-relay and the Manual Trip for each set of breakers. The 

K-relay actuated contacts and the upstream circuitry are considered 

to be RPS Logic. Manual Trip contacts and upstream circuitry are 

considered to be Manual Trip circuitry. 

A Note associated with the ACTIONS states that if one set of RTCBs 

has been opened in response to a single RTCB channel, Initiation 

Logic channel, or Manual Trip channel failure, the affected set of 

RTCBs may be closed for up to 1 hour for Surveillance on the 

OPERABLE Initiation Logic, RTCB, and Manual Trip channels. In 

this case the redundant set of RTCBs will provide protection. If a 

single matrix power supply or vital bus failure has opened two sets of 

RTCBs, Manual Trip and RTCB testing on the closed breakers 

cannot be performed without causing a trip. 

4. Manual Trip

The LCO requires all four Manual Trip channels to be OPERABLE in 

MODES 1 and 2, and MODES 3, 4, and 5 when the RTCBs are 

closed and any CEA is capable of being withdrawn. 

Two independent sets of two adjacent push buttons are provided at 

separate locations. Each push button is considered a channel and 

operates two of the eight RTCBs. Depressing both push buttons in 

either channel will cause an interruption of power to the CEDMs, 

allowing the CEAs to fall into the core. This design ensures that no 

single failure in any push button circuit can either cause or prevent a 

reactor trip. 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-8 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

Manual Trip push buttons are also provided at the reactor trip 

switchgear (locally) in case the control room push buttons become 

inoperable or the control room becomes uninhabitable. These are 

not part of the RPS and cannot be credited in fulfilling the LCO 

OPERABILITY requirements. Furthermore, LCO ACTIONS need not 

be entered due to failure of a local Manual Trip. 

APPLICABILITY The RPS Logic, RTCBs, and Manual Trip are required to be OPERABLE 

in any MODE when the CEAs are capable of being withdrawn off the 

bottom of the core (i.e., RTCBs closed and power available to the 

CEDMs). This ensures that the reactor can be tripped when necessary, 

but allows for maintenance and testing when the reactor trip is not 

needed. 

In MODES 3, 4, and 5 with the RTCBs open, the CEAs are not capable of 

withdrawal and these Functions do not have to be OPERABLE. 

However, two logarithmic power level channels must be OPERABLE to 

ensure proper indication of neutron population and to indicate a boron 

dilution event. This is addressed in LCO 3.3.13, "[Logarithmic] Power 

Monitoring Channels." 

ACTIONS When the number of inoperable channels in a trip Function exceeds that 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 is 

immediately entered if applicable in the current MODE of operation. 

A.1

Condition A applies if one Matrix Logic channel is inoperable or three 

Matrix Logic channels are inoperable due to a common power source 

failure de-energizing three matrix power supplies in any applicable 

MODE. Loss of a single vital instrument bus will de-energize one of the 

two matrix power supplies in up to three matrices. This is considered a 

single matrix failure, providing the matrix relays associated with the failed 

power supplies de-energize as required. 

The channel must be restored to OPERABLE status within 48 hours. The 

Completion Time of 48 hours provides the operator time to take 

appropriate actions and still ensures that any risk involved in operating 

with a failed channel is acceptable. Operating experience has 

demonstrated that the probability of a random failure of a second Matrix 

Logic channel is low during any given 48 hour interval. If the channel 

cannot be restored to OPERABLE status within 48 hours, Condition E is 

entered. 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-9 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1

Condition B applies to one Initiation Logic channel, RTCB channel, or 

Manual Trip channel in MODES 1 and 2, since they have the same 

actions. MODES 3, 4, and 5, with the RTCBs shut, are addressed in 

Condition C. These Required Actions require opening the affected 

RTCBs. This removes the need for the affected channel by performing its 

associated safety function. With an RTCB open, the affected Functions 

are in one-out-of-two logic, which meets redundancy requirements, but 

testing on the OPERABLE channels cannot be performed without causing 

a reactor trip unless the RTCBs in the inoperable channels are closed to 

permit testing. 

Required Action B.1 provides for opening the RTCBs associated with the 

inoperable channel within a Completion Time of 1 hour. This Required 

Action is conservative, since depressing the Manual Trip push button 

associated with either set of breakers in the other trip leg will cause a 

reactor trip. With this configuration, a single channel failure will not 

prevent a reactor trip. The allotted Completion Time is adequate for 

opening the affected RTCBs while maintaining the risk of having them 

closed at an acceptable level. 

C.1

Condition C applies to the failure of one Initiation Logic channel, RTCB 

channel, or Manual Trip channel affecting the same trip leg in MODE 3, 4, 

or 5 with the RTCBs closed. The channel must be restored to 

OPERABLE status within 48 hours. If the inoperable channel cannot be 

restored to OPERABLE status within 48 hours, the affected RTCBs must 

be opened. In some cases, this condition may effect all of the RTCBs. 

This removes the need for the affected channel by performing its 

associated safety function. With the RTCBs open, the affected functions 

are in a one-out-of-two logic, which meets redundancy requirements. 

The Completion Time of 48 hours is consistent with that of other RPS 

instrumentation and should be adequate to repair most failures. 

Testing on the OPERABLE channels cannot be performed without 

causing a reactor trip unless the RTCBs in the inoperable channels are 

closed to permit testing. 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-10 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

D.1

Condition D applies to the failure of both Manual Trip or Initiation Logic 

channels affecting the same trip leg. Since this will open two channels of 

RTCBs, this Condition is also applicable to channels in the same trip leg. 

This will open both sets of RTCBs in the affected trip leg, satisfying the 

Required Action of opening the affected RTCBs. 

Of greater concern is the failure of the initiation circuit in a nontrip 

condition (e.g., due to two initiation K-relay failures). With only one 

Initiation Logic channel failed in a nontrip condition, there is still the 

redundant set of RTCBs in the trip leg. With both failed in a nontrip 

condition, the reactor will not trip automatically when required. In either 

case, the affected RTCBs must be opened immediately by using the 

appropriate Manual Trip push buttons, since each of the four push 

buttons opens one set of RTCBs, independent of the initiation circuitry. 

Caution must be exercised, since depressing the wrong push buttons 

may result in a reactor trip. 

If two Manual Trip channels are inoperable and affecting the same trip 

leg, the associated RTCBs must be opened immediately to ensure 

Manual Trip capability is maintained. With the affected RTCBs open, any 

one of two Manual Trip push buttons being depressed will result in a 

reactor trip. 

If the affected RTCB cannot be opened, Required Action E is entered. 

This would only occur if there is a failure in the Manual Trip circuitry or the 

RTCB(s). 

E.1 and E.2

Condition E is entered if Required Actions associated with Condition A, B, 

or D are not met within the required Completion Time or, if for one or 

more Functions, more than one Manual Trip, Matrix Logic, Initiation Logic, 

or RTCB channel is inoperable for reasons other than Condition A or D. 

If the RTCBs associated with the inoperable channel cannot be opened, 

the reactor must be shut down within 6 hours and all the RTCBs opened. 

A Completion Time of 6 hours is reasonable, based on operating 

experience, for reaching the required plant conditions from full power 

conditions in an orderly manner and without challenging plant systems 

and for opening RTCBs. All RTCBs should then be opened, placing the 

plant in a MODE where the LCO does not apply and ensuring no CEA 

withdrawal occurs. 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-11 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE -----------------------------------REVIEWER’S NOTE----------------------------------- 

REQUIREMENTS In order for a unit to take credit for topical reports as the basis for 

justifying Frequencies, topical reports must be supported by an NRC staff 

Safety Evaluation Report that establishes the acceptability of each topical 

report for that unit (Ref. 4). 

-------------------------------------------------------------------------------------------------- 

SR 3.3.4.1

A CHANNEL FUNCTIONAL TEST is performed on each RTCB channel 

every 31 days. This verifies proper operation of each RTCB. The RTCB 

must then be closed prior to testing the other RTCBs, or a reactor trip 

may result. The Frequency of 31 days is based on the reliability analysis 

presented in Topical Report CEN-327, "RPS/ESFAS Extended Test 

Interval Evaluation," (Ref. 4). 

SR 3.3.4.2

A CHANNEL FUNCTIONAL TEST on each RPS Logic channel is 

performed every [92] days to ensure the entire channel will perform its 

intended function when needed. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 

In addition to power supply tests, the RPS CHANNEL FUNCTIONAL 

TEST consists of three overlapping tests as described in Reference 3. 

These tests verify that the RPS is capable of performing its intended 

function, from bistable input through the RTCBs. The first test, the 

bistable test, is addressed by SR 3.3.1.7 in LCO 3.3.1. 

This SR addresses the two tests associated with the RPS Logic: Matrix 

Logic and Trip Path. 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-12 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Matrix Logic Tests

These tests are performed one matrix at a time. They verify that a 

coincidence in the two input channels for each Function removes power 

from the matrix relays. During testing, power is applied to the matrix relay 

test coils and prevents the matrix relay contacts from assuming their deenergized state. The Matrix Logic tests will detect any short circuits 

around the bistable contacts in the coincidence logic such as may be 

caused by faulty bistable relay or trip channel bypass contacts. 

Trip Path Tests

These tests are similar to the Matrix Logic tests, except that test power is 

withheld from one matrix relay at a time, allowing the initiation circuit to 

de-energize, opening the affected set of RTCBs. The RTCBs must then 

be closed prior to testing the other three initiation circuits, or a reactor trip 

may result. 

The Frequency of [92] days is based on the reliability analysis presented 

in topical report CEN-327, "RPS/ESFAS Extended Test Interval 

Evaluation" (Ref. 5). 

Additionally, operating experience has shown that these components 

usually pass the Surveillance when performed at a Frequency of once 

every 7 days prior to each reactor startup. 

SR 3.3.4.3

Each RTCB is actuated by an undervoltage coil and a shunt trip coil. The 

system is designed so that either de-energizing the undervoltage coil or 

energizing the shunt trip coil will cause the circuit breaker to open. When 

an RTCB is opened, either during an automatic reactor trip or by using 

the manual push buttons in the control room, the undervoltage coil is deenergized and the shunt trip coil is energized. This makes it impossible to 

determine if one of the coils or associated circuitry is defective. 
RPS Logic and Trip Initiation (Digital) 

B 3.3.4 

CEOG STS B 3.3.4-13 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Therefore, once every [18] months, a CHANNEL FUNCTIONAL TEST is 

performed that individually tests all four sets of undervoltage coils and all 

four sets of shunt trip coils. A successful test of the required contact(s) of 

a channel relay may be performed by the verification of the change of 

state of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. During 

undervoltage coil testing, the shunt trip coils must remain de-energized, 

preventing their operation. Conversely, during shunt trip coil testing, the 

undervoltage coils must remain energized, preventing their operation. 

This Surveillance ensures that every undervoltage coil and every shunt 

trip coil is capable of performing its intended function and that no single 

active failure of any RTCB component will prevent a reactor trip. 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. Operating experience has shown these components 

usually pass the Surveillance when performed at the Frequency of once 

every [18] months. 

SR 3.3.4.4

A CHANNEL FUNCTIONAL TEST on the Manual Trip channels is 

performed prior to a reactor startup to ensure the entire channel will 

perform its intended function if required. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. The Manual Trip 

Function can only be tested at shutdown. However, the simplicity of this 

circuitry and the absence of drift concern make this Frequency adequate. 

REFERENCES 1. 10 CFR 50, Appendix A. 

 2. 10 CFR 100. 

 3. FSAR, Section [7.2]. 

 4. CEN-327, June 2, 1986, including Supplement 1, March 3, 1989. 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.5 Engineered Safety Features Actuation System (ESFAS) Logic and Manual Trip 

 (Analog) 

BASES 

BACKGROUND The ESFAS initiates necessary safety systems, based upon the values of 

selected unit parameters, to protect against violating core design limits 

and the Reactor Coolant System (RCS) pressure boundary and to 

mitigate accidents. 

The ESFAS contains devices and circuitry that generate the following 

signals when the monitored variables reach levels that are indicative of 

conditions requiring protective action: 

1. Safety Injection Actuation Signal (SIAS), 

2. Containment Spray Actuation Signal (CSAS), 

3. Containment Isolation Actuation Signal (CIAS), 

4. Main Steam Isolation Signal (MSIS), 

5. Recirculation Actuation Signal (RAS), and 

6. Auxiliary Feedwater Actuation Signal (AFAS). 

Equipment actuated by each of the above signals is identified in the 

FSAR (Ref. 1). 

Each of the above ESFAS actuation systems is segmented into four 

sensor subsystems addressed by LCO 3.3.4, "Engineered Safety 

Features Actuation System (ESFAS) Instrumentation," and two actuation 

subsystems addressed by this LCO. Each sensor subsystem includes 

measurement channels and bistables. The SIAS actuation subsystems 

include two logic subsystems for sequentially loading the diesel 

generators. 

Each of the four sensor subsystem channels monitors redundant and 

independent process measurement channels. Each sensor is monitored 

by at least one bistable. The bistable associated with each ESFAS 

Function will trip when the monitored variable exceeds the trip setpoint. 

When tripped, the sensor subsystems provide outputs to the two 

actuation subsystems. 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The two independent actuation subsystems each compare the four 

associated sensor subsystem outputs. If a trip occurs in two or more 

sensor subsystem channels, the two-out-of-four logic in each actuation 

subsystem will initiate one train of ESFAS. Each has sufficient equipment 

to provide protection to the public in the case of a Design Basis Event. 

The sensor subsystem is addressed in LCO 3.3.4. This LCO addresses 

the actuation subsystem. 

Each of the four sensor subsystems is mounted in a separate cabinet, 

excluding the sensors and field wiring. 

The role of the sensor subsystem (measurement channels and bistables) 

is discussed in LCO 3.3.4. That of the actuation subsystem is discussed 

below. 

ESFAS Logic

The two independent actuation subsystems compare the four sensor 

subsystem outputs. If a trip occurs in the same parameter in two or more 

sensor subsystem channels, the two-out-of-four logic in each actuation 

subsystem initiates one train of ESFAS. Either train controls sufficient 

redundant and independent equipment. 

Each actuation subsystem channel is housed in two cabinets. One 

cabinet contains the logic circuitry for the actuation channel, while the 

other cabinet contains the power relay equipment. This power relay 

equipment includes the power relays (initiation relays) that actuate the 

ESFAS equipment in response to a signal from the Actuation Logic. 

It is possible to change the two-out-of-four ESFAS Logic to a two-out-ofthree logic for a given input parameter in one channel at a time by 

disabling one channel input to the logic. Thus, the bistables will function 

normally, producing normal trip indication and annunciation, but ESFAS 

actuation will not occur since the bypassed channel is effectively removed 

from the coincidence logic. Maintenance bypassing can be 

simultaneously performed on any number of parameters in any number of 

channels, providing each parameter is bypassed in only one channel at a 

time. At some plants an interlock prevents simultaneous maintenance 

bypassing of the same parameter in more than one channel. 

Maintenance bypassing is normally employed during maintenance or 

testing. 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

For plants that have demonstrated sufficient channel to channel 

independence, two-out-of-three logic is the minimum that is required to 

provide adequate plant protection, since a failure of one channel still 

ensures that ESFAS actuation would be generated by the two remaining 

OPERABLE channels. Two-out-of-three logic also prevents inadvertent 

actuation caused by any single channel failure in a trip condition. 

In addition to the maintenance bypasses, there are operating bypasses 

(blocks) on the Pressurizer Pressure - Low input to the SIAS and on the 

Steam Generator Pressure - Low input to the MSIS when these inputs are 

no longer required for protection. These bypasses are enabled manually 

when the enabling conditions are satisfied in three of the four sensor 

subsystem channels. The operating bypass circuitry employs four 

bistable channels in the sensor subsystems, sensing pressurizer pressure 

(for the SIAS) and steam generator pressure (for the MSIS). These 

bistables provide contact output to the three-out-of-four logic in the two 

actuation subsystem channels. When the logic is satisfied, manual 

bypassing is permitted. There are two manual bypass actuation controls 

for each Function, one per train. 

All operating bypasses are automatically removed when enabling bypass 

conditions are no longer satisfied. 

Manual ESFAS initiation capability is provided to permit the operator to 

manually actuate an Engineered Safety Features (ESF) System when 

necessary. Two push buttons are provided in the control room for each 

ESFAS Function. Each push button actuates one train via the ESFAS 

Logic. 

The Actuation Logic is tested by inserting a local test signal. A 

coincidence logic trip will occur if there is the simultaneous presence of a 

sensor channel trip, either legitimate or due to testing. Most ESFAS 

Functions employ several separate parallel two-out-of-four Actuation 

Logic modules, with each module actuating a subset of the ESFAS 

equipment associated with that Function. Each of these subchannels can 

be tested individually so that simultaneous actuation of an entire train can 

be avoided during testing. 

Except in the case of actuation subchannels SIAS Nos. 5 and 10, CIAS 

No. 5, and MSIS No. 1, all Actuation Logic channels can be tested at 

power. The above designated subchannels must be tested when shut 

down because they actuate the following equipment, which cannot be 

actuated at power: 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-4 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

• Reactor coolant pump (RCP) seal bleedoff isolation valves, 

• Service water isolation valves, 

• Volume control tank (VCT) discharge valves, 

• Letdown stop valves, 

• Component cooling water (CCW) to RCPs, 

• CCW from RCPs, 

• Main steam isolation valves (MSIVs), 

• Feedwater isolation valves, and 

• Instrument air containment isolation valves. 

APPLICABLE Each of the analyzed accidents can be detected by one or more ESFAS 

SAFETY Functions. One of the ESFAS Functions is the primary actuation signal 

ANALYSES for that accident. An ESFAS Function may be the primary actuation 

signal for more than one type of accident. An ESFAS Function may also 

be a secondary, or backup, actuation signal for one or more other 

accidents. Functions such as Manual Initiation, not specifically credited in 

the accident analysis, serve as backups to Functions and are part of the 

NRC staff approved licensing basis for the plant. 

ESFAS protective Functions are as follows: 

1. Safety Injection Actuation Signal

The SIAS ensures acceptable consequences during loss of coolant 

accident (LOCA) events, including steam generator tube rupture, and 

main steam line breaks (MSLBs) or feedwater line breaks (FWLBs) 

(inside containment). To provide the required protection, either a 

high containment pressure or a low pressurizer pressure signal will 

initiate SIAS. SIAS initiates the Emergency Core Cooling Systems 

(ECCS) and performs several other Functions, such as initiating 

control room isolation and starting the diesel generators. 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

2. Containment Spray Actuation Signal

The CSAS initiates containment spray, preventing containment 

overpressurization during a LOCA or MSLB. At some plants, both a 

high containment pressure signal and an SIAS have to actuate to 

provide the required protection. This configuration reduces the 

likelihood of inadvertent containment spray. 

3. Containment Isolation Actuation Signal

The CIAS actuates the Containment Isolation System, ensuring 

acceptable consequences during LOCAs and MSLBs or FWLBs 

(inside containment). To provide protection, a high containment 

pressure signal will initiate CIAS at the same setpoint at which an 

SIAS is initiated. 

4. Main Steam Isolation Signal

The MSIS ensures acceptable consequences during an MSLB or 

FWLB by isolating both steam generators if either generator indicates 

a low steam generator pressure. The MSIS, concurrent with or 

following a reactor trip, minimizes the rate of heat extraction and 

subsequent cooldown of the RCS during these events. 

5. Recirculation Actuation Signal

At the end of the injection phase of a LOCA, the refueling water tank 

(RWT) will be nearly empty. Continued cooling must be provided by 

the ECCS to remove decay heat. The source of water for the ECCS 

pumps is automatically switched to the containment recirculation 

sump. Switchover from RWT to containment sump must occur 

before the RWT empties to prevent damage to the ECCS pumps and 

a loss of core cooling capability. For similar reasons, switchover 

must not occur before there is sufficient water in the containment 

sump to support pump suction. Furthermore, early switchover must 

not occur to ensure sufficient borated water is injected from the RWT 

to ensure the reactor remains shut down in the recirculation mode. 

An RWT Level - Low signal initiates the RAS. 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-6 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

6. Auxiliary Feedwater Actuation Signal

An AFAS initiates feedwater flow to both steam generators if a low 

level is indicated in either steam generator, unless the generator is 

ruptured. 

The AFAS maintains a steam generator heat sink during the following 

events: 

• MSLB, 

• FWLB, 

• Inadvertent opening of a steam generator atmospheric dump 

valve, and 

• Loss of feedwater. 

A low steam generator water level signal will initiate auxiliary feed to 

the affected steam generator. 

Secondary steam generator (SG) differential pressure (SG-A > SG-B) 

or (SG-B > SG-A) inhibits auxiliary feed to a generator identified as 

being ruptured. This input to the AFAS logic prevents loss of the 

intact generator while preventing feeding a ruptured generator during 

MSLBs and FWLBs. This prevents containment overpressurization 

during these events. 

The ESFAS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The LCO requires that all components necessary to provide an ESFAS 

actuation be OPERABLE. 

Actions allow maintenance bypass of individual channels. Plants are 

restricted to 48 hours in a maintenance bypass condition before either 

restoring the Function to four channel operation (two-out-of-four logic) or 

placing the channel in trip (one-out-of-three logic). 

The Bases for the LCO on ESFAS automatic actuation Functions are 

addressed in the Bases for LCO 3.3.4. Those associated with the Manual 

Trip or Actuation Logic are addressed below. 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-7 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

1. Safety Injection Actuation Signal

a. Manual Trip

This LCO requires two channels of SIAS Manual Trip to be 

OPERABLE in MODES 1, 2, 3, and 4. 

b. Actuation Logic

This LCO requires two channels of SIAS Actuation Logic to be 

OPERABLE in MODES 1, 2, 3, and 4. 

Failures in the actuation subsystems, including the manual 

bypass key switches, are Actuation Logic failures and are 

addressed in this LCO. 

Actuation Logic consists of all circuitry housed within the 

actuation subsystems, including the initiating relay contacts 

responsible for actuating the ESF equipment. 

2. Containment Spray Actuation Signal

CSAS is initiated either manually or automatically. At many plants it 

is also necessary to have an automatic or manual SIAS for a 

complete actuation. The SIAS opens the containment spray valves, 

whereas the CSAS actuates other required components. The SIAS 

requirement should always be satisfied on a legitimate CSAS, since 

the Containment Pressure - High signal used in the SIAS is the same 

setpoint used in the CSAS. The transmitters used to initiate CSAS 

are independent of those used in the SIAS to prevent inadvertent 

containment spray due to failures in two sensor channels. 

a. Manual Trip

This LCO requires two channels of CSAS Manual Trip to be 

OPERABLE in MODES 1, 2, 3, and 4. 

b. Actuation Logic

This LCO requires two channels of CSAS Actuation Logic to be 

OPERABLE in MODES 1, 2, 3, and 4. 

Actuation Logic consists of all circuitry housed within the 

actuation subsystems, including the initiating relay contacts 

responsible for actuating the ESF equipment. 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-8 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

3. Containment Isolation Actuation Signal

a. Manual Trip

This LCO requires two channels of CIAS Manual Trip to be 

OPERABLE in MODES 1, 2, 3, and 4. 

b. Actuation Logic

This LCO requires two channels of Actuation Logic for CIAS to 

be OPERABLE in MODES 1, 2, 3, and 4. 

Actuation Logic consists of all circuitry housed within the 

actuation subsystems, including the initiating relay contacts 

responsible for actuating the ESF equipment. 

4. Main Steam Isolation Signal

a. Manual Trip

This LCO requires two channels per steam generator of the 

MSIS Manual Trip to be OPERABLE in MODES 1, 2, 3, and 4. 

b. Actuation Logic

This LCO requires two channels of MSIS Actuation Logic to be 

OPERABLE in MODES 1, 2, 3, and 4. 

Failures in the actuation subsystems, including the manual 

bypass key switches, are considered Actuation Logic failures 

and are addressed in the logic LCO. 

5. Recirculation Actuation Signal

a. Manual Trip

This LCO requires two channels of RAS Manual Trip to be 

OPERABLE in MODES 1, 2, 3, and 4. 

b. Actuation Logic

This LCO requires two channels of RAS Actuation Logic to be 

OPERABLE in MODES 1, 2, 3, and 4. 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-9 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

6. Auxiliary Feedwater Actuation Signal

A low level in either generator, as sensed by a two-out-of-four 

coincidence of four wide range sensors for each generator, will 

generate an auxiliary feedwater actuation signal (AFAS), which starts 

both trains of auxiliary feedwater (AFW) pumps and feeds both steam 

generators. The AFAS also monitors the secondary differential 

pressure in both steam generators and initiates an AFAS block signal 

to a ruptured generator if the pressure in that generator is lower than 

the other generator by the differential pressure setpoint. 

a. Manual Trip

This LCO requires two channels of AFAS Manual Trip to be 

OPERABLE in MODES 1, 2, and 3. 

b. Actuation Logic

This LCO requires two channels of AFAS Actuation Logic to be 

OPERABLE in MODES 1, 2, and 3. 

Actuation Logic consists of all circuitry housed within the 

actuation subsystems, including the initiating relay contacts 

responsible for actuating the ESF equipment. 

APPLICABILITY All ESFAS Functions are required to be OPERABLE in MODES 1, 2, 

and 3. In MODES 1, 2, and 3, there is sufficient energy in the primary 

and secondary systems to warrant automatic ESF System responses to: 

• Close the MSIVs to preclude a positive reactivity addition, 

• Actuate AFW to preclude the loss of the steam generators as a heat 

sink (in the event the normal feedwater system is not available), 

• Actuate ESF systems to prevent or limit the release of fission product 

radioactivity to the environment by isolating containment and limiting 

the containment pressure from exceeding the containment design 

pressure during a design basis LOCA or MSLB, and 

• Actuate ESF systems to ensure sufficient borated inventory to permit 

adequate core cooling and reactivity control during a design basis 

LOCA or MSLB accident. 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-10 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY (continued) 

In MODES 4, 5, and 6, automatic actuation of ESFAS Functions is not 

required, because adequate time is available for plant operators to 

evaluate plant conditions and respond by manually operating the ESF 

components if required. ESFAS Manual Trip capability is required for 

Functions other than AFAS in MODE 4 even though automatic actuation 

is not required. Because of the large number of components actuated on 

each ESFAS, actuation is simplified by the use of the Manual Trip push 

buttons. Manual Trip of AFAS is not required in MODE 4 because AFW 

or shutdown cooling will already be in operation in this MODE. 

The ESFAS Actuation Logic must be OPERABLE in the same MODES as 

the Automatic and Manual Trips. In MODE 4, only the portion of the 

ESFAS logic responsible for the required Manual Trip must be 

OPERABLE. 

In MODES 5 and 6, ESFAS initiated systems are either reconfigured or 

disabled for shutdown cooling operation. Accidents in these MODES are 

slow to develop and would be mitigated by manual operation of individual 

components. 

ACTIONS When the number of inoperable channels in a trip Function exceeds those 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 should 

be immediately entered, if applicable in the current MODE of operation. 

A Note has been added to the ACTIONS to clarify the application of the 

Completion Time rules. The Conditions of this Specification may be 

entered independently for each Function in Table 3.3.5-1 in the LCO. 

Completion Times for the inoperable channel of a Function will be tracked 

separately. 

A.1

Condition A applies to one AFAS Manual Trip or AFAS Actuation Logic 

channel inoperable. It is identical to Condition C for the other ESFAS 

Functions, except for the shutdown track imposed by Condition D. 

The channel must be restored to OPERABLE status to restore 

redundancy of the AFAS Function. The 48 hour Completion Time is 

commensurate with the importance of avoiding the vulnerability of a 

single failure in the only remaining OPERABLE channel. 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-11 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1 and B.2

If two Manual Trip or Actuation Logic channels are inoperable or the 

Required Action and associated Completion Time of Condition A cannot 

be met, the reactor should be brought to a MODE in which the LCO does 

not apply. To achieve this status, the plant must be brought to at least 

MODE 3 within 6 hours and to MODE 4 within [12] hours. The allowed 

Completion Times are reasonable, based on operating experience, to 

reach the required plant conditions from full power conditions in an 

orderly manner and without challenging plant systems. 

C.1

Condition C applies to one Manual Trip or Actuation Logic channel 

inoperable for those ESFAS Functions that must be OPERABLE in 

MODES 1, 2, 3, and 4 (all Functions except AFAS). The shutdown track 

imposed by Condition D requires entry into MODE 5, where the LCO 

does not apply to the affected Functions. 

The channel must be restored to OPERABLE status to restore 

redundancy of the affected Functions. The 48 hour Completion Time is 

commensurate with the importance of avoiding the vulnerability of a 

single failure in the only remaining OPERABLE channel. 

D.1 and D.2

Condition D is entered when one or more Functions have two Manual Trip 

or Actuation Logic channels inoperable except AFAS or the Required 

Action and associated Completion Time of Condition C are not met. If 

Required Action C.1 cannot be met within the required Completion Time, 

the plant must be brought to a MODE in which the LCO does not apply. 

To achieve this status, the plant must be brought to at least MODE 3 

within 6 hours and to MODE 5 within 36 hours. The allowed Completion 

Times are reasonable, based on operating experience, to reach the 

required plant conditions from full power conditions in an orderly manner 

and without challenging plant systems. 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-12 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.3.5.1

REQUIREMENTS 

A CHANNEL FUNCTIONAL TEST is performed every 92 days to ensure 

the entire channel will perform its intended function when needed. 

Sensor subsystem tests are addressed in LCO 3.3.4. This SR addresses 

Actuation Logic tests. A successful test of the required contact(s) of a 

channel relay may be performed by the verification of the change of state 

of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 

Actuation Logic Tests

Actuation subsystem testing includes injecting one trip signal into each 

two-out-of-four logic subsystem in each ESFAS Function and using a 

bistable trip input to satisfy the trip logic. Initiation relays associated with 

the affected channel will then actuate the individual ESFAS components. 

Since each ESFAS Function employs subchannels of Actuation Logic, it 

is possible to actuate individual components without actuating an entire 

ESFAS Function. 

Note 1 requires that Actuation Logic tests include operation of initiation 

relays. Note 2 allows deferred at power testing of certain relays to allow 

for the fact that operating certain relays during power operation could 

cause plant transients or equipment damage. Those initiation relays that 

cannot be tested at power must be tested in accordance with Note 2. 

These include [SIAS No. 5, SIAS No. 10, CIAS No. 5, and MSIS No. 1.] 

These relays actuate the following components, which cannot be tested 

at power: 

• RCP seal bleedoff isolation valves, 

• Service water isolation valves, 

• VCT discharge valves, 

• Letdown stop valves, 

• CCW to and from the RCPs, 

• MSIVs and feedwater isolation valves, and 

• Instrument air containment isolation valves. 
ESFAS Logic and Manual Trip (Analog) 

B 3.3.5 

CEOG STS B 3.3.5-13 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The reasons that each of the above cannot be fully tested at power are 

stated in Reference 1. 

These tests verify that the ESFAS is capable of performing its intended 

function, from bistable input through the actuated components. 

The Frequency of [92] days is based on the reliability analysis presented 

in topical report CEN-327, "RPS/ESFAS Extended Test Interval 

Evaluation" (Ref. 2). 

SR 3.3.5.2

A CHANNEL FUNCTIONAL TEST is performed on the manual ESFAS 

actuation circuitry, de-energizing relays and providing Manual Trip of the 

Function. A successful test of the required contact(s) of a channel relay 

may be performed by the verification of the change of state of a single 

contact of the relay. This clarifies what is an acceptable CHANNEL 

FUNCTIONAL TEST of a relay. This is acceptable because all of the 

other required contacts of the relay are verified by other Technical 

Specifications and non-Technical Specifications tests at least once per 

refueling interval with applicable extensions. 

This Surveillance verifies that the trip push buttons are capable of 

opening contacts in the Actuation Logic as designed, de-energizing the 

initiation relays and providing Manual Trip of the Function. The 

[18] month Frequency is based on the need to perform this Surveillance 

under the conditions that apply during a plant outage and the potential for 

an unplanned transient if the Surveillance were performed with the 

reactor at power. Operating experience has shown these components 

usually pass the Surveillance when performed at a Frequency of once 

every [18] months. 

REFERENCES 1. FSAR, Section [7.3]. 

 2. CEN-327, June 2, 1986, including Supplement 1, March 3, 1989. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.5 Engineered Safety Features Actuation System (ESFAS) Instrumentation (Digital) 

BASES 

BACKGROUND The ESFAS initiates necessary safety systems, based upon the values of 

selected unit parameters, to protect against violating core design limits 

and the Reactor Coolant System (RCS) pressure boundary during 

anticipated operational occurrences (AOOs) and ensures acceptable 

consequences during accidents. 

The ESFAS contains devices and circuitry that generate the following 

signals when monitored variables reach levels that are indicative of 

conditions requiring protective action: 

1. Safety Injection Actuation Signal (SIAS), Containment Cooling 

Actuation Signal (CCAS) (actuated by an automatic SIAS), 

2. Containment Spray Actuation Signal (CSAS), 

3. Containment Isolation Actuation Signal (CIAS), 

4. Main Steam Isolation Signal (MSIS), 

5. Recirculation Actuation Signal (RAS), and 

6, 7. Emergency Feedwater Actuation Signal (EFAS). 

Equipment actuated by each of the above signals is identified in the 

FSAR (Ref. 1). 

Each of the above ESFAS instrumentation systems is segmented into 

three interconnected modules. These modules are: 

• Measurement channels, 

• Bistable trip units, and 

• ESFAS Logic: 

 - Matrix Logic, 

 - Initiation Logic (trip paths), and 

- Actuation Logic. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

This LCO addresses measurement channels and bistables. Logic is 

addressed in LCO 3.3.6, "Engineered Safety Features Actuation System 

(ESFAS) Logic and Manual Trip." 

The role of each of these modules in the ESFAS, including the logic of 

LCO 3.3.6, is discussed below. 

Measurement Channels

Measurement channels, consisting of field transmitters or process 

sensors and associated instrumentation, provide a measurable electronic 

signal based upon the physical characteristics of the parameter being 

measured. 

Four identical measurement channels with electrical and physical 

separation are provided for each parameter used in the generation of trip 

signals. These channels are designated A through D. Measurement 

channels provide input to ESFAS bistables within the same ESFAS 

channel. In addition, some measurement channels are used as inputs to 

Reactor Protective System (RPS) bistables, and most provide indication 

in the control room. Measurement channels used as an input to the RPS 

or ESFAS are not used for control Functions. 

When a channel monitoring a parameter indicates an unsafe condition, 

the bistable monitoring the parameter in that channel will trip. Tripping 

two or more channels of bistables monitoring the same parameter will deenergize Matrix Logic, which in turn de-energizes the Initiation Logic. 

This causes both channels of Actuation Logic to de-energize. Each 

channel of Actuation Logic controls one train of the associated 

Engineered Safety Features (ESF) equipment. 

Three of the four measurement and bistable channels are necessary to 

meet the redundancy and testability of GDC 21 in Appendix A to 

10 CFR 50 (Ref. 2). The fourth channel provides additional flexibility by 

allowing one channel to be removed from service (trip channel bypass) 

for maintenance or testing while still maintaining a minimum two-out-ofthree logic. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

In order to take full advantage of the four channel design, adequate 

channel to channel independence must be demonstrated and approved 

by the NRC staff. Plants not currently licensed to credit four channel 

independence that may desire this capability must have approval of the 

NRC staff, documented by an NRC Safety Evaluation Report (Ref. 3). 

Adequate channel to channel independence includes physical and 

electrical independence of each channel from the others. Furthermore, 

each channel must be energized from separate inverters and station 

batteries. Plants that have demonstrated adequate channel to channel 

independence may operate in two-out-of-three logic configuration, with 

one channel removed from service, until following the next MODE 5 entry. 

Plants not demonstrating four channel independence can only operate for 

48 hours with one channel inoperable (Ref. 3). 

-------------------------------------------------------------------------------------------------- 

Since no single failure will either cause or prevent a protective system 

actuation, and no protective channel feeds a control channel, this 

arrangement meets the requirements of IEEE Standard 279-1971 

(Ref. 4). 

Bistable Trip Units

Bistable trip units, mounted in the Plant Protection System (PPS) cabinet, 

receive an analog input from the measurement channels, compare the 

analog input to trip setpoints, and provide contact output to the Matrix 

Logic for each ESFAS Function. They also provide local trip indication 

and remote annunciation. 

There are four channels of bistables, designated A through D, for each 

ESFAS Function, one for each measurement channel. In cases where 

two ESF Functions share the same input and trip setpoint (e.g., 

containment pressure input to CIAS and SIAS), the same bistable may be 

used to satisfy both Functions. Similarly, bistables may be shared 

between the RPS and ESFAS (e.g., Pressurizer Pressure - Low input to 

the RPS and SIAS). Bistable output relays de-energize when a trip 

occurs, in turn de-energizing bistable relays mounted in the PPS relay 

card racks. 

The contacts from these bistable relays are arranged into six coincidence 

matrices, comprising the Matrix Logic. If bistables monitoring the same 

parameter in at least two channels trip, the Matrix Logic will generate an 

ESF actuation (two-out-of-four logic). 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-4 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The trip setpoints and Allowable Values used in the bistables are based 

on the analytical limits stated in Reference 5. The selection of these trip 

setpoints is such that adequate protection is provided when all sensor 

and processing time delays are taken into account. To allow for 

calibration tolerances, instrumentation uncertainties, instrument drift, and 

severe environment effects, for those ESFAS channels that must function 

in harsh environments as defined by 10 CFR 50.49 (Ref. 6), Allowable 

Values specified in Table 3.3.5-1, in the accompanying LCO, are 

conservatively adjusted with respect to the analytical limits. A detailed 

description of the methodology used to calculate the trip setpoints, 

including their explicit uncertainties, is provided in the "Plant Protection 

System Selection of Trip Setpoint Values" (Ref. 7). The actual nominal 

trip setpoint entered into the bistable is normally still more conservative 

than that specified by the Allowable Value to account for changes in 

random measurement errors detectable by a CHANNEL FUNCTIONAL 

TEST. A channel is inoperable if its actual trip setpoint is not within its 

required Allowable Value. 

Setpoints in accordance with the Allowable Value will ensure that Safety 

Limits of LCO Section 2.0, "Safety Limits," are not violated during AOOs 

and the consequences of Design Basis Accidents (DBAs) will be 

acceptable, providing the plant is operated from within the LCOs at the 

onset of the AOO or DBA and the equipment functions as designed. 

Functional testing of the ESFAS, from the bistable input through the 

opening of initiation relay contacts in the ESFAS Actuation Logic, can be 

performed either at power or at shutdown and is normally performed on a 

quarterly basis. FSAR, Section [7.2] (Ref. 8), provides more detail on 

ESFAS testing. Process transmitter calibration is normally performed on 

a refueling basis. SRs for the channels are specified in the Surveillance 

Requirements section. 

ESFAS Logic

The ESFAS Logic, consisting of Matrix, Initiation and Actuation Logic, 

employs a scheme that provides an ESF actuation of both trains when 

bistables in any two of the four channels sense the same input parameter 

trip. This is called a two-out-of-four trip logic. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-5 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Bistable relay contact outputs from the four channels are configured into 

six logic matrices. Each logic matrix checks for a coincident trip in the 

same parameter in two bistable channels. The matrices are designated 

the AB, AC, AD, BC, BD, and CD matrices to reflect the bistable channels 

being monitored. Each logic matrix contains four normally energized 

matrix relays. When a coincidence is detected in the two channels being 

monitored by the logic matrix, all four matrix relays de-energize. 

The matrix relay contacts are arranged into trip paths, with one relay 

contact from each matrix relay in each of the four trip paths. Each trip 

path controls two initiation relays. Each of the two initiation relays in each 

trip path controls contacts in the Actuation Logic for one train of ESF. 

Each of the two channels of Actuation Logic, mounted in the Auxiliary 

Relay Cabinet (ARCs), is responsible for actuating one train of ESF 

equipment. Each ESF Function has separate Actuation Logic in each 

ARC. 

The contacts from the Initiation Logic are configured in a selective twoout-of-four logic in the Actuation Logic, similar to the configuration 

employed by the RPS in the RTCBs. This logic controls ARC mounted 

subgroup relays, which are normally energized. Contacts from these 

relays, when de-energized, actuate specific ESF equipment. 

When a coincidence occurs in two ESFAS channels, all four matrix relays 

in the affected matrix will de-energize. This in turn will de-energize all 

eight initiation relays, four used in each Actuation Logic. 

Matrix Logic refers to the matrix power supplies, trip channel bypass 

contacts, and interconnecting matrix wiring between bistable relay cards, 

up to but not including the matrix relays. Matrix contacts on the bistable 

relay cards are excluded from the Matrix Logic definition, since they are 

addressed as part of the measurement channel. 

Initiation Logic consists of the trip path power source, matrix relays and 

their associated contacts, all interconnecting wiring, and the initiation 

relays. 

Actuation Logic consists of all circuitry housed within the ARCs used to 

actuate the ESF Function, excluding the subgroup relays, and 

interconnecting wiring to the initiation relay contacts mounted in the PPS 

cabinet. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-6 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The subgroup relays are actuated by the ESFAS logic. Each ESFAS 

Function typically employs several subgroup relays, with each subgroup 

relay responsible for actuating one or more components in the ESFAS 

Function. Subgroup relays and their contacts are considered part of the 

actuated equipment and are addressed under the applicable LCO for this 

equipment. Initiation and Actuation Logic up to the subgroup relays is 

addressed in LCO 3.3.6. 

It is possible to change the two-out-of-four ESFAS logic to a two-out-ofthree logic for a given input parameter in one channel at a time by trip 

channel bypassing select portions of the Matrix Logic. Trip channel 

bypassing a bistable effectively shorts the bistable relay contacts in the 

three matrices associated with that channel. Thus, the bistables will 

function normally, producing normal trip indication and annunciation, but 

ESFAS actuation will not occur since the bypassed channel is effectively 

removed from the coincidence logic. Trip channel bypassing can be 

simultaneously performed on any number of parameters in any number of 

channels, providing each parameter is bypassed in only one channel at a 

time. An interlock prevents simultaneous trip channel bypassing of the 

same parameter in more than one channel. Trip channel bypassing is 

normally employed during maintenance or testing. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

For plants that have demonstrated sufficient channel to channel 

independence, two-out-of-three logic is the minimum that is required to 

provide adequate plant protection, since a failure of one channel still 

ensures ESFAS actuation would be generated by the two remaining 

OPERABLE channels. Two-out-of-three logic also prevents inadvertent 

actuations caused by any single channel failure in a trip condition. 

-------------------------------------------------------------------------------------------------- 

In addition to the trip channel bypasses, there are also operating 

bypasses on select ESFAS actuation trips. These bypasses are enabled 

manually in all four channels when plant conditions do not warrant the 

specific trip protection. All operating bypasses are automatically removed 

when enabling bypass conditions are no longer satisfied. Operating 

bypasses normally are implemented in the bistable, so that normal trip 

indication is also disabled. The Pressurizer Pressure - Low input to the 

SIAS shares an operating bypass with the Pressurizer Pressure - Low 

reactor trip. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-7 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Manual ESFAS initiation capability is provided to permit the operator to 

manually actuate an ESF System when necessary. 

Two sets of two push buttons (located in the control room) for each ESF 

Function are provided, and each set actuates both trains. Each Manual 

Trip push button opens one trip path, de-energizing one set of two 

initiation relays, one affecting each train of ESF. Initiation relay contacts 

are arranged in a selective two-out-of-four configuration in the Actuation 

Logic. By arranging the push buttons in two sets of two, such that both 

push buttons in a set must be depressed, it is possible to ensure that 

Manual Trip will not be prevented in the event of a single random failure. 

Each set of two push buttons is designated a single channel in LCO 3.3.6. 

APPLICABLE Each of the analyzed accidents can be detected by one or more ESFAS 

SAFETY Functions. One of the ESFAS Functions is the primary actuation signal 

ANALYSES for that accident. An ESFAS Function may be the primary actuation 

signal for more than one type of accident. An ESFAS Function may also 

be the secondary, or backup, actuation signal for one or more other 

accidents. 

ESFAS protective Functions are as follows: 

1. Safety Injection Actuation Signal

SIAS ensures acceptable consequences during large break loss of 

coolant accidents (LOCAs), small break LOCAs, control element 

assembly ejection accidents, and main steam line breaks (MSLBs) 

inside containment. To provide the required protection, either a high 

containment pressure or a low pressurizer pressure signal will initiate 

SIAS. SIAS initiates the Emergency Core Cooling Systems (ECCS) 

and performs several other functions such as initiating a containment 

cooling actuation, initiating control room isolation, and starting the 

diesel generators. 

CCAS mitigates containment overpressurization when required by 

either a manual CCAS actuation or an automatic SIAS Function. 

This Function is not employed by all plants. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-8 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

2. Containment Spray Actuation Signal

CSAS actuates containment spray, preventing containment 

overpressurization during large break LOCAs, small break LOCAs, 

and MSLBs or feedwater line breaks (FWLBs) inside containment. 

CSAS is initiated by high containment pressure and an SIAS. This 

configuration reduces the likelihood of inadvertent containment spray. 

3. Containment Isolation Actuation Signal

CIAS ensures acceptable mitigating actions during large and small 

break LOCAs, and MSLBs or FWLBs either inside or outside 

containment. CIAS is initiated by low pressurizer pressure or high 

containment pressure. 

4. Main Steam Isolation Signal

MSIS ensures acceptable consequences during an MSLB or FWLB 

(between the steam generator and the main feedwater check valve), 

either inside or outside containment. MSIS isolates both steam 

generators if either generator indicates a low pressure condition or if 

a high containment pressure condition exists. This prevents an 

excessive rate of heat extraction and subsequent cooldown of the 

RCS during these events. 

5. Recirculation Actuation Signal

At the end of the injection phase of a LOCA, the refueling water 

storage tank (RWST) will be nearly empty. Continued cooling must 

be provided by the ECCS to remove decay heat. The source of 

water for the ECCS pumps is automatically switched to the 

containment recirculation sump. Switchover from RWST to 

containment sump must occur before the RWST empties to prevent 

damage to the ECCS pumps and a loss of core cooling capability. 

For similar reasons, switchover must not occur before there is 

sufficient water in the containment sump to support pump suction. 

Furthermore, early switchover must not occur to ensure sufficient 

borated water is injected from the RWST to ensure the reactor 

remains shut down in the recirculation mode. An RWST Level - Low 

signal initiates the RAS. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-9 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

6, 7. Emergency Feedwater Actuation Signal

EFAS consists of two steam generator (SG) specific signals (EFAS-1 

and EFAS-2). EFAS-1 initiates emergency feed to SG #1, and 

EFAS-2 initiates emergency feed to SG #2. 

EFAS maintains a steam generator heat sink during a steam 

generator tube rupture event and an MSLB or FWLB event either 

inside or outside containment. 

Low steam generator water level initiates emergency feed to the 

affected steam generator, providing the generator is not identified (by 

the circuitry) as faulted (a steam or FWLB). 

EFAS logic includes steam generator specific inputs from the Steam 

Generator Pressure - Low bistable comparator (also used in MSIS) 

and the SG Pressure Difference - High (SG #1 > SG #2 or 

SG #2 > SG #1, bistable comparators) to determine if a rupture in 

either generator has occurred. 

Rupture is assumed if the affected generator has a low pressure 

condition, unless that generator is significantly higher in pressure 

than the other generator. 

This latter feature allows feeding the intact steam generator, even if 

both are below the MSIS setpoint, while preventing the ruptured 

generator from being fed. Not feeding a ruptured generator prevents 

containment overpressurization during the analyzed events. 

The ESFAS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The LCO requires all channel components necessary to provide an 

ESFAS actuation to be OPERABLE. 

Plants are restricted to 48 hours in a trip channel bypass condition before 

restoring the Function to four channel operation (two-out-of-four logic) or 

placing the channel in trip (two-out-of-three logic). 

The Bases for the LCOs on ESFAS Functions are: 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-10 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

1. Safety Injection Actuation Signal

a. Containment Pressure - High

This LCO requires four channels of Containment Pressure - High 

to be OPERABLE in MODES 1, 2, and 3. 

The Containment Pressure - High signal is shared among the 

SIAS (Function 1), CIAS (Function 3), and MSIS (Function 4). 

The Allowable Value for this trip is set high enough to allow for 

small pressure increases in containment expected during normal 

operation (i.e., plant heatup) and is not indicative of an abnormal 

condition. The setting is low enough to initiate the ESF 

Functions when an abnormal condition is indicated. This allows 

the ESF systems to perform as expected in the accident 

analyses to mitigate the consequences of the analyzed 

accidents. 

b. Pressurizer Pressure - Low

This LCO requires four channels of Pressurizer Pressure - Low 

to be OPERABLE in MODES 1 and 2. 

The Allowable Value for this trip is set low enough to prevent 

actuating the ESF Functions (SIAS and CIAS) during normal 

plant operation and pressurizer pressure transients. The setting 

is high enough that, with the specified accidents, the ESF 

systems will actuate to perform as expected, mitigating the 

consequences of the accident. 

The Pressurizer Pressure - Low trip setpoint, which provides 

SIAS, CIAS, and RPS trip, may be manually decreased to a floor 

value of 300 psia to allow for a controlled cooldown and 

depressurization of the RCS without causing a reactor trip, CIAS, 

or SIAS. The margin between actual pressurizer pressure and 

the trip setpoint must be maintained less than or equal to the 

specified value (400 psia) to ensure a reactor trip, CIAS, and 

SIAS will occur if required during RCS cooldown and 

depressurization. 

From this reduced setting, the trip setpoint will increase 

automatically as pressurizer pressure increases, tracking actual 

RCS pressure until the trip setpoint is reached. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-11 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

When the trip setpoint has been lowered below the bypass 

permissive setpoint of 400 psia, the Pressurizer Pressure - Low 

reactor trip, CIAS, and SIAS actuation may be manually 

bypassed in preparation for shutdown cooling. When RCS 

pressure rises above the bypass removal setpoint, the bypass is 

removed. 

Bypass Removal

This LCO requires four channels of bypass removal for 

Pressurizer Pressure - Low to be OPERABLE in MODES 1, 2, 

and 3. 

Each of the four channels enables and disables the bypass 

capability for a single channel. Therefore, this LCO applies to 

the bypass removal feature only. If the bypass enable function is 

failed so as to prevent entering a bypass condition, operation 

may continue. Because the trip setpoint has a floor value of 

300 psia, a channel trip will result if pressure is decreased below 

this setpoint without bypassing. 

The bypass removal Allowable Value was chosen because 

MSLB events originating from below this setpoint add less 

positive reactivity than that which can be compensated for by 

required SDM. 

2. Containment Spray Actuation Signal

CSAS is initiated either manually or automatically. For an automatic 

actuation, it is necessary to have a Containment Pressure - High 

High signal, coincident with an SIAS. The SIAS requirement should 

always be satisfied on a legitimate CSAS, since the Containment 

Pressure - High signal used in the SIAS will initiate before the 

Containment Pressure - High High. This ensures that a CSAS will 

not initiate unless required. 

a. Containment Pressure - High High

This LCO requires four channels of Containment Pressure - High 

High to be OPERABLE in MODES 1, 2, and 3. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-12 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The Allowable Value for this trip is set high enough to allow for 

first response ESF systems (containment cooling systems) to 

attempt to mitigate the consequences of an accident before 

resorting to spraying borated water onto containment equipment. 

The setting is low enough to initiate CSAS in time to prevent 

containment pressure from exceeding design. 

3. Containment Isolation Actuation Signal

For plants where the SIAS and CIAS are actuated on Pressurizer 

Pressure - Low or Containment Pressure - High, the SIAS and CIAS 

share the same input channels, bistables, and matrices and matrix 

relays. The remainder of the initiation channels, the manual 

channels, and the Actuation Logic are separate and are addressed in 

LCO 3.3.6. Since their Applicability is also the same, they have 

identical Required Actions. 

a. Containment Pressure - High

This LCO requires four channels of Containment Pressure - High 

to be OPERABLE in MODES 1, 2, and 3. 

The Containment Pressure - High signal is shared among the 

SIAS (Function 1), CIAS (Function 3), and MSIS (Function 4). 

The Allowable Value for this trip is set high enough to allow for 

small pressure increases in containment expected during normal 

operation (i.e., plant heatup) and is not indicative of an abnormal 

condition. The setting is low enough to initiate the ESF 

Functions when an abnormal condition is indicated. This allows 

the ESF systems to perform as expected in the accident 

analyses to mitigate the consequences of the analyzed 

accidents. 

b. Pressurizer Pressure - Low

This LCO requires four channels of Pressurizer Pressure - Low 

to be OPERABLE in MODES 1, 2, and 3. 

The Allowable Value for this trip is set low enough to prevent 

actuating the ESF Functions (SIAS and CIAS) during normal 

plant operation and pressurizer pressure transients. The setting 

is high enough that, with the specified accident, the ESF systems 

will actuate to perform as expected, mitigating the consequences 

of the accidents. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-13 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The Pressurizer Pressure - Low trip setpoint, which provides an 

SIAS, CIAS, and RPS trip, may be manually decreased to a floor 

Allowable Value of 300 psia to allow for a controlled cooldown 

and depressurization of the RCS without causing a reactor trip, 

CIAS or SIAS. The safety margin between actual pressurizer 

pressure and the trip setpoint must be maintained less than or 

equal to the specified value (400 psi) to ensure a reactor trip, 

CIAS, and SIAS will occur if required during RCS cooldown and 

depressurization. 

From this reduced setting, the trip setpoint will increase 

automatically as pressurizer pressure increases, tracking actual 

RCS pressure until the trip setpoint is reached. 

When the trip setpoint has been lowered below the bypass 

removal setpoint of 400 psia, the Pressurizer Pressure - Low 

reactor trip, CIAS, and SIAS actuation may be manually 

bypassed in preparation for shutdown cooling. When RCS 

pressure rises above the bypass removal, the bypass is 

removed. 

Bypass Removal

This LCO requires four channels of bypass removal for 

Pressurizer Pressure - Low to be OPERABLE in MODES 1, 2, 

and 3. 

Each of the four channels enables and disables the bypass 

capability for a single channel. Therefore all four bypass 

removal channels must be OPERABLE to ensure that none of 

the four channels are inadvertently bypassed. 

This LCO applies to the bypass removal feature only. If the 

bypass enable function is failed so as to prevent entering a 

bypass condition, operation may continue. Because the trip 

setpoint has a floor value of 300 psia, a channel trip will result if 

pressure is decreased below this setpoint without bypassing. 

The bypass removal Allowable Value was chosen because 

MSLB events originating from below this setpoint add less 

positive reactivity than that which can be compensated for by 

required SDM. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-14 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

4. Main Steam Isolation Signal

The LCO is applicable to the MSIS in MODES 1, 2, and 3 except 

when all associated valves are closed and de-activated. 

a. Steam Generator Pressure - Low

This LCO requires four channels of Steam Generator Pressure - 

Low to be OPERABLE in MODES 1, 2, and 3. 

The Allowable Value for this trip is set below the full load 

operating value for steam pressure so as not to interfere with 

normal plant operation. However, the setting is high enough to 

provide an MSIS (Function 4) during an excessive steam 

demand event. An excessive steam demand event causes the 

RCS to cool down, resulting in a positive reactivity addition to the 

core. 

MSIS limits this cooldown by isolating both steam generators if 

the pressure in either drops below the trip setpoint. An RPS trip 

on Steam Generator Pressure - Low is initiated simultaneously, 

using the same bistable. The Steam Generator Pressure - Low 

bistable output is also used in the EFAS logic (Function 7) to aid 

in determining if a steam generator is intact. 

The Steam Generator Pressure - Low trip setpoint may be 

manually decreased as steam generator pressure is reduced. 

This prevents an RPS trip or MSIS actuation during controlled 

plant cooldown. The margin between actual pressurizer 

pressure and the trip setpoint must be maintained less than or 

equal to the specified value of 200 psia to ensure a reactor trip 

and MSIS will occur when required. 

b. Containment Pressure - High

This LCO requires four channels of Containment Pressure - High 

to be OPERABLE in MODES 1, 2, and 3. The Containment 

Pressure - High signal is shared among the SIAS (Function 1), 

CIAS (Function 3), and MSIS (Function 4). 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-15 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The Allowable Value for this trip is set high enough to allow for 

small pressure increases in containment expected during normal 

operation (i.e., plant heatup) and is not indicative of an abnormal 

condition. The setting is low enough to initiate the ESF 

Functions when an abnormal condition is indicated. This allows 

the ESF systems to perform as expected in the accident 

analyses to mitigate the consequences of the analyzed 

accidents. 

5. Recirculation Actuation Signal

a. Refueling Water Storage Tank Level - Low

This LCO requires four channels of RWST Level - Low to be 

OPERABLE in MODES 1, 2, and 3. 

The upper limit on the Allowable Value for this trip is set low 

enough to ensure RAS does not initiate before sufficient water is 

transferred to the containment sump. Premature recirculation 

could impair the reactivity control function of safety injection by 

limiting the amount of boron injection. Premature recirculation 

could also damage or disable the recirculation system if 

recirculation begins before the sump has enough water to 

prevent air entrainment in the suction. The lower limit on the 

RWST Level - Low trip Allowable Value is high enough to 

transfer suction to the containment sump prior to emptying the 

RWST. 

6, 7 Emergency Feedwater Actuation Signal SG #1 and 

SG #2 (EFAS-1 and EFAS-2)

EFAS-1 is initiated to SG #1 by either a low steam generator level 

coincident with no low pressure trip present on SG #1 or by a low 

steam generator level coincident with a differential pressure between 

the two generators with the higher pressure in SG #1. EFAS-2 is 

similarly configured to feed SG #2. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-16 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The steam generator secondary differential pressure is used, in 

conjunction with a Steam Generator Pressure - Low input from each 

steam generator, as an input of the EFAS logic where it is used to 

determine if a generator is intact. The EFAS logic inhibits feeding a 

steam generator if a Steam Generator Pressure - Low condition 

exists in that generator and the pressure in that steam generator is 

less than the pressure in the other steam generator by the Steam 

Generator Pressure Difference (SGPD) - High setpoint. 

The SGPD logic thus enables the feeding of a steam generator in the 

event that a plant cooldown causes a Steam Generator Pressure - 

Low condition, while inhibiting feeding the other (lower pressure) 

steam generator, which may be ruptured. The setpoint is high 

enough to allow for small pressure differences and normal 

instrumentation errors between the steam generator channels during 

normal operation. 

The following LCO description applies to both EFAS signals. 

a. Steam Generator Level - Low

This LCO requires four channels of Steam Generator Level - 

Low to be OPERABLE for each EFAS in MODES 1, 2, and 3. 

The Steam Generator Level - Low EFAS input is derived from 

the Steam Generator Level - Low RPS bistable output. EFAS is 

thus initiated simultaneously with a reactor trip. The setpoint 

ensures at least a 20 minute inventory of water remains in the 

affected steam generator at reactor trip. Thus, EFAS is initiated 

well before steam generator inventory is challenged. 

b. SG Pressure Difference - High (SG #1 > SG #2) or

(SG #2 > SG #1)

This LCO requires four channels of SG Pressure Difference - 

High to be OPERABLE for each EFAS in MODES 1, 2, and 3. 

The Allowable Value for this trip is high enough to allow for small 

pressure differences and normal instrumentation errors between 

the steam generator channels during normal operation without 

an actuation. The setting is low enough to detect and inhibit 

feeding of a ruptured steam generator in the event of an MSLB 

or FWLB, while permitting the feeding of the intact steam 

generator. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-17 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

c. Steam Generator Pressure - Low

This LCO requires four channels of Steam Generator Pressure - 

Low to be OPERABLE for each EFAS in MODES 1, 2, and 3. 

The Steam Generator Pressure - Low input is derived from the 

Steam Generator Pressure - Low RPS bistable output. This 

output is also used as an MSIS input. 

The Allowable Value for this trip is set below the full load 

operating value for steam pressure so as not to interfere with 

normal plant operation. However, the setting is high enough to 

provide an MSIS (Function 4) during an excessive steam 

demand event. An excessive steam demand is one indicator of 

a potentially ruptured steam generator; thus, this EFAS input, in 

conjunction with the SGPD Function, prevents the feeding of a 

potentially ruptured steam generator. 

The Steam Generator Pressure - Low trip setpoint may be 

manually decreased as steam generator pressure is reduced. 

This prevents an RPS trip or MSIS actuation during controlled 

plant cooldown. The margin between actual pressurizer 

pressure and the trip setpoint must be maintained less than or 

equal to the specified value of 200 psi to ensure that a reactor 

trip and MSIS will occur when required. 

APPLICABILITY In MODES 1, 2 and 3 there is sufficient energy in the primary and 

secondary systems to warrant automatic ESF System responses to: 

• Close the main steam isolation valves to preclude a positive reactivity 

addition, 

• Actuate emergency feedwater to preclude the loss of the steam 

generators as a heat sink (in the event the normal feedwater system 

is not available), 

• Actuate ESF systems to prevent or limit the release of fission product 

radioactivity to the environment by isolating containment and limiting 

the containment pressure from exceeding the containment design 

pressure during a design basis LOCA or MSLB, and 

• Actuate ESF systems to ensure sufficient borated inventory to permit 

adequate core cooling and reactivity control during a design basis 

LOCA or MSLB accident. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-18 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY (continued) 

In MODES 4, 5, and 6, automatic actuation of these Functions is not 

required because adequate time is available to evaluate plant conditions 

and respond by manually operating the ESF components if required, as 

addressed by LCO 3.3.6. 

Several trips have operating bypasses, discussed in the preceding LCO 

section. The interlocks that allow these bypasses shall be OPERABLE 

whenever the RPS Function they support is OPERABLE. 

ACTIONS The most common causes of channel inoperability are outright failure or 

drift of the bistable or process module sufficient to exceed the tolerance 

allowed by the plant specific setpoint analysis. Typically, the drift is found 

to be small and results in a delay of actuation rather than a total loss of 

function. Determination of setpoint drift is generally made during the 

performance of a CHANNEL FUNCTIONAL TEST when the process 

instrument is set up for adjustment to bring it to within specification. 

In the event a channel's trip setpoint is found nonconservative with 

respect to the Allowable Value, or the transmitter, instrument loop, signal 

processing electronics, or ESFAS bistable is found inoperable, then all 

affected Functions provided by that channel must be declared inoperable 

and the LCO Condition entered for the particular protection Function 

affected. 

When the number of inoperable channels in a trip Function exceeds those 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 should 

be entered immediately, if applicable in the current MODE of operation. 

A Note has been added to the ACTIONS. The Note has been added to 

clarify the application of the Completion Time rules. The Conditions of 

this Specification may be entered independently for each Function. The 

Completion Time for the inoperable channel of a Function will be tracked 

separately for each Function starting from the time the Condition was 

entered for that Function. 

A.1 and A.2

Condition A applies to the failure of a single channel of one or more input 

parameters in the following ESFAS Functions: 

1. Safety Injection Actuation Signal Containment Pressure - High 

Pressurizer Pressure - Low 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-19 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

2. Containment Spray Actuation Signal Containment Pressure - High 

High Automatic SIAS 

3. Containment Isolation Actuation Signal Containment Pressure - High 

Pressurizer Pressure - Low 

4. Main Steam Isolation Signal Steam Generator Pressure - Low 

Containment Pressure - High 

5. Recirculation Actuation Signal Refueling Water Storage Tank Level - 

Low 

6. Emergency Feedwater Actuation Signal SG #1 (EFAS-1) Steam 

Generator Level - Low SG Pressure Difference - High Steam 

Generator Pressure - Low 

7. Emergency Feedwater Actuation Signal SG #2 (EFAS-2) Steam 

Generator Level - Low SG Pressure Difference - High Steam 

Generator Pressure - Low 

ESFAS coincidence logic is normally two-out-of-four. 

If one ESFAS channel is inoperable, startup or power operation is allowed 

to continue, providing the inoperable channel is placed in bypass or trip 

within 1 hour (Required Action A.1). 

The Completion Time of 1 hour allotted to restore, bypass, or trip the 

channel is sufficient to allow the operator to take all appropriate actions 

for the failed channel and still ensures that the risk involved in operating 

with the failed channel is acceptable. 

The failed channel must be restored to OPERABLE status prior to 

entering MODE 2 following the next MODE 5 entry. With a channel 

bypassed, the coincidence logic is now in a two-out-of-three 

configuration. In this configuration, common cause failure of dependent 

channels cannot prevent trip. The Completion Time of prior to entering 

MODE 2 following the next MODE 5 entry is based on adequate channel 

to channel independence, which allows a two-out-of-three channel 

operation, since no single failure will cause or prevent a reactor trip. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-20 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1

Condition B applies to the failure of two channels of one or more input 

parameters in the following ESFAS automatic trip Functions: 

1. Safety Injection Actuation Signal Containment Pressure - High 

Pressurizer Pressure - Low 

2. Containment Spray Actuation Signal Containment Pressure - High 

High Automatic SIAS 

3. Containment Isolation Actuation Signal Containment Pressure - High 

Pressurizer Pressure - Low 

4. Main Steam Isolation Signal Steam Generator Pressure - Low 

Containment Pressure - High 

5. Recirculation Actuation Signal Refueling Water Storage Tank Level - 

Low 

6. Emergency Feedwater Actuation Signal SG #1 (EFAS-1) Steam 

Generator Level - Low SG Pressure Difference - High Steam 

Generator Pressure - Low 

7. Emergency Feedwater Actuation Signal SG #2 (EFAS-2) Steam 

Generator Level - Low SG Pressure Difference - High Steam 

Generator Pressure - Low 

With two inoperable channels, power operation may continue, provided 

one inoperable channel is placed in bypass and the other channel is 

placed in trip within 1 hour. With one channel of protective 

instrumentation bypassed, the ESFAS Function is in two-out-of-three 

logic in the bypassed input parameter, but with another channel failed, the 

ESFAS may be operating with a two-out-of-two logic. This is outside the 

assumptions made in the analyses and should be corrected. To correct 

the problem, the second channel is placed in trip. This places the ESFAS 

Function in a one-out-of-two logic. If any of the other OPERABLE 

channels receives a trip signal, ESFAS actuation will occur. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-21 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

One of the two inoperable channels will need to be restored to 

OPERABLE status prior to the next required CHANNEL FUNCTIONAL 

TEST because channel surveillance testing on an OPERABLE channel 

requires that the OPERABLE channel be placed in bypass. However, it is 

not possible to bypass more than one ESFAS channel, and placing a 

second channel in trip will result in an ESFAS actuation. Therefore, if one 

ESFAS channel is in trip and a second channel is in bypass, a third 

inoperable channel would place the unit in LCO 3.0.3. 

C.1, C.2.1, and C.2.2

Condition C applies to one automatic bypass removal channel inoperable. 

The only automatic bypass removal on an ESFAS is on the Pressurizer 

Pressure - Low signal. This bypass removal is shared with the RPS 

Pressurizer Pressure - Low bypass removal. 

If the bypass removal channel for any operating bypass cannot be 

restored to OPERABLE status, the associated ESFAS channel may be 

considered OPERABLE only if the bypass is not in effect. Otherwise, the 

affected ESFAS channel must be declared inoperable, as in Condition A, 

and the bypass either removed or the bypass removal channel repaired. 

The Bases for the Required Actions and required Completion Times are 

consistent with Condition A. 

D.1 and D.2

Otherwise, the affected ESFAS channels must be declared inoperable, as 

in Condition B, and either the bypass removed or the bypass removal 

channel repaired. The restoration of one affected bypassed automatic 

trip channel must be completed prior to the next CHANNEL 

FUNCTIONAL TEST or the plant must shut down per LCO 3.0.3, as 

explained in Condition B. Completion Times are consistent with 

Condition B. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-22 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

E.1 and E.2

If the Required Actions and associated Completion Times of Condition A, 

B, C, or D cannot be met, the plant must be brought to a MODE in which 

the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 4 within 

[12] hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE SR 3.3.5.1

REQUIREMENTS 

Performance of the CHANNEL CHECK once every 12 hours ensures that 

a gross failure of instrumentation 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 instrument 

channels could be an indication of excessive instrument drift in one of the 

channels or of something even more serious. CHANNEL CHECK will 

detect gross channel failure; thus, it is key to verifying the instrumentation 

continues to operate properly between each CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the sensor or the signal processing equipment has drifted outside its 

limit. If the channels are within the criteria, it is an indication that the 

channels are OPERABLE. 

The Frequency, about once every shift, is based on operating experience 

that demonstrates channel failure is rare. Since the probability of two 

random failures in redundant channels in any 12 hour period is low, the 

CHANNEL CHECK minimizes the chance of loss of protective function 

due to failure of redundant channels. The CHANNEL CHECK 

supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of displays associated with 

the LCO required channels. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-23 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.5.2

A CHANNEL FUNCTIONAL TEST is performed every 92 days to ensure 

the entire channel will perform its intended function when needed. A 

successful test of the required contact(s) of a channel relay may be 

performed by the verification of the change of state of a single contact of 

the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL 

TEST of a relay. This is acceptable because all of the other required 

contacts of the relay are verified by other Technical Specifications and 

non-Technical Specifications tests at least once per refueling interval with 

applicable extensions. 

The CHANNEL FUNCTIONAL TEST is part of an overlapping test 

sequence similar to that employed in the RPS. This sequence, consisting 

of SR 3.3.5.2, SR 3.3.6.1, and SR 3.3.6.2, tests the entire ESFAS from 

the bistable input through the actuation of the individual subgroup relays. 

These overlapping tests are described in Reference 1. SR 3.3.5.2 and 

SR 3.3.6.1 are normally performed together and in conjunction with 

ESFAS testing. SR 3.3.6.2 verifies that the subgroup relays are capable 

of actuating their respective ESF components when de-energized. 

These tests verify that the ESFAS is capable of performing its intended 

function, from bistable input through the actuated components. 

SRs 3.3.6.1 and 3.3.6.2 are addressed in LCO 3.3.6. SR 3.3.5.2 includes 

bistable tests. 

A test signal is superimposed on the input in one channel at a time to 

verify that the bistable trips within the specified tolerance around the 

setpoint. This is done with the affected RPS trip channel bypassed. Any 

setpoint adjustment shall be consistent with the assumptions of the 

current plant specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [9]. 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-24 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.5.3

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the detector and the bypass removal functions. The 

Surveillance verifies that the channel responds to a measured parameter 

within the necessary range and accuracy. CHANNEL CALIBRATION 

leaves the channel adjusted to account for instrument drift between 

successive calibrations to ensure that the channel remains operational 

between successive surveillances. CHANNEL CALIBRATIONS must be 

performed consistent with the plant specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [9]. 

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. 

SR 3.3.5.4

This Surveillance ensures that the train actuation response times are 

within the maximum values assumed in the safety analyses. 

Response time testing acceptance criteria are included in Reference 10. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Applicable portions of the following TS Bases are applicable to plants 

adopting CEOG Topical Report CE NPSD-1167-1, "Elimination of 

Pressure Sensor Response Time Testing Requirements." 

-------------------------------------------------------------------------------------------------- 

Response time may be verified by any series of sequential, overlapping 

or total channel measurements, including allocated sensor response time, 

such that the response time is verified. Allocations for sensor response 

times may be obtained from records of test results, vendor test data, or 

vendor engineering specifications. Topical Report CE NPSD-1167-A, 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-25 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

"Elimination of Pressure Sensor Response Time Testing Requirements," 

(Ref. 11) provides the basis and methodology for using allocated sensor 

response times in the overall verification of the channel response time for 

specific sensors identified in the Topical Report. Response time 

verification for other sensor types must be demonstrated by test. The 

allocation of sensor response times must be verified prior to placing a 

new component in operation and reverified after maintenance that may 

adversely affect the sensor response time. 

ESF RESPONSE TIME tests are conducted on a STAGGERED TEST 

BASIS of once every [18] months. The [18] month Frequency is 

consistent with the typical industry refueling cycle and is based upon plant 

operating experience, which shows that random failures of 

instrumentation components causing serious response time degradation, 

but not channel failure, are infrequent occurrences. 

SR 3.3.5.5

SR 3.3.5.5 is a CHANNEL FUNCTIONAL TEST similar to SR 3.3.5.2, 

except SR 3.3.5.5 is performed within 92 days prior to startup and is only 

applicable to bypass functions. Since the Pressurizer Pressure - Low 

bypass is identical for both the RPS and ESFAS, this is the same 

Surveillance performed for the RPS in SR 3.3.1.13. A successful test of 

the required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. 

The CHANNEL FUNCTIONAL TEST for proper operation of the bypass 

permissives is critical during plant heatups because the bypasses may be 

in place prior to entering MODE 3 but must be removed at the appropriate 

points during plant startup to enable the ESFAS Function. Consequently, 

just prior to startup is the appropriate time to verify bypass function 

OPERABILITY. Once the bypasses are removed, the bypasses must not 

fail in such a way that the associated ESFAS Function is inappropriately 

bypassed. This feature is verified by SR 3.3.5.2. 

The allowance to conduct this test with 92 days of startup is based on the 

reliability analysis presented in topical report CEN-327, "RPS/ESFAS 

Extended Test Interval Evaluation" (Ref. 9). 
ESFAS Instrumentation (Digital) 

B 3.3.5 

CEOG STS B 3.3.5-26 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Section [7.3]. 

 2. 10 CFR 50, Appendix A. 

 3. NRC Safety Evaluation Report. 

 4. IEEE Standard 279-1971. 

 5. FSAR, Chapter [15]. 

 6. 10 CFR 50.49. 

 7. "Plant Protection System Selection of Trip Setpoint Values." 

 8. FSAR, Section [7.2]. 

 9. CEN-327, May 1986, including Supplement 1, March 1989. 

 10. Response Time Testing Acceptance Criteria. 

 11. CEOG Topical Report CE NPSD-1167-A, "Elimination of Pressure 

Sensor Response Time Testing Requirements." 
DG - LOVS (Analog) 

B 3.3.6 

CEOG STS B 3.3.6-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.6 Diesel Generator (DG) - Loss of Voltage Start (LOVS) (Analog) 

BASES 

BACKGROUND The DGs provide a source of emergency power when offsite power is 

either unavailable or insufficiently stable to allow safe plant operation. 

Undervoltage protection will generate a LOVS in the event a Loss of 

Voltage or Degraded Voltage condition occurs. There are two LOVS 

Functions for each 4.16 kV vital bus. 

Four undervoltage relays with inverse time characteristics are provided on 

each 4.16 kV Class 1E instrument bus for the purpose of detecting a 

sustained undervoltage condition or a loss of bus voltage. The relays are 

combined in a two-out-of-four logic to generate a LOVS if the voltage is 

below 75% for a short time or below 90% for a long time. The LOVS 

initiated actions are described in Reference 1. 

Trip Setpoints and Allowable Values

The trip setpoints and Allowable Values are based on the analytical limits 

presented in Reference 2. The selection of these trip setpoints is such 

that adequate protection is provided when all sensor and processing time 

delays are taken into account. To allow for calibration tolerances, 

instrumentation uncertainties, and instrument drift, Allowable Values 

specified in SR 3.3.6.3 are conservatively adjusted with respect to the 

analytical limits. A detailed description of the methodology used to 

calculate the trip setpoints, including their explicit uncertainties, is 

provided in Reference 3. The actual nominal trip setpoint is normally still 

more conservative than that required by the plant specific setpoint 

calculations. If the measured setpoint does not exceed the documented 

surveillance trip acceptance criteria, the undervoltage relay is considered 

OPERABLE. 

Setpoints in accordance with the Allowable Values will ensure that the 

consequences of accidents will be acceptable, providing the plant is 

operated from within the LCOs at the onset of the accident and the 

equipment functions as designed. 
DG - LOVS (Analog) 

B 3.3.6 

CEOG STS B 3.3.6-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The undervoltage protection scheme has been designed to protect the 

plant from spurious trips caused by the offsite power source. This is 

made possible by the inverse voltage time characteristics of the relays 

used. A complete loss of offsite power will result in approximately a 

1 second delay in LOVS actuation. The DG starts and is available to 

accept loads within a 10 second time interval on the Engineered Safety 

Features Actuation System (ESFAS) or LOVS. Emergency power is 

established within the maximum time delay assumed for each event 

analyzed in the accident analysis (Ref. 2). 

Since there are four protective channels in a two-out-of-four trip logic for 

each division of the 4.16 kV power supply, no single failure will cause or 

prevent protective system actuation. This arrangement meets IEEE 

Standard 279-1971 criteria (Ref. 4). 

APPLICABLE The DG - LOVS is required for Engineered Safety Features (ESF) 

SAFETY systems to function in any accident with a loss of offsite power. Its design 

ANALYSES basis is that of the ESFAS. 

Accident analyses credit the loading of the DG based on a loss of offsite 

power during a loss of coolant accident. The actual DG start has 

historically been associated with the ESFAS actuation. The diesel 

loading has been included in the delay time associated with each safety 

system component requiring DG supplied power following a loss of offsite 

power. The analysis assumes a nonmechanistic DG loading, which does 

not explicitly account for each individual component of the loss of power 

detection and subsequent actions. This delay time includes contributions 

from the DG start, DG loading, and Safety Injection System component 

actuation. The response of the DG to a loss of power must be 

demonstrated to fall within this analysis response time when including the 

contributions of all portions of the delay. 

The required channels of LOVS, in conjunction with the ESF systems 

powered from the DGs, provide plant protection in the event of any of the 

analyzed accidents discussed in Reference 2, in which a loss of offsite 

power is assumed. LOVS channels are required to meet the redundancy 

and testability requirements of GDC 21 in 10 CFR 50, Appendix A 

(Ref. 5). 

The delay times assumed in the safety analysis for the ESF equipment 

include the [10] second DG start delay and the appropriate sequencing 

delay, if applicable. The response times for ESFAS actuated equipment 

include the appropriate DG loading and sequencing delay. 

The DG - LOVS channels satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 
DG - LOVS (Analog) 

B 3.3.6 

CEOG STS B 3.3.6-3 Rev. 3.0, 03/31/04 

BASES 

LCO The LCO for the LOVS requires that four channels per bus of each LOVS 

instrumentation Function be OPERABLE in MODES 1, 2, 3, and 4 and 

when the associated DG is required to be OPERABLE by LCO 3.8.2, "AC 

Sources - Shutdown." The LOVS supports safety systems associated 

with the ESFAS. In MODES 5 and 6, the four channels must be 

OPERABLE whenever the associated DG is required to be OPERABLE 

to ensure that the automatic start of the DG is available when needed. 

Actions allow maintenance (trip channel) bypass of individual channels. 

Plants are restricted to 48 hours in a trip channel bypass condition before 

either restoring the Function to four channel operation (two-out-of-four 

logic) or placing the channel in trip (one-out-of-three logic). At plants 

where adequate channel to channel independence has been 

demonstrated, specific exceptions have been approved by the NRC staff 

to permit one of the two-out-of-four channels to be bypassed for an 

extended period of time. 

Loss of LOVS Function could result in the delay of safety system initiation 

when required. This could lead to unacceptable consequences during 

accidents. During the loss of offsite power, which is an anticipated 

operational occurrence, the DG powers the motor driven auxiliary 

feedwater pumps. Failure of these pumps to start would leave only the 

one turbine driven pump as well as an increased potential for a loss of 

decay heat removal through the secondary system. 

Only Allowable Values are specified for each Function in the LCO. 

Nominal trip setpoints are specified in the plant specific setpoint 

calculations. The nominal setpoints are selected to ensure that the 

setpoint measured by CHANNEL FUNCTIONAL TESTS does not exceed 

the Allowable Value if the bistable is performing as required. Operation 

with a trip setpoint less conservative than the nominal trip setpoint, but 

within the Allowable Value, is acceptable, provided that operation and 

testing are consistent with the assumptions of the plant specific setpoint 

calculation. A channel is inoperable if its actual trip setpoint is not within 

its required Allowable Value. 

[ For this unit, the Bases for the Allowable Values and trip setpoints are as 

follows: ] 
DG - LOVS (Analog) 

B 3.3.6 

CEOG STS B 3.3.6-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY The DG - LOVS actuation Function is required in MODES 1, 2, 3, and 4 

because ESF Functions are designed to provide protection in these 

MODES. Actuation in MODE 5 or 6 is required whenever the required 

DG must be OPERABLE, so that it can perform its function on a loss of 

power or degraded power to the vital bus. 

ACTIONS A LOVS channel is inoperable when it does not satisfy the OPERABILITY 

criteria for the channel's Function. The most common cause of channel 

inoperability is outright failure or drift of the bistable or process module 

sufficient to exceed the tolerance allowed by the plant specific setpoint 

analysis. Typically, the drift is found to be small and results in a delay of 

actuation rather than a total loss of function. Determination of setpoint 

drift is generally made during the performance of a CHANNEL 

FUNCTIONAL TEST when the instrument is set up for adjustment to 

bring it within specification. If the actual trip setpoint is not within the 

Allowable Value, the channel is inoperable and the appropriate 

Conditions must be entered. 

In the event a channel's trip setpoint is found nonconservative with 

respect to the Allowable Value, or the channel is found inoperable, then 

all affected Functions provided by that channel must be declared 

inoperable and the LCO Condition entered. The required channels are 

specified on a per DG basis. 

When the number of inoperable channels in a trip Function exceeds those 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 should 

be entered immediately if applicable in the current MODE of operation. 

A Note has been added to the ACTIONS to clarify the application of 

Completion Time rules. The Conditions of this LCO may be entered 

independently for each Function. The Completion Time(s) of the 

inoperable channel(s)/train(s) of a Function will be tracked separately for 

each Function, starting from the time the Condition was entered for that 

Function. 

A.1, A.2.1, and A.2.2

Condition A applies if one channel is inoperable for one or more 

Functions per DG bus. 

If the channel cannot be restored to OPERABLE status, the affected 

channel should either be bypassed or tripped within 1 hour (Required 

Action A.1). 
DG - LOVS (Analog) 

B 3.3.6 

CEOG STS B 3.3.6-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Placing this channel in either Condition ensures that logic is in a known 

configuration. In trip, the LOVS Logic is one-out-of-three. In bypass, the 

LOVS Logic is two-out-of-three. The 1 hour Completion Time is sufficient 

to perform these Required Actions. 

Once Required Action A.1 has been complied with, Required Action A.2.1 

allows [48] hours to repair the inoperable channel for those plants that 

have not demonstrated sufficient channel to channel independence on 

this Function. If the channel cannot be restored to OPERABLE status, it 

must be tripped in accordance with Required Action A.2.2. The time 

allowed to repair or trip the channel is reasonable to repair the affected 

channel while ensuring that the risk involved in operating with the 

inoperable channel is acceptable. The [48] hour Completion Time is 

based upon operating experience, which has demonstrated that a random 

failure of a second channel is a rare event during any given [48] hour 

period. 

B.1, B.2.1, and B.2.2

Condition B applies if two channels are inoperable for one or more 

Functions per DG. 

If the channel cannot be restored to OPERABLE status within 1 hour, the 

Conditions and Required Actions for the associated DG made inoperable 

by DG - LOVS instrumentation are required to be entered. Alternatively, 

one affected channel is required to be bypassed and the other is tripped, 

in accordance with Required Action B.2.1. This places the Function in 

one-out-of-two logic. The 1 hour Completion Time is sufficient to perform 

the Required Actions. 

Once Required Action B.2.1 has been complied with, Required 

Action B.2.2 allows [48] hours to repair the bypassed or inoperable 

channel. 

After one channel is restored to OPERABLE status, the provisions of 

Condition A still apply to the remaining inoperable channel. Therefore, 

the channel that is still inoperable after completion of Required 

Action B.2.2 shall be placed in trip if more than [48] hours have elapsed 

since the initial channel failure. 
DG - LOVS (Analog) 

B 3.3.6 

CEOG STS B 3.3.6-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1

Condition C applies when more than two undervoltage or Degraded 

Voltage channels on a single bus are inoperable. 

Required Action C.1 requires all but two channels to be restored to 

OPERABLE status within 1 hour. With more than two channels 

inoperable, the logic is not capable of providing a DG - LOVS signal for 

valid Loss of Voltage or Degraded Voltage conditions. The 1 hour 

Completion Time is reasonable to evaluate and take action to correct the 

degraded condition in an orderly manner and takes into account the low 

probability of an event requiring LOVS occurring during this interval. 

D.1

Condition D applies if the Required Actions and associated Completion 

Times are not met. 

Required Action D.1 ensures that Required Actions for the affected DG 

inoperabilities are initiated. Depending upon plant MODE, the actions 

specified in LCO 3.8.1, "AC Sources - Operating," or LCO 3.8.2 are 

required immediately. 

SURVEILLANCE The following SRs apply to each DG - LOVS Function. 

REQUIREMENTS 

[ SR 3.3.6.1

Performance of the CHANNEL CHECK once every 12 hours ensures that 

a gross failure of instrumentation has not occurred. A CHANNEL CHECK 

is normally a comparison of the indicated output of the potential 

transformers that feed the LOVS undervoltage relays. It is based on the 

assumption that instrument channels monitoring the same parameter 

should read approximately the same value. Significant deviations 

between the two channels could be an indication of excessive drift in one 

of the channels or of something even more serious. CHANNEL CHECK 

will detect gross channel failure; thus, it is key to verifying that the 

instrumentation continues to operate properly between each CHANNEL 

CALIBRATION. 
DG - LOVS (Analog) 

B 3.3.6 

CEOG STS B 3.3.6-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Agreement criteria are determined by the plant staff, based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If the channels are within the criteria, it is an indication 

that the channels are OPERABLE. ]

[ The Frequency, about once every shift, is based upon operating 

experience that demonstrates channel failure is rare. Since the 

probability of two random failures in redundant channels in any 12 hour 

period is extremely low, the CHANNEL CHECK minimizes the chance of 

loss of protective function due to failure of redundant channels. The 

CHANNEL CHECK supplements less formal, but more frequent, checks 

of channel OPERABILITY during normal operational use of the displays 

associated with the LCO required channels. ]

SR 3.3.6.2

A CHANNEL FUNCTIONAL TEST is performed every [92] days to ensure 

that the entire channel will perform its intended function when needed. A 

successful test of the required contact(s) of a channel relay may be 

performed by the verification of the change of state of a single contact of 

the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL 

TEST of a relay. This is acceptable because all of the other required 

contacts of the relay are verified by other Technical Specifications and 

non-Technical Specifications tests at least once per refueling interval with 

applicable extensions. 

The Frequency of [92] days is based on plant operating experience with 

regard to channel OPERABILITY and drift, which demonstrates that 

failure of more than one channel of a given function in any [92] day 

Frequency is a rare event. Any setpoint adjustment shall be consistent 

with the assumptions of the current plant specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [6]. 
DG - LOVS (Analog) 

B 3.3.6 

CEOG STS B 3.3.6-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.6.3

SR 3.3.6.3 is the performance of a CHANNEL CALIBRATION every 

18 months. The CHANNEL CALIBRATION verifies the accuracy of each 

component within the instrument channel. This includes calibration of the 

undervoltage relays and demonstrates that the equipment falls within the 

specified operating characteristics defined by the manufacturer. 

The Surveillance verifies that the channel responds to a measured 

parameter within the necessary range and accuracy. CHANNEL 

CALIBRATION leaves the channel adjusted to account for instrument drift 

between successive calibrations to ensure that the channel remains 

operational between successive tests. CHANNEL CALIBRATIONS must 

be performed consistent with the plant specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [6]. 

The setpoints, as well as the response to a Loss of Voltage and 

Degraded Voltage test, shall include a single point verification that the trip 

occurs within the required delay time as shown in Reference 1. The 

Frequency is based upon the assumption of an [18] month calibration 

interval for the determination of the magnitude of equipment drift in the 

setpoint analysis. 

REFERENCES 1. FSAR, Section [8.3]. 

 2. FSAR, Chapter [15]. 

 3. "Plant Protection System Selection of Trip Setpoint Values." 

 4. IEEE Standard 279-1971. 

 5. 10 CFR 50, Appendix A, GDC 21. 

 6. [ ] 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.6 Engineered Safety Features Actuation System (ESFAS) Logic and Manual Trip (Digital) 

BASES 

BACKGROUND The ESFAS initiates necessary safety systems, based upon the values of 

selected unit parameters, to protect against violating core design limits 

and the Reactor Coolant System (RCS) pressure boundary during 

anticipated operational occurrences (AOOs) and ensures acceptable 

consequences during accidents. 

The ESFAS contains devices and circuitry that generate the following 

signals when monitored variables reach levels that are indicative of 

conditions requiring protective action: 

1. Safety Injection Actuation Signal (SIAS), 

2. Containment Isolation Actuation Signal (CIAS), 

3. Containment Cooling Actuation Signal (CCAS), 

4. Recirculation Actuation Signal (RAS), 

5. Containment Spray Actuation Signal (CSAS), 

6. Main Steam Isolation Signal (MSIS), 

7. Emergency Feedwater Actuation Signal SG #1 (EFAS-1), and 

8. Emergency Feedwater Actuation Signal SG #2 (EFAS-2). 

Equipment actuated by each of the above signals is identified in the 

FSAR (Ref. 1). 

Each of the above ESFAS instrumentation systems is segmented into 

three interconnected modules. These modules are: 

• Measurement channels, 

• Bistable trip units, and 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

• ESFAS Logic: 

 - Matrix Logic, 

- Initiation Logic (trip paths), and 

 - Actuation Logic. 

This LCO addresses ESFAS Logic. Bistables and measurement 

channels are addressed in LCO 3.3.5, "Engineered Safety Features 

Actuation System (ESFAS) Instrumentation." 

The role of the measurement channels and bistables is described in 

LCO 3.3.5. The role of the ESFAS Logic is described below. 

ESFAS Logic

The ESFAS Logic, consisting of Matrix, Initiation and Actuation Logic, 

employs a scheme that provides an ESF actuation of both trains when 

bistables in any two of the four channels sense the same input parameter 

trip. This is called a two-out-of-four trip logic. 

Bistable relay contact outputs from the four channels are configured into 

six Matrix Logics. Each Matrix Logic checks for a coincident trip in the 

same parameter in two bistable channels. The matrices are designated 

the AB, AC, AD, BC, BD, and CD matrices, to reflect the bistable 

channels being monitored. Each Matrix Logic contains four normally 

energized matrix relays. When a coincidence is detected in the two 

channels being monitored by the Matrix Logic, all four matrix relays deenergize. 

The matrix relay contacts are arranged into trip paths, with one relay 

contact from each matrix relay in each of the four trip paths. Each trip 

path controls two initiation relays. Each of the two initiation relays in each 

trip path controls contacts in the Actuation Logic for one train of ESF. 

Each of the two channels of Actuation Logic, mounted in the Auxiliary 

Relay Cabinets (ARCs), is responsible for actuating one train of ESF 

equipment. Each ESF Function has separate Actuation Logic in each 

ARC. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The contacts from the Initiation Logic are configured in a selective twoout-of-four logic in the Actuation Logic, similar to the configuration 

employed by the RPS in the RTCBs. This logic controls ARC mounted 

subgroup relays, which are normally energized. Contacts from these 

relays, when de-energized, actuate specific ESF equipment. 

When a coincidence occurs in two ESFAS channels, all four matrix relays 

in the affected matrix will de-energize. This, in turn, will de-energize all 

eight initiation relays, four used in each Actuation Logic. 

Matrix Logic refers to the matrix power supplies, trip channel bypass 

contacts, and interconnecting matrix wiring between bistable relay cards, 

up to but not including the matrix relays. Matrix contacts on the bistable 

relay cards are excluded from the Matrix Logic definition, since they are 

addressed as part of the measurement channel. 

Initiation Logic consists of the trip path power source, matrix relays and 

their associated contacts, all interconnecting wiring, and the initiation 

relays. 

Actuation Logic consists of all circuitry housed within the ARCs used to 

actuate the ESF Function, excluding the subgroup relays, and 

interconnecting wiring to the initiation relay contacts mounted in the PPS 

cabinet. 

The subgroup relays are actuated by the ESFAS Logic. Each ESFAS 

Function typically employs several subgroup relays, with each subgroup 

relay responsible for actuating one or more components in the ESFAS 

Function. Subgroup relays and their contacts are considered part of the 

actuated equipment and are addressed under the applicable LCO for this 

equipment. 

It is possible to change the two-out-of-four ESFAS Logic to two-out-ofthree logic for a given input parameter in one channel at a time by trip 

channel bypassing select portions of the Matrix Logic. Trip channel 

bypassing a bistable effectively shorts the bistable relay contacts in the 

three matrices associated with that channel. Thus, the bistables will 

function normally, producing normal trip indication and annunciation, but 

ESFAS actuation will not occur since the bypassed channel is effectively 

removed from the coincidence logic. Trip channel bypassing can be 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-4 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

simultaneously performed on any number of parameters in any number of 

channels, providing each parameter is bypassed in only one channel at a 

time. An interlock prevents simultaneous trip channel bypassing of the 

same parameter in more than one channel. Trip channel bypassing is 

normally employed during maintenance or testing. Trip channel 

bypassing is addressed in LCO 3.3.5. 

Manual ESFAS initiation capability is provided to permit the operator to 

manually actuate an ESF System when necessary. 

Two sets of two push buttons (located in the control room) for each ESF 

Function are provided, and each set actuates both trains. Each Manual 

Trip push button opens one trip path, de-energizing one set of two 

initiation relays, one affecting each train of ESF. Initiation relay contacts 

are arranged in a selective two-out-of-four configuration in the Actuation 

Logic. By arranging the push buttons in two sets of two, such that both 

push buttons in a set must be depressed, it is possible to ensure that 

Manual Trip will not be prevented in the event of a single random failure. 

Each set of two push buttons is designated a single channel in this LCO. 

APPLICABLE Each of the analyzed accidents can be detected by one or more ESFAS 

SAFETY Functions. One of the ESFAS Functions is the primary actuation signal 

ANALYSES for that accident. An ESFAS Function may be the primary actuation 

signal for more than one type of accident. An ESFAS Function may also 

be a secondary, or backup, actuation signal for one or more other 

accidents. 

ESFAS Functions are as follows: 

1. Safety Injection Actuation Signal

SIAS ensures acceptable consequences during large break loss of 

coolant accidents (LOCAs), small break LOCAs, control element 

assembly ejection accidents, and main steam line breaks (MSLBs) 

inside containment. To provide the required protection, either a high 

containment pressure or a low pressurizer pressure signal will initiate 

SIAS. SIAS initiates the Emergency Core Cooling Systems (ECCS) 

and performs several other Functions, such as initiating a 

containment cooling actuation, initiating control room isolation, and 

starting the diesel generators. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

2. Containment Isolation Actuation Signal

CIAS ensures acceptable mitigating actions during large and small 

break LOCAs and during MSLBs or feedwater line breaks (FWLBs) 

either inside or outside containment. CIAS is initiated by low 

pressurizer pressure or high containment pressure. 

3. Containment Cooling Actuation Signal

CCAS mitigates containment overpressurization when required by 

either a manual CCAS actuation or an automatic SIAS Function. 

This Function is not employed by all plants. 

4. Recirculation Actuation Signal

At the end of the injection phase of a LOCA, the refueling water 

storage tank (RWST) will be nearly empty. Continued cooling must 

be provided by the ECCS to remove decay heat. The source of 

water for the ECCS pumps is automatically switched to the 

containment recirculation sump. Switchover from RWST to 

containment sump must occur before the RWST empties to prevent 

damage to the ECCS pumps and a loss of core cooling capability. 

For similar reasons, switchover must not occur before there is 

sufficient water in the containment sump to support pump suction. 

Furthermore, early switchover must not occur to ensure sufficient 

borated water is injected from the RWST to ensure the reactor 

remains shut down in the recirculation mode. An RWST Level - Low 

signal initiates the RAS. 

5. Containment Spray Actuation Signal

CSAS actuates containment spray, preventing containment 

overpressurization during large break LOCAs, small break LOCAs, 

and MSLBs or FWLBs inside containment. CSAS is initiated by high 

high containment pressure and an SIAS. This configuration reduces 

the likelihood of inadvertent containment spray. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-6 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

6. Main Steam Isolation Signal

MSIS ensures acceptable consequences during an MSLB or FWLB 

(between the steam generator and the main feedwater check valve) 

either inside or outside containment. MSIS isolates both steam 

generators if either generator indicates a low pressure condition or if 

a high containment pressure condition exists. This prevents an 

excessive rate of heat extraction and subsequent cooldown of the 

RCS during these events. 

7, 8. Emergency Feedwater Actuation Signal

EFAS consists of two steam generator (SG) specific signals (EFAS-1 

and EFAS-2). EFAS-1 initiates emergency feed to SG #1, and 

EFAS-2 initiates emergency feed to SG #2. 

EFAS maintains a steam generator heat sink during a steam 

generator tube rupture event and an MSLB or FWLB event either 

inside or outside containment. 

Low steam generator water level initiates emergency feed to the 

affected steam generator, providing the generator is not identified (by 

the circuitry) as faulted (an MSLB or FWLB). 

EFAS logic includes steam generator specific inputs from the Steam 

Generator Pressure - Low bistable comparator (also used in MSIS) 

and the SG Pressure Difference - High (SG #1 > SG #2 

or SG #2 > SG #1, bistable comparators) to determine if a rupture in 

either generator has occurred. 

Rupture is assumed if the affected generator has a low pressure 

condition, unless that generator is significantly higher in pressure 

than the other generator. 

This latter feature allows feeding the intact steam generator even if 

both are below the MSIS setpoint, while preventing the ruptured 

generator from being fed. Not feeding a ruptured generator prevents 

containment overpressurization during the analyzed events. 

The ESFAS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-7 Rev. 3.0, 03/31/04 

BASES 

LCO The LCO requires all channel components necessary to provide an 

ESFAS actuation to be OPERABLE. 

The requirements for each Function are listed below. The reasons for the 

applicable MODES for each Function are addressed under 

APPLICABILITY. 

1. Safety Injection Actuation Signal

Automatic SIAS is required to initiate CCAS and CSAS. Automatic 

SIAS occurs in Pressurizer Pressure - Low or Containment Pressure 

- High and is explained in Bases 3.3.5. 

a. Manual Trip

This LCO requires two channels of SIAS Manual Trip to be 

OPERABLE in MODES 1, 2, 3, and 4. 

b. Matrix Logic

This LCO requires six channels of SIAS Matrix Logic to be 

OPERABLE in MODES 1, 2, and 3. 

c. Initiation Logic

This LCO requires four channels of SIAS Initiation Logic to be 

OPERABLE in MODES 1, 2, 3, and 4. 

d. Actuation Logic

This LCO requires two channels of SIAS Actuation Logic to be 

OPERABLE in MODES 1, 2, 3, and 4. 

2. Containment Isolation Actuation Signal

For plants where the SIAS and CIAS are actuated on Pressurizer 

Pressure - Low or Containment Pressure - High, the SIAS and CIAS 

share the same input channels, bistables, and matrices and matrix 

relays. The remainder of the initiation channels, the manual 

channels, and the Actuation Logic are separate. Since their 

applicability is also the same, they have identical actions. 

a. Manual Trip

This LCO requires two channels of CIAS Manual Trip to be 

OPERABLE in MODES 1, 2, 3, and 4. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-8 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

b. Matrix Logic

This LCO requires six channels of CIAS Matrix Logic to be 

OPERABLE in MODES 1, 2, and 3. 

c. Initiation Logic

This LCO requires four channels of CIAS Initiation Logic to be 

OPERABLE in MODES 1, 2, 3, and 4. 

d. Actuation Logic

This LCO requires two channels of CIAS Actuation Logic to be 

OPERABLE in MODES 1, 2, 3, and 4. 

3. Containment Cooling Actuation Signal

For plants employing a separate CCAS signal, the CCAS Function 

can be automatically actuated on an SIAS. It can also be manually 

actuated using two channels of CCAS push buttons, configured 

similarly to all other ESFAS Manual Trips. CCAS therefore shares 

the SIAS sensor channels, bistables, coincidence matrices, and 

matrix relays. It has separate manual channels and Actuation Logic. 

a. Manual Trip

This LCO requires two channels of CCAS Manual Trip to be 

OPERABLE in MODES 1, 2, 3, and 4. 

b. Initiation Logic

This LCO requires four channels of CCAS Initiation Logic to be 

OPERABLE in MODES 1, 2, 3, and 4. 

c. Actuation Logic

This LCO requires two channels of CCAS Actuation Logic to be 

OPERABLE in MODES 1, 2, 3, and 4. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-9 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

4. Recirculation Actuation Signal

a. Manual Trip

This LCO requires two channels of RAS Manual Trip to be 

OPERABLE in MODES 1, 2, 3, and 4. 

b. Matrix Logic

This LCO requires six channels of RAS Matrix Logic to be 

OPERABLE in MODES 1, 2, and 3. 

c. Initiation Logic

This LCO requires four channels of RAS Initiation Logic to be 

OPERABLE in MODES 1, 2, 3, and 4. 

d. Actuation Logic

This LCO requires two channels of RAS Actuation Logic to be 

OPERABLE in MODES 1, 2, 3, and 4. 

5. Containment Spray Actuation Signal

CSAS is initiated either manually or automatically. For an automatic 

actuation it is necessary to have a Containment Pressure - High High 

signal, coincident with an SIAS. The SIAS requirement should 

always be satisfied on a legitimate CSAS, since the Containment 

Pressure - High signal used in the SIAS will initiate before the 

Containment Pressure - High High input signal to CSAS. This 

ensures that a CSAS will not initiate unless required. 

a. Manual Trip

This LCO requires two channels of CSAS Manual Trip to be 

OPERABLE in MODES 1, 2, and 3. 

b. Automatic SIAS (Function 1)

This LCO requires four channels of Automatic SIAS input to 

CSAS to be OPERABLE in MODES 1, 2, and 3. 

The Automatic SIAS occurs on Pressurizer Pressure - Low or 

Containment Pressure - High and is explained above. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-10 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

c. Matrix Logic

This LCO requires six channels of CSAS Matrix Logic to be 

OPERABLE in MODES 1, 2, and 3. 

d. Initiation Logic

This LCO requires four channels of CSAS Initiation Logic to be 

OPERABLE in MODES 1, 2, and 3. 

e. Actuation Logic

This LCO requires two channels of CSAS Actuation Logic to be 

OPERABLE in MODES 1, 2, and 3. 

6. Main Steam Isolation Signal

a. Manual Trip

This LCO requires two channels of MSIS Manual Trip to be 

OPERABLE in MODES 1, 2, and 3. 

b. Matrix Logic

This LCO requires six channels of MSIS Matrix Logic to be 

OPERABLE in MODES 1, 2, and 3. 

c. Initiation Logic

This LCO requires four channels of MSIS Initiation Logic to be 

OPERABLE in MODES 1, 2, and 3. 

d. Actuation Logic

This LCO requires two channels of MSIS Actuation Logic to be 

OPERABLE in MODES 1, 2, and 3. 

7. Emergency Feedwater Actuation Signal SG #1 (EFAS-1)

EFAS-1 is initiated either by a low steam generator level coincident 

with no low pressure trip present on SG #1 or by a low steam 

generator level coincident with a differential pressure between the 

two generators with the higher pressure in SG #1. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-11 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The steam generator secondary differential pressure is used, in 

conjunction with a Steam Generator Pressure - Low input from each 

steam generator, as an input of the EFAS logic where it is used to 

determine if a generator is intact. The EFAS logic inhibits feeding a 

steam generator if a Steam Generator Pressure - Low condition 

exists in that generator and the pressure in that steam generator is 

less than the Steam Generator Pressure Difference (SGPD) - High 

setpoint pressure. 

The SGPD logic thus enables the feeding of a steam generator in the 

event that a plant cooldown causes a Steam Generator Pressure - 

Low condition, while inhibiting feeding the other (lower pressure) 

steam generator, which may be ruptured. The setpoint is high 

enough to allow for small pressure differences and normal 

instrumentation errors between the steam generator channels during 

normal operation. 

a. Manual Trip

This LCO requires two channels of Manual Trip to be 

OPERABLE in MODES 1, 2, and 3. 

b. Matrix Logic

This LCO requires six channels of Matrix Logic to be 

OPERABLE in MODES 1, 2, and 3. 

c. Initiation Logic

This LCO requires four channels of Initiation Logic to be 

OPERABLE in MODES 1, 2, and 3. 

d. Actuation Logic

This LCO requires one channel of Actuation Logic to be 

OPERABLE in MODES 1, 2, and 3. 

8. Emergency Feedwater Actuation Signal SG #2 (EFAS-2)

EFAS-2 is initiated either by a low steam generator level coincident 

with no low pressure trip present on SG #2 or by a low steam 

generator level coincident with a differential pressure between the 

two generators with the higher pressure in SG #2. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-12 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The steam generator secondary differential pressure is used, in 

conjunction with a Steam Generator Pressure - Low input from each 

steam generator, as an input of the EFAS Logic where it is used to 

determine if a generator is intact. The EFAS Logic inhibits feeding a 

steam generator if a Steam Generator Pressure - Low condition 

exists in that generator and the pressure in that steam generator is 

less than the SGPD - High setpoint pressure. 

The SGPD logic thus enables the feeding of a steam generator in the 

event that a plant cooldown causes a Steam Generator Pressure - 

Low condition, while inhibiting feeding the other (lower pressure) 

steam generator, which may be ruptured. The setpoint is high 

enough to allow for small pressure differences and normal 

instrumentation errors between the steam generator channels during 

normal operation. 

a. Manual Trip

This LCO requires two channels of Manual Trip to be 

OPERABLE in MODES 1, 2, and 3. 

b. Matrix Logic

This LCO requires six channels of Matrix Logic to be 

OPERABLE in MODES 1, 2, and 3. 

c. Initiation Logic

This LCO requires four channels of Initiation Logic to be 

OPERABLE in MODES 1, 2, and 3. 

d. Actuation Logic

This LCO requires one channel of Actuation Logic to be 

OPERABLE in MODES 1, 2, and 3. 

APPLICABILITY In MODES 1, 2 and 3, there is sufficient energy in the primary and 

secondary systems to warrant automatic ESF System responses to: 

• Close the main steam isolation valves to preclude a positive reactivity 

addition, 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-13 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY (continued) 

• Actuate emergency feedwater to preclude the loss of the steam 

generators as a heat sink (in the event the normal feedwater system 

is not available), 

• Actuate ESF systems to prevent or limit the release of fission product 

radioactivity to the environment by isolating containment and limiting 

the containment pressure from exceeding the containment design 

pressure during a design basis LOCA or MSLB, and 

• Actuate ESF systems to ensure sufficient borated inventory to permit 

adequate core cooling and reactivity control during a design basis 

LOCA or MSLB accident. 

In MODES 4, 5, and 6, automatic actuation of these Functions is not 

required because adequate time is available to evaluate plant conditions 

and respond by manually operating the ESF components if required. 

ESFAS Manual Trip capability is required in MODE 4 for SIAS, CIAS, 

CCAS, and RAS even though automatic actuation is not required. 

Because of the large number of components actuated by these 

Functions, ESFAS actuation is simplified by the use of the Manual Trip 

push buttons. 

CSAS, MSIS, and EFAS have relatively few components, which can be 

actuated individually if required in MODE 4, and the systems may be 

disabled or reconfigured, making system level Manual Trip impossible 

and unnecessary. 

The ESFAS logic must be OPERABLE in the same MODES as the 

automatic and Manual Trip. In MODE 4, only the portion of the ESFAS 

logic responsible for the required Manual Trip must be OPERABLE. 

In MODES 5 and 6, the systems initiated by ESFAS are either 

reconfigured or disabled for shutdown cooling operation. Accidents in 

these MODES are slow to develop and would be mitigated by manual 

operation of individual components. 

ACTIONS When the number of inoperable channels in a trip Function exceeds those 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 should 

be entered immediately, if applicable in the current MODE of operation. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-14 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

A Note has been added to the ACTIONS to clarify the application of the 

Completion Time rules. The Conditions of this Specification may be 

entered independently for each Function. The Completion Time for the 

inoperable channel of a Function will be tracked separately for each 

Function, starting from the time the Condition was entered for that 

Function. 

A.1

Condition A applies if one Matrix Logic channel is inoperable. Since 

matrix power supplies in a given matrix (e.g., AB, BC, etc.) are common 

to all ESFAS Functions, a single power supply failure may affect more 

than one matrix. 

Failures of individual bistables and their relays are considered 

measurement channel failures. This section describes failures of the 

Matrix Logic not addressed in the above, such as the failure of matrix 

relay power supplies, or the failure of the trip channel bypass contact in 

the bypass condition. Loss of a single vital bus will de-energize one of 

the two power supplies in each of three matrices. This will result in two 

initiation circuits de-energizing, reducing the ESFAS Actuation Logic to a 

one-out-of-two logic in both trains. 

This Condition has been modified by a Note stating that for the purposes 

of this LCO, de-energizing up to three matrix power supplies due to a 

single failure, such as loss of a vital instrument bus, is to be treated as a 

single matrix channel failure, providing the affected matrix relays deenergize as designed. Although each of the six matrices within an 

ESFAS Function uses separate power supplies, the matrices for the 

different ESFAS Functions share power supplies. Thus, failure of a 

matrix power supply may force entry into the Condition specified for each 

of the affected ESFAS Functions. 

The channel must be restored to OPERABLE status within 48 hours. 

This provides the operator with time to take appropriate actions and still 

ensures that any risk involved in operating with a failed channel is 

acceptable. Operating experience has demonstrated that the probability 

of a random failure of a second Matrix Logic channel is low during any 

given 48 hour period. If the channel cannot be restored to OPERABLE 

status with 48 hours, Condition E is entered. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-15 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1

Condition B applies to one Manual Trip or Initiation Logic channel 

inoperable. 

The channel must be restored to OPERABLE status within 48 hours. 

Operating experience has demonstrated that the probability of a random 

failure in a second channel is low during any given 48 hour period. 

Failure of a single Initiation Logic channel may open one contact affecting 

both Actuation Logic channels. For the purposes of this Specification, the 

Actuation Logic is not inoperable. This prevents the need to enter 

LCO 3.0.3 in the event of an Initiation Logic channel failure. The Actions 

differ from those involving one RPS manual channel inoperable, because 

in the case of the RPS, opening RTCBs can be easily performed and 

verified. Opening an initiation relay contact is more difficult to verify, and 

subsequent shorting of the contact is always possible. 

C.1 and C.2

Condition C applies to the failure of both Initiation Logic channels 

affecting the same trip leg. 

In this case, the Actuation Logic channels are not inoperable, since they 

are in one-out-of-two logic and capable of performing as required. This 

obviates the need to enter LCO 3.0.3 in the event of a matrix or vital bus 

power failure. 

Both Initiation Logic channels in the same trip leg will de-energize if a 

matrix power supply or vital instrument bus is lost. This will open the 

Actuation Logic contacts, satisfying the Required Action to open at least 

one set of contacts in the affected trip leg. Indefinite operation in this 

condition is prohibited because of the difficulty of ensuring the contacts 

remain open under all conditions. Thus, the channel must be restored to 

OPERABLE status within 48 hours. This provides the operator with time 

to take appropriate actions and still ensures that any risk involved in 

operating with a failed channel is acceptable. Operating experience has 

demonstrated that the probability of a random failure of a second channel 

is low during any given 48 hour period. If the channel cannot be restored 

to OPERABLE status with 48 hours, Condition E is entered. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-16 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Of greater concern is the failure of the initiation circuit in a nontrip 

condition, e.g., due to two initiation relay failures. With one failed, there is 

still the redundant contact in the trip leg of each Actuation Logic. With 

both failed in a nontrip condition, the ESFAS Function is lost in the 

affected train. To prevent this, immediate opening of at least one contact 

in the affected trip leg is required. If the required contact has not opened, 

as indicated by annunciation or trip leg current lamps, Manual Trip of the 

affected trip leg contacts may be attempted. Caution must be exercised, 

since depressing the wrong ESFAS push buttons may result in an ESFAS 

actuation. 

D.1

Condition D applies to Actuation Logic. 

With one Actuation Logic channel inoperable, automatic actuation of one 

train of ESF may be inhibited. The remaining train provides adequate 

protection in the event of Design Basis Accidents, but the single failure 

criterion may be violated. For this reason operation in this condition is 

restricted. 

The channel must be restored to OPERABLE status within 48 hours. 

Operating experience has demonstrated that the probability of a random 

failure in the Actuation Logic of the second train is low during a given 

48 hour period. 

Failure of a single Initiation Logic channel, matrix channel power supply, 

or vital instrument bus may open one or both contacts in the same trip leg 

in both Actuation Logic channels. For the purposes of this Specification, 

the Actuation Logic is not inoperable. This obviates the need to enter 

LCO 3.0.3 in the event of a vital bus, matrix, or initiation channel failure. 

Required Action D.1 is modified by a Note to indicate that one channel of 

Actuation Logic may be bypassed for up to 1 hour for Surveillance, 

provided the other channel is OPERABLE. 

This allows performance of a PPS CHANNEL FUNCTIONAL TEST on an 

OPERABLE ESFAS train without generating an ESFAS actuation in the 

inoperable train. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-17 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

E.1 and E.2

If two associated Actuation Logic channels are inoperable, or if the 

Required Actions and associated Completion Times of Conditions for 

CSAS, MSIS, or EFAS cannot be met, the plant must be brought to a 

MODE in which the LCO does not apply. To achieve this status, the plant 

must be brought to at least MODE 3 within 6 hours and to MODE 4 within 

[12] hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

F.1 and F.2

If two associated Actuation Logic channels are inoperable, or if the 

Required Actions and associated Completion Times for SIAS, CIAS, 

RAS, or CCAS are not met, the plant must be brought to a MODE in 

which the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 5 within 

36 hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE SR 3.3.6.1

REQUIREMENTS 

A CHANNEL FUNCTIONAL TEST is performed every [92] days to ensure 

the entire channel will perform its intended function when needed. A 

successful test of the required contact(s) of a channel relay may be 

performed by the verification of the change of state of a single contact of 

the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL 

TEST of a relay. This is acceptable because all of the other required 

contacts of the relay are verified by other Technical Specifications and 

non-Technical Specifications tests at least once per refueling interval with 

applicable extensions. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-18 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The CHANNEL FUNCTIONAL TEST is part of an overlapping test 

sequence similar to that employed in the RPS. This sequence, consisting 

of SR 3.3.5.2, SR 3.3.6.1, and SR 3.3.6.2, tests the entire ESFAS from 

the bistable input through the actuation of the individual subgroup relays. 

These overlapping tests are described in Reference 1. SR 3.3.5.2 and 

SR 3.3.6.1 are normally performed together and in conjunction with 

ESFAS testing. SR 3.3.6.2 verifies that the subgroup relays are capable 

of actuating their respective ESF components when de-energized. 

These tests verify that the ESFAS is capable of performing its intended 

function, from bistable input through the actuated components. 

SR 3.3.5.2 is addressed in LCO 3.3.5. SR 3.3.6.1 includes Matrix Logic 

tests and trip path (Initiation Logic) tests. 

Matrix Logic Tests

These tests are performed one matrix at a time. They verify that a 

coincidence in the two input channels for each function removes power to 

the matrix relays. During testing, power is applied to the matrix relay test 

coils, preventing the matrix relay contacts from assuming their energized 

state. The Matrix Logic tests will detect any short circuits around the 

bistable contacts in the coincidence logic, such as may be caused by 

faulty bistable relay or trip channel bypass contacts. 

Trip Path (Initiation Logic) Tests

These tests are similar to the Matrix Logic tests, except that test power is 

withheld from one matrix relay at a time, allowing the initiation circuit to 

de-energize, opening one contact in each Actuation Logic channel. 

The initiation circuit lockout relay must be reset (except for EFAS, which 

lacks initiation circuit lockout relays) prior to testing the other three 

initiation circuits, or an ESFAS actuation may result. 

Automatic Actuation Logic operation is verified during Initiation Logic 

testing by verifying that current is interrupted in each trip leg in the 

selective two-out-of-four actuation circuit logic whenever the initiation 

relay is de-energized. A Note is added to indicate that testing of 

Actuation Logic shall include verification of the proper operation of each 

initiation relay. 

The Frequency of [92] days is based on the reliability analysis presented 

in topical report CEN-327, "RPS/ESFAS Extended Test Interval 

Evaluation" (Ref. 2). 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-19 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.6.2

Individual ESFAS subgroup relays must also be tested, one at a time, to 

verify the individual ESFAS components will actuate when required. 

Proper operation of the individual subgroup relays is verified by deenergizing these relays one at a time using an ARC mounted test circuit. 

Proper operation of each component actuated by the individual relays is 

thus verified without the need to actuate the entire ESFAS function. 

The 184 day Frequency is based on operating experience and ensures 

individual relay problems can be detected within this time frame. 

Considering the large number of similar relays in the ARC, and the 

similarity in their use, a large test sample can be assembled to verify the 

validity of this Frequency. The actual justification is based on CEN-403, 

"Relaxation of Surveillance Test Interval for ESFAS Subgroup Relay 

Testing" (Ref. 3). 

Some components cannot be tested at power since their actuation might 

lead to plant trip or equipment damage. Reference 1 lists those relays 

exempt from testing at power, with an explanation of the reason for each 

exception. Relays not tested at power must be tested in accordance with 

the Note to this SR. 

SR 3.3.6.3

A CHANNEL FUNCTIONAL TEST is performed on the manual ESFAS 

actuation circuitry, de-energizing relays and providing manual actuation of 

the function. A successful test of the required contact(s) of a channel 

relay may be performed by the verification of the change of state of a 

single contact of the relay. This clarifies what is an acceptable CHANNEL 

FUNCTIONAL TEST of a relay. This is acceptable because all of the 

other required contacts of the relay are verified by other Technical 

Specifications and non-Technical Specifications tests at least once per 

refueling interval with applicable extensions. 

This test verifies that the trip push buttons are capable of opening 

contacts in the Actuation Logic as designed. 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. 

Operating experience has shown these components usually pass the 

Surveillance when performed at a Frequency of once every [18] months. 
ESFAS Logic and Manual Trip (Digital) 

B 3.3.6 

CEOG STS B 3.3.6-20 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Section [7.3]. 

 2. CEN-327, May 1986, including Supplement 1, March 1989. 

 3. CEN-403. 
CPIS (Analog) 

B 3.3.7 

CEOG STS B 3.3.7-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.7 Containment Purge Isolation Signal (CPIS) (Analog) 

BASES 

BACKGROUND This LCO encompasses CPIS actuation, which is a plant specific 

instrumentation system that performs an actuation Function required for 

plant protection but is not otherwise included in LCO 3.3.5, "Engineered 

Safety Features Actuation System (ESFAS) Logic and Manual Trip," or 

LCO 3.3.6, "Diesel Generator (DG) - Loss of Voltage Start (LOVS)." This 

is a non-Nuclear Steam Supply System ESFAS Function that, because of 

differences in purpose, design, and operating requirements, is not 

included in LCOs 3.3.5 and 3.3.6. Details of this LCO are for illustration 

only. Individual plants shall include those Functions and LCO 

requirements applicable to them. 

The CPIS provides protection from radioactive contamination in the 

containment in the event an irradiated fuel assembly should be severely 

damaged during handling. 

The CPIS will detect any abnormal amounts of radioactive material in the 

containment and will initiate purge valve closure to limit the release of 

radioactivity to the environment. The containment purge supply and 

exhaust valves are closed on a CPIS when a high radiation level in 

containment is detected. 

The CPIS includes two independent, redundant actuation subsystems. 

Where two isolation control valves are provided for a single containment 

penetration, each valve is controlled by a separate actuation subsystem. 

Where one valve is available, a single actuation subsystem initiates valve 

closure. One train also isolates the containment air exhaust fan, whereas 

the other train actuates the containment air supply fan. A list of actuated 

valves and an additional description of the CPIS are included in 

Reference 1. Both trains of CPIS are actuated on a two-out-of-four 

coincidence from the same four containment radiation sensor 

subsystems. Containment purge isolation also occurs on a Containment 

Isolation Actuation Signal (CIAS). The CIAS is addressed by LCO 3.3.4, 

"Engineered Safety Features Actuation System (ESFAS) 

Instrumentation." 
CPIS (Analog) 

B 3.3.7 

CEOG STS B 3.3.7-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Trip Setpoints and Allowable Values

Trip setpoints used in the bistables are based on the analytical limits 

stated in Reference 2. The selection of these trip setpoints is such that 

adequate protection is provided when all sensor and processing time 

delays are taken into account. To allow for calibration tolerances, 

instrumentation uncertainties, and instrument drift, Allowable Values 

specified in SR 3.3.7.2 are conservatively adjusted with respect to the 

analytical limits. A detailed description of the methodology used to 

calculate the trip setpoints, including their explicit uncertainties, is 

provided in "Plant Protection System Selection of Trip Setpoint Values" 

(Ref. 3). The actual nominal trip setpoint entered into the bistable is 

normally still more conservative than that specified by the Allowable 

Value to account for changes in random measurement errors detectable 

by a CHANNEL FUNCTIONAL TEST. One example of such a change in 

measurement error is drift during the surveillance interval. If the 

measured setpoint does not exceed the Allowable Value, the bistable is 

considered OPERABLE. 

Setpoints in accordance with the Allowable Value will ensure that Safety 

Limits are not violated during anticipated operational occurrences (AOOs) 

and the consequences of Design Basis Accidents will be acceptable, 

providing the plant is operated from within the LCOs at the onset of the 

AOO or accident and the equipment functions as designed. 

APPLICABLE The CPIS satisfies the requirements of Criterion 3 of 

SAFETY 10 CFR 50.36(c)(2)(ii). 

ANALYSES 

LCO Only the Allowable Values are specified for each trip Function in the LCO. 

Operation with a trip setpoint less conservative than the nominal trip 

setpoint, but within its Allowable Value, is acceptable, provided that the 

difference between the nominal trip setpoint and the Allowable Value is 

equal to or greater than the drift allowance assumed for each trip in the 

transient and accident analyses. 

Each Allowable Value specified is more conservative than the analytical 

limit assumed in the transient and accident analysis in order to account 

for instrument uncertainties appropriate to the trip Function. These 

uncertainties are defined in Reference 3. A channel is inoperable if its 

actual trip setpoint is not within its required Allowable Value. 
CPIS (Analog) 

B 3.3.7 

CEOG STS B 3.3.7-3 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The Bases for the LCO on the CPIS are discussed below for each 

Function: 

a. Manual Trip

The LCO on Manual Trip backs up the automatic trips and ensures 

operators have the capability to rapidly initiate the CPIS Function if 

any parameter is trending toward its setpoint. At least one channel 

must be OPERABLE to be consistent with the requirements of 

LCO 3.9.3, "Containment Penetrations." 

b. Containment Radiation - High

The LCO on the radiation channels requires that all four be 

OPERABLE. 

[ For this unit, the basis for the Containment Radiation - High setpoint 

is as follows: ] 

c. Actuation Logic

One train of Actuation Logic must be OPERABLE to be consistent 

with the requirements of LCO 3.9.3. If one fails, it must be restored 

to OPERABLE status. 

APPLICABILITY In MODE 5 or 6, the CPIS isolation of containment purge valves is not 

required to be OPERABLE. However, during movement of [recently] 

irradiated fuel [(i.e., fuel that has occupied part of a critical reactor core 

within the previous [X] days)], there is the possibility of a fuel handling 

accident requiring the CPIS on high radiation in containment. 

Accordingly, the CPIS must be OPERABLE during movement of [recently] 

irradiated fuel in containment. 

In MODES 1, 2, 3, and 4, the containment purge valves are sealed 

closed. 
CPIS (Analog) 

B 3.3.7 

CEOG STS B 3.3.7-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A CPIS channel is inoperable when it does not satisfy the OPERABILITY 

criteria for the channel's Function. The most common cause of channel 

inoperability is outright failure or drift of the bistable or process module 

sufficient to exceed the tolerance allowed by the plant specific setpoint 

analysis. Typically, the drift is not large and would result in a delay of 

actuation rather than a total loss of function. This determination is 

generally made during the performance of a CHANNEL FUNCTIONAL 

TEST when the process instrument is set up for adjustment to bring it 

within specification. If the actual trip setpoint is not within the Allowable 

Value in SR 3.3.7.2, the channel is inoperable and the appropriate 

Conditions must be entered. 

In the event a channel's trip setpoint is found nonconservative with 

respect to the Allowable Value, or the sensor, instrument loop, signal 

processing electronics, or bistable is found inoperable, then all affected 

Functions provided by that channel should be declared inoperable and 

the LCO Condition entered for the particular protective function affected. 

When the number of inoperable channels in a trip Function exceeds those 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 should 

be immediately entered if applicable in the current MODE of operation. 

A.1 and A.2

Condition A applies to the failure of one Containment Radiation - High 

CPIS channel. The Required Action is to place the affected channel in 

the trip condition within 4 hours. The Completion Time accounts for the 

fact that three redundant channels monitoring containment radiation are 

still available to provide a single trip input to the CPIS logic to provide the 

automatic mitigation of a radiation release. Alternately, action must be 

taken to place the unit in a condition where the LCO does not apply. This 

does not preclude the movement of fuel to a safe position. 

B.1 and B.2

Condition B applies to the failure of the required Manual Trip or automatic 

Actuation Logic train, to the failure of more than one radiation monitoring 

channel, or if the Required Action and associated Completion Time of 

Condition A are not met. Required Action B.1 is to place the containment 

purge and exhaust isolation valves in the closed position. The Required 

Action immediately performs the isolation Function of the CPIS. Required 

Action B.2 is to immediately enter the applicable Conditions and Required 

Actions for the affected isolation valves of LCO 3.9.3, "Containment 

Penetrations," that were made inoperable by the inoperable 
CPIS (Analog) 

B 3.3.7 

CEOG STS B 3.3.7-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

instrumentation of the CPIS LCO. The Required Action directs the 

operator to take actions that are appropriate for the containment isolation 

Function of the CPIS without initiating the containment air supply and 

exhaust fans. The Completion Time accounts for the fact that the 

automatic capability to isolate containment and initiate supply and 

exhaust fans on valid containment high radiation signals is degraded 

during conditions in which a fuel handling accident is possible and CPIS 

provides the only automatic mitigation of radiation release. 

SURVEILLANCE SR 3.3.7.1

REQUIREMENTS 

Performance of the CHANNEL CHECK once every 12 hours ensures that 

a gross failure of instrumentation 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 or of 

something even more serious. CHANNEL CHECK will detect gross 

channel failure; thus, it is key to verifying the instrumentation continues to 

operate properly between each CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff, based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the transmitter or the signal processing equipment has drifted outside 

its limits. 

The Frequency, about once every shift, is based on operating experience 

that demonstrates the rarity of channel failure. Since the probability of 

two random failures in redundant channels in any 12 hour period is low, 

the CHANNEL CHECK minimizes the chance of loss of protective 

function due to failure of redundant channels. The CHANNEL CHECK 

supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of the displays associated 

with the LCO required channels. 
CPIS (Analog) 

B 3.3.7 

CEOG STS B 3.3.7-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.7.2

A CHANNEL FUNCTIONAL TEST is performed on each containment 

radiation monitoring channel to ensure the entire channel will perform its 

intended function. A successful test of the required contact(s) of a 

channel relay may be performed by the verification of the change of state 

of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. Any setpoint 

adjustment shall be consistent with the assumptions of the current plant 

specific setpoint analysis. 

The Frequency of [92] days is based on plant operating experience with 

regard to channel OPERABILITY and drift, which demonstrates that 

failure of more than one channel of a given Function in any [92] day 

interval is a rare event. 

SR 3.3.7.3

Proper operation of the initiation relays is verified by de-energizing these 

relays during the CHANNEL FUNCTIONAL TEST of the Actuation Logic 

every [31] days. This will actuate the Function, operating all associated 

equipment. Proper operation of the equipment actuated by each train is 

thus verified. A successful test of the required contact(s) of a channel 

relay may be performed by the verification of the change of state of a 

single contact of the relay. This clarifies what is an acceptable CHANNEL 

FUNCTIONAL TEST of a relay. This is acceptable because all of the 

other required contacts of the relay are verified by other Technical 

Specifications and non-Technical Specifications tests at least once per 

refueling interval with applicable extensions. A Note indicates this 

Surveillance includes verification of operation for each initiation relay. 

The Frequency of [31] days is based on plant operating experience with 

regard to channel OPERABILITY, which demonstrates that failure of more 

than one channel of a given Function in any [31] day interval is a rare 

event. 
CPIS (Analog) 

B 3.3.7 

CEOG STS B 3.3.7-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.7.4

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the sensor. The Surveillance verifies that the channel responds 

to a measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive tests. CHANNEL 

CALIBRATIONS must be performed consistent with the plant specific 

setpoint analysis. 

The Frequency is based upon the assumption of an [18] month calibration 

interval for the determination of the magnitude of equipment drift in the 

setpoint analysis. 

SR 3.3.7.5

Every [18] months, a CHANNEL FUNCTIONAL TEST is performed on the 

manual CPIS actuation circuitry. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 

This Surveillance verifies that the trip push buttons are capable of 

opening contacts in the Actuation Logic as designed, de-energizing the 

initiation relays and providing Manual Trip of the Function. The 

[18] month Frequency is based on the need to perform this Surveillance 

under the conditions that apply during a plant outage and the potential for 

an unplanned transient if the Surveillance were performed with the 

reactor at power. Operating experience has shown these components 

usually pass the Surveillance when performed at a Frequency of once 

every 18 months. 
CPIS (Analog) 

B 3.3.7 

CEOG STS B 3.3.7-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.7.6

This Surveillance ensures that the train actuation response times are less 

than or equal to the maximum times assumed in the analyses. The 

18 month Frequency is based upon plant operating experience, which 

shows random failures of instrumentation components causing serious 

response time degradation, but not channel failure, are infrequent 

occurrences. Testing of the final actuating devices, which make up the 

bulk of the response time, is included. Testing of the final actuating 

device in one channel is included in the testing of each actuation logic 

channel. 

REFERENCES 1. FSAR, Section [6.2]. 

 2. FSAR, Section [7.3]. 

 3. "Plant Protection System Selection of Trip Setpoint Values." 
DG - LOVS (Digital) 

B 3.3.7 

CEOG STS B 3.3.7-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.7 Diesel Generator (DG) - Loss of Voltage Start (LOVS) (Digital) 

BASES 

BACKGROUND The DGs provide a source of emergency power when offsite power is 

either unavailable or insufficiently stable to allow safe unit operation. 

Undervoltage protection will generate a LOVS in the event a Loss of 

Voltage or Degraded Voltage condition occurs. There are two LOVS 

Functions for each 4.16 kV vital bus. 

Four undervoltage relays with inverse time characteristics are provided on 

each 4.16 kV Class 1E instrument bus for the purpose of detecting a 

sustained undervoltage condition or a loss of bus voltage. The relays are 

combined in a two-out-of-four logic to generate a LOVS if the voltage is 

below 75% for a short time or below 90% for a long time. The LOVS 

initiated actions are described in "Onsite Power Systems" (Ref. 1). 

Trip Setpoints and Allowable Values

The trip setpoints and Allowable Values are based on the analytical limits 

presented in "Accident Analysis," Reference 2. The selection of these trip 

setpoints is such that adequate protection is provided when all sensor 

and processing time delays are taken into account. To allow for 

calibration tolerances, instrumentation uncertainties, and instrument drift, 

Allowable Values specified in SR 3.3.7.3 are conservatively adjusted with 

respect to the analytical limits. A detailed description of the methodology 

used to calculate the trip setpoints, including their explicit uncertainties, is 

provided in Reference 3. The actual nominal trip setpoint is normally still 

more conservative than that required by the plant specific setpoint 

calculations. If the measured trip setpoint does not exceed the 

documented Surveillance acceptance criteria, the undervoltage relay is 

considered OPERABLE. 

Setpoints in accordance with the Allowable Values will ensure that the 

consequences of accidents will be acceptable, providing the plant is 

operated from within the LCOs at the onset of the accident and the 

equipment functions as designed. 
DG - LOVS (Digital) 

B 3.3.7 

CEOG STS B 3.3.7-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The undervoltage protection scheme has been designed to protect the 

plant from spurious trips caused by the offsite power source. This is 

made possible by the inverse voltage time characteristics of the relays 

used. A complete loss of offsite power will result in approximately a 

1 second delay in LOVS actuation. The DG starts and is available to 

accept loads within a 10 second time interval on the Engineered Safety 

Features Actuation System (ESFAS) or LOVS. Emergency power is 

established within the maximum time delay assumed for each event 

analyzed in the accident analysis (Ref. 2). 

Since there are four protective channels in a two-out-of-four trip logic for 

each division of the 4.16 kV power supply, no single failure will cause or 

prevent protective system actuation. This arrangement meets IEEE 

Standard 279-1971 criteria (Ref. 4). 

APPLICABLE The DG - LOVS is required for Engineered Safety Features (ESF) 

SAFETY systems to function in any accident with a loss of offsite power. Its design 

ANALYSES basis is that of the ESFAS. 

Accident analyses credit the loading of the DG based on a loss of offsite 

power during a loss of coolant accident. The actual DG start has 

historically been associated with the ESFAS actuation. The diesel 

loading has been included in the delay time associated with each safety 

system component requiring DG supplied power following a loss of offsite 

power. The analysis assumes a nonmechanistic DG loading, which does 

not explicitly account for each individual component of the loss of power 

detection and subsequent actions. This delay time includes contributions 

from the DG start, DG loading, and Safety Injection System component 

actuation. The response of the DG to a loss of power must be 

demonstrated to fall within this analysis response time when including the 

contributions of all portions of the delay. 

The required channels of LOVS, in conjunction with the ESF systems 

powered from the DGs, provide plant protection in the event of any of the 

analyzed accidents discussed in Reference 2, in which a loss of offsite 

power is assumed. LOVS channels are required to meet the redundancy 

and testability requirements of GDC 21 in 10 CFR 50, Appendix A 

(Ref. 5). 
DG - LOVS (Digital) 

B 3.3.7 

CEOG STS B 3.3.7-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The delay times assumed in the safety analysis for the ESF equipment 

include the [10] second DG start delay and the appropriate sequencing 

delay, if applicable. The response times for ESFAS actuated equipment 

in LCO 3.3.5, "Engineered Safety Features Actuation System (ESFAS) 

Instrumentation," include the appropriate DG loading and sequencing 

delay. 

The DG - LOVS channels satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The LCO for the LOVS requires that four channels per bus of each LOVS 

instrumentation Function be OPERABLE in MODES 1, 2, 3, and 4 and 

when the associated DG is required to be OPERABLE by LCO 3.8.2, "AC 

Sources - Shutdown." The LOVS supports safety systems associated 

with the ESFAS. In MODES 5 and 6, the four channels must be 

OPERABLE whenever the associated DG is required to be OPERABLE 

to ensure that the automatic start of the DG is available when needed. 

Actions allow maintenance (trip channel) bypass of individual channels. 

Plants are restricted to 48 hours in a trip channel bypass condition before 

either restoring the Function to four channel operation (two-out-of-four 

logic) or placing the channel in trip (one-out-of-three logic). At units 

where adequate channel to channel independence has been 

demonstrated, specific exceptions have been approved by the NRC staff 

to permit one of the two-out-of-four channels to be bypassed for an 

extended period of time. 

Loss of LOVS Function could result in the delay of safety system initiation 

when required. This could lead to unacceptable consequences during 

accidents. During the loss of offsite power, which is an anticipated 

operational occurrence, the DG powers the motor driven auxiliary 

feedwater pumps. Failure of these pumps to start would leave only the 

one turbine driven pump as well as an increased potential for a loss of 

decay heat removal through the secondary system. 

Only Allowable Values are specified for each Function in the LCO. 

Nominal trip setpoints are specified in the plant specific setpoint 

calculations. The nominal setpoints are selected to ensure that the 

setpoint measured by CHANNEL FUNCTIONAL TESTS does not exceed 

the Allowable Value if the bistable is performing as required. Operation 

with a trip setpoint less conservative than the nominal trip setpoint, but 

within the Allowable Value, is acceptable, provided that operation and 

testing is consistent with the assumptions of the plant specific setpoint 

calculation. A channel is inoperable if its actual trip setpoint is not within 

its required Allowable Value. 
DG - LOVS (Digital) 

B 3.3.7 

CEOG STS B 3.3.7-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

[ For this unit, the Bases for the Allowable Values and trip setpoints are as 

follows: ] 

APPLICABILITY The DG - LOVS actuation Function is required in MODES 1, 2, 3, and 4 

because ESF Functions are designed to provide protection in these 

MODES. Actuation in MODE 5 or 6 is required whenever the required 

DG must be OPERABLE, so that it can perform its function on a loss of 

power or degraded power to the vital bus. 

ACTIONS A LOVS channel is inoperable when it does not satisfy the OPERABILITY 

criteria for the channel's function. The most common cause of channel 

inoperability is outright failure or drift of the bistable or process module 

sufficient to exceed the tolerance allowed by the plant specific setpoint 

analysis. Typically, the drift is found to be small and results in a delay of 

actuation rather than a total loss of function. Determination of setpoint 

drift is generally made during the performance of a CHANNEL 

FUNCTIONAL TEST when the instrument is set up for adjustment to 

bring it within specification. If the actual trip setpoint is not within the 

Allowable Value, the channel is inoperable and the appropriate 

Conditions must be entered. 

In the event a channel's trip setpoint is found nonconservative with 

respect to the Allowable Value, or the channel is found inoperable, then 

all affected Functions provided by that channel must be declared 

inoperable and the LCO Condition entered. The required channels are 

specified on a per DG basis. 

When the number of inoperable channels in a trip Function exceeds those 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 should 

be entered immediately if applicable in the current MODE of operation. 

A Note has been added to clarify the application of Completion Time 

rules. The Conditions of this Specification may be entered independently 

for each DG - LOVS Function. The Completion Time(s) of the inoperable 

channel(s) of a Function will be tracked separately for each Function, 

starting from the time the Condition was entered for that Function. 

A.1 and A.2

Condition A applies if one channel is inoperable for one or more 

Functions per DG bus. 
DG - LOVS (Digital) 

B 3.3.7 

CEOG STS B 3.3.7-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

If the channel cannot be restored to OPERABLE status, the affected 

channel should either be bypassed or tripped within 1 hour (Required 

Action A.1). 

Placing this channel in either Condition ensures that logic is in a known 

configuration. In trip, the LOVS Logic is one-out-of-three. In bypass, the 

LOVS Logic is two-out-of-three, and interlocks prevent bypass of a 

second channel for the affected Function. The 1 hour Completion Time is 

sufficient to perform these Required Actions. 

Once Required Action A.1 has been complied with, Required Action A.2 

allows prior to entering MODE 2 following the next MODE 5 entry to 

repair the inoperable channel. If the channel cannot be restored to 

OPERABLE status, the plant cannot enter MODE 2 following the next 

MODE 5 entry. The time allowed to repair or trip the channel is 

reasonable to repair the affected channel while ensuring that the risk 

involved in operating with the inoperable channel is acceptable. The prior 

to entering MODE 2 following the next MODE 5 entry Completion Time is 

based on adequate channel independence, which allows a two-out-ofthree channel operation since no single failure will cause or prevent a 

reactor trip. 

B.1 and B.2

Condition B applies if two channels are inoperable for one or more 

Functions. 

If the channel cannot be placed in bypass or trip within 1 hour, the 

Conditions and Required Actions for the associated DG made inoperable 

by DG - LOVS instrumentation are required to be entered. Alternatively, 

one affected channel is required to be bypassed and the other is tripped, 

in accordance with Required Action B.2. This places the Function in oneout-of-two logic. The 1 hour Completion Time is sufficient to perform the 

Required Actions. 

One of the two inoperable channels will need to be restored to 

OPERABLE status prior to the next required CHANNEL FUNCTIONAL 

TEST because channel surveillance testing on an OPERABLE channel 

requires that the OPERABLE channel be placed in bypass. However, it is 

not possible to bypass more than one DG - LOVS channel, and placing a 

second channel in trip will result in a loss of voltage diesel start signal. 

Therefore, if one DG - LOVS channel is in trip and a second channel is in 

bypass, a third inoperable channel would place the unit in LCO 3.0.3. 
DG - LOVS (Digital) 

B 3.3.7 

CEOG STS B 3.3.7-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

After one channel is restored to OPERABLE status, the provisions of 

Condition A still apply to the remaining inoperable channel. 

C.1

Condition C applies when more than two undervoltage or Degraded 

Voltage channels on a single bus are inoperable. 

Required Action C.1 requires all but two channels to be restored to 

OPERABLE status within 1 hour. With more than two channels 

inoperable, the logic is not capable of providing the DG - LOVS signal for 

valid Loss of Voltage or Degraded Voltage conditions. The 1 hour 

Completion Time is reasonable to evaluate and take action to correct the 

degraded condition in an orderly manner and takes into account the low 

probability of an event requiring LOVS occurring during this interval. 

D.1

Condition D applies if the Required Actions and associated Completion 

Times are not met. 

Required Action D.1 ensures that Required Actions for the affected DG 

inoperabilities are initiated. Depending upon plant MODE, the ACTIONS 

specified in LCO 3.8.1, "AC Sources - Operating," or LCO 3.8.2 are 

required immediately. 

SURVEILLANCE The following SRs apply to each DG - LOVS Function. 

REQUIREMENTS 

[ SR 3.3.7.1

Performance of the CHANNEL CHECK once every 12 hours ensures that 

a gross failure of instrumentation has not occurred. A CHANNEL CHECK 

is normally a comparison of the indicated output of the potential 

transformers that feed the LOVS undervoltage relays. It is based on the 

assumption that instrument channels monitoring the same parameter 

should read approximately the same value. Significant deviations 

between the two channels could be an indication of excessive drift in one 

of the channels or of something even more serious. CHANNEL CHECK 

will detect gross channel failure; thus, it is key to verifying that the 

instrumentation continues to operate properly between each CHANNEL 

CALIBRATION. ]
DG - LOVS (Digital) 

B 3.3.7 

CEOG STS B 3.3.7-7 Rev. 3.0, 03/31/04 

BASES 

 SURVEILLANCE REQUIREMENTS (continued) 

[ Agreement criteria are determined by the plant staff based on a 

combination of channel instrument uncertainties, including indication and 

readability. If the channels are within the criteria, it is an indication that 

the channels are OPERABLE. 

The Frequency, about once every shift, is based upon operating 

experience that demonstrates channel failure is rare. Since the 

probability of two random failures in redundant channels in any 12 hour 

period is extremely low, the CHANNEL CHECK minimizes the chance of 

loss of protective function due to failure of redundant channels. The 

CHANNEL CHECK supplements less formal, but more frequent, checks 

of channel OPERABILITY during normal operational use of the displays 

associated with the LCO required channels. ]

SR 3.3.7.2

A CHANNEL FUNCTIONAL TEST is performed every [92] days to ensure 

that the entire channel will perform its intended function when needed. A 

successful test of the required contact(s) of a channel relay may be 

performed by the verification of the change of state of a single contact of 

the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL 

TEST of a relay. This is acceptable because all of the other required 

contacts of the relay are verified by other Technical Specifications and 

non-Technical Specifications tests at least once per refueling interval with 

applicable extensions. 

The Frequency of [92] days is based on plant operating experience with 

regard to channel OPERABILITY and drift, which demonstrates that 

failure of more than one channel of a given Function in any [92] day 

Frequency is a rare event. Any setpoint adjustment shall be consistent 

with the assumptions of the current plant specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [6]. 
DG - LOVS (Digital) 

B 3.3.7 

CEOG STS B 3.3.7-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.7.3

SR 3.3.7.3 is the performance of a CHANNEL CALIBRATION every 

[18] months. The CHANNEL CALIBRATION verifies the accuracy of 

each component within the instrument channel. This includes calibration 

of the undervoltage relays and demonstrates that the equipment falls 

within the specified operating characteristics defined by the manufacturer. 

The Surveillance verifies that the channel responds to a measured 

parameter within the necessary range and accuracy. CHANNEL 

CALIBRATION leaves the channel adjusted to account for instrument drift 

between successive surveillances to ensure the instrument channel 

remains operational. CHANNEL CALIBRATIONS must be performed 

consistent with the plant specific setpoint analysis. Any setpoint 

adjustment shall be consistent with the assumptions of the current plant 

specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [6]. 

The setpoints, as well as the response to a Loss of Voltage and 

Degraded Voltage test, shall include a single point verification that the trip 

occurs within the required delay time, as shown in Reference 1. The 

Frequency is based upon the assumption of an [18] month calibration 

interval for the determination of the magnitude of equipment drift in the 

setpoint analysis. 

REFERENCES 1. FSAR, Section [8.3]. 

2. FSAR, Chapter [15]. 

 3. "Plant Protection System Selection of Trip Setpoint Values." 

 4. IEEE Standard 279-1971. 

 5. 10 CFR 50, Appendix A, GDC 21. 

 6. [ ]. 
CRIS (Analog) 

B 3.3.8 

CEOG STS B 3.3.8-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.8 Control Room Isolation Signal (CRIS) (Analog) 

BASES 

BACKGROUND This LCO encompasses CRIS actuation, which is a plant specific 

instrumentation channel that performs an actuation Function required for 

plant protection but is not otherwise included in LCO 3.3.5, "Engineered 

Safety Features Actuation System (ESFAS) Logic and Manual Trip," or 

LCO 3.3.6, "Diesel Generator (DG) - Loss of Voltage Start (LOVS)." This 

is a non-Nuclear Steam Supply System ESFAS Function that, because of 

differences in purpose, design, and operating requirements, is not 

included in LCO 3.3.5 and LCO 3.3.6. Details of this LCO are for 

illustration only. Individual plants shall include those Functions and LCO 

requirements that are applicable to them. 

The CRIS terminates the normal supply of outside air to the control room 

and initiates actuation of the Emergency Radiation Protection System to 

minimize operator radiation exposure. The CRIS includes two 

independent, redundant subsystems, including actuation trains. Each 

train employs two separate sensors. One sensor detects gaseous 

activity. The other detects particulate and iodine activity. Since the two 

sensors detect different types of activity, they are not considered 

redundant to each other. However, since there are separate sensors in 

each train, the trains are redundant. If the bistable monitoring either 

sensor indicates an unsafe condition, that train will be actuated (one-outof-two logic). The two trains actuate separate equipment. Actuating 

either train will perform the intended function. Control room isolation also 

occurs on a Safety Injection Actuation Signal (SIAS). 

Trip Setpoints and Allowable Values

Trip setpoints used in the bistables are based on the analytical limits 

(Ref. 1). The selection of these trip setpoints is such that adequate 

protection is provided when all sensor and processing time delays are 

taken into account. To allow for calibration tolerances, instrumentation 

uncertainties, and instrument drift, Allowable Values specified in 

LCO 3.3.8 are conservatively adjusted with respect to the analytical limits. 

A detailed description of the methodology used to calculate the trip 

setpoints, including their explicit uncertainties, is provided in "Plant 

Protection System Selection of Trip Setpoint Values" (Ref. 2). The actual 

nominal trip setpoint entered into the bistable is normally still more 
CRIS (Analog) 

B 3.3.8 

CEOG STS B 3.3.8-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

conservative than that specified by the Allowable Value to account for 

changes in random measurement errors detectable by a CHANNEL 

FUNCTIONAL TEST. One example of such a change in measurement 

error is drift during the surveillance interval. If the measured setpoint 

does not exceed the Allowable Value, the bistable is considered 

OPERABLE. 

Setpoints in accordance with the Allowable Value will ensure that Safety 

Limits are not violated during anticipated operational occurrences (AOOs) 

and the consequences of Design Basis Accidents will be acceptable, 

providing the plant is operated from within the LCOs at the onset of the 

AOO or accident and the equipment functions as designed. 

APPLICABLE The CRIS, in conjunction with the Control Room Emergency Air Cleanup 

SAFETY System (CREACS), maintains the control room atmosphere within 

ANALYSES conditions suitable for prolonged occupancy throughout the duration of 

any one of the accidents discussed in Reference 1. The radiation 

exposure of control room personnel, through the duration of any one of 

the postulated accidents discussed in "Accident Analysis," FSAR, 

Chapter [15] (Ref. 1), does not exceed the limits set by 10 CFR 50, 

Appendix A, GDC 19 (Ref. 3). 

The CRIS satisfies the requirements of Criterion 3 of 

10 CFR 50.36(c)(2)(ii). 

LCO LCO 3.3.8 requires one channel of CRIS to be OPERABLE. The required 

channel consists of Actuation Logic, Manual Trip, and particulate/iodine 

and gaseous radiation monitors. The specific Allowable Values for the 

setpoints of the CRIS are listed in the SRs. 

Only the Allowable Values are specified for each trip Function in the LCO. 

Operation with a trip setpoint less conservative than the nominal trip 

setpoint, but within its Allowable Value, is acceptable, provided that the 

difference between the nominal trip setpoint and the Allowable Value is 

equal to or greater than the drift allowance assumed for each trip in the 

transient and accident analyses. 

Each Allowable Value specified is more conservative than the analytical 

limit assumed in the transient and accident analysis in order to account 

for instrument uncertainties appropriate to the trip Function. These 

uncertainties are defined in Reference 2. A channel is inoperable if its 

actual trip setpoint is not within its required Allowable Value. 
CRIS (Analog) 

B 3.3.8 

CEOG STS B 3.3.8-3 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The Bases for the LCO on the CRIS are discussed below for each 

Function: 

a. Manual Trip

The LCO on Manual Trip backs up the automatic trips and ensures 

operators have the capability to rapidly initiate the CRIS Function if 

any parameter is trending toward its setpoint. One channel must be 

OPERABLE. This considers that the Manual Trip capability is a 

backup and that other means are available to actuate the redundant 

train if required, including manual SIAS. 

b. Airborne Radiation

Both channels of Airborne Radiation detection in the required train 

are required to be OPERABLE to ensure the control room isolates on 

either high iodine and high particulate or gaseous concentration. 

[ For this unit, the basis for the Allowable Value is as follows: ] 

c. Actuation Logic

One train of Actuation Logic must be OPERABLE, since there are 

alternate means available to actuate the redundant train, including 

SIAS. 

APPLICABILITY The CRIS Functions must be OPERABLE in MODES 1, 2, 3, 4, [5, and 6] 

and during movement of [recently] irradiated fuel assemblies [(i.e., fuel 

that has occupied part of a critical reactor core within the previous [X] 

days)] to ensure a habitable environment for the control room operators. 

----------------------------------REVIEWER’S NOTE------------------------------------ 

For those plants that credit gas decay tank rupture accidents, the CRIS 

must also be OPERABLE in MODES 5 and 6. 

-------------------------------------------------------------------------------------------------- 

ACTIONS A CRIS channel is inoperable when it does not satisfy the OPERABILITY 

criteria for the channel's function. The most common cause of channel 

inoperability is outright failure or drift of the bistable or process module 

sufficient to exceed the tolerance allowed by the plant specific setpoint 

analysis. Typically, the drift is not large and would result in a delay of 

actuation rather than a total loss of function. This determination is 
CRIS (Analog) 

B 3.3.8 

CEOG STS B 3.3.8-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

generally made during the performance of a CHANNEL FUNCTIONAL 

TEST when the process instrument is set up for adjustment to bring it 

within specification. If the trip setpoint is not within the Allowable Value, 

the channel is inoperable and the appropriate Conditions must be 

entered. 

A.1, B.1, B.2, C.1, C.2.1, and C.2.2

Conditions A and C have been modified by a Note, which specifies that 

CREACS be placed manually in the toxic gas protection mode if the 

automatic transfer to the toxic gas protection mode is inoperable. [At this 

unit, the basis for this Note is as follows:] 

Conditions A, B, and C are applicable to manual and automatic actuation 

of the CREACS by CRIS. Condition A applies to the failure of the CRIS 

Manual Trip, Actuation Logic, and required particulate/iodine and required 

gaseous radiation monitor channels in MODE 1, 2, 3, or 4. Entry into this 

Condition requires action to either restore the failed channel(s) or 

manually perform the CRIS safety function (Required Action A.1). The 

Completion Time of 1 hour is sufficient to complete the Required Actions 

and accounts for the fact that CRIS supplements control room isolation by 

other Functions (e.g., SIAS) in MODES 1, 2, 3, and 4. If the channel 

cannot be restored to OPERABLE status, the plant must be brought to a 

MODE in which the LCO does not apply. To achieve this status, the plant 

must be brought to at least MODE 3 within 6 hours (Required Action B.1) 

and to MODE 5 within 36 hours (Required Action B.2). The Completion 

Times of 6 hours and 36 hours for reaching MODES 3 and 5 from 

MODE 1 are reasonable, based on operating experience and normal 

cooldown rates, for reaching the required MODE from full power 

conditions in an orderly manner and without challenging plant safety 

systems or operators. 

Condition C applies to the failure of CRIS Manual Trip, Actuation Logic, 

and required particulate/iodine and required gaseous radiation monitor 

channels [in MODE 5 or 6] or when moving [recently] irradiated 

assemblies. The Required Actions are immediately taken to place one 

OPERABLE CREACS train in the emergency radiation protection mode 

or to suspend positive reactivity additions and movement of [recently] 

irradiated fuel assemblies. The Completion Time recognizes the fact that 

the radiation signals are the only Functions available to initiate control 

room isolation in the event of a fuel handling accident requiring control 

room isolation. 
CRIS (Analog) 

B 3.3.8 

CEOG STS B 3.3.8-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Required Action [C.2.2] is modified by a Note to indicate that normal plant 

control operations that individually add limited positive reactivity (e.g., 

temperature or boron fluctuations associated with RCS inventory 

management or temperature control) are not precluded by this Action, 

provided they are accounted for in the calculated SDM. 

SURVEILLANCE SR 3.3.8.1

REQUIREMENTS 

Performance of the CHANNEL CHECK once every 12 hours ensures that 

a gross failure of instrumentation 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 or of 

something even more serious. CHANNEL CHECK will detect gross 

channel failure; thus, it is key to verifying the instrumentation continues to 

operate properly between each CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the transmitter or the signal processing equipment has drifted outside 

its limit. 

The Frequency, about once every shift, is based on operating experience 

that demonstrates the rarity of channel failure. Since the probability of 

two random failures in redundant channels in any 12 hour period is low, 

the CHANNEL CHECK minimizes the chance of loss of protective 

function due to failure of redundant channels. The CHANNEL CHECK 

supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of the displays associated 

with the LCO required channels. 

At this unit, the following administrative controls and design features (e.g., 

downscale alarms) immediately alert operations to loss of function in the 

nonredundant channels. 

[ At this unit, verification of sample system alignment and operation for 

gaseous, particulate, and iodine monitors is required as follows: ]
CRIS (Analog) 

B 3.3.8 

CEOG STS B 3.3.8-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.8.2

A CHANNEL FUNCTIONAL TEST is performed on the required control 

room radiation monitoring channel to ensure the entire channel will 

perform its intended function. A successful test of the required contact(s) 

of a channel relay may be performed by the verification of the change of 

state of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. Any setpoint 

adjustment shall be consistent with the assumptions of the current plant 

specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the frequency extension analysis. 

The requirements for this review are outlined in Reference [4]. 

The Frequency of [92] days is based on plant operating experience with 

regard to channel OPERABILITY and drift, which demonstrates that 

failure of more than one channel of a given Function in any [92] day 

interval is a rare event. 

SR 3.3.8.3

Proper operation of the individual initiation relays is verified by deenergizing these relays during the CHANNEL FUNCTIONAL TEST of the 

Actuation Logic every [31] days. This will actuate the Function, operating 

all associated equipment. Proper operation of the equipment actuated by 

each train is thus verified. A successful test of the required contact(s) of 

a channel relay may be performed by the verification of the change of 

state of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 

The Frequency of [31] days is based on plant operating experience with 

regard to channel OPERABILITY, which demonstrates that failure of more 

than one channel of a given Function in any [31] days interval is a rare 

event. 
CRIS (Analog) 

B 3.3.8 

CEOG STS B 3.3.8-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Note 1 indicates this Surveillance includes verification of operation for 

each initiation relay. 

Note 2 indicates that relays that cannot be tested at power are excepted 

from the Surveillance Requirement while at power. These relays must, 

however, be tested during each entry into MODE 5 exceeding 24 hours 

unless they have been tested within the previous 6 months. 

SR 3.3.8.4

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the sensor. The Surveillance verifies that the channel responds 

to a measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive surveillances. 

CHANNEL CALIBRATIONS must be performed consistent with the plant 

specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [4]. 

The Frequency is based upon the assumption of an [18] month calibration 

interval for the determination of the magnitude of equipment drift in the 

setpoint analysis. 

SR 3.3.8.5

Every [18] months, a CHANNEL FUNCTIONAL TEST is performed on the 

manual CRIS actuation circuitry. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 
CRIS (Analog) 

B 3.3.8 

CEOG STS B 3.3.8-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

This test verifies that the trip push buttons are capable of opening 

contacts in the Actuation Logic as designed, de-energizing the initiation 

relays and providing Manual Trip of the function. The [18] month 

Frequency is based on the need to perform this Surveillance under the 

conditions that apply during a plant outage and the potential for an 

unplanned transient if the Surveillance were performed with the reactor at 

power. Operating experience has shown these components usually pass 

the Surveillance when performed at a Frequency of once every 

[18] months. 

[ SR 3.3.8.6

This Surveillance ensures that the train actuation response times are less 

than the maximum times assumed in the analyses. The [18] month 

Frequency is based upon plant operating experience, which shows that 

random failures of instrumentation components causing serious response 

time degradation, but not channel failure, are infrequent occurrences. 

Testing of the final actuating devices, which make up the bulk of the 

response time, is included in the Surveillance testing. ] 

REFERENCES 1. FSAR, Chapter [15]. 

 2. "Plant Protection System Selection of Trip Setpoint Values." 

 3. 10 CFR 50, Appendix A, GDC 19. 

 4. [ ]. 
CPIS (Digital) 

B 3.3.8 

CEOG STS B 3.3.8-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.8 Containment Purge Isolation Signal (CPIS) (Digital) 

BASES 

BACKGROUND This LCO encompasses the CPIS, which is a plant specific 

instrumentation channel that performs an actuation function required for 

plant protection but is not otherwise included in LCO 3.3.6, "Engineered 

Safety Features Actuation System (ESFAS) Logic and Manual Trip," or 

LCO 3.3.7, "Diesel Generator (DG) - Loss of Voltage Start (LOVS)." 

Individual plants shall include the CPIS Function and LCO requirements 

that are applicable to them. 

The CPIS provides protection from the release of radioactive 

contamination from the containment in the event a fuel assembly should 

be severely damaged during handling. It also closes the purge valves 

during plant operation in response to a Reactor Coolant System (RCS) 

leak. 

The CPIS will detect any abnormal amounts of radioactive material in the 

containment and will initiate purge valve closure to limit the release of 

radioactivity to the environment. Both the minipurge and large volume 

purge supply and exhaust valves are closed on a CPIS when a high 

radiation level in containment is detected. 

The CPIS includes two independent, redundant logic subsystems, 

including actuation trains. Each train employs four sensors, each one 

detecting one of the following: 

• Gaseous 

• Airborne particulate 

• Iodine 

• Gamma (area) 

If any one of these sensors exceeds the bistable trip setpoint, the CPIS 

train will be actuated (one-out-of-four logic). 

Each train actuates a separate series valve in the containment purge 

supply and return lines. Either train controls sufficient equipment to 

perform the isolation function. These valves are also isolated on a Safety 

Injection Actuation Signal (SIAS) and Containment Isolation Actuation 

Signal (CIAS). 
CPIS (Digital) 

B 3.3.8 

CEOG STS B 3.3.8-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Trip Setpoints and Allowable Values

Trip setpoints used in the bistables are based on the analytical limits 

(Ref. 1). The selection of these trip setpoints is such that adequate 

protection is provided when all sensor and processing time delays are 

taken into account. To allow for calibration tolerances, instrumentation 

uncertainties, and instrument drift, trip setpoint Allowable Values specified 

in LCO 3.3.8 are conservatively adjusted with respect to the analytical 

limits. A detailed description of the methodology used to calculate the trip 

setpoints, including their explicit uncertainties, is provided in "Plant 

Protection System Selection of Trip Setpoint Values" (Ref. 2). The actual 

nominal trip setpoint entered into the bistable is normally still more 

conservative than that specified by the Allowable Value to account for 

changes in random measurement errors detectable by a CHANNEL 

FUNCTIONAL TEST. One example of such a change in measurement 

error is drift during the surveillance interval. If the measured setpoint 

does not exceed the Allowable Value, the bistable is considered 

OPERABLE. 

Setpoints in accordance with the Allowable Value will ensure that safety 

limits are not violated during anticipated operational occurrences (AOOs) 

and the consequences of Design Basis Accidents will be acceptable, 

providing the plant is operated from within the LCOs at the onset of the 

AOO or accident and the equipment functions as designed. 

APPLICABLE The CPIS is a backup to the CIAS systems in MODES 1, 2, 3, and 4 and 

SAFETY will close the containment purge valves in the event of high radiation 

ANALYSES levels resulting from a primary leak in the containment. 

The CPIS is also required to close the containment purge valves in the 

event of the fuel handling accident in containment [involving handling 

recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor 

core within the previous [X] days)], as described in Reference 1. This 

accident is a limiting case representing a class of accidents that might 

involve radiation release in containment without CIAS actuation. The 

CPIS ensures the consequences of a dropped [recently] irradiated fuel 

assembly in containment are not as severe as a dropped [recently] 

irradiated assembly in the fuel handling building. This ensures that the 

offsite consequences of radiation accidents in containment are within 

10 CFR 100 limits (Ref. 3). 

The CPIS satisfies the requirements of Criterion 3 of 

10 CFR 50.36(c)(2)(ii). 
CPIS (Digital) 

B 3.3.8 

CEOG STS B 3.3.8-3 Rev. 3.0, 03/31/04 

BASES 

LCO LCO 3.3.8 requires one CPIS channel to be OPERABLE. The required 

channel consists of [particulate, iodine, gaseous, and area radiation 

monitors]; Actuation Logic; and Manual Trip. The specific Allowable 

Values for the setpoints of the CPIS are listed in the SRs. 

Only the Allowable Values are specified for each trip Function in the LCO. 

Operation with a trip setpoint less conservative than the nominal trip 

setpoint, but within its Allowable Value, is acceptable, provided that the 

difference between the nominal trip setpoint and the Allowable Value is 

equal to or greater than the drift allowance assumed for each trip in the 

transient and accident analyses. A channel is inoperable if its actual trip 

setpoint is not within its Allowable Value. 

Each Allowable Value specified is more conservative than the analytical 

limit assumed in the transient and accident analysis in order to account 

for instrument uncertainties appropriate to the trip function. These 

uncertainties are defined in the "Plant Protection System Selection of Trip 

Setpoint Values" (Ref. 2). 

The Bases for the LCO on CPIS are discussed below for each Function: 

a. Manual Trip

The LCO on Manual Trip backs up the automatic trip and ensures 

operators have the capability to rapidly initiate the CPIS Function if 

any parameter is trending toward its setpoint. Only one manual 

channel of CPIS is required in MODES 1, 2, 3, and 4, since the CPIS 

is redundant with the CIAS and SIAS. Only one manual channel of 

CPIS is required during CORE ALTERATIONS and movement of 

irradiated fuel assemblies, since there are additional means of 

closing the containment purge valves in the event of a channel 

failure. 

b. Airborne Radiation and Containment Area Radiation

The LCO on the radiation channels requires that each channel be 

OPERABLE for each Actuation Logic channel, since they are not 

totally redundant to each other. 

The trip setpoint of twice background is selected to allow detection of 

small deviations from normal. The absolute value of the trip setpoint 

in MODES 5 and 6 differs from the setpoint in MODES 1, 2, 3, and 4 

so that a fuel handling accident can be detected in the lower 

background radiation expected in these MODES. 
CPIS (Digital) 

B 3.3.8 

CEOG STS B 3.3.8-4 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

c. Actuation Logic

One channel of Actuation Logic is required, since the valves can be 

shut independently of the CPIS signal either manually from the 

control room or using either the SIAS or CIAS push button. 

APPLICABILITY In MODES 1, 2, 3, and 4, the minipurge valves may be open. In the 

MODES, it is necessary to ensure the valves will shut in the event of a 

primary leak in containment whenever any of the containment purge 

valves are open. 

With the purge valves open during movement of [recently] irradiated fuel 

assemblies within containment, there is the possibility of a fuel handling 

accident requiring CPIS on high radiation in containment. [Due to 

radioactive decay, CPIS is only required to mitigate fuel handling 

accidents involving handling recently irradiated fuel (i.e., fuel that has 

occupied part of a critical reactor core within the previous [X] days).] 

The APPLICABILITY is modified by a Note, which states that the CPIS 

Specification is only required when the penetration is not isolated by at 

least one closed and de-activated automatic valve, closed manual valve, 

or blind flange. 

ACTIONS A CPIS channel is inoperable when it does not satisfy the OPERABILITY 

criteria for the channel's function. The most common cause of channel 

inoperability is outright failure or drift of the bistable or process module 

sufficient to exceed the tolerance allowed by the plant specific setpoint 

analysis. Typically, the drift is not large and would result in a delay of 

actuation rather than a total loss of function. This determination is 

generally made during the performance of a CHANNEL FUNCTIONAL 

TEST when the process instrument is set up for adjustment to bring it 

within specification. If the trip setpoint is not consistent with the Allowable 

Value, the channel must be declared inoperable immediately, and the 

appropriate Conditions must be entered. 

In the event a channel's trip setpoint is found nonconservative with 

respect to the Allowable Value, or the sensor, instrument loop, signal 

processing electronics, or bistable is found inoperable, then all affected 

Functions provided by that channel are required to be declared 

inoperable and the LCO Condition entered for the particular protective 

function affected. 
CPIS (Digital) 

B 3.3.8 

CEOG STS B 3.3.8-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

When the number of inoperable channels in a trip Function exceeds that 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 is 

immediately entered if applicable in the current MODE of operation. 

A.1

Condition A applies to the failure of CPIS Manual Trip, Actuation Logic, 

and required [particulate, iodine, gaseous, and area radiation monitors]. 

The Required Action is to enter the applicable Conditions and Required 

Actions for affected valves of LCO 3.6.3, "Containment Isolation Valves." 

The Completion Time accounts for the condition that the capability to 

isolate containment on valid containment high radiation or manual signals 

is degraded during power operation or shutdown modes. 

B.1 and B.2

Condition B applies when the Required Action and associated Completion 

Time of Condition A are not met in MODE 1, 2, 3, or 4. If Required 

Action A cannot be met within the required Completion Time, the plant 

must be brought to a MODE in which the LCO does not apply. To 

achieve this status, the plant must be brought to at least MODE 3 within 

6 hours and to MODE 5 within 36 hours. 

C.1 and C.2

Condition C applies to the same conditions as are described in 

Condition A; however, the applicability is during the movement of 

[recently] irradiated fuel assemblies within containment. Required 

Action C.1 is to place the containment purge and exhaust isolation valves 

in the closed position. The Required Action immediately performs the 

isolation function of the CPIS. Required Action C.2 may be performed in 

lieu of Required Action C.1. Required Action C.2 requires suspension of 

movement of [recently] irradiated fuel in containment immediately. The 

Completion Time accounts for the fact that the automatic capability to 

isolate containment on valid containment high radiation signals is 

degraded during conditions in which a fuel handling accident is possible 

and CPIS provides the only required automatic mitigation of radiation 

release. 
CPIS (Digital) 

B 3.3.8 

CEOG STS B 3.3.8-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.3.8.1

REQUIREMENTS 

Performance of the CHANNEL CHECK once every 12 hours ensures that 

a gross failure of instrumentation has not occurred on the required area 

and gaseous radiation monitor channels used in the CPIS. 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 or of 

something even more serious. CHANNEL CHECK will detect gross 

channel failure; thus, it is key to verifying the instrumentation continues to 

operate properly between each CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the transmitter or the signal processing equipment has drifted outside 

its limit. 

The Frequency, about once every shift, is based on operating experience 

that demonstrates the rarity of channel failure. Since the probability of 

two random failures in redundant channels in any 12 hour period is low, 

the CHANNEL CHECK minimizes the chance of loss of protective 

function due to failure of redundant channels. The CHANNEL CHECK 

supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of the displays associated 

with the LCO required channels. 

SR 3.3.8.2

SR 3.3.8.2 is the performance of a CHANNEL CHECK on the particulate 

and iodine channels used in the CPIS. It differs only in the Frequency, 

which is weekly. These channels use a filter to trap the particulate and 

iodine activity prior to the air sample being pumped to the gaseous 

activity chamber. This technique results in an integration of total 

particulate and iodine activity until the filter assemblies are replaced. The 

low levels of activity expected make more frequent monitoring 

unnecessary. 
CPIS (Digital) 

B 3.3.8 

CEOG STS B 3.3.8-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.8.3

A CHANNEL FUNCTIONAL TEST is performed on the required 

containment radiation monitoring channel to ensure the entire channel will 

perform its intended function. Setpoints must be found within the 

Allowable Values specified in SR 3.3.8.3 and left consistent with the 

assumptions of the plant specific setpoint analysis (Ref. 4). A successful 

test of the required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. The Frequency of 92 days is based on plant operating 

experience with regard to channel OPERABILITY and drift, which 

demonstrates that failure of more than one channel of a given Function in 

any 92 day Frequency is a rare event. 

A Note to the SR indicates this Surveillance is required to be met in 

MODES 1, 2, 3, and 4 only. 

SR 3.3.8.4

A CHANNEL FUNCTIONAL TEST is performed on the required 

containment radiation monitoring channel to ensure the entire channel will 

perform its intended function. A successful test of the required contact(s) 

of a channel relay may be performed by the verification of the change of 

state of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. Setpoints must be 

found within the Allowable Values specified in SR 3.3.8.4 and left 

consistent with the assumptions of the plant specific setpoint 

methodology (Ref. 4). The Frequency of 92 days is based on plant 

operating experience with regard to channel OPERABILITY and drift, 

which demonstrates that failure of more than one channel of a given 

Function in any 92 day interval is a rare event. 

A Note to the SR indicates that this test is only required to be met during 

CORE ALTERATIONS or during movement of irradiated fuel assemblies 

within containment. 
CPIS (Digital) 

B 3.3.8 

CEOG STS B 3.3.8-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.8.5

Proper operation of the individual initiation relays is verified by actuating 

these relays during the CHANNEL FUNCTIONAL TEST of the Actuation 

Logic every [18] months. This will actuate the Function, operating all 

associated equipment. Proper operation of the equipment actuated by 

each train is thus verified. The Frequency of [18] months is based on 

plant operating experience with regard to channel OPERABILITY and 

drift, which demonstrates that failure of more than one channel of a given 

Function during any [18] month interval is a rare event. A successful test 

of the required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. A Note to the SR indicates that this Surveillance includes 

verification of operation for each initiation relay. 

SR 3.3.8.6

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the sensor. The Surveillance verifies that the channel responds 

to a measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive surveillances. 

CHANNEL CALIBRATIONS must be performed consistent with the plant 

specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [5]. 

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. 
CPIS (Digital) 

B 3.3.8 

CEOG STS B 3.3.8-9 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.8.7

This Surveillance ensures that the train actuation response times are less 

than or equal to the maximum times assumed in the analyses. The 

[18] month Frequency is based upon plant operating experience, which 

shows that random failures of instrumentation components causing 

serious response time degradation, but not channel failure, are infrequent 

occurrences. Testing of the final actuating devices, which make up the 

bulk of the response time, is included in the Surveillance. 

SR 3.3.8.8

Every [18] months, a CHANNEL FUNCTIONAL TEST is performed on the 

CPIS Manual Trip channel. A successful test of the required contact(s) of 

a channel relay may be performed by the verification of the change of 

state of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 

This test verifies that the trip push buttons are capable of opening 

contacts in the Actuation Logic as designed, de-energizing the initiation 

relays and providing manual actuation of the Function. The [18] month 

Frequency is based on the need to perform this Surveillance under the 

conditions that apply during a plant outage and the potential for an 

unplanned transient if the Surveillance were performed with the reactor at 

power. Operating experience has shown these components usually pass 

the Surveillance when performed at a Frequency of once every 

[18] months. 

REFERENCES 1. FSAR, Chapter [15]. 

 2. "Plant Protection System Selection of Trip Setpoint Values." 

 3. 10 CFR 100. 

 4. Plant Specific Setpoint Methodology. 

 5. [ ]. 
CVCS Isolation signal (Analog) 

B 3.3.9 

CEOG STS B 3.3.9-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.9 Chemical and Volume Control System (CVCS) Isolation Signal (Analog) 

BASES 

BACKGROUND This LCO encompasses Chemical and Volume Control System (CVCS) 

Isolation Signal actuation. This is a plant specific instrumentation channel 

that performs an actuation Function required for plant protection and is 

not otherwise included in LCO 3.3.5, "Engineered Safety Features 

Actuation System (ESFAS) Logic and Manual Trip," or LCO 3.3.6, "Diesel 

Generator (DG) - Loss of Voltage Start (LOVS)." This is a non-Nuclear 

Steam Supply System ESFAS Function that, because of differences in 

purpose, design, and operating requirements, is not included in 

LCOs 3.3.5 and 3.3.6. Details of this LCO are for illustration only. 

Individual plants shall include those Functions and LCO requirements that 

are applicable to them. 

The CVCS Isolation Signal provides protection from radioactive 

contamination, as well as personnel and equipment protection in the 

event of a letdown line rupture outside containment. 

Each of the two actuation subsystems will isolate a separate letdown 

isolation valve in response to a high pressure condition in either the West 

Penetration Room or Letdown Heat Exchanger Room. Two pressure 

detectors in each of these rooms feed the four sensor subsystems. On a 

two-out-of-four coincidence, both actuation subsystems will actuate. 

Trip Setpoints and Allowable Values

Trip setpoints used in the bistables are based on the analytical limits 

stated in Reference 1. The selection of these trip setpoints is such that 

adequate protection is provided when all sensor and processing time 

delays are taken into account. To allow for calibration tolerances, 

instrumentation uncertainties, and instrument drift, Allowable Values 

specified in SR 3.3.9.2 are conservatively adjusted with respect to the 

analytical limits. A detailed description of the methodology used to 

calculate the trip setpoints, including their explicit uncertainties, is 

provided in "Plant Protection System Selection of Trip Setpoint Values" 

(Ref. 2). The actual nominal trip setpoint entered into the bistable is 

normally still more conservative than that specified by the Allowable 

Value to account for changes in random measurement errors detectable 

by a CHANNEL FUNCTIONAL TEST. One example of such a change in 

measurement error is drift during the interval. If the measured setpoint 

does not exceed the Allowable Value, the bistable is considered 

OPERABLE. 
CVCS Isolation signal (Analog) 

B 3.3.9 

CEOG STS B 3.3.9-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Setpoints in accordance with the Allowable Value will ensure that Safety 

Limits are not violated during anticipated operational occurrences (AOOs) 

and the consequences of Design Basis Accidents will be acceptable, 

providing the plant is operated from within the LCOs at the onset of the 

AOO or accident and the equipment functions as designed. 

APPLICABLE The CVCS Isolation Signal is redundant to the Safety Injection Actuation 

SAFETY Signal for letdown line breaks outside containment. In addition, an 

ANALYSES excess flow check valve is located in containment just downstream of the 

regenerative heat exchanger, which isolates letdown when flow exceeds 

200 gpm. 

[ At this unit, the provision of two sensors in each room in a two-out-of-four 

logic configuration satisfies the single failure criterion as follows: ]

The CVCS satisfies the requirements of Criterion 3 of 

10 CFR 50.36(c)(2)(ii). 

LCO Only the Allowable Values are specified for each trip Function in the LCO. 

Operation with a trip setpoint less conservative than the nominal trip 

setpoint, but within its Allowable Value, is acceptable, provided that the 

difference between the nominal trip setpoint and the Allowable Value is 

equal to or greater than the drift allowance assumed for each trip in the 

transient and accident analyses. 

Each Allowable Value specified is more conservative than the analytical 

limit assumed in the transient and accident analysis, in order to account 

for instrument uncertainties appropriate to the trip Function. These 

uncertainties are defined in the "Plant Protection System Selection of Trip 

Setpoint Values" (Ref. 2). 

CVCS isolation consists of closing the appropriate valve. This is 

undesirable at power, since letdown isolation will result. The absence of 

letdown flow will significantly decrease the charging flow temperature due 

to the absence of the regenerative heat exchanger preheating, causing 

unnecessary thermal stress to the charging nozzle. Therefore, the 

preferred action is to restore the valve function to OPERABLE status. 

Four channels of West Penetration Room and Letdown Heat Exchanger 

Room pressure sensing and two Actuation Logic channels are required to 

be OPERABLE. 

[ For this unit, the Bases for the Allowable Values are as follows: ]

[ For this unit, the Bases for the LCO requirement are as follows: ] 
CVCS Isolation signal (Analog) 

B 3.3.9 

CEOG STS B 3.3.9-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY The CVCS Isolation Signal must be OPERABLE in MODES 1, 2, 3, 

and 4, since the possibility of a loss of coolant accident is greatest in 

these MODES. In MODE 5 or 6, the probability is greatly diminished, and 

there is time to manually isolate CVCS. 

ACTIONS A CVCS isolation channel is inoperable when it does not satisfy the 

OPERABILITY criteria for the channel's Function. The most common 

cause of channel inoperability is outright failure or drift of the bistable or 

process module sufficient to exceed the tolerance allowed by the plant 

specific setpoint analysis. Typically, the drift is not large and would result 

in a delay of actuation rather than a total loss of function. This 

determination is generally made during the performance of a CHANNEL 

FUNCTIONAL TEST, when the process instrument is set up for 

adjustment to bring it within specification. If the trip setpoint is not 

consistent with the Allowable Value in SR 3.3.9.2, the channel must be 

declared inoperable immediately and the appropriate Conditions must be 

entered. 

In the event a channel's trip setpoint is found nonconservative with 

respect to the Allowable Value, or the sensor, instrument loop, signal 

processing electronics, or bistable is found inoperable, then all affected 

Functions provided by that channel should be declared inoperable and 

the LCO Condition entered for the particular protection Function affected. 

When the number of inoperable channels in a trip Function exceeds those 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 should 

be immediately entered if applicable in the current MODE of operation. 

A.1

Condition A applies to the failure of one CVCS Actuation Logic channel 

associated with the CVCS Isolation Signal. Required Action A.1 requires 

restoration of the inoperable channel to restore redundancy of the 

affected Function. The Completion Time of 48 hours is consistent with 

the Completion Time of other ESFAS Functions and should be adequate 

for most repairs, while minimizing the risk of operating with an inoperable 

channel. 
CVCS Isolation signal (Analog) 

B 3.3.9 

CEOG STS B 3.3.9-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1, B.2.1, and B.2.2

Condition B applies if one of the four CVCS instrument channels is 

inoperable. The Required Actions are identical to those of ESFAS 

Functions employing four redundant sensors specified in LCO 3.3.4, 

"Engineered Safety Features Actuation System (ESFAS) 

Instrumentation." The channel must be placed in bypass or trip if it 

cannot be repaired within 1 hour (Required Action B.1). The provision of 

four trip channels allows one channel to be bypassed (removed from 

service) during operations, placing the ESFAS in two-out-of-three 

coincidence logic. Placing the channel in bypass is preferred, since the 

CVCS isolation Function will be in two-out-of-three logic. This will avoid 

possible inadvertent CVCS isolation if an additional channel fails. The 

1 hour Completion Time to bypass or trip the channel is sufficient time to 

perform the Required Actions. 

Once the Required Action to trip or bypass the channel has been 

complied with, Required Action B.2.1 and Required Action B.2.2 provide 

for restoring the channel to OPERABLE status or placing it in trip within 

48 hours. Required Action B.2.1 restores the full capability of the 

Function. Required Action B.2.2 places the Function in a one-out-of-three 

configuration. In this configuration, common cause failure of dependent 

channels cannot prevent CVCS isolation actuation. The Completion Time 

provides the operator with time to take appropriate actions and still 

ensures that any risk involved in operating with a failed channel is 

acceptable. It is improbable that a failure of a second channel will occur 

during any given 48 hour period. 

C.1 and C.2

Condition C applies if two of the four CVCS West Penetration 

Room/Letdown Heat Exchanger Room Pressure - High channels are 

inoperable. The Required Actions are identical to those for other ESFAS 

Functions employing four redundant sensors in LCO 3.3.4. 

Restoring at least one channel to OPERABLE status is the preferred 

Required Action. If this cannot be accomplished, one channel should be 

placed in bypass and the other channel in trip. The allowed Completion 

Time of 1 hour is sufficient time to perform the Required Actions. 
CVCS Isolation signal (Analog) 

B 3.3.9 

CEOG STS B 3.3.9-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Once the Required Action to trip or bypass the channel has been 

complied with, Required Action C.2 provides for restoring one channel to 

OPERABLE status within 48 hours. The justification of the 48 hour 

Completion Time is the same as for Condition B. 

After one channel is restored to OPERABLE status, the provisions of 

Condition C still apply to the remaining inoperable channel. 

D.1 and D.2

Condition D specifies the shutdown track to be followed if two Actuation 

Logic channels are inoperable or if the Required Actions and associated 

Completion Times of Condition A, B, or C are not met. If two Actuation 

Logic channels are inoperable or the Required Actions cannot be met 

within the required Completion Time, the plant must be brought to a 

MODE in which the LCO does not apply. To achieve this status, the plant 

must be brought to at least MODE 3 within 6 hours and to MODE 5 within 

36 hours. The Completion Times are reasonable, based on operating 

experience, to reach the required MODE from full power conditions in an 

orderly manner and without challenging plant systems. 

SURVEILLANCE SR 3.3.9.1

REQUIREMENTS 

Performance of the CHANNEL CHECK on each CVCS isolation pressure 

indicating channel once every 12 hours ensures that a gross failure of 

instrumentation 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 or of 

something even more serious. CHANNEL CHECK will detect gross 

channel failure; thus, it is key to verifying the instrumentation continues to 

operate properly between each CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the transmitter or the signal processing equipment has drifted outside 

its limit. 
CVCS Isolation signal (Analog) 

B 3.3.9 

CEOG STS B 3.3.9-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The Frequency, about once every shift, is based on operating experience 

that demonstrates the rarity of channel failure. Since the probability of 

two random failures in redundant channels in any 12 hour period is low, 

the CHANNEL CHECK minimizes the chance of loss of protective 

function due to failure of redundant channels. The CHANNEL CHECK 

supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of the displays associated 

with the LCO required channels. 

SR 3.3.9.2

A CHANNEL FUNCTIONAL TEST is performed on each channel to 

ensure the entire channel will perform its intended function. A successful 

test of the required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. Any setpoint adjustment shall be consistent with the 

assumptions of the current plant specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [3]. 

The Frequency of 31 days is based on plant operating experience with 

regard to channel OPERABILITY and drift, which demonstrates that 

failure of more than one channel of a given Function in any 31 day 

interval is a rare event. 

Proper operation of the individual subgroup relays is verified by deenergizing these relays during the CHANNEL FUNCTIONAL TEST of the 

Actuation Logic every 31 days. This will actuate the Function, operating 

all associated equipment. Proper operation of the equipment actuated by 

each train is thus verified. Note 1 indicates this test includes verification 

of operation for each initiation relay. [At this unit, the verification is 

conducted as follows:] 

Note 2 indicates that relays that cannot be tested at power are excepted 

from the SR while at power. These relays must, however, be tested 

during each entry into MODE 5 exceeding 24 hours unless they have 

been tested within the previous 6 months. 
CVCS Isolation signal (Analog) 

B 3.3.9 

CEOG STS B 3.3.9-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

[ At this unit, the basis for this test exception is as follows: ]

[ At this unit, the following relays excepted by this Note are: ]

SR 3.3.9.3

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the sensor. The Surveillance verifies that the channel responds 

to a measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive tests. CHANNEL 

CALIBRATIONS must be performed consistent with the plant specific 

setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [3]. 

Radiation detectors may be removed and calibrated in a laboratory, 

calibrated in place using a transfer source or replaced with an equivalent 

laboratory calibrated unit. 

The Frequency is based upon the assumptions of an 18 month calibration 

interval for the determination of the magnitude of equipment drift in the 

setpoint analysis and includes operating experience as well as 

consistency with an 18 month fuel cycle. 

REFERENCES 1. FSAR, Section [7.3]. 

 2. "Plant Protection System Selection of Trip Setpoint Values." 

 3. [ ]. 
CRIS (Digital) 

B 3.3.9 

CEOG STS B 3.3.9-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.9 Control Room Isolation Signal (CRIS) (Digital) 

BASES 

BACKGROUND This LCO encompasses CRIS actuation, which is a plant specific 

instrumentation channel that performs an actuation Function required for 

plant protection but is not otherwise included in LCO 3.3.6, "Engineered 

Safety Features Actuation System (ESFAS) Logic and Manual Trip," or 

LCO 3.3.7, "Diesel Generator (DG) - Loss of Voltage Start (LOVS)." This 

is a non-Nuclear Steam Supply System ESFAS Function that, because of 

differences in purpose, design, and operating requirements, is not 

included in LCO 3.3.6 and LCO 3.3.7. Details of this LCO are for 

illustration only. Individual plants shall include those Functions and LCO 

requirements that are applicable to them. 

The CRIS terminates the normal supply of outside air to the control room 

and initiates actuation of the Emergency Radiation Protection System to 

minimize operator radiation exposure. The CRIS includes two 

independent, redundant subsystems, including actuation trains. Each 

train employs two separate sensors. One sensor detects gaseous 

activity. The other detects particulate and iodine activity. Since the two 

sensors detect different types of activity, they are not considered 

redundant to each other. However, since there are separate sensors in 

each train, the trains are redundant. If the bistable monitoring either 

sensor indicates an unsafe condition, that train will be actuated (one-outof-two logic). The two trains actuate separate equipment. Actuating 

either train will perform the intended function. Control room isolation also 

occurs on a Safety Injection Actuation Signal (SIAS). 

Trip Setpoints and Allowable Values

Trip setpoints used in the bistables are based on the analytical limits 

(Ref. 1). The selection of these trip setpoints is such that adequate 

protection is provided when all sensor and processing time delays are 

taken into account. To allow for calibration tolerances, instrumentation 

uncertainties, and instrument drift, Allowable Values specified in 

LCO 3.3.9 are conservatively adjusted with respect to the analytical limits. 

A detailed description of the methodology used to calculate the trip 

setpoints, including their explicit uncertainties, is provided in "Plant 

Protection System Selection of Trip Setpoint Values" (Ref. 2). The actual 

nominal trip setpoint entered into the bistable is normally still more 
CRIS (Digital) 

B 3.3.9 

CEOG STS B 3.3.9-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

conservative than that specified by the Allowable Value to account for 

changes in random measurement errors detectable by a CHANNEL 

FUNCTIONAL TEST. One example of such a change in measurement 

error is drift during the surveillance interval. If the measured setpoint 

does not exceed the Allowable Value, the bistable is considered 

OPERABLE. 

Setpoints in accordance with the Allowable Value will ensure that Safety 

Limits are not violated during anticipated operational occurrences (AOOs) 

and the consequences of Design Basis Accidents will be acceptable, 

providing the plant is operated from within the LCOs at the onset of the 

AOO or accident and the equipment functions as designed. 

APPLICABLE The CRIS, in conjunction with the Control Room Emergency Air Cleanup 

SAFETY System (CREACS), maintains the control room atmosphere within 

ANALYSES conditions suitable for prolonged occupancy throughout the duration of 

any one of the accidents discussed in Reference 1. The radiation 

exposure of control room personnel, through the duration of any one of 

the postulated accidents discussed in "Accident Analysis," FSAR, 

Chapter [15] (Ref. 1), does not exceed the limits set by 10 CFR 50, 

Appendix A, GDC 19 (Ref. 3). 

The CRIS satisfies the requirements of Criterion 3 of 

10 CFR 50.36(c)(2)(ii). 

LCO LCO 3.3.9 requires one channel of CRIS to be OPERABLE. The required 

channel consists of Actuation Logic, Manual Trip, and [particulate/iodine 

and gaseous radiation monitors]. The specific Allowable Values for the 

setpoints of the CRIS are listed in the SRs. 

Only the Allowable Values are specified for each trip Function in the LCO. 

Operation with a trip setpoint less conservative than the nominal trip 

setpoint, but within its Allowable Value, is acceptable, provided that the 

difference between the nominal trip setpoint and the Allowable Value is 

equal to or greater than the drift allowance assumed for each trip in the 

transient and accident analyses. 

Each Allowable Value specified is more conservative than the analytical 

limit assumed in the transient and accident analysis in order to account 

for instrument uncertainties appropriate to the trip Function. These 

uncertainties are defined in the "Plant Protection System Selection of Trip 

Setpoint Values" (Ref. 2). A channel is inoperable if its actual trip setpoint 

is not within its required Allowable Value. 
CRIS (Digital) 

B 3.3.9 

CEOG STS B 3.3.9-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The Bases for the LCO on the CRIS are discussed below for each 

Function: 

a. Manual Trip

The LCO on Manual Trip backs up the automatic trips and ensures 

operators have the capability to rapidly initiate the CRIS Function if 

any parameter is trending toward its setpoint. One channel must be 

OPERABLE. This considers that the Manual Trip capability is a 

backup and that other means are available to actuate the redundant 

train if required, including manual SIAS. 

b. Airborne Radiation

Both channels of Airborne Radiation detection in the required train 

are required to be OPERABLE to ensure the control room isolates on 

either high iodine and high particulate or gaseous concentration. 

[ For this unit, the basis for the Allowable Value is as follows: ] 

c. Actuation Logic

One train of Actuation Logic must be OPERABLE, since there are 

alternate means available to actuate the redundant train, including 

SIAS. 

APPLICABILITY The CRIS Functions must be OPERABLE in MODES 1, 2, 3, 4, [5, and 6] 

and during movement of [recently] irradiated fuel assemblies to ensure a 

habitable environment for the control room operators. [Due to radioactive 

decay, CRIS is only required to mitigate fuel handling accidents involving 

handling recently irradiated fuel (i.e., fuel that has occupied part of a 

critical reactor core within the previous [X] days)]. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

For those plants that credit gas decay tank rupture accidents, the CRIS 

must also be OPERABLE in MODES 5 and 6. 

-------------------------------------------------------------------------------------------------- 

ACTIONS A CRIS channel is inoperable when it does not satisfy the OPERABILITY 

criteria for the channel's function. The most common cause of channel 

inoperability is outright failure or drift of the bistable or process module 

sufficient to exceed the tolerance allowed by the plant specific setpoint 

analysis. Typically, the drift is not large and would result in a delay of 

actuation rather than a total loss of function. This determination is 
CRIS (Digital) 

B 3.3.9 

CEOG STS B 3.3.9-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

generally made during the performance of a CHANNEL FUNCTIONAL 

TEST when the process instrument is set up for adjustment to bring it 

within specification. If the trip setpoint is not within the Allowable Value, 

the channel is inoperable and the appropriate Conditions must be 

entered. 

A.1, B.1, B.2, C.1, C.2.1, and C.2.2

Conditions A and C have been modified by a Note, which specifies that 

CREACS be placed manually in the toxic gas protection mode if the 

automatic transfer to the toxic gas protection mode is inoperable. [At this 

unit, the basis for this Note is as follows:] 

Conditions A, B, and C are applicable to manual and automatic actuation 

of the CREACS by CRIS. Condition A applies to the failure of the CRIS 

Manual Trip, Actuation Logic, and required [particulate/iodine and 

required gaseous radiation monitor channels] in MODE 1, 2, 3, or 4. 

Entry into this Condition requires action to either restore the failed 

channel(s) or manually perform the CRIS safety function (Required 

Action A.1). The Completion Time of 1 hour is sufficient to complete the 

Required Actions and accounts for the fact that CRIS supplements control 

room isolation by other Functions (e.g., SIAS) in MODES 1, 2, 3, and 4. If 

the channel cannot be restored to OPERABLE status, the plant must be 

brought to a MODE in which the LCO does not apply. To achieve this 

status, the plant must be brought to at least MODE 3 within 6 hours 

(Required Action B.1) and to MODE 5 within 36 hours (Required 

Action B.2). The Completion Times of 6 hours and 36 hours for reaching 

MODES 3 and 5 from MODE 1 are reasonable, based on operating 

experience and normal cooldown rates, for reaching the required MODE 

from full power conditions in an orderly manner and without challenging 

plant safety systems or operators. 

Condition C applies to the failure of CRIS Manual Trip, Actuation Logic, 

and required particulate/iodine and required gaseous radiation monitor 

channels [in MODE 5 or 6] or when moving [recently] irradiated 

assemblies. The Required Actions are immediately taken to place one 

OPERABLE CREACS train in the emergency radiation protection mode, 

or to suspend positive reactivity additions and movement of [recently] 

irradiated fuel assemblies. The Completion Time recognizes the fact that 

the radiation signals are the only Functions available to initiate control 

room isolation in the event of a fuel handling accident [involving handling 

recently irradiated fuel]. 
CRIS (Digital) 

B 3.3.9 

CEOG STS B 3.3.9-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Required Action [ C.2.2 is modified by a Note to indicate that normal plant 

control operations that individually add limited positive reactivity (e.g., 

temperature or boron fluctuations associated with RCS inventory 

management or temperature control) are not precluded by this Action, 

provided they are accounted for in the calculated SDM. 

SURVEILLANCE SR 3.3.9.1

REQUIREMENTS 

Performance of the CHANNEL CHECK once every 12 hours ensures that 

a gross failure of instrumentation 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 or of 

something even more serious. CHANNEL CHECK will detect gross 

channel failure; thus, it is key to verifying the instrumentation continues to 

operate properly between each CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the transmitter or the signal processing equipment has drifted outside 

its limit. 

The Frequency, about once every shift, is based on operating experience 

that demonstrates the rarity of channel failure. Since the probability of 

two random failures in redundant channels in any 12 hour period is low, 

the CHANNEL CHECK minimizes the chance of loss of protective 

function due to failure of redundant channels. The CHANNEL CHECK 

supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of the displays associated 

with the LCO required channels. 

At this unit, the following administrative controls and design features (e.g., 

downscale alarms) immediately alert operations to loss of function in the 

nonredundant channels. 

[ At this unit, verification of sample system alignment and operation for 

gaseous, particulate, and iodine monitors is required as follows: ]
CRIS (Digital) 

B 3.3.9 

CEOG STS B 3.3.9-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.9.2

A CHANNEL FUNCTIONAL TEST is performed on the required control 

room radiation monitoring channel to ensure the entire channel will 

perform its intended function. A successful test of the required contact(s) 

of a channel relay may be performed by the verification of the change of 

state of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. Any setpoint 

adjustment shall be consistent with the assumptions of the current plant 

specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the frequency extension analysis. 

The requirements for this review are outlined in Reference [4]. 

The Frequency of [92] days is based on plant operating experience with 

regard to channel OPERABILITY and drift, which demonstrates that 

failure of more than one channel of a given Function in any [92] day 

interval is a rare event. 

SR 3.3.9.3

Proper operation of the individual initiation relays is verified by deenergizing these relays during the CHANNEL FUNCTIONAL TEST of the 

Actuation Logic every [18] months. This will actuate the Function, 

operating all associated equipment. Proper operation of the equipment 

actuated by each train is thus verified. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 

The Frequency of [18] months is based on plant operating experience 

with regard to channel OPERABILITY, which demonstrates that failure of 

more than one channel of a given Function in any [18] month interval is a 

rare event. 
CRIS (Digital) 

B 3.3.9 

CEOG STS B 3.3.9-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Note 1 indicates this Surveillance includes verification of operation for 

each initiation relay. 

Note 2 indicates that relays that cannot be tested at power are excepted 

from the Surveillance Requirement while at power. These relays must, 

however, be tested during each entry into MODE 5 exceeding 24 hours 

unless they have been tested within the previous 6 months. 

SR 3.3.9.4

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the sensor. The Surveillance verifies that the channel responds 

to a measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive surveillances. 

CHANNEL CALIBRATIONS must be performed consistent with the plant 

specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [4]. 

The Frequency is based upon the assumption of an [18] month calibration 

interval for the determination of the magnitude of equipment drift in the 

setpoint analysis. 

SR 3.3.9.5

Every [18] months, a CHANNEL FUNCTIONAL TEST is performed on the 

manual CRIS actuation circuitry. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 
CRIS (Digital) 

B 3.3.9 

CEOG STS B 3.3.9-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

This test verifies that the trip push buttons are capable of opening 

contacts in the Actuation Logic as designed, de-energizing the initiation 

relays and providing Manual Trip of the function. The [18] month 

Frequency is based on the need to perform this Surveillance under the 

conditions that apply during a plant outage and the potential for an 

unplanned transient if the Surveillance were performed with the reactor at 

power. Operating experience has shown these components usually pass 

the Surveillance when performed at a Frequency of once every 

[18] months. 

[ SR 3.3.9.6

This Surveillance ensures that the train actuation response times are less 

than the maximum times assumed in the analyses. The [18] month 

Frequency is based upon plant operating experience, which shows that 

random failures of instrumentation components causing serious response 

time degradation, but not channel failure, are infrequent occurrences. 

Testing of the final actuating devices, which make up the bulk of the 

response time, is included in the Surveillance testing. ] 

REFERENCES 1. FSAR, Chapter [15]. 

 2. "Plant Protection System Selection of Trip Setpoint Values." 

 3. 10 CFR 50, Appendix A, GDC 19. 

 4. [ ]. 
SBFAS (Analog) 

B 3.3.10 

CEOG STS B 3.3.10-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.10 Shield Building Filtration Actuation Signal (SBFAS) (Analog) 

BASES 

BACKGROUND This LCO encompasses the SBFAS, which is a plant specific 

instrumentation system that performs an actuation Function required for 

plant protection but is not otherwise included in LCO 3.3.5, "Engineered 

Safety Features Actuation System (ESFAS) Logic and Manual Trip," or 

LCO 3.3.6, "Diesel Generator (DG) - Loss of Voltage Start (LOVS)." This 

is a non-Nuclear Steam Supply System ESFAS Function that, because of 

differences in purpose, design, and operating requirements, is not 

included in LCOs 3.3.5 and 3.3.6. Details of this LCO are for illustration 

only. Individual plants shall include those Functions and LCO 

requirements that are applicable to them. 

APPLICABLE The SBFAS is required to filter the air space between the containment 

SAFETY and shield building during a loss of coolant accident (LOCA), as 

ANALYSES discussed in FSAR, Chapter 15 (Ref. 1). 

The SBFAS satisfies the requirements of Criterion 3 of 

10 CFR 50.36(c)(2)(ii). 

LCO The LCO on equipment OPERABILITY ensures that the SBFAS will 

perform as required when called upon. 

The LCO requires two channels of SBFAS automatic and Manual Trip to 

be OPERABLE. Two channels are necessary to ensure the required 

redundancy should one channel become inoperable. 

APPLICABILITY The SBFAS must be OPERABLE in MODES 1, 2, 3, and 4, since the 

possibility of a LOCA is greatest in these MODES. In MODE 5 or 6 the 

probability of a LOCA is greatly diminished, and there is ample time to 

respond manually to a LOCA event. 

ACTIONS When the number of inoperable channels in a trip Function exceeds those 

specified in the Conditions associated with the same trip Function, then 

the plant is outside the safety analysis. Therefore, LCO 3.0.3 should be 

immediately entered if applicable in the current MODE of operation. 
SBFAS (Analog) 

B 3.3.10 

CEOG STS B 3.3.10-2 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

A.1

Condition A applies to the failure of one SBFAS Manual Trip channel or of 

one Actuation Logic associated with the Chemical and Volume Control 

System Isolation Signal or SBFAS. Required Action A.1 requires 

restoration of the inoperable channel to restore redundancy of the 

affected Function. The Completion Time of 48 hours is consistent with 

the Completion Time of other ESFAS Functions employing similar logic 

and should be adequate for most repairs while minimizing the risk of 

operating with an inoperable channel for a manually actuated Function. 

B.1 and B.2

Condition B specifies the shutdown track to be followed if the Required 

Action and associated Completion Time of Condition A are not met. If 

Required Action A.1 cannot be met within the required Completion Time, 

the plant must be brought to a MODE in which the LCO does not apply. 

To achieve this status, the plant must be brought to at least MODE 3 

within 6 hours and to MODE 5 within 36 hours. The Completion Times 

are reasonable, based on operating experience, to reach the required 

MODE from full power conditions in an orderly manner and without 

challenging plant systems. 

SURVEILLANCE SR 3.3.10.1

REQUIREMENTS 

The SBFAS can be initiated either on a Safety Injection Actuation Signal 

(SIAS) or manually. This Surveillance is a restatement of SR 3.3.5.1 on 

the SIAS Function. Performing SR 3.3.5.1 satisfies this Surveillance. A 

successful test of the required contact(s) of a channel relay may be 

performed by the verification of the change of state of a single contact of 

the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL 

TEST of a relay. This is acceptable because all of the other required 

contacts of the relay are verified by other Technical Specifications and 

non-Technical Specifications tests at least once per refueling interval with 

applicable extensions. The Frequency is the same as that for SR 3.3.5.1. 
SBFAS (Analog) 

B 3.3.10 

CEOG STS B 3.3.10-3 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.10.2

Every [18] months, a CHANNEL FUNCTIONAL TEST is performed on the 

manual SBFAS actuation circuitry. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 

This Surveillance verifies that the trip push buttons are capable of 

opening contacts in the Actuation Logic as designed, de-energizing the 

initiation relays and providing Manual Trip of the Function. The 18 month 

Frequency is based on the need to perform this Surveillance under the 

conditions that apply during a plant outage and the potential for an 

unplanned transient if the Surveillance were performed with the reactor at 

power. Operating experience has shown these components usually pass 

the Surveillance when performed at a Frequency of once every 

[18] months. 

REFERENCES 1. FSAR, Chapter [15]. 
FHIS (Digital) 

B 3.3.10 

CEOG STS B 3.3.10-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.10 Fuel Handling Isolation Signal (FHIS) (Digital) 

BASES 

BACKGROUND This LCO encompasses FHIS actuation, which is a plant specific 

instrumentation channel that performs an actuation Function required for 

plant protection but is not otherwise included in LCO 3.3.6, "Engineered 

Safety Features Actuation System (ESFAS) Logic and Manual Trip," or 

LCO 3.3.7, "Diesel Generator (DG) - Loss of Voltage Start (LOVS)." This 

is a non-Nuclear Steam Supply System ESFAS Function that, because of 

differences in purpose, design, and operating requirements, is not 

included in LCO 3.3.6 and LCO 3.3.7. Details of this LCO are for 

illustration only. Individual plants shall include those Functions and LCO 

requirements that are applicable to them. 

The FHIS provides protection from radioactive contamination in the spent 

fuel pool area in the event that a spent fuel element ruptures during 

handling. 

The FHIS will detect radioactivity from fission products in the fuel and will 

initiate appropriate actions so the release to the environment is limited. 

More detail is provided in Reference 1. 

The FHIS includes two independent, redundant subsystems, including 

actuation trains. Each train employs two separate sensors. One sensor 

detects gaseous activity. The other detects particulate and iodine activity. 

Since the two sensors detect different types of activity, they are not 

considered redundant to each other. However, since there are separate 

sensors in each train, the trains are redundant. If the bistable monitoring 

either sensor indicates an unsafe condition, that train will be actuated 

(one-out-of-two logic). The two trains actuate separate equipment. 

Trip Setpoints and Allowable Values

Trip setpoints used in the bistables are based on the analytical limits 

(Ref. 2). The selection of these trip setpoints is such that adequate 

protection is provided when all sensor and processing time delays are 

taken into account. To allow for calibration tolerances, instrumentation 

uncertainties, and instrument drift, Allowable Values specified in 

LCO 3.3.10 are conservatively adjusted with respect to the analytical 

limits. A detailed description of the methodology used to calculate the trip 

setpoints, including their explicit uncertainties, is provided in "Plant 
FHIS (Digital) 

B 3.3.10 

CEOG STS B 3.3.10-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Protection System Selection of Trip Setpoint Values" (Ref. 3). The actual 

nominal trip setpoint entered into the bistable is normally still more 

conservative than that specified by the Allowable Value to account for 

changes in random measurement errors detectable by a CHANNEL 

FUNCTIONAL TEST. One example of such a change in measurement 

error is drift during the surveillance interval. If the measured setpoint 

does not exceed the Allowable Value, the bistable is considered 

OPERABLE. 

Setpoints in accordance with the Allowable Value will ensure that Safety 

Limits are not violated during anticipated operational occurrences (AOOs) 

and the consequences of Design Basis Accidents will be acceptable, 

providing the plant is operated from within the LCOs at the onset of the 

AOO or accident and the equipment functions as designed. 

APPLICABLE The FHIS is required to isolate the normal Fuel Building Air Cleanup 

SAFETY System (FBACS) and automatically initiate the recirculation and filtration 

ANALYSES systems in the event of the fuel handling accident [involving handling 

recently irradiated fuel] in the fuel handling building, as described in 

Reference 2. The FHIS helps ensure acceptable consequences for the 

dropping of a spent fuel bundle breaching up to 60 fuel pins. 

The FHIS satisfies the requirements of Criterion 3 of 

10 CFR 50.36(c)(2)(ii). 

LCO LCO 3.3.10 requires one channel of FHIS to be OPERABLE. The 

required channel consists of Actuation Logic, Manual Trip, and 

[particulate/iodine and] gaseous radiation monitors. The specific 

Allowable Values for the setpoints of the FHIS are listed in the SRs. 

Only the Allowable Values are specified for each trip Function in the SRs. 

Operation with a trip setpoint less conservative than the nominal trip 

setpoint, but within its Allowable Value, is acceptable, provided that the 

difference between the nominal trip setpoint and the Allowable Value is 

equal to or greater than the drift allowance assumed for each trip in the 

transient and accident analyses. 

Each Allowable Value specified is more conservative than the analytical 

limit assumed in the transient and accident analysis in order to account 

for instrument uncertainties appropriate to the trip Function. These 

uncertainties are defined in the "Plant Protection System Selection of Trip 

Setpoint Values" (Ref. 3). 
FHIS (Digital) 

B 3.3.10 

CEOG STS B 3.3.10-3 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The Bases for the LCO on the FHIS are discussed below for each 

Function: 

a. Manual Trip

The LCO on Manual Trip ensures that the FHIS Function can easily 

be initiated if any parameter is trending rapidly toward its setpoint. 

Components can be actuated independently of the FHIS. Both 

available channels are required to ensure a single failure will not 

disable automatic initiation capability. 

b. Airborne Radiation

The LCO on the two Airborne Radiation channels requires that each 

channel be OPERABLE for the required Actuation Logic channel, 

since they are not redundant to each other. 

[ At this plant, the basis for the FHIS radiation monitor Allowable 

Values is as follows: ] 

c. Actuation Logic

Two channels of Actuation Logic are required to be OPERABLE to 

ensure no single random failure can prevent automatic actuation. 

APPLICABILITY One FHIS channel is required to be OPERABLE during movement of 

[recently] irradiated fuel in the fuel building. The FHIS isolates the fuel 

building area in the event of a fuel handling accident [involving handling 

recently irradiated fuel]. 

[ The FHIS is required to be OPERABLE in MODES 1, 2, 3, and 4 and 

during movement of [recently] irradiated fuel because the fuel building 

heating, ventilation, and air conditioning (HVAC) is shared with 

Engineered Safety Features (ESF) equipment. ]

The FHIS must be OPERABLE in [MODES 1, 2, 3, and 4] and during 

movement of [recently] irradiated fuel in the fuel building, since the FHIS 

isolates the fuel handling area in the event of a fuel handling accident in 

any MODE or other condition. [Due to radioactive decay, FHIS is only 

required to mitigate fuel handling accidents involving handling recently 

irradiated fuel (i.e., fuel that has occupied part of a critical reactor core 

within the previous [X] days).] 
FHIS (Digital) 

B 3.3.10 

CEOG STS B 3.3.10-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS LCO 3.0.3 is not applicable while in MODE 5 or 6. However, since 

irradiated fuel assembly movement can occur in MODE 1, 2, 3, or 4, the 

ACTIONS have been modified by a Note stating that LCO 3.0.3 is not 

applicable. If moving irradiated fuel assemblies while in MODE 5 or 6, 

LCO 3.0.3 would not specify any action. If moving irradiated fuel 

assemblies while in MODE 1, 2, 3, or 4, the fuel movement is 

independent of reactor operations. Entering LCO 3.0.3, while in MODE 1, 

2, 3, or 4 would require the unit to be shutdown unnecessarily. 

An FHIS channel is inoperable when it does not satisfy the OPERABILITY 

criteria for the channel's function. The most common cause of channel 

inoperability is outright failure or drift of the bistable or process module 

sufficient to exceed the tolerance allowed by the plant specific setpoint 

analysis. Typically, the drift is not large and would result in a delay of 

actuation rather than a total loss of function. This determination is 

generally made during the performance of a CHANNEL FUNCTIONAL 

TEST when the process instrument is set up for adjustment to bring it 

within specification. If the trip setpoint is not consistent with the Allowable 

Value in LCO 3.3.10, the channel must be declared inoperable 

immediately and the appropriate Conditions must be entered. 

In the event a channel's trip setpoint is found nonconservative with 

respect to the Allowable Value, or the sensor, instrument loop, signal 

processing electronics, or bistable is found inoperable, then all affected 

Functions provided by that channel are required to be declared 

inoperable and the LCO Condition entered for the particular protective 

function affected. 

When the number of inoperable channels in a trip Function exceeds that 

specified in any related Condition associated with the same trip Function, 

then the plant is outside the safety analysis. Therefore, LCO 3.0.3 is 

immediately entered if applicable in the current MODE of operation. 

[ A.1, B.1, and B.2

Conditions A and B apply only to those plants whose fuel building HVAC 

is shared with an ESF equipment room. 

Condition A applies to FHIS Manual Trip, Actuation Logic, and required 

[particulate/iodine and gaseous radiation monitors] inoperable. 
FHIS (Digital) 

B 3.3.10 

CEOG STS B 3.3.10-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

The Required Actions are to restore the affected channels to OPERABLE 

status or place one OPERABLE FBACS train in operation within 1 hour. 

The Completion Time of 1 hour is sufficient to perform the Required 

Actions. The Completion Time accounts for the fact that the FHIS 

radiation monitors are the only signals available to automatically initiate 

the FBACS to mitigate radiation releases in the fuel building and credits 

the relatively lower likelihood of such events when irradiated fuel is not 

being moved. 

Condition B applies if the affected channels cannot be restored to 

OPERABLE status or one OPERABLE FBACS train cannot be placed in 

operation. If the channels cannot be restored to OPERABLE status, the 

plant must be brought to a MODE in which the LCO does not apply. To 

achieve this status, the plant must be brought to at least MODE 3 within 

6 hours and to MODE 5 within 36 hours. The allowed Completion Times 

are reasonable, based on operating experience, to reach the required 

MODE from full power conditions in an orderly manner and without 

challenging plant systems. ]

C.1 and C.2

Condition C applies to FHIS Manual Trip, Actuation Logic, and required 

[particulate/iodine and] gaseous radiation monitor inoperable during 

movement of [recently] irradiated fuel in the fuel building. 

The Required Actions are to restore required channels to OPERABLE 

status, or place one OPERABLE FBACS train in operation, or suspend 

movement of [recently] irradiated fuel in the fuel building. These 

Required Actions are required to be completed immediately. The 

Completion Time accounts for the higher likelihood of releases in the fuel 

building during fuel handling. 

SURVEILLANCE SR 3.3.10.1

REQUIREMENTS 

Performance of the CHANNEL CHECK once every 12 hours ensures that 

a gross failure of instrumentation 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. 
FHIS (Digital) 

B 3.3.10 

CEOG STS B 3.3.10-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Significant deviations between the two instrument channels could be an 

indication of excessive instrument drift in one of the channels or of 

something even more serious. CHANNEL CHECK will detect gross 

channel failure; thus, it is key to verifying the instrumentation continues to 

operate properly between each CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the transmitter or the signal processing equipment has drifted outside 

its limit. 

The Frequency, about once every shift, is based on operating experience 

that demonstrates the rarity of channel failure. Since the probability of 

two random failures in redundant channels in any 12 hour period is low, 

the CHANNEL CHECK minimizes the chance of loss of protective 

function due to failure of redundant channels. The CHANNEL CHECK 

supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of the displays associated 

with the LCO required channels. 

[ For this plant, the CHANNEL CHECK verification of sample system 

alignment and operation for gaseous, particulate, iodine, and gamma 

monitors is as follows: ]

SR 3.3.10.2

A CHANNEL FUNCTIONAL TEST is performed on the required fuel 

building radiation monitoring channel to ensure the entire channel will 

perform its intended function. A successful test of the required contact(s) 

of a channel relay may be performed by the verification of the change of 

state of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. Any setpoint 

adjustment shall be consistent with the assumptions of the current plant 

specific setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the frequency extension analysis. 

The requirements for this review are outlined in Reference [4]. 
FHIS (Digital) 

B 3.3.10 

CEOG STS B 3.3.10-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The Frequency of 92 days is based on plant operating experience with 

regard to channel OPERABILITY and drift, which demonstrates that 

failure of more than one channel of a given Function in any 92 day 

Frequency is a rare event. 

SR 3.3.10.3

Proper operation of the individual initiation relays is verified by actuating 

these relays during the CHANNEL FUNCTIONAL TEST of the Actuation 

Logic every [18] months. This will actuate the Function, operating all 

associated equipment. Proper operation of the equipment actuated by 

each train is thus verified. A successful test of the required contact(s) of 

a channel relay may be performed by the verification of the change of 

state of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. The Frequency of 

[18] months is based on plant operating experience with regard to 

channel OPERABILITY and drift, which demonstrates that failure of more 

than one channel of a given Function during any [18] month Frequency is 

a rare event. 

A Note to the SR indicates that this Surveillance includes verification of 

operation for each initiation relay. 

[ At this unit, the verification is conducted as follows: ]

SR 3.3.10.4

Every 18 months, a CHANNEL FUNCTIONAL TEST is performed on the 

FHIS Manual Trip channel. A successful test of the required contact(s) of 

a channel relay may be performed by the verification of the change of 

state of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. 
FHIS (Digital) 

B 3.3.10 

CEOG STS B 3.3.10-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

This Surveillance verifies that the trip push buttons are capable of 

opening contacts in the Actuation Logic as designed, de-energizing the 

initiation relays and providing Manual Trip of the Function. The 

[18] month Frequency is based on the need to perform this Surveillance 

under the conditions that apply during a plant outage and the potential for 

an unplanned transient if the Surveillance were performed with the 

reactor at power. Operating experience has shown these components 

usually pass the Surveillance when performed at a Frequency of once 

every [18] months. 

SR 3.3.10.5

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the sensor. The Surveillance verifies that the channel responds 

to a measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive tests. CHANNEL 

CALIBRATIONS must be performed consistent with the plant specific 

setpoint analysis. 

The as found and as left values must also be recorded and reviewed for 

consistency with the assumptions of the surveillance interval extension 

analysis. The requirements for this review are outlined in Reference [4]. 

The Frequency is based upon the assumption of an [18] month calibration 

interval for the determination of the magnitude of equipment drift in the 

setpoint analysis. 

[ SR 3.3.10.6

This Surveillance ensures that the train actuation response times are less 

than the maximum times assumed in the analyses. The [18] month 

Frequency is based upon plant operating experience, which shows that 

random failures of instrumentation components causing serious response 

time degradation, but not channel failure, are infrequent occurrences. 

Testing of the final actuating devices, which make up the bulk of the 

response time, is included in the Surveillance. ] 
FHIS (Digital) 

B 3.3.10 

CEOG STS B 3.3.10-9 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Chapter [9]. 

 2. FSAR, Chapter [15]. 

 3. "Plant Protection System Selection of Trip Setpoint Values." 

 4. [ ]. 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.11 Post Accident Monitoring (PAM) Instrumentation (Analog) 

BASES 

BACKGROUND The primary purpose of the post accident monitoring (PAM) 

instrumentation is to display plant variables that provide information 

required by the control room operators during accident situations. This 

information provides the necessary support for the operator to take the 

manual actions, for which no automatic control is provided, that are 

required for safety systems to accomplish their safety Functions for 

Design Basis Events. 

The OPERABILITY of the PAM instrumentation ensures that there is 

sufficient information available on selected plant parameters to monitor 

and assess plant status and behavior following an accident. 

The availability of PAM instrumentation is important so that responses to 

corrective actions can be observed and the need for, and magnitude of, 

further actions can be determined. These essential instruments are 

identified by plant specific documents (Ref. 1) addressing the 

recommendations of Regulatory Guide 1.97 (Ref. 2), as required by 

Supplement 1 to NUREG-0737, "TMI Action Items" (Ref. 3). 

Type A variables are included in this LCO because they provide the 

primary information required to permit the control room operator to take 

specific manually controlled actions, for which no automatic control is 

provided, that are required for safety systems to accomplish their safety 

functions for Design Basis Accidents (DBAs). Because the list of Type A 

variables differs widely between plants, Table 3.3.11-1, in the 

accompanying LCO, contains no examples of Type A variables, except 

for those that may also be Category I. 

Category I variables are the key variables deemed risk significant 

because they are needed to: 

• Determine whether other systems important to safety are performing 

their intended functions, 

• Provide information to the operators that will enable them to 

determine the potential for causing a gross breach of the barriers to 

radioactivity release, and 

• Provide information regarding the release of radioactive materials to 

allow for early indication of the need to initiate action necessary to 

protect the public and for an estimate of the magnitude of any 

impending threat. 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

These key variables are identified by plant specific Regulatory Guide 1.97 

analyses (Ref. 1). These analyses identified the plant specific Type A 

and Category I variables and provided justification for deviating from the 

NRC proposed list of Category I variables. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Table 3.3.11-1, in the accompanying LCO, provides a list of variables 

typical of those identified by plant specific Regulatory Guide 1.97 

analyses. Table 3.3.11-1 in the plant specific Technical Specifications 

shall list all Type A and Category I variables identified by plant specific 

Regulatory Guide 1.97 analyses, as amended by NRC's Safety 

Evaluation Report (SER) (Ref. 4). The specific instrument Functions 

listed in Table 3.3.11-1 are discussed in the LCO Bases. 

-------------------------------------------------------------------------------------------------- 

APPLICABLE The PAM instrumentation ensures the OPERABILITY of Regulatory 

SAFETY Guide 1.97 Type A variables, so that the control room operating staff 

ANALYSES can: 

• Perform the diagnosis specified in the emergency operating 

procedures. These variables are restricted to preplanned actions for 

the primary success path of DBAs and 

• Take the specified, preplanned, manually controlled actions, for 

which no automatic control is provided, that are required for safety 

systems to accomplish their safety functions. 

The PAM instrumentation also ensures OPERABILITY of Category I, nonType A variables. This ensures the control room operating staff can: 

• Determine whether systems important to safety are performing their 

intended functions, 

• Determine the potential for causing a gross breach of the barriers to 

radioactivity release, 

• Determine if a gross breach of a barrier has occurred, and 

• Initiate action necessary to protect the public as well as to obtain an 

estimate of the magnitude of any impending threat. 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

PAM instrumentation that satisfies the definition of Type A in Regulatory 

Guide 1.97 meets Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

Category I, non-Type A PAM instruments are retained in the Specification 

because they are intended to assist operators in minimizing the 

consequences of accidents. Therefore, these Category I variables are 

important in reducing public risk. 

LCO LCO 3.3.11 requires two OPERABLE channels for all but one Function to 

ensure no single failure prevents the operators from being presented with 

the information necessary to determine the status of the plant and to bring 

the plant to, and maintain it in, a safe condition following that accident. 

Furthermore, provision of two channels allows a CHANNEL CHECK 

during the post accident phase to confirm the validity of displayed 

information. 

[ More than two channels may be required at some units if the Regulatory 

Guide 1.97 analysis determined that failure of one PAM channel results in 

information ambiguity (that is, the redundant displays disagree) that could 

lead operators to defeat or to fail to accomplish a required safety 

function. ]

The exception to the two channel requirement is Containment Isolation 

Valve Position. In this case, the important information is the status of the 

containment penetrations. The LCO requires one position indicator for 

each active containment isolation valve. This is sufficient to redundantly 

verify the isolation status of each isolable penetration either via indicated 

status of the active valve and prior knowledge of the passive valve or via 

system boundary status. If a normally active containment isolation valve 

is known to be closed and deactivated, position indication is not needed 

to determine status. Therefore, the position indication for valves in this 

state is not required to be OPERABLE. 

Listed below are discussions of the specified instrument Functions listed 

in Table 3.3.11-1. These discussions are intended as examples of what 

should be provided for each Function when the plant specific list is 

prepared. 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-4 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

1. [Logarithmic] Neutron Flux[ 

Logarithmic] Neutron Flux indication is provided to verify reactor 

shutdown. 

[ At this unit, the [Logarithmic] Neutron Flux PAM channels consist of 

the following: ]

2, 3. Reactor Coolant System (RCS) Hot and Cold Leg Temperature

RCS Hot and Cold Leg Temperatures are Category I variables 

provided for verification of core cooling and long term surveillance. 

Reactor outlet temperature inputs to the PAM are provided by two 

fast response resistance elements and associated transmitters in 

each loop. The channels provide indication over a range of 32°F to 

700°F. 

4. Reactor Coolant System Pressure (wide range)

RCS wide range pressure is a Category I variable provided for 

verification of core cooling and RCS integrity long term surveillance. 

Wide range RCS loop pressure is measured by pressure transmitters 

with a span of 0 psig to 3000 psig. The pressure transmitters are 

located outside the containment. Redundant monitoring capability is 

provided by two trains of instrumentation. Control room indications 

are provided through the inadequate core cooling (ICC) plasma 

display. The ICC plasma display is the primary indication used by 

the operator during an accident. Therefore, the PAM instrumentation 

LCO deals specifically with this portion of the instrument channel. 

In some plants, RCS pressure is a Type A variable because the 

operator uses this indication to monitor the cooldown of the RCS 

following a steam generator tube rupture or small break loss of 

coolant accident (LOCA). Operator actions to maintain a controlled 

cooldown, such as adjusting steam generator pressure or level, 

would use this indication. Furthermore, RCS pressure is one factor 

that may be used in decisions to terminate reactor coolant pump 

operation. 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-5 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

5. Reactor Vessel Water Level

Reactor Vessel Water Level is provided for verification and long term 

surveillance of core cooling. 

The Reactor Vessel Water Level monitoring system provides a direct 

measurement of the collapsed liquid level above the fuel alignment 

plate. The collapsed level represents the amount of liquid mass that 

is in the reactor vessel above the core. Measurement of the 

collapsed water level is selected because it is a direct indication of 

the water inventory. The collapsed level is obtained over the same 

temperature and pressure range as the saturation measurements, 

thereby encompassing all operating and accident conditions where it 

must function. Also, it functions during the recovery interval. 

Therefore, it is designed to survive the high steam temperature that 

may occur during the preceding core recovery interval. 

The level range extends from the top of the vessel down to the top of 

the fuel alignment plate. The response time is short enough to track 

the level during small break LOCA events. The resolution is 

sufficient to show the initial level drop, the key locations near the hot 

leg elevation, and the lowest levels just above the alignment plate. 

This provides the operator with adequate indication to track the 

progression of the accident and to detect the consequences of its 

mitigating actions or the functionality of automatic equipment. 

6. Containment Sump Water Level (wide range)

Containment Sump Water Level is provided for verification and long 

term surveillance of RCS integrity. 

[ For this unit, Containment Sump Water Level instrumentation 

consists of the following: ] 

7. Containment Pressure (wide range)

Containment Pressure is provided for verification of RCS and 

containment OPERABILITY. 

[ For this unit, Containment Pressure instrumentation consists of the 

following: ] 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-6 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

8. Containment Isolation Valve Position

Containment Isolation Valve Position is provided for verification of 

containment OPERABILITY. 

PCIV position is provided for verification of containment integrity. In 

the case of PCIV position, the important information is the isolation 

status of the containment penetration. The LCO requires one 

channel of valve position indication in the control room to be 

OPERABLE for each active PCIV in a containment penetration flow 

path, i.e., two total channels of PCIV position indication for a 

penetration flow path with two active valves. For containment 

penetrations with only one active PCIV having control room 

indication, Note (b) requires a single channel of valve position 

indication to be OPERABLE. This is sufficient to redundantly verify 

the isolation status of each isolable penetration via indicated status of 

the active valve, as applicable, and prior knowledge of passive valve 

or system boundary status. If a penetration flow path is isolated, 

position indication for the PCIV(s) in the associated penetration flow 

path is not needed to determine status. Therefore, the position 

indication for valves in an isolated penetration flow path is not 

required to be OPERABLE. Each penetration is treated separately 

and each penetration flow path is considered a separate function. 

Therefore, separate Condition entry is allowed for each inoperable 

penetration flow path. 

[ For this unit, the PCIV position PAM instrumentation consists of the 

following: ] 

9. Containment Area Radiation (high range)

Containment Area Radiation is provided to monitor for the potential of 

significant radiation releases and to provide release assessment for 

use by operators in determining the need to invoke site emergency 

plans. 

[ For this unit, Containment Area Radiation instrumentation consists 

of the following: ]
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-7 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

10. Pressurizer Level

Pressurizer Level is used to determine whether to terminate safety 

injection (SI), if still in progress, or to reinitiate SI if it has been 

stopped. Knowledge of pressurizer water level is also used to verify 

the plant conditions necessary to establish natural circulation in the 

RCS and to verify that the plant is maintained in a safe shutdown 

condition. 

[ For this unit, Pressurizer Level instrumentation consists of the 

following: ]

11. Steam Generator Water Level

Steam Generator Water Level is provided to monitor operation of 

decay heat removal via the steam generators. The Category I 

indication of steam generator level is the extended startup range 

level instrumentation. The extended startup range level covers a 

span of 6 inches to 394 inches above the lower tubesheet. The 

measured differential pressure is displayed in inches of water at 

68°F. Temperature compensation of this indication is performed 

manually by the operator. Redundant monitoring capability is 

provided by two trains of instrumentation. The uncompensated level 

signal is input to the plant computer, a control room indicator, and the 

[Auxiliary Feedwater (AFW)] Control System. 

At some plants, operator action is based on the control room 

indication of Steam Generator Water Level. The RCS response 

during a design basis small break LOCA is dependent on the break 

size. For a certain range of break sizes, the boiler condenser mode 

of heat transfer is necessary to remove decay heat. At these plants, 

extended startup range level is a Type A variable because the 

operator must manually raise and control the steam generator level 

to establish boiler condenser heat transfer. Operator action is 

initiated on a loss of subcooled margin. Feedwater flow is increased 

until the indicated extended startup range level reaches the boiler 

condenser setpoint. 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-8 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

12. Condensate Storage Tank (CST) Level

CST Level is provided to ensure water supply for [AFW]. The CST 

provides the ensured safety grade water supply for the [AFW] 

System. The CST consists of two identical tanks connected by a 

common outlet header. Inventory is monitored by a 0 to 144 inch 

level indication for each tank. CST Level is displayed on a control 

room indicator, strip chart recorder, and plant computer. In addition, 

a control room annunciator alarms on low level. 

At some plants, CST Level is considered a Type A variable because 

the control room meter and annunciator are considered the primary 

indication used by the operator. The DBAs that require [AFW] are 

the loss of electric power, steam line break (SLB), and small break 

LOCA. The CST is the initial source of water for the [AFW] System. 

However, as the CST is depleted, manual operator action is 

necessary to replenish the CST or align suction to the [AFW] pumps 

from the hotwell. 

 13, 14, 15, 16. Core Exit Temperature

Core Exit Temperature is provided for verification and long term 

surveillance of core cooling. 

An evaluation was made of the minimum number of valid core exit 

thermocouples necessary for inadequate core cooling detection. The 

evaluation determined the reduced complement of core exit 

thermocouples necessary to detect initial core uncovery and trend 

the ensuing core heatup. The evaluations account for core 

nonuniformities including incore effects of the radial decay power 

distribution and excore effects of condensate runback in the hot legs 

and nonuniform inlet temperatures. Based on these evaluations, 

adequate or inadequate core cooling detection is ensured with two 

valid core exit thermocouples per quadrant. 

The design of the Incore Instrumentation System includes a Type K 

(chromel alumel) thermocouple within each of the 56 incore 

instrument detector assemblies. 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-9 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The junction of each thermocouple is located a few inches above the 

fuel assembly, inside a structure that supports and shields the incore 

instrument detector assembly string from flow forces in the outlet 

plenum region. These core exit thermocouples monitor the 

temperature of the reactor coolant as it exits the fuel assemblies. 

The core exit thermocouples have a usable temperature range from 

32°F to 2300°F, although accuracy is reduced at temperatures 

above 1800°F. 

17. [Auxiliary Feedwater (AFW)] Flow

[AFW] Flow is provided to monitor operation of decay heat removal 

via the steam generators. 

The [AFW] Flow to each steam generator is determined from a 

differential pressure measurement calibrated to a span of 0 gpm to 

1200 gpm. Redundant monitoring capability is provided by two 

independent trains of instrumentation for each steam generator. 

Each differential pressure transmitter provides an input to a control 

room indicator and the plant computer. Since the primary indication 

used by the operator during an accident is the control room indicator, 

the PAM instrumentation Specification deals specifically with this 

portion of the instrument channel. 

At some plants [AFW] Flow is a Type A variable because operator 

action is required to throttle flow during an SLB accident in order to 

prevent the [AFW] pumps from operating in runout conditions. [AFW] 

Flow is also used by the operator to verify that the [AFW] System is 

delivering the correct flow to each steam generator. However, the 

primary indication used by the operator to ensure an adequate 

inventory is steam generator level. 

Two channels are required to be OPERABLE for all but one Function. 

Two OPERABLE channels ensure that no single failure, within either the 

PAM instrumentation or its auxiliary supporting features or power sources 

(concurrent with the failures that are a condition of or result from a 

specific accident), prevents the operators from being presented the 

information necessary for them to determine the safety status of the plant 

and to bring the plant to and maintain it in a safe condition following that 

accident. 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-10 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

In Table 3.3.11-1 the exception to the two channel requirement is 

Containment Isolation Valve Position. 

Two OPERABLE channels of core exit thermocouples are required for 

each channel in each quadrant to provide indication of radial distribution 

of the coolant temperature rise across representative regions of the core. 

Power distribution symmetry was considered in determining the specific 

number and locations provided for diagnosis of local core problems. 

Therefore, two randomly selected thermocouples may not be sufficient to 

meet the two thermocouples per channel requirement in any quadrant. 

The two thermocouples in each channel must meet the additional 

requirement that one be located near the center of the core and the other 

near the core perimeter, such that the pair of core exit thermocouples 

indicate the radial temperature gradient across their core quadrant. Plant 

specific evaluations in response to Item II.F.2 of NUREG-0737 should 

have identified the thermocouple pairings that satisfy these requirements. 

Two sets of two thermocouples in each quadrant ensure a single failure 

will not disable the ability to determine the radial temperature gradient. 

For loop and steam generator related variables, the required information 

is individual loop temperature and individual steam generator level. In 

these cases two channels are required to be OPERABLE for each loop of 

steam generator to redundantly provide the necessary information. 

In the case of Containment Isolation Valve Position, the important 

information is the status of the containment penetrations. The LCO 

requires one position indicator for each active containment isolation valve. 

This is sufficient to redundantly verify the isolation status of each isolable 

penetration either via indicated status of the active valve and prior 

knowledge of the passive valve or via system boundary status. If a 

normally active containment isolation valve is known to be closed and 

deactivated, position indication is not needed to determine status. 

Therefore, the position indication for valves in this state is not required to 

be OPERABLE. 

APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1, 2, and 3. 

These variables are related to the diagnosis and preplanned actions 

required to mitigate DBAs. The applicable DBAs are assumed to occur in 

MODES 1, 2, and 3. In MODES 4, 5, and 6, plant conditions are such 

that the likelihood of an event occurring that would require PAM 

instrumentation is low; therefore, PAM instrumentation is not required to 

be OPERABLE in these MODES. 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-11 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A Note has been added in the ACTIONS to clarify the 

application of Completion Time rules. The Conditions of this Specification 

may be entered independently for each Function listed in Table 3.3.11-1. 

The Completion Time(s) of the inoperable channel(s) of a Function will be 

tracked separately for each Function, starting from the time the Condition 

was entered for that Function. 

A.1

When one or more Functions have one required channel that is 

inoperable, the required inoperable channel must be restored to 

OPERABLE status within 30 days. The 30 day Completion Time is based 

on operating experience and takes into account the remaining 

OPERABLE channel (or in the case of a Function that has only one 

required channel, other non-Regulatory Guide 1.97 instrument channels 

to monitor the Function), the passive nature of the instrument (no critical 

automatic action is assumed to occur from these instruments), and the 

low probability of an event requiring PAM instrumentation during this 

interval. 

B.1

This Required Action specifies initiation of actions in accordance with 

Specification 5.6.7, which requires a written report to be submitted to the 

Nuclear Regulatory Commission. This report discusses the results of the 

root cause evaluation of the inoperability and identifies proposed 

restorative Required Actions. This Required Action is appropriate in lieu 

of a shutdown requirement, given the likelihood of plant conditions that 

would require information provided by this instrumentation. Also, 

alternative Required Actions are identified before a loss of functional 

capability condition occurs. 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-12 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

D.1

This Required Action directs entry into the appropriate Condition 

referenced in Table 3.3.11-1. The applicable Condition referenced in the 

Table is Function dependent. Each time Required Action C.1 is not met, 

and the associated Completion Time has expired, Condition D is entered 

for that channel and provides for transfer to the appropriate subsequent 

Condition. 

E.1 and E.2

If the Required Action and associated Completion Time of Condition D is 

not met, and Table 3.3.11-1 directs entry into Condition E, the plant must 

be brought to a MODE in which the requirements of this LCO do not 

apply. To achieve this status, the plant must be brought to at least 

MODE 3 within 6 hours and to MODE 4 within 12 hours. 

The allowed Completion Times are reasonable, based on operating 

experience, to reach the required plant conditions from full power 

conditions in an orderly manner and without challenging plant systems. 

F.1

[ At this plant, alternate means of monitoring Reactor Vessel Water Level 

and Containment Area Radiation have been developed and tested. 

These alternate means may be temporarily installed if the normal PAM 

channel cannot be restored to OPERABLE status within the allotted time. 

If these alternate means are used, the Required Action is not to shut 

down the plant, but rather to follow the directions of Specification 5.6.7. 

The report provided to the NRC should discuss the alternate means used, 

describe the degree to which the alternate means are equivalent to the 

installed PAM channels, justify the areas in which they are not equivalent, 

and provide a schedule for restoring the normal PAM channels. ] 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-13 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE A Note at the beginning of the Surveillance Requirementsspecifies that 

REQUIREMENTS the following SRs apply to each PAM instrumentation Function in 

 Table 3.3.11-1. 

SR 3.3.11.1

Performance of the CHANNEL CHECK once every 31 days ensures that 

a gross failure of instrumentation 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 or of something even more serious. A CHANNEL 

CHECK will detect gross channel failure; thus, it is key to verifying the 

instrumentation continues to operate properly between each CHANNEL 

CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the sensor or the signal processing equipment has drifted outside its 

limit. If the channels are within the criteria, it is an indication that the 

channels are OPERABLE. If the channels are normally off scale during 

times when surveillance is required, the CHANNEL CHECK will only 

verify that they are off scale in the same direction. Off scale low current 

loop channels are verified to be reading at the bottom of the range and 

not failed downscale. 

The Frequency of 31 days is based upon plant operating experience with 

regard to channel OPERABILITY and drift, which demonstrates that 

failure of more than one channel of a given Function in any 31 day 

interval is a rare event. The CHANNEL CHECK supplements less formal, 

but more frequent, checks of channel during normal operational use of 

the displays associated with this LCO's required channels. 
PAM Instrumentation (Analog) 

B 3.3.11 

CEOG STS B 3.3.11-14 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.11.2

A CHANNEL CALIBRATION is performed every [18] months or 

approximately every refueling. CHANNEL CALIBRATION is a complete 

check of the instrument channel including the sensor. The Surveillance 

verifies the channel responds to the measured parameter within the 

necessary range and accuracy. A Note allows exclusion of neutron 

detectors from the CHANNEL CALIBRATION. 

[ At this unit, CHANNEL CALIBRATION shall find measurement errors are 

within the following acceptance criteria: ]

For the Containment Area Radiation instrumentation, a CHANNEL 

CALIBRATION may consist of an electronic calibration of the channel, not 

including the detector, for range decades above 10 R/hr, and a one point 

calibration check of the detector below 10 R/hr with a gamma source. 

Whenever a sensing element is replaced, the next required CHANNEL 

CALIBRATION of the resistance temperature detectors (RTD) sensors is 

accomplished by an inplace cross calibration that compares the other 

sensing elements with the recently installed sensing element. 

Whenever a sensing element is replaced, the next required CHANNEL 

CALIBRATION of the Core Exit thermocouple sensors is accomplished by 

an inplace cross calibration that compares the other sensing elements 

with the recently installed sensing element. 

The Frequency is based upon operating experience and consistency with 

the typical industry refueling cycle and is justified by an [18] month 

calibration interval for the determination of the magnitude of equipment 

drift. 

REFERENCES 1. Plant specific document (e.g., FSAR, NRC Regulatory Guide 1.97, 

SER letter). 

 2. Regulatory Guide 1.97. 

 3. NUREG-0737, Supplement 1. 

 4. NRC Safety Evaluation Report (SER). 
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.11 Post Accident Monitoring (PAM) Instrumentation (Digital) 

BASES 

BACKGROUND The primary purpose of the PAM instrumentation is to display plant 

variables that provide information required by the control room operators 

during accident situations. This information provides the necessary 

support for the operator to take the manual actions, for which no 

automatic control is provided, that are required for safety systems to 

accomplish their safety functions for Design Basis Events. 

The OPERABILITY of PAM instrumentation ensures that there is 

sufficient information available on selected plant parameters to monitor 

and assess plant status and behavior following an accident. 

The availability of PAM instrumentation is important so that responses to 

corrective actions can be observed and the need for, and magnitude of, 

further actions can be determined. These essential instruments are 

identified by plant specific documents (Ref. 1) addressing the 

recommendations of Regulatory Guide 1.97 (Ref. 2), as required by 

Supplement 1 to NUREG-0737, "TMI Action Items" (Ref. 3). 

Type A variables are included in this LCO because they provide the 

primary information required to permit the control room operator to take 

specific manually controlled actions, for which no automatic control is 

provided, that are required for safety systems to accomplish their safety 

functions for Design Basis Accidents (DBAs). Because the list of Type A 

variables differs widely between plants, Table 3.3.11-1 in the 

accompanying LCO contains no examples of Type A variables, except for 

those that may also be Category I. 

Category I variables are the key variables deemed risk significant 

because they are needed to: 

• Determine whether other systems important to safety are performing 

their intended functions, 

• Provide information to the operators that will enable them to 

determine the potential for causing a gross breach of the barriers to 

radioactivity release, and 

• Provide information regarding the release of radioactive materials to 

allow for early indication of the need to initiate action necessary to 

protect the public as well as to obtain an estimate of the magnitude of 

any impending threat. 
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

These key variables are identified by plant specific Regulatory Guide 1.97 

analyses (Ref. 1). These analyses identified the plant specific Type A 

variables and provided justification for deviating from the NRC proposed 

list of Category I variables. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Table 3.3.11-1 provides a list of variables typical of those identified by 

plant specific Regulatory Guide 1.97 analyses. Table 3.3.11-1 in the 

plant specific Technical Specifications (TS) shall list all Type A and 

Category I variables identified by plant specific Regulatory Guide 1.97 

analyses, as amended by the NRC's Safety Evaluation Report (SER) 

(Ref. 4). The specific instrument Functions listed in Table 3.3.11-1 are 

discussed in the LCO Bases. 

-------------------------------------------------------------------------------------------------- 

APPLICABLE The PAM instrumentation ensures the OPERABILITY of Regulatory 

SAFETY Guide 1.97 Type A variables, so that the control room operating staff 

ANALYSES can: 

• Perform the diagnosis specified in the emergency operating 

procedures. These variables are restricted to preplanned actions for 

the primary success path of DBAs and 

• Take the specified, preplanned, manually controlled actions, for 

which no automatic control is provided, that are required for safety 

systems to accomplish their safety functions. 

The PAM instrumentation also ensures OPERABILITY of Category I, nonType A variables. This ensures the control room operating staff can: 

• Determine whether systems important to safety are performing their 

intended functions, 

• Determine the potential for causing a gross breach of the barriers to 

radioactivity release, 

• Determine if a gross breach of a barrier has occurred, and 

• Initiate action necessary to protect the public as well as to obtain an 

estimate of the magnitude of any impending threat. 
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

PAM instrumentation that meets the definition of Type A in Regulatory 

Guide 1.97 satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

Category I, non-Type A PAM instruments are retained in the Specification 

because they are intended to assist operators in minimizing the 

consequences of accidents. Therefore, these Category I, non-Type A 

variables are important in reducing public risk. 

LCO LCO 3.3.11 requires two OPERABLE channels for all but one Function to 

ensure no single failure prevents the operators from being presented with 

the information necessary to determine the status of the plant and to bring 

the plant to, and maintain it in, a safe condition following that accident. 

Furthermore, provision of two channels allows a CHANNEL CHECK 

during the post accident phase to confirm the validity of displayed 

information. [More than two channels may be required at some plants if 

the Regulatory Guide 1.97 analysis determined that failure of one 

accident monitoring channel results in information ambiguity (that is, the 

redundant displays disagree) that could lead operators to defeat or to fail 

to accomplish a required safety function.] 

The exception to the two channel requirement is Containment Isolation 

Valve Position. In this case, the important information is the status of the 

containment penetrations. The LCO requires one position indicator for 

each active containment isolation valve. This is sufficient to redundantly 

verify the isolation status of each isolable penetration either via indicated 

status of the active valve and prior knowledge of the passive valve or via 

system boundary status. If a normally active containment isolation valve 

is known to be closed and deactivated, position indication is not needed 

to determine status. Therefore, the position indication for valves in this 

state is not required to be OPERABLE. 

Listed below are discussions of the specified instrument Functions listed 

in Table 3.3.11-1. These discussions are intended as examples of what 

should be provided for each Function when the plant specific list is 

prepared. 

1. [Wide Range] Neutron Flux

[Wide Range] Neutron Flux indication is provided to verify reactor 

shutdown. 

[ At this unit, the [Wide Range] Neutron Flux PAM channels consist of 

the following: ]
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-4 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

2, 3. Reactor Coolant System (RCS) Hot and Cold Leg Temperature

RCS Hot and Cold Leg Temperatures are Category I variables 

provided for verification of core cooling and long term surveillance. 

Reactor outlet temperature inputs to the PAM are provided by two 

fast response resistance elements and associated transmitters in 

each loop. The channels provide indication over a range of 32°F to 

700°F. 

4. Reactor Coolant System Pressure (wide range)

RCS Pressure (wide range) is a Category I variable, provided for 

verification of core cooling and RCS integrity long term surveillance. 

Wide range RCS loop pressure is measured by pressure transmitters 

with a span of 0 psig to 3000 psig. The pressure transmitters are 

located outside the containment. Redundant monitoring capability is 

provided by two trains of instrumentation. Control room indications 

are provided through the inadequate core cooling (ICC) plasma 

display. The ICC plasma display is the primary indication used by 

the operator during an accident. Therefore, the PAM instrumentation 

Specification deals specifically with this portion of the instrument 

channel. 

In some plants, RCS pressure is a Type A variable because the 

operator uses this indication to monitor the cooldown of the RCS 

following a steam generator tube rupture or small break loss of 

coolant accident (LOCA). Operator actions to maintain a controlled 

cooldown, such as adjusting steam generator pressure or level, 

would use this indication. Furthermore, RCS pressure is one factor 

that may be used in decisions to terminate reactor coolant pump 

operation. 

5. Reactor Vessel Water Level

Reactor Vessel Water Level is provided for verification and long term 

surveillance of core cooling. 
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-5 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The Reactor Vessel Water Level Monitoring System provides a direct 

measurement of the collapsed liquid level above the fuel alignment 

plate. The collapsed level represents the amount of liquid mass that 

is in the reactor vessel above the core. Measurement of the 

collapsed water level is selected because it is a direct indication of 

the water inventory. The collapsed level is obtained over the same 

temperature and pressure range as the saturation measurements, 

thereby encompassing all operating and accident conditions where it 

must function. Also, it functions during the recovery interval. 

Therefore, it is designed to survive the high steam temperature that 

may occur during the preceding core recovery interval. 

The level range extends from the top of the vessel down to the top of 

the fuel alignment plate. The response time is short enough to track 

the level during small break LOCA events. The resolution is 

sufficient to show the initial level drop, the key locations near the hot 

leg elevation, and the lowest levels just above the alignment plate. 

This provides the operator with adequate indication to track the 

progression of the accident and to detect the consequences of its 

mitigating actions or the functionality of automatic equipment. 

6. Containment Sump Water Level (wide range)

Containment Sump Water Level is provided for verification and long 

term surveillance of RCS integrity. 

[ For this unit, Containment Sump Water Level instrumentation 

consists of the following: ]

7. Containment Pressure (wide range)

Containment Pressure is provided for verification of RCS and 

containment OPERABILITY. 

[ For this unit, Containment Pressure instrumentation consists of the 

following: ] 

8. Penetration Flow Path Containment Isolation Valve Position

Containment Isolation Valve Position is provided for verification of 

containment OPERABILITY. 
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-6 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

PCIV position is provided for verification of containment integrity. In 

the case of PCIV position, the important information is the isolation 

status of the containment penetration. The LCO requires one 

channel of valve position indication in the control room to be 

OPERABLE for each active PCIV in a containment penetration flow 

path, i.e., two total channels of PCIV position indication for a 

penetration flow path with two active valves. For containment 

penetrations with only one active PCIV having control room 

indication, Note (b) requires a single channel of valve position 

indication to be OPERABLE. This is sufficient to redundantly verify 

the isolation status of each isolable penetration via indicated status of 

the active valve, as applicable, and prior knowledge of passive valve 

or system boundary status. If a penetration flow path is isolated, 

position indication for the PCIV(s) in the associated penetration flow 

path is not needed to determine status. Therefore, the position 

indication for valves in an isolated penetration flow path is not 

required to be OPERABLE. Each penetration is treated separately 

and each penetration flow path is considered a separate function. 

Therefore, separate condition entry is allowed for each inoperable 

penetration flow path. 

[ For this unit, the PCIV position PAM instrumentation consists of the 

following: ]

9. Containment Area Radiation (high range)

Containment Area Radiation is provided to monitor for the potential of 

significant radiation releases and to provide release assessment for 

use by operators in determining the need to invoke site emergency 

plans. 

[ For this unit, Containment Area Radiation instrumentation consists of 

the following: ]
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-7 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

10. Pressurizer Level

Pressurizer Level is used to determine whether to terminate safety 

injection (SI), if still in progress, or to reinitiate SI if it has been 

stopped. Knowledge of pressurizer water level is also used to verify 

the plant conditions necessary to establish natural circulation in the 

RCS and to verify that the plant is maintained in a safe shutdown 

condition. 

[ For this unit, Pressurizer Level instrumentation consists of the 

following: ]

11. Steam Generator Water Level

Steam Generator Water Level is provided to monitor operation of 

decay heat removal via the steam generators. The Category I 

indication of steam generator level is the extended startup range 

level instrumentation. The extended startup range level covers a 

span of 6 inches to 394 inches above the lower tubesheet. The 

measured differential pressure is displayed in inches of water at 

68°F. Temperature compensation of this indication is performed 

manually by the operator. Redundant monitoring capability is 

provided by two trains of instrumentation. The uncompensated level 

signal is input to the plant computer, a control room indicator, and the 

Emergency Feedwater (EFW) Control System. 

At some plants, operator action is based on the control room 

indication of Steam Generator Water Level. The RCS response 

during a design basis small break LOCA is dependent on the break 

size. For a certain range of break sizes, the boiler condenser mode 

of heat transfer is necessary to remove decay heat. At these plants, 

extended startup range level is a Type A variable because the 

operator must manually raise and control the steam generator level 

to establish boiler condenser heat transfer. Operator action is 

initiated on a loss of subcooled margin. Feedwater flow is increased 

until the indicated extended startup range level reaches the boiler 

condenser setpoint. 
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-8 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

12. Condensate Storage Tank (CST) Level

CST Level is provided to ensure water supply for EFW. The CST 

provides the ensured, safety grade water supply for the EFW 

System. The CST consists of two identical tanks connected by a 

common outlet header. Inventory is monitored by a 0 to 144 inch 

level indication for each tank. CST Level is displayed on a control 

room indicator, strip chart recorder, and plant computer. In addition, 

a control room annunciator alarms on low level. 

At some plants, CST Level is considered a Type A variable because 

the control room meter and annunciator are considered the primary 

indication used by the operator. The DBAs that require EFW are the 

loss of electric power, steam line break (SLB), and small break 

LOCA. The CST is the initial source of water for the EFW System. 

However, as the CST is depleted, manual operator action is 

necessary to replenish the CST or align suction to the EFW pumps 

from the hotwell. 

 13, 14, 15, 16. Core Exit Temperature

Core Exit Temperature is provided for verification and long term 

surveillance of core cooling. 

An evaluation was made of the minimum number of valid core exit 

thermocouples necessary for inadequate core cooling detection. The 

evaluation determined the reduced complement of core exit 

thermocouples necessary to detect initial core recovery and trend the 

ensuing core heatup. The evaluations account for core 

nonuniformities including incore effects of the radial decay power 

distribution and excore effects of condensate runback in the hot legs 

and nonuniform inlet temperatures. Based on these evaluations, 

adequate or inadequate core cooling detection is ensured with two 

valid core exit thermocouples per quadrant. 

The design of the Incore Instrumentation System includes a Type K 

(chromel alumel) thermocouple within each of the 56 incore 

instrument detector assemblies. The junction of each thermocouple 

is located a few inches above the fuel assembly, inside a structure 

that supports and shields the incore instrument detector assembly 

string from flow forces in the outlet plenum region. These core exit 

thermocouples monitor the temperature of the reactor coolant as it 

exits the fuel assemblies. 
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-9 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The core exit thermocouples have a usable temperature range from 

32°F to 2300°F, although accuracy is reduced at temperatures above 

1800°F. 

17. Emergency Feedwater (EFW) Flow

EFW Flow is provided to monitor operation of decay heat removal via 

the steam generators. 

EFW Flow to each steam generator is determined from a differential 

pressure measurement calibrated to a span of 0 gpm to 1200 gpm. 

Redundant monitoring capability is provided by two independent 

trains of instrumentation for each steam generator. Each differential 

pressure transmitter provides an input to a control room indicator 

and the plant computer. Since the primary indication used by the 

operator during an accident is the control room indicator, the PAM 

instrumentation Specification deals specifically with this portion of the 

instrument channel. 

At some plants EFW Flow is a Type A variable because operator 

action is required to throttle flow during an SLB accident in order to 

prevent the EFW pumps from operating in runout conditions. EFW 

Flow is also used by the operator to verify that the EFW System is 

delivering the correct flow to each steam generator. However, the 

primary indication used by the operator to ensure an adequate 

inventory is steam generator level. 

Two channels are required to be OPERABLE for all but one Function. 

Two OPERABLE channels ensure that no single failure within the PAM 

instrumentation or its auxiliary supporting features or power sources, 

concurrent with failures that are a condition of or result from a specific 

accident, prevents the operators from being presented the information 

necessary for them to determine the safety status of the plant and to bring 

the plant to and maintain it in a safe condition following that accident. 

In Table 3.3.11-1 the exception to the two channel requirement is 

Containment Isolation Valve Position. 
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-10 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

Two OPERABLE channels of core exit thermocouples are required for 

each channel in each quadrant to provide indication of radial distribution 

of the coolant temperature rise across representative regions of the core. 

Power distribution symmetry was considered in determining the specific 

number and locations provided for diagnosis of local core problems. 

Therefore, two randomly selected thermocouples may not be sufficient to 

meet the two thermocouples per channel requirement in any quadrant. 

The two thermocouples in each channel must meet the additional 

requirement that one be located near the center of the core and the other 

near the core perimeter, such that the pair of core exit thermocouples 

indicate the radial temperature gradient across their core quadrant. Plant 

specific evaluations in response to Item II.F.2 of NUREG-0737 (Ref. 3) 

should have identified the thermocouple pairings that satisfy these 

requirements. Two sets of two thermocouples in each quadrant ensure a 

single failure will not disable the ability to determine the radial 

temperature gradient. 

For loop and steam generator related variables, the required information 

is individual loop temperature and individual steam generator level. In 

these cases two channels are required to be OPERABLE for each loop of 

steam generator to redundantly provide the necessary information. 

In the case of Containment Isolation Valve Position, the important 

information is the status of the containment penetrations. The LCO 

requires one position indicator for each active containment isolation valve. 

This is sufficient to redundantly verify the isolation status of each isolable 

penetration either via indicated status of the active valve and prior 

knowledge of the passive valve or via system boundary status. If a 

normally active containment isolation valve is known to be closed and 

deactivated, position indication is not needed to determine status. 

Therefore, the position indication for valves in this state is not required to 

be OPERABLE. 

APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1, 2, and 3. 

These variables are related to the diagnosis and preplanned actions 

required to mitigate DBAs. The applicable DBAs are assumed to occur in 

MODES 1, 2, and 3. In MODES 4, 5, and 6, plant conditions are such 

that the likelihood of an event occurring that would require PAM 

instrumentation is low; therefore, PAM instrumentation is not required to 

be OPERABLE in these MODES. 
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-11 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A Note has been added in the ACTIONS to clarify the 

application of Completion Time rules. The Conditions of this Specification 

may be entered independently for each Function listed in Table 3.3.11-1. 

The Completion Time(s) of the inoperable channel(s) of a Function will be 

tracked separately for each Function starting from the time the Condition 

was entered for that Function. 

A.1

When one or more Functions have one required channel that is 

inoperable, the required inoperable channel must be restored to 

OPERABLE status within 30 days. The 30 day Completion Time is based 

on operating experience and takes into account the remaining 

OPERABLE channel (or in the case of a Function that has only one 

required channel, other non-Regulatory Guide 1.97 instrument channels 

to monitor the Function), the passive nature of the instrument (no critical 

automatic action is assumed to occur from these instruments), and the 

low probability of an event requiring PAM instrumentation during this 

interval. 

B.1

This Required Action specifies initiation of actions in accordance with 

Specification 5.6.7, which requires a written report to be submitted to the 

Nuclear Regulatory Commission. This report discusses the results of the 

root cause evaluation of the inoperability and identifies proposed 

restorative Required Actions. This Required Action is appropriate in lieu 

of a shutdown requirement, given the likelihood of plant conditions that 

would require information provided by this instrumentation. Also, 

alternative Required Actions are identified before a loss of functional 

capability condition occurs. 

C.1

When one or more Functions have two required channels inoperable (i.e., 

two channels inoperable in the same Function), one channel in the 

Function should be restored to OPERABLE status within 7 days. The 

Completion Time of 7 days is based on the relatively low probability of an 

event requiring PAM instrumentation operation and the availability of 

alternate means to obtain the required information. Continuous operation 
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-12 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

with two required channels inoperable in a Function is not acceptable 

because the alternate indications may not fully meet all performance 

qualification requirements applied to the PAM instrumentation. Therefore, 

requiring restoration of one inoperable channel of the Function limits the 

risk that the PAM Function will be in a degraded condition should an 

accident occur. 

D.1

This Required Action directs entry into the appropriate Condition 

referenced in Table 3.3.11-1. The applicable Condition referenced in the 

Table is Function dependent. Each time Required Action C.1 is not met, 

and the associated Completion Time has expired, Condition D is entered 

for that channel and provides for transfer to the appropriate subsequent 

Condition. 

E.1 and E.2

If the Required Action and associated Completion Time of Condition C 

are not met and Table 3.3.11-1 directs entry into Condition E, the plant 

must be brought to a MODE in which the LCO does not apply. To 

achieve this status, the plant must be brought to at least MODE 3 within 

6 hours and to MODE 4 within 12 hours. The allowed Completion Times 

are reasonable, based on operating experience, to reach the required 

plant conditions from full power conditions in an orderly manner and 

without challenging plant systems. 

[ F.1

At this plant, alternate means of monitoring Reactor Vessel Water Level 

and Containment Area Radiation have been developed and tested. 

These alternate means may be temporarily installed if the normal PAM 

channel cannot be restored to OPERABLE status within the allotted time. 

If these alternate means are used, the Required Action is not to shut 

down the plant, but rather to follow the directions of Specification 5.6.7. 

The report provided to the NRC should discuss whether the alternate 

means are equivalent to the installed PAM channels, justify the areas in 

which they are not equivalent, and provide a schedule for restoring the 

normal PAM channels. ] 
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-13 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE A Note at the beginning of the SR Table specifies thatthe following SRs 

REQUIREMENTS apply to each PAM instrumentation Function found in Table 3.3.11-1. 

SR 3.3.11.1

Performance of the CHANNEL CHECK once every 31 days ensures that 

a gross failure of instrumentation 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 or of something even more serious. A CHANNEL 

CHECK will detect gross channel failure; thus, it is key to verifying the 

instrumentation continues to operate properly between each CHANNEL 

CALIBRATION. 

Agreement criteria are determined by the plant staff based on a 

combination of the channel instrument uncertainties, including indication 

and readability. If a channel is outside the criteria, it may be an indication 

that the sensor or the signal processing equipment has drifted outside its 

limit. If the channels are within the criteria, it is an indication that the 

channels are OPERABLE. If the channels are normally off scale during 

times when surveillance is required, the CHANNEL CHECK will only 

verify that they are off scale in the same direction. Off scale low current 

loop channels are verified to be reading at the bottom of the range and 

not failed downscale. 

The Frequency of 31 days is based upon plant operating experience with 

regard to channel OPERABILITY and drift, which demonstrates that 

failure of more than one channel of a given Function in any 31 day 

interval is a rare event. The CHANNEL CHECK supplements less formal, 

but more frequent, checks of channel during normal operational use of 

the displays associated with this LCO's required channels. 

SR 3.3.11.2

A CHANNEL CALIBRATION is performed every [18] months or 

approximately every refueling. CHANNEL CALIBRATION is a complete 

check of the instrument channel including the sensor. The Surveillance 

verifies the channel responds to the measured parameter within the 

necessary range and accuracy. A Note allows exclusion of the neutron 

detectors from the CHANNEL CALIBRATION. 
PAM Instrumentation (Digital) 

B 3.3.11 

CEOG STS B 3.3.11-14 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

[ At this unit, CHANNEL CALIBRATION shall find measurement errors are 

within the following acceptance criteria: ]

For the Containment Area Radiation instrumentation, a CHANNEL 

CALIBRATION may consist of an electronic calibration of the channel, not 

including the detector, for range decades above 10 R/hr, and a one point 

calibration check of the detector below 10 R/hr with a gamma source. 

Whenever a sensing element is replaced, the next required CHANNEL 

CALIBRATION of the resistance temperature detectors (RTD) sensors is 

accomplished by an inplace cross calibration that compares the other 

sensing elements with the recently installed sensing element. 

Whenever a sensing element is replaced, the next required CHANNEL 

CALIBRATION of the Core Exit thermocouple sensors is accomplished by 

an inplace cross calibration that compares the other sensing elements 

with the recently installed sensing element. 

The Frequency is based upon operating experience and consistency with 

the typical industry refueling cycle and is justified by the assumption of an 

[18] month calibration interval for the determination of the magnitude of 

equipment drift. 

REFERENCES [ 1. Plant specific document (e.g., FSAR, NRC Regulatory Guide 1.97, 

SER letter). ] 

 2. Regulatory Guide 1.97. 

 3. NUREG-0737, Supplement 1. 

 4. NRC Safety Evaluation Report (SER). 
Remote Shutdown System (Analog) 

B 3.3.12 

CEOG STS B 3.3.12-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.12 Remote Shutdown System (Analog) 

BASES 

BACKGROUND The Remote Shutdown System provides the control room operator with 

sufficient instrumentation and controls to place and maintain the unit in a 

safe shutdown condition from a location other than the control room. This 

capability is necessary to protect against the possibility that the control 

room becomes inaccessible. A safe shutdown condition is defined as 

MODE 3. With the unit in MODE 3, the [Auxiliary Feedwater (AFW) 

System] and the steam generator safety valves or the steam generator 

atmospheric dump valves can be used to remove core decay heat and 

meet all safety requirements. The long term supply of water for the [AFW 

System] and the ability to borate the Reactor Coolant System (RCS) from 

outside the control room allow extended operation in MODE 3. 

In the event that the control room becomes inaccessible, the operators 

can establish control at the remote shutdown panel and place and 

maintain the unit in MODE 3. Not all controls and necessary transfer 

switches are located at the remote shutdown panel. Some controls and 

transfer switches will be operated locally at the switchgear, motor control 

panels, or other local stations. The unit automatically reaches MODE 3 

following a unit shutdown and can be maintained safely in MODE 3 for an 

extended period of time. 

The OPERABILITY of the Remote Shutdown System control and 

instrumentation Functions ensures that there is sufficient information 

available on selected plant parameters to place and maintain the plant in 

MODE 3, should the control room become inaccessible. 

APPLICABLE The Remote Shutdown System is required to provide equipment at 

SAFETY appropriate locations outside the control room with a capability to 

ANALYSES promptly shut down and maintain the plant in a safe condition in MODE 3. 

The criteria governing the design and the specific system requirements of 

the Remote Shutdown System are located in 10 CFR 50, Appendix A, 

GDC 19, and Appendix R (Ref. 1). 

The Remote Shutdown System satisfies Criterion 4 of 

10 CFR 50.36(c)(2)(ii). 

LCO The Remote Shutdown System LCO provides the requirements for the 

OPERABILITY of the instrumentation and controls necessary to place 

and maintain the unit in MODE 3 from a location other than the control 

room. The instrumentation and controls required are listed in 

Table B 3.3.12-1. 
Remote Shutdown System (Analog) 

B 3.3.12 

CEOG STS B 3.3.12-2 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The controls, instrumentation, and transfer switches are those required 

for: 

• Core Reactivity Control (initial and long term), 

• RCS Pressure Control, 

• Decay Heat Removal via the [AFW System] and the safety valves or 

steam generator ADVs, 

• RCS Inventory Control via charging flow, and 

• Safety support systems for the above Functions, as well as service 

water, component cooling water, and onsite power including the 

diesel generators. 

A Function of a Remote Shutdown System is OPERABLE if all instrument 

and control channels needed to support the remote shutdown Functions 

are OPERABLE. In some cases, Table B 3.3.12-1 may indicate that the 

required information or control capability is available from several 

alternate sources. In these cases, the Function is OPERABLE as long as 

one channel of any of the alternate information or control sources for 

each Function is OPERABLE. 

The Remote Shutdown System instrumentation and control circuits 

covered by this LCO do not need to be energized to be considered 

OPERABLE. This LCO is intended to ensure that the instrument and 

control circuits will be OPERABLE if plant conditions require that the 

Remote Shutdown System be placed in operation. 

APPLICABILITY The Remote Shutdown System LCO is applicable in MODES 1, 2, and 3. 

This is required so that the unit can be placed and maintained in MODE 3 

for an extended period of time from a location other than the control room. 

This LCO is not applicable in MODE 4, 5, or 6. In these MODES, the unit 

is already subcritical and in the condition of reduced RCS energy. Under 

these conditions, considerable time is available to restore necessary 

instrument control Functions if control room instruments or control 

become unavailable. 
Remote Shutdown System (Analog) 

B 3.3.12 

CEOG STS B 3.3.12-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A Remote Shutdown System division is inoperable when each Function is 

not accomplished by at least one designated Remote Shutdown System 

channel that satisfies the OPERABILITY criteria for the channel's 

Function. These criteria are outlined in the LCO section of the Bases. 

A Note has been added in the ACTIONS to clarify the application of 

Completion Time rules. The Conditions of this Specification may be 

entered independently for each Function. The Completion Time(s) of the 

inoperable channel(s)/train(s) of a Function will be tracked separately for 

each Function, starting from the time the Condition was entered for that 

Function. 

A.1

Condition A addresses the situation where one or more channels of the 

Remote Shutdown System are inoperable. This includes the control and 

transfer switches for any required Function. 

The Required Action is to restore the divisions to OPERABLE status 

within 30 days. The Completion Time is based on operating experience 

and the low probability of an event that would require evacuation of the 

control room. 

B.1 and B.2

If the Required Action and associated Completion Time of Condition A 

are not met, the plant must be brought to a MODE in which the LCO does 

not apply. To achieve this status, the plant must be brought to at least 

MODE 3 within 6 hours and to MODE 4 within [12] hours. The allowed 

Completion Times are reasonable, based on operating experience, to 

reach the required MODE from full power conditions in an orderly manner 

and without challenging plant systems. 
Remote Shutdown System (Analog) 

B 3.3.12 

CEOG STS B 3.3.12-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE [ SR 3.3.12.1

REQUIREMENTS 

Performance of the CHANNEL CHECK once every 31 days ensures that 

a gross failure of instrumentation 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 

instrument channels could be an indication of excessive instrument drift in 

one of the channels or of something even more serious. A CHANNEL 

CHECK will detect gross channel failure; thus, it is key to verifying that 

the instrumentation continues to operate properly between each 

CHANNEL CALIBRATION. Agreement criteria are determined by the 

plant staff, based on a combination of the channel instrument 

uncertainties, including indication and readability. If a channel is outside 

the criteria, it may be an indication that the sensor or the signal 

processing equipment has drifted outside its limit. As specified in the 

Surveillance, a CHANNEL CHECK is only required for those channels 

that are normally energized. If the channels are within the criteria, it is an 

indication that the channels are OPERABLE. If the channels are normally 

off scale during times when surveillance is required, the CHANNEL 

CHECK will only verify that they are off scale in the same direction. Off 

scale low current loop channels are verified to be reading at the bottom of 

the range and not failed downscale. 

The Frequency is based on plant operating experience that demonstrates 

channel failure is rare. ]

SR 3.3.12.2

SR 3.3.12.2 verifies that each required Remote Shutdown System 

transfer switch and control circuit performs its intended function. This 

verification is performed from the reactor shutdown panel and locally, as 

appropriate. Operation of the equipment from the remote shutdown panel 

is not necessary. The Surveillance can be satisfied by performance of a 

continuity check. This will ensure that if the control room becomes 

inaccessible, the plant can be placed and maintained in MODE 3 from the 

reactor shutdown panel and the local control stations. 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. Operating experience demonstrates that Remote Shutdown 

System control channels seldom fail to pass the Surveillance when 

performed at a Frequency of once every [18] months. 
Remote Shutdown System (Analog) 

B 3.3.12 

CEOG STS B 3.3.12-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.12.3

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the sensor. The Surveillance verifies that the channel responds 

to the measured parameter within the necessary range and accuracy. 

Whenever a sensing element is replaced, the next required CHANNEL 

CALIBRATION of the resistance temperature detectors (RTD) sensors is 

accomplished by an inplace cross calibration that compares the other 

sensing elements with the recently installed sensing element. 

The 18 month Frequency is based upon 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. 

The SR is modified by a Note, which excludes neutron detectors from the 

CHANNEL CALIBRATION. 

[ SR 3.3.12.4

SR 3.3.12.4 is the performance of a CHANNEL FUNCTIONAL TEST 

every 18 months. A successful test of the required contact(s) of a 

channel relay may be performed by the verification of the change of state 

of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. This Surveillance 

should verify the OPERABILITY of the reactor trip circuit breaker (RTCB) 

open/closed indication on the remote shutdown panels by actuating the 

RTCBs. The Frequency of 18 months was chosen because the RTCBs 

cannot be exercised while the unit is at power. Operating experience has 

shown that these components usually pass the Surveillance when 

performed at a Frequency of once every 18 months. Therefore, the 

Frequency was concluded to be acceptable from a reliability standpoint. ] 

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

2. NRC Safety Evaluation Report (SER). 
Remote Shutdown System (Analog) 

B 3.3.12 

CEOG STS B 3.3.12-6 Rev. 3.0, 03/31/04 

Table B 3.3.12-1 (page 1 of 1) 

Remote Shutdown System Instrumentation and Controls 

-----------------------------------------------------------------------NOTE---------------------------------------------------------------------------- 

This Table is for illustration purposes only. It does not attempt to encompass every Function used at every unit, but 

does contain the types of Functions commonly found. 

------------------------------------------------------------------------------------------------------------------------------------------------------------ 

FUNCTION/INSTRUMENT 

OR CONTROL PARAMETER 

REQUIRED 

NUMBER OF DIVISIONS 

1. Reactivity Control 

 a. Log Power Neutron Flux [1] 

 b. Source Range Neutron Flux [1] 

 c. Reactor Trip Circuit Breaker Position [1 per trip breaker] 

 d. Manual Reactor Trip [2] 

2. Reactor Coolant System Pressure Control 

 a. Pressurizer Pressure or RCS Wide Range 

Pressure 

[1] 

 b. Pressurizer Power Operated Relief Valve Control 

and Block Valve Control 

[1, controls must be for power operated relief 

valve and block valves on same line] 

3. Decay Heat Removal via Steam Generators 

 a. Reactor Coolant\ Hot Leg Temperature [1 per loop] 

 b. Reactor Coolant Cold Leg Temperature [1 per loop] 

 c. Auxiliary Feedwater Controls [1] 

 d. Steam Generator Pressure [1 per steam generator] 

 e. Steam Generator Level or Auxiliary Feedwater 

Flow 

[1 per steam generator] 

 f. Condensate Storage Tank Level [1] 

4. Reactor Coolant System Inventory Control 

 a. Pressurizer Level [1] 

 b. Reactor Coolant Charging Pump Controls [1] 

----------------------------------------------------------------REVIEWER’S NOTE---------------------------------------------------------------- 

The number of channels that fulfill GDC 19 requirements for the number of OPERABLE channels required depends 

upon the plant's licensing basis as described in the NRC plant specific Safety Evaluation Report (SER) (Ref. 2). 

Generally, two divisions are required to be OPERABLE. However, only one channel is required if the plant has 

justified such a design and the NRC's SER accepted the justification. 

------------------------------------------------------------------------------------------------------------------------------------------------------------
Remote Shutdown System (Digital) 

B 3.3.12 

CEOG STS B 3.3.12-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.12 Remote Shutdown System (Digital) 

BASES 

BACKGROUND The Remote Shutdown System provides the control room operator with 

sufficient instrumentation and controls to place and maintain the unit in a 

safe shutdown condition from a location other than the control room. This 

capability is necessary to protect against the possibility that the control 

room becomes inaccessible. A safe shutdown condition is defined as 

MODE 3. With the unit in MODE 3, the [Auxiliary Feedwater (AFW) 

System] and the steam generator safety valves or the steam generator 

atmospheric dump valves can be used to remove core decay heat and 

meet all safety requirements. The long term supply of water for the [AFW 

System] and the ability to borate the Reactor Coolant System (RCS) from 

outside the control room allow extended operation in MODE 3. 

In the event that the control room becomes inaccessible, the operators 

can establish control at the remote shutdown panel and place and 

maintain the unit in MODE 3. Not all controls and necessary transfer 

switches are located at the remote shutdown panel. Some controls and 

transfer switches will be operated locally at the switchgear, motor control 

panels, or other local stations. The unit automatically reaches MODE 3 

following a unit shutdown and can be maintained safely in MODE 3 for an 

extended period of time. 

The OPERABILITY of the Remote Shutdown System control and 

instrumentation Functions ensures that there is sufficient information 

available on selected plant parameters to bring the plant to, and maintain 

it in, MODE 3 should the control room become inaccessible. 

APPLICABLE The Remote Shutdown System is required to provide equipment at 

SAFETY appropriate locations outside the control room with a capability to 

ANALYSES promptly shut down the plant and maintain it in a safe condition in 

MODE 3. 

The criteria governing the design and the specific system requirements of 

the Remote Shutdown System are located in 10 CFR 50, Appendix A, 

GDC 19 (Ref. 1) and Appendix R (Ref. 2). 

The Remote Shutdown System satisfies Criterion 4 of 

10 CFR 50.36(c)(2)(ii). 
Remote Shutdown System (Digital) 

B 3.3.12 

CEOG STS B 3.3.12-2 Rev. 3.0, 03/31/04 

BASES 

LCO The Remote Shutdown System LCO provides the requirements for the 

OPERABILITY of the instrumentation and controls necessary to place 

and maintain the plant in MODE 3 from a location other than the control 

room. The instrumentation and controls required are listed in 

Table B 3.3.12-1. 

The controls, instrumentation, and transfer switches are those required 

for: 

• Reactivity Control (initial and long term), 

• RCS Pressure Control, 

• Decay Heat Removal, 

• RCS Inventory Control, and 

• Safety support systems for the above Functions, as well as service 

water, component cooling water, and onsite power including the 

diesel generators. 

A Function of a Remote Shutdown System is OPERABLE if all instrument 

and control channels needed to support the remote shutdown Functions 

are OPERABLE. In some cases, Table B 3.3.12-1 may indicate that the 

required information or control capability is available from several 

alternate sources. In these cases, the Remote Shutdown System is 

OPERABLE as long as one channel of any of the alternate information or 

control sources for each Function is OPERABLE. 

The Remote Shutdown System instrumentation and control circuits 

covered by this LCO do not need to be energized to be considered 

OPERABLE. This LCO is intended to ensure that the instrument and 

control circuits will be OPERABLE if plant conditions require that the 

Remote Shutdown System be placed in operation. 

APPLICABILITY The Remote Shutdown System LCO is applicable in MODES 1, 2, and 3. 

This is required so that the unit can be placed and maintained in MODE 3 

for an extended period of time from a location other than the control room. 

This LCO is not applicable in MODE 4, 5, or 6. In these MODES, the unit 

is already subcritical and in the condition of reduced RCS energy. Under 

these conditions, considerable time is available to restore necessary 

instrument control Functions if control room instruments or control 

become unavailable. 
Remote Shutdown System (Digital) 

B 3.3.12 

CEOG STS B 3.3.12-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A Remote Shutdown System division is inoperable when each Function is 

not accomplished by at least one designated Remote Shutdown System 

channel that satisfies the OPERABILITY criteria for the channel's 

Function. These criteria are outlined in the LCO section of the Bases. 

A Note has been added in the ACTIONS to clarify the application of 

Completion Time rules. The Conditions of this Specification may be 

entered independently for each Function. The Completion Time(s) of the 

inoperable channel(s)/train(s) of a Function will be tracked separately for 

each Function starting from the time the Condition was entered for that 

Function. 

A.1

Condition A addresses the situation where one or more channels of the 

Remote Shutdown System are inoperable. This includes the control and 

transfer switches for any required Function. 

The Required Action is to restore the divisions to OPERABLE status 

within 30 days. The Completion Time is based on operating experience 

and the low probability of an event that would require evacuation of the 

control room. 

B.1 and B.2

If the Required Action and associated Completion Time of Condition A 

are not met, the plant must be brought to a MODE in which the LCO does 

not apply. To achieve this status, the plant must be brought to at least 

MODE 3 within 6 hours and to MODE 4 within [12] hours. The allowed 

Completion Times are reasonable, based on operating experience, to 

reach the required MODE from full power conditions in an orderly manner 

and without challenging plant systems. 
Remote Shutdown System (Digital) 

B 3.3.12 

CEOG STS B 3.3.12-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE [ SR 3.3.12.1

REQUIREMENTS 

Performance of the CHANNEL CHECK once every 31 days ensures that 

a gross failure of instrumentation 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 

instrument channels could be an indication of excessive instrument drift in 

one of the channels or of something even more serious. A CHANNEL 

CHECK will detect gross channel failure; thus, it is key to verifying that 

the instrumentation continues to operate properly between each 

CHANNEL CALIBRATION. Agreement criteria are determined by the 

plant staff, based on a combination of the channel instrument 

uncertainties, including indication and readability. If a channel is outside 

the criteria, it may be an indication that the sensor or the signal 

processing equipment has drifted outside its limit. As specified in the 

Surveillance, a CHANNEL CHECK is only required for those channels 

that are normally energized. 

The Frequency is based on plant operating experience that demonstrates 

channel failure is rare. ]

SR 3.3.12.2

SR 3.3.12.2 verifies that each required Remote Shutdown System 

transfer switch and control circuit performs its intended function. This 

verification is performed from the reactor shutdown panel and locally, as 

appropriate. Operation of the equipment from the remote shutdown panel 

is not necessary. The Surveillance can be satisfied by performance of a 

continuity check. This will ensure that if the control room becomes 

inaccessible, the plant can be brought to and maintained in MODE 3 from 

the reactor shutdown panel and the local control stations. 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. Operating experience demonstrates that Remote Shutdown 

System control channels seldom fail to pass the Surveillance when 

performed at a Frequency of once every [18] months. 
Remote Shutdown System (Digital) 

B 3.3.12 

CEOG STS B 3.3.12-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.12.3

CHANNEL CALIBRATION is a complete check of the instrument channel 

including the sensor. The Surveillance verifies that the channel responds 

to the measured parameter within the necessary range and accuracy. 

Whenever a sensing element is replaced, the next required CHANNEL 

CALIBRATION of the resistance temperature detectors (RTD) sensors is 

accomplished by an inplace cross calibration that compares the other 

sensing elements with the recently installed sensing element. 

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. 

[ SR 3.3.12.4

SR 3.3.12.4 is the performance of a CHANNEL FUNCTIONAL TEST 

every 18 months. This Surveillance should verify the OPERABILITY of 

the reactor trip circuit breaker (RTCB) open/closed indication on the 

remote shutdown panels by actuating the RTCBs. A successful test of 

the required contact(s) of a channel relay may be performed by the 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. The Frequency of 18 months was chosen because the 

RTCBs cannot be exercised while the unit is at power. Operating 

experience has shown that these components usually pass the 

Surveillance when performed at a Frequency of once every 18 months. 

Therefore, the Frequency was concluded to be acceptable from a 

reliability standpoint. ] 

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

 2. 10 CFR 50, Appendix R. 

 3. NRC Safety Evaluation Report (SER). 
Remote Shutdown System (Digital) 

B 3.3.12 

CEOG STS B 3.3.12-6 Rev. 3.0, 03/31/04 

Table B 3.3.12-1 (page 1 of 1) 

Remote Shutdown System Instrumentation and Controls 

-----------------------------------------------------------------------NOTE---------------------------------------------------------------------------- 

This Table is for illustration purposes only. It does not attempt to encompass every Function used at every unit, but 

does contain the types of Functions commonly found. 

------------------------------------------------------------------------------------------------------------------------------------------------------------ 

FUNCTION/INSTRUMENT 

OR CONTROL PARAMETER 

REQUIRED 

NUMBER OF DIVISIONS 

1. Reactivity Control 

 a. Log Power Neutron Flux [1] 

 b. Source Range Neutron Flux [1] 

 c. Reactor Trip Circuit Breaker Position [1 per trip breaker] 

 d. Manual Reactor Trip [4] 

2. Reactor Coolant System Pressure Control 

 a. Pressurizer Pressure or RCS Wide Range 

Pressure 

[1] 

 b. Pressurizer Power Operated Relief Valve Control 

and Block Valve Control 

[1, controls must be for power operated relief 

valve and block valves on same line] 

3. Decay Heat Removal via Steam Generators 

 a. Reactor Coolant\ Hot Leg Temperature [1 per loop] 

 b. Reactor Coolant Cold Leg Temperature [1 per loop] 

 c. Auxiliary Feedwater Controls [1] 

 d. Steam Generator Pressure [1 per steam generator] 

 e. Steam Generator Level or Auxiliary Feedwater 

Flow 

[1 per steam generator] 

 f. Condensate Storage Tank Level [1] 

4. Reactor Coolant System Inventory Control 

 a. Pressurizer Level [1] 

 b. Reactor Coolant Charging Pump Controls [1] 

----------------------------------------------------------------REVIEWER’S NOTE---------------------------------------------------------------- 

The number of channels that fulfill GDC 19 requirements for the number of OPERABLE channels required depends 

upon the plant's licensing basis as described in the NRC plant specific Safety Evaluation Report (SER) (Ref. 3). 

Generally, two divisions are required to be OPERABLE. However, only one channel is required if the plant has 

justified such a design and the NRC's SER accepted the justification. 

------------------------------------------------------------------------------------------------------------------------------------------------------------
 [Logarithmic] Power Monitoring Channels (Analog) 

B 3.3.13 

CEOG STS B 3.3.13-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.13 [Logarithmic] Power Monitoring Channels (Analog) 

BASES 

BACKGROUND The [logarithmic] power monitoring channels provide neutron flux power 

indication from < 1E-7% RTP to > 100% RTP. They also provide reactor 

protection when the reactor trip circuit breakers (RTCBs) are shut, in the 

form of a Power Rate of Change - High trip (analog plants) or a 

[Logarithmic] Power Level - High trip (digital plants). 

This LCO addresses MODES 3, 4, and 5 with the RTCBs open. When 

the RTCBs are shut, the [logarithmic] power monitoring channels are 

addressed by LCO 3.3.2, "Reactor Protective System (RPS) 

Instrumentation - Shutdown." 

When the RTCBs are open, two of the four wide range power channels 

must be available to monitor neutron flux power. In this application, the 

RPS channels need not be OPERABLE since the reactor trip Function is 

not required. By monitoring neutron flux power when the RTCBs are 

open, loss of SDM caused by boron dilution can be detected as an 

increase in flux. Alarms are also provided when power increases above 

the fixed bistable setpoints. For plants employing separate post accident, 

[logarithmic] nuclear instrumentation channels with adequate range, these 

can be substituted for the [logarithmic] power range channels. Two 

channels must be OPERABLE to provide single failure protection and to 

facilitate detection of channel failure by providing CHANNEL CHECK 

capability. 

APPLICABLE The [logarithmic] power monitoring channels are necessary to monitor 

SAFETY core reactivity changes. They are the primary means for detecting and 

ANALYSES triggering operator actions to respond to reactivity transients initiated from 

conditions in which the RPS is not required to be OPERABLE. They also 

trigger operator actions to anticipate RPS actuation in the event of 

reactivity transients starting from shutdown or low power conditions. The 

[logarithmic] power monitoring channel's LCO requirements support 

compliance with 10 CFR 50, Appendix A, GDC 13 (Ref. 1). The FSAR, 

Chapters [7] and [15] (Refs. 2 and 3, respectively), describes the specific 

[logarithmic] power monitoring channel features that are critical to comply 

with the GDC. 

The OPERABILITY of [logarithmic] power monitoring channels is 

necessary to meet the assumptions of the safety analyses and provide for 

the mitigation of accident and transient conditions. 

The [logarithmic] power monitoring channels satisfy Criterion 3 of 

10 CFR 50.36(c)(2)(ii). 
 [Logarithmic] Power Monitoring Channels (Analog) 

B 3.3.13 

CEOG STS B 3.3.13-2 Rev. 3.0, 03/31/04 

BASES 

LCO The LCO on the [logarithmic] power monitoring channels ensures that 

adequate information is available to verify core reactivity conditions while 

shut down. 

A minimum of two [logarithmic] power monitoring channels are required to 

be OPERABLE. Some plants may have either four or six channels 

capable of performing this function. In these cases, multiple failures may 

be tolerated while the plants are still complying with LCO requirements. 

APPLICABILITY In MODES 3, 4, and 5, with RTCBs open or the Control Element 

Assembly (CEA) Drive System not capable of CEA withdrawal, 

[logarithmic] power monitoring channels must be OPERABLE to monitor 

core power for reactivity changes. In MODES 1 and 2, and in MODES 3, 

4, and 5 with the RTCBs shut and the CEAs capable of withdrawal, the 

[logarithmic] power monitoring channels are addressed as part of the 

RPS in LCO 3.3.1, "Reactor Protective System (RPS) Instrumentation - 

Operating." 

The requirements for source range neutron flux monitoring in MODE 6 

are addressed in LCO 3.9.2, "Nuclear Instrumentation." The source 

range nuclear instrumentation channels provide neutron flux coverage 

extending an additional one to two decades below the [logarithmic] 

channels for use during refueling, when neutron flux may be extremely 

low. They are built into the [logarithmic] neutron flux channels in the 

analog plants and in many of the post accident channels used in both the 

digital and analog plants. 

ACTIONS A.1 and A.2

With one required channel inoperable, it may not be possible to perform a 

CHANNEL CHECK to verify that the other required channel is 

OPERABLE. Therefore, with one or more required channels inoperable, 

the [logarithmic] power monitoring Function cannot be reliably performed. 

Consequently, the Required Actions are the same for one required 

channel inoperable or more than one required channel inoperable. The 

absence of reliable neutron flux indication makes it difficult to ensure 

SDM is maintained. Required Action [A.1] is modified by a Note to 

indicate that normal plant control operations that individually add limited 

positive reactivity (e.g., temperature or boron fluctuations associated with 

RCS inventory management or temperature control) are not precluded by 

this Action, provided they are accounted for in the calculated SDM. 
 [Logarithmic] Power Monitoring Channels (Analog) 

B 3.3.13 

CEOG STS B 3.3.13-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

SDM must be verified periodically to ensure that it is being maintained. 

Both required channels must be restored as soon as possible. The initial 

Completion Time of 4 hours and once every 12 hours thereafter to 

perform SDM verification takes into consideration that Required 

Action A.1 eliminates many of the means by which SDM can be reduced. 

These Completion Times are also based on operating experience in 

performing the Required Actions and the fact that plant conditions will 

change slowly. 

SURVEILLANCE SR 3.3.13.1

REQUIREMENTS 

SR 3.3.13.1 is the performance of a CHANNEL CHECK on each required 

channel every 12 hours. A CHANNEL CHECK is normally a comparison 

of the parameter indicated on one channel to a similar parameter on other 

channels. It is based upon the assumption that instrument channels 

monitoring the same parameter should read approximately the same 

value. Significant deviations between instrument channels could be an 

indication of excessive instrument drift in one of the channels or of 

something even more serious. CHANNEL CHECK will detect gross 

channel failure; thus, it is key to verifying that the instrumentation 

continues to operate properly between each CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff and should be based 

on a combination of the channel instrument uncertainties including control 

isolation, indication, and readability. If a channel is outside the criteria, it 

may be an indication that the transmitter or the signal processing 

equipment has drifted outside its limits. If the channels are within the 

criteria, it is an indication that the channels are OPERABLE. 

The Frequency, about once every shift, is based on operating experience 

that demonstrates the rarity of channel failure. Since the probability of 

two random failures in redundant channels in any 12 hour period is 

extremely low, CHANNEL CHECK minimizes the chance of loss of 

protective function due to failure of redundant channels. CHANNEL 

CHECK supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of displays associated with 

the LCO required channels. 
 [Logarithmic] Power Monitoring Channels (Analog) 

B 3.3.13 

CEOG STS B 3.3.13-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.13.2

A CHANNEL FUNCTIONAL TEST is performed every [92] days to ensure 

that the entire channel is capable of properly indicating neutron flux. A 

successful test of the required contact(s) of a channel relay may be 

performed by the verification of the change of state of a single contact of 

the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL 

TEST of a relay. This is acceptable because all of the other required 

contacts of the relay are verified by other Technical Specifications and 

non-Technical Specifications tests at least once per refueling interval with 

applicable extensions. Internal test circuitry is used to feed preadjusted 

test signals into the preamplifier to verify channel alignment. It is not 

necessary to test the detector, because generating a meaningful test 

signal is difficult; the detectors are of simple construction, and any failures 

in the detectors will be apparent as change in channel output. This 

Frequency is the same as that employed for the same channels in the 

other applicable MODES. [At this unit, the channel trip Functions tested 

by the CHANNEL FUNCTIONAL TEST are as follows:] 

SR 3.3.13.3

SR 3.3.13.3 is the performance of a CHANNEL CALIBRATION. A 

CHANNEL CALIBRATION is performed every [18] months. The 

Surveillance is a complete check and readjustment of the [logarithmic] 

power channel from the preamplifier input through to the remote 

indicators. The Surveillance verifies that the channel responds to a 

measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational between successive surveillances. 

CHANNEL CALIBRATIONS must be performed consistent with the plant 

specific setpoint analysis. 

This SR is modified by a Note to indicate that it is not necessary to test 

the detector because generating a meaningful test signal is difficult; the 

detectors are of simple construction, and any failures in the detectors will 

be apparent as change in channel output. This Frequency is the same as 

that employed for the same channels in the other applicable MODES. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 13. 

 2. FSAR, Chapter [7]. 

 3. FSAR, Chapter [15]. 
 [Logarithmic] Power Monitoring Channels (Digital) 

B 3.3.13 

CEOG STS B 3.3.13-1 Rev. 3.0, 03/31/04 

B 3.3 INSTRUMENTATION 

B 3.3.13 [Logarithmic] Power Monitoring Channels (Digital) 

BASES 

BACKGROUND The [logarithmic] power monitoring channels provide neutron flux power 

indication from < 1E-7% RTP to > 100% RTP. They also provide reactor 

protection when the reactor trip circuit breakers (RTCBs) are shut, in the 

form of a Power Rate of Change - High trip (analog plants) or a 

[Logarithmic] Power Level - High trip (digital plants). 

This LCO addresses MODES 3, 4, and 5 with the RTCBs open. When 

the RTCBs are shut, the [logarithmic] power monitoring channels are 

addressed by LCO 3.3.2, "Reactor Protective System (RPS) 

Instrumentation - Shutdown." 

When the RTCBs are open, two of the four wide range power channels 

must be available to monitor neutron flux power. In this application, the 

RPS channels need not be OPERABLE since the reactor trip Function is 

not required. By monitoring neutron flux (wide range) power when the 

RTCBs are open, loss of SDM caused by boron dilution can be detected 

as an increase in flux. Alarms are also provided when power increases 

above the fixed bistable setpoints. For plants employing separate post 

accident, wide range nuclear instrumentation channels with adequate 

range, these can be substituted for the [logarithmic] power range 

channels. Two channels must be OPERABLE to provide single failure 

protection and to facilitate detection of channel failure by providing 

CHANNEL CHECK capability. 

APPLICABLE The [logarithmic] power monitoring channels are necessary to monitor 

SAFETY core reactivity changes. They are the primary means for detecting and 

ANALYSES triggering operator actions to respond to reactivity transients initiated from 

conditions in which the RPS is not required to be OPERABLE. They also 

trigger operator actions to anticipate RPS actuation in the event of 

reactivity transients starting from shutdown or low power conditions. The 

[logarithmic] power monitoring channel's LCO requirements support 

compliance with 10 CFR 50, Appendix A, GDC 13 (Ref. 1). Reference 2 

describes the specific [logarithmic] power monitoring channel features 

that are critical to comply with the GDC. 

The OPERABILITY of [logarithmic] power monitoring channels is 

necessary to meet the assumptions of the safety analyses and provide for 

the mitigation of accident and transient conditions. 

The [logarithmic] power monitoring channels satisfy Criterion 3 of 

10 CFR 50.36(c)(2)(ii). 
 [Logarithmic] Power Monitoring Channels (Digital) 

B 3.3.13 

CEOG STS B 3.3.13-2 Rev. 3.0, 03/31/04 

BASES 

LCO The LCO on the [logarithmic] power monitoring channels ensures that 

adequate information is available to verify core reactivity conditions while 

shut down. 

A minimum of two [logarithmic] power monitoring channels are required to 

be OPERABLE. Some plants may have four or six channels capable of 

performing this function. In these cases, multiple failures may be 

tolerated while the plants are still complying with LCO requirements. 

APPLICABILITY In MODES 3, 4, and 5, with RTCBs open or the Control Element 

Assembly (CEA) Drive System not capable of CEA withdrawal, 

[logarithmic] power monitoring channels must be OPERABLE to monitor 

core power for reactivity changes. In MODES 1 and 2, and in MODES 3, 

4, and 5, with the RTCBs shut and the CEAs capable of withdrawal, the 

[logarithmic] power monitoring channels are addressed as part of the 

RPS in LCO 3.3.1, "Reactor Protective System (RPS) Instrumentation - 

Operating." 

The requirements for source range neutron flux monitoring in MODE 6 

are addressed in LCO 3.9.2, "Nuclear Instrumentation." The source 

range nuclear instrumentation channels provide neutron flux coverage 

extending an additional one to two decades below the [logarithmic] 

channels for use during refueling, when neutron flux may be extremely 

low. They are built into the [wide range] neutron flux channels in the 

analog plants and in many of the post accident channels used in both the 

digital and analog plants. 

ACTIONS A channel is inoperable when it does not satisfy the OPERABILITY 

criteria for the channel's function. These criteria are outlined in the LCO 

section of the Bases. 

A.1 and A.2

With one required channel inoperable, it may not be possible to perform a 

CHANNEL CHECK to verify that the other required channel is 

OPERABLE. Therefore, with one or more required channels inoperable, 

the [logarithmic] power monitoring Function cannot be reliably performed. 

Consequently, the Required Actions are the same for one required 

channel inoperable or more than one required channel inoperable. The 

absence of reliable neutron flux indication makes it difficult to ensure 

SDM is maintained. Required Action [A.1] is modified by a Note to 

indicate that normal plant control operations that individually add limited 

positive reactivity (e.g., temperature or boron fluctuations associated with 

RCS inventory management or temperature control) are not precluded by 

this Action, provided they are accounted for in the calculated SDM. 
 [Logarithmic] Power Monitoring Channels (Digital) 

B 3.3.13 

CEOG STS B 3.3.13-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

SDM must be verified periodically to ensure that it is being maintained. 

Both required channels must be restored as soon as possible. The initial 

Completion Time of 4 hours and once every 12 hours thereafter to 

perform SDM verification takes into consideration that Required 

Action A.1 eliminates many of the means by which SDM can be reduced. 

These Completion Times are also based on operating experience in 

performing the Required Actions and the fact that plant conditions will 

change slowly. 

SURVEILLANCE SR 3.3.13.1

REQUIREMENTS 

SR 3.3.13.1 is the performance of a CHANNEL CHECK on each required 

channel every 12 hours. A CHANNEL CHECK is normally a comparison 

of the parameter indicated on one channel to a similar parameter on other 

channels. It is based upon the assumption that instrument channels 

monitoring the same parameter should read approximately the same 

value. Significant deviations between instrument channels could be an 

indication of excessive instrument drift in one of the channels or of 

something even more serious. CHANNEL CHECK will detect gross 

channel failure; thus, it is key to verifying that the instrumentation 

continues to operate properly between each CHANNEL CALIBRATION. 

Agreement criteria are determined by the plant staff and should be based 

on a combination of the channel instrument uncertainties including control 

isolation, indication, and readability. If a channel is outside of the criteria, 

it may be an indication that the transmitter or the signal processing 

equipment has drifted outside of its limits. If the channels are within the 

criteria, it is an indication that the channels are OPERABLE. 

The Frequency, about once every shift, is based on operating experience 

that demonstrates the rarity of channel failure. Since the probability of 

two random failures in redundant channels in any 12 hour period is 

extremely low, CHANNEL CHECK minimizes the chance of loss of 

protective function due to failure of redundant channels. CHANNEL 

CHECK supplements less formal, but more frequent, checks of channel 

OPERABILITY during normal operational use of displays associated with 

the LCO required channels. 
 [Logarithmic] Power Monitoring Channels (Digital) 

B 3.3.13 

CEOG STS B 3.3.13-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.3.13.2

A CHANNEL FUNCTIONAL TEST is performed every [92] days to ensure 

that the entire channel is capable of properly indicating neutron flux. 

Internal test circuitry is used to feed preadjusted test signals into the 

preamplifier to verify channel alignment. A successful test of the required 

contact(s) of a channel relay may be performed by the verification of the 

change of state of a single contact of the relay. This clarifies what is an 

acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable 

because all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. It is not necessary 

to test the detector, because generating a meaningful test signal is 

difficult; the detectors are of simple construction, and any failures in the 

detectors will be apparent as change in channel output. This Frequency 

is the same as that employed for the same channels in the other 

applicable MODES. 

[ At this unit, the channel trip Functions tested by the CHANNEL 

FUNCTIONAL TEST are as follows: ]

SR 3.3.13.3

SR 3.3.13.3 is the performance of a CHANNEL CALIBRATION. A 

CHANNEL CALIBRATION is performed every [18] months. The 

Surveillance is a complete check and readjustment of the [logarithmic] 

power channel from the preamplifier input through to the remote 

indicators. The Surveillance verifies that the channel responds to a 

measured parameter within the necessary range and accuracy. 

CHANNEL CALIBRATION leaves the channel adjusted to account for 

instrument drift between successive calibrations to ensure that the 

channel remains operational. CHANNEL CALIBRATIONS must be 

performed consistent with the plant specific setpoint analysis. 

This SR is modified by a Note to indicate that it is not necessary to test 

the detector, because generating a meaningful test signal is difficult; the 

detectors are of simple construction, and any failures in the detectors will 

be apparent as change in channel output. This test interval is the same 

as that employed for the same channels in the other applicable MODES. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 13. 

 2. FSAR, Chapter [7] and Chapter [15]. 
RCS Pressure, Temperature, and Flow [DNB] Limits 

B 3.4.1 

CEOG STS B 3.4.1-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.1 RCS Pressure, Temperature, and Flow [Departure from Nucleate Boiling (DNB)] Limits 

BASES 

BACKGROUND These Bases address requirements for maintaining RCS pressure, 

temperature, and flow rate within limits assumed in the safety analyses. 

The safety analyses (Ref. 1) of normal operating conditions and 

anticipated operational occurrences assume initial conditions within the 

normal steady state envelope. The limits placed on departure from 

nucleate boiling (DNB) related parameters ensure that these parameters 

will not be less conservative than were assumed in the analyses and 

thereby provide assurance that the minimum departure from nucleate 

boiling ratio (DNBR) will meet the required criteria for each of the 

transients analyzed. 

The LCO limits for minimum and maximum RCS pressures as measured 

at the pressurizer are consistent with operation within the nominal 

operating envelope and are bounded by those used as the initial 

pressures in the analyses. 

The LCO limits for minimum and maximum RCS cold leg temperatures 

are consistent with operation at the indicated power level and are 

bounded by those used as the initial temperatures in the analyses. 

The LCO limits for minimum RCS flow rate is bounded by the initial flow 

rate in the analyses. The RCS flow rate is not expected to vary during 

plant operation with all pumps running. 

APPLICABLE The requirements of LCO 3.4.1 represent the initial conditions for DNB 

SAFETY limited transients analyzed in the safety analyses (Ref. 1). The safety 

ANALYSES analyses have shown that transients initiated from the limits of this LCO 

will meet the DNBR criterion of ≥ [1.3]. This is the acceptance limit for the 

RCS DNB parameters. Changes to the facility that could impact these 

parameters must be assessed for their impact on the DNBR criterion. 

The transients analyzed for include loss of coolant flow events and 

dropped or struck control element assembly (CEA) events. A key 

assumption for the analysis of these events is that the core power 

distribution is within the limits of [LCO 3.1.6, "Regulating CEA Insertion 

Limits," LCO 3.1.7, "Part Length CEA Insertion Limits," LCO 3.2.3, 

"AZIMUTHAL POWER TILT (Tq)," and LCO 3.2.5, "AXIAL SHAPE INDEX 

(ASI)"]. The safety analyses are performed over the following range of 

initial values: RCS pressure [1785-2400] psig, core inlet temperature 

[500-580]°F, and reactor vessel inlet coolant flow rate > [95]%. 

The RCS DNB limits satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii). 
RCS Pressure, Temperature, and Flow [DNB] Limits 

B 3.4.1 

CEOG STS B 3.4.1-2 Rev. 3.0, 03/31/04 

BASES 

LCO This LCO specifies limits on the monitored process variables - RCS 

pressurizer pressure, RCS cold leg temperature, and RCS total flow rate - 

to ensure that the core operates within the limits assumed for the plant 

safety analyses. Operating within these limits will result in meeting the 

DNBR criterion in the event of a DNB limited transient. 

The LCO numerical values for pressure, temperature, and flow rate are 

given for the measurement location but have not been adjusted for 

instrument error. Plant specific limits of instrument error are established 

by the plant staff to meet the operational requirements of this LCO. 

APPLICABILITY In MODE 1, the limits on RCS pressurizer pressure, RCS cold leg 

temperature, and RCS flow rate must be maintained during steady state 

operation in order to ensure that DNBR criteria will be met in the event of 

an unplanned loss of forced coolant flow or other DNB limited transient. 

In all other MODES, the power level is low enough so that DNBR is not a 

concern. 

A Note has been added to indicate the limit on pressurizer pressure may 

be exceeded during short term operational transients such as a 

THERMAL POWER ramp increase of > 5% RTP per minute or a 

THERMAL POWER step increase of > 10% RTP. These conditions 

represent short term perturbations where actions to control pressure 

variations might be counterproductive. Also, since they represent 

transients initiated from power levels < 100% RTP, an increased DNBR 

margin exists to offset the temporary pressure variations. 

Another set of limits on DNB related parameters is provided in Safety 

Limit (SL) 2.1.1, "Reactor Core Safety Limits." Those limits are less 

restrictive than the limits of this LCO, but violation of SLs merits a stricter, 

more severe Required Action. Should a violation of this LCO occur, the 

operator should check whether or not an SL may have been exceeded. 

ACTIONS A.1

Pressurizer pressure is a controllable and measurable parameter. RCS 

flow rate is not a controllable parameter and is not expected to vary 

during steady state operation. With either parameter not within the LCO 

limits, action must be taken to restore the out of limit parameter. 

The 2 hour Completion Time for restoration of the parameters provides 

sufficient time to adjust plant parameters, to determine the cause of the 

off normal condition, and to restore the readings within limits. The 

Completion Time is based on plant operating experience that shows the 

parameter can be restored in this time period. 
RCS Pressure, Temperature, and Flow [DNB] Limits 

B 3.4.1 

CEOG STS B 3.4.1-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1

If Required Action A.1 is not met within the associated Completion Time, 

the plant must be brought to a MODE in which the LCO does not apply. 

To achieve this status, the plant must be brought to at least MODE 2 

within 6 hours. In MODE 2, the reduced power condition eliminates the 

potential for violation of the accident analysis bounds. 

Six hours is a reasonable time that permits the plant power to be reduced 

at an orderly rate in conjunction with even control of steam generator 

(SG) heat removal. 

C.1

Cold leg temperature is a controllable and measurable parameter. If this 

parameter is not within the LCO limits, action must be taken to restore the 

parameter. 

The 2 hour Completion Time is based on plant operating experience that 

shows that the parameter can be restored in this time period. 

D.1

If Required Action C.1 is not met within the associated Completion Time, 

THERMAL POWER must be reduced to ≤ [30%] RTP. Plant operation 

may continue for an indefinite period of time in this condition. At the 

reduced power level, the potential for violation of the DNB limits is greatly 

reduced. 

The 6 hour Completion Time is a reasonable time that permits power 

reduction at an orderly rate in conjunction with even control of SG heat 

removal. 

SURVEILLANCE SR 3.4.1.1

REQUIREMENTS 

Since Required Action A.1 allows a Completion Time of 2 hours to restore 

parameters that are not within limits, the 12 hour Surveillance Frequency 

for pressurizer pressure is sufficient to ensure that the pressure can be 

restored to a normal operation, steady state condition following load 

changes and other expected transient operations. The 12 hour interval 

has been shown by operating practice to be sufficient to regularly assess 

for potential degradation and verify operation is within safety analysis 

assumptions. 
RCS Pressure, Temperature, and Flow [DNB] Limits 

B 3.4.1 

CEOG STS B 3.4.1-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.4.1.2

Since Required Action A.1 allows a Completion Time of 2 hours to restore 

parameters that are not within limits, the 12 hour Surveillance Frequency 

for cold leg temperature is sufficient to ensure that the RCS coolant 

temperature can be restored to a normal operation, steady state condition 

following load changes and other expected transient operations. The 

12 hour 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. 

SR 3.4.1.3

The 12 hour Surveillance Frequency for RCS total flow rate is performed 

using the installed flow instrumentation. The 12 hour Frequency has 

been shown by operating experience to be sufficient to assess for 

potential degradation and to verify operation is within safety analysis 

assumptions. 

This SR is modified by a Note that only requires performance of this SR in 

MODE 1. The Note is necessary to allow measurement of RCS flow rate 

at normal operating conditions at power with all RCPs running. 

SR 3.4.1.4

Measurement of RCS total flow rate by performance of a precision 

calorimetric heat balance once every [18] months. This allows the 

installed RCS flow instrumentation to be calibrated and verifies that the 

actual RCS flow rate is within the bounds of the analyses. 

The Frequency of [18] months reflects the importance of verifying flow 

after a refueling outage where the core has been altered, which may have 

caused an alteration of flow resistance. 

The SR is modified by a Note that states the SR is only required to be 

performed [24] hours after ≥ [90]% RTP. The Note is necessary to allow 

measurement of the flow rate at normal operating conditions at power in 

MODE 1. The Surveillance cannot be performed in MODE 2 or below, 

and will not yield accurate results if performed below 90% RTP. 

REFERENCES 1. FSAR, Section [15]. 
RCS Minimum Temperature for Criticality 

B 3.4.2 

CEOG STS B 3.4.2-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.2 RCS Minimum Temperature for Criticality 

BASES 

BACKGROUND Establishing the value for the minimum temperature for reactor criticality 

is based upon considerations for: 

a. Operation within the existing instrumentation ranges and accuracies, 

b. Operation within the bounds of the existing accident analyses, and 

c. Operation with the reactor vessel above its minimum nil ductility 

reference temperature when the reactor is critical. 

The reactor coolant moderator temperature coefficient used in core 

operating and accident analysis is typically defined for the normal 

operating temperature range (532°F to 573°F). The Reactor Protection 

System receives inputs from the narrow range hot leg temperature 

detectors, which have a range of 520°F to 620°F. The RCS loop average 

temperature (Tavg) is controlled using inputs of the same range. Nominal 

Tavg for making the reactor critical is 532°F. Safety and operating 

analyses for lower temperature have not been made. 

APPLICABLE There are no accident analyses that dictate the minimum temperature for 

SAFETY criticality, but all low power safety analyses assume initial temperatures 

ANALYSES near the [520]°F limit (Ref. 1). 

The RCS minimum temperature for criticality satisfies Criterion 2 of 

10 CFR 50.36(c)(2)(ii). 

LCO The purpose of the LCO is to prevent criticality outside the normal 

operating regime (532°F to 573°F) and to prevent operation in an 

unanalyzed condition. 

The LCO is only applicable below [535]°F and provides a reasonable 

distance to the limit of [520]°F. This allows adequate time to trend its 

approach and take corrective actions prior to exceeding the limit. 

APPLICABILITY The reactor has been designed and analyzed to be critical in MODES 1 

and 2 only and in accordance with this specification. Criticality is not 

permitted in any other MODE. Therefore, this LCO is applicable in 

MODE 1, and MODE 2 when Keff ≥ 1.0. Coupled with the applicability 

definition for criticality is a temperature limit. Monitoring is required at or 

below a Tavg of [535]°F. The no load temperature of 544°F is maintained 

by the Steam Dump Control System. 
RCS Minimum Temperature for Criticality 

B 3.4.2 

CEOG STS B 3.4.2-2 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

If Tavg is below [520]°F, the plant must be brought to a MODE in which the 

LCO does not apply. To achieve this status, the plant must be brought to 

MODE 2 with Keff < 1.0 within 30 minutes. Rapid reactor shutdown can 

be readily and practically achieved within a 30 minute period. The 

allowed time reflects the ability to perform this action and to maintain the 

plant within the analyzed range. 

SURVEILLANCE SR 3.4.2.1

REQUIREMENTS 

RCS loop average temperature is required to be verified at or above 

[520]°F every 12 hours. The SR to verify RCS loop average 

temperatures every 12 hours 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. In addition, operators are trained to be sensitive to RCS 

temperature during approach to criticality and will ensure that the 

minimum temperature for criticality is met as criticality is approached. 

REFERENCES 1. FSAR, Section [15]. 
RCS P/T Limits 

B 3.4.3 

CEOG STS B 3.4.3-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.3 RCS Pressure and Temperature (P/T) Limits 

BASES 

BACKGROUND All components of the RCS are designed to withstand effects of cyclic 

loads due to system pressure and temperature changes. These loads 

are introduced by startup (heatup) and shutdown (cooldown) operations, 

power transients, and reactor trips. This LCO limits the pressure and 

temperature changes during RCS heatup and cooldown, within the design 

assumptions and the stress limits for cyclic operation. 

The PTLR contains P/T limit curves for heatup, cooldown, and inservice 

leak and hydrostatic (ISLH) testing, and data for the maximum rate of 

change of reactor coolant temperature (Ref. 1). 

Each P/T limit curve defines an acceptable region for normal operation. 

The usual use of the curves is operational guidance during heatup or 

cooldown maneuvering, when pressure and temperature indications are 

monitored and compared to the applicable curve to determine that 

operation is within the allowable region. 

The LCO establishes operating limits that provide a margin to brittle 

failure of the reactor vessel and piping of the reactor coolant pressure 

boundary (RCPB). The vessel is the component most subject to brittle 

failure, and the LCO limits apply mainly to the vessel. The limits do not 

apply to the pressurizer, which has different design characteristics and 

operating functions. 

10 CFR 50, Appendix G (Ref. 2), requires the establishment of P/T limits 

for material fracture toughness requirements of the RCPB materials. 

Reference 2 requires an adequate margin to brittle failure during normal 

operation, anticipated operational occurrences, and system hydrostatic 

tests. It mandates the use of the ASME Code, Section III, Appendix G 

(Ref. 3). 

The actual shift in the RTNDT of the vessel material will be established 

periodically by removing and evaluating the irradiated reactor vessel 

material specimens, in accordance with ASTM E 185 (Ref. 4) and 

Appendix H of 10 CFR 50 (Ref. 5). The operating P/T limit curves will be 

adjusted, as necessary, based on the evaluation findings and the 

recommendations of Reference 3. 
RCS P/T Limits 

B 3.4.3 

CEOG STS B 3.4.3-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The P/T limit curves are composite curves established by superimposing 

limits derived from stress analyses of those portions of the reactor vessel 

and head that are the most restrictive. At any specific pressure, 

temperature, and temperature rate of change, one location within the 

reactor vessel will dictate the most restrictive limit. Across the span of the 

P/T limit curves, different locations are more restrictive, and, thus, the 

curves are composites of the most restrictive regions. 

The heatup curve represents a different set of restrictions than the 

cooldown curve because the directions of the thermal gradients through 

the vessel wall are reversed. The thermal gradient reversal alters the 

location of the tensile stress between the outer and inner walls. 

The criticality limit includes the Reference 2 requirement that the limit be 

no less than 40°F above the heatup curve or the cooldown curve and not 

less than the minimum permissible temperature for the ISLH testing. 

However, the criticality limit is not operationally limiting; a more restrictive 

limit exists in LCO 3.4.2, "RCS Minimum Temperature for Criticality." 

The consequence of violating the LCO limits is that the RCS has been 

operated under conditions that can result in brittle failure of the RCPB, 

possibly leading to a nonisolable leak or loss of coolant accident. In the 

event these limits are exceeded, an evaluation must be performed to 

determine the effect on the structural integrity of the RCPB components. 

The ASME Code, Section XI, Appendix E (Ref. 6), provides a 

recommended methodology for evaluating an operating event that causes 

an excursion outside the limits. 

APPLICABLE The P/T limits are not derived from Design Basis Accident (DBA) 

SAFETY Analyses. They are prescribed during normal operation to avoid 

ANALYSES encountering pressure, temperature, and temperature rate of change 

conditions that might cause undetected flaws to propagate and cause 

nonductile failure of the RCPB, an unanalyzed condition. Reference 1 

establishes the methodology for determining the P/T limits. Since the P/T 

limits are not derived from any DBA, there are no acceptance limits 

related to the P/T limits. Rather, the P/T limits are acceptance limits 

themselves since they preclude operation in an unanalyzed condition. 

The RCS P/T limits satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii). 
RCS P/T Limits 

B 3.4.3 

CEOG STS B 3.4.3-3 Rev. 3.0, 03/31/04 

BASES 

LCO The two elements of this LCO are: 

a. The limit curves for heatup, cooldown, and ISLH testing and 

b. Limits on the rate of change of temperature. 

The LCO limits apply to all components of the RCS, except the 

pressurizer. 

These limits define allowable operating regions and permit a large 

number of operating cycles while providing a wide margin to nonductile 

failure. 

The limits for the rate of change of temperature control the thermal 

gradient through the vessel wall and are used as inputs for calculating the 

heatup, cooldown, and ISLH testing P/T limit curves. Thus, the LCO for 

the rate of change of temperature restricts stresses caused by thermal 

gradients and also ensures the validity of the P/T limit curves. 

Violating the LCO limits places the reactor vessel outside of the bounds of 

the stress analyses and can increase stresses in other RCPB 

components. The consequences depend on several factors, as follows: 

a. The severity of the departure from the allowable operating P/T 

regime or the severity of the rate of change of temperature, 

b. The length of time the limits were violated (longer violations allow the 

temperature gradient in the thick vessel walls to become more 

pronounced), and 

c. The existences, sizes, and orientations of flaws in the vessel 

material. 

APPLICABILITY The RCS P/T limits Specification provides a definition of acceptable 

operation for prevention of nonductile failure in accordance with 

10 CFR 50, Appendix G (Ref. 2). Although the P/T limits were developed 

to provide guidance for operation during heatup or cooldown (MODES 3, 

4, and 5) or ISLH testing, their Applicability is at all times in keeping with 

the concern for nonductile failure. The limits do not apply to the 

pressurizer. 

During MODES 1 and 2, other Technical Specifications provide limits for 

operation that can be more restrictive than or can supplement these P/T 

limits. LCO 3.4.1, "RCS Pressure, Temperature, and Flow Departure 

from Nucleate Boiling (DNB) Limits," LCO 3.4.2, "RCS Minimum 
RCS P/T Limits 

B 3.4.3 

CEOG STS B 3.4.3-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY (continued) 

Temperature for Criticality," and Safety Limit 2.1, "Safety Limits," also 

provide operational restrictions for pressure and temperature and 

maximum pressure. Furthermore, MODES 1 and 2 are above the 

temperature range of concern for nonductile failure, and stress analyses 

have been performed for normal maneuvering profiles, such as power 

ascension or descent. 

The actions of this LCO consider the premise that a violation of the limits 

occurred during normal plant maneuvering. Severe violations caused by 

abnormal transients, at times accompanied by equipment failures, may 

also require additional actions from emergency operating procedures. 

ACTIONS A.1 and A.2

Operation outside the P/T limits must be corrected so that the RCPB is 

returned to a condition that has been verified by stress analyses. 

The 30 minute Completion Time reflects the urgency of restoring the 

parameters to within the analyzed range. Most violations will not be 

severe, and the activity can be accomplished in this time in a controlled 

manner. 

Besides restoring operation to within limits, an evaluation is required to 

determine if RCS operation can continue. The evaluation must verify the 

RCPB integrity remains acceptable and must be completed before 

continuing operation. Several methods may be used, including 

comparison with pre-analyzed transients in the stress analyses, new 

analyses, or inspection of the components. 

ASME Code, Section XI, Appendix E (Ref. 6), may be used to support the 

evaluation. However, its use is restricted to evaluation of the vessel 

beltline. 

The 72 hour Completion Time is reasonable to accomplish the evaluation. 

The evaluation for a mild violation is possible within this time, but more 

severe violations may require special, event specific stress analyses or 

inspections. A favorable evaluation must be completed before continuing 

to operate. 

Condition A is modified by a Note requiring Required Action A.2 to be 

completed whenever the Condition is entered. The Note emphasizes the 

need to perform the evaluation of the effects of the excursion outside the 

allowable limits. Restoration alone per Required Action A.1 is insufficient 

because higher than analyzed stresses may have occurred and may have 

affected the RCPB integrity. 
RCS P/T Limits 

B 3.4.3 

CEOG STS B 3.4.3-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1 and B.2

If a Required Action and associated Completion Time of Condition A are 

not met, the plant must be placed in a lower MODE because: 

a. The RCS remained in an unacceptable P/T region for an extended 

period of increased stress or 

b. A sufficiently severe event caused entry into an unacceptable region. 

Either possibility indicates a need for more careful examination of the 

event, best accomplished with the RCS at reduced pressure and 

temperature. With reduced pressure and temperature conditions, the 

possibility of propagation of undetected flaws is decreased. 

Pressure and temperature are reduced by placing the plant in MODE 3 

within 6 hours and in MODE 5 with RCS pressure < [500] psig within 

36 hours. 

The Completion Times are reasonable, based on operating experience, to 

reach the required plant conditions from full power conditions in an 

orderly manner and without challenging plant systems. 

C.1 and C.2

The actions of this LCO, anytime other than in MODE 1, 2, 3, or 4, 

consider the premise that a violation of the limits occurred during normal 

plant maneuvering. Severe violations caused by abnormal transients, at 

times accompanied by equipment failures, may also require additional 

actions from emergency operating procedures. Operation outside the P/T 

limits must be corrected so that the RCPB is returned to a condition that 

has been verified by stress analyses. 

The Completion Time of "immediately" reflects the urgency of restoring 

the parameters to within the analyzed range. Most violations will not be 

severe, and the activity can be accomplished in a short period of time in a 

controlled manner. 

Besides restoring operation to within limits, an evaluation is required to 

determine if RCS operation can continue. The evaluation must verify that 

the RCPB integrity remains acceptable and must be completed before 

continuing operation. Several methods may be used, including 

comparison with pre-analyzed transients in the stress analyses, new 

analyses, or inspection of the components. 
RCS P/T Limits 

B 3.4.3 

CEOG STS B 3.4.3-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

ASME Code, Section XI, Appendix E (Ref. 6), may be used to support the 

evaluation. However, its use is restricted to evaluation of the vessel 

beltline. 

The Completion Time of prior to entering MODE 4 forces the evaluation 

prior to entering a MODE where temperature and pressure can be 

significantly increased. The evaluation for a mild violation is possible 

within several days, but more severe violations may require special, event 

specific stress analyses or inspections. 

Condition C is modified by a Note requiring Required Action C.2 to be 

completed whenever the Condition is entered. The Note emphasizes the 

need to perform the evaluation of the effects of the excursion outside the 

allowable limits. Restoration alone per Required Action C.1 is insufficient 

because higher than analyzed stresses may have occurred and may have 

affected the RCPB integrity. 

SURVEILLANCE SR 3.4.3.1

REQUIREMENTS 

Verification that operation is within the PTLR limits is required every 

30 minutes when RCS pressure and temperature conditions are 

undergoing planned changes. This Frequency is considered reasonable 

in view of the control room indication available to monitor RCS status. 

Also, since temperature rate of change limits are specified in hourly 

increments, 30 minutes permits assessment and correction for minor 

deviations within a reasonable time. 

Surveillance for heatup, cooldown, or ISLH testing may be discontinued 

when the definition given in the relevant plant procedure for ending the 

activity is satisfied. 

This SR is modified by a Note that requires this SR be performed only 

during RCS system heatup, cooldown, and ISLH testing. No SR is given 

for criticality operations because LCO 3.4.2 contains a more restrictive 

requirement. 
RCS P/T Limits 

B 3.4.3 

CEOG STS B 3.4.3-7 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. [NRC approved topical report that defines the methodology for 

determining the P/T limits]. 

 2. 10 CFR 50, Appendix G. 

 3. ASME, Boiler and Pressure Vessel Code, Section III, Appendix G. 

 4. ASTM E 185-82, July 1982. 

 5. 10 CFR 50, Appendix H. 

 6. ASME, Boiler and Pressure Vessel Code, Section XI, Appendix E. 
RCS Loops - MODES 1 and 2 

B 3.4.4 

CEOG STS B 3.4.4-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.4 RCS Loops - MODES 1 and 2 

BASES 

BACKGROUND The primary function of the RCS is removal of the heat generated in the 

fuel due to the fission process and transfer of this heat, via the steam 

generators (SGs), to the secondary plant. 

The secondary functions of the RCS include: 

a. Moderating the neutron energy level to the thermal state, to increase 

the probability of fission, 

b. Improving the neutron economy by acting as a reflector, 

c. Carrying the soluble neutron poison, boric acid, 

d. Providing a second barrier against fission product release to the 

environment, and 

e. Removing the heat generated in the fuel due to fission product decay 

following a unit shutdown. 

The RCS configuration for heat transport uses two RCS loops. Each 

RCS loop contains a SG and two reactor coolant pumps (RCPs). An 

RCP is located in each of the two SG cold legs. The pump flow rate has 

been sized to provide core heat removal with appropriate margin to 

departure from nucleate boiling (DNB) during power operation and for 

anticipated transients originating from power operation. This 

Specification requires two RCS loops with both RCPs in operation in each 

loop. The intent of the Specification is to require core heat removal with 

forced flow during power operation. Specifying two RCS loops provides 

the minimum necessary paths (two SGs) for heat removal. 

APPLICABLE Safety analyses contain various assumptions for the Design Bases 

SAFETY Accident (DBA) initial conditions including RCS pressure, RCS 

ANALYSES temperature, reactor power level, core parameters, and safety system 

setpoints. The important aspect for this LCO is the reactor coolant forced 

flow rate, which is represented by the number of RCS loops in service. 
RCS Loops - MODES 1 and 2 

B 3.4.4 

CEOG STS B 3.4.4-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Both transient and steady state analyses have been performed to 

establish the effect of flow on DNB. The transient or accident analysis for 

the plant has been performed assuming four RCPs are in operation. The 

majority of the plant safety analyses are based on initial conditions at high 

core power or zero power. The accident analyses that are of most 

importance to RCP operation are the four pump coastdown, single pump 

locked rotor, single pump (broken shaft or coastdown), and rod 

withdrawal events (Ref. 1). 

Steady state DNB analysis had been performed for the [four] pump 

combination. For [four] pump operation, the steady state DNB analysis, 

which generates the pressure and temperature and Safety Limit (i.e., the 

departure from nucleate boiling ratio (DNBR) limit), assumes a maximum 

power level of 107% RTP. This is the design overpower condition for four 

pump operation. The 107% value is the accident analysis setpoint of the 

nuclear overpower (high flux) trip and is based on an analysis assumption 

that bounds possible instrumentation errors. The DNBR limit defines a 

locus of pressure and temperature points that result in a minimum DNBR 

greater than or equal to the critical heat flux correlation limit. 

RCS Loops - MODES 1 and 2 satisfy Criteria 2 and 3 of 

10 CFR 50.36(c)(2)(ii). 

LCO The purpose of this LCO is to require adequate forced flow for core heat 

removal. Flow is represented by having both RCS loops with both RCPs 

in each loop in operation for removal of heat by the two SGs. To meet 

safety analysis acceptance criteria for DNB, four pumps are required at 

rated power. 

Each OPERABLE loop consists of two RCPs providing forced flow for 

heat transport to an SG that is OPERABLE in accordance with the Steam 

Generator Tube Surveillance Program. SG, and hence RCS loop, 

OPERABILITY with regard to SG water level is ensured by the Reactor 

Protection System (RPS) in MODES 1 and 2. A reactor trip places the 

plant in MODE 3 if any SG level is ≤ [25]% as sensed by the RPS. The 

minimum water level to declare the SG OPERABLE is [25]%. 

APPLICABILITY In MODES 1 and 2, the reactor is critical and thus has the potential to 

produce maximum THERMAL POWER. Thus, to ensure that the 

assumptions of the accident analyses remain valid, all RCS loops are 

required to be OPERABLE and in operation in these MODES to prevent 

DNB and core damage. 
RCS Loops - MODES 1 and 2 

B 3.4.4 

CEOG STS B 3.4.4-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY (continued) 

The decay heat production rate is much lower than the full power heat 

rate. As such, the forced circulation flow and heat sink requirements are 

reduced for lower, noncritical MODES as indicated by the LCOs for 

MODES 3, 4, 5, and 6. 

Operation in other MODES is covered by: 

LCO 3.4.5, "RCS Loops - MODE 3," 

LCO 3.4.6, "RCS Loops - MODE 4," 

LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled," 

LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled," 

LCO 3.9.4, "Shutdown Cooling (SDC) and Coolant Circulation - High 

 Water Level" (MODE 6), and 

LCO 3.9.5, "Shutdown Cooling (SDC) and Coolant Circulation - Low 

 Water Level" (MODE 6). 

ACTIONS A.1

If the requirements of the LCO are not met, the Required Action is to 

reduce power and bring the plant to MODE 3. This lowers power level 

and thus reduces the core heat removal needs and minimizes the 

possibility of violating DNB limits. It should be noted that the reactor will 

trip and place the plant in MODE 3 as soon as the RPS senses less than 

four RCPs operating. 

The Completion Time of 6 hours is reasonable, based on operating 

experience, to reach MODE 3 from full power conditions in an orderly 

manner and without challenging safety systems. 

SURVEILLANCE SR 3.4.4.1

REQUIREMENTS 

This SR requires verification every 12 hours of the required number of 

loops in operation. Verification includes flow rate, temperature, or pump 

status monitoring, which help to ensure that forced flow is providing heat 

removal while maintaining the margin to DNB. The Frequency of 

12 hours has been shown by operating practice to be sufficient to 

regularly assess degradation and verify operation within safety analyses 

assumptions. In addition, control room indication and alarms will normally 

indicate loop status. 

REFERENCES 1. FSAR, Section [ ]. 
RCS Loops - MODE 3 

B 3.4.5 

CEOG STS B 3.4.5-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.5 RCS Loops - MODE 3 

BASES 

BACKGROUND The primary function of the reactor coolant in MODE 3 is removal of 

decay heat and transfer of this heat, via the steam generators (SGs), to 

the secondary plant fluid. The secondary function of the reactor coolant 

is to act as a carrier for soluble neutron poison, boric acid. 

In MODE 3, reactor coolant pumps (RCPs) are used to provide forced 

circulation heat removal during heatup and cooldown. The MODE 3 

decay heat removal requirements are low enough that a single RCS loop 

with one RCP is sufficient to remove core decay heat. However, [two] 

RCS loops are required to be OPERABLE to provide redundant paths for 

decay heat removal. Only one RCP needs to be OPERABLE to declare 

the associated RCS loop OPERABLE. 

Reactor coolant natural circulation is not normally used but is sufficient for 

core cooling. However, natural circulation does not provide turbulent flow 

conditions. Therefore, boron reduction in natural circulation is prohibited 

because mixing to obtain a homogeneous concentration in all portions of 

the RCS cannot be ensured. 

APPLICABLE Analyses have shown that the rod withdrawal event from MODE 3 with 

SAFETY one RCS loop in operation is bounded by the rod withdrawal initiated 

ANALYSES from MODE 2. 

Failure to provide heat removal may result in challenges to a fission 

product barrier. The RCS loops are part of the primary success path that 

functions or actuates to prevent or mitigate a Design Basis Accident or 

transient that either assumes the failure of, or presents a challenge to, the 

integrity of a fission product barrier. 

RCS Loops - MODE 3 satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The purpose of this LCO is to require both RCS loops to be available for 

heat removal, thus providing redundancy. The LCO requires both loops 

to be OPERABLE with the intent of requiring both SGs to be capable 

(> 25% water level) of transferring heat from the reactor coolant at a 

controlled rate. Forced reactor coolant flow is the required way to 

transport heat, although natural circulation flow provides adequate 

removal. A minimum of one running RCP meets the LCO requirement for 

one loop in operation. 
RCS Loops - MODE 3 

B 3.4.5 

CEOG STS B 3.4.5-2 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The Note permits a limited period of operation without RCPs. All RCPs 

may be removed from operation for ≤ 1 hour per 8 hour period. This 

means that natural circulation has been established. When in natural 

circulation, a reduction in boron concentration with coolant at boron 

concentrations less than required to assure the SDM of LCO 3.1.1 is 

maintained is prohibited because an even concentration distribution 

throughout the RCS cannot be ensured. Core outlet temperature is to be 

maintained at least 10°F below the saturation temperature so that no 

vapor bubble may form and possibly cause a natural circulation flow 

obstruction. 

In MODES 3, 4, and 5, it is sometimes necessary to stop all RCPs or 

shutdown cooling (SDC) pump forced circulation (e.g., to change 

operation from one SDC train to the other, to perform surveillance or 

startup testing, to perform the transition to and from SDC System cooling, 

or to avoid operation below the RCP minimum net positive suction head 

limit). The time period is acceptable because natural circulation is 

adequate for heat removal, or the reactor coolant temperature can be 

maintained subcooled and boron stratification affecting reactivity control is 

not expected. 

An OPERABLE RCS loop consists of at least one OPERABLE RCP and 

an SG that is OPERABLE in accordance with the Steam Generator Tube 

Surveillance Program. A RCP is OPERABLE if it is capable of being 

powered and is able to provide forced flow if required. 

APPLICABILITY In MODE 3, the heat load is lower than at power; therefore, one RCS loop 

in operation is adequate for transport and heat removal. A second RCS 

loop is required to be OPERABLE but not in operation for redundant heat 

removal capability. 

Operation in other MODES is covered by: 

LCO 3.4.4, "RCS Loops - MODES 1 and 2," 

LCO 3.4.6, "RCS Loops - MODE 4," 

LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled," 

LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled," 

LCO 3.9.4, "Shutdown Cooling (SDC) and Coolant Circulation - High 

 Water Level" (MODE 6), and 

LCO 3.9.5, "Shutdown Cooling (SDC) and Coolant Circulation - Low 

 Water Level" (MODE 6). 
RCS Loops - MODE 3 

B 3.4.5 

CEOG STS B 3.4.5-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

If one RCS loop is inoperable, redundancy for forced flow heat removal is 

lost. The Required Action is restoration of the RCS loop to OPERABLE 

status within a Completion Time of 72 hours. This time allowance is a 

justified period to be without the redundant, nonoperating loop because a 

single loop in operation has a heat transfer capability greater than that 

needed to remove the decay heat produced in the reactor core. 

B.1

If restoration for Required Action A.1 is not possible within 72 hours, the 

unit must be placed in MODE 4 within 12 hours. In MODE 4, the plant 

may be placed on the SDC System. The Completion Time of 12 hours is 

compatible with required operation to achieve cooldown and 

depressurization from the existing plant conditions in an orderly manner 

and without challenging plant systems. 

C.1 and C.2

If two RCS loops are inoperable or a required RCS loop is not in 

operation, except as provided in Note 1 in the LCO section, all operations 

involving introduction of coolant into the RCS with boron concentration 

less than required to meet the minimum SDM of LCO 3.1.1 must be 

suspended. Action to restore one RCS loop to OPERABLE status and 

operation shall be initiated immediately and continued until one RCS loop 

is restored to OPERABLE status and operation. Suspending the 

introduction of coolant into the RCS of coolant with boron concentration 

less than required to meet the minimum SDM of LCO 3.1.1 is required to 

assure continued safe operation. With coolant added without forced 

circulation, unmixed coolant could be introduced to the core, however 

coolant added with boron concentration meeting the minimum SDM 

maintains acceptable margin to subcritical operation. The immediate 

Completion Times reflect the importance of maintaining operation for 

decay heat removal. 

SURVEILLANCE SR 3.4.5.1

REQUIREMENTS 

This SR requires verification every 12 hours that one RCS loop is in 

operation. Verification includes flow rate, temperature, and pump status 

monitoring, which help ensure that forced flow is providing heat removal. 

The 12 hour interval has been shown by operating practice to be 

sufficient to regularly assess degradation and verify operation within 

safety analyses assumptions. In addition, control room indication and 

alarms will normally indicate loop status. 
RCS Loops - MODE 3 

B 3.4.5 

CEOG STS B 3.4.5-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.4.5.2

This SR requires verification every 12 hours that the secondary side 

water level in each SG is ≥ [25]%. An adequate SG water level is 

required in order to have a heat sink for removal of the core decay heat 

from the reactor coolant. The 12 hour interval has been shown by 

operating practice to be sufficient to regularly assess degradation and 

verify operation within the safety analyses assumptions. 

SR 3.4.5.3

Verification that each required RCP is OPERABLE ensures that the single 

failure criterion is met and that an additional RCS loop can be placed in 

operation, if needed, to maintain decay heat removal and reactor coolant 

circulation. Verification is performed by verifying proper breaker 

alignment and power availability to each required RCP. Alternatively, 

verification that a pump is in operation also verifies proper breaker 

alignment and power availability. 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. 

This SR is modified by a Note that states the SR is not required to be 

performed until 24 hours after a required pump is not in operation. 

REFERENCES None. 
RCS Loops - MODE 4 

B 3.4.6 

CEOG STS B 3.4.6-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.6 RCS Loops - MODE 4 

BASES 

BACKGROUND In MODE 4, the primary function of the reactor coolant is the removal of 

decay heat and transfer of this heat to the steam generators (SGs) or 

shutdown cooling (SDC) heat exchangers. The secondary function of the 

reactor coolant is to act as a carrier for soluble neutron poison, boric acid. 

In MODE 4, either reactor coolant pumps (RCPs) or SDC trains can be 

used for coolant circulation. The intent of this LCO is to provide forced 

flow from at least one RCP or one SDC train for decay heat removal and 

transport. The flow provided by one RCP loop or SDC train is adequate 

for heat removal. The other intent of this LCO is to require that two paths 

be available to provide redundancy for heat removal. 

APPLICABLE In MODE 4, RCS circulation is considered in the determination of the time 

SAFETY available for mitigation of the accidental boron dilution event. The RCS 

ANALYSES loops and SDC trains provide this circulation. 

RCS Loops - MODE 4 satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii). 

LCO The purpose of this LCO is to require that at least two loops or trains, 

RCS or SDC, be OPERABLE in MODE 4 and one of these loops or trains 

be in operation. The LCO allows the two loops that are required to be 

OPERABLE to consist of any combination of RCS and SDC System 

loops. Any one loop or train in operation provides enough flow to remove 

the decay heat from the core with forced circulation. An additional loop or 

train is required to be OPERABLE to provide redundancy for heat 

removal. 

Note 1 permits all RCPs and SDC pumps to be removed from operation 

≤ 1 hour per 8 hour period. This means that natural circulation has been 

established using the SGs. The Note prohibits boron dilution with coolant 

at boron concentrations less than required to assure the SDM of 

LCO 3.1.1 is maintained when forced flow is stopped because an even 

concentration distribution cannot be ensured. Core outlet temperature is 

to be maintained at least 10°F below saturation temperature so that no 

vapor bubble may form and possibly cause a natural circulation flow 

obstruction. The response of the RCS without the RCPs or SDC pumps 

depends on the core decay heat load and the length of time that the 
RCS Loops - MODE 4 

B 3.4.6 

CEOG STS B 3.4.6-2 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

pumps are stopped. As decay heat diminishes, the effects on RCS 

temperature and pressure diminish. Without cooling by forced flow, 

higher heat loads will cause the reactor coolant temperature and pressure 

to increase at a rate proportional to the decay heat load. Because 

pressure can increase, the applicable system pressure limits (pressure 

and temperature (P/T) limits or low temperature overpressure protection 

(LTOP) limits) must be observed and forced SDC flow or heat removal via 

the SGs must be re-established prior to reaching the pressure limit. The 

circumstances for stopping both RCPs or SDC pumps are to be limited to 

situations where: 

a. Pressure and temperature increases can be maintained well within 

the allowable pressure (P/T limits and LTOP) and 10°F subcooling 

limits or 

b. An alternate heat removal path through the SGs is in operation. 

Note 2 requires that either of the following two conditions be satisfied 

before an RCP may be started with any RCS cold leg temperature less 

than or equal to the LTOP enable temperature specified in the PTLR: 

a. Pressurizer water level is < [60]% or 

b. Secondary side water temperature in each SG is < [100]°F above 

each of the RCS cold leg temperatures. 

Satisfying either of the above conditions will preclude a large pressure 

surge in the RCS when the RCP is started. 

An OPERABLE RCS loop consists of at least one OPERABLE RCP and 

an SG that is OPERABLE in accordance with the Steam Generator Tube 

Surveillance Program and has the minimum water level specified in 

SR 3.4.6.2. 

Similarly, for the SDC System, an OPERABLE SDC train is composed of 

the OPERABLE SDC pump(s) capable of providing forced flow to the 

SDC heat exchanger(s). RCPs and SDC pumps are OPERABLE if they 

are capable of being powered and are able to provide flow if required. 
RCS Loops - MODE 4 

B 3.4.6 

CEOG STS B 3.4.6-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODE 4, this LCO applies because it is possible to remove core decay 

heat and to provide proper boron mixing with either the RCS loops and 

SGs or the SDC System. 

Operation in other MODES is covered by: 

LCO 3.4.4, "RCS Loops - MODES 1 and 2," 

LCO 3.4.5, "RCS Loops - MODE 3," 

LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled," 

LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled," 

LCO 3.9.4, "Shutdown Cooling and Coolant Circulation - High Water 

 Level" (MODE 6), and 

LCO 3.9.5, "Shutdown Cooling and Coolant Circulation - Low Water 

 Level" (MODE 6). 

ACTIONS A.1

If only one required RCS loop is OPERABLE and in operation and no 

SDC trains are OPERABLE, redundancy for heat removal is lost. Action 

must be initiated immediately to restore a required non-operating loop or 

train to OPERABLE status. The immediate Completion Time reflects the 

importance of maintaining the availability of two paths for decay heat 

removal. 

A.2

If restoration is not accomplished and a SDC train is OPERABLE, the 

plant must be placed in MODE 5 within the next 24 hours. Placing the 

plant in MODE 5 is a conservative action with regard to decay heat 

removal. With only one SDC train OPERABLE, redundancy for decay 

heat removal is lost and, in the event of a loss of the remaining SDC train, 

it would be safer to initiate that loss from MODE 5 rather than MODE 4. 

The Completion Time of 24 hours is reasonable, based on operating 

experience, to reach MODE 5 from MODE 4, with only one SDC train 

operating, in an orderly manner and without challenging plant systems. 

This Required Action is modified by a Note which indicates that the unit 

must be placed in MODE 5 only if a SDC train is OPERABLE. With no 

SDC train OPERABLE, the unit is in a condition with only limited 

cooldown capabilities. Therefore, the actions are to be concentrated on 

the restoration of a SDC train, rather than a cooldown of extended 

duration. 
RCS Loops - MODE 4 

B 3.4.6 

CEOG STS B 3.4.6-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1 and B.2

If two required loops or trains are inoperable or a required loop or train is 

not in operation except during conditions permitted by Note 1 in the LCO 

section, all operations involving introduction of coolant into the RCS with 

boron concentration less than required to meet the minimum SDM of 

LCO 3.1.1 must be suspended and action to restore one RCS loop or 

SDC train to OPERABLE status and operation must be initiated. The 

required margin to criticality must not be reduced in this type of operation. 

Suspending the introduction of coolant into the RCS of coolant with boron 

concentration less than required to meet the minimum SDM of LCO 3.1.1 

is required to assure continued safe operation. With coolant added 

without forced circulation, unmixed coolant could be introduced to the 

core, however coolant added with boron concentration meeting the 

minimum SDM maintains acceptable margin to subcritical operations. The 

immediate Completion Times reflect the importance of decay heat 

removal. The action to restore must continue until one loop or train is 

restored to operation. 

SURVEILLANCE SR 3.4.6.1

REQUIREMENTS 

This SR requires verification every 12 hours that the required loop or train 

is in operation. This ensures forced flow is providing heat removal. 

Verification includes flow rate, temperature, or pump status monitoring. 

The 12 hour Frequency has been shown by operating practice to be 

sufficient to regularly assess RCS loop status. In addition, control room 

indication and alarms will normally indicate loop status. 

SR 3.4.6.2

This SR requires verification every 12 hours of secondary side water level 

in the required SG(s) ≥ [25]%. An adequate SG water level is required in 

order to have a heat sink for removal of the core decay heat from the 

reactor coolant. The 12 hour interval has been shown by operating 

practice to be sufficient to regularly assess degradation and verify 

operation within safety analyses assumptions. 
RCS Loops - MODE 4 

B 3.4.6 

CEOG STS B 3.4.6-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.4.6.3

Verification that each required pump is OPERABLE ensures that an 

additional RCS loop or SDC train can be placed in operation, if needed to 

maintain decay heat removal and reactor coolant circulation. Verification 

is performed by verifying proper breaker alignment and power available to 

each required pump. Alternatively, verification that a pump is in operation 

also verifies proper breaker alignment and power availability. 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. 

This SR is modified by a Note that states the SR is not required to be 

performed until 24 hours after a required pump is not in operation. 

REFERENCES None. 
RCS Loops - MODE 5, Loops Filled 

B 3.4.7 

CEOG STS B 3.4.7-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.7 RCS Loops - MODE 5, Loops Filled 

BASES 

BACKGROUND In MODE 5 with the RCS loops filled, the primary function of the reactor 

coolant is the removal of decay heat and the transfer of this heat either to 

the steam generator (SG) secondary side coolant via natural circulation 

(Ref. 1) or the component cooling water via the shutdown cooling (SDC) 

heat exchangers. While the principal means for decay heat removal is via 

the SDC System, the SGs via natural circulation (Ref. 1) are specified as 

a backup means for redundancy. Even though the SGs cannot produce 

steam in this MODE, they are capable of being a heat sink due to their 

large contained volume of secondary side water. As long as the SG 

secondary side water is at a lower temperature than the reactor coolant, 

heat transfer will occur. The rate of heat transfer is directly proportional to 

the temperature difference. The secondary function of the reactor coolant 

is to act as a carrier for soluble neutron poison, boric acid. 

In MODE 5 with RCS loops filled, the SDC trains are the principal means 

for decay heat removal. The number of trains in operation can vary to 

suit the operational needs. The intent of this LCO is to provide forced 

flow from at least one SDC train for decay heat removal and transport. 

The flow provided by one SDC train is adequate for decay heat removal. 

The other intent of this LCO is to require that a second path be available 

to provide redundancy for decay heat removal. 

The LCO provides for redundant paths of decay heat removal capability. 

The first path can be an SDC train that must be OPERABLE and in 

operation. The second path can be another OPERABLE SDC train, or 

through the SGs via natural circulation (Ref. 1), each having an adequate 

water level. 

APPLICABLE In MODE 5, RCS circulation is considered in the determination of the time 

SAFETY available for mitigation of the accidental boron dilution event. The SDC 

ANALYSES trains provide this circulation. 

RCS Loops - MODE 5 (Loops Filled) satisfies Criterion 4 of 

10 CFR 50.36(c)(2)(ii). 
RCS Loops - MODE 5, Loops Filled 

B 3.4.7 

CEOG STS B 3.4.7-2 Rev. 3.0, 03/31/04 

BASES 

LCO The purpose of this LCO is to require at least one of the SDC trains be 

OPERABLE and in operation with the other SDC train OPERABLE or 

secondary side water level of each SG shall be ≥ [25]%. One SDC train 

provides sufficient forced circulation to perform the safety functions of the 

reactor coolant under these conditions. The second SDC train is normally 

maintained OPERABLE as a backup to the operating SDC train to 

provide redundant paths for decay heat removal. However, if the standby 

SDC train is not OPERABLE, a sufficient alternate method to provide 

redundant paths for decay heat removal is two SGs with their secondary 

side water levels ≥ [25%]. Should the operating SDC train fail, the SGs 

could be used to remove the decay heat via natural circulation. 

Note 1 permits all SDC pumps to be removed from operation ≤ 1 hour per 

8 hour period. The circumstances for stopping both SDC trains are to be 

limited to situations where pressure and temperature increases can be 

maintained well within the allowable pressure (pressure and temperature 

and low temperature overpressure protection) and 10°F subcooling limits, 

or an alternate heat removal path through the SG(s) is in operation. 

This LCO is modified by a Note that prohibits boron dilution with coolant 

at boron concentrations less than required to assure the SDM of 

LCO 3.1.1 is maintained when SDC forced flow is stopped because an 

even concentration distribution cannot be ensured. Core outlet 

temperature is to be maintained at least 10°F below saturation 

temperature, so that no vapor bubble would form and possibly cause a 

natural circulation flow obstruction. In this MODE, the SG(s) can be used 

as the backup for SDC heat removal. To ensure their availability, the 

RCS loop flow path is to be maintained with subcooled liquid. 

In MODE 5, it is sometimes necessary to stop all RCP or SDC forced 

circulation. This is permitted to change operation from one SDC train to 

the other, perform surveillance or startup testing, perform the transition to 

and from the SDC, or to avoid operation below the RCP minimum net 

positive suction head limit. The time period is acceptable because natural 

circulation is acceptable for decay heat removal, the reactor coolant 

temperature can be maintained subcooled, and boron stratification 

affecting reactivity control is not expected. 

Note 2 allows one SDC train to be inoperable for a period of up to 2 hours 

provided that the other SDC train is OPERABLE and in operation. This 

permits periodic surveillance tests to be performed on the inoperable train 

during the only time when such testing is safe and possible. 
RCS Loops - MODE 5, Loops Filled 

B 3.4.7 

CEOG STS B 3.4.7-3 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

Note 3 requires that either of the following two conditions be satisfied 

before an RCP may be started with any RCS cold leg temperature less 

than or equal to the LTOP enable temperature specified in the PTLR: 

a. Pressurizer water level must be < [60]% or 

b. Secondary side water temperature in each SG must be < [100]°F 

above each of the RCS cold leg temperatures. 

Satisfying either of the above conditions will preclude a low temperature 

overpressure event due to a thermal transient when the RCP is started. 

Note 4 provides for an orderly transition from MODE 5 to MODE 4 during 

a planned heatup by permitting SDC trains to not be in operation when at 

least one RCP is in operation. This Note provides for the transition to 

MODE 4 where an RCP is permitted to be in operation and replaces the 

RCS circulation function provided by the SDC trains. 

An OPERABLE SDC train is composed of an OPERABLE SDC pump and 

an OPERABLE SDC heat exchanger. 

SDC pumps are OPERABLE if they are capable of being powered and 

are able to provide flow if required. An OPERABLE SG can perform as a 

heat sink via natural circulation when it has an adequate water level and 

is OPERABLE in accordance with the SG Tube Surveillance Program. 

APPLICABILITY In MODE 5 with RCS loops filled, this LCO requires forced circulation to 

remove decay heat from the core and to provide proper boron mixing. 

One SDC train provides sufficient circulation for these purposes. 

Operation in other MODES is covered by: 

LCO 3.4.4, "RCS Loops - MODES 1 and 2," 

LCO 3.4.5, "RCS Loops - MODE 3," 

LCO 3.4.6, "RCS Loops – MODE 4," 

LCO 3.4.8, "RCS Loops - MODE 5, Loops Not Filled," 

LCO 3.9.4, "Shutdown Cooling (SDC) and Coolant Circulation - High 

 Water Level" (MODE 6), and 

LCO 3.9.5, "Shutdown Cooling (SDC) and Coolant Circulation - Low 

 Water Level" (MODE 6). 
RCS Loops - MODE 5, Loops Filled 

B 3.4.7 

CEOG STS B 3.4.7-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1, A.2, B.1 and B.2

If one SDC train is OPERABLE and any required SGs has secondary side 

water levels < [25%], or one required SDC train is inoperable, redundancy 

for heat removal is lost. Action must be initiated immediately to restore a 

second SDC train to OPERABLE status or to restore the water level in the 

required SGs. Either Required Action will restore redundant decay heat 

removal paths. The immediate Completion Times reflect the importance 

of maintaining the availability of two paths for decay heat removal. 

C.1 and C.2

If a required SDC train is not in operation, or no required SDC train is 

OPERABLE, except as permitted in Note 1, all operations involving 

introduction of coolant into the RCS with boron concentration less than 

required to meet the minimum SDM of LCO 3.1.1 must be suspended. 

Action to restore one SDC train to OPERABLE status and operation must 

be initiated. The required margin to criticality must not be reduced in this 

type of operation. Suspending the introduction of coolant into the RCS of 

coolant with boron concentration less than required to meet the minimum 

SDM of LCO 3.1.1 is required to assure continued safe operation. With 

coolant added without forced circulation, unmixed coolant could be 

introduced to the core, however coolant added with boron concentration 

meeting the minimum SDM maintains acceptable margin to subcritical 

operations. The immediate Completion Times reflect the importance of 

maintaining operation for decay heat removal. 

SURVEILLANCE SR 3.4.7.1

REQUIREMENTS 

This SR requires verification every 12 hours that one SDC train is in 

operation. Verification includes flow rate, temperature, or pump status 

monitoring, which help ensure that forced flow is providing decay heat 

removal. The 12 hour Frequency has been shown by operating practice 

to be sufficient to regularly assess degradation and verify operation is 

within safety analyses assumptions. In addition, control room indication 

and alarms will normally indicate loop status. 

The SDC flow is established to ensure that core outlet temperature is 

maintained sufficiently below saturation to allow time for swapover to the 

standby SDC train should the operating train be lost. 
RCS Loops - MODE 5, Loops Filled 

B 3.4.7 

CEOG STS B 3.4.7-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.4.7.2

Verifying the SGs are OPERABLE by ensuring their secondary side water 

levels are ≥ [25%] ensures that redundant heat removal paths are 

available if the second SDC train is inoperable. The Surveillance is 

required to be performed when the LCO requirement is being met by use 

of the SGs. If both SDC trains are OPERABLE, this SR is not needed. 

The 12 hour Frequency has been shown by operating practice to be 

sufficient to regularly assess degradation and verify operation within 

safety analyses assumptions. 

SR 3.4.7.3

Verification that each required SDC train is OPERABLE ensures that 

redundant paths for decay heat removal are available. The requirement 

also ensures that the additional train can be placed in operation, if 

needed, to maintain decay heat removal and reactor coolant circulation. 

Verification is performed by verifying proper breaker alignment and power 

available to each required pump. Alternatively, verification that a pump is 

in operation also verifies proper breaker alignment and power availability. 

The Surveillance is required to be performed when the LCO requirement 

is being met by one of two SDC trains, e.g., both SGs have < [25]% water 

level. 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. 

This SR is modified by a Note that states the SR is not required to be 

performed until 24 hours after a required pump is not in operation. 

REFERENCES 1. NRC Information Notice 95-35, "Degraded Ability of Steam 

Generators to Remove Decay Heat by Natural Circulation." 
RCS Loops - MODE 5, Loops Not Filled 

B 3.4.8 

CEOG STS B 3.4.8-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.8 RCS Loops - MODE 5, Loops Not Filled 

BASES 

BACKGROUND In MODE 5 with the RCS loops not filled, the primary function of the 

reactor coolant is the removal of decay heat and transfer of this heat to 

the shutdown cooling (SDC) heat exchangers. The steam generators 

(SGs) are not available as a heat sink when the loops are not filled. The 

secondary function of the reactor coolant is to act as a carrier for the 

soluble neutron poison, boric acid. 

In MODE 5 with loops not filled, only the SDC System can be used for 

coolant circulation. The number of trains in operation can vary to suit the 

operational needs. The intent of this LCO is to provide forced flow from at 

least one SDC train for decay heat removal and transport and to require 

that two paths be available to provide redundancy for heat removal. 

APPLICABLE In MODE 5, RCS circulation is considered in determining the time 

SAFETY available for mitigation of the accidental boron dilution event. The SDC 

ANALYSES trains provide this circulation. The flow provided by one SDC train is 

adequate for decay heat removal and for boron mixing. 

RCS loops - MODE 5 (loops not filled) satisfies Criterion 4 of 

10 CFR 50.36(c)(2)(ii). 

LCO The purpose of this LCO is to require a minimum of two SDC trains be 

OPERABLE and one of these trains be in operation. An OPERABLE train 

is one that is capable of transferring heat from the reactor coolant at a 

controlled rate. Heat cannot be removed via the SDC System unless 

forced flow is used. A minimum of one running SDC pump meets the 

LCO requirement for one train in operation. An additional SDC train is 

required to be OPERABLE to meet the single failure criterion. 

Note 1 permits the SDC pumps to be removed from operation for 

≤ 15 minutes when switching from one train to another. The 

circumstances for stopping both SDC pumps are to be limited to 

situations when the outage time is short [and the core outlet temperature 

is maintained > 10°F below saturation temperature]. The Note prohibits 

boron dilution with coolant at boron concentrations less than required to 

assure the SDM of LCO 3.1.1 is maintained or draining operations when 

SDC forced flow is stopped. 

Note 2 allows one SDC train to be inoperable for a period of 2 hours 

provided that the other train is OPERABLE and in operation. This permits 

periodic surveillance tests to be performed on the inoperable train during 

the only time when these tests are safe and possible. 
RCS Loops - MODE 5, Loops Not Filled 

B 3.4.8 

CEOG STS B 3.4.8-2 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

An OPERABLE SDC train is composed of an OPERABLE SDC pump 

capable of providing forced flow to an OPERABLE SDC heat exchanger, 

along with the appropriate flow and temperature instrumentation for 

control, protection, and indication. SDC pumps are OPERABLE if they 

are capable of being powered and are able to provide flow if required. 

APPLICABILITY In MODE 5 with loops not filled, this LCO requires core heat removal and 

coolant circulation by the SDC System. 

Operation in other MODES is covered by: 

LCO 3.4.4, "RCS Loops - MODES 1 and 2," 

LCO 3.4.5, "RCS Loops - MODE 3," 

LCO 3.4.6, "RCS Loops - MODE 4," 

LCO 3.4.7, "RCS Loops - MODE 5, Loops Filled," 

LCO 3.9.4, "Shutdown Cooling (SDC) and Coolant Circulation - High 

 Water Level" (MODE 6), and 

LCO 3.9.5, "Shutdown Cooling (SDC) and Coolant Circulation - Low 

 Water Level" (MODE 6). 

ACTIONS A.1

If one required SDC train is inoperable, redundancy for heat removal is 

lost. Action must be initiated immediately to restore a second train to 

OPERABLE status. The Completion Time reflects the importance of 

maintaining the availability of two paths for heat removal. 

B.1 and B.2

If no required SDC train is OPERABLE or the required train is not in 

operation, except as provided in Note 1, all operations involving 

introduction of coolant into the RCS with boron concentration less than 

required to meet the minimum SDM of LCO 3.1.1 must be suspended. 

Action to restore one SDC train to OPERABLE status and operation must 

be initiated immediately. The required margin to criticality must not be 

reduced in this type of operation. Suspending the introduction of coolant 

into the RCS of coolant with boron concentration less than required to 

meet the minimum SDM of LCO 3.1.1 is required to assure continued 

safe operation. With coolant added without forced circulation, unmixed 

coolant could be introduced to the core, however coolant added with 

boron concentration meeting the minimum SDM maintains acceptable 

margin to subcritical operations. The immediate Completion Time reflects 

the importance of maintaining operation for decay heat removal. 
RCS Loops - MODE 5, Loops Not Filled 

B 3.4.8 

CEOG STS B 3.4.8-3 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.4.8.1

REQUIREMENTS 

This SR requires verification every 12 hours that the required SDC train is 

in operation. Verification includes flow rate, temperature, or pump status 

monitoring, which help ensure that forced flow is providing decay heat 

removal. The 12 hour Frequency has been shown by operating practice 

to be sufficient to regularly assess degradation and verify operation is 

within safety analyses assumptions. 

SR 3.4.8.2

Verification that each required train is OPERABLE ensures that 

redundant paths for heat removal are available and that an additional 

train can be placed in operation, if needed, to maintain decay heat 

removal and reactor coolant circulation. Verification is performed by 

verifying proper breaker alignment and indicated power available to each 

required pump. Alternatively, verification that a pump is in operation also 

verifies proper breaker alignment and power availability. 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. 

This SR is modified by a Note that states the SR is not required to be 

performed until 24 hours after a required pump is not in operation. 

REFERENCES None. 
Pressurizer 

B 3.4.9 

CEOG STS B 3.4.9-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.9 Pressurizer 

BASES 

BACKGROUND The pressurizer provides a point in the RCS where liquid and vapor are 

maintained in equilibrium under saturated conditions for pressure control 

purposes to prevent bulk boiling in the remainder of the RCS. Key 

functions include maintaining required primary system pressure during 

steady state operation and limiting the pressure changes caused by 

reactor coolant thermal expansion and contraction during normal load 

transients. 

The pressure control components addressed by this LCO include the 

pressurizer water level, the required heaters and their backup heater 

controls, and emergency power supplies. Pressurizer safety valves and 

pressurizer power operated relief valves (PORVs) are addressed by 

LCO 3.4.10, "Pressurizer Safety Valves," and LCO 3.4.11, "Pressurizer 

Power Operated Relief Valves (PORVs)," respectively. 

The maximum water level limit has been established to ensure that a 

liquid to vapor interface exists to permit RCS pressure control, using the 

sprays and heaters during normal operation and proper pressure 

response for anticipated design basis transients. The water level limit 

serves two purposes: 

a. Pressure control during normal operation maintains subcooled 

reactor coolant in the loops and thus in the preferred state for heat 

transport and 

b. By restricting the level to a maximum, expected transient reactor 

coolant volume increases (pressurizer insurge) will not cause 

excessive level changes that could result in degraded ability for 

pressure control. 

The maximum water level limit permits pressure control equipment to 

function as designed. The limit preserves the steam space during normal 

operation, thus, both sprays and heaters can operate to maintain the 

design operating pressure. The level limit also prevents filling the 

pressurizer (water solid) for anticipated design basis transients, thus 

ensuring that pressure relief devices (PORVs or pressurizer safety 

valves) can control pressure by steam relief rather than water relief. If the 

level limits were exceeded prior to a transient that creates a large 

pressurizer insurge volume leading to water relief, the maximum RCS 

pressure might exceed the Safety Limit of 2750 psig. 
Pressurizer 

B 3.4.9 

CEOG STS B 3.4.9-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The requirement to have [two groups of] pressurizer heaters ensures that 

RCS pressure can be maintained. The pressurizer heaters maintain RCS 

pressure to keep the reactor coolant subcooled. Inability to control RCS 

pressure during natural circulation flow could result in loss of single phase 

flow and decreased capability to remove core decay heat. 

APPLICABLE In MODES 1, 2, and 3, the LCO requirement for a steam bubble is 

SAFETY reflected implicitly in the accident analyses. No safety analyses are 

ANALYSES performed in lower MODES. All analyses performed from a critical 

reactor condition assume the existence of a steam bubble and saturated 

conditions in the pressurizer. In making this assumption, the analyses 

neglect the small fraction of noncondensible gases normally present. 

Safety analyses presented in the FSAR do not take credit for pressurizer 

heater operation; however, an implicit initial condition assumption of the 

safety analyses is that the RCS is operating at normal pressure. 

Although the heaters are not specifically used in accident analysis, the 

need to maintain subcooling in the long term during loss of offsite power, 

as indicated in NUREG-0737 (Ref. 1), is the reason for their inclusion. 

The requirement for emergency power supplies is based on 

NUREG-0737 (Ref. 1). The intent is to keep the reactor coolant in a 

subcooled condition with natural circulation at hot, high pressure 

conditions for an undefined, but extended, time period after a loss of 

offsite power. While loss of offsite power is a coincident occurrence 

assumed in the accident analyses, maintaining hot, high pressure 

conditions over an extended time period is not evaluated in the accident 

analyses. 

The pressurizer satisfies Criterion 2 and Criterion 3 of 

10 CFR 50.36(c)(2)(ii). 

LCO -----------------------------------REVIEWER’S NOTE----------------------------------- 

Plants licensed prior to the issuance of NUREG-0737 may not have a 

requirement on the number of pressurizer groups. 

-------------------------------------------------------------------------------------------------- 

The LCO requirement for the pressurizer to be OPERABLE with water 

level < [60]% ensures that a steam bubble exists. Limiting the maximum 

operating water level preserves the steam space for pressure control. 

The LCO has been established to minimize the consequences of potential 

overpressure transients. Requiring the presence of a steam bubble is 

also consistent with analytical assumptions. 
Pressurizer 

B 3.4.9 

CEOG STS B 3.4.9-3 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The LCO requires [two groups of] OPERABLE pressurizer heaters, [each] 

with a capacity ≥ [150] kW [and capable of being powered from an 

emergency power supply]. The minimum heater capacity required is 

sufficient to maintain the RCS near normal operating pressure when 

accounting for heat losses through the pressurizer insulation. By 

maintaining the pressure near the operating conditions, a wide subcooling 

margin to saturation can be obtained in the loops. The exact design 

value of [150] kW is derived from the use of 12 heaters rated at 12.5 kW 

each. The amount needed to maintain pressure is dependent on the 

ambient heat losses. 

APPLICABILITY The need for pressure control is most pertinent when core heat can cause 

the greatest effect on RCS temperature resulting in the greatest effect on 

pressurizer level and RCS pressure control. Thus, Applicability has been 

designated for MODES 1 and 2. The Applicability is also provided for 

MODE 3. The purpose is to prevent solid water RCS operation during 

heatup and cooldown to avoid rapid pressure rises caused by normal 

operational perturbation, such as reactor coolant pump startup. The 

LCO does not apply to MODE 5 (Loops Filled) because LCO 3.4.12, "Low 

Temperature Overpressure Protection (LTOP) System," applies. The 

LCO does not apply to MODES 5 and 6 with partial loop operation. 

In MODES 1, 2, and 3, there is the need to maintain the availability of 

pressurizer heaters capable of being powered from an emergency power 

supply. In the event of a loss of offsite power, the initial conditions of 

these MODES gives the greatest demand for maintaining the RCS in a 

hot pressurized condition with loop subcooling for an extended period. 

For MODE 4, 5, or 6, it is not necessary to control pressure (by heaters) 

to ensure loop subcooling for heat transfer when the Shutdown Cooling 

System is in service and therefore the LCO is not applicable. 

ACTIONS A.1 and A.2

With pressurizer water level not within the limit, action must be taken to 

restore the plant to operation within the bounds of the safety analyses. 

To achieve this status, the unit must be brought to MODE 3, with the 

reactor trip breakers open, within 6 hours and to MODE 4 within 

[12] hours. This takes the plant out of the applicable MODES and 

restores the plant to operation within the bounds of the safety analyses. 
Pressurizer 

B 3.4.9 

CEOG STS B 3.4.9-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Six hours is reasonable, based on operating experience, to reach 

MODE 3 from full power in an orderly manner and without challenging 

plant systems. Further pressure and temperature reduction to MODE 4 

brings the plant to a MODE where the LCO is not applicable. The 

12 hour time to reach the nonapplicable MODE is reasonable based on 

operating experience for that evolution. 

B.1

If one [required] group of pressurizer heaters is inoperable, restoration is 

required within 72 hours. The Completion Time of 72 hours is reasonable 

considering that a demand caused by loss of offsite power would be 

unlikely in this period. Pressure control may be maintained during this 

time using normal station powered heaters. 

C.1 and C.2

If one [required] group of pressurizer heaters is inoperable and cannot be 

restored within the allowed Completion Time of Required Action B.1, the 

plant must be brought to a MODE in which the LCO does not apply. To 

achieve this status, the plant must be brought to MODE 3 within 6 hours 

and to MODE 4 within [12] hours. The Completion Time of 6 hours is 

reasonable, based on operating experience, to reach MODE 3 from full 

power in an orderly manner and without challenging safety systems. 

Similarly, the Completion Time of [12] hours is reasonable, based on 

operating experience, to reach MODE 4 from full power in an orderly 

manner and without challenging plant systems. 

SURVEILLANCE SR 3.4.9.1

REQUIREMENTS 

This Surveillance ensures that during steady state operation, pressurizer 

water level is maintained below the nominal upper limit to provide a 

minimum space for a steam bubble. The Surveillance is performed by 

observing the indicated level. The 12 hour interval has been shown by 

operating practice to be sufficient to regularly assess the level for any 

deviation and verify that operation is within safety analyses assumptions. 

Alarms are also available for early detection of abnormal level indications. 
Pressurizer 

B 3.4.9 

CEOG STS B 3.4.9-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.4.9.2

-----------------------------------REVIEWER’S NOTE----------------------------------- 

The frequency for performing pressurizer heater capacity testing shall be 

either 18 months or 92 days, depending on whether or not the plant has 

dedicated safety-related heaters. For dedicated safety-related heaters, 

which do not normally operate, 92 days is applied. For non-dedicated 

safety-related heaters, which normally operate, 18 months is applied. 

-------------------------------------------------------------------------------------------------- 

The Surveillance is satisfied when the power supplies are demonstrated 

to be capable of producing the minimum power and the associated 

pressurizer heaters are verified to be at their design rating. (This may be 

done by testing the power supply output and by performing an electrical 

check on heater element continuity and resistance.) The Frequency of 

[18] months is considered adequate to detect heater degradation and has 

been shown by operating experience to be acceptable. 

 [ SR 3.4.9.3

This SR is not applicable if the heaters are permanently powered by 1E 

power supplies. 

This Surveillance demonstrates that the heaters can be manually 

transferred to and energized by emergency power supplies. The 

Frequency of [18] months is based on a typical fuel cycle and industry 

accepted practice. This is consistent with similar verifications of 

emergency power. ] 

REFERENCES 1. NUREG-0737, November 1980. 
Pressurizer Safety Valves 

B 3.4.10 

CEOG STS B 3.4.10-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.10 Pressurizer Safety Valves 

BASES 

BACKGROUND The purpose of the two spring loaded pressurizer safety valves is to 

provide RCS overpressure protection. Operating in conjunction with the 

Reactor Protection System, two valves are used to ensure that the Safety 

Limit (SL) of 2750 psia is not exceeded for analyzed transients during 

operation in MODES 1 and 2. Two safety valves are used for MODE 3 

and portions of MODE 4. For the remainder of MODE 4, MODE 5, and 

MODE 6 with the head on, overpressure protection is provided by 

operating procedures and the LCO 3.4.12, "Low Temperature 

Overpressure Protection (LTOP) System." 

The self actuated pressurizer safety valves are designed in accordance 

with the requirements set forth in the ASME, Boiler and Pressure Vessel 

Code, Section III (Ref. 1). The required lift pressure is 2500 psia ± 1%. 

The safety valves discharge steam from the pressurizer to a quench tank 

located in the containment. The discharge flow is indicated by an 

increase in temperature downstream of the safety valves and by an 

increase in the quench tank temperature and level. 

The upper and lower pressure limits are based on the ± 1%-tolerance 

requirement (Ref. 1) for lifting pressures above 1000 psig. The lift setting 

is for the ambient conditions associated with MODES 1, 2, and 3. This 

requires either that the valves be set hot or that a correlation between hot 

and cold settings be established. 

The pressurizer safety valves are part of the primary success path and 

mitigate the effects of postulated accidents. OPERABILITY of the safety 

valves ensures that the RCS pressure will be limited to 110% of design 

pressure. The consequences of exceeding the ASME pressure limit 

(Ref. 1) could include damage to RCS components, increased leakage, or 

a requirement to perform additional stress analyses prior to resumption of 

reactor operation. 

APPLICABLE All accident analyses in the FSAR that require safety valve actuation 

SAFETY assume operation of both pressurizer safety valves to limit increasing 

ANALYSES reactor coolant pressure. The overpressure protection analysis is also 

based on operation of both safety valves and assumes that the valves 

open at the high range of the setting (2500-psia system design pressure 

plus 1%). These valves must accommodate pressurizer insurges that 
Pressurizer Safety Valves 

B 3.4.10 

CEOG STS B 3.4.10-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

could occur during a startup, rod withdrawal, ejected rod, loss of main 

feedwater, or main feedwater line break accident. The startup accident 

establishes the minimum safety valve capacity. The startup accident is 

assumed to occur at < 15% power. Single failure of a safety valve is 

neither assumed in the accident analysis nor required to be addressed by 

the ASME Code. Compliance with this specification is required to ensure 

that the accident analysis and design basis calculations remain valid. 

The pressurizer safety valves satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The [two] pressurizer safety valves are set to open at the RCS design 

pressure (2500 psia) and within the ASME specified tolerance to avoid 

exceeding the maximum RCS design pressure SL, to maintain accident 

analysis assumptions, and to comply with ASME Code requirements. 

The upper and lower pressure tolerance limits are based on the ± 1% 

tolerance requirements (Ref. 1) for lifting pressures above 1000 psig. 

The limit protected by this specification is the reactor coolant pressure 

boundary (RCPB) SL of 110% of design pressure. Inoperability of one or 

both valves could result in exceeding the SL if a transient were to occur. 

The consequences of exceeding the ASME pressure limit could include 

damage to one or more RCS components, increased leakage, or 

additional stress analysis being required prior to resumption of reactor 

operation. 

APPLICABILITY In MODES 1, 2, and 3, and portions of MODE 4 above the LTOP 

temperature, OPERABILITY of [two] valves is required because the 

combined capacity is required to keep reactor coolant pressure below 

110% of its design value during certain accidents. MODE 3 and portions 

of MODE 4 are conservatively included, although the listed accidents may 

not require both safety valves for protection. 

The LCO is not applicable in MODE 4 when any RCS cold leg 

temperature is less than or equal to the LTOP enable temperature 

specified in the PTLR and MODE 5 because LTOP protection is provided. 

Overpressure protection is not required in MODE 6 with the reactor 

vessel head detensioned. 

The Note allows entry into MODES 3 and 4 with the lift settings outside 

the LCO limits. This permits testing and examination of the safety valves 

at high pressure and temperature near their normal operating range, but 

only after the valves have had a preliminary cold setting. The cold setting 

gives assurance that the valves are OPERABLE near their design 

condition. Only one valve at a time will be removed from service for 

testing. The [36] hour exception is based on 18 hour outage time for 

each of the two valves. The 18 hour period is derived from operating 

experience that hot testing can be performed within this timeframe. 
Pressurizer Safety Valves 

B 3.4.10 

CEOG STS B 3.4.10-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

With one pressurizer safety valve inoperable, restoration must take place 

within 15 minutes. The Completion Time of 15 minutes reflects the 

importance of maintaining the RCS overpressure protection system. An 

inoperable safety valve coincident with an RCS overpressure event could 

challenge the integrity of the RCPB. 

B.1 and B.2

If the Required Action cannot be met within the required Completion Time 

or if two or more pressurizer safety valves are inoperable, the plant must 

be brought to a MODE in which the requirement does not apply. To 

achieve this status, the plant must be brought to at least MODE 3 within 

6 hours and to MODE 4 with any RCS cold leg temperature less than or 

equal to the LTOP enable temperature specified in the PTLR within 

[24] hours. The 6 hours allowed is reasonable, based on operating 

experience, to reach MODE 3 from full power without challenging plant 

systems. Similarly, the [24] hours allowed is reasonable, based on 

operating experience, to reach MODE 4 without challenging plant 

systems. With any RCS cold leg temperature less than or equal to the 

LTOP enable temperature specified in the PTLR, overpressure protection 

is provided by LTOP. The change from MODE 1, 2, or 3 to MODE 4 

reduces the RCS energy (core power and pressure), lowers the potential 

for large pressurizer insurges, and thereby removes the need for 

overpressure protection by [two] pressurizer safety valves. 

SURVEILLANCE SR 3.4.10.1

REQUIREMENTS 

SRs are specified in the Inservice Testing Program. Pressurizer safety 

valves are to be tested in accordance with the requirements of Section XI 

of the ASME Code (Ref. 1), which provides the activities and the 

Frequency necessary to satisfy the SRs. No additional requirements are 

specified. 

The pressurizer safety valve setpoint is ± [3]% for OPERABILITY; 

however, the valves are reset to ± 1% during the Surveillance to allow for 

drift. 

REFERENCES 1. ASME, Boiler and Pressure Vessel Code, Section III, Section XI. 
Pressurizer PORVs 

B 3.4.11 

CEOG STS B 3.4.11-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.11 Pressurizer Power Operated Relief Valves (PORVs) 

BASES 

BACKGROUND The pressurizer is equipped with two types of devices for pressure relief: 

pressurizer safety valves and PORVs. The PORV is an air operated 

valve that is automatically opened at a specific set pressure when the 

pressurizer pressure increases and is automatically closed on decreasing 

pressure. The PORV may also be manually operated using controls 

installed in the control room. 

An electric, motor operated, normally open, block valve is installed 

between the pressurizer and the PORV. The function of the block valve 

is to isolate the PORV. Block valve closure is accomplished manually 

using controls in the control room and may be used to isolate a leaking 

PORV to permit continued power operation. Most importantly, the block 

valve is used to isolate a stuck open PORV to isolate the resulting small 

break loss of coolant accident (LOCA). Closure terminates the RCS 

depressurization and coolant inventory loss. 

The PORV and its block valve controls are powered from normal power 

supplies. Their controls are also capable of being powered from 

emergency supplies. Power supplies for the PORV are separate from 

those for the block valve. Power supply requirements are defined in 

NUREG-0737, Paragraph II, G.1 (Ref. 1). 

The PORV setpoint is above the high pressure reactor trip setpoint and 

below the opening setpoint for the pressurizer safety valves as required 

by Reference 2. The purpose of the relationship of these setpoints is to 

limit the number of transient pressure increase challenges that might 

open the PORV, which, if opened, could fail in the open position. The 

PORV setpoint thus limits the frequency of challenges from transients and 

limits the possibility of a small break LOCA from a failed open PORV. 

Placing the setpoint below the pressurizer safety valve opening setpoint 

reduces the frequency of challenges to the safety valves, which, unlike 

the PORV, cannot be isolated if they were to fail to open. 

The primary purpose of this LCO is to ensure that the PORV and the 

block valve are operating correctly so the potential for a small break 

LOCA through the PORV pathway is minimized, or if a small break LOCA 

were to occur through a failed open PORV, the block valve could be 

manually operated to isolate the path. 
Pressurizer PORVs 

B 3.4.11 

CEOG STS B 3.4.11-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The PORV may be manually operated to depressurize the RCS as 

deemed necessary by the operator in response to normal or abnormal 

transients. The PORV may be used for depressurization when the 

pressurizer spray is not available, a condition that may be encountered 

during loss of offsite power. Operators can manually open the PORVs to 

reduce RCS pressure in the event of a steam generator tube rupture 

(SGTR) with offsite power unavailable. 

The PORV may also be used for feed and bleed core cooling in the case 

of multiple equipment failure events that are not within the design basis, 

such as a total loss of feedwater. 

The PORV functions as an automatic overpressure device and limits 

challenges to the safety valves. Although the PORV acts as an 

overpressure device for operational purposes, safety analyses [do not 

take credit for PORV actuation, but] do take credit for the safety valves. 

The PORV also provides low temperature overpressure protection 

(LTOP) during heatup and cooldown. LCO 3.4.12, "Low Temperature 

Overpressure Protection (LTOP) System," addresses this function. 

APPLICABLE The PORV small break LOCA break size is bounded by the spectrum of 

SAFETY piping breaks analyzed for plant licensing. Because the PORV small 

ANALYSES break LOCA is located at the top of the pressurizer, the RCS response 

characteristics are different from RCS loop piping breaks; analyses have 

been performed to investigate these characteristics. 

The possibility of a small break LOCA through the PORV is reduced when 

the PORV flow path is OPERABLE and the PORV opening setpoint is 

established to be reasonably remote from expected transient challenges. 

The possibility is minimized if the flow path is isolated. 

The PORV opening setpoint has been established in accordance with 

Reference 2. It has been set so expected RCS pressure increases from 

anticipated transients will not challenge the PORV, minimizing the 

possibility of small break LOCA through the PORV. 

Overpressure protection is provided by safety valves, and analyses do 

not take credit for the PORV opening for accident mitigation. 

Pressurizer PORVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 
Pressurizer PORVs 

B 3.4.11 

CEOG STS B 3.4.11-3 Rev. 3.0, 03/31/04 

BASES 

LCO The LCO requires the PORV and its associated block valve to be 

OPERABLE. The block valve is required to be OPERABLE so it may be 

used to isolate the flow path if the PORV is not OPERABLE. 

Valve OPERABILITY also means the PORV setpoint is correct. By 

ensuring that the PORV opening setpoint is correct, the PORV is not 

subject to frequent challenges from possible pressure increase transients, 

and therefore the possibility of a small break LOCA through a failed open 

PORV is not a frequent event. 

APPLICABILITY In MODES 1, 2, and 3, the PORV and its block valve are required to be 

OPERABLE to limit the potential for a small break LOCA through the flow 

path. A likely cause for PORV small break LOCA is a result of pressure 

increase transients that cause the PORV to open. Imbalances in the 

energy output of the core and heat removal by the secondary system can 

cause the RCS pressure to increase to the PORV opening setpoint. 

Pressure increase transients can occur any time the steam generators 

are used for heat removal. The most rapid increases will occur at higher 

operating power and pressure conditions of MODES 1 and 2. 

Pressure increases are less prominent in MODE 3 because the core input 

energy is reduced, but the RCS pressure is high. Therefore, this LCO is 

applicable in MODES 1, 2, and 3. The LCO is not applicable in MODE 4 

when both pressure and core energy are decreased and the pressure 

surges become much less significant. The PORV setpoint is reduced for 

LTOP in MODES 4, 5, and 6 with the reactor vessel head in place. 

LCO 3.4.12 addresses the PORV requirements in these MODES. 

ACTIONS The ACTIONS are modified by a Note. The Note clarifies that all 

pressurizer PORVs and block valves are treated as separate entities, 

each with separate Completion Times (i.e., the Completion Time is on a 

component basis). 

A.1

With the PORV inoperable and capable of being manually cycled, either 

the PORV must be restored or the flow path isolated within 1 hour. The 

block valve should be closed but power must be maintained to the 

associated block valve, since removal of power would render the block 

valve inoperable. Although the PORV may be designated inoperable, it 

may be able to be manually opened and closed and in this manner can 

be used to perform its function. PORV inoperability may be due to seat 

leakage, instrumentation problems, automatic control problems, or other 

causes that do not prevent manual use and do not create a possibility for 
Pressurizer PORVs 

B 3.4.11 

CEOG STS B 3.4.11-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

a small break LOCA. For these reasons, the block valve may be closed 

but the Action requires power be maintained to the valve. This Condition 

is only intended to permit operation of the plant for a limited period of time 

not to exceed the next refueling outage (MODE 6) so that maintenance 

can be performed on the PORVs to eliminate the problem condition. The 

PORVs should normally be available for automatic mitigation of 

overpressure events and should be returned to OPERABLE status prior 

to entering startup (MODE 2). 

Quick access to the PORV for pressure control can be made when power 

remains on the closed block valve. The Completion Time of 1 hour is 

based on plant operating experience that minor problems can be 

corrected or closure can be accomplished in this time period. 

B.1, B.2, and B.3

If one PORV is inoperable and not capable of being manually cycled, it 

must either be isolated, by closing the associated block valve and 

removing the power from the block valve, or restored to OPERABLE 

status. The Completion Time of 1 hour is reasonable, based on 

challenges to the PORVs during this time period, and provides the 

operator adequate time to correct the situation. If the inoperable valve 

cannot be restored to OPERABLE status, it must be isolated within the 

specified time. Because there is at least one PORV that remains 

OPERABLE, an additional 72 hours is provided to restore the inoperable 

PORV to OPERABLE status. 

C.1 and C.2

If one block valve is inoperable, then it must be restored to OPERABLE 

status, or the associated PORV placed in manual control. The prime 

importance for the capability to close the block valve is to isolate a stuck 

open PORV. Therefore, if the block valve cannot be restored to 

OPERABLE status within 1 hour, the Required Action is to place the 

PORV in manual control to preclude its automatic opening for an 

overpressure event and to avoid the potential for a stuck open PORV at a 

time that the block valve is inoperable. The Completion Times of 1 hour 

are reasonable based on the small potential for challenges to the system 

during this time period and provide the operator time to correct the 

situation. Because at least one PORV remains OPERABLE, the operator 

is permitted a Completion Time of 72 hours to restore the inoperable 

block valve to OPERABLE status. The time allowed to restore the block 
Pressurizer PORVs 

B 3.4.11 

CEOG STS B 3.4.11-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

valve is based upon the Completion Time for restoring an inoperable 

PORV in Condition B since the PORVs are not capable of automatically 

mitigating an overpressure event when placed in manual control. If the 

block valve is restored within the Completion Time of 72 hours, the power 

will be restored and the PORV restored to OPERABLE status. 

D.1 and D.2

If the Required Action cannot be met within the associated Completion 

Time, the plant must be brought to a MODE in which the requirement 

does not apply. To achieve this status, the plant must be brought to at 

least MODE 3 within 6 hours and to MODE 4 within 12 hours. The 

allowed Completion Times are reasonable, based on operating 

experience, to reach the required plant conditions from full power 

conditions in an orderly manner and without challenging plant systems. 

E.1, E.2, E.3, and E.4

If more than one PORV is inoperable and not capable of being manually 

cycled, it is necessary to either restore at least one valve within the 

Completion Time of 1 hour or isolate the flow path by closing and 

removing the power to the associated block valves. The Completion 

Time of 1 hour is reasonable based on the small potential for challenges 

to the system during this time and provides the operator time to correct 

the situation. If one PORV is restored and one PORV remains 

inoperable, then the plant will be in Condition B with the time clock started 

at the original declaration of having two PORVs inoperable. If no PORVs 

are restored within the Completion Time, then the plant must be brought 

to a MODE in which the LCO does not apply. To achieve this status, the 

plant must be brought to at least MODE 3 within 6 hours and to MODE 4 

within 12 hours. The Completion Time of 6 hours is reasonable, based 

on operating experience, to reach MODE 3 from full power in an orderly 

manner and without challenging plant systems. Similarly, the Completion 

Time of 12 hours to reach MODE 4 is reasonable, considering that a plant 

can cool down within that time frame on one safety system train. In 

MODES 4 and 5, maintaining PORV OPERABILITY may be required. 

See LCO 3.4.12. 
Pressurizer PORVs 

B 3.4.11 

CEOG STS B 3.4.11-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

F.1

If two block valves are inoperable, it is necessary to restore at least one 

block valve to OPERABLE status within 2 hours. The Completion Time is 

reasonable based on the small potential for challenges to the system 

during this time and provides the operator time to correct the situation. 

G.1 and G.2

If the Required Actions and associated Completion Times of Condition E 

or F are not met, then the plant must be brought to a MODE in which the 

LCO does not apply. The plant must be brought to at least MODE 3 

within 6 hours and to MODE 4 within 12 hours. The Completion Time of 

6 hours is reasonable, based on operating experience, to reach MODE 3 

from full power in an orderly manner and without challenging safety 

systems. Similarly, the Completion Time of 12 hours to reach MODE 4 is 

reasonable considering that a plant can cool down within that time frame 

on one safety system train. In MODES 4 and 5, maintaining PORV 

OPERABILITY may be required. See LCO 3.4.12. 

SURVEILLANCE SR 3.4.11.1

REQUIREMENTS 

Block valve cycling verifies that it can be closed if necessary. The basis 

for the Frequency of [92 days] is ASME XI (Ref. 3). 

This SR is modified by two Notes. Note 1 modifies this SR by stating that 

this SR is not required to be performed with the block valve closed in 

accordance with the Required Actions of this LCO. Opening the block 

valve in this condition increases the risk of an unisolable leak from the 

RCS since the PORV is already inoperable. Note 2 modifies this SR to 

allow entry into and operation in MODE 3 prior to performing the SR. 

This allows the test to be performed in MODE 3 under operating 

temperature and pressure conditions, prior to entering MODE 1 or 2. [In 

accordance with Reference 4, administrative controls require this test be 

performed in MODE 3 or 4 to adequately simulate operating temperature 

and pressure effects on PORV operation.] 

SR 3.4.11.2

SR 3.4.11.2 requires complete cycling of each PORV. PORV cycling 

demonstrates its function. The Frequency of [18] months is based on a 

typical refueling cycle and industry accepted practice. 
Pressurizer PORVs 

B 3.4.11 

CEOG STS B 3.4.11-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The Note modifies this SR to allow entry into and operation in MODE 3 

prior to performing the SR. This allows the test to be performed in 

MODE 3 under operating temperature and pressure conditions, prior to 

entering MODE 1 or 2. [In accordance with Reference 4, administrative 

controls require this test be performed in MODE 3 or 4 to adequately 

simulate operating temperature and pressure effects on PORV operation.] 

[ SR 3.4.11.3

Operating the solenoid air control valves and check valves on the air 

accumulators ensures the PORV control system actuates properly when 

called upon. The Frequency of [18] months is based on a typical 

refueling cycle and the Frequency of the other surveillances used to 

demonstrate PORV OPERABILITY. ]

[ SR 3.4.11.4

This Surveillance is not required for plants with permanent 1E power 

supplies to the valves. The test demonstrates that emergency power can 

be provided and is performed by transferring power from the normal 

supply to the emergency supply and cycling the valves. The Frequency 

of [18] months is based on a typical refueling cycle and industry accepted 

practice. ] 

REFERENCES 1. NUREG-0737, Paragraph II, G.I, November 1980. 

 2. Inspection and Enforcement (IE) Bulletin 79-05B, April 21, 1979. 

 3. ASME, Boiler and Pressure Vessel Code, Section XI. 

 [ 4. Generic Letter 90-06, "Resolution of Generic Issue 70, 'PowerOperated Relief Valve and Block Valve Reliability,' and Generic Issue 

94, 'Additional Low-Temperature Overpressure for Light-Water 

Reactors,' Pursuant to 10 CFR 50.54(f)," June 25, 1990. ] 
LTOP System 

B 3.4.12 

CEOG STS B 3.4.12-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.12 Low Temperature Overpressure Protection (LTOP) System 

BASES 

BACKGROUND The LTOP System controls RCS pressure at low temperatures so the 

integrity of the reactor coolant pressure boundary (RCPB) is not 

compromised by violating the pressure and temperature (P/T) limits of 

10 CFR 50, Appendix G (Ref. 1). The reactor vessel is the limiting RCPB 

component for demonstrating such protection. LCO 3.4.3, "RCS 

Pressure and Temperature (P/T) Limits," provides the allowable 

combinations for operational pressure and temperature during cooldown, 

shutdown, and heatup to keep from violating the Reference 1 

requirements during the LTOP MODES. 

The reactor vessel material is less tough at low temperatures than at 

normal operating temperatures. As the vessel neutron exposure 

accumulates, the material toughness decreases and becomes less 

resistant to pressure stress at low temperatures (Ref. 2). RCS pressure, 

therefore, is maintained low at low temperatures and is increased only as 

temperature is increased. 

The potential for vessel overpressurization is most acute when the RCS is 

water solid, occurring only while shutdown; a pressure fluctuation can 

occur more quickly than an operator can react to relieve the condition. 

Exceeding the RCS P/T limits by a significant amount could cause brittle 

cracking of the reactor vessel. LCO 3.4.3 requires administrative control 

of RCS pressure and temperature during heatup and cooldown to prevent 

exceeding the P/T limits. 

This LCO provides RCS overpressure protection by having a minimum 

coolant input capability and having adequate pressure relief capacity. 

Limiting coolant input capability requires all but one high pressure safety 

injection (HPSI) pump and one charging pump incapable of injection into 

the RCS and isolating the safety injection tanks (SITs). The pressure 

relief capacity requires either two OPERABLE redundant power operated 

relief valves (PORVs) or the RCS depressurized and an RCS vent of 

sufficient size. One PORV or the RCS vent is the overpressure protection 

device that acts to terminate an increasing pressure event. 
LTOP System 

B 3.4.12 

CEOG STS B 3.4.12-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

With minimum coolant input capability, the ability to provide core coolant 

addition is restricted. The LCO does not require the makeup control 

system deactivated or the safety injection (SI) actuation circuits blocked. 

Due to the lower pressures in the LTOP MODES and the expected core 

decay heat levels, the makeup system can provide adequate flow via the 

makeup control valve. If conditions require the use of more than one [HPI 

or] charging pump for makeup in the event of loss of inventory, then 

pumps can be made available through manual actions. 

The LTOP System for pressure relief consists of two PORVs with reduced 

lift settings or an RCS vent of sufficient size. Two relief valves are 

required for redundancy. One PORV has adequate relieving capability to 

prevent overpressurization for the required coolant input capability. 

PORV Requirements

As designed for the LTOP System, each PORV is signaled to open if the 

RCS pressure approaches a limit determined by the LTOP actuation 

logic. The actuation logic monitors RCS pressure and determines when 

the LTOP overpressure setting is approached. If the indicated pressure 

meets or exceeds the calculated value, a PORV is signaled to open. 

The LCO presents the PORV setpoints for LTOP. The setpoints are 

normally staggered so only one valve opens during a low temperature 

overpressure transient. Having the setpoints of both valves within the 

limits of the LCO ensures the P/T limits will not be exceeded in any 

analyzed event. 

When a PORV is opened in an increasing pressure transient, the release 

of coolant causes the pressure increase to slow and reverse. As the 

PORV releases coolant, the system pressure decreases until a reset 

pressure is reached and the valve is signaled to close. The pressure 

continues to decrease below the reset pressure as the valve closes. 

RCS Vent Requirements

Once the RCS is depressurized, a vent exposed to the containment 

atmosphere will maintain the RCS at containment ambient pressure in an 

RCS overpressure transient, if the relieving requirements of the transient 

do not exceed the capabilities of the vent. Thus, the vent path must be 

capable of relieving the flow resulting from the limiting LTOP mass or heat 

input transient and maintaining pressure below the P/T limits. The 

required vent capacity may be provided by one or more vent paths. 
LTOP System 

B 3.4.12 

CEOG STS B 3.4.12-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

For an RCS vent to meet the specified flow capacity, it requires removing 

a pressurizer safety valve, removing a PORV's internals, and disabling its 

block valve in the open position, or similarly establishing a vent by 

opening an RCS vent valve. The vent path(s) must be above the level of 

reactor coolant, so as not to drain the RCS when open. 

APPLICABLE Safety analyses (Ref. 3) demonstrate that the reactor vessel is 

SAFETY adequately protected against exceeding the Reference 1 P/T limits 

ANALYSES during shutdown. In MODES 1, 2, and 3, and in MODE 4 with any RCS 

cold leg temperature greater than the LTOP enable temperature specified 

in the PTLR, the pressurizer safety valves prevent RCS pressure from 

exceeding the Reference 1 limits. At the LTOP enable temperature 

specified in the PTLR and below, overpressure prevention falls to the 

OPERABLE PORVs [or to a depressurized RCS and a sufficient sized 

RCS vent]. Each of these means has a limited overpressure relief 

capability. 

The actual temperature at which the pressure in the P/T limit curve falls 

below the pressurizer safety valve setpoint increases as the reactor 

vessel material toughness decreases due to neutron embrittlement. Each 

time the P/T limit curves are revised, the LTOP System will be reevaluated to ensure its functional requirements can still be satisfied using 

the PORV method or the depressurized and vented RCS condition. 

Reference 3 contains the acceptance limits that satisfy the LTOP 

requirements. Any change to the RCS must be evaluated against these 

analyses to determine the impact of the change on the LTOP acceptance 

limits. 

Transients that are capable of overpressurizing the RCS are categorized 

as either mass or heat input transients, examples of which follow: 

Mass Input Type Transients

a. Inadvertent safety injection or 

b. Charging/letdown flow mismatch. 

Heat Input Type Transients

a. Inadvertent actuation of pressurizer heaters, 

b. Loss of shutdown cooling (SDC), or 
LTOP System 

B 3.4.12 

CEOG STS B 3.4.12-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

c. Reactor coolant pump (RCP) startup with temperature asymmetry 

within the RCS or between the RCS and steam generators. 

The following are required during the LTOP MODES to ensure that mass 

and heat input transients do not occur, which either of the LTOP 

overpressure protection means cannot handle: 

a. Rendering all but one HPSI pump, and all but one charging pump 

incapable of injection and 

b. Deactivating the SIT discharge isolation valves in their closed 

positions. 

The Reference 3 analyses demonstrate that either one PORV or the RCS 

vent can maintain RCS pressure below limits when only one HPSI pump 

and one charging pump are actuated. Thus, the LCO allows only one 

HPSI pump and one charging pump OPERABLE during the LTOP 

MODES. Since neither the PORV nor the RCS vent can handle the 

pressure transient produced from accumulator injection, when RCS 

temperature is low, the LCO also requires the SITs isolation when 

accumulator pressure is greater than or equal to the maximum RCS 

pressure for the existing RCS cold leg temperature allowed in the PTLR. 

The isolated SITs must have their discharge valves closed and the valve 

power supply breakers fixed in their open positions. The analyses show 

the effect of SIT discharge is over a narrower RCS temperature range 

([175]°F and below) than that of the LCO (less than or equal to the LTOP 

enable temperature specified in the PTLR and below). 

Fracture mechanics analyses established the temperature of LTOP 

Applicability at less than or equal to the LTOP enable temperature 

specified in the PTLR. Above this temperature, the pressurizer safety 

valves provide the reactor vessel pressure protection. The vessel 

materials were assumed to have a neutron irradiation accumulation 

equal to 21 effective full power years of operation. 

The consequences of a small break loss of coolant accident (LOCA) in 

LTOP MODE 4 conform to 10 CFR 50.46 and 10 CFR 50, Appendix K 

(Refs. 4 and 5), requirements by having a maximum of one HPSI pump 

and one charging pump OPERABLE and SI actuation enabled for these 

pumps. 
LTOP System 

B 3.4.12 

CEOG STS B 3.4.12-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

PORV Performance

The fracture mechanics analyses show that the vessel is protected when 

the PORVs are set to open at or below the limits specified in the PTLR. 

The setpoint is derived by modeling the performance of the LTOP 

System, assuming the limiting allowed LTOP transient of one HPSI pump 

and one charging pump injecting into the RCS. These analyses consider 

pressure overshoot and undershoot beyond the PORV opening and 

closing setpoints, resulting from signal processing and valve stroke times. 

The PORV setpoints at or below the derived limit ensure the Reference 1 

limits will be met. 

The PORV setpoints will be re-evaluated for compliance when the revised 

P/T limits conflict with the LTOP analysis limits. The P/T limits are 

periodically modified as the reactor vessel material toughness decreases 

due to embrittlement caused by neutron irradiation. Revised P/T limits 

are determined using neutron fluence projections and the results of 

examinations of the reactor vessel material irradiation surveillance 

specimens. The Bases for LCO 3.4.3, "RCS Pressure and Temperature 

(P/T) Limits," discuss these examinations. 

The PORVs are considered active components. Thus, the failure of one 

PORV represents the worst case, single active failure. 

RCS Vent Performance

With the RCS depressurized, analyses show a vent size of [1.3] square 

inches is capable of mitigating the limiting allowed LTOP overpressure 

transient. In that event, this size vent maintains RCS pressure less than 

the maximum RCS pressure on the P/T limit curve. 

The RCS vent size will also be re-evaluated for compliance each time the 

P/T limit curves are revised based on the results of the vessel material 

surveillance. 

The RCS vent is passive and is not subject to active failure. 

LTOP System satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 
LTOP System 

B 3.4.12 

CEOG STS B 3.4.12-6 Rev. 3.0, 03/31/04 

BASES 

LCO This LCO is required to ensure that the LTOP System is OPERABLE. 

The LTOP System is OPERABLE when the minimum coolant input and 

pressure relief capabilities are OPERABLE. Violation of this LCO could 

lead to the loss of low temperature overpressure mitigation and violation 

of the Reference 1 limits as a result of an operational transient. 

To limit the coolant input capability, the LCO requires that a maximum of 

one HPSI pump and one charging pump be capable of injecting into the 

RCS, and the SITs isolated (when accumulator pressure is greater than 

or equal to the maximum RCS pressure for the existing RCS cold leg 

temperature allowed in the PTLR). 

The LCO is modified by two Notes. Note 1 allows [two charging pumps] 

to be made capable of injecting for ≤ 1 hour during pump swap 

operations. One hour provides sufficient time to safely complete the 

actual transfer and to complete the administrative controls and 

Surveillance Requirements associated with the swap. The intent is to 

minimize the actual time that more than [one] charging pump is physically 

capable of injection. Note 2 states that SIT isolation is only required 

when the SIT pressure is greater than or equal to the RCS pressure for 

the existing temperature, as allowed by the P/T limit curves provided in 

the PTLR. This Note permits the SIT discharge valve surveillance 

performed only under these pressure and temperature conditions. 

The elements of the LCO that provide overpressure mitigation through 

pressure relief are: 

a. Two OPERABLE PORVs or 

b. The depressurized RCS and an RCS vent. 

A PORV is OPERABLE for LTOP when its block valve is open, its lift 

setpoint is set within the limits specified in the PTLR and testing has 

proven its ability to open at that setpoint, and motive power is available to 

the two valves and their control circuits. 

An RCS vent is OPERABLE when open with an area ≥ [1.3] square 

inches. 

Each of these methods of overpressure prevention is capable of 

mitigating the limiting LTOP transient. 
LTOP System 

B 3.4.12 

CEOG STS B 3.4.12-7 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY This LCO is applicable in MODE 4 when the temperature of any RCS cold 

leg is less than or equal to the LTOP enable temperature specified in the 

PTLR, in MODE 5, and in MODE 6 when the reactor vessel head is on. 

The pressurizer safety valves provide overpressure protection that meets 

the Reference 1 P/T limits above the LTOP enable temperature and 

below. When the reactor vessel head is off, overpressurization cannot 

occur. 

LCO 3.4.3 provides the operational P/T limits for all MODES. 

LCO 3.4.10, "Pressurizer Safety Valves," requires the OPERABILITY of 

the pressurizer safety valves that provide overpressure protection during 

MODES 1, 2, and 3, and MODE 4 above the LTOP enable temperature 

specified in the PTLR. 

Low temperature overpressure prevention is most critical during 

shutdown when the RCS is water solid, and a mass or heat input 

transient can cause a very rapid increase in RCS pressure when little or 

no time allows operator action to mitigate the event. 

ACTIONS A Note prohibits the application of LCO 3.0.4.b to inoperable PORVs 

used for LTOP. There is an increased risk associated with entering 

MODE 4 from MODE 5 with PORVs used for LTOP inoperable and the 

provisions of LCO 3.0.4.b, which allow entry into a MODE or other 

specified condition in the Applicability with the LCO not met after 

performance of a risk assessment addressing inoperable systems and 

components, should not be applied in this circumstance. 

 A.1 and B.1

With two or more HPSI pumps capable of injecting into the RCS, 

overpressurization is possible. 

The immediate Completion Time to initiate actions to restore restricted 

coolant input capability to the RCS reflects the importance of maintaining 

overpressure protection of the RCS. 

C.1, D.1, and D.2

An unisolated SIT requires isolation within 1 hour. This is only required 

when the SIT pressure is greater than or equal to the maximum RCS 

pressure for the existing cold leg temperature allowed in the PTLR. 
LTOP System 

B 3.4.12 

CEOG STS B 3.4.12-8 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

If isolation is needed and cannot be accomplished within 1 hour, Required 

Action D.1 and Required Action D.2 provide two options, either of which 

must be performed within 12 hours. By increasing the RCS temperature 

to > [175]°F, a SIT pressure of [600] psig cannot exceed the LTOP limits if 

the tanks are fully injected. Depressurizing the SIT below the LTOP limit 

stated in the PTLR also protects against such an event. 

The Completion Times are based on operating experience that these 

activities can be accomplished in these time periods and on engineering 

evaluations indicating that an event requiring LTOP is not likely in the 

allowed times. 

E.1

In MODE 4 when any RCS cold leg temperature is ≤ [285]°F, with one 

PORV inoperable, two PORVs must be restored to OPERABLE status 

within a Completion Time of 7 days. Two valves are required to meet the 

LCO requirement and to provide low temperature overpressure mitigation 

while withstanding a single failure of an active component. 

The Completion Time is based on the facts that only one PORV is 

required to mitigate an overpressure transient and that the likelihood of an 

active failure of the remaining valve path during this time period is very 

low. 

F.1

The consequences of operational events that will overpressure the RCS 

are more severe at lower temperature (Ref. 6). Thus, one required PORV 

inoperable in MODE 5 or in MODE 6 with the head on, the Completion 

Time to restore two valves to OPERABLE status is 24 hours. 

The 24 hour Completion Time to restore two PORVs OPERABLE in 

MODE 5 or in MODE 6 when the vessel head is on is a reasonable 

amount of time to investigate and repair several types of PORV failures 

without exposure to a lengthy period with only one PORV OPERABLE to 

protect against overpressure events. 
LTOP System 

B 3.4.12 

CEOG STS B 3.4.12-9 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

G.1

If two required PORVs are inoperable, or if a Required Action and the 

associated Completion Time of Condition A, B, D, E, or F are not met, or 

if the LTOP System is inoperable for any reason other than Condition A 

through Condition F, the RCS must be depressurized and a vent 

established within 12 hours. The vent must be sized at least [1.3] square 

inches to ensure the flow capacity is greater than that required for the 

worst case mass input transient reasonable during the applicable 

MODES. This action protects the RCPB from a low temperature 

overpressure event and a possible brittle failure of the reactor vessel. 

The Completion Time of 12 hours to depressurize and vent the RCS is 

based on the time required to place the plant in this condition and the 

relatively low probability of an overpressure event during this time period 

due to increased operator awareness of administrative control 

requirements. 

SURVEILLANCE SR 3.4.12.1, SR 3.4.12.2, and SR 3.4.12.3

REQUIREMENTS 

To minimize the potential for a low temperature overpressure event by 

limiting the mass input capability, only one HPSI pump and all but [one] 

charging pump are verified OPERABLE with the other pumps locked out 

with power removed and the SIT discharge incapable of injecting into the 

RCS. The [HPI] pump[s] and charging pump[s] are rendered incapable of 

injecting into the RCS through removing the power from the pumps by 

racking the breakers out under administrative control. An alternate 

method of LTOP control may be employed using at least two independent 

means to prevent a pump start such that a single failure or single action 

will not result in an injection into the RCS. This may be accomplished 

through the pump control switch being placed in [pull to lock] and at least 

one valve in the discharge flow path being closed. 

The 12 hour interval considers operating practice to regularly assess 

potential degradation and to verify operation within the safety analysis. 

SR 3.4.12.4

SR 3.4.12.4 requires verifying that the required RCS vent is open 

≥ [1.3] square inches is proven OPERABLE by verifying its open condition 

either: 
LTOP System 

B 3.4.12 

CEOG STS B 3.4.12-10 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

a. Once every 12 hours for a valve that is unlocked open (valves that 

are sealed or secured in the open position are considered "locked" in 

this context) or 

b. Once every 31 days for other vent path(s) (e.g., a vent valve that is 

locked, sealed, or secured in position, a removed pressurizer safety 

valve, or open manway). 

The passive vent path arrangement must only be open to be OPERABLE. 

This Surveillance need only be performed if the vent is being used to 

satisfy the requirements of this LCO. The Frequencies consider 

operating experience with mispositioning of unlocked and locked vent 

valves, respectively. 

SR 3.4.12.5

The PORV block valve must be verified open every 72 hours to provide 

the flow path for each required PORV to perform its function when 

actuated. The valve can be remotely verified open in the main control 

room. 

The block valve is a remotely controlled, motor operated valve. The 

power to the valve motor operator is not required to be removed, and the 

manual actuator is not required locked in the inactive position. Thus, the 

block valve can be closed in the event the PORV develops excessive 

leakage or does not close (sticks open) after relieving an overpressure 

event. 

The 72 hour Frequency considers operating experience with accidental 

movement of valves having remote control and position indication 

capabilities available where easily monitored. These considerations 

include the administrative controls over main control room access and 

equipment control. 

SR 3.4.12.6

Performance of a CHANNEL FUNCTIONAL TEST is required every 

31 days to verify and, as necessary, adjust the PORV open setpoints. 

The CHANNEL FUNCTIONAL TEST will verify on a monthly basis that 

the PORV lift setpoints are within the LCO limit. A successful test of the 

required contact(s) of a channel relay may be performed by the 
LTOP System 

B 3.4.12 

CEOG STS B 3.4.12-11 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

verification of the change of state of a single contact of the relay. This 

clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. 

This is acceptable because all of the other required contacts of the relay 

are verified by other Technical Specifications and non-Technical 

Specifications tests at least once per refueling interval with applicable 

extensions. PORV actuation could depressurize the RCS and is not 

required. The 31 day Frequency considers experience with equipment 

reliability. 

 A Note has been added indicating this SR is required to be performed 

[12] hours after decreasing RCS cold leg temperature to less than or 

equal to the LTOP enable temperature specified in the PTLR. The test 

cannot be performed until the RCS is in the LTOP MODES when the 

PORV lift setpoint can be reduced to the LTOP setting. The test must be 

performed within 12 hours after entering the LTOP MODES. 

SR 3.4.12.7

Performance of a CHANNEL CALIBRATION on each required PORV 

actuation channel is required every [18] months to adjust the whole 

channel so that it responds and the valve opens within the required LTOP 

range and with accuracy to known input. 

The [18] month Frequency considers operating experience with 

equipment reliability and matches the typical refueling outage schedule. 

REFERENCES 1. 10 CFR 50, Appendix G. 

 2. Generic Letter 88-11. 

 3. FSAR, Section [15]. 

 4. 10 CFR 50.46. 

 5. 10 CFR 50, Appendix K. 

 6. Generic Letter 90-06. 
RCS Operational LEAKAGE 

B 3.4.13 

CEOG STS B 3.4.13-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.13 RCS Operational LEAKAGE 

BASES 

BACKGROUND Components that contain or transport the coolant to or from the reactor 

core make up the RCS. Component joints are made by welding, bolting, 

rolling, or pressure loading, and valves isolate connecting systems from 

the RCS. 

During plant life, the joint and valve interfaces can produce varying 

amounts of reactor coolant LEAKAGE, through either normal operational 

wear or mechanical deterioration. The purpose of the RCS Operational 

LEAKAGE LCO is to limit system operation in the presence of LEAKAGE 

from these sources to amounts that do not compromise safety. This LCO 

specifies the types and amounts of LEAKAGE. 

10 CFR 50, Appendix A, GDC 30 (Ref. 1), requires means for detecting 

and, to the extent practical, identifying the source of reactor coolant 

LEAKAGE. Regulatory Guide 1.45 (Ref. 2) describes acceptable 

methods for selecting leakage detection systems. 

The safety significance of RCS LEAKAGE varies widely depending on its 

source, rate, and duration. Therefore, detecting and monitoring reactor 

coolant LEAKAGE into the containment area is necessary. Quickly 

separating the identified LEAKAGE from the unidentified LEAKAGE is 

necessary to provide quantitative information to the operators, allowing 

them to take corrective action should a leak occur detrimental to the 

safety of the facility and the public. 

A limited amount of leakage inside containment is expected from auxiliary 

systems that cannot be made 100% leaktight. Leakage from these 

systems should be detected, located, and isolated from the containment 

atmosphere, if possible, to not interfere with RCS LEAKAGE detection. 

This LCO deals with protection of the reactor coolant pressure boundary 

(RCPB) from degradation and the core from inadequate cooling, in 

addition to preventing the accident analysis radiation release assumptions 

from being exceeded. The consequences of violating this LCO include 

the possibility of a loss of coolant accident (LOCA). 
RCS Operational LEAKAGE 

B 3.4.13 

CEOG STS B 3.4.13-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE Except for primary to secondary LEAKAGE, the safety analyses do not 

SAFETY address operational LEAKAGE. However, other operational LEAKAGE 

ANALYSES is related to the safety analyses for LOCA; the amount of leakage can 

affect the probability of such an event. The safety analysis for an event 

resulting in steam discharge to the atmosphere assumes a 1 gpm primary 

to secondary LEAKAGE as the initial condition. 

Primary to secondary LEAKAGE is a factor in the dose releases outside 

containment resulting from a steam line break (SLB) accident. To a 

lesser extent, other accidents or transients involve secondary steam 

release to the atmosphere, such as a steam generator tube rupture 

(SGTR). The leakage contaminates the secondary fluid. 

The FSAR (Ref. 3) analysis for SGTR assumes the contaminated 

secondary fluid is only briefly released via safety valves and the majority 

is steamed to the condenser. The 1 gpm primary to secondary 

LEAKAGE is relatively inconsequential. 

The SLB is more limiting for site radiation releases. The safety analysis 

for the SLB accident assumes 1 gpm primary to secondary LEAKAGE in 

one generator as an initial condition. The dose consequences resulting 

from the SLB accident are well within the limits defined in 10 CFR 50 or 

the staff approved licensing basis (i.e., a small fraction of these limits). 

RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO RCS operational LEAKAGE shall be limited to: 

a. Pressure Boundary LEAKAGE

No pressure boundary LEAKAGE is allowed, being indicative of 

material deterioration. LEAKAGE of this type is unacceptable as the 

leak itself could cause further deterioration, resulting in higher 

LEAKAGE. Violation of this LCO could result in continued 

degradation of the RCPB. LEAKAGE past seals and gaskets is not 

pressure boundary LEAKAGE. 

b. Unidentified LEAKAGE

One gallon per minute (gpm) of unidentified LEAKAGE is allowed as 

a reasonable minimum detectable amount that the containment air 

monitoring and containment sump level monitoring equipment can 

detect within a reasonable time period. Violation of this LCO could 

result in continued degradation of the RCPB, if the LEAKAGE is from 

the pressure boundary. 
RCS Operational LEAKAGE 

B 3.4.13 

CEOG STS B 3.4.13-3 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

c. Identified LEAKAGE

Up to 10 gpm of identified LEAKAGE is considered allowable 

because LEAKAGE is from known sources that do not interfere with 

detection of unidentified LEAKAGE and is well within the capability of 

the RCS makeup system. Identified LEAKAGE includes LEAKAGE 

to the containment from specifically known and located sources, but 

does not include pressure boundary LEAKAGE or controlled reactor 

coolant pump (RCP) seal leakoff (a normal function not considered 

LEAKAGE). Violation of this LCO could result in continued 

degradation of a component or system. 

LCO 3.4.14, "RCS Pressure Isolation Valve (PIV) Leakage," 

measures leakage through each individual PIV and can impact this 

LCO. Of the two PIVs in series in each isolated line, leakage 

measured through one PIV does not result in RCS LEAKAGE when 

the other is leaktight. If both valves leak and result in a loss of mass 

from the RCS, the loss must be included in the allowable identified 

LEAKAGE. 

d. Primary to Secondary LEAKAGE through All Steam Generators 

(SGs)

Total primary to secondary LEAKAGE amounting to 1 gpm through 

all SGs produces acceptable offsite doses in the SLB accident 

analysis. Violation of this LCO could exceed the offsite dose limits 

for this accident analysis. Primary to secondary LEAKAGE must be 

included in the total allowable limit for identified LEAKAGE. 

e. Primary to Secondary LEAKAGE through Any One SG

The [720] gallon per day limit on primary to secondary LEAKAGE 

through any one SG allocates the total 1 gpm allowed primary to 

secondary LEAKAGE equally between the two generators. 

APPLICABILITY In MODES 1, 2, 3, and 4, the potential for RCPB LEAKAGE is greatest 

when the RCS is pressurized. 

In MODES 5 and 6, LEAKAGE limits are not required because the reactor 

coolant pressure is far lower, resulting in lower stresses and reduced 

potentials for LEAKAGE. 
RCS Operational LEAKAGE 

B 3.4.13 

CEOG STS B 3.4.13-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

Unidentified LEAKAGE, identified LEAKAGE, or primary to secondary 

LEAKAGE in excess of the LCO limits must be reduced to within limits 

within 4 hours. This Completion Time allows time to verify leakage rates 

and either identify unidentified LEAKAGE or reduce LEAKAGE to within 

limits before the reactor must be shut down. This action is necessary to 

prevent further deterioration of the RCPB. 

B.1 and B.2

If any pressure boundary LEAKAGE exists or if unidentified, identified, or 

primary to secondary LEAKAGE cannot be reduced to within limits within 

4 hours, the reactor must be brought to lower pressure conditions to 

reduce the severity of the LEAKAGE and its potential consequences. 

The reactor must be brought to MODE 3 within 6 hours and to MODE 5 

within 36 hours. This action reduces the LEAKAGE and also reduces the 

factors that tend to degrade the pressure boundary. 

The allowed Completion Times are reasonable, based on operating 

experience, to reach the required conditions from full power conditions in 

an orderly manner and without challenging plant systems. In MODE 5, 

the pressure stresses acting on the RCPB are much lower, and further 

deterioration is much less likely. 

SURVEILLANCE SR 3.4.13.1

REQUIREMENTS 

Verifying RCS LEAKAGE to be within the LCO limits ensures the integrity 

of the RCPB is maintained. Pressure boundary LEAKAGE would at first 

appear as unidentified LEAKAGE and can only be positively identified by 

inspection. Unidentified LEAKAGE and identified LEAKAGE are 

determined by performance of an RCS water inventory balance. Primary 

to secondary LEAKAGE is also measured by performance of an RCS 

water inventory balance in conjunction with effluent monitoring within the 

secondary steam and feedwater systems. 

The RCS water inventory balance must be performed with the reactor at 

steady state operating conditions (stable temperature, power level, 

pressurizer and makeup tank levels, makeup and letdown, [and RCP seal 

injection and return flows]). Therefore, a Note is added allowing that this 

SR is not required to be performed until 12 hours after establishing steady 

state operation. The 12 hour allowance provides sufficient time to collect 

and process all necessary data after stable plant conditions are 

established. 
RCS Operational LEAKAGE 

B 3.4.13 

CEOG STS B 3.4.13-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Steady state operation is required to perform a proper water inventory 

balance since calculations during maneuvering are not useful. For RCS 

operational LEAKAGE determination by water inventory balance, steady 

state is defined as stable RCS pressure, temperature, power level, 

pressurizer and makeup tank levels, makeup and letdown, and RCP seal 

injection and return flows. 

An early warning of pressure boundary LEAKAGE or unidentified 

LEAKAGE is provided by the automatic systems that monitor the 

containment atmosphere radioactivity and the containment sump level. 

These leakage detection systems are specified in LCO 3.4.15, "RCS 

Leakage Detection Instrumentation." 

The 72 hour Frequency is a reasonable interval to trend LEAKAGE and 

recognizes the importance of early leakage detection in the prevention of 

accidents. 

SR 3.4.13.2

This SR provides the means necessary to determine SG OPERABILITY 

in an operational MODE. The requirement to demonstrate SG tube 

integrity in accordance with the Steam Generator Tube Surveillance 

Program emphasizes the importance of SG tube integrity, even though 

this Surveillance cannot be performed at normal operating conditions. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 30. 

 2. Regulatory Guide 1.45, May 1973. 

 3. FSAR, Section [15]. 
RCS PIV Leakage 

B 3.4.14 

CEOG STS B 3.4.14-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage 

BASES 

BACKGROUND 10 CFR 50.2, 10 CFR 50.55a(c), and GDC 55 of 10 CFR 50, Appendix A 

(Refs. 1, 2, and 3), define RCS PIVs as any two normally closed valves in 

series within the RCS pressure boundary that separate the high pressure 

RCS from an attached low pressure system. During their lives, these 

valves can produce varying amounts of reactor coolant leakage through 

either normal operational wear or mechanical deterioration. The RCS PIV 

LCO allows RCS high pressure operation when leakage through these 

valves exists in amounts that do not compromise safety. 

The PIV leakage limit applies to each individual valve. Leakage through 

both PIVs in series in a line must be included as part of the identified 

LEAKAGE, governed by LCO 3.4.13, "RCS Operational LEAKAGE." This 

is true during operation only when the loss of RCS mass through two 

valves in series is determined by a water inventory balance (SR 3.4.13.1). 

A known component of the identified LEAKAGE before operation begins 

is the least of the two individual leakage rates determined for leaking 

series PIVs during the required surveillance testing; leakage measured 

through one PIV in a line is not RCS operational LEAKAGE if the other is 

leaktight. 

Although this specification provides a limit on allowable PIV leakage rate, 

its main purpose is to prevent overpressure failure of the low pressure 

portions of connecting systems. The leakage limit is an indication that the 

PIVs between the RCS and the connecting systems are degraded or 

degrading. PIV leakage could lead to overpressure of the low pressure 

piping or components. Failure consequences could be a loss of coolant 

accident (LOCA) outside of containment, an unanalyzed condition that 

could degrade the ability for low pressure injection. 

The basis for this LCO is the 1975 NRC "Reactor Safety Study" (Ref. 4) 

that identified potential intersystem LOCAs as a significant contributor to 

the risk of core melt. A subsequent study (Ref. 5) evaluated various PIV 

configurations to determine the probability of intersystem LOCAs. 

PIVs are provided to isolate the RCS from the following typically 

connected systems: 
RCS PIV Leakage 

B 3.4.14 

CEOG STS B 3.4.14-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

a. Shutdown Cooling (SDC) System, 

b. Safety Injection System, and 

c. Chemical and Volume Control System. 

The PIVs are listed in FSAR section (Ref. 6). 

Violation of this LCO could result in continued degradation of a PIV, which 

could lead to overpressurization of a low pressure system and the loss of 

the integrity of a fission product barrier. 

APPLICABLE Reference 4 identified potential intersystem LOCAs as a significant 

SAFETY contributor to the risk of core melt. The dominant accident sequence in 

ANALYSES the intersystem LOCA category is the failure of the low pressure portion 

of the SDC System outside of containment. The accident is the result of 

a postulated failure of the PIVs, which are part of the reactor coolant 

pressure boundary (RCPB), and the subsequent pressurization of the 

SDC System downstream of the PIVs from the RCS. Because the low 

pressure portion of the SDC System is typically designed for [600] psig, 

overpressurization failure of the SDC low pressure line would result in a 

LOCA outside containment and subsequent risk of core melt. 

Reference 5 evaluated various PIV configurations, leakage testing of the 

valves, and operational changes to determine the effect on the probability 

of intersystem LOCAs. This study concluded that periodic leakage testing 

of the PIVs can substantially reduce the probability of an intersystem 

LOCA. 

RCS PIV leakage satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO RCS PIV leakage is identified LEAKAGE into closed systems connected 

to the RCS. Isolation valve leakage is usually on the order of drops per 

minute. Leakage that increases significantly suggests that something is 

operationally wrong and corrective action must be taken. 

The LCO PIV leakage limit is 0.5 gpm per nominal inch of valve size, with 

a maximum limit of 5 gpm. The previous criterion of 1 gpm for all valve 

sizes imposed an unjustified penalty on the larger valves without 

providing information on potential valve degradation and resulted in 

higher personnel radiation exposures. A study concluded a leakage rate 

limit based on valve size was superior to a single allowable value. 
RCS PIV Leakage 

B 3.4.14 

CEOG STS B 3.4.14-3 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

Reference 7 permits leakage testing at a lower pressure differential than 

between the specified maximum RCS pressure and the normal pressure 

of the connected system during RCS operation (the maximum pressure 

differential) in those types of valves in which the higher service pressure 

will tend to diminish the overall leakage channel opening. In such cases, 

the observed rate may be adjusted to the maximum pressure differential 

by assuming leakage is directly proportional to the pressure differential to 

the one half power. 

APPLICABILITY In MODES 1, 2, 3, and 4, this LCO applies because the PIV leakage 

potential is greatest when the RCS is pressurized. In MODE 4, valves in 

the SDC flow path are not required to meet the requirements of this LCO 

when in, or during the transition to or from, the SDC mode of operation. 

In MODES 5 and 6, leakage limits are not provided because the lower 

reactor coolant pressure results in a reduced potential for leakage and for 

a LOCA outside the containment. 

ACTIONS The Actions are modified by two Notes. Note 1 is added to provide 

clarification that each flow path allows separate entry into a Condition. 

This is allowed based on the functional independence of the flow path. 

Note 2 requires an evaluation of affected systems if a PIV is inoperable. 

The leakage may have affected system operability or isolation of a 

leaking flow path with an alternate valve may have degraded the ability of 

the interconnected system to perform its safety function. 

A.1 and A.2

The flow path must be isolated by two valves. Required Actions A.1 

and A.2 are modified by a Note stating that the valves used for isolation 

must meet the same leakage requirements as the PIVs and must be in 

the RCPB [or the high pressure portion of the system]. 

Required Action A.1 requires that the isolation with one valve must be 

performed within 4 hours. Four hours provides time to reduce leakage in 

excess of the allowable limit and to isolate if leakage cannot be reduced. 

The 4 hours allows the actions and restricts the operation with leaking 

isolation valves. 
RCS PIV Leakage 

B 3.4.14 

CEOG STS B 3.4.14-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

[ Required Action A.2 specifies that the double isolation barrier of two 

valves be restored by closing some other valve qualified for isolation or 

restoring one leaking PIV. The 72 hour Completion Time after exceeding 

the limit considers the time required to complete the action and the low 

probability of a second valve failing during this time period. 

or 

The 72 hour Completion Time after exceeding the limit allows for the 

restoration of the leaking PIV to OPERABLE status. This timeframe 

considers the time required to complete this Action and the low probability 

of a second valve failing during this period.] 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Two options are provided for Required Action A.2. The second option 

(72 hour restoration) is appropriate if isolation of a second valve would 

place the unit in an unanalyzed condition. 

-------------------------------------------------------------------------------------------------- 

B.1 and B.2

If leakage cannot be reduced [the system isolated] or other Required 

Actions accomplished, the plant must be brought to a MODE in which the 

LCO does not apply. To achieve this status, the plant must be brought to 

MODE 3 within 6 hours and to MODE 5 within 36 hours. This Action 

reduces the leakage and also reduces the potential for a LOCA outside 

the containment. The allowed Completion Times are reasonable, based 

on operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

C.1

The inoperability of the SDC autoclosure interlock renders the SDC 

suction isolation valves incapable of: isolating in response to a high 

pressure condition and preventing inadvertent opening of the valves at 

RCS pressures in excess of the SDC systems design pressure. If the 

SDC autoclosure interlock is inoperable, operation may continue as long 

as the affected SDC suction penetration is closed by at least one closed 

manual or deactivated automatic valve within 4 hours. This Action 

accomplishes the purpose of the autoclosure function. 
RCS PIV Leakage 

B 3.4.14 

CEOG STS B 3.4.14-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.4.14.1

REQUIREMENTS 

Performance of leakage testing on each RCS PIV or isolation valve used 

to satisfy Required Action A.1 or A.2 is required to verify that leakage is 

below the specified limit and to identify each leaking valve. The leakage 

limit of 0.5 gpm per inch of nominal valve diameter up to 5 gpm maximum 

applies to each valve. Leakage testing requires a stable pressure 

condition. 

For the two PIVs in series, the leakage requirement applies to each valve 

individually and not to the combined leakage across both valves. If the 

PIVs are not individually leakage tested, one valve may have failed 

completely and not be detected if the other valve in series meets the 

leakage requirement. In this situation, the protection provided by 

redundant valves would be lost. 

Testing is to be performed every 9 months, but may be extended up to a 

maximum of [18] months, a typical refueling cycle, if the plant does not go 

into MODE 5 for at least 7 days. 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, Section XI (Ref. 7), and is based on 

the need to perform the Surveillance under conditions that apply during a 

plant outage and the potential for an unplanned transient if the 

Surveillance were performed with the reactor at power. 

In addition, testing must be performed once after the valve has been 

opened by flow or exercised to ensure tight reseating. PIVs disturbed in 

the performance of this Surveillance should also be tested unless 

documentation shows that an infinite testing loop cannot practically be 

avoided. Testing must be performed within 24 hours after the valve has 

been reseated. Within 24 hours is a reasonable and practical time limit 

for performing this test after opening or reseating a valve. 

The leakage limit is to be met at the RCS pressure associated with 

MODES 1 and 2. This permits leakage testing at high differential 

pressures with stable conditions not possible in the MODES with lower 

pressures. 
RCS PIV Leakage 

B 3.4.14 

CEOG STS B 3.4.14-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Entry into MODES 3 and 4 is allowed to establish the necessary 

differential pressures and stable conditions to allow for performance of 

this Surveillance. The Note that allows this provision is complimentary to 

the Frequency of prior to entry into MODE 2 whenever the unit has been 

in MODE 5 for 7 days or more, if leakage testing has not been performed 

in the previous 9 months. In addition, this Surveillance is not required to 

be performed on the SDC System when the SDC System is aligned to the 

RCS in the shutdown cooling mode of operation. PIVs contained in the 

SDC shutdown cooling flow path must be leakage rate tested after SDC is 

secured and stable unit conditions and the necessary differential 

pressures are established. 

SR 3.4.14.2 and SR 3.4.14.3

Verifying that the SDC autoclosure interlocks are OPERABLE ensures 

that RCS pressure will not pressurize the SDC system beyond 125% of 

its design pressure of [600] psig. The interlock setpoint that prevents the 

valves from being opened is set so the actual RCS pressure must be 

< [425] psig to open the valves. This setpoint ensures the SDC design 

pressure will not be exceeded and the SDC relief valves will not lift. The 

18 month Frequency is based on the need to perform these Surveillances 

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. 

The SRs are modified by Notes allowing the SDC autoclosure function to 

be disabled when using the SDC System suction relief valves for cold 

overpressure protection in accordance with SR 3.4.12.7. 

REFERENCES 1. 10 CFR 50.2. 

 2. 10 CFR 50.55a(c). 

 3. 10 CFR 50, Appendix A, Section V, GDC 55. 

 4. WASH-1400 (NUREG-75/014), Appendix V, October 1975. 

 5. NUREG-0677, May 1980. 

 6. [ Document containing list of PIVs. ] 

 7. ASME, Boiler and Pressure Vessel Code, Section XI. 

 8. 10 CFR 50.55a(g). 
RCS Leakage Detection Instrumentation 

B 3.4.15 

CEOG STS B 3.4.15-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.15 RCS Leakage Detection Instrumentation 

BASES 

BACKGROUND GDC 30 of Appendix A to 10 CFR 50 (Ref. 1) requires means for 

detecting and, to the extent practical, identifying the location of the source 

of RCS LEAKAGE. Regulatory Guide 1.45 (Ref. 2) describes acceptable 

methods for selecting leakage detection systems. 

Leakage detection systems must have the capability to detect significant 

reactor coolant pressure boundary (RCPB) degradation as soon after 

occurrence as practical to minimize the potential for propagation to a 

gross failure. Thus, an early indication or warning signal is necessary to 

permit proper evaluation of all unidentified LEAKAGE. 

Industry practice has shown that water flow changes of 0.5 gpm to 

1.0 gpm can readily be detected in contained volumes by monitoring 

changes in water level, in flow rate, or in the operating frequency of a 

pump. The containment sump used to collect unidentified LEAKAGE [is] 

and the containment air cooler condensate flow rate monitor [are] 

instrumented to alarm for increases of 0.5 gpm to 1.0 gpm in the normal 

flow rates. This sensitivity is acceptable for detecting increases in 

unidentified LEAKAGE. 

The reactor coolant contains radioactivity that, when released to the 

containment, can be detected by radiation monitoring instrumentation. 

Reactor coolant radioactivity levels will be low during initial reactor startup 

and for a few weeks thereafter until activated corrosion products have 

been formed and fission products appear from fuel element cladding 

contamination or cladding defects. Instrument sensitivities of 10-9 μCi/cc 

radioactivity for particulate monitoring and of 10-6 μCi/cc radioactivity for 

gaseous monitoring are practical for these leakage detection systems. 

Radioactivity detection systems are included for monitoring both 

particulate and gaseous activities, because of their sensitivities and rapid 

responses to RCS LEAKAGE. 

An increase in humidity of the containment atmosphere would indicate 

release of water vapor to the containment. Dew point temperature 

measurements can thus be used to monitor humidity levels of the 

containment atmosphere as an indicator of potential RCS LEAKAGE. A 

1°F increase in dew point is well within the sensitivity range of available 

instruments. 
RCS Leakage Detection Instrumentation 

B 3.4.15 

CEOG STS B 3.4.15-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Since the humidity level is influenced by several factors, a quantitative 

evaluation of an indicated leakage rate by this means may be 

questionable and should be compared to observed increases in liquid 

flow into or from the containment sump [and condensate flow from air 

coolers]. Humidity level monitoring is considered most useful as an 

indirect alarm or indication to alert the operator to a potential problem. 

Humidity monitors are not required by this LCO. 

Air temperature and pressure monitoring methods may also be used to 

infer unidentified LEAKAGE to the containment. Containment 

temperature and pressure fluctuate slightly during plant operation, but a 

rise above the normally indicated range of values may indicate RCS 

LEAKAGE into the containment. The relevance of temperature and 

pressure measurements are affected by containment free volume and, for 

temperature, detector location. Alarm signals from these instruments can 

be valuable in recognizing rapid and sizable leakage to the containment. 

Temperature and pressure monitors are not required by this LCO. 

APPLICABLE The need to evaluate the severity of an alarm or an indication is important 

SAFETY to the operators, and the ability to compare and verify with indications 

ANALYSES from other systems is necessary. The system response times and 

sensitivities are described in the FSAR (Ref. 3). Multiple instrument 

locations are utilized, if needed, to ensure the transport delay time of the 

LEAKAGE from its source to an instrument location yields an acceptable 

overall response time. 

The safety significance of RCS LEAKAGE varies widely depending on its 

source, rate, and duration. Therefore, detecting and monitoring RCS 

LEAKAGE into the containment area are necessary. Quickly separating 

the identified LEAKAGE from the unidentified LEAKAGE provides 

quantitative information to the operators, allowing them to take corrective 

action should leakage occur detrimental to the safety of the facility and 

the public. 

RCS leakage detection instrumentation satisfies Criterion 1 of 

10 CFR 50.36(c)(2)(ii). 
RCS Leakage Detection Instrumentation 

B 3.4.15 

CEOG STS B 3.4.15-3 Rev. 3.0, 03/31/04 

BASES 

LCO One method of protecting against large RCS LEAKAGE derives from the 

ability of instruments to rapidly detect extremely small leaks. This LCO 

requires instruments of diverse monitoring principles to be OPERABLE to 

provide a high degree of confidence that extremely small leaks are 

detected in time to allow actions to place the plant in a safe condition 

when RCS LEAKAGE indicates possible RCPB degradation. 

The LCO is satisfied when monitors of diverse measurement means are 

available. Thus, the containment sump monitor, in combination with a 

particulate or gaseous radioactivity monitor [and a containment air cooler 

condensate flow rate monitor], provides an acceptable minimum. 

APPLICABILITY Because of elevated RCS temperature and pressure in MODES 1, 2, 3, 

and 4, RCS leakage detection instrumentation is required to be 

OPERABLE. 

In MODE 5 or 6, the temperature is ≤ 200°F and pressure is maintained 

low or at atmospheric pressure. Since the temperatures and pressures 

are far lower than those for MODES 1, 2, 3, and 4, the likelihood of 

leakage and crack propagation is much smaller. Therefore, the 

requirements of this LCO are not applicable in MODES 5 and 6. 

ACTIONS A.1 and A.2

If the containment sump monitor is inoperable, no other form of sampling 

can provide the equivalent information. 

However, the containment atmosphere radioactivity monitor will provide 

indications of changes in leakage. Together with the atmosphere 

monitor, the periodic surveillance for RCS water inventory balance, 

SR 3.4.13.1, must be performed at an increased frequency of 24 hours to 

provide information that is adequate to detect leakage. A Note is added 

allowing that SR 3.4.13.1 is not required to be performed until 12 hours 

after establishing steady state operation (stable temperature, power level, 

pressurizer and makeup tank levels, makeup and letdown, and [RCP seal 

injection and return flows]). The 12 hour allowance provides sufficient 

time to collect and process all necessary data after stable plant conditions 

are established. 

Restoration of the sump monitor to OPERABLE status is required to 

regain the function in a Completion Time of 30 days after the monitor's 

failure. This time is acceptable considering the frequency and adequacy 

of the RCS water inventory balance required by Required Action A.1. 
RCS Leakage Detection Instrumentation 

B 3.4.15 

CEOG STS B 3.4.15-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1.1, B.1.2, B.2.1, and B.2.2

With both gaseous and particulate containment atmosphere radioactivity 

monitoring instrumentation channels inoperable, alternative action is 

required. Either grab samples of the containment atmosphere must be 

taken and analyzed, or water inventory balances, in accordance with 

SR 3.4.13.1, must be performed to provide alternate periodic information. 

With a sample obtained and analyzed or an inventory balance performed 

every 24 hours, the reactor may be operated for up to 30 days to allow 

restoration of at least one of the radioactivity monitors. 

Alternatively, continued operation is allowed if the air cooler condensate 

flow rate monitoring system is OPERABLE, provided grab samples are 

taken or water inventory balance performed every 24 hours. 

The 24 hour interval provides periodic information that is adequate to 

detect leakage. A Note is added allowing that SR 3.4.13.1 is not required 

to be performed until 12 hours after establishing steady state operation 

(stable temperature, power level, pressurizer and makeup tank levels, 

makeup and letdown, and [RCP seal injection and return flows]). The 

12 hour allowance provides sufficient time to collect and process all 

necessary data after stable plant conditions are established. The 30 day 

Completion Time recognizes at least one other form of leakage detection 

is available. 

[ C.1 and C.2

If the required containment air cooler condensate flow rate monitor is 

inoperable, alternative action is again required. Either SR 3.4.15.1 must 

be performed, or water inventory balances, in accordance with 

SR 3.4.13.1, must be performed to provide alternate periodic information. 

Provided a CHANNEL CHECK is performed every 8 hours or an inventory 

balance is performed every 24 hours, reactor operation may continue 

while awaiting restoration of the containment air cooler condensate flow 

rate monitor to OPERABLE status. 

The 24 hour interval provides periodic information that is adequate to 

detect RCS LEAKAGE. A Note is added allowing that SR 3.4.13.1 is not 

required to be performed until 12 hours after establishing steady state 

operation (stable temperature, power level, pressurizer and makeup tank 

levels, makeup and letdown, and [RCP seal injection and return flows]). 

The 12 hour allowance provides sufficient time to collect and process all 

necessary data after stable plant conditions are established. 
RCS Leakage Detection Instrumentation 

B 3.4.15 

CEOG STS B 3.4.15-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

D.1 and D.2

If the required containment atmosphere radioactivity monitor and the 

containment air cooler condensate flow rate monitor are inoperable, the 

only means of detecting leakage is the containment sump monitor. This 

Condition does not provide the required diverse means of leakage 

detection. The Required Action is to restore either of the inoperable 

monitors to OPERABLE status within 30 days to regain the intended 

leakage detection diversity. The 30 day Completion Times ensure that 

the plant will not be operated in a reduced configuration for a lengthy time 

period. ]

E.1 and E.2

If any Required Action of Condition A, B, [C], or [D] cannot be met within 

the required Completion Time, the plant must be brought to a MODE in 

which the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 5 within 

36 hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

F.1

If all required monitors are inoperable, no automatic means of monitoring 

leakage are available and immediate plant shutdown in accordance with 

LCO 3.0.3 is required. 

SURVEILLANCE SR 3.4.15.1

REQUIREMENTS 

SR 3.4.15.1 requires the performance of a CHANNEL CHECK of the 

required containment atmosphere radioactivity monitors. The check gives 

reasonable confidence the channel is operating properly. The Frequency 

of [12] hours is based on instrument reliability and is reasonable for 

detecting off normal conditions. 
RCS Leakage Detection Instrumentation 

B 3.4.15 

CEOG STS B 3.4.15-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.4.15.2

SR 3.4.15.2 requires the performance of a CHANNEL FUNCTIONAL 

TEST of the required containment atmosphere radioactivity monitors. 

The test ensures that the monitor can perform its function in the desired 

manner. The test verifies the alarm setpoint and relative accuracy of the 

instrument string. A successful test of the required contact(s) of a 

channel relay may be performed by the verification of the change of state 

of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. The Frequency of 

92 days considers instrument reliability, and operating experience has 

shown it proper for detecting degradation. 

SR 3.4.15.3, SR 3.4.15.4, and [SR 3.4.15.5]

These SRs require the performance of a CHANNEL CALIBRATION for 

each of the RCS leakage detection instrumentation channels. The 

calibration verifies the accuracy of the instrument string, including the 

instruments located inside containment. The Frequency of [18] months is 

a typical refueling cycle and considers channel reliability. Operating 

experience has shown this Frequency is acceptable. 

REFERENCES 1. 10 CFR 50, Appendix A, Section IV, GDC 30. 

 2. Regulatory Guide 1.45. 

 3. FSAR, Section [ ]. 
RCS Specific Activity 

B 3.4.16 

CEOG STS B 3.4.16-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.16 RCS Specific Activity 

BASES 

BACKGROUND The Code of Federal Regulations, 10 CFR 100 (Ref. 1) specifies the 

maximum dose to the whole body and the thyroid an individual at the site 

boundary can receive for 2 hours during an accident. The limits on 

specific activity ensure that the doses are held to a small fraction of the 

10 CFR 100 limits during analyzed transients and accidents. 

The RCS specific activity LCO limits the allowable concentration level of 

radionuclides in the reactor coolant. The LCO limits are established to 

minimize the offsite radioactivity dose consequences in the event of a 

steam generator tube rupture (SGTR) accident. 

The LCO contains specific activity limits for both DOSE 

EQUIVALENT I-131 and gross specific activity. The allowable levels are 

intended to limit the 2 hour dose at the site boundary to a small fraction of 

the 10 CFR 100 dose guideline limits. The limits in the LCO are 

standardized based on parametric evaluations of offsite radioactivity dose 

consequences for typical site locations. 

The parametric evaluations showed the potential offsite dose levels for an 

SGTR accident were an appropriately small fraction of the 10 CFR 100 

dose guideline limits. Each evaluation assumes a broad range of site 

applicable atmospheric dispersion factors in a parametric evaluation. 

APPLICABLE The LCO limits on the specific activity of the reactor coolant ensure that 

SAFETY the resulting 2 hour doses at the site boundary will not exceed a small 

ANALYSES fraction of the 10 CFR 100 dose guideline limits following an SGTR 

accident. The SGTR safety analysis (Ref. 2) assumes the specific activity 

of the reactor coolant at the LCO limits and an existing reactor coolant 

steam generator (SG) tube leakage rate of 1 gpm. The analysis also 

assumes a reactor trip and a turbine trip at the same time as the SGTR 

event. 

The analysis for the SGTR accident establishes the acceptance limits for 

RCS specific activity. Reference to this analysis is used to assess 

changes to the facility that could affect RCS specific activity as they relate 

to the acceptance limits. 
RCS Specific Activity 

B 3.4.16 

CEOG STS B 3.4.16-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The rise in pressure in the ruptured SG causes radioactively 

contaminated steam to discharge to the atmosphere through the 

atmospheric dump valves or the main steam safety valves. The 

atmospheric discharge stops when the turbine bypass to the condenser 

removes the excess energy to rapidly reduce the RCS pressure and close 

the valves. The unaffected SG removes core decay heat by venting 

steam until the cooldown ends. 

The safety analysis shows the radiological consequences of an SGTR 

accident are within a small fraction of the Reference 1 dose guideline 

limits. Operation with iodine specific activity levels greater than the LCO 

limit is permissible, if the activity levels do not exceed the limits shown in 

Figure 3.4.16-1 for more than 48 hours. 

The remainder of the above limit permissible iodine levels shown in 

Figure 3.4.16-1 are acceptable because of the low probability of an SGTR 

accident occurring during the established 48 hour time limit. The 

occurrence of an SGTR accident at these permissible levels could 

increase the site boundary dose levels, but still be within 10 CFR 100 

dose guideline limits. 

RCS specific activity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The specific iodine activity is limited to 1.0 μCi/gm DOSE EQUIVALENT 

I-131, and the gross specific activity in the primary coolant is limited to the 

number of μCi/gm equal to 100 divided by Ē (average disintegration 

energy of the sum of the average beta and gamma energies of the 

coolant nuclides). The limit on DOSE EQUIVALENT I-131 ensures the 

2 hour thyroid dose to an individual at the site boundary during the Design 

Basis Accident (DBA) will be a small fraction of the allowed thyroid dose. 

The limit on gross specific activity ensures the 2 hour whole body dose to 

an individual at the site boundary during the DBA will be a small fraction 

of the allowed whole body dose. 

The SGTR accident analysis (Ref. 2) shows that the 2 hour site boundary 

dose levels are within acceptable limits. Violation of the LCO may result 

in reactor coolant radioactivity levels that could, in the event of an SGTR, 

lead to site boundary doses that exceed the 10 CFR 100 dose guideline 

limits. 
RCS Specific Activity 

B 3.4.16 

CEOG STS B 3.4.16-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODES 1 and 2, and in MODE 3 with RCS average temperature 

≥ 500°F, operation within the LCO limits for DOSE EQUIVALENT I-131 

and gross specific activity is necessary to contain the potential 

consequences of an SGTR to within the acceptable site boundary dose 

values. 

For operation in MODE 3 with RCS average temperature < 500°F, and in 

MODES 4 and 5, the release of radioactivity in the event of an SGTR is 

unlikely since the saturation pressure of the reactor coolant is below the 

lift pressure settings of the atmospheric dump valves and main steam 

safety valves. 

ACTIONS A.1 and A.2

With the DOSE EQUIVALENT I-131 greater than the LCO limit, samples 

at intervals of 4 hours must be taken to demonstrate the limits of 

Figure 3.4.16-1 are not exceeded. The Completion Time of 4 hours is 

required to obtain and analyze a sample. 

Sampling must continue for trending. The DOSE EQUIVALENT I-131 

must be restored to within limits within 48 hours. 

The Completion Time of 48 hours is required if the limit violation resulted 

from normal iodine spiking. 

A Note permits the use of the provisions of LCO 3.0.4.c. This allowance 

permits entry into the applicable MODE(S) while relying on the ACTIONS. 

This allowance is acceptable due to the significant conservatism 

incorporated into the specific activity limit, the low probability of an event 

which is limiting due to exceeding this limit, and the ability to restore 

transient specific activity excursions while the plant remains at, or 

proceeds to power operation. 

B.1

If a Required Action and associated Completion Time of Condition A is 

not met or if the DOSE EQUIVALENT I-131 is in the unacceptable region 

of Figure 3.4.16-1, the reactor must be brought to MODE 3 with RCS 

average temperature < 500°F within 6 hours. The allowed Completion 

Time of 6 hours is required to reach MODE 3 below 500°F without 

challenging plant systems. 
RCS Specific Activity 

B 3.4.16 

CEOG STS B 3.4.16-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1

With the gross specific activity in excess of the allowed limit, the unit must 

be placed in a MODE in which the requirement does not apply. 

The change within 6 hours to MODE 3 and RCS average temperature 

< 500°F lowers the saturation pressure of the reactor coolant below the 

setpoints of the main steam safety valves and prevents venting the SG to 

the environment in an SGTR event. The allowed Completion Time of 

6 hours is required to reach MODE 3 below 500°F from full power 

conditions and without challenging plant systems. 

SURVEILLANCE SR 3.4.16.1

REQUIREMENTS 

The Surveillance requires performing a gamma isotopic analysis as a 

measure of the gross specific activity of the reactor coolant at least once 

per 7 days. While basically a quantitative measure of radionuclides with 

half lives longer than 15 minutes, excluding iodines, this measurement is 

the sum of the degassed gamma activities and the gaseous gamma 

activities in the sample taken. This Surveillance provides an indication of 

any increase in gross specific activity. 

Trending the results of this Surveillance allows proper remedial action to 

be taken before reaching the LCO limit under normal operating 

conditions. The Surveillance is applicable in MODES 1 and 2, and in 

MODE 3 with RCS average temperature at least 500°F. The 7 day 

Frequency considers the unlikelihood of a gross fuel failure during the 

time. 

SR 3.4.16.2

This Surveillance is performed to ensure iodine remains within limit during 

normal operation and following fast power changes when fuel failure is 

more apt to occur. The 14 day Frequency is adequate to trend changes 

in the iodine activity level considering gross activity is monitored every 

7 days. The Frequency, between 2 hours and 6 hours after a power 

change of ≥ 15% RTP within a 1 hour period, is established because the 

iodine levels peak during this time following fuel failure; samples at other 

times would provide inaccurate results. 
RCS Specific Activity 

B 3.4.16 

CEOG STS B 3.4.16-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.4.16.3

A radiochemical analysis for Ē determination is required every 184 days 

(6 months) with the plant operating in MODE 1 equilibrium conditions. 

The Ē determination directly relates to the LCO and is required to verify 

plant operation within the specified gross activity LCO limit. The analysis 

for Ē is a measurement of the average energies per disintegration for 

isotopes with half lives longer than 15 minutes, excluding iodines. The 

Frequency of 184 days recognizes Ē does not change rapidly. 

This SR has been modified by a Note that indicates sampling is required 

to be performed within 31 days after 2 effective full power days and 

20 days of MODE 1 operation have elapsed since the reactor was last 

subcritical for at least 48 hours. This ensures the radioactive materials 

are at equilibrium so the analysis for Ē is representative and not skewed 

by a crud burst or other similar abnormal event. 

REFERENCES 1. 10 CFR 100.11, 1973. 

 2. FSAR, Section [15.6.3]. 
STE - RCS Loops 

B 3.4.17 

CEOG STS B 3.4.17-1 Rev. 3.0, 03/31/04 

B 3.4 REACTOR COOLANT SYSTEM (RCS) 

B 3.4.17 Special Test Exception (STE) RCS Loops 

BASES 

BACKGROUND This special test exception to LCO 3.4.4, "RCS Loops - MODES 1 

and 2," and LCO 3.3.1, "RPS Instrumentation," permits reactor criticality 

under no flow conditions during PHYSICS TESTS (natural circulation 

demonstration, station blackout, and loss of offsite power) while at low 

THERMAL POWER levels. Section XI of 10 CFR Part 50, Appendix B 

(Ref. 1), requires that a test program be established to ensure that 

structures, systems, and components will perform satisfactorily in service. 

All functions necessary to ensure that the specified design conditions are 

not exceeded during normal operation and anticipated operational 

occurrences must be tested. This testing is an integral part of the design, 

construction, and operation of the power plant as specified in 10 CFR 50, 

Appendix A, GDC 1 (Ref. 2). 

The key objectives of a test program are to provide assurance that the 

facility has been adequately designed to validate the analytical models 

used in the design and analysis, to verify the assumptions used to predict 

plant response, to provide assurance that installation of equipment at the 

facility has been accomplished in accordance with the design, and to 

verify that the operating and emergency procedures are adequate. 

Testing is performed prior to initial criticality, during startup, and following 

low power operations. 

The tests will include verifying the ability to establish and maintain natural 

circulation following a plant trip between 10% and 20% RTP, performing 

natural circulation cooldown on emergency power, and during the 

cooldown, showing that adequate boron mixing occurs and that pressure 

can be controlled using auxiliary spray and pressurizer heaters powered 

from the emergency power sources. 

APPLICABLE As described in LCO 3.0.7, compliance with Special Test Exception LCOs 

SAFETY is optional, and therefore no criteria of 10 CFR 50.36(c)(2)(ii) apply. 

ANALYSES Special Test Exception LCOs provide flexibility to perform certain 

operations by appropriately modifying requirements of other LCOs. A 

discussion of the criteria satisfied for the other LCOs is provided in their 

respective Bases. 
STE - RCS Loops 

B 3.4.17 

CEOG STS B 3.4.17-2 Rev. 3.0, 03/31/04 

BASES 

LCO This LCO is provided to allow for the performance of PHYSICS TESTS in 

MODE 2 (after a refueling), where the core cooling requirements are 

significantly different than after the core has been operating. Without this 

LCO, plant operations would be held bound to the normal operating LCOs 

for reactor coolant loops and circulation (MODES 1 and 2), and the 

appropriate tests could not be performed. 

In MODE 2, where core power level is considerably lower and the 

associated PHYSICS TESTS must be performed, operation is allowed 

under no flow conditions provided THERMAL POWER is < 5% RTP and 

the reactor trip setpoints of the OPERABLE power level channels are set 

≤ 20% RTP. These limits ensure no Safety Limits or fuel design limits will 

be violated. 

The exception is allowed even though there are no bounding safety 

analyses. These tests are allowed since they are performed under close 

supervision during the test program and provide valuable information on 

the plant's capability to cool down without offsite power available to the 

reactor coolant pumps. 

APPLICABILITY This LCO ensures that the plant will not be operated in MODE 1 without 

forced circulation. It only allows testing under these conditions while in 

MODE 2. This testing establishes that heat input from nuclear heat does 

not exceed the natural circulation heat removal capabilities. Therefore, 

no safety or fuel design limits will be violated as a result of the associated 

tests. 

ACTIONS A.1

If THERMAL POWER increases to > 5% RTP, the reactor must be tripped 

immediately. This ensures the plant is not placed in an unanalyzed 

condition and prevents exceeding the specified acceptable fuel design 

limits. 

SURVEILLANCE SR 3.4.17.1

REQUIREMENTS 

THERMAL POWER must be verified to be within limits once per hour to 

ensure that the fuel design criteria are not violated during the 

performance of the PHYSICS TESTS. The hourly Frequency has been 

shown by operating practice to be sufficient to regularly assess conditions 

for potential degradation and verify operation is within the LCO limits. 

Plant operations are conducted slowly during the performance of 

PHYSICS TESTS, and monitoring the power level once per hour is 

sufficient to ensure that the power level does not exceed the limit. 
STE - RCS Loops 

B 3.4.17 

CEOG STS B 3.4.17-3 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.4.17.2

Within 12 hours of initiating startup or PHYSICS TESTS, a CHANNEL 

FUNCTIONAL TEST must be performed on each logarithmic power level 

and linear power level neutron flux monitoring channel to verify 

OPERABILITY and adjust setpoints to proper values. This will ensure 

that the Reactor Protection System is properly aligned to provide the 

required degree of core protection during startup or the performance of 

the PHYSICS TESTS. A successful test of the required contact(s) of a 

channel relay may be performed by the verification of the change of state 

of a single contact of the relay. This clarifies what is an acceptable 

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because 

all of the other required contacts of the relay are verified by other 

Technical Specifications and non-Technical Specifications tests at least 

once per refueling interval with applicable extensions. The interval is 

adequate to ensure that the appropriate equipment is OPERABLE prior to 

the tests to aid the monitoring and protection of the plant during these 

tests. 

REFERENCES 1. 10 CFR 50, Appendix B, Section XI. 

 2. 10 CFR 50, Appendix A, GDC 1, 1988. 
SITs 

B 3.5.1 

CEOG STS B 3.5.1-1 Rev. 3.0, 03/31/04 

B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 

B 3.5.1 Safety Injection Tanks (SITs) 

BASES 

BACKGROUND The functions of the [four] SITs are to supply water to the reactor vessel 

during the blowdown phase of a loss of coolant accident (LOCA), to 

provide inventory to help accomplish the refill phase that follows 

thereafter, and to provide Reactor Coolant System (RCS) makeup for a 

small break LOCA. 

The blowdown phase of a large break LOCA is the initial period of the 

transient during which the RCS departs from equilibrium conditions, and 

heat from fission product decay, hot internals, and the vessel continues to 

be transferred to the reactor coolant. The blowdown phase of the 

transient ends when the RCS pressure falls to a value approaching that of 

the containment atmosphere. 

The refill phase of a LOCA follows immediately where reactor coolant 

inventory has vacated the core through steam flashing and ejection out 

through the break. The core is essentially in adiabatic heatup. The 

balance of the SITs' inventory is then available to help fill voids in the 

lower plenum and reactor vessel downcomer to establish a recovery level 

at the bottom of the core and ongoing reflood of the core with the addition 

of safety injection (SI) water. 

The SITs are pressure vessels partially filled with borated water and 

pressurized with nitrogen gas. The SITs are passive components, since 

no operator or control action is required for them to perform their function. 

Internal tank pressure is sufficient to discharge the contents to the RCS, if 

RCS pressure decreases below the SIT pressure. 

Each SIT is piped into one RCS cold leg via the injection lines utilized by 

the High Pressure Safety Injection and Low Pressure Safety Injection 

(HPSI and LPSI) systems. Each SIT is isolated from the RCS by a motor 

operated isolation valve and two check valves in series. The motor 

operated isolation valves are normally open, with power removed from 

the valve motor to prevent inadvertent closure prior to or during an 

accident. 

The SIT gas and water volumes, gas pressure, and outlet pipe size are 

selected to allow three of the four SITs to partially recover the core before 

significant clad melting or zirconium water reaction can occur following a 

LOCA. The need to ensure that three SITs are adequate for this function 

is consistent with the LOCA assumption that the entire contents of one 

SIT will be lost via the break during the blowdown phase of a LOCA. 
SITs 

B 3.5.1 

CEOG STS B 3.5.1-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The SITs are taken credit for in both the large and small break LOCA 

SAFETY analyses at full power (Ref. 1). These are the Design Basis Accidents 

ANALYSES (DBAs) that establish the acceptance limits for the SITs. Reference to the 

analyses for these DBAs is used to assess changes to the SITs as they 

relate to the acceptance limits. 

In performing the LOCA calculations, conservative assumptions are made 

concerning the availability of SI flow. These assumptions include signal 

generation time, equipment starting times, and delivery time due to 

system piping. In the early stages of a LOCA with a loss of offsite power, 

the SITs provide the sole source of makeup water to the RCS. (The 

assumption of a loss of offsite power is required by regulations.) This is 

because the LPSI pumps, HPSI pumps, and charging pumps cannot 

deliver flow until the diesel generators (DGs) start, come to rated speed, 

and go through their timed loading sequence. In cold leg breaks, the 

entire contents of one SIT are assumed to be lost through the break 

during the blowdown and reflood phases. 

The limiting large break LOCA is a double ended guillotine cold leg break 

at the discharge of the reactor coolant pump. 

During this event, the SITs discharge to the RCS as soon as RCS 

pressure decreases to below SIT pressure. As a conservative estimate, 

no credit is taken for SI pump flow until the SITs are empty. This results 

in a minimum effective delay of over 60 seconds, during which the SITs 

must provide the core cooling function. The actual delay time does not 

exceed 30 seconds. No operator action is assumed during the blowdown 

stage of a large break LOCA. 

The worst case small break LOCA also assumes a time delay before 

pumped flow reaches the core. For the larger range of small breaks, the 

rate of blowdown is such that the increase in fuel clad temperature is 

terminated solely by the SITs, with pumped flow then providing continued 

cooling. As break size decreases, the SITs and HPSI pumps both play a 

part in terminating the rise in clad temperature. As break size continues 

to decrease, the role of the SITs continues to decrease until they are not 

required, and the HPSI pumps become solely responsible for terminating 

the temperature increase. 

This LCO helps to ensure that the following acceptance criteria, 

established by 10 CFR 50.46 (Ref. 2) for the ECCS, will be met following 

a LOCA: 
SITs 

B 3.5.1 

CEOG STS B 3.5.1-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

a. Maximum fuel element cladding temperature is ≤ 2200°F, 

b. Maximum cladding oxidation is ≤ 0.17 times the total cladding 

thickness before oxidation, 

c. Maximum hydrogen generation from a zirconium water reaction is 

≤ 0.01 times the hypothetical amount that would be generated if all of 

the metal in the cladding cylinders surrounding the fuel, excluding the 

cladding surrounding the plenum volume, were to react, and 

d. The core is maintained in a coolable geometry. 

Since the SITs discharge during the blowdown phase of a LOCA, they do 

not contribute to the long term cooling requirements of 10 CFR 50.46. 

Since the SITs are passive components, single active failures are not 

applicable to their operation. The SIT isolation valves, however, are not 

single failure proof; therefore, whenever the valves are open, power is 

removed from their operators and the switch is key locked open. 

These precautions ensure that the SITs are available during an accident 

(Ref. 3). With power supplied to the valves, a single active failure could 

result in a valve closure, which would render one SIT unavailable for 

injection. If a second SIT is lost through the break, only two SITs would 

reach the core. Since the only active failure that could affect the SITs 

would be the closure of a motor operated outlet valve, the requirement to 

remove power from these eliminates this failure mode. 

The minimum volume requirement for the SITs ensures that three SITs 

can provide adequate inventory to reflood the core and downcomer 

following a LOCA. The downcomer then remains flooded until the HPSI 

and LPSI systems start to deliver flow. 

The maximum volume limit is based on maintaining an adequate gas 

volume to ensure proper injection and the ability of the SITs to fully 

discharge, as well as limiting the maximum amount of boron inventory in 

the SITs. 
SITs 

B 3.5.1 

CEOG STS B 3.5.1-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

A minimum of 25% narrow range level, corresponding to [1790] cubic feet 

of borated water, and a maximum of 75% narrow range level, 

corresponding to [1927] cubic feet of borated water, are used in the safety 

analyses as the volume in the SITs. To allow for instrument inaccuracy, a 

[28]% narrow range (corresponding to [1802] cubic feet) and a [72]% 

narrow range (corresponding to [1914] cubic feet) are specified. The 

analyses are based upon the cubic feet requirements; the percentage 

figures are provided for operator use because the level indicator provided 

in the control room is marked in percentages, not in cubic feet. 

The minimum nitrogen cover pressure requirement ensures that the 

contained gas volume will generate discharge flow rates during injection 

that are consistent with those assumed in the safety analyses. 

The maximum nitrogen cover pressure limit ensures that excessive 

amounts of gas will not be injected into the RCS after the SITs have 

emptied. 

A minimum pressure of [593] psig and a maximum pressure of [632] psig 

are used in the analyses. To allow for instrument accuracy, a [615] psig 

minimum and [655] psig maximum are specified. The maximum 

allowable boron concentration of [2800] ppm is based upon boron 

precipitation limits in the core following a LOCA. Establishing a maximum 

limit for boron is necessary since the time at which boron precipitation 

would occur in the core following a LOCA is a function of break location, 

break size, the amount of boron injected into the core, and the point of 

ECCS injection. Post LOCA emergency procedures directing the 

operator to establish simultaneous hot and cold leg injection are based on 

the worst case minimum boron precipitation time. Maintaining the 

maximum SIT boron concentration within the upper limit ensures that the 

SITs do not invalidate this calculation. An excessive boron concentration 

in any of the borated water sources used for injection during a LOCA 

could result in boron precipitation earlier than predicted. 

The minimum boron requirements of [1500] ppm are based on beginning 

of life reactivity values and are selected to ensure that the reactor will 

remain subcritical during the reflood stage of a large break LOCA. During 

a large break LOCA, all control element assemblies (CEAs) are assumed 

not to insert into the core, and the initial reactor shutdown is 
SITs 

B 3.5.1 

CEOG STS B 3.5.1-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

accomplished by void formation during blowdown. Sufficient boron 

concentration must be maintained in the SITs to prevent a return to 

criticality during reflood. Although this requirement is similar to the basis 

for the minimum boron concentration of the refueling water tank (RWT), 

the minimum SIT concentration is lower than that of the RWT since the 

SITs need not account for dilution by the RCS. 

The SITs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The LCO establishes the minimum conditions required to ensure that the 

SITs are available to accomplish their core cooling safety function 

following a LOCA. [Four] SITs are required to be OPERABLE to ensure 

that 100% of the contents of [three] of the SITs will reach the core during 

a LOCA. 

This is consistent with the assumption that the contents of one tank spill 

through the break. If the contents of fewer than three tanks are injected 

during the blowdown phase of a LOCA, the ECCS acceptance criteria of 

10 CFR 50.46 (Ref. 2) could be violated. 

For an SIT to be considered OPERABLE, the isolation valve must be fully 

open, power removed above [2000] psig, and the limits established in the 

SR for contained volume, boron concentration, and nitrogen cover 

pressure must be met. 

APPLICABILITY In MODES 1 and 2, and MODE 3 with RCS pressure ≥ 700 psia, the SIT 

OPERABILITY requirements are based on an assumption of full power 

operation. Although cooling requirements decrease as power decreases, 

the SITs are still required to provide core cooling as long as elevated 

RCS pressures and temperatures exist. 

This LCO is only applicable at pressures ≥ 700 psia. Below 700 psia, the 

rate of RCS blowdown is such that the ECCS pumps can provide 

adequate injection to ensure that peak clad temperature remains below 

the 10 CFR 50.46 (Ref. 2) limit of 2200°F. 

In MODE 3, at pressures < 700 psia, and in MODES 4, 5, and 6, the SIT 

motor operated isolation valves are closed to isolate the SITs from the 

RCS. This allows RCS cooldown and depressurization without 

discharging the SITs into the RCS or requiring depressurization of the 

SITs. 
SITs 

B 3.5.1 

CEOG STS B 3.5.1-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

If the boron concentration of one SIT is not within limits, it must be 

returned to within the limits within 72 hours. In this condition, ability to 

maintain subcriticality or minimum boron precipitation time may be 

reduced, but the reduced concentration effects on core subcriticality 

during reflood are minor. Boiling of the ECCS water in the core during 

reflood concentrates the boron in the saturated liquid that remains in the 

core. In addition, the volume of the SIT is still available for injection. 

Since the boron requirements are based on the average boron 

concentration of the total volume of three SITs, the consequences are 

less severe than they would be if an SIT were not available for injection. 

Thus, 72 hours is allowed to return the boron concentration to within 

limits. 

The combination of redundant level and pressure instrumentation for any 

single SIT provides sufficient information so that it is not worthwhile to 

always attempt to correct drift associated with one instrument, with the 

resulting radiation exposures during entry into containment, as there is 

sufficient time to repair one in the event that a second one became 

inoperable. Because these instruments do not initiate a safety action, it is 

reasonable to extend the allowable outage time for them. While 

technically inoperable, the SIT will be available to fulfill its safety function 

during this time and, thus, this Completion Time results in a negligible 

increase in risk. 

B.1

If one SIT is inoperable, for reasons other than boron concentration or the 

inability to verify level or pressure, the SIT must be returned to 

OPERABLE status within 24 hours. In this Condition, the required 

contents of three SITs cannot be assumed to reach the core during a 

LOCA as is assumed in Appendix K (Ref. 5). 

CE NPSD-994 (Ref. 6) provides a series of deterministic and probabilistic 

findings that support the 24 hour Completion Time as having no affect on 

risk as compared to shorter periods for restoring the SIT to OPERABLE 

status. 
SITs 

B 3.5.1 

CEOG STS B 3.5.1-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1 and C.2

If the SIT cannot be restored to OPERABLE status within the associated 

Completion Time, the plant must be brought to a MODE in which the LCO 

does not apply. To achieve this status, the plant must be brought to at 

least MODE 3 within 6 hours and pressurizer pressure reduced to 

< 700 psia within 12 hours. The allowed Completion Times are 

reasonable, based on operating experience, to reach the required plant 

conditions from full power conditions in an orderly manner and without 

challenging plant systems. 

D.1

If more than one SIT is inoperable, the unit is in a condition outside the 

accident analyses. Therefore, LCO 3.0.3 must be entered immediately. 

SURVEILLANCE SR 3.5.1.1

REQUIREMENTS 

Verification every 12 hours that each SIT isolation valve is fully open, as 

indicated in the control room, ensures that SITs are available for injection 

and ensures timely discovery if a valve should be partially closed. If an 

isolation valve is not fully open, the rate of injection to the RCS would be 

reduced. Although a motor operated valve should not change position 

with power removed, a closed valve could result in not meeting accident 

analysis assumptions. A 12 hour Frequency is considered reasonable in 

view of other administrative controls that ensure the unlikelihood of a 

mispositioned isolation valve. 

SR 3.5.1.2 and SR 3.5.1.3

SIT borated water volume and nitrogen cover pressure should be verified 

to be within specified limits every 12 hours in order to ensure adequate 

injection during a LOCA. Due to the static design of the SITs, a 12 hour 

Frequency usually allows the operator sufficient time to identify changes 

before the limits are reached. Operating experience has shown this 

Frequency to be appropriate for early detection and correction of off 

normal trends. 
SITs 

B 3.5.1 

CEOG STS B 3.5.1-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.5.1.4

Thirty-one days is reasonable for verification to determine that each SIT's 

boron concentration is within the required limits, because the static design 

of the SITs limits the ways in which the concentration can be changed. 

The 31 day Frequency is adequate to identify changes that could occur 

from mechanisms such as stratification or inleakage. Sampling the 

affected SIT within 6 hours after a 1% volume increase will identify 

whether inleakage has caused a reduction in boron concentration to 

below the required limit. It is not necessary to verify boron concentration 

if the added water is from the RWT, because the water contained in the 

RWT is within the SIT boron concentration requirements. This is 

consistent with the recommendations of NUREG-1366 (Ref. 4). 

SR 3.5.1.5

Verification every 31 days that power is removed from each SIT isolation 

valve operator when the pressurizer pressure is ≥ 2000 psia ensures that 

an active failure could not result in the undetected closure of an SIT motor 

operated isolation valve. If this were to occur, only two SITs would be 

available for injection, given a single failure coincident with a LOCA. 

Since installation and removal of power to the SIT isolation valve 

operators is conducted under administrative control, the 31 day 

Frequency was chosen to provide additional assurance that power is 

removed. 

This SR allows power to be supplied to the motor operated isolation 

valves when RCS pressure is < 2000 psia, thus allowing operational 

flexibility by avoiding unnecessary delays to manipulate the breakers 

during unit startups or shutdowns. 

REFERENCES 1. FSAR, Section [6.3]. 

 2. 10 CFR 50.46. 

 3. FSAR, Chapter [15]. 

 4. Draft NUREG-1366, February 1990. 

 5. 10 CFR 50 Appendix K. 

 6. CE NPSD-994, "CEOG Joint Applications Report for Safety Injection 

Tank AOT/STI Extension," May 1995. 
ECCS - Operating 

B 3.5.2 

CEOG STS B 3.5.2-1 Rev. 3.0, 03/31/04 

B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 

B 3.5.2 ECCS - Operating 

BASES 

BACKGROUND The function of the ECCS is to provide core cooling and negative 

reactivity to ensure that the reactor core is protected after any of the 

following accidents: 

a. Loss of coolant accident (LOCA), 

b. Control Element Assembly (CEA) ejection accident, 

c. Loss of secondary coolant accident, including uncontrolled steam 

release or loss of feedwater, and 

d. Steam generator tube rupture (SGTR). 

The addition of negative reactivity is designed primarily for the loss of 

secondary coolant accident where primary cooldown could add enough 

positive reactivity to achieve criticality and return to significant power. 

There are two phases of ECCS operation: injection and recirculation. In 

the injection phase, all injection is initially added to the Reactor Coolant 

System (RCS) via the cold legs. After the blowdown stage of the LOCA 

stabilizes, injection flow is split equally between the hot and cold legs. 

After the refueling water tank (RWT) has been depleted, the ECCS 

recirculation phase is entered as the ECCS suction is automatically 

transferred to the containment sump. 

Two redundant, 100% capacity trains are provided. In MODES 1, 2, 

and 3, with pressurizer pressure ≥ 1700 psia, each train consists of high 

pressure safety injection (HPSI), low pressure safety injection (LPSI), and 

charging subsystems. In MODES 1, 2, and 3, with pressurizer pressure 

≥ 1700 psia, both trains must be OPERABLE. This ensures that 100% of 

the core cooling requirements can be provided in the event of a single 

active failure. 

A suction header supplies water from the RWT or the containment sump 

to the ECCS pumps. Separate piping supplies each train. The discharge 

headers from each HPSI pump divide into four supply lines. Both HPSI 

trains feed into each of the four injection lines. The discharge header 

from each LPSI pump divides into two supply lines, each feeding the 

injection line to two RCS cold legs. Control valves or orifices are set to 

balance the flow to the RCS. This flow balance directs sufficient flow to 

the core to meet the analysis assumptions following a LOCA in one of the 

RCS cold legs. 
ECCS - Operating 

B 3.5.2 

CEOG STS B 3.5.2-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

For LOCAs that are too small to initially depressurize the RCS below the 

shutoff head of the HPSI pumps, the charging pumps supply water to 

maintain inventory until the RCS pressure decreases below the HPSI 

pump shutoff head. During this period, the steam generators (SGs) must 

provide the core cooling function. The charging pumps take suction from 

the RWT on a safety injection actuation signal (SIAS) and discharge 

directly to the RCS through a common header. The normal supply source 

for the charging pumps is isolated on an SIAS to prevent noncondensible 

gas (e.g., air, nitrogen, or hydrogen) from being entrained in the charging 

pumps. 

During low temperature conditions in the RCS, limitations are placed on 

the maximum number of HPSI pumps that may be OPERABLE. Refer to 

the Bases for LCO 3.4.12, "Low Temperature Overpressure Protection 

(LTOP) System," for the basis of these requirements. 

During a large break LOCA, RCS pressure will decrease to < 200 psia in 

< 20 seconds. The safety injection (SI) systems are actuated upon 

receipt of an SIAS. The actuation of safeguard loads is accomplished in 

a programmed time sequence. If offsite power is available, the safeguard 

loads start immediately in the programmed sequence. If offsite power is 

not available, the Engineered Safety Feature (ESF) buses shed normal 

operating loads and are connected to the diesel generators (DGs). 

Safeguard loads are then actuated in the programmed time sequence. 

The time delay associated with diesel starting, sequenced loading, and 

pump starting determines the time required before pumped flow is 

available to the core following a LOCA. 

The active ECCS components, along with the passive safety injection 

tanks (SITs) and the RWT, covered in LCO 3.5.1, "Safety Injection Tanks 

(SITs)," and LCO 3.5.4, "Refueling Water Tank (RWT)," provide the 

cooling water necessary to meet GDC 35 (Ref. 1). 

APPLICABLE The LCO helps to ensure that the following acceptance criteria, 

SAFETY established by 10 CFR 50.46 (Ref. 2) for ECCSs, will be met following a 

ANALYSES LOCA: 

a. Maximum fuel element cladding temperature is ≤ 2200°F, 

b. Maximum cladding oxidation is ≤ 0.17 times the total cladding 

thickness before oxidation, 
ECCS - Operating 

B 3.5.2 

CEOG STS B 3.5.2-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

c. Maximum hydrogen generation from a zirconium water reaction is 

≤ 0.01 times the hypothetical amount generated if all of the metal in 

the cladding cylinders surrounding the fuel, excluding the cladding 

surrounding the plenum volume, were to react, 

d. Core is maintained in a coolable geometry, and 

e. Adequate long term core cooling capability is maintained. 

The LCO also limits the potential for a post trip return to power following a 

steam line break (SLB) and ensures that containment temperature limits 

are met. 

Both HPSI and LPSI subsystems are assumed to be OPERABLE in the 

large break LOCA analysis at full power (Ref. 3). This analysis 

establishes a minimum required runout flow for the HPSI and LPSI 

pumps, as well as the maximum required response time for their 

actuation. The HPSI pumps and charging pumps are credited in the 

small break LOCA analysis. This analysis establishes the flow and 

discharge head requirements at the design point for the HPSI pump. The 

SGTR and SLB analyses also credit the HPSI pumps, but are not limiting 

in their design. 

The large break LOCA event with a loss of offsite power and a single 

failure (disabling one ECCS train) establishes the OPERABILITY 

requirements for the ECCS. During the blowdown stage of a LOCA, the 

RCS depressurizes as primary coolant is ejected through the break into 

the containment. The nuclear reaction is terminated either by moderator 

voiding during large breaks or control element assembly (CEA) insertion 

during small breaks. Following depressurization, emergency cooling 

water is injected into the cold legs, flows into the downcomer, fills the 

lower plenum, and refloods the core. 

On smaller breaks, RCS pressure will stabilize at a value dependent upon 

break size, heat load, and injection flow. The smaller the break, the 

higher this equilibrium pressure. In all LOCA analyses, injection flow is 

not credited until RCS pressure drops below the shutoff head of the HPSI 

pumps. 
ECCS - Operating 

B 3.5.2 

CEOG STS B 3.5.2-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The LCO ensures that an ECCS train will deliver sufficient water to match 

decay heat boiloff rates soon enough to minimize core uncovery for a 

large LOCA. It also ensures that the HPSI pump will deliver sufficient 

water during a small break LOCA and provide sufficient boron to maintain 

the core subcritical following an SLB. For smaller LOCAs, the charging 

pumps deliver sufficient fluid to maintain RCS inventory until the RCS can 

be depressurized below the HPSI pumps' shutoff head. During this 

period of a small break LOCA, the SGs continue to serve as the heat sink 

providing core cooling. 

ECCS - Operating satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO In MODES 1, 2, and 3, with pressurizer pressure ≥ 1700 psia, two 

independent (and redundant) ECCS trains are required to ensure that 

sufficient ECCS flow is available, assuming there is a single failure 

affecting either train. Additionally, individual components within the 

ECCS trains may be called upon to mitigate the consequences of other 

transients and accidents. 

In MODES 1 and 2, and in MODE 3 with pressurizer pressure 

≥ 1700 psia, an ECCS train consists of an HPSI subsystem, an LPSI 

subsystem, and a charging pump. 

Each train includes the piping, instruments, and controls to ensure the 

availability of an OPERABLE flow path capable of taking suction from the 

RWT on an SIAS and automatically transferring suction to the 

containment sump upon a recirculation actuation signal (RAS). 

During an event requiring ECCS actuation, a flow path is provided to 

ensure an abundant supply of water from the RWT to the RCS, via the 

HPSI and LPSI pumps and their respective supply headers, to each of the 

four cold leg injection nozzles. In the long term, this flow path may be 

switched to take its supply from the containment sump and to supply part 

of its flow to the RCS hot legs via the shutdown cooling (SDC) suction 

nozzles. The charging pump flow path takes suction from the RWT and 

supplies the RCS via the normal charging lines. 

The flow path for each train must maintain its designed independence to 

ensure that no single failure can disable both ECCS trains. 
ECCS - Operating 

B 3.5.2 

CEOG STS B 3.5.2-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODES 1 and 2, and in MODE 3 with RCS pressure ≥ 1700 psia, the 

ECCS OPERABILITY requirements for the limiting Design Basis Accident 

(DBA) large break LOCA are based on full power operation. Although 

reduced power would not require the same level of performance, the 

accident analysis does not provide for reduced cooling requirements in 

the lower MODES. The HPSI pump performance is based on the small 

break LOCA, which establishes the pump performance curve and has 

less dependence on power. The charging pump performance 

requirements are based on a small break LOCA. The requirements of 

MODES 2 and 3, with RCS pressure ≥ 1700 psia, are bounded by the 

MODE 1 analysis. 

The ECCS functional requirements of MODE 3, with RCS pressure 

< 1700 psia, and MODE 4 are described in LCO 3.5.3, "ECCS - 

Shutdown." 

In MODES 5 and 6, unit conditions are such that the probability of an 

event requiring ECCS injection is extremely low. Core cooling 

requirements in MODE 5 are addressed by LCO 3.4.7, "RCS Loops - 

MODE 5, Loops Filled," and LCO 3.4.8, "RCS Loops - MODE 5, Loops 

Not Filled." MODE 6 core cooling requirements are addressed by 

LCO 3.9.4, "Shutdown Cooling (SDC) and Coolant Circulation - High 

Water Level," and LCO 3.9.5, "Shutdown Cooling (SDC) and Coolant 

Circulation - Low Water Level." 

ACTIONS A.1

With one LPSI subsystem inoperable, action must be taken to restore 

OPERABLE status within 7 days. In this condition, the remaining 

OPERABLE ECCS train is adequate to perform the heat removal 

function. However, the overall reliability is reduced because a single 

failure to the remaining LPSI subsystem could result in loss of ECCS 

function. The 7 day Completion Time is reasonable to perform corrective 

maintenance on the inoperable LPSI subsystem. The 7 day Completion 

Time is based on the findings of the deterministic and probabilistic 

analysis in Reference 6. Reference 6 concluded that extending the 

Completion Time to 7 days for an inoperable LPSI train provides plant 

operational flexibility while simultaneously reducing overall plant risk. 

This is because the risks incurred by having the LPSI train unavailable for 

a longer time at power will be substantially offset by the benefits 

associated with avoiding unnecessary plant transitions and by reducing 

risk during plant shutdown operations. 
ECCS - Operating 

B 3.5.2 

CEOG STS B 3.5.2-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1

If one or more trains are inoperable except for reasons other than 

Condition A (one LPSI subsystem inoperable) and at least 100% of the 

ECCS flow equivalent to a single OPERABLE ECCS train is available, the 

inoperable components must be returned to OPERABLE status within 

72 hours. The 72 hour Completion Time is based on an NRC study 

(Ref. 4) using a reliability evaluation and is a reasonable amount of time 

to effect many repairs. 

An ECCS train is inoperable if it is not capable of delivering the design 

flow to the RCS. The individual components are inoperable if they are not 

capable of performing their design function, or if supporting systems are 

not available. 

The LCO requires the OPERABILITY of a number of independent 

subsystems. Due to the redundancy of trains and the diversity of 

subsystems, the inoperability of one component in a train does not render 

the ECCS incapable of performing its function. Neither does the 

inoperability of two different components, each in a different train, 

necessarily result in a loss of function for the ECCS. This allows 

increased flexibility in plant operations when components in opposite 

trains are inoperable. 

An event accompanied by a loss of offsite power and the failure of an 

emergency DG can disable one ECCS train until power is restored. A 

reliability analysis (Ref. 4) has shown that the impact with one full ECCS 

train inoperable is sufficiently small to justify continued operation for 

72 hours. 

Reference 5 describes situations in which one component, such as a 

shutdown cooling total flow control valve, can disable both ECCS trains. 

With one or more components inoperable, such that 100% of the 

equivalent flow to a single OPERABLE ECCS train is not available, the 

facility is in a condition outside the accident analyses. Therefore, 

LCO 3.0.3 must be immediately entered. 
ECCS - Operating 

B 3.5.2 

CEOG STS B 3.5.2-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1 and C.2

If the inoperable train cannot be restored to OPERABLE status within the 

associated Completion Time, the plant must be brought to a MODE in 

which the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and pressurizer pressure 

reduced to < 1700 psia within 12 hours. The allowed Completion Times 

are reasonable, based on operating experience, to reach the required unit 

conditions from full power in an orderly manner and without challenging 

unit systems. 

D.1

Condition B is applicable with one or more trains inoperable. The allowed 

Completion Time is based on the assumption that at least 100% of the 

ECCS flow equivalent to a single OPERABLE ECCS train is available. 

With less than 100% of the ECCS flow equivalent to a single OPERABLE 

ECCS train available, the facility is in a condition outside of the accident 

analyses. Therefore, LCO 3.0.3 must be entered immediately. 

SURVEILLANCE SR 3.5.2.1

REQUIREMENTS 

Verification of proper valve position ensures that the flow path from the 

ECCS pumps to the RCS is maintained. Misalignment of these valves 

could render both ECCS trains inoperable. Securing these valves in 

position by removing power or by key locking the control in the correct 

position ensures that the valves cannot be inadvertently misaligned or 

change position as the result of an active failure. These valves are of the 

type described in Reference 5, which can disable the function of both 

ECCS trains and invalidate the accident analysis. A 12 hour Frequency is 

considered reasonable in view of other administrative controls ensuring 

that a mispositioned valve is an unlikely possibility. 

SR 3.5.2.2

Verifying the correct alignment for manual, power operated, and 

automatic valves in the ECCS flow paths provides assurance that the 

proper flow paths will exist for ECCS operation. This SR does not apply 

to valves that are locked, sealed, or otherwise secured in position, since 

these valves were verified to be in the correct position prior to locking, 
ECCS - Operating 

B 3.5.2 

CEOG STS B 3.5.2-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

sealing, or securing. A valve that receives an actuation signal is allowed 

to be in a nonaccident position provided the valve automatically 

repositions within the proper stroke time. This Surveillance does not 

require any testing or valve manipulation. Rather, it involves verification 

that those valves capable of being mispositioned are in the correct 

position. 

The 31 day Frequency is appropriate because the valves are operated 

under procedural control and an improper valve position would only affect 

a single train. This Frequency has been shown to be acceptable through 

operating experience. 

SR 3.5.2.3

With the exception of systems in operation, the ECCS pumps are 

normally in a standby, nonoperating mode. As such, flow path piping has 

the potential to develop voids and pockets of entrained gases. 

Maintaining the piping from the ECCS pumps to the RCS full of water 

ensures that the system will perform properly, injecting its full capacity 

into the RCS upon demand. This will also prevent water hammer, pump 

cavitation, and pumping of noncondensible gas (e.g., air, nitrogen, or 

hydrogen) into the reactor vessel following an SIAS or during SDC. The 

31 day Frequency takes into consideration the gradual nature of gas 

accumulation in the ECCS piping and the adequacy of the procedural 

controls governing system operation. 

SR 3.5.2.4

Periodic surveillance testing of ECCS pumps to detect gross degradation 

caused by impeller structural damage or other hydraulic component 

problems is required by Section XI of the 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 unit safety 

analysis. SRs are specified in the Inservice Testing Program, which 

encompasses Section XI of the ASME Code. Section XI of the ASME 

Code provides the activities and Frequencies necessary to satisfy the 

requirements. 
ECCS - Operating 

B 3.5.2 

CEOG STS B 3.5.2-9 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.5.2.5

Discharge head at design flow is a normal test of charging pump 

performance required by Section XI of the ASME Code. A quarterly 

Frequency for such tests is a Code requirement. Such inservice 

inspections detect component degradation and incipient failures. 

SR 3.5.2.6, SR 3.5.2.7, and SR 3.5.2.8

These SRs demonstrate that each automatic ECCS valve actuates to the 

required position on an actual or simulated SIAS and on an RAS, that 

each ECCS pump starts on receipt of an actual or simulated SIAS, and 

that the LPSI pumps stop on receipt of an actual or simulated RAS. This 

Surveillance 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 these 

Surveillances under the conditions that apply during a plant outage and 

the potential for unplanned 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. The actuation logic is tested as part of the 

Engineered Safety Feature Actuation System (ESFAS) testing, and 

equipment performance is monitored as part of the Inservice Testing 

Program. 

SR 3.5.2.9

Realignment of valves in the flow path on an SIAS is necessary for proper 

ECCS performance. The safety injection valves have stops to position 

them properly so that flow is restricted to a ruptured cold leg, ensuring 

that the other cold legs receive at least the required minimum flow. This 

SR is not required for units with flow limiting orifices. The 18 month 

Frequency is based on the same factors as those stated above for 

SR 3.5.2.6, SR 3.5.2.7, and SR 3.5.2.8. 
ECCS - Operating 

B 3.5.2 

CEOG STS B 3.5.2-10 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.5.2.10

Periodic inspection of the containment sump ensures that it is unrestricted 

and stays in proper operating condition. The 18 month Frequency is 

based on the need to perform this Surveillance under the conditions that 

apply during an outage, on the need to have access to the location, and 

on the potential for unplanned transients if the Surveillance were 

performed with the reactor at power. This Frequency is sufficient to 

detect abnormal degradation and is confirmed by operating experience. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 35. 

 2. 10 CFR 50.46. 

 3. FSAR, Chapter [6]. 

 4. NRC Memorandum to V. Stello, Jr., from R. L. Baer, "Recommended 

Interim Revisions to LCOs for ECCS Components," 

December 1, 1975. 

 5. IE Information Notice No. 87-01, January 6, 1987. 

 6. CE NPSD-995, "Low Pressure Safety Injection System AOT 

Extension," May 1995. 
ECCS - Shutdown 

B 3.5.3 

CEOG STS B 3.5.3-1 Rev. 3.0, 03/31/04 

B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 

B 3.5.3 ECCS - Shutdown 

BASES 

BACKGROUND The Background section for Bases B 3.5.2, "ECCS - Operating," is 

applicable to these Bases, with the following modifications. 

In MODE 3 with pressurizer pressure < 1700 psia and in MODE 4, an 

ECCS train is defined as one high pressure safety injection (HPSI) 

subsystem. The HPSI flow path consists of piping, valves, and pumps 

that enable water from the refueling water tank (RWT) to be injected into 

the Reactor Coolant System (RCS) following the accidents described in 

Bases 3.5.2. 

APPLICABLE The Applicable Safety Analyses section of Bases 3.5.2 is applicable to 

SAFETY these Bases. 

ANALYSES 

Due to the stable conditions associated with operation in MODE 4, and 

the reduced probability of a Design Basis Accident (DBA), the ECCS 

operational requirements are reduced. Included in these reductions is 

that certain automatic safety injection (SI) actuation signals are not 

available. In this MODE, sufficient time exists for manual actuation of the 

required ECCS to mitigate the consequences of a DBA. 

Only one train of ECCS is required for MODE 4. Protection against single 

failures is not relied on for this MODE of operation. 

ECCS - Shutdown satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO In MODE 3 with pressurizer pressure < 1700 psia, an ECCS subsystem is 

composed of a single HPSI subsystem. Each HPSI subsystem includes 

the piping, instruments, and controls to ensure an OPERABLE flow path 

capable of taking suction from the RWT and transferring suction to the 

containment sump. 

During an event requiring ECCS actuation, a flow path is required to 

supply water from the RWT to the RCS via the HPSI pumps and their 

respective supply headers to each of the four cold leg injection nozzles. 

In the long term, this flow path may be switched to take its supply from 

the containment sump and to deliver its flow to the RCS hot and cold 

legs. 
ECCS - Shutdown 

B 3.5.3 

CEOG STS B 3.5.3-2 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

With RCS pressure < 1700 psia, one HPSI pump is acceptable without 

single failure consideration, based on the stable reactivity condition of the 

reactor and the limited core cooling requirements. The low pressure 

safety injection (LPSI) pumps may therefore be released from the ECCS 

train for use in shutdown cooling (SDC). In MODE 4 with RCS cold leg 

temperature less than or equal to the LTOP enable temperature specified 

in the PTLR, a maximum of one HPSI pump is allowed to be OPERABLE 

in accordance with LCO 3.4.12, "Low Temperature Overpressure 

Protection (LTOP) System." 

APPLICABILITY In MODES 1, 2, and 3 with RCS pressure ≥ 1700 psia, the OPERABILITY 

requirements for ECCS are covered by LCO 3.5.2. 

In MODE 3 with RCS pressure < 1700 psia and in MODE 4, one 

OPERABLE ECCS train is acceptable without single failure consideration, 

based on the stable reactivity condition of the reactor and the limited core 

cooling requirements. 

In MODES 5 and 6, unit conditions are such that the probability of an 

event requiring ECCS injection is extremely low. Core cooling 

requirements in MODE 5 are addressed by LCO 3.4.7, "RCS Loops - 

MODE 5, Loops Filled," and LCO 3.4.8, "RCS Loops - MODE 5, Loops 

Not Filled." MODE 6 core cooling requirements are addressed by 

LCO 3.9.4, "Shutdown Cooling (SDC) and Coolant Circulation - High 

Water Level," and LCO 3.9.5, "Shutdown Cooling (SDC) and Coolant 

Circulation - Low Water Level." 

ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable ECCS 

High Pressure Safety Injection subsystem. There is an increased risk 

associated with entering MODE 4 from MODE 5 with an inoperable ECCS 

High Pressure Safety Injection subsystem and the provisions of 

LCO 3.0.4.b, which allow entry into a MODE or other specified condition 

in the Applicability with the LCO not met after performance of a risk 

assessment addressing inoperable systems and components, should not 

be applied in this circumstance. 

 A.1

With no HPSI pump OPERABLE, the unit is not prepared to respond to a 

loss of coolant accident. The 1 hour Completion Time to restore at least 

one HPSI train to OPERABLE status ensures that prompt action is taken 

to restore the required cooling capacity or to initiate actions to place the 

unit in MODE 5, where an ECCS train is not required. 
ECCS - Shutdown 

B 3.5.3 

CEOG STS B 3.5.3-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

 B.1

When the Required Action cannot be completed within the required 

Completion Time, a controlled shutdown should be initiated. Twenty-four 

hours is reasonable, based on operating experience, to reach MODE 5 in 

an orderly manner and without challenging plant systems. 

SURVEILLANCE SR 3.5.3.1

REQUIREMENTS 

The applicable Surveillance descriptions from Bases 3.5.2 apply. 

REFERENCES The applicable references from Bases 3.5.2 apply. 
RWT 

B 3.5.4 

CEOG STS B 3.5.4-1 Rev. 3.0, 03/31/04 

B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 

B 3.5.4 Refueling Water Tank (RWT) 

BASES 

BACKGROUND The RWT supports the ECCS and the Containment Spray System by 

providing a source of borated water for Engineered Safety Feature (ESF) 

pump operation. 

The RWT supplies two ECCS trains by separate, redundant supply 

headers. Each header also supplies one train of the Containment Spray 

System. A motor operated isolation valve is provided in each header to 

allow the operator to isolate the usable volume of the RWT from the 

ECCS after the ESF pump suction has been transferred to the 

containment sump following depletion of the RWT during a loss of coolant 

accident (LOCA). A separate header is used to supply the Chemical and 

Volume Control System (CVCS) from the RWT. Use of a single RWT to 

supply both trains of the ECCS is acceptable since the RWT is a passive 

component, and passive failures are not assumed to occur coincidently 

with the Design Basis Event during the injection phase of an accident. 

Not all the water stored in the RWT is available for injection following a 

LOCA; the location of the ECCS suction piping in the RWT will result in 

some portion of the stored volume being unavailable. 

The high pressure safety injection (HPSI), low pressure safety injection 

(LPSI), and containment spray pumps are provided with recirculation lines 

that ensure each pump can maintain minimum flow requirements when 

operating at shutoff head conditions. These lines discharge back to the 

RWT, which vents to the atmosphere. When the suction for the HPSI and 

containment spray pumps is transferred to the containment sump, this 

flow path must be isolated to prevent a release of the containment sump 

contents to the RWT. If not isolated, this flow path could result in a 

release of contaminants to the atmosphere and the eventual loss of 

suction head for the ESF pumps. 

This LCO ensures that: 

a. The RWT contains sufficient borated water to support the ECCS 

during the injection phase, 

b. Sufficient water volume exists in the containment sump to support 

continued operation of the ESF pumps at the time of transfer to the 

recirculation mode of cooling, and 

c. The reactor remains subcritical following a LOCA. 
RWT 

B 3.5.4 

CEOG STS B 3.5.4-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Insufficient water inventory in the RWT could result in insufficient cooling 

capacity of the ECCS when the transfer to the recirculation mode occurs. 

Improper boron concentrations could result in a reduction of SDM or 

excessive boric acid precipitation in the core following a LOCA, as well as 

excessive caustic stress corrosion of mechanical components and 

systems inside containment. 

APPLICABLE During accident conditions, the RWT provides a source of borated water 

SAFETY to the HPSI, LPSI, containment spray, and charging pumps. As such, it 

ANALYSES provides containment cooling and depressurization, core cooling, and 

replacement inventory and is a source of negative reactivity for reactor 

shutdown (Ref. 1). The design basis transients and applicable safety 

analyses concerning each of these systems are discussed in the 

Applicable Safety Analyses section of Bases B 3.5.2, "ECCS - Operating," 

and B 3.6.6, "Containment Spray and Cooling Systems." These analyses 

are used to assess changes to the RWT in order to evaluate their effects 

in relation to the acceptance limits. 

The volume limit of [362,800] gallons is based on two factors: 

a. Sufficient deliverable volume must be available to provide at least 

20 minutes (plus a 10% margin) of full flow from all ESF pumps prior 

to reaching a low level switchover to the containment sump for 

recirculation and 

b. The containment sump water volume must be sufficient to support 

continued ESF pump operation after the switchover to recirculation 

occurs. This sump volume water inventory is supplied by the RWT 

borated water inventory. 

Twenty minutes is the point at which 75% of the design flow of one HPSI 

pump is capable of meeting or exceeding the decay heat boiloff rate. 

When ESF pump suction is transferred to the sump, there must be 

sufficient water in the sump to ensure adequate net positive suction head 

(NPSH) for the HPSI and containment spray pumps. The RWT capacity 

must be sufficient to supply this amount of water without considering the 

inventory added from the safety injection tanks or Reactor Coolant 

System (RCS), but accounting for loss of inventory to containment 

subcompartments and reservoirs due to containment spray operation and 

to areas outside containment due to leakage from ECCS injection and 

recirculation equipment. 
RWT 

B 3.5.4 

CEOG STS B 3.5.4-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The [1720] ppm limit for minimum boron concentration was established to 

ensure that, following a LOCA with a minimum level in the RWT, the 

reactor will remain subcritical in the cold condition following mixing of the 

RWT and RCS water volumes. Small break LOCAs assume that all 

control rods are inserted, except for the control element assembly (CEA) 

of highest worth, which is withdrawn from the core. Large break LOCAs 

assume that all CEAs remain withdrawn from the core. The most limiting 

case occurs at beginning of core life. 

The maximum boron limit of [2500] ppm in the RWT is based on boron 

precipitation in the core following a LOCA. With the reactor vessel at 

saturated conditions, the core dissipates heat by pool nucleate boiling. 

Because of this boiling phenomenon in the core, the boric acid 

concentration will increase in this region. If allowed to proceed in this 

manner, a point will be reached where boron precipitation will occur in the 

core. Post LOCA emergency procedures direct the operator to establish 

simultaneous hot and cold leg injection to prevent this condition by 

establishing a forced flow path through the core regardless of break 

location. These procedures are based on the minimum time in which 

precipitation could occur, assuming that maximum boron concentrations 

exist in the borated water sources used for injection following a LOCA. 

Boron concentrations in the RWT in excess of the limit could result in 

precipitation earlier than assumed in the analysis. 

The upper limit of [100]°F and the lower limit of [40]°F on RWT 

temperature are the limits assumed in the accident analysis. Although 

RWT temperature affects the outcome of several analyses, the upper and 

lower limits established by the LCO are not limited by any of these 

analyses. 

The RWT satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The RWT ensures that an adequate supply of borated water is available 

to cool and depressurize the containment in the event of a Design Basis 

Accident (DBA) and to cool and cover the core in the event of a LOCA, 

that the reactor remains subcritical following a DBA, and that an adequate 

level exists in the containment sump to support ESF pump operation in 

the recirculation mode. 

To be considered OPERABLE, the RWT must meet the limits established 

in the SRs for water volume, boron concentration, and temperature. 
RWT 

B 3.5.4 

CEOG STS B 3.5.4-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODES 1, 2, 3, and 4, the RWT OPERABILITY requirements are 

dictated by the ECCS and Containment Spray System OPERABILITY 

requirements. Since both the ECCS and the Containment Spray System 

must be OPERABLE in MODES 1, 2, 3, and 4, the RWT must be 

OPERABLE to support their operation. 

Core cooling requirements in MODE 5 are addressed by LCO 3.4.7, 

"RCS Loops - MODE 5, Loops Filled," and LCO 3.4.8, "RCS Loops - 

MODE 5, Loops Not Filled." MODE 6 core cooling requirements are 

addressed by LCO 3.9.4, "Shutdown Cooling (SDC) and Coolant 

Circulation - High Water Level," and LCO 3.9.5, "Shutdown Cooling 

(SDC) and Coolant Circulation - Low Water Level." 

ACTIONS A.1

With RWT boron concentration or borated water temperature not within 

limits, it must be returned to within limits within 8 hours. In this condition 

neither the ECCS nor the Containment Spray System can perform their 

design functions; therefore, prompt action must be taken to restore the 

tank to OPERABLE condition. The allowed Completion Time of 8 hours to 

restore the RWT to within limits was developed considering the time 

required to change boron concentration or temperature and that the 

contents of the tank are still available for injection. 

B.1

With RWT borated water volume not within limits, it must be returned to 

within limits within 1 hour. In this condition, neither the ECCS nor 

Containment Spray System can perform their design functions; therefore, 

prompt action must be taken to restore the tank to OPERABLE status or 

to place the unit in a MODE in which these systems are not required. The 

allowed Completion Time of 1 hour to restore the RWT to OPERABLE 

status is based on this condition simultaneously affecting multiple 

redundant trains. 

C.1 and C.2

If the RWT cannot be restored to OPERABLE status within the associated 

Completion Time, the plant must be brought to a MODE in which the LCO 

does not apply. To achieve this status, the plant must be brought to at 

least MODE 3 within 6 hours and to MODE 5 within 36 hours. The 

allowed Completion Times are reasonable, based on operating 

experience, to reach the required plant conditions from full power 

conditions in an orderly manner and without challenging plant systems. 
RWT 

B 3.5.4 

CEOG STS B 3.5.4-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.5.4.1

REQUIREMENTS 

RWT borated water temperature shall be verified every 24 hours to be 

within the limits assumed in the accident analysis. This Frequency has 

been shown to be sufficient to identify temperature changes that 

approach either acceptable limit. 

The SR is modified by a Note that eliminates the requirement to perform 

this Surveillance when ambient air temperatures are within the operating 

temperature limits of the RWT. With ambient temperatures within this 

range, the RWT temperature should not exceed the limits. 

SR 3.5.4.2

Above minimum RWT water volume level shall be verified every 7 days. 

This Frequency ensures that a sufficient initial water supply is available 

for injection and to support continued ESF pump operation on 

recirculation. Since the RWT volume is normally stable and is provided 

with a Low Level Alarm, a 7 day Frequency is appropriate and has been 

shown to be acceptable through operating experience. 

SR 3.5.4.3

Boron concentration of the RWT shall be verified every 7 days to be 

within the required range. This Frequency ensures that the reactor will 

remain subcritical following a LOCA. Further, it ensures that the resulting 

sump pH will be maintained in an acceptable range such that boron 

precipitation in the core will not occur earlier than predicted and the effect 

of chloride and caustic stress corrosion on mechanical systems and 

components will be minimized. Since the RWT volume is normally stable, 

a 7 day sampling Frequency is appropriate and has been shown through 

operating experience to be acceptable. 

REFERENCES 1. FSAR, Chapter [6] and Chapter [15]. 
TSP 

B 3.5.5 

CEOG STS B 3.5.5-1 Rev. 3.0, 03/31/04 

B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 

B 3.5.5 Trisodium Phosphate (TSP) 

BASES 

BACKGROUND Trisodium phosphate (TSP) is placed on the floor or in the sump of the 

containment building to ensure that iodine, which may be dissolved in the 

recirculated reactor cooling water following a loss of coolant accident 

(LOCA), remains in solution. TSP also helps inhibit stress corrosion 

cracking (SCC) of austenitic stainless steel components in containment 

during the recirculation phase following an accident. 

Fuel that is damaged during a LOCA will release iodine in several 

chemical forms to the reactor coolant and to the containment atmosphere. 

A portion of the iodine in the containment atmosphere is washed to the 

sump by containment sprays. The emergency core cooling water is 

borated for reactivity control. This borated water causes the sump 

solution to be acidic. In a low pH (acidic) solution, dissolved iodine will be 

converted to a volatile form. The volatile iodine will evolve out of solution 

into the containment atmosphere, significantly increasing the levels of 

airborne iodine. The increased levels of airborne iodine in containment 

contribute to the radiological releases and increase the consequences 

from the accident due to containment atmosphere leakage. 

After a LOCA, the components of the core cooling and containment spray 

systems will be exposed to high temperature borated water. Prolonged 

exposure to the core cooling water combined with stresses imposed on 

the components can cause SCC. The SCC is a function of stress, 

oxygen and chloride concentrations, pH, temperature, and alloy 

composition of the components. High temperatures and low pH, which 

would be present after a LOCA, tend to promote SCC. This can lead to 

the failure of necessary safety systems or components. 

Adjusting the pH of the recirculation solution to levels above 7.0 prevents 

a significant fraction of the dissolved iodine from converting to a volatile 

form. The higher pH thus decreases the level of airborne iodine in 

containment and reduces the radiological consequences from 

containment atmosphere leakage following a LOCA. Maintaining the 

solution pH above 7.0 also reduces the occurrence of SCC of austenitic 

stainless steel components in containment. Reducing SCC reduces the 

probability of failure of components. 
TSP 

B 3.5.5 

CEOG STS B 3.5.5-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

TSP is employed as a passive form of pH control for post LOCA 

containment spray and core cooling water. Baskets of TSP are placed on 

the floor or in the sump of the containment building to dissolve from 

released reactor coolant water and containment sprays after a LOCA. 

Recirculation of the water for core cooling and containment sprays then 

provides mixing to achieve a uniform solution pH. The hydrated form (45-

57% moisture) of TSP is used because of the high humidity in the 

containment building during normal operation. Since the TSP is hydrated, 

it is less likely to absorb large amounts of water from the humid 

atmosphere and will undergo less physical and chemical change than the 

anhydrous form of TSP. 

APPLICABLE The LOCA radiological consequences analysis takes credit for iodine 

SAFETY retention in the sump solution based on the recirculation water pH being 

ANALYSES ≥ 7.0. The radionuclide releases from the containment atmosphere and 

the consequences of a LOCA would be increased if the pH of the 

recirculation water were not adjusted to 7.0 or above. 

TSP satisfies Criterion 3 of the 10 CFR 50.36(c)(2)(ii). 

LCO The TSP is required to adjust the pH of the recirculation water to > 7.0 

after a LOCA. A pH > 7.0 is necessary to prevent significant amounts of 

iodine released from fuel failures and dissolved in the recirculation water 

from converting to a volatile form and evolving into the containment 

atmosphere. Higher levels of airborne iodine in containment may 

increase the release of radionuclides and the consequences of the 

accident. A pH > 7.0 is also necessary to prevent SCC of austenitic 

stainless steel components in containment. SCC increases the 

probability of failure of components. 

The required amount of TSP is based upon the extreme cases of water 

volume and pH possible in the containment sump after a large break 

LOCA. The minimum required volume is the volume of TSP that will 

achieve a sump solution pH of ≥ 7.0 when taking into consideration the 

maximum possible sump water volume and the minimum possible pH. 

The amount of TSP needed in the containment building is based on the 

mass of TSP required to achieve the desired pH. However, a required 

volume is specified, rather than mass, since it is not feasible to weigh the 

entire amount of TSP in containment. The minimum required volume is 

based on the manufactured density of TSP. Since TSP can have a 

tendency to agglomerate from high humidity in the containment building, 

the density may increase and the volume decrease during normal plant 

operation. Due to possible agglomeration and increase in density, 

estimating the minimum volume of TSP in containment is conservative 

with respect to achieving a minimum required pH. 
TSP 

B 3.5.5 

CEOG STS B 3.5.5-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODES 1, 2, and 3, the RCS is at elevated temperature and pressure, 

providing an energy potential for a LOCA. The potential for a LOCA 

results in a need for the ability to control the pH of the recirculated 

coolant. 

In MODES 4, 5, and 6, the potential for a LOCA is reduced or 

nonexistent, and TSP is not required. 

ACTIONS A.1

If it is discovered that the TSP in the containment building sump is not 

within limits, action must be taken to restore the TSP to within limits. 

During plant operation the containment sump is not accessible and 

corrections may not be possible. 

The Completion Time of 72 hours is allowed for restoring the TSP within 

limits, where possible, because 72 hours is the same time allowed for 

restoration of other ECCS components. 

B.1 and B.2

If the TSP cannot be restored within limits within the Completion Time of 

Required Action A.1, the plant must be brought to a MODE in which the 

LCO does not apply. The specified Completion Times for reaching 

MODES 3 and 4 are those used throughout the Technical Specifications; 

they were chosen to allow reaching the specified conditions from full 

power in an orderly manner and without challenging plant systems. 

SURVEILLANCE SR 3.5.5.1

REQUIREMENTS 

Periodic determination of the volume of TSP in containment must be 

performed due to the possibility of leaking valves and components in the 

containment building that could cause dissolution of the TSP during 

normal operation. A Frequency of 18 months is required to determine 

visually that a minimum of [291] cubic feet is contained in the TSP 

baskets. This requirement ensures that there is an adequate volume of 

TSP to adjust the pH of the post LOCA sump solution to a value ≥ 7.0. 

The periodic verification is required every 18 months, since access to the 

TSP baskets is only feasible during outages, and normal fuel cycles are 

scheduled for 18 months. Operating experience has shown this 

Surveillance Frequency acceptable due to the margin in the volume of 

TSP placed in the containment building. 
TSP 

B 3.5.5 

CEOG STS B 3.5.5-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.5.5.2

Testing must be performed to ensure the solubility and buffering ability of 

the TSP after exposure to the containment environment. A representative 

sample of [ ] grams of TSP from one of the baskets in containment is 

submerged in 1.0 gal ± 0.05 gal of water at a boron concentration of 

[ ] ppm and at the standard temperature of 25°C ± 5°C. Without 

agitation, the solution pH should be raised to ≥ 7 within 4 hours. The 

representative sample weight is based on the minimum required TSP 

weight of [ ] kilograms, which at manufactured density corresponds to the 

minimum volume of [ ] cubic ft, and maximum possible post LOCA sump 

volume of [ ] gallons, normalized to buffer a 1.0 gal sample. The boron 

concentration of the test water is representative of the maximum possible 

boron concentration corresponding to the maximum possible post LOCA 

sump volume. Agitation of the test solution is prohibited, since an 

adequate standard for the agitation intensity cannot be specified. The 

test time of 4 hours is necessary to allow time for the dissolved TSP to 

naturally diffuse through the sample solution. In the post LOCA 

containment sump, rapid mixing would occur, significantly decreasing the 

actual amount of time before the required pH is achieved. This would 

ensure compliance with the Standard Review Plan requirement of a pH 

≥ 7.0 by the onset of recirculation after a LOCA. 

REFERENCES None. 
Containment (Atmospheric) 

B 3.6.1A 

CEOG STS B 3.6.1A-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.1A Containment (Atmospheric) 

BASES 

BACKGROUND The containment consists of the concrete reactor building (RB), its steel 

liner, and the penetrations through this structure. The structure is 

designed to contain radioactive material that may be released from the 

reactor core following a design basis loss of coolant accident (LOCA). 

Additionally, this structure provides shielding from the fission products 

that may be present in the containment atmosphere following accident 

conditions. 

The containment is a reinforced concrete structure with a cylindrical wall, 

a flat foundation mat, and a shallow dome roof. For containments with 

ungrouted tendons, the cylinder wall is prestressed with a post tensioning 

system in the vertical and horizontal directions, and the dome roof is 

prestressed utilizing a three way post tensioning system. The inside 

surface of the containment is lined with a carbon steel liner to ensure a 

high degree of leak tightness during operating and accident conditions. 

The concrete RB is required for structural integrity of the containment 

under Design Basis Accident (DBA) conditions. The steel liner and its 

penetrations establish the leakage limiting boundary of the containment. 

Maintaining the containment OPERABLE limits the leakage of fission 

product radioactivity from the containment to the environment. SR 3.6.1.1 

leakage rate requirements comply with 10 CFR 50, Appendix J, Option 

[A][B] (Ref. 1), as modified by approved exemptions. 

The isolation devices for the penetrations in the containment boundary 

are a part of the containment leak tight barrier. To maintain this leak tight 

barrier: 

a. All penetrations required to be closed during accident conditions are 

either: 

1. Capable of being closed by an OPERABLE automatic 

containment isolation system or 

2. Closed by manual valves, blind flanges, or de-activated 

automatic valves secured in their closed positions, except as 

provided in LCO 3.6.3, "Containment Isolation Valves," 
Containment (Atmospheric) 

B 3.6.1A 

CEOG STS B 3.6.1A-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

b. Each air lock is OPERABLE, except as provided in LCO 3.6.2, 

"Containment Air Locks," 

c. All equipment hatches are closed, and 

[ d. The pressurized sealing mechanism associated with a penetration, 

except as provided in LCO 3.6.[ ], is OPERABLE. ] 

APPLICABLE The safety design basis for the containment is that the containment must 

SAFETY withstand the pressures and temperatures of the limiting DBA without 

ANALYSES exceeding the design leakage rate. 

The DBAs that result in a release of radioactive material within 

containment are a LOCA, a main steam line break, and a control element 

assembly ejection accident (Ref. 2). In the analysis of each of these 

accidents, it is assumed that containment is OPERABLE such that 

release of fission products to the environment is controlled by the rate of 

containment leakage. The containment was designed with an allowable 

leakage rate of [0.10]% of containment air weight per day (Ref. 3). This 

leakage rate is defined in 10 CFR 50, Appendix J, Option [A][B], (Ref. 1), 

as La: the maximum allowable containment leakage rate at the calculated 

maximum peak containment pressure (Pa) of [55.7] psig, which results 

from the limiting design basis LOCA (Ref. 2). 

Satisfactory leakage rate test results are a requirement for the 

establishment of containment OPERABILITY. 

The containment satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Containment OPERABILITY is maintained by limiting leakage to ≤ 1.0 La, 

except prior to the first startup after performing a required Containment 

Leakage Rate Testing Program leakage test. At this time, the applicable 

leakage limits must be met. 

Compliance with this LCO will ensure a containment configuration, 

including equipment hatches, that is structurally sound and that will limit 

leakage to those leakage rates assumed in the safety analysis. 

Individual leakage rates specified for the containment air lock (LCO 3.6.2) 

[and purge valves with resilient seals (LCO 3.6.3)] are not specifically part 

of the acceptance criteria of 10 CFR 50, Appendix J. Therefore, leakage 

rates exceeding these individual limits only result in the containment 

being inoperable when the leakage results in exceeding the overall 

acceptance criteria of 1.0 La. 
Containment (Atmospheric) 

B 3.6.1A 

CEOG STS B 3.6.1A-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive 

material into containment. In MODES 5 and 6, the probability and 

consequences of these events are reduced due to the pressure and 

temperature limitations of these MODES. Therefore, containment is not 

required to be OPERABLE in MODE 5 to prevent leakage of radioactive 

material from containment. The requirements for containment during 

MODE 6 are addressed in LCO 3.9.3, "Containment Penetrations." 

ACTIONS A.1

In the event containment is inoperable, containment must be restored to 

OPERABLE status within 1 hour. The 1 hour Completion Time provides a 

period of time to correct the problem commensurate with the importance 

of maintaining containment during MODES 1, 2, 3, and 4. This time 

period also ensures that the probability of an accident (requiring 

containment OPERABILITY) occurring during periods when containment 

is inoperable is minimal. 

B.1 and B.2

If containment cannot be restored to OPERABLE status within the 

required Completion Time, the plant must be brought to a MODE in which 

the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 5 within 

36 hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE SR 3.6.1.1

REQUIREMENTS 

Maintaining the containment OPERABLE requires compliance with the 

visual examinations and leakage rate test requirements of the 

Containment Leakage Rate Testing Program. Failure to meet air lock 

and purge valve with resilient seal leakage limits specified in LCO 3.6.2 

and LCO 3.6.3 does not invalidate the acceptability of these overall 

leakage determinations unless their contribution to overall Type A, B, 

and C leakage causes that to exceed limits. As left leakage prior to the 

first startup after performing a required Containment Leakage Rate 

Testing Program leakage test is required to be < 0.6 La for combined 

Type B and C leakage, and [< 0.75 La for Option A] [≤ 0.75 La for 
Containment (Atmospheric) 

B 3.6.1A 

CEOG STS B 3.6.1A-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Option B] for overall Type A leakage. At all other times between required 

leakage rate tests, the acceptance criteria is based on an overall Type A 

leakage limit of ≤ 1.0 La. At ≤ 1.0 La the offsite dose consequences are 

bounded by the assumptions of the safety analysis. SR Frequencies are 

as required by the Containment Leakage Rate Testing Program. These 

periodic testing requirements verify that the containment leakage rate 

does not exceed the leakage rate assumed in the safety analysis. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Regulatory Guide 1.163 and NEI 94-01 include acceptance criteria for asleft and as-found Type A leakage rates and combined Type B and C 

leakage rates, which may be reflected in the Bases. 

-------------------------------------------------------------------------------------------------- 

[ SR 3.6.1.2

For ungrouted, post tensioned tendons, this SR ensures that the 

structural integrity of the containment will be maintained in accordance 

with the provisions of the Containment Tendon Surveillance Program. 

Testing and Frequency are consistent with the recommendations of 

Regulatory Guide 1.35 (Ref. 4). ] 

REFERENCES 1. 10 CFR 50, Appendix J, Option [A][B]. 

 2. FSAR, Section [ ]. 

 3. FSAR, Section [ ]. 

 4. Regulatory Guide 1.35, Revision [1]. 
Containment (Dual) 

B 3.6.1B 

CEOG STS B 3.6.1B-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.1B Containment (Dual) 

BASES 

BACKGROUND The containment is a free standing steel pressure vessel surrounded by a 

reinforced concrete shield building. The containment vessel, including all 

its penetrations, is a low leakage steel shell designed to contain 

radioactive material that may be released from the reactor core following 

a design basis loss of coolant accident (LOCA). Additionally, the 

containment and shield building provide shielding from the fission 

products that may be present in the containment atmosphere following 

accident conditions. 

The containment vessel is a vertical cylindrical steel pressure vessel with 

hemispherical dome and ellipsoidal bottom, completely enclosed by a 

reinforced concrete shield building. A 4 ft wide annular space exists 

between the walls and domes of the steel containment vessel and the 

concrete shield building to permit inservice inspection and collection of 

containment outleakage. Dual containments utilize an outer concrete 

building for shielding and an inner steel containment for leak tightness. 

Containment piping penetration assemblies provide for the passage of 

process, service, sampling, and instrumentation pipelines into the 

containment vessel while maintaining containment OPERABILITY. The 

shield building provides biological shielding and allows controlled release 

of the annulus atmosphere under accident conditions, as well as 

environmental missile protection for the containment vessel and the 

Nuclear Steam Supply System. 

The inner steel containment and its penetrations establish the leakage 

limiting boundary of the containment. Maintaining the containment 

OPERABLE limits the leakage of fission product radioactivity from the 

containment to the environment. Loss of containment OPERABILITY 

could cause site boundary doses, in the event of a Design Basis Accident 

(DBA), to exceed values given in the licensing basis. SR 3.6.1.1 leakage 

rate requirements comply with 10 CFR 50, Appendix J, Option [A][B] 

(Ref. 1), as modified by approved exemptions. 

The isolation devices for the penetrations in the containment boundary 

are a part of the containment leak tight barrier. To maintain this leak tight 

barrier: 
Containment (Dual) 

B 3.6.1B 

CEOG STS B 3.6.1B-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

a. All penetrations required to be closed during accident conditions are 

either: 

1. Capable of being closed by an OPERABLE automatic 

containment isolation system or 

2. Closed by manual valves, blind flanges, or de-activated 

automatic valves secured in their closed positions, except as 

provided in LCO 3.6.3, "Containment Isolation Valves," 

b. Each air lock is OPERABLE except as provided in LCO 3.6.2, 

"Containment Air Locks," 

c. All equipment hatches are closed, and 

[d. The pressurized sealing mechanism associated with a penetration, 

 except as provided in LCO 3.6.[ ], is OPERABLE. ] 

APPLICABLE The safety design basis for the containment is that the containment must 

SAFETY withstand the pressures and temperatures of the limiting DBA without 

ANALYSES exceeding the design leakage rate. 

The DBAs that result in a release of radioactive material within 

containment are a LOCA, a main steam line break, and a control element 

assembly ejection accident (Ref. 2). In the analysis of each of these 

accidents, it is assumed that containment is OPERABLE such that 

release of fission products to the environment is controlled by the rate of 

containment leakage. The containment was designed with an allowable 

leakage rate of [0.50]% of containment air weight per day (Ref. 3). This 

leakage rate is defined in 10 CFR 50, Appendix J, Option [A][B] (Ref. 1), 

as La: the maximum allowable containment leakage rate at the calculated 

maximum peak containment pressure (Pa) of [42.3] psig, which results 

from the limiting design basis LOCA (Ref. 2). 

Satisfactory leakage rate test results are a requirement for the 

establishment of containment OPERABILITY. 

The containment satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 
Containment (Dual) 

B 3.6.1B 

CEOG STS B 3.6.1B-3 Rev. 3.0, 03/31/04 

BASES 

LCO Containment OPERABILITY is maintained by limiting leakage to ≤ 1.0 La, 

except prior to the first startup after performing a required Containment 

Leakage Rate Testing Program leakage test. At this time, the applicable 

leakage limits must be met. 

 Compliance with this LCO will ensure a containment configuration, 

including equipment hatches, that is structurally sound and that will limit 

leakage to those leakage rates assumed in the safety analysis. 

Individual leakage rates specified for the containment air lock (LCO 3.6.2) 

[, purge valves with resilient seals, and secondary bypass leakage 

(LCO 3.6.3)] are not specifically part of the acceptance criteria of 

10 CFR 50, Appendix J. Therefore, leakage rates exceeding these 

individual limits only result in the containment being inoperable when the 

leakage results in exceeding the overall acceptance criteria of 1.0 La. 

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive 

material into containment. In MODES 5 and 6, the probability and 

consequences of these events are reduced due to the pressure and 

temperature limitations of these MODES. Therefore, containment is not 

required to be OPERABLE in MODE 5 to prevent leakage of radioactive 

material from containment. The requirements for containment during 

MODE 6 refueling operations are addressed in LCO 3.9.3, "Containment 

Penetrations." 

ACTIONS A.1

In the event that containment is inoperable, it must be restored to 

OPERABLE status within 1 hour. The 1 hour Completion Time provides a 

period of time to correct the problem commensurate with the importance 

of maintaining containment OPERABLE during MODES 1, 2, 3, and 4. 

This time period also ensures that the probability of an accident (requiring 

containment OPERABILITY) occurring during periods when containment 

is inoperable is minimal. 

B.1 and B.2

If containment cannot be restored to OPERABLE status within the 

required Completion Time, the plant must be brought to a MODE in which 

the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 5 within 

36 hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 
Containment (Dual) 

B 3.6.1B 

CEOG STS B 3.6.1B-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.6.1.1

REQUIREMENTS 

Maintaining containment OPERABLE requires compliance with the visual 

examinations and leakage rate test requirements of the Containment 

Leakage Rate Testing Program. Failure to meet air lock and purge valve 

with resilient seal specific leakage limits specified in LCO 3.6.2 and 

LCO 3.6.3 does not invalidate the acceptability of these overall leakage 

determinations unless their contribution to overall Type A, B, and C 

leakage causes that to exceed limits. As left leakage prior to the first 

startup after performing a required Containment Leakage Rate Testing 

Program leakage test is required to be < 0.6 La for combined Type B and 

C leakage, and [< 0.75 La for Option A] [≤ 0.75 La for Option B] for overall 

Type A leakage. At all other times between required leakage rate tests, 

the acceptance criteria is based on an overall Type A leakage limit of 

≤ 1.0 La. At ≤ 1.0 La the offsite dose consequences are bounded by the 

assumptions of the safety analysis. SR Frequencies are as required by 

the Containment Leakage Rate Testing Program. These periodic testing 

requirements verify that the containment leakage rate does not exceed 

the leakage rate assumed in the safety analysis. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Regulatory Guide 1.163 and NEI 94-01 include acceptance criteria for asleft and as-found Type A leakage rates and combined Type B and C 

leakage rates, which may be reflected in the Bases. 

-------------------------------------------------------------------------------------------------- 

[ SR 3.6.1.2

For ungrouted, post tensioned tendons, this SR ensures that the 

structural integrity of the containment will be maintained in accordance 

with the provisions of the Containment Tendon Surveillance Program. 

Testing and Frequency are consistent with recommendations of 

Regulatory Guide 1.35 (Ref. 4). ] 

REFERENCES 1. 10 CFR 50, Appendix J, Option [A][B]. 

 2. FSAR, Section [ ]. 

 3. FSAR, Section [ ]. 

 4. Regulatory Guide 1.35, Revision [1]. 
Containment Air Locks (Atmospheric and Dual) 

B 3.6.2 

CEOG STS B 3.6.2-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.2 Containment Air Locks (Atmospheric and Dual) 

BASES 

BACKGROUND Containment air locks form part of the containment pressure boundary 

and provide a means for personnel access during all MODES of 

operation. 

Each air lock is nominally a right circular cylinder, 10 ft in diameter, with a 

door at each end. The doors are interlocked to prevent simultaneous 

opening. During periods when containment is not required to be 

OPERABLE, the door interlock mechanism may be disabled, allowing 

both doors of an air lock to remain open for extended periods when 

frequent containment entry is necessary. Each air lock door has been 

designed and tested to certify its ability to withstand a pressure in excess 

of the maximum expected pressure following a Design Basis Accident 

(DBA) in containment. As such, closure of a single door supports 

containment OPERABILITY. Each of the doors contains double gasketed 

seals and local leakage rate testing capability to ensure pressure 

integrity. To effect a leak tight seal, the air lock design uses pressure 

seated doors (i.e., an increase in containment internal pressure results in 

increased sealing force on each door). 

Each personnel air lock is provided with limit switches on both doors that 

provide control room indication of door position. Additionally, control 

room indication is provided to alert the operator whenever an air lock door 

interlock mechanism is defeated. 

The containment air locks form part of the containment pressure 

boundary. As such, air lock integrity and leak tightness is essential for 

maintaining the containment leakage rate within limit in the event of a 

DBA. Not maintaining air lock integrity or leak tightness may result in a 

leakage rate in excess of that assumed in the unit safety analysis. 

APPLICABLE [ For atmospheric containment, the DBAs that result in a release of 

SAFETY radioactive material within containment are a loss of coolant accident 

ANALYSES (LOCA), a main steam line break (MSLB) and a control element assembly 

(CEA) ejection accident (Ref. 2). In the analysis of each of these 

accidents, it is assumed that containment is OPERABLE such that 

release of fission products to the environment is controlled by the rate of 

containment leakage. The containment was designed with an allowable 

leakage rate of [0.10]% of containment air weight per day (Ref. 3). This 

leakage rate is defined in 10 CFR 50, Appendix J, Option A (Ref. 1), as 
Containment Air Locks (Atmospheric and Dual) 

B 3.6.2 

CEOG STS B 3.6.2-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

La: the maximum allowable containment leakage rate at the calculated 

[maximum] peak containment pressure (Pa) of [55.7] psig, which results 

from the limiting design basis LOCA. This allowable leakage rate forms 

the basis for the acceptance criteria imposed on the SRs associated with 

the air lock. 

For dual containment, the DBAs that result in a release of radioactive 

material within containment are a LOCA, an MSLB, and a CEA ejection 

accident (Ref. 2). In the analysis of each of these accidents, it is 

assumed that containment is OPERABLE such that release of fission 

products to the environment is controlled by the rate of containment 

leakage. The containment was designed with an allowable leakage rate 

of [0.50]% of containment air weight per day (Ref. 3). This leakage rate is 

defined in 10 CFR 50, Appendix J, Option A (Ref. 1), as La: the maximum 

allowable containment leakage rate at the calculated [maximum] peak 

containment pressure (Pa) of [42.3] psig, which results from the limiting 

design basis LOCA. This allowable leakage rate forms the basis for the 

acceptance criteria imposed on the SRs associated with the air lock. ]

The containment air locks satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Each containment air lock forms part of the containment pressure 

boundary. As part of the containment pressure boundary, the air lock 

safety function is related to control of the containment leakage rate 

resulting from a DBA. Thus, each air lock's structural integrity and leak 

tightness are essential to the successful mitigation of such an event. 

Each air lock is required to be OPERABLE. For the air lock to be 

considered OPERABLE, the air lock interlock mechanism must be 

OPERABLE, the air lock must be in compliance with the Type B air lock 

leakage test, and both air lock doors must be OPERABLE. The interlock 

allows only one air lock door of an air lock to be opened at one time. This 

provision ensures that a gross breach of containment does not exist when 

containment is required to be OPERABLE. Closure of a single door in 

each air lock is sufficient to provide a leak tight barrier following 

postulated events. Nevertheless, both doors are kept closed when the air 

lock is not being used for normal entry into or exit from containment. 
Containment Air Locks (Atmospheric and Dual) 

B 3.6.2 

CEOG STS B 3.6.2-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive 

material to containment. In MODES 5 and 6, the probability and 

consequences of these events are reduced due to the pressure and 

temperature limitations of these MODES. Therefore, the containment air 

locks are not required in MODE 5 to prevent leakage of radioactive 

material from containment. The requirements for the containment air 

locks during MODE 6 are addressed in LCO 3.9.3, "Containment 

Penetrations." 

ACTIONS The ACTIONS are modified by a Note that allows entry and exit to 

perform repairs on the affected air lock component. If the outer door is 

inoperable, then it may be easily accessed for most repairs. It is 

preferred that the air lock be accessed from inside primary containment 

by entering through the other OPERABLE air lock. However, if this is not 

practicable, or if repairs on either door must be performed from the barrel 

side of the door then it is permissible to enter the air lock through the 

OPERABLE door, which means there is a short time during which the 

containment boundary is not intact (during access through the 

OPERABLE door). The ability to open the OPERABLE door, even if it 

means the containment boundary is temporarily not intact, is acceptable 

because of the low probability of an event that could pressurize the 

containment during the short time in which the OPERABLE door is 

expected to be open. After each entry and exit, the OPERABLE door 

must be immediately closed. If ALARA conditions permit, entry and exit 

should be via an OPERABLE air lock. 

A second Note has been added to provide clarification that, for this LCO, 

separate Condition entry is allowed for each air lock. This is acceptable, 

since the Required Actions for each Condition provide appropriate 

compensatory actions for each inoperable air lock. Complying with the 

Required Actions may allow for continued operation, and a subsequent 

inoperable air lock is governed by subsequent Condition entry and 

application of associated Required Actions. A third Note has been 

included that requires entry into the applicable Conditions and Required 

Actions of LCO 3.6.1, "Containment," when leakage results in exceeding 

the overall containment leakage limit. 

A.1, A.2, and A.3

With one air lock door inoperable in one or more containment air locks, 

the OPERABLE door must be verified closed (Required Action A.1) in 

each affected containment air lock. This ensures that a leak tight 

containment barrier is maintained by the use of an OPERABLE air lock 

door. This action must be completed within 1 hour. This specified time 

period is consistent with the ACTIONS of LCO 3.6.1, which requires 

containment be restored to OPERABLE status within 1 hour. 
Containment Air Locks (Atmospheric and Dual) 

B 3.6.2 

CEOG STS B 3.6.2-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

In addition, the affected air lock penetration must be isolated by locking 

closed an OPERABLE air lock door within the 24 hour Completion Time. 

The 24 hour Completion Time is considered reasonable for locking the 

OPERABLE air lock door, considering the OPERABLE door of the 

affected air lock is being maintained closed. 

Required Action A.3 verifies that an air lock with an inoperable door has 

been isolated by the use of a locked and closed OPERABLE air lock 

door. This ensures that an acceptable containment leakage boundary is 

maintained. The Completion Time of once per 31 days is based on 

engineering judgment and is considered adequate in view of the low 

likelihood of a locked door being mispositioned and other administrative 

controls. Required Action A.3 is modified by a Note that applies to air 

lock doors located in high radiation areas and allows these doors to be 

verified locked closed by use of administrative means. Allowing 

verification by administrative means is considered acceptable, since 

access to these areas is typically restricted. Therefore, the probability of 

misalignment of the door, once it has been verified to be in the proper 

position, is small. 

The Required Actions have been modified by two Notes. Note 1 ensures 

that only the Required Actions and associated Completion Times of 

Condition C are required if both doors in the same air lock are inoperable. 

With both doors in the same air lock inoperable, an OPERABLE door is 

not available to be closed. Required Actions C.1 and C.2 are the 

appropriate remedial actions. The exception of Note 1 does not affect 

tracking the Completion Time from the initial entry into Condition A; only 

the requirement to comply with the Required Actions. Note 2 allows use 

of the air lock for entry and exit for 7 days under administrative controls if 

both air locks have an inoperable door. This 7 day restriction begins 

when the second air lock is discovered inoperable. Containment entry 

may be required to perform Technical Specifications (TS) Surveillances 

and Required Actions, as well as other activities on equipment inside 

containment that are required by TS or activities on equipment that 

support TS-required equipment. This Note is not intended to preclude 

performing other activities (i.e., non-TS-required activities) if the 

containment was entered, using the inoperable air lock, to perform an 

allowed activity listed above. This allowance is acceptable due to the low 

probability of an event that could pressurize the containment during the 

short time that the OPERABLE door is expected to be open. 
Containment Air Locks (Atmospheric and Dual) 

B 3.6.2 

CEOG STS B 3.6.2-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1, B.2, and B.3

With an air lock interlock mechanism inoperable in one or more air locks, 

the Required Actions and associated Completion Times are consistent 

with those specified in Condition A. 

The Required Actions have been modified by two Notes. Note 1 ensures 

that only the Required Actions and associated Completion Times of 

Condition C are required if both doors in the same air lock are inoperable. 

With both doors in the same air lock inoperable, an OPERABLE door is 

not available to be closed. Required Actions C.1 and C.2 are the 

appropriate remedial actions. Note 2 allows entry into and exit from 

containment under the control of a dedicated individual stationed at the 

air lock to ensure that only one door is opened at a time (i.e., the 

individual performs the function of the interlock). 

Required Action B.3 is modified by a Note that applies to air lock doors 

located in high radiation areas and allows these doors to be verified 

locked closed by use of administrative means. Allowing verification by 

administrative means is considered acceptable, since access to these 

areas is typically restricted. Therefore, the probability of misalignment of 

the door, once it has been verified to be in the proper position, is small. 

C.1, C.2, and C.3

With one or more air locks inoperable for reasons other than those 

described in Condition A or B, Required Action C.1 requires action to be 

initiated immediately to evaluate previous combined leakage rates using 

current air lock test results. An evaluation is acceptable since it is overly 

conservative to immediately declare the containment inoperable if both 

doors in an air lock have failed a seal test or if the overall air lock leakage 

is not within limits. In many instances (e.g., only one seal per door has 

failed), containment remains OPERABLE, yet only 1 hour (per LCO 3.6.1) 

would be provided to restore the air lock door to OPERABLE status prior 

to requiring a plant shutdown. In addition, even with both doors failing the 

seal test, the overall containment leakage rate can still be within limits. 

Required Action C.2 requires that one door in the affected containment air 

lock must be verified to be closed. This action must be completed within 

the 1 hour Completion Time. This specified time period is consistent with 

the ACTIONS of LCO 3.6.1, which requires that containment be restored 

to OPERABLE status within 1 hour. 
Containment Air Locks (Atmospheric and Dual) 

B 3.6.2 

CEOG STS B 3.6.2-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Additionally, the affected air lock(s) must be restored to OPERABLE 

status within the 24 hour Completion Time. The specified time period is 

considered reasonable for restoring an inoperable air lock to OPERABLE 

status, assuming that at least one door is maintained closed in each 

affected air lock. 

D.1 and D.2

If the inoperable containment air lock cannot be restored to OPERABLE 

status within the required Completion Time, the plant must be brought to 

a MODE in which the LCO does not apply. To achieve this status, the 

plant must be brought to at least MODE 3 within 6 hours and to MODE 5 

within 36 hours. The allowed Completion Times are reasonable, based 

on operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE SR 3.6.2.1

REQUIREMENTS 

Maintaining containment air locks OPERABLE requires compliance with 

the leakage rate test requirements of the Containment Leakage Rate 

Testing Program. This SR reflects the leakage rate testing requirements 

with regard to air lock leakage (Type B leakage tests). The acceptance 

criteria were established during initial air lock and containment 

OPERABILITY testing. The periodic testing requirements verify that the 

air lock leakage does not exceed the allowed fraction of the overall 

containment leakage rate. The Frequency is required by the Containment 

Leakage Rate Testing Program. 

The SR has been modified by two Notes. Note 1 states that an 

inoperable air lock door does not invalidate the previous successful 

performance of the overall air lock leakage test. This is considered 

reasonable since either air lock door is capable of providing a fission 

product barrier in the event of a DBA. Note 2 has been added to this SR 

requiring the results to be evaluated against the acceptance criteria which 

is applicable to SR 3.6.1.1. This ensures that air lock leakage is properly 

accounted for in determining the combined Type B and C containment 

leakage rate. 
Containment Air Locks (Atmospheric and Dual) 

B 3.6.2 

CEOG STS B 3.6.2-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.6.2.2

The air lock interlock is designed to prevent simultaneous opening of both 

doors in a single air lock. Since both the inner and outer doors of an air 

lock are designed to withstand the maximum expected post accident 

containment pressure, closure of either door will support containment 

OPERABILITY. Thus, the door interlock feature supports containment 

OPERABILITY while the air lock is being used for personnel transit into 

and out of containment. Periodic testing of this interlock demonstrates 

that the interlock will function as designed and that simultaneous opening 

of the inner and outer doors will not inadvertently occur. Due to the 

purely mechanical nature of this interlock, and given that the interlock 

mechanism is not normally challenged when the containment airlock 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 24 

month Frequency is based on engineering judgment and is considered 

adequate given that the interlock is not challenged during the use of the 

airlock. 

REFERENCES 1. 10 CFR 50, Appendix J, Option [A][B]. 

 2. FSAR, Section [ ]. 

 3. FSAR, Section [ ]. 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.3 Containment Isolation Valves (Atmospheric and Dual) 

BASES 

BACKGROUND The containment isolation valves form part of the containment pressure 

boundary and provide a means for fluid penetrations not serving accident 

consequence limiting systems to be provided with two isolation barriers 

that are closed on an automatic isolation signal. These isolation devices 

are either passive or active (automatic). Manual valves, de-activated 

automatic valves secured in their closed position (including check valves 

with flow through the valve secured), blind flanges, and closed systems 

are considered passive devices. Check valves, or other automatic valves 

designed to close without operator action following an accident, are 

considered active devices. Two barriers in series are provided for each 

penetration so that no single credible failure or malfunction of an active 

component can result in a loss of isolation or leakage that exceeds limits 

assumed in the safety analysis. One of these barriers may be a closed 

system. 

Containment isolation occurs upon receipt of a high containment pressure 

signal or a low Reactor Coolant System (RCS) pressure signal. The 

containment isolation signal closes automatic containment isolation 

valves in fluid penetrations not required for operation of Engineered 

Safety Feature systems in order to prevent leakage of radioactive 

material. Upon actuation of safety injection, automatic containment 

isolation valves also isolate systems not required for containment or RCS 

heat removal. Other penetrations are isolated by the use of valves in the 

closed position or blind flanges. As a result, the containment isolation 

valves (and blind flanges) help ensure that the containment atmosphere 

will be isolated in the event of a release of radioactive material to 

containment atmosphere from the RCS following a Design Basis Accident 

(DBA). 

The OPERABILITY requirements for containment isolation valves help 

ensure that containment is isolated within the time limits assumed in the 

safety analysis. Therefore, the OPERABILITY requirements provide 

assurance that the containment function assumed in the accident analysis 

will be maintained. 

The purge valves were designed for intermittent operation, providing a 

means of removing airborne radioactivity caused by minor RCS leakage 

prior to personnel entry into containment. There are two sets of purge 

valves: normal purge and exhaust valves and minipurge and exhaust 

valves. The normal and minipurge supply and exhaust lines are each 

supplied with inside and outside containment isolation valves but share 

common supply and exhaust penetration lines. 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The normal purge valves are designed for purging the containment 

atmosphere to the unit stack while introducing filtered makeup from the 

outside to provide adequate ventilation for personnel comfort when the 

unit is shut down during refueling operations and maintenance. Motor 

operated isolation valves are provided inside the containment, and air 

operated isolation valves are provided outside the containment. The 

valves are operated manually from the control room. The valves will 

close automatically upon receipt of a containment purge isolation signal. 

The air operated valves fail closed upon a loss of air. Because of their 

large size, the normal purge valves in some units are not qualified for 

automatic closure from their open position under DBA conditions. 

Therefore, the normal purge valves are normally maintained closed in 

MODES 1, 2, 3, and 4 to ensure the containment boundary is maintained. 

Open normal purge valves, or a failure of the minipurge valves to close, 

following an accident that releases contamination to the containment 

atmosphere would cause a significant increase in the containment 

leakage rate. 

APPLICABLE The containment isolation valve LCO was derived from the assumptions 

SAFETY related to minimizing the loss of reactor coolant inventory and 

ANALYSES establishing the containment boundary during major accidents. As part of 

the containment boundary, containment isolation valve OPERABILITY 

supports leak tightness of the containment. Therefore, the safety analysis 

of any event requiring isolation of containment is applicable to this LCO. 

The DBAs that result in a release of radioactive material within 

containment are a loss of coolant accident (LOCA), a main steam line 

break, and a control element assembly ejection accident. In the analysis 

for each of these accidents, it is assumed that containment isolation 

valves are either closed or function to close within the required isolation 

time following event initiation. This ensures that potential paths to the 

environment through containment isolation valves (including containment 

purge valves) are minimized. The safety analysis assumes that the 

normal purge valves are closed at event initiation. 

The DBA analysis assumes that, within 60 seconds after the accident, 

isolation of the containment is complete and leakage terminated except 

for the design leakage rate, La. The containment isolation total response 

time of 60 seconds includes signal delay, diesel generator startup (for 

loss of offsite power), and containment isolation valve stroke times. 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The single failure criterion required to be imposed in the conduct of unit 

safety analyses was considered in the original design of the containment 

purge valves. Two valves in series on each purge line provide assurance 

that both the supply and exhaust lines could be isolated even if a single 

failure occurred. The inboard and outboard isolation valves on each line 

are provided with diverse power sources, motor operated and 

pneumatically operated spring closed, respectively. This arrangement 

was designed to preclude common mode failures from disabling both 

valves on a purge line. 

The purge valves may be unable to close in the environment following a 

LOCA. Therefore, each of the purge valves is required to remain sealed 

closed during MODES 1, 2, 3, and 4. In this case, the single failure 

criterion remains applicable to the containment purge valves due to failure 

in the control circuit associated with each valve. Again, the purge system 

valve design precludes a single failure from compromising the 

containment boundary as long as the system is operated in accordance 

with the subject LCO. The minipurge valves are capable of closing under 

accident conditions. Therefore, they are allowed to be open for limited 

periods during power operation. 

The containment isolation valves satisfy Criterion 3 of 

10 CFR 50.36(c)(2)(ii). 

LCO Containment isolation valves form a part of the containment boundary. 

The containment isolation valve safety function is related to minimizing 

the loss of reactor coolant inventory and establishing the containment 

boundary during a DBA. 

The automatic power operated isolation valves are required to have 

isolation times within limits and to actuate on an automatic isolation 

signal. The purge valves must be maintained sealed closed [or have 

blocks installed to prevent full opening]. [Blocked purge valves also 

actuate on an automatic signal.] The valves covered by this LCO are 

listed with their associated stroke times in the FSAR (Ref. 1). 

The normally closed isolation valves are considered OPERABLE when 

manual valves are closed, automatic valves are de-activated and secured 

in their closed position, blind flanges are in place, and closed systems are 

intact. These passive isolation valves or devices are those listed in 

Reference 2. 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-4 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

Purge valves with resilient seals [and secondary containment bypass 

valves] must meet additional leakage rate requirements. The other 

containment isolation valve leakage rates are addressed by LCO 3.6.1, 

"Containment," as Type C testing. 

This LCO provides assurance that the containment isolation valves and 

purge valves will perform their designed safety functions to minimize the 

loss of reactor coolant inventory and establish the containment boundary 

during accidents. 

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive 

material to containment. In MODES 5 and 6, the probability and 

consequences of these events are reduced due to the pressure and 

temperature limitations of these MODES. Therefore, the containment 

isolation valves are not required to be OPERABLE in MODE 5. The 

requirements for containment isolation valves during MODE 6 are 

addressed in LCO 3.9.3, "Containment Penetrations." 

ACTIONS The ACTIONS are modified by a Note allowing penetration flow paths, 

except for [42] inch purge valve penetration flow paths, to be unisolated 

intermittently under administrative controls. These administrative controls 

consist of stationing a dedicated operator at the valve controls, who is in 

continuous communication with the control room. In this way, the 

penetration can be rapidly isolated when a need for containment isolation 

is indicated. Due to the size of the containment purge line penetration 

and the fact that those penetrations exhaust directly from the containment 

atmosphere to the environment, these valves may not be opened under 

administrative controls. 

A second Note has been added to provide clarification that, for this LCO, 

separate Condition entry is allowed for each penetration flow path. This 

is acceptable, since the Required Actions for each Condition provide 

appropriate compensatory actions for each inoperable containment 

isolation valve. Complying with the Required Actions may allow for 

continued operation, and subsequent inoperable containment isolation 

valves are governed by subsequent Condition entry and application of 

associated Required Actions. 

The ACTIONS are further modified by a third Note, which ensures that 

appropriate remedial actions are taken, if necessary, if the affected 

systems are rendered inoperable by an inoperable containment isolation 

valve. 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

A fourth Note has been added that requires entry into the applicable 

Conditions and Required Actions of LCO 3.6.1 when leakage results in 

exceeding the overall containment leakage limit. 

A.1 and A.2

In the event one containment isolation valve in one or more penetration 

flow paths is inoperable, [except for purge valve leakage and shield 

building bypass leakage not within limit], the affected penetration flow 

path must be isolated. The method of isolation must include the use of at 

least one isolation barrier that cannot be adversely affected by a single 

active failure. Isolation barriers that meet this criterion are a closed and 

de-activated automatic containment isolation valve, a closed manual 

valve, a blind flange, and a check valve with flow through the valve 

secured. For penetrations isolated in accordance with Required 

Action A.1, the device used to isolate the penetration should be the 

closest available one to containment. Required Action A.1 must be 

completed within the 4 hour Completion Time. The 4 hour Completion 

Time is reasonable, considering the time required to isolate the 

penetration and the relative importance of supporting containment 

OPERABILITY during MODES 1, 2, 3, and 4. 

For affected penetration flow paths that cannot be restored to 

OPERABLE status within the 4 hour Completion Time and that have been 

isolated in accordance with Required Action A.1, the affected penetration 

flow paths must be verified to be isolated on a periodic basis. This is 

necessary to ensure that containment penetrations required to be isolated 

following an accident and no longer capable of being automatically 

isolated will be in the isolation position should an event occur. This 

Required Action does not require any testing or device manipulation. 

Rather, it involves verification that those isolation devices outside 

containment and capable of being mispositioned are in the correct 

position. The Completion Time of "once per 31 days for isolation devices 

outside containment" is appropriate considering the fact that the devices 

are operated under administrative controls and the probability of their 

misalignment is low. For the isolation devices inside containment, the 

time period specified as "prior to entering MODE 4 from MODE 5 if not 

performed within the previous 92 days" is based on engineering judgment 

and is considered reasonable in view of the inaccessibility of the isolation 

devices and other administrative controls that will ensure that isolation 

device misalignment is an unlikely possibility. 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Condition A has been modified by a Note indicating that this Condition is 

only applicable to those penetration flow paths with two [or more] 

containment isolation valves. For penetration flow paths with only one 

containment isolation valve and a closed system, Condition C provides 

appropriate actions. 

Required Action A.2 is modified by two Notes. Note 1 applies to isolation 

devices located in high radiation areas and allows these devices to be 

verified closed by use of administrative means. Allowing verification by 

administrative means is considered acceptable, since access to these 

areas is typically restricted. Note 2 applies to isolation devices that are 

locked, sealed, or otherwise secured in position and allows these devices 

to be verified closed by use of administrative means. Allowing verification 

by administrative means is considered acceptable, since the function of 

locking, sealing, or securing components is to ensure that these devices 

are not inadvertently repositioned. Therefore, the probability of 

misalignment of these devices, once they have been verified to be in the 

proper position, is small. 

B.1

With two [or more] containment isolation valves in one or more 

penetration flow paths inoperable, [except for purge valve leakage and 

shield building bypass leakage not within limit], the affected penetration 

flow path must be isolated within 1 hour. The method of isolation must 

include the use of at least one isolation barrier that cannot be adversely 

affected by a single active failure. Isolation barriers that meet this 

criterion are a closed and de-activated automatic valve, a closed manual 

valve, and a blind flange. The 1 hour Completion Time is consistent with 

the ACTIONS of LCO 3.6.1. In the event the affected penetration is 

isolated in accordance with Required Action B.1, the affected penetration 

must be verified to be isolated on a periodic basis per Required 

Action A.2, which remains in effect. This periodic verification is necessary 

to assure leak tightness of containment and that penetrations requiring 

isolation following an accident are isolated. The Completion Time of once 

per 31 days for verifying each affected penetration flow path is isolated is 

appropriate considering the fact that the valves are operated under 

administrative controls and the probability of their misalignment is low. 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Condition B is modified by a Note indicating this Condition is only 

applicable to penetration flow paths with two [or more] containment 

isolation valves. Condition A of this LCO addresses the condition of one 

containment isolation valve inoperable in this type of penetration flow 

path. 

C.1 and C.2

With one or more penetration flow paths with one containment isolation 

valve inoperable, the inoperable valve must be restored to OPERABLE 

status or the affected penetration flow path must be isolated. The method 

of isolation must include the use of at least one isolation barrier that 

cannot be adversely affected by a single active failure. Isolation barriers 

that meet this criterion are a closed and de-activated automatic valve, a 

closed manual valve, and a blind flange. A check valve may not be used 

to isolate the affected penetration. Required Action C.1 must be 

completed within the [72] hour Completion Time. The specified time 

period is reasonable, considering the relative stability of the closed 

system (hence, reliability) to act as a penetration isolation boundary and 

the relative importance of supporting containment OPERABILITY during 

MODES 1, 2, 3, and 4. In the event the affected penetration is isolated in 

accordance with Required Action C.1, the affected penetration flow path 

must be verified to be isolated on a periodic basis. This is necessary to 

assure leak tightness of containment and that containment penetrations 

requiring isolation following an accident are isolated. The Completion 

Time of once per 31 days for verifying that each affected penetration flow 

path is isolated is appropriate considering the valves are operated under 

administrative controls and the probability of their misalignment is low. 

Condition C is modified by a Note indicating that this Condition is only 

applicable to those penetration flow paths with only one containment 

isolation valve and a closed system. The closed system must meet the 

requirements of Reference 3. This Note is necessary since this Condition 

is written to specifically address those penetration flow paths in a closed 

system. 

Required Action C.2 is modified by two Notes. Note 1 applies to valves 

and blind flanges located in high radiation areas and allows these devices 

to be verified closed by use of administrative means. Allowing verification 

by administrative means is considered acceptable, since access to these 

areas is typically restricted. Note 2 applies to isolation devices that are 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-8 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

locked, sealed, or otherwise secured in position and allows these devices 

to be verified closed by use of administrative means. Allowing verification 

by administrative means is considered acceptable, since the function of 

locking, sealing, or securing components is to ensure that these devices 

are not inadvertently repositioned. Therefore, the probability of 

misalignment of these valves, once they have been verified to be in the 

proper position, is small. 

[ D.1

With the secondary containment bypass leakage rate (SR 3.6.3.9) [or 

purge valve leakage rate (SR 3.6.3.6)] not within limit, the assumptions of 

the safety analysis are not met. Therefore, the leakage must be restored 

to within limit. Restoration can be accomplished by isolating the 

penetration(s) that caused the limit to be exceeded by use of one closed 

and de-activated automatic valve, closed manual valve, or blind flange. 

When a penetration is isolated, the leakage rate for the isolated 

penetration is assumed to be the actual pathway leakage through the 

isolation device. If two isolation devices are used to isolate the 

penetration, the leakage rate is assumed to be the lesser actual pathway 

leakage of the two devices. The 4 hour Completion Time for secondary 

containment bypass leakage is reasonable considering the time required 

to restore the leakage by isolating the penetration(s) and the relative 

importance of secondary containment bypass leakage to the overall 

containment function. [The 24 hour Completion Time for purge valve 

leakage is acceptable considering the purge valves remain closed so that 

a gross breach of containment does not exist.] 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

[The bracketed options provided in ACTION D reflect options in plant 

design and options in adopting the associated leakage rate Surveillances. 

The options (in both ACTION D and ACTION E for purge valve leakage, 

are based primarily on the design - if leakage rates can be measured 

separately for each purge valve, ACTION E is intended to apply. This 

would be required to be able to implement Required Action E.3. Should 

the design allow only for leak testing both purge valves simultaneously, 

then the Completion Time for ACTION D should include the "24 hours for 

purge valve leakage" and ACTION E should be eliminated.] ] 

-------------------------------------------------------------------------------------------------- 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-9 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

[ E.1, E.2, and E.3

In the event one or more containment purge valves in one or more 

penetration flow paths are not within the purge valve leakage limits, purge 

valve leakage must be restored to within limits, or the affected penetration 

must be isolated. The method of isolation must be by the use of at least 

one isolation barrier that cannot be adversely affected by a single active 

failure. Isolation barriers that meet this criterion are a [closed and deactivated automatic valve with resilient seals, a closed manual valve with 

resilient seals, or a blind flange]. A purge valve with resilient seals 

utilized to satisfy Required Action E.1 must have been demonstrated to 

meet the leakage requirements of SR 3.6.3.6. The specified Completion 

Time is reasonable, considering that one containment purge valve 

remains closed so that a gross breach of containment does not exist. 

In accordance with Required Action E.2, this penetration flow path must 

be verified to be isolated on a periodic basis. The periodic verification is 

necessary to ensure that containment penetrations required to be isolated 

following an accident, which are no longer capable of being automatically 

isolated, will be in the isolation position should an event occur. This 

Required Action does not require any testing or valve manipulation. 

Rather, it involves verification that those isolation devices outside 

containment capable of being mispositioned are in the correct position. 

For the isolation devices inside containment, the time period specified as 

"prior to entering MODE 4 from MODE 5 if not performed within the 

previous 92 days" is based on engineering judgment and is considered 

reasonable in view of the inaccessibility of the isolation devices and other 

administrative controls that will ensure that isolation device misalignment 

is an unlikely possibility. 

For the containment purge valve with resilient seal that is isolated in 

accordance with Required Action E.1, SR 3.6.3.6 must be performed at 

least once every [92] days. This assures that degradation of the resilient 

seal is detected and confirms that the leakage rate of the containment 

purge valve does not increase during the time the penetration is isolated. 

The normal Frequency for SR 3.6.3.6, 184 days, is based on an NRC 

initiative, Generic Issue B-20 (Ref. 4). Since more reliance is placed on a 

single valve while in this Condition, it is prudent to perform the SR more 

often. Therefore, a Frequency of once per [92] days was chosen and has 

been shown to be acceptable based on operating experience. 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-10 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Required Action E.2 is modified by two Notes. Note 1 applies to isolation 

devices located in high radiation areas and allows these devices to be 

verified closed by use of administrative means. Allowing verification by 

administrative means is considered acceptable, since access to these 

areas is typically restricted. Note 2 applies to isolation devices that are 

locked, sealed, or otherwise secured in position and allows these devices 

to be verified closed by use of administrative means. Allowing verification 

by administrative means is considered acceptable, since the function of 

locking, sealing, or securing components is to ensure that these devices 

are not inadvertently repositioned. ]

F.1 and F.2

If the Required Actions and associated Completion Times are not met, 

the plant must be brought to a MODE in which the LCO does not apply. 

To achieve this status, the plant must be brought to at least MODE 3 

within 6 hours and to MODE 5 within 36 hours. The allowed Completion 

Times are reasonable, based on operating experience, to reach the 

required plant conditions from full power conditions in an orderly manner 

and without challenging plant systems. 

SURVEILLANCE [ SR 3.6.3.1

REQUIREMENTS 

Each [42] inch containment purge valve is required to be verified sealed 

closed at 31 day intervals. This Surveillance is designed to ensure that a 

gross breach of containment is not caused by an inadvertent or spurious 

opening of a containment purge valve. Detailed analysis of the purge 

valves failed to conclusively demonstrate their ability to close during a 

LOCA in time to limit offsite doses. Therefore, these valves are required 

to be in the sealed closed position during MODES 1, 2, 3, and 4. A 

containment purge valve that is sealed closed must have motive power to 

the valve operator removed. This can be accomplished by de-energizing 

the source of electric power or by removing the air supply to the valve 

operator. In this application, the term "sealed" has no connotation of leak 

tightness. The Frequency is a result of an NRC initiative, Generic 

Issue B-24 (Ref. 5), related to containment purge valve use during unit 

operations. This SR is not required to be met while in Condition E of this 

LCO. This is reasonable since the penetration flow path would be 

isolated. ]
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-11 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.6.3.2

This SR ensures that the minipurge valves are closed as required or, if 

open, open for an allowable reason. If a purge valve is open in violation 

of this SR, the valve is considered inoperable. If the inoperable valve is 

not otherwise known to have excessive leakage when closed, it is not 

considered to have leakage outside of limits. The SR is not required to 

be met when the purge valves are open for pressure control, ALARA or 

air quality considerations for personnel entry, or for Surveillances that 

require the valves to be open. The minipurge valves are capable of 

closing in the environment following a LOCA. Therefore, these valves are 

allowed to be open for limited periods of time. The 31 day Frequency is 

consistent with other containment isolation valve requirements discussed 

in SR 3.6.3.3. 

SR 3.6.3.3

This SR requires verification that each containment isolation manual 

valve and blind flange located outside containment and not locked, 

sealed, or otherwise secured and required to be closed during accident 

conditions is closed. The SR helps to ensure that post accident leakage 

of radioactive fluids or gases outside the containment boundary is within 

design limits. This SR does not require any testing or valve manipulation. 

Rather, it involves verification that those containment isolation valves 

outside containment and capable of being mispositioned are in the correct 

position. 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. Containment isolation valves that are 

open under administrative controls are not required to meet the SR during 

the time the valves are open. This SR does not apply to valves that are 

locked, sealed, or otherwise secured in the closed position, since these 

were verified to be in the correct position upon locking, sealing, or 

securing. 

The Note applies to valves and blind flanges located in high radiation 

areas and allows these devices to be verified closed by use of 

administrative means. Allowing verification by administrative means is 

considered acceptable, since access to these areas is typically restricted 

during MODES 1, 2, 3, 4 and for ALARA reasons. Therefore, the 

probability of misalignment of these containment isolation valves, once 

they have been verified to be in the proper position, is small. 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-12 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.6.3.4

This SR requires verification that each containment isolation manual 

valve and blind flange located inside containment and not locked, sealed, 

or otherwise secured and required to be closed during accident conditions 

is closed. The SR helps to ensure that post accident leakage of 

radioactive fluids or gases outside the containment boundary is within 

design limits. For containment isolation valves inside containment, the 

Frequency of "prior to entering MODE 4 from MODE 5 if not performed 

within the previous 92 days" is appropriate, since these containment 

isolation valves are operated under administrative controls and the 

probability of their misalignment is low. Containment isolation valves that 

are open under administrative controls are not required to meet the SR 

during the time that they are open. This SR does not apply to valves that 

are locked, sealed, or otherwise secured in the closed position, since 

these were verified to be in the correct position upon locking, sealing, or 

securing. 

The Note allows valves and blind flanges located in high radiation areas 

to be verified closed by use of administrative means. Allowing verification 

by administrative means is considered acceptable, since access to these 

areas is typically restricted during MODES 1, 2, and 3 for ALARA 

reasons. Therefore, the probability of misalignment of these containment 

isolation valves, once they have been verified to be in their proper 

position, is small. 

SR 3.6.3.5

Verifying that the isolation time of each automatic power operated 

containment isolation valve is within limits is required to demonstrate 

OPERABILITY. The isolation time test ensures the valve will isolate in a 

time period less than or equal to that assumed in the safety analysis. 

[The isolation time and Frequency of this SR are in accordance with the 

Inservice Testing Program or 92 days.] 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-13 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.6.3.6

For containment purge valves with resilient seals, additional leakage rate 

testing beyond the test requirements of 10 CFR 50, Appendix J, 

Option [A][B], (Ref. 6), is required to ensure OPERABILITY. Operating 

experience has demonstrated that this type of seal has the potential to 

degrade in a shorter time period than do other seal types. Based on this 

observation and the importance of maintaining this penetration leak tight 

(due to the direct path between containment and the environment), a 

Frequency of 184 days was established as part of the NRC resolution of 

Generic Issue B-20, "Containment Leakage Due to Seal Deterioration" 

(Ref. 4). 

Additionally, this SR must be performed within 92 days after opening the 

valve. The 92 day Frequency was chosen recognizing that cycling the 

valve could introduce additional seal degradation (beyond that occurring 

to a valve that has not been opened). Thus, decreasing the interval (from 

184 days) is a prudent measure after a valve has been opened. 

SR 3.6.3.7

Automatic containment isolation valves close on a containment isolation 

signal to prevent leakage of radioactive material from containment 

following a DBA. This SR ensures each automatic containment isolation 

valve will actuate to its isolation position on a containment isolation 

actuation signal. This Surveillance is not required for valves that are 

locked, sealed, or otherwise secured in the required position under 

administrative controls. The [18] month Frequency was developed 

considering it is prudent that this SR be performed only during a unit 

outage, since isolation of penetrations would eliminate cooling water flow 

and disrupt normal operation of many critical components. Operating 

experience has shown that these components usually pass this SR when 

performed on the [18] month Frequency. Therefore, the Frequency was 

concluded to be acceptable from a reliability standpoint. 

[ SR 3.6.3.8

-----------------------------------REVIEWER’S NOTE----------------------------------- 

This SR is only required for those units with resilient seal purge valves 

allowed to be open during [MODE 1, 2, 3, or 4] and having blocking 

devices on the valves that are not permanently installed. 

-------------------------------------------------------------------------------------------------- 
Containment Isolation Valves (Atmospheric and Dual) 

B 3.6.3 

CEOG STS B 3.6.3-14 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Verifying that each [42] inch containment purge valve is blocked to restrict 

opening to ≤ [50]% is required to ensure that the valves can close under 

DBA conditions within the times assumed in the analyses of References 1 

and 2. If a LOCA occurs, the purge valves must close to maintain 

containment leakage within the values assumed in the accident analysis. 

At other times when purge valves are required to be capable of closing 

(e.g., during movement of [recently] irradiated fuel assemblies), 

pressurization concerns are not present, thus the purge valves can be 

fully open. The [18] month Frequency is appropriate because the 

blocking devices are typically removed only during a refueling outage. ]

[ SR 3.6.3.9

This SR ensures that the combined leakage rate of all secondary 

containment bypass leakage paths is less than or equal to the specified 

leakage rate. This provides assurance that the assumptions in the safety 

analysis are met. The leakage rate of each bypass leakage path is 

assumed to be the maximum pathway leakage (leakage through the 

worse of the two isolation valves) unless the penetration is isolated by 

use of one closed and de-activated automatic valve, closed manual valve, 

or blind flange. In this case, the leakage rate of the isolated bypass 

leakage path is assumed to be the actual pathway leakage through the 

isolation device. If both isolation valves in the penetration are closed, the 

actual leakage rate is the lesser leakage rate of the two valves. The 

Frequency is required by the Containment Leakage Rate Testing 

Program. This SR simply imposes additional acceptance criteria. 

[Bypass leakage is considered part of La. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Unless specifically exempted.] ]

-------------------------------------------------------------------------------------------------- 

REFERENCES 1. FSAR, Section [ ]. 

 2. FSAR, Section [ ]. 

 3. Standard Review Plan 6.2.4. 

 4. Generic Issue B-20. 

 5. Generic Issue B-24. 

 6. 10 CFR 50, Appendix J, Option [A][B]. 
Containment Pressure (Atmospheric) 

B 3.6.4A 

CEOG STS B 3.6.4A-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.4A Containment Pressure (Atmospheric) 

BASES 

BACKGROUND The containment pressure is limited during normal operation to preserve 

the initial conditions assumed in the accident analyses for a loss of 

coolant accident (LOCA) or main steam line break (MSLB). These limits 

also prevent the containment pressure from exceeding the containment 

design negative pressure differential with respect to the outside 

atmosphere in the event of inadvertent actuation of the Containment 

Spray System. 

Containment pressure is a process variable that is monitored and 

controlled. The containment pressure limits are derived from the input 

conditions used in the containment functional analyses and the 

containment structure external pressure analysis. Should operation occur 

outside these limits coincident with a Design Basis Accident (DBA), post 

accident containment pressures could exceed calculated values. 

APPLICABLE Containment internal pressure is an initial condition used in the DBA 

SAFETY analyses to establish the maximum peak containment internal pressure. 

ANALYSES The limiting DBAs considered for determining the maximum containment 

internal pressure (Pa) are the LOCA and MSLB. An MSLB at 102% RTP 

results in the highest calculated internal containment pressure of 

55.7 psig, which is below the internal design pressure of 60 psig. The 

postulated DBAs are analyzed assuming degraded containment 

Engineered Safety Feature (ESF) systems (i.e., assuming the loss of one 

ESF bus, which is the worst case single active failure, resulting in one 

train of the Containment Spray System and one train of the Containment 

Cooling System being rendered inoperable). It is this maximum 

containment pressure that is used to ensure that the licensing basis dose 

limitations are met. 

The initial pressure condition used in the containment analysis was 

[14.7] psia ([0.0] psig). This resulted in a maximum peak pressure from 

an MSLB of [55.7] psig. The LCO limit of [1.5] psig ensures that, in the 

event of an accident, the maximum accident design pressure for 

containment, [60] psig, is not exceeded. If an MSLB occurred while the 

containment internal pressure was at the LCO value of [1.5] psig, a total 

pressure of [57.3] psig would result. This value is still below the design 

value of [60] psig. The containment was also designed for an internal 

pressure equal to [5.0] psig below external pressure in order to withstand 

the resultant pressure drop from an accidental actuation of the 
Containment Pressure (Atmospheric) 

B 3.6.4A 

CEOG STS B 3.6.4A-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Containment Spray System. The LCO limit of [-0.3] psig ensures that 

operation within the design limit of [-0.5] psig is maintained. The 

maximum calculated external pressure that would occur as a result of an 

inadvertent actuation of the Containment Spray System is [2.8] psig. 

Containment pressure satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO Maintaining containment pressure less than or equal to the LCO upper 

pressure limit ensures that, in the event of a DBA, the resultant peak 

containment accident pressure will remain below the containment design 

pressure. Maintaining containment pressure greater than or equal to the 

LCO lower pressure limit ensures that the containment will not exceed the 

design negative pressure differential following the inadvertent actuation of 

the Containment Spray System. 

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive 

material to containment. Since maintaining containment pressure within 

limits is essential to ensure initial conditions assumed in the accident 

analysis are maintained, the LCO is applicable in MODES 1, 2, 3, and 4. 

In MODES 5 and 6, the probability and consequences of these events are 

reduced due to the pressure and temperature limitations of these 

MODES. Therefore, maintaining containment pressure within the limits of 

the LCO is not required in MODE 5 or 6. 

ACTIONS A.1

When containment pressure is not within the limits of the LCO, 

containment pressure must be restored to within these limits within 

1 hour. The Required Action is necessary to return operation to within the 

bounds of the containment analysis. The 1 hour Completion Time is 

consistent with the ACTIONS of LCO 3.6.1, "Containment," which 

requires that containment be restored to OPERABLE status within 1 hour. 

B.1 and B.2

If containment pressure cannot be restored to within limits within the 

required Completion Time, the plant must be brought to a MODE in which 

the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 5 within 

36 hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 
Containment Pressure (Atmospheric) 

B 3.6.4A 

CEOG STS B 3.6.4A-3 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.6.4A.1

REQUIREMENTS 

Verifying that containment pressure is within limits ensures that operation 

remains within the limits assumed in the accident analysis. The 12 hour 

Frequency of this SR was developed after taking into consideration 

operating experience related to trending of containment pressure 

variations during the applicable MODES. Furthermore, the 12 hour 

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. 

REFERENCES None. 
Containment Pressure (Dual) 

B 3.6.4B 

CEOG STS B 3.6.4B-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.4B Containment Pressure (Dual) 

BASES 

BACKGROUND The containment pressure is limited, during normal operation, to preserve 

the initial conditions assumed in the accident analyses for a loss of 

coolant accident (LOCA) or main steam line break (MSLB). These limits 

also prevent the containment pressure from exceeding the containment 

design negative pressure differential, with respect to the outside 

atmosphere, in the event of inadvertent actuation of the Containment 

Spray System. 

Containment pressure is a process variable that is monitored and 

controlled. The containment pressure limits are derived from the input 

conditions used in the containment functional analyses and the 

containment structure external pressure analysis. Should operation occur 

outside these limits coincident with a Design Basis Accident (DBA), post 

accident containment pressures could exceed calculated values. 

APPLICABLE Containment internal pressure is an initial condition used in the DBA 

SAFETY analyses to establish the maximum peak containment internal pressure. 

ANALYSES The limiting DBAs considered for determining the maximum containment 

internal pressure (Pa) are the LOCA and MSLB. An MSLB at 75% RTP 

results in the highest calculated internal containment pressure of 

42.3 psig, which is below the internal design pressure of 44 psig. The 

postulated DBAs are analyzed assuming degraded containment 

Engineered Safety Feature (ESF) systems (i.e., assuming the loss of one 

ESF bus, which is the worst case single active failure, resulting in one 

train of the Containment Spray System and one train of the Containment 

Cooling System being rendered inoperable). It is this maximum 

containment pressure that is used to ensure that the licensing basis dose 

limitations are met. 

The initial pressure condition used in the containment analysis was 

[14.7] psig. The maximum containment pressure resulting from the 

limiting DBA, [42.3] psig, does not exceed the containment design 

pressure, [44] psig. The containment was also designed for an internal 

pressure equal to [0.65] psid below external pressure to withstand the 

resultant pressure drop from an accidental actuation of the Containment 

Spray System. The LCO limit of [27] inches of water ensures that 

operation within the design limit of [-0.65] psid is maintained. The 

maximum calculated differential pressure that would occur as a result of 

an inadvertent actuation of the Containment Spray System is [0.49] psid. 

Containment pressure satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 
Containment Pressure (Dual) 

B 3.6.4B 

CEOG STS B 3.6.4B-2 Rev. 3.0, 03/31/04 

BASES 

LCO Maintaining containment pressure less than or equal to the LCO upper 

pressure limit ensures that, in the event of a DBA, the resultant peak 

containment accident pressure will remain below the containment design 

pressure. Maintaining containment pressure greater than or equal to the 

LCO lower pressure limit ensures the containment will not exceed the 

design negative differential pressure following the inadvertent actuation of 

the Containment Spray System. 

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive 

material to containment. Since maintaining containment pressure within 

limits is essential to ensure initial conditions assumed in the accident 

analysis are maintained, the LCO is applicable in MODES 1, 2, 3, and 4. 

In MODES 5 and 6, the probability and consequences of these events are 

reduced due to the pressure and temperature limitations of these 

MODES. 

ACTIONS A.1

When containment pressure is not within the limits of the LCO, 

containment pressure must be restored to within these limits within 

1 hour. The Required Action is necessary to return operation to within the 

bounds of the containment analysis. The 1 hour Completion Time is 

consistent with the ACTIONS of LCO 3.6.1, "Containment," which 

requires that containment be restored to OPERABLE status within 1 hour. 

B.1 and B.2

If containment pressure cannot be restored to within limits within the 

required Completion Time, the plant must be brought to a MODE in which 

the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 5 within 

36 hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE SR 3.6.4B.1

REQUIREMENTS 

Verifying that containment pressure is within limits ensures that facility 

operation remains within the limits assumed in the containment analysis. 

The 12 hour Frequency of this SR was developed after taking into 

consideration operating experience related to trending of containment 

pressure variations during the applicable MODES. Furthermore, the 

12 hour 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. 
Containment Pressure (Dual) 

B 3.6.4B 

CEOG STS B 3.6.4B-3 Rev. 3.0, 03/31/04 

BASES 

REFERENCES None. 
Containment Air Temperature (Atmospheric and Dual) 

B 3.6.5 

CEOG STS B 3.6.5-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.5 Containment Air Temperature (Atmospheric and Dual) 

BASES 

BACKGROUND The containment structure serves to contain radioactive material that may 

be released from the reactor core following a Design Basis Accident 

(DBA). The containment average air temperature is limited during normal 

operation to preserve the initial conditions assumed in the accident 

analyses for a loss of coolant accident (LOCA) or main steam line break 

(MSLB). 

The containment average air temperature limit is derived from the input 

conditions used in the containment functional analyses and the 

containment structure external pressure analyses. This LCO ensures that 

initial conditions assumed in the analysis of containment response to a 

DBA are not violated during unit operations. The total amount of energy 

to be removed from containment by the Containment Spray and Cooling 

systems during post accident conditions is dependent on the energy 

released to the containment due to the event, as well as the initial 

containment temperature and pressure. The higher the initial 

temperature, the more energy that must be removed, resulting in a higher 

peak containment pressure and temperature. Exceeding containment 

design pressure may result in leakage greater than that assumed in the 

accident analysis (Ref. 1). Operation with containment temperature in 

excess of the LCO limit violates an initial condition assumed in the 

accident analysis. 

APPLICABLE Containment average air temperature is an initial condition used in the 

SAFETY DBA analyses that establishes the containment environmental 

ANALYSES qualification operating envelope for both pressure and temperature. The 

limit for containment average air temperature ensures that operation is 

maintained within the assumptions used in the DBA analysis for 

containment. The accident analyses and evaluations considered both 

LOCAs and MSLBs for determining the maximum peak containment 

pressures and temperatures. The worst case MSLB generates larger 

mass and energy releases than the worst case LOCA. Thus, the MSLB 

event bounds the LOCA event from the containment peak pressure and 

temperature standpoint. The initial pre-accident temperature inside 

containment was assumed to be [120]°F (Ref. 2). 

[ For atmospheric containment, the initial containment average air 

temperature condition of [120]°F resulted in a maximum vapor 

temperature in containment of [413]°F. The temperature of the 
Containment Air Temperature (Atmospheric and Dual) 

B 3.6.5 

CEOG STS B 3.6.5-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

containment steel liner and concrete structure reach approximately 230°F 

and 220°F, respectively. The containment average air temperature limit 

of [120]°F ensures that, in the event of an accident, the maximum design 

temperature for containment, [300]°F, is not exceeded. The consequence 

of exceeding this design temperature may be the potential for degradation 

of the containment structure under accident loads. 

For dual containment, the initial containment condition of [120]°F resulted 

in a maximum vapor temperature in containment of [413.5]°F. The 

temperature of the containment steel pressure vessel also reaches 

approximately [413.5]°F. The containment average temperature limit of 

[120]°F ensures that, in the event of an accident, the maximum design 

temperature for containment of [269.3]°F during LOCA conditions and 

[413.5]°F during MSLB conditions is not exceeded. The consequences of 

exceeding this design temperature may be the potential for degradation of 

the containment structure under accident loads. ]

Containment average air temperature satisfies Criterion 2 of 

10 CFR 50.36(c)(2)(ii). 

LCO During a DBA, with an initial containment average air temperature less 

than or equal to the LCO temperature limit, the resultant accident 

temperature profile assures that the containment structural temperature is 

maintained below its design temperature and that required safety related 

equipment will continue to perform its function. 

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive 

material to containment. In MODES 5 and 6, the probability and 

consequences of these events are reduced due to the pressure and 

temperature limitations of these MODES. Therefore, maintaining 

containment average air temperature within the limit is not required in 

MODE 5 or 6. 

ACTIONS A.1

When containment average air temperature is not within the limit of the 

LCO, it must be restored to within limit within 8 hours. This Required 

Action is necessary to return operation to within the bounds of the 

containment analysis. The 8 hour Completion Time is acceptable 

considering the sensitivity of the analysis to variations in this parameter 

and provides sufficient time to correct minor problems. 
Containment Air Temperature (Atmospheric and Dual) 

B 3.6.5 

CEOG STS B 3.6.5-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1 and B.2

If the containment average air temperature cannot be restored to within 

its limit within the required Completion Time, the plant must be brought to 

a MODE in which the LCO does not apply. To achieve this status, the 

plant must be brought to at least MODE 3 within 6 hours and to MODE 5 

within 36 hours. The allowed Completion Times are reasonable, based 

on operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE SR 3.6.5.1

REQUIREMENTS 

Verifying that containment average air temperature is within the LCO limit 

ensures that containment operation remains within the limit assumed for 

the containment analyses. In order to determine the containment 

average air temperature, an arithmetic average is calculated using 

measurements taken at locations within the containment selected to 

provide a representative sample of the overall containment atmosphere. 

The 24 hour Frequency of this SR is considered acceptable based on the 

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 hour 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. 

REFERENCES 1. FSAR, Section [ ]. 

 2. FSAR, Section [ ]. 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6A 

CEOG STS B 3.6.6A-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.6A Containment Spray and Cooling Systems (Atmospheric and Dual) (Credit taken for 

 iodine removal by the Containment Spray System) 

BASES 

BACKGROUND The Containment Spray and Containment Cooling systems provide 

containment atmosphere cooling to limit post accident pressure and 

temperature in containment to less than the design values. Reduction of 

containment pressure and the iodine removal capability of the spray 

reduce the release of fission product radioactivity from containment to the 

environment, in the event of a Design Basis Accident (DBA), to within 

limits. The Containment Spray and Containment Cooling systems are 

designed to the requirements of 10 CFR 50, Appendix A, GDC 38, 

"Containment Heat Removal," GDC 39, "Inspection of Containment Heat 

Removal Systems," GDC 40, "Testing of Containment Heat Removal 

Systems," GDC 41, "Containment Atmosphere Cleanup," GDC 42, 

"Inspection of Containment Atmosphere Cleanup Systems," and GDC 43, 

"Testing of Containment Atmosphere Cleanup Systems" (Ref. 1), or other 

documents that were appropriate at the time of licensing (identified on a 

unit specific basis). 

The Containment Cooling System and Containment Spray System are 

Engineered Safety Feature (ESF) systems. They are designed to ensure 

that the heat removal capability required during the post accident period 

can be attained. The Containment Spray System and the Containment 

Cooling System provide redundant methods to limit and maintain post 

accident conditions to less than the containment design values. 

Containment Spray System

The Containment Spray System consists of two separate trains of equal 

capacity, each capable of meeting the design bases. Each train includes 

a containment spray pump, spray headers, nozzles, valves, and piping. 

Each train is powered from a separate ESF bus. The refueling water tank 

(RWT) supplies borated water to the containment spray during the 

injection phase of operation. In the recirculation mode of operation, 

containment spray pump suction is transferred from the RWT to the 

containment sump(s). 

The Containment Spray System provides a spray of cold borated water 

mixed with sodium hydroxide from the spray additive tank into the upper 

regions of containment to reduce containment pressure and temperature 

and to reduce the concentration of fission products in the containment 

atmosphere during a DBA. The RWT solution temperature is an 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6A 

CEOG STS B 3.6.6A-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

important factor in determining the heat removal capability of the 

Containment Spray System during the injection phase. In the 

recirculation mode of operation, heat is removed from the containment 

sump water by the shutdown cooling heat exchangers. Each train of the 

Containment Spray System provides adequate spray coverage to meet 

50% of the system design requirements for containment heat removal 

and 100% of the iodine removal design bases. 

The Spray Additive System injects a hydrazine (N2H4) solution into the 

spray. The resulting alkaline pH of the spray enhances its ability to 

scavenge fission products from the containment atmosphere. The N2H4

added to the spray also ensures an alkaline pH for the solution 

recirculated in the containment sump. The alkaline pH of the containment 

sump water minimizes the evolution of iodine and minimizes the 

occurrence of chloride and caustic stress corrosion on mechanical 

systems and components exposed to the fluid. 

The Containment Spray System is actuated either automatically by a 

containment High-High pressure signal coincident with a safety injection 

actuation signal (SIAS) or manually. An automatic actuation opens the 

containment spray pump discharge valves, starts the two Containment 

Spray System pumps, and begins the injection phase. The containment 

spray header isolation valves open upon a containment spray actuation 

signal. A manual actuation of the Containment Spray System is available 

on the main control board to begin the same sequence. The injection 

phase continues until an RWT level Low signal is received. The Low 

level for the RWT generates a recirculation actuation signal that aligns 

valves from the containment spray pump suction to the containment 

sump. The Containment Spray System in recirculation mode maintains 

an equilibrium temperature between the containment atmosphere and the 

recirculated sump water. Operation of the Containment Spray System in 

the recirculation mode is controlled by the operator in accordance with the 

emergency operating procedures. 

Containment Cooling System

Two trains of containment cooling, each of sufficient capacity to supply 

50% of the design cooling requirement, are provided. Two trains with two 

fan units each are supplied with cooling water from a separate train of 

service water cooling. All four fans are required to furnish the design 

cooling capacity. Air is drawn into the coolers through the fans and 

discharged to the steam generator compartments and pressurizer 

compartment. 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6A 

CEOG STS B 3.6.6A-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

In post accident operation following a containment cooling actuation 

signal (CCAS), all four Containment Cooling System fans are designed to 

start automatically in slow speed. Cooling is shifted from the chilled water 

cooled coils to the service water cooled coils. The temperature of the 

service water is an important factor in the heat removal capability of the 

fan units. 

APPLICABLE The Containment Spray System and Containment Cooling System limit 

SAFETY the temperature and pressure that could be experienced following a 

ANALYSES DBA. The limiting DBAs considered relative to containment temperature 

and pressure are the loss of coolant accident (LOCA) and the main steam 

line break (MSLB). The DBA LOCA and MSLB are analyzed using 

computer codes designed to predict the resultant containment pressure 

and temperature transients. No DBAs are assumed to occur 

simultaneously or consecutively. The postulated DBAs are analyzed with 

regard to containment ESF systems, assuming the loss of one ESF bus, 

which is the worst case single active failure, resulting in one train of the 

Containment Spray System and one train of the Containment Cooling 

System being rendered inoperable. 

The analysis and evaluation show that under the worst case scenario, the 

highest peak containment pressure is [55.7] psig (experienced during an 

MSLB). The analysis shows that the peak containment vapor 

temperature is [413]°F (experienced during an MSLB). Both results are 

within the design. (See the Bases for Specifications 3.6.4A and 3.6.4B, 

"Containment Pressure," and 3.6.5, "Containment Air Temperature," for a 

detailed discussion.) The analyses and evaluations assume a power 

level of [102]% RTP, one containment spray train and one containment 

cooling train operating, and initial (pre-accident) conditions of [120]°F and 

[14.7] psia. The analyses also assume a response time delayed initiation 

in order to provide a conservative calculation of peak containment 

pressure and temperature responses. 

The effect of an inadvertent containment spray actuation has been 

analyzed. An inadvertent spray actuation reduces the containment 

pressure to [-2.8] psig due to the sudden cooling effect in the interior of 

the air tight containment. Additional discussion is provided in the Bases 

for Specifications 3.6.4A, 3.6.4B, and 3.6.12, "Vacuum Relief Valves." 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6A 

CEOG STS B 3.6.6A-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The modeled Containment Spray System actuation from the containment 

analysis is based upon a response time associated with exceeding the 

containment High-High pressure setpoint coincident with an SIAS to 

achieve full flow through the containment spray nozzles. The 

Containment Spray System total response time of [60] seconds includes 

diesel generator startup (for loss of offsite power), block loading of 

equipment, containment spray pump startup, and spray line filling 

(Ref. 2). 

The performance of the containment cooling train for post accident 

conditions is given in Reference 3. The result of the analysis is that each 

train can provide 50% of the required peak cooling capacity during the 

post accident condition. The train post accident cooling capacity under 

varying containment ambient conditions, required to perform the accident 

analyses, is also shown in Reference 4. 

The modeled Containment Cooling System actuation from the 

containment analysis is based upon the unit specific response time 

associated with exceeding the CCAS to achieve full Containment Cooling 

System air and safety grade cooling water flow. 

The Containment Spray System and the Containment Cooling System 

satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO During a DBA, a minimum of two containment cooling trains or two 

containment spray trains, or one of each, is required to maintain the 

containment peak pressure and temperature below the design limits 

(Ref. 5). Additionally, one containment spray train is also required to 

remove iodine from the containment atmosphere and maintain 

concentrations below those assumed in the safety analysis. To ensure 

that these requirements are met, two containment spray trains and two 

containment cooling units must be OPERABLE. Therefore, in the event 

of an accident, the minimum requirements are met, assuming that the 

worst case single active failure occurs. 

Each Containment Spray System includes a spray pump, spray headers, 

nozzles, valves, piping, instruments, and controls to ensure an 

OPERABLE flow path capable of taking suction from the RWT upon an 

ESF actuation signal and automatically transferring suction to the 

containment sump. 

Each Containment Cooling System includes demisters, cooling coils, 

dampers, fans, instruments, and controls to ensure an OPERABLE flow 

path. 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6A 

CEOG STS B 3.6.6A-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive 

material to containment and an increase in containment pressure and 

temperature, requiring the operation of the containment spray trains and 

containment cooling trains. 

In MODES 5 and 6, the probability and consequences of these events are 

reduced due to the pressure and temperature limitations of these 

MODES. Thus, the Containment Spray and Containment Cooling 

systems are not required to be OPERABLE in MODES 5 and 6. 

ACTIONS A.1

 -----------------------------------REVIEWER’S NOTE----------------------------------- 

Utilization of the 7 day Completion Time for Required Action A.1 is 

dependent on the licensee adopting CE NPSD-1045-A (Ref. 6) and 

meeting the requirements of the Topical Report and the associated Safety 

Evaluation. Otherwise, a 72 hour Completion Time applies. 

 -------------------------------------------------------------------------------------------------- 

With one containment spray train inoperable, the inoperable containment 

spray train must be restored to OPERABLE status within [7] days. In this 

Condition, the remaining OPERABLE spray and cooling trains are 

adequate to perform the iodine removal and containment cooling 

functions. The [7] day Completion Time takes into account the redundant 

heat removal capability afforded by the Containment Spray System, 

reasonable time for repairs, and the findings of Ref. 6. 

The 14 day portion of the Completion Time for Required Action A.1 is 

based upon engineering judgment. It takes into account the low 

probability of coincident entry into two Conditions in this Specification 

coupled with the low probability of an accident occurring during this time. 

Refer to Section 1.3, "Completion Times," for a more detailed discussion 

of the purpose of the "from discovery of failure to meet the LCO" portion 

of the Completion Time. 

B.1 and B.2

If the inoperable containment spray train cannot be restored to 

OPERABLE status within the required Completion Time, the plant must 

be brought to a MODE in which the LCO does not apply. To achieve this 

status, the plant must be brought to at least MODE 3 within 6 hours and 

to MODE 5 within 84 hours. The allowed Completion Time of 6 hours is 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6A 

CEOG STS B 3.6.6A-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

reasonable, based on operating experience, to reach MODE 3 from full 

power conditions in an orderly manner and without challenging plant 

systems. The extended interval to reach MODE 5 allows additional time 

for the restoration of the containment spray train and is reasonable when 

considering that the driving force for a release of radioactive material from 

the Reactor Coolant System is reduced in MODE 3. 

C.1

With one required containment cooling train inoperable, the inoperable 

containment cooling train must be restored to OPERABLE status within 

7 days. The remaining OPERABLE containment spray and cooling 

components provide iodine removal capabilities and are capable of 

providing at least 100% of the heat removal needs after an accident. The 

7 day Completion Time was developed taking into account the redundant 

heat removal capabilities afforded by combinations of the Containment 

Spray System and Containment Cooling System and the low probability 

of a DBA occurring during this period. 

The 14 day portion of the Completion Time for Required Action C.1 is 

based upon engineering judgment. It takes into account the low 

probability of coincident entry into two Conditions in this Specification 

coupled with the low probability of an accident occurring during this time. 

Refer to Section 1.3 for a more detailed discussion of the purpose of the 

"from discovery of failure to meet the LCO" portion of the Completion 

Time. 

D.1 and D.2

With one containment spray and one containment cooling train 

inoperable, one of the required containment cooling trains must be 

restored to OPERABLE status within 72 hours. The components in this 

degraded condition provide iodine removal capabilities and are capable of 

providing at least 100% of the heat removal needs after an accident. The 

72 hour Completion Time was developed taking into account the 

redundant heat removal capabilities afforded by combinations of the 

Containment Spray System and Containment Cooling System, the iodine 

removal function of the Containment Spray System, and the low 

probability of a DBA occurring during this period. 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6A 

CEOG STS B 3.6.6A-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

E.1

With two required containment cooling trains inoperable, one of the 

required containment cooling trains must be restored to OPERABLE 

status within 72 hours. The components in this degraded condition 

provide iodine removal capabilities and are capable of providing at least 

100% of the heat removal needs after an accident. The 72 hour 

Completion Time was developed taking into account the redundant heat 

removal capabilities afforded by combinations of the Containment Spray 

System and Containment Cooling System, the iodine removal function of 

the Containment Spray System, and the low probability of a DBA 

occurring during this period. 

F.1 and F.2

If the Required Actions and associated Completion Times of Condition C, 

D, or E of this LCO are not met, the plant must be brought to a MODE in 

which the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 5 within 

36 hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

G.1

With two containment spray trains or any combination of three or more 

Containment Spray System and Containment Cooling System trains 

inoperable, the unit is in a condition outside the accident analysis. 

Therefore, LCO 3.0.3 must be entered immediately. 

SURVEILLANCE SR 3.6.6A.1

REQUIREMENTS 

Verifying the correct alignment for manual, power operated, and 

automatic valves in the containment spray flow path provides assurance 

that the proper flow paths will exist for Containment Spray System 

operation. This SR does not apply to valves that are locked, sealed, or 

otherwise secured in position since these were verified to be in the 

correct position prior to being secured. This SR also does not apply to 

valves that cannot be inadvertently misaligned, such as check valves. 

This SR does not require any testing or valve manipulation. Rather, it 

involves verifying that those valves outside containment and capable of 

potentially being mispositioned are in the correct position. 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6A 

CEOG STS B 3.6.6A-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.6.6A.2

Operating each containment cooling train fan unit for ≥ 15 minutes 

ensures that all trains are OPERABLE and that all associated controls are 

functioning properly. It also ensures that blockage, fan or motor failure, or 

excessive vibration can be detected and corrective action taken. The 

31 day Frequency of this SR was developed considering the known 

reliability of the fan units and controls, the two train redundancy available, 

and the low probability of a significant degradation of the containment 

cooling train occurring between surveillances and has been shown to be 

acceptable through operating experience. 

SR 3.6.6A.3

Verifying a service water flow rate of ≥ [2000] gpm to each cooling unit 

provides assurance that the design flow rate assumed in the safety 

analyses will be achieved (Ref. 2). Also considered in selecting this 

Frequency were the known reliability of the Cooling Water System, the 

two train redundancy, and the low probability of a significant degradation 

of flow occurring between surveillances. 

[ SR 3.6.6A.4

Verifying that the containment spray header piping is full of water to the 

[100] ft level minimizes the time required to fill the header. This ensures 

that spray flow will be admitted to the containment atmosphere within the 

time frame assumed in the containment analysis. The 31 day Frequency 

is based on the static nature of the fill header and the low probability of a 

significant degradation of water level in the piping occurring between 

surveillances. ]

SR 3.6.6A.5

Verifying that each containment spray pump's developed head at the flow 

test point is greater than or equal to the required developed head ensures 

that spray pump performance has not degraded during the cycle. Flow 

and differential pressure are normal tests of centrifugal pump 

performance required by Section XI of the ASME Code (Ref. 7). Since 

the containment spray pumps cannot be tested with flow through the 

spray headers, they are tested on recirculation flow. This test confirms 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6A 

CEOG STS B 3.6.6A-9 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

one point on the pump design curve and is indicative of overall 

performance. Such inservice inspections confirm component 

OPERABILITY, trend performance, and detect incipient failures by 

indicating abnormal performance. The Frequency of this SR is in 

accordance with the Inservice Testing Program. 

SR 3.6.6A.6 and SR 3.6.6A.7

These SRs verify that each automatic containment spray valve actuates 

to its correct position and that each containment spray pump starts upon 

receipt of an actual or simulated actuation signal. This Surveillance 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 these Surveillances under the 

conditions that apply during a plant outage and the potential for an 

unplanned transient if the Surveillances were performed with the reactor 

at power. 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. 

The surveillance of containment sump isolation valves is also required by 

SR 3.5.2.5. A single surveillance may be used to satisfy both 

requirements. 

SR 3.6.6A.8

This SR verifies that each containment cooling train actuates upon receipt 

of an actual or simulated actuation signal. The [18] month Frequency is 

based on engineering judgment and has been shown to be acceptable 

through operating experience. See SR 3.6.6A.6 and SR 3.6.6A.7, above, 

for further discussion of the basis for the [18] month Frequency. 

SR 3.6.6A.9

With the containment spray inlet valves closed and the spray header 

drained of any solution, low pressure air or smoke can be blown through 

test connections. Performance of this SR demonstrates that each spray 

nozzle is unobstructed and provides assurance that spray coverage of the 

containment during an accident is not degraded. Due to the passive 

design of the nozzle, a test at [the first refueling and at] 10 year intervals 

is considered adequate to detect obstruction of the spray nozzles. 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6A 

CEOG STS B 3.6.6A-10 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 38, GDC 39, GDC 40, GDC 41, 

GDC 42, and GDC 43. 

 2. FSAR, Section [ ]. 

 3. FSAR, Section [ ]. 

 4. FSAR, Section [ ]. 

5. FSAR, Section [ ]. 

6. CE NPSD-1045-A, “CEOG Joint Application Report for Modification 

to the Containment Spray System Technical Specifications," 

March 2000. 

 7. ASME, Boiler and Pressure Vessel Code, Section XI. 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6B 

CEOG STS B 3.6.6B-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.6B Containment Spray and Cooling Systems (Atmospheric and Dual) (Credit not taken 

 for iodine removal by the Containment Spray System) 

BASES 

BACKGROUND The Containment Spray and Containment Cooling systems provide 

containment atmosphere cooling to limit post accident pressure and 

temperature in containment to less than the design values. Reduction of 

containment pressure reduces the release of fission product radioactivity 

from containment to the environment, in the event of a Design Basis 

Accident (DBA). The Containment Spray and Containment Cooling 

systems are designed to the requirements of 10 CFR 50, Appendix A, 

GDC 38, "Containment Heat Removal," GDC 39, "Inspection of 

Containment Heat Removal Systems," GDC 40, "Testing of Containment 

Heat Removal Systems," GDC 41, "Containment Atmosphere Cleanup," 

GDC 42, "Inspection of Containment Atmosphere Cleanup Systems," and 

GDC 43, "Testing of Containment Atmosphere Cleanup Systems" 

(Ref. 1), or other documents that were appropriate at the time of licensing 

(identified on a unit specific basis). 

The Containment Cooling System and Containment Spray System are 

Engineered Safety Feature (ESF) systems. They are designed to ensure 

that the heat removal capability required during the post accident period 

can be attained. The Containment Spray System and the Containment 

Cooling System provide redundant methods to limit and maintain post 

accident conditions to less than the containment design values. 

Containment Spray System

The Containment Spray System consists of two separate trains of equal 

capacity, each capable of meeting the design bases. Each train includes 

a containment spray pump, spray headers, nozzles, valves, and piping. 

Each train is powered from a separate ESF bus. The refueling water tank 

(RWT) supplies borated water to the containment spray during the 

injection phase of operation. In the recirculation mode of operation, 

containment spray pump suction is transferred from the RWT to the 

containment sump(s). 

The Containment Spray System provides a spray of cold borated water 

into the upper regions of containment to reduce the containment pressure 

and temperature during a DBA. The RWT solution temperature is an 

important factor in determining the heat removal capability of the 

Containment Spray System during the injection phase. In the 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6B 

CEOG STS B 3.6.6B-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

recirculation mode of operation, heat is removed from the containment 

sump water by the shutdown cooling heat exchangers. Each train of the 

Containment Spray System provides adequate spray coverage to meet 

50% of the system design requirements for containment heat removal. 

The Containment Spray System is actuated either automatically by a 

containment High-High pressure signal coincident with a safety injection 

actuation signal (SIAS) or manually. An automatic actuation opens the 

containment spray pump discharge valves, starts the two containment 

spray pumps, and begins the injection phase. The containment spray 

header isolation valves open on a containment spray actuation signal. A 

manual actuation of the Containment Spray System is available on the 

main control board to begin the same sequence. The injection phase 

continues until an RWT level Low signal is received. The Low level signal 

for the RWT generates a recirculation actuation signal that aligns valves 

from the containment spray pump suction to the containment sump. The 

Containment Spray System in recirculation mode maintains an 

equilibrium temperature between the containment atmosphere and the 

recirculated sump water. Operation of the Containment Spray System in 

the recirculation mode is controlled by the operator in accordance with the 

emergency operating procedures. 

Containment Cooling System

Two trains of containment cooling, each of sufficient capacity to supply 

50% of the design cooling requirements, are provided. Two trains with 

two fan units each are supplied with cooling water from a separate train of 

service water. All four fans are required to furnish the design cooling 

capacity. Air is drawn into the coolers through the fan and discharged to 

the steam generator compartments and pressurizer compartments. 

In post accident operation following a containment cooling actuation 

signal (CCAS), all four Containment Cooling System fans are designed to 

start automatically in slow speed, if not already running. Cooling is 

shifted from the chilled water cooled coils to the service water cooled 

coils. The temperature of the service water is an important factor in the 

heat removal capability of the fan units. 

APPLICABLE The Containment Spray System and Containment Cooling System limit 

SAFETY the temperature and pressure that could be experienced following a 

ANALYSES DBA. The limiting DBAs considered relative to containment temperature 

and pressure are the loss of coolant accident (LOCA) and the main steam 

line break (MSLB). The DBA LOCA and MSLB are analyzed using 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6B 

CEOG STS B 3.6.6B-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

computer codes designed to predict the resultant containment pressure 

and temperature transients. No DBAs are assumed to occur 

simultaneously or consecutively. The postulated DBAs are analyzed, in 

regard to containment ESF systems, assuming the loss of one ESF bus, 

which is the worst case single active failure, resulting in one train of the 

Containment Spray System and one train of Containment Cooling System 

being rendered inoperable. 

The analysis and evaluation show that under the worst case scenario, the 

highest peak containment pressure is [55.7] psig (experienced during an 

MSLB). The analysis shows that the peak containment vapor 

temperature is [414]°F (experienced during an MSLB). Both results are 

within the intent of the design basis. (See the Bases for 

Specifications 3.6.4A and 3.6.4B, "Containment Pressure," and 3.6.5, 

"Containment Air Temperature," for a detailed discussion.) The analyses 

and evaluations assume a power level of [102]% RTP, one containment 

spray train and one containment cooling train operating, and initial (preaccident) conditions of [120]°F and [14.7] psia. The analyses also 

assume a response time delayed initiation in order to provide 

conservative peak calculated containment pressure and temperature 

responses. 

The effect of an inadvertent containment spray actuation has been 

analyzed. An inadvertent spray actuation reduces the containment 

pressure to [-2.8] psig due to the sudden cooling effect in the interior of 

the air tight containment. Additional discussion is provided in the Bases 

for Specifications 3.6.4A, 3.6.4B, and 3.6.12, "Vacuum Relief Valves." 

The modeled Containment Spray System actuation from the containment 

analysis is based on a response time associated with exceeding the 

containment High-High pressure setpoint coincident with an SIAS to 

achieve full flow through the containment spray nozzles. The 

Containment Spray System total response time of [60] seconds includes 

diesel generator startup (for loss of offsite power), block loading of 

equipment, containment spray pump startup, and spray line filling 

(Ref. 2). 

The performance of the containment cooling train for post accident 

conditions is given in Reference 3. The result of the analysis is that each 

train can provide 50% of the required peak cooling capacity during the 

post accident condition. The train post accident cooling capacity under 

varying containment ambient conditions, required to perform the accident 

analyses, is also shown in Reference [4]. 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6B 

CEOG STS B 3.6.6B-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The modeled Containment Cooling System actuation from the 

containment analysis is based on the unit specific response time 

associated with exceeding the CCAS to achieve full Containment Cooling 

System air and safety grade cooling water flow. 

The Containment Spray System and the Containment Cooling System 

satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO During a DBA, a minimum of two containment cooling trains or two 

containment spray trains, or one of each, is required to maintain the 

containment peak pressure and temperature below the design limits 

(Ref. 5). To ensure that these requirements are met, two containment 

spray trains and two containment cooling units must be OPERABLE. 

Therefore, in the event of an accident, the minimum requirements are 

met, assuming the worst case single active failure occurs. 

Each Containment Spray System typically includes a spray pump, spray 

headers, nozzles, valves, piping, instruments, and controls to ensure an 

OPERABLE flow path capable of taking suction from the RWT upon an 

ESF actuation signal and automatically transferring suction to the 

containment sump. 

Each Containment Cooling System typically includes demisters, cooling 

coils, dampers, fans, instruments, and controls to ensure an OPERABLE 

flow path. 

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive 

material to containment and an increase in containment pressure and 

temperature requiring the operation of the containment spray trains and 

containment cooling trains. 

In MODES 5 and 6, the probability and consequences of these events are 

reduced due to the pressure and temperature limitations of these 

MODES. Thus, the Containment Spray and Containment Cooling 

systems are not required to be OPERABLE in MODES 5 and 6. 

ACTIONS A.1

With one containment spray train inoperable, the inoperable containment 

spray train must be restored to OPERABLE status within 7 days. The 

components in this degraded condition are capable of providing greater 

than 100% of the heat removal needs (for the condition of one 

containment spray train inoperable) after an accident. The 7 day 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6B 

CEOG STS B 3.6.6B-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Completion Time was developed taking into account the redundant heat 

removal capabilities afforded by combinations of the Containment Spray 

System and Containment Cooling System and the low probability of a 

DBA occurring during this period. 

The 14 day portion of the Completion Time for Required Action A.1 is 

based upon engineering judgment. It takes into account the low 

probability of coincident entry into two Conditions in this Specification 

coupled with the low probability of an accident occurring during this time. 

Refer to Section 1.3, "Completion Times," for a more detailed discussion 

of the purpose of the "from discovery of failure to meet the LCO" portion 

of the Completion Time. 

B.1

With one required containment cooling train inoperable, the inoperable 

containment cooling train must be restored to OPERABLE status within 

7 days. The components in this degraded condition are capable of 

providing greater than 100% of the heat removal needs (for the condition 

of one containment cooling train inoperable) after an accident. The 7 day 

Completion Time was developed based on the same reasons as those for 

Required Action A.1. 

The 14 day portion of the Completion Time for Required Action B.1 is 

based upon engineering judgment. It takes into account the low 

probability of coincident entry into two Conditions in this Specification 

coupled with the low probability of an accident occurring during this time. 

Refer to Section 1.3 for a more detailed discussion of the purpose of the 

"from discovery of failure to meet the LCO" portion of the Completion 

Time. 

C.1

With two required containment spray trains inoperable, one of the 

required containment spray trains must be restored to OPERABLE status 

within 72 hours. The components in this degraded condition are capable 

of providing greater than 100% of the heat removal needs after an 

accident. The 72 hour Completion Time was developed taking into 

account the redundant heat removal capabilities afforded by combinations 

of the Containment Spray System and Containment Cooling System and 

the low probability of a DBA occurring during this period. 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6B 

CEOG STS B 3.6.6B-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

D.1 and D.2

With one required containment spray train inoperable and one of the 

required containment cooling trains inoperable, the inoperable 

containment spray train or the inoperable containment cooling train must 

be restored to OPERABLE status within 72 hours. The components in 

this degraded condition are capable of providing at least 100% of the heat 

removal needs after an accident. The 72 hour Completion Time was 

developed based on the same reasons as those for Required Action C.1. 

E.1

With two containment cooling trains inoperable, one of the required 

containment cooling trains must be restored to OPERABLE status within 

72 hours. The components in this degraded condition are capable of 

providing greater than 100% of the heat removal needs after an accident. 

The 72 hour Completion Time was developed based on the same 

reasons as those for Required Action C.1. 

F.1 and F.2

If any of the Required Actions and associated Completion Times of this 

LCO are not met, the plant must be brought to a MODE in which the LCO 

does not apply. To achieve this status, the plant must be brought to at 

least MODE 3 within 6 hours and to MODE 5 within 36 hours. The 

allowed Completion Times are reasonable, based on operating 

experience, to reach the required plant conditions from full power 

conditions in an orderly manner and without challenging plant systems. 

G.1

With any combination of three or more Containment Spray System and 

Containment Cooling System trains inoperable, the unit is in a condition 

outside the accident analysis. Therefore, LCO 3.0.3 must be entered 

immediately. 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6B 

CEOG STS B 3.6.6B-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.6.6B.1

REQUIREMENTS 

Verifying the correct alignment for manual, power operated, and 

automatic valves, excluding check valves, in the Containment Spray 

System provides assurance that the proper flow path exists for 

Containment Spray System operation. This SR also does not apply to 

valves that are locked, sealed, or otherwise secured in position since 

these were verified to be in the correct positions prior to being secured. 

This SR also does not apply to valves that cannot be inadvertently 

misaligned, such as check valves. This SR does not require any testing 

or valve manipulation. Rather, it involves verification that those valves 

outside containment and capable of potentially being mispositioned, are 

in the correct position. 

SR 3.6.6B.2

Operating each containment cooling train fan unit for ≥ 15 minutes 

ensures that all trains are OPERABLE and that all associated controls are 

functioning properly. It also ensures that blockage, fan or motor failure, or 

excessive vibration can be detected for corrective action. The 31 day 

Frequency was developed considering the known reliability of the fan 

units and controls, the two train redundancy available, and the low 

probability of a significant degradation of the containment cooling train 

occurring between surveillances. 

SR 3.6.6B.3

Verifying a service water flow rate of ≥ [2000] gpm to each cooling unit 

provides assurance the design flow rate assumed in the safety analyses 

will be achieved (Ref. 2). Also considered in selecting this Frequency 

were the known reliability of the cooling water system, the two train 

redundancy, and the low probability of a significant degradation of flow 

occurring between surveillances. 

[ SR 3.6.6B.4

Verifying the containment spray header is full of water to the [100] ft level 

minimizes the time required to fill the header. This ensures that spray 

flow will be admitted to the containment atmosphere within the time frame 

assumed in the containment analysis. The 31 day Frequency is based on 

the static nature of the fill header and the low probability of a significant 

degradation of the water level in the piping occurring between 

surveillances. ]
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6B 

CEOG STS B 3.6.6B-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.6.6B.5

Verifying that each containment spray pump's developed head at the flow 

test point is greater than or equal to the required developed head ensures 

that spray pump performance has not degraded during the cycle. Flow 

and differential pressure are normal tests of centrifugal pump 

performance required by Section XI of the ASME Code (Ref. 6). Since 

the containment spray pumps cannot be tested with flow through the 

spray headers, they are tested on recirculation flow. This test confirms 

one point on the pump design curve and is indicative of overall 

performance. Such inservice inspections confirm component 

OPERABILITY, trend performance, and detect incipient failures by 

indicating abnormal performance. The Frequency of this SR is in 

accordance with the Inservice Testing Program. 

SR 3.6.6B.6 and SR 3.6.6B.7

These SRs verify each automatic containment spray valve actuates to its 

correct position and that each containment spray pump starts upon 

receipt of an actual or simulated actuation signal. This Surveillance 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 these Surveillances under the 

conditions that apply during a plant outage and the potential for an 

unplanned transient if the Surveillances were performed with the reactor 

at power. 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. 

The surveillance of containment sump isolation valves is also required by 

SR 3.5.2.5. A single surveillance may be used to satisfy both 

requirements. 

SR 3.6.6B.8

This SR verifies each containment cooling train actuates upon receipt of 

an actual or simulated actuation signal. The [18] month Frequency is 

based on engineering judgment and has been shown to be acceptable 

through operating experience. See SR 3.6.6B.6 and SR 3.6.6B.7, above, 

for further discussion of the basis for the [18] month Frequency. 
Containment Spray and Cooling Systems (Atmospheric and Dual) 

B 3.6.6B 

CEOG STS B 3.6.6B-9 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.6.6B.9

With the containment spray inlet valves closed and the spray header 

drained of any solution, low pressure air or smoke can be blown through 

test connections. Performance of this SR demonstrates that each spray 

nozzle is unobstructed and provides assurance that spray coverage of the 

containment during an accident is not degraded. Due to the passive 

design of the nozzle, a test at [the first refueling and at] 10 year intervals 

is considered adequate to detect obstruction of the spray nozzles. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 38, GDC 39, GDC 40, GDC 41, 

GDC 42, and GDC 43. 

 2. FSAR, Section [ ]. 

 3. FSAR, Sections [ ]. 

 4. FSAR, Section [ ]. 

 5. FSAR, Section [ ]. 

 6. ASME, Boiler and Pressure Vessel Code, Section XI. 
Spray Additive System (Atmospheric and Dual) 

B 3.6.7 

CEOG STS B 3.6.7-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.7 Spray Additive System (Atmospheric and Dual) 

BASES 

BACKGROUND The Spray Additive System is a subsystem of the Containment Spray 

System that assists in reducing the iodine fission product inventory in the 

containment atmosphere in the event of an accident such as a loss of 

coolant accident (LOCA). 

The addition of a spray additive to the boric acid spray solution increases 

the pH of the spray solution and maintains the containment sump pH 

above 8.0 during the recirculation phase of an accident. An elevated pH 

is desired since it enhances the iodine removal capacity of the sprays and 

aids in the retention of iodine in the water in the containment sump. 

The Spray Additive System consists of a single spray additive tank and 

two redundant 100% capacity trains. Each train contains a chemical 

addition pump, an injection valve, isolation valves, a flow meter, and a 

flow controller. Upon receipt of a containment spray actuation signal 

(CSAS), the chemical addition pumps start and the injection valves open 

in each redundant train. The spray additive is then injected into the 

Containment Spray System at the suction of the containment spray 

pumps at metered amounts corresponding to the individual containment 

spray pump discharge flow rate. The rate at which the spray additive is 

added is reduced when a recirculation actuation signal is generated and 

the Containment Spray System enters the recirculation mode of 

operation. The pH of the containment spray solution is maintained 

between 9.0 and 10.0 during the injection mode and between 8.0 and 9.0 

in the recirculation mode. Upon reaching a Low-Low level in the spray 

chemical addition tank, the spray chemical addition pumps stop and the 

injection and isolation valves close (Ref. 1). 

The Spray Additive System aids in reducing the iodine fission production 

inventory in the containment atmosphere. 

APPLICABLE The Spray Additive System is essential to the effective removal of 

SAFETY airborne iodine within containment following a Design Basis Accident 

ANALYSES (DBA). 

Following the assumed release of radioactive materials into containment, 

the containment is assumed to leak at its design value following the 

accident. 
Spray Additive System (Atmospheric and Dual) 

B 3.6.7 

CEOG STS B 3.6.7-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The DBA response time assumed for the Spray Additive System is the 

same as for the Containment Spray System and is discussed in the 

Bases for Specification 3.6.6, "Containment Spray and Cooling Systems." 

The DBA analyses assume that one train of the Containment Spray 

System/Spray Additive System is inoperable and that the entire spray 

additive tank volume is added to the remaining Containment Spray 

System flow path. 

During a LOCA, the iodine inventory released to the containment is 

considered to be released instantaneously and uniformly distributed in the 

containment free volume. The containment volume is made up of 

sprayed and unsprayed regions. The sprayed region is enveloped by 

direct spray and mixed by the dome air circulators and emergency fan 

coolers. Mixing between the sprayed and unsprayed regions is facilitated 

by the emergency fan coolers and condensation of steam by the sprays. 

The Spray Additive System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The Spray Additive System is necessary to reduce the release of 

radioactive material to the environment in the event of a DBA. To be 

considered OPERABLE, the volume and concentration of the spray 

additive solution must be sufficient to maintain the pH of the spray 

solution between [9.0 and 10.0] in the injection mode and [8.0 and 9.0] in 

the recirculation mode. This pH range maximizes the effectiveness of the 

iodine removal mechanism, without introducing conditions that may 

induce caustic stress corrosion cracking of mechanical components. 

During a LOCA, one Spray Additive System train is capable of providing 

100% of the required iodine removal capacity. To ensure at least one 

train is available in the event of the limiting single failure, both trains must 

be maintained in an OPERABLE status. 

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive 

material to containment requiring the operation of the Spray Additive 

System. The Spray Additive System assists in reducing the iodine fission 

product inventory prior to release to the environment. 

In MODES 5 and 6, the probability and consequences of these events are 

reduced due to the pressure and temperature limitations in these 

MODES. Thus, the Spray Additive System is not required to be 

OPERABLE in MODES 5 and 6. 
Spray Additive System (Atmospheric and Dual) 

B 3.6.7 

CEOG STS B 3.6.7-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

With the Spray Additive System inoperable, the system must be restored 

to OPERABLE status within 72 hours. The pH adjustment of the 

containment spray flow for corrosion protection and iodine removal 

enhancement are reduced in this condition. The Containment Spray 

System would still be available and would remove some iodine from the 

containment atmosphere in the event of a DBA. The 72 hour Completion 

Time takes into account the redundant flow path capabilities and the low 

probability of the worst case DBA occurring during this period. 

B.1 and B.2

If the Spray Additive System cannot be restored to OPERABLE status 

within the required Completion Time, the plant must be brought to a 

MODE in which the LCO does not apply. To achieve this status, the plant 

must be brought to at least MODE 3 within 6 hours and to MODE 5 within 

84 hours. The allowed Completion Time of 6 hours is reasonable, based 

on operating experience, to reach MODE 3 from full power conditions in 

an orderly manner and without challenging plant systems. The extended 

interval to reach MODE 5 allows additional time for restoration of the 

Spray Additive System and is reasonable when considering the reduced 

pressure and temperature conditions in MODE 3 for the release of 

radioactive material from the Reactor Coolant System. 

SURVEILLANCE SR 3.6.7.1

REQUIREMENTS 

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 SR 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 SR does not require any testing or valve manipulation. 

Rather, it involves verification that those valves outside containment and 

capable of potentially being mispositioned are in the correct position. 
Spray Additive System (Atmospheric and Dual) 

B 3.6.7 

CEOG STS B 3.6.7-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.6.7.2

To provide effective iodine removal, the containment spray must be an 

alkaline solution. Since the refueling water tank 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 SR is 

performed to verify the availability of sufficient hydrazine (N2H4) solution in 

the Spray Additive System. The 184 day Frequency is based on the low 

probability of an undetected change in tank volume occurring during the 

SR interval (the tank is isolated during normal unit operations). Tank 

level is also indicated and alarmed in the control room, such that there is 

a high confidence that a substantial change in level would be detected. 

SR 3.6.7.3

This SR provides verification of the N2H4 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 concentration of 

N2H4 in the spray additive tank must be determined by chemical analysis. 

The 184 day Frequency is sufficient to ensure that the concentration level 

of N2H4 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 

substantial variance in tank volume will be detected. 

[ SR 3.6.7.4

The chemical addition pump must be verified to provide the flow rate 

assumed in the accident analysis to the Containment Spray System. The 

Spray Additive System is not operated during normal operations. This 

prevents periodically subjecting systems, structures, and components 

within containment to a caustic spray solution. Therefore, this test must 

be performed on recirculation with the discharge flow path from each 

spray chemical addition pump aligned back to the spray additive tank. 

The differential pressure obtained by the pump on recirculation is 

analogous to the full spray additive flow provided to the Containment 

Spray System on an actual CSAS. The Frequency of this SR is in 

accordance with the Inservice Testing Program and is sufficient to identify 

component degradation that may affect flow rate. ]
Spray Additive System (Atmospheric and Dual) 

B 3.6.7 

CEOG STS B 3.6.7-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.6.7.5

This SR verifies that each automatic valve in the Spray Additive System 

flow path actuates to its correct position on a CSAS. This Surveillance 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 Surveillance under the 

conditions that apply during a plant outage and the potential for an 

unplanned transient if the Surveillance were performed with the reactor at 

power. Operating experience has shown that these components usually 

pass the Surveillance when performed at the [18] month Frequency. 

Therefore, the Frequency was concluded to be acceptable from a 

reliability standpoint. 

[ SR 3.6.7.6

To ensure that the correct pH level is established in the borated water 

solution provided by the Containment Spray System, the flow rate in the 

Spray Additive System is verified once per 5 years. This SR provides 

assurance that the correct amount of N2H4 will be metered into the flow 

path upon Containment Spray System initiation. 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 rate. ] 

REFERENCES 1. FSAR, Section [ ]. 
HMS (Atmospheric and Dual) 

B 3.6.9 

CEOG STS B 3.6.9-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.9 Hydrogen Mixing System (HMS) (Atmospheric and Dual) 

BASES 

BACKGROUND The HMS reduces the potential for breach of containment due to a 

hydrogen oxygen reaction by providing a uniformly mixed post accident 

containment atmosphere, thereby minimizing the potential for local 

hydrogen burns due to a local pocket of hydrogen above the flammable 

concentration and giving the operator the capability of preventing the 

occurrence of a bulk hydrogen burn inside containment per 

10 CFR 50.44, "Standards for Combustible Gas Control Systems in LightWater-Cooled Reactors" (Ref. 1), and 10 CFR 50, GDC 41, "Containment 

Atmosphere Cleanup" (Ref. 2). 

The post accident HMS is an Engineered Safety Feature and is designed 

to withstand a loss of coolant accident (LOCA) without loss of function. 

The system has two independent trains, each of which consists of two 

dome air circulation fans, motors, and controls. Each train is sized for 

[37,000] cfm. The two trains are initiated automatically on a containment 

cooling actuation signal (CCAS) or can be manually started from the 

control room. Each train is powered from a separate emergency power 

supply. Since each train can provide 100% of the mixing requirements, 

the system will provide its design function with a limiting single active 

failure. 

The HMS accelerates the air mixing process between the upper dome 

space of the containment atmosphere during LOCA operations. It also 

prevents any hot spot air pockets during the containment cooling mode 

and avoids any hydrogen concentration in pocket areas. 

Hydrogen mixing within the containment is accomplished by the 

Containment Spray System, the containment emergency fan coolers, and 

the containment internal structure design, which permits convective 

mixing and prevents entrapment. The HMS, operating in conjunction with 

the Containment Spray System and the emergency fan coolers, prevents 

localized accumulations of hydrogen from exceeding the flammability limit 

of 4.1 volume percent (v/o). 

APPLICABLE The HMS mixes the containment atmosphere to provide a uniform 

SAFETY hydrogen concentration. 

ANALYSES 

Hydrogen may accumulate in containment following a LOCA as a result 

of: 
HMS (Atmospheric and Dual) 

B 3.6.9 

CEOG STS B 3.6.9-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

a. A metal steam reaction between the zirconium fuel rod cladding and 

the reactor coolant, 

b. Radiolytic decomposition of water in the Reactor Coolant System 

(RCS) and the containment sump, 

c. Hydrogen in the RCS at the time of the LOCA (i.e., hydrogen 

dissolved in the reactor coolant and hydrogen gas in the pressurizer 

vapor space), or 

d. Corrosion of metals exposed to Containment Spray System and 

Emergency Core Cooling Systems solutions. 

To evaluate the potential for hydrogen accumulation in containment 

following a LOCA, the hydrogen generation as a function of time following 

the initiation of the accident is calculated. Conservative assumptions 

recommended by Reference 3 are used to maximize the amount of 

hydrogen calculated. 

The HMS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Two HMS trains must be OPERABLE, with power to each from an 

independent, safety related power supply. Each train typically consists of 

two fans with their own motors and controls and is automatically initiated 

by a CCAS. 

Operation with at least one HMS train provides the mixing necessary to 

ensure uniform hydrogen concentration throughout containment. 

APPLICABILITY In MODES 1 and 2, the two HMS trains ensure the capability to prevent 

localized hydrogen concentrations above the flammability limit of 4.1 v/o 

in containment, assuming a worst case single active failure. 

In MODE 3 or 4, both the hydrogen production rate and the total 

hydrogen produced after a LOCA would be less than that calculated for 

the DBA LOCA. Also, because of the limited time in these MODES, the 

probability of an accident requiring the HMS is low. Therefore, the HMS 

is not required in MODE 3 or 4. 

In MODES 5 and 6, the probability and consequences of a LOCA or main 

steam line break are low due to the pressure and temperature limitations 

of these MODES. Therefore, the HMS is not required in these MODES. 
HMS (Atmospheric and Dual) 

B 3.6.9 

CEOG STS B 3.6.9-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

With one HMS train inoperable, the inoperable train must be restored to 

OPERABLE status within 30 days. The 30 day Completion Time is based 

on the availability of the other HMS train, the small probability of a LOCA 

or SLB occurring (that would generate an amount of hydrogen that 

exceeds the flammability limit), the amount of time available after a LOCA 

or SLB (should one occur) for operator action to prevent hydrogen 

accumulation from exceeding the flammability limit, and the availability of 

the Containment Spray System and Hydrogen Purge System. 

B.1 and B.2

-----------------------------------REVIEWER’S NOTE----------------------------------- 

This Condition is only allowed for units with an alternate hydrogen control 

system acceptable to the technical staff. 

-------------------------------------------------------------------------------------------------- 

With two HMS inoperable, the ability to perform the hydrogen control 

function via alternate capabilities must be verified by administrative 

means within 1 hour. The alternate hydrogen control capabilities are 

provided by [the containment Hydrogen Purge System/Hydrogen Ignitor 

System/HMS/Containment Air Dilution System/Containment Inerting 

System]. The 1 hour Completion Time allows a reasonable period of time 

to verify that a loss of hydrogen control function does not exist. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

The following is to be used if a non-Technical Specification alternate 

hydrogen control function is used to justify this Condition. In addition, the 

alternate hydrogen control system capability must be verified every 

12 hours thereafter to ensure its continued availability. 

-------------------------------------------------------------------------------------------------- 

[Both] the [initial] verification [and all subsequent verifications] may be 

performed as an administrative check, by examining logs or other 

information to determine the availability of the alternate hydrogen control 

system. It does not mean to perform the Surveillances needed to 

demonstrate OPERABILITY of the alternate hydrogen control system. If 

the ability to perform the hydrogen control function is maintained, 

continued operation is permitted with two HMS trains inoperable for up to 

7 days. Seven days is a reasonable time to allow two HMS trains to be 

inoperable because the hydrogen control function is maintained and 

because of the low probability of the occurrence of a LOCA that would 

generate hydrogen in the amounts capable of exceeding the flammability 

limit. 
HMS (Atmospheric and Dual) 

B 3.6.9 

CEOG STS B 3.6.9-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1

If an inoperable HMS train cannot be restored to OPERABLE status 

within the required Completion Time, the plant must be brought to a 

MODE in which the LCO does not apply. To achieve this status, the plant 

must be brought to at least MODE 3 within 6 hours. The allowed 

Completion Time of 6 hours is reasonable, based on operating 

experience, to reach MODE 3 from full power conditions in an orderly 

manner and without challenging plant systems. 

SURVEILLANCE SR 3.6.9.1

REQUIREMENTS 

Operating each HMS train for ≥ 15 minutes ensures that the train is 

OPERABLE and that all associated controls are functioning properly. It 

also ensures that blockage, fan and/or motor failure, or excessive 

vibration can be detected for corrective action. The 92 day Frequency is 

consistent with Inservice Testing Program Surveillance Frequencies, 

operating experience, the known reliability of the fan motors and controls, 

and the two train redundancy available. 

SR 3.6.9.2

Verifying that each HMS train flow rate on slow speed is ≥ [37,000] cfm 

ensures that each train is capable of maintaining localized hydrogen 

concentrations below the flammability limit. 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. Operating 

experience has shown that these components usually pass the 

Surveillance when performed at the [18] month Frequency. Therefore, 

the Frequency was concluded to be acceptable from a reliability 

standpoint. 

SR 3.6.9.3

This SR ensures that the HMS responds properly to a CCAS. 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. Operating experience has shown that these 

components usually pass the Surveillance when performed at the 

[18] month Frequency. Therefore, the Frequency was concluded to be 

acceptable from a reliability standpoint. 
HMS (Atmospheric and Dual) 

B 3.6.9 

CEOG STS B 3.6.9-5 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. 10 CFR 50.44. 

 2. 10 CFR 50, Appendix A, GDC 41. 

 3. Regulatory Guide 1.7, Revision [1]. 
ICS (Atmospheric and Dual) 

B 3.6.10 

CEOG STS B 3.6.10-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.10 Iodine Cleanup System (ICS) (Atmospheric and Dual) 

BASES 

BACKGROUND The ICS is provided per GDC 41, "Containment Atmosphere Cleanup," 

GDC 42, "Inspection of Containment Atmosphere Cleanup Systems," and 

GDC 43, "Testing of Containment Atmosphere Cleanup Systems" 

(Ref. 1), to reduce the concentration of fission products released to the 

containment atmosphere following a postulated accident. The ICS would 

function together with the Containment Spray and Cooling systems 

following a Design Basis Accident (DBA) to reduce the potential release 

of radioactive material, principally iodine, from the containment to the 

environment. 

The ICS consists of two 100% capacity separate, independent, and 

redundant trains. Each train includes a heater, [cooling coils,] a prefilter, 

a moisture separator, a high efficiency particulate air (HEPA) filter, an 

activated charcoal adsorber section for removal of radioiodines, and a 

fan. Ductwork, valves and/or dampers, and instrumentation also form 

part of the system. The moisture separators function to reduce the 

moisture content of the airstream. A second bank of HEPA filters follows 

the adsorber section to collect carbon fines and provide backup in case of 

failure of the main HEPA filter bank. Only the upstream HEPA filter and 

the charcoal adsorber section are credited in the analysis. The system 

initiates filtered recirculation of the containment atmosphere following 

receipt of a containment isolation actuation signal. The system design is 

described in Reference 2. 

The primary purpose of the heaters is to ensure that the relative humidity 

of the airstream entering the charcoal adsorbers is maintained below 

70%, which is consistent with the assigned iodine and iodide removal 

efficiencies as per Regulatory Guide 1.52 (Ref. 3). 

The moisture separator is included for moisture (free water) removal from 

the gas stream. Heaters are used to heat the gas stream, which lowers 

the relative humidity. Continuous operation of each train for at least 

10 hours per month with the heaters on reduces moisture buildup on the 

HEPA filters and adsorbers. Both the moisture separator and heater are 

important to the effectiveness of the charcoal adsorbers. 

Two ICS trains are provided to meet the requirement for separation, 

independence, and redundancy. Each ICS train is powered from a 

separate Engineered Safety Features bus and is provided with a separate 

power panel and control panel. [Service water is required to supply 

cooling water to the cooling coils.] 
ICS (Atmospheric and Dual) 

B 3.6.10 

CEOG STS B 3.6.10-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The DBAs that result in a release of radioactive iodine within containment 

SAFETY are a loss of coolant accident (LOCA), a main steam line break (MSLB), 

ANALYSES or a control element assembly (CEA) ejection accident. In the analysis 

for each of these accidents, it is assumed that adequate containment leak 

tightness is intact at event initiation to limit potential leakage to the 

environment. Additionally, it is assumed that the amount of radioactive 

iodine release is limited by reducing the iodine concentration in the 

containment atmosphere. 

The ICS design basis is established by the consequences of the limiting 

DBA, which is a LOCA. The accident analysis (Ref. 4) assumes that only 

one train of the ICS is functional due to a single failure that disables the 

other train. The accident analysis accounts for the reduction in airborne 

radioactive iodine provided by the remaining one train of this filtration 

system. 

The ICS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Two separate, independent, and redundant trains of the ICS are required 

to ensure that at least one is available, assuming a single failure 

coincident with a loss of offsite power. 

APPLICABILITY In MODES 1, 2, 3, and 4, iodine is a fission product that can be released 

from the fuel to the reactor coolant as a result of a DBA. The DBAs that 

can cause a failure of the fuel cladding are a LOCA, MSLB, and CEA 

ejection accident. Because these accidents are considered credible 

accidents in MODES 1, 2, 3, and 4, the ICS must be operable in these 

MODES to ensure the reduction in iodine concentration assumed in the 

accident analysis. 

In MODES 5 and 6, the probability and consequences of a LOCA are low 

due to the pressure and temperature limitations of these MODES. The 

ICS is not required in these MODES to remove iodine from the 

containment atmosphere. 

ACTIONS A.1

With one ICS train inoperable, the inoperable train must be restored to 

OPERABLE status within 7 days. The components in this degraded 

condition are capable of providing 100% of the iodine removal needs after 

a DBA. The 7 day Completion Time is based on consideration of such 

factors as: 

a. The availability of the OPERABLE redundant ICS train, 
ICS (Atmospheric and Dual) 

B 3.6.10 

CEOG STS B 3.6.10-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

b. The fact that, even with no ICS train in operation, almost the same 

amount of iodine would be removed from the containment 

atmosphere through absorption by the Containment Spray System, 

and 

c. The fact that the Completion Time is adequate to make most repairs. 

B.1 and B.2

If the ICS train cannot be restored to OPERABLE status within the 

required Completion Time, the plant must be brought to a MODE in which 

the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 5 within 

36 hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE SR 3.6.10.1

REQUIREMENTS 

Operating each ICS train for ≥ 15 minutes ensures that all trains are 

OPERABLE and that all associated controls are functioning properly. It 

also ensures that blockage, fan or motor failure, or excessive vibration 

can be detected for corrective action. For systems with heaters, 

operation with the heaters on (automatic heater cycling to maintain 

temperature) for ≥ 10 continuous hours eliminates moisture on the 

adsorbers and HEPA filters. Experience from filter testing at operating 

units indicates that the 10 hour period is adequate for moisture 

elimination on the adsorbers and HEPA filters. The 31 day Frequency 

was developed considering the known reliability of fan motors and 

controls, the two train redundancy available, and the iodine removal 

capability of the Containment Spray System independent of the ICS. 

SR 3.6.10.2

This SR verifies that the required ICS filter testing is performed in 

accordance with the Ventilation Filter Testing Program (VFTP). The 

VFTP includes testing HEPA filter performance, charcoal adsorber 

efficiency, minimum system flow rate, and the physical properties of the 

activated charcoal (general use and following specific operations). 

Specific test frequencies and additional information are discussed in 

detail in the VFTP. 
ICS (Atmospheric and Dual) 

B 3.6.10 

CEOG STS B 3.6.10-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.6.10.3

The automatic startup test verifies that both trains of equipment start upon 

receipt of an actual or simulated test signal. 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. Operating 

experience has shown that these components usually pass the 

Surveillance when performed at the [18] month Frequency. Therefore, 

the Frequency was concluded to be acceptable from a reliability 

standpoint. Furthermore, the Frequency was developed considering that 

the system equipment OPERABILITY is demonstrated on a 31 day 

Frequency by SR 3.6.10.1. 

[ SR 3.6.10.4

The ICS filter bypass dampers are tested to verify OPERABILITY. The 

dampers are in the bypass position during normal operation and must 

reposition for accident operation to draw air through the filters. The 

[18] month Frequency is considered to be acceptable based on the 

damper reliability and design, the mild environmental conditions in the 

vicinity of the dampers, and the fact that operating experience has shown 

that the dampers usually pass the Surveillance when performed at the 

[18] month Frequency. ] 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 41, GDC 42, and GDC 43. 

 2. FSAR, Section [ ]. 

 3. Regulatory Guide 1.52, Revision [2]. 

 4. FSAR, Section [ ]. 
Shield Building (Dual) 

B 3.6.11 

CEOG STS B 3.6.11-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.11 Shield Building (Dual) 

BASES 

BACKGROUND The shield building is a concrete structure that surrounds the steel 

containment vessel. Between the containment vessel and the shield 

building inner wall is an annular space that collects any containment 

leakage that may occur following a loss of coolant accident (LOCA). This 

space also allows for periodic inspection of the outer surface of the steel 

containment vessel. 

Following a LOCA, the Shield Building Exhaust Air Cleanup System 

(SBEACS) establishes a negative pressure in the annulus between the 

shield building and the steel containment vessel. Filters in the system 

then control the release of radioactive contaminants to the environment. 

A description of the SBEACS is provided in the Bases for 

Specification 3.6.8, "Shield Building Exhaust Air Cleanup System 

(SBEACS)." Shield building OPERABILITY is required to ensure 

retention of primary containment leakage and proper operation of the 

SBEACS. 

APPLICABLE The design basis for shield building OPERABILITY is a large break 

SAFETY LOCA. Maintaining shield building OPERABILITY ensures that the 

ANALYSES release of radioactive material from the primary containment atmosphere 

is restricted to those leakage paths and associated leakage rates 

assumed in the accident analysis. 

The shield building satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Shield building OPERABILITY must be maintained to ensure proper 

operation of the SBEACS and to limit radioactive leakage from the 

containment to those paths and leakage rates assumed in the accident 

analysis. 

APPLICABILITY Maintaining shield building OPERABILITY prevents leakage of radioactive 

material from the shield building. Radioactive material may enter the 

shield building from the primary containment following a LOCA. 

Therefore, shield building OPERABILITY is required in MODES 1, 2, 3, 

and 4 when a main steam line break, LOCA, or control element assembly 

ejection accident could release radioactive material to the primary 

containment atmosphere. 

In MODES 5 and 6, the probability and consequences of these events are 

low due to the Reactor Coolant System temperature and pressure 

limitations in these MODES. Therefore, shield building OPERABILITY is 

not required in MODE 5 or 6. 
Shield Building (Dual) 

B 3.6.11 

CEOG STS B 3.6.11-2 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

In the event shield building OPERABILITY is not maintained, shield 

building OPERABILITY must be restored within 24 hours. 

Twenty-four hours is a reasonable Completion Time considering the 

limited leakage design of the containment and the low probability of a 

DBA occurring during this time period. 

B.1 and B.2

If the shield building cannot be restored to OPERABLE status within the 

required Completion Time, the plant must be brought to a MODE in which 

the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 5 within 

36 hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE SR 3.6.11.1

REQUIREMENTS 

Verifying that shield building annulus pressure is within limit ensures that 

operation remains within the limit assumed in the containment analysis. 

The 12 hour Frequency of this SR was developed considering operating 

experience related to shield building annulus pressure variations and 

pressure instrument drift during the applicable MODES. 

SR 3.6.11.2

Maintaining shield building OPERABILITY requires verifying one door in 

the access opening closed. [An access opening may contain one inner 

and one outer door, or in some cases, shield building access openings 

are shared such that a shield building barrier may have multiple inner or 

multiple outer doors. The intent is to not breach the shield building 

boundary at any time when the shield building boundary is required. This 

is achieved by maintaining the inner or outer portion of the barrier closed 

at all times.] However, all shield building access doors are normally kept 

closed, except when the access opening is being used for entry and exit 

or when maintenance is being performed on an access opening. The 

Frequency of 31 days is based on engineering judgment and is 

considered adequate in view of other indications of door status available 

to the operator. 
Shield Building (Dual) 

B 3.6.11 

CEOG STS B 3.6.11-3 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.6.11.3

This Surveillance would give advance indication of gross deterioration of 

the concrete structural integrity of the shield building. The Frequency of 

this SR is the same as that of SR 3.6.1.1. The verification is done during 

shutdown and as part of Type A leakage tests associated with SR 3.6.1.1. 

SR 3.6.11.4

The SBEACS produces a negative pressure to prevent leakage from the 

building. SR 3.6.11.4 verifies that the shield building can be rapidly 

drawn down to ≥ [0.25] inch water. This test is used to ensure shield 

building boundary integrity. Establishment of this pressure is confirmed 

by SR 3.6.11.4, which demonstrates that the shield building can be drawn 

down to ≥ [0.25] inches of water ≤ 1 minute using one SBEACS train. 

The time limit ensures that no significant quantity of radioactive material 

leaks from the shield building prior to developing the negative pressure. 

Since this SR is a shield building boundary integrity test, it does not need 

to be performed with each SBEACS train. The SBEACS train used for 

this Surveillance is staggered to ensure that in addition to the 

requirements of LCO 3.6.11.4, either train will perform this test. The 

primary purpose of this SR is to ensure shield building integrity. The 

secondary purpose of this SR is to ensure that the SBEACS being tested 

functions as designed. The inoperability of the SBEACS train does not 

necessarily constitute a failure of this Surveillance relative to the shield 

building OPERABILITY. The 18 month Frequency is consistent with 

Regulatory Guide 1.52 (Ref. 1) guidance for functional testing of the 

ability of the SBEACS. 

REFERENCES 1. Regulatory Guide 1.52, Revision [2]. 
Vacuum Relief Valves (Dual) 

B 3.6.12 

CEOG STS B 3.6.12-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.12 Vacuum Relief Valves (Dual) 

BASES 

BACKGROUND The vacuum relief valves protect the containment vessel against negative 

pressure (i.e., a lower pressure inside than outside). Excessive negative 

pressure inside containment can occur if there is an inadvertent actuation 

of the Containment Cooling System or the Containment Spray System. 

Multiple equipment failures or human errors are necessary to have 

inadvertent actuation. 

The containment pressure vessel contains two 100% vacuum relief lines 

installed in parallel that protect the containment from excessive external 

loading. The vacuum relief lines are 24 inch penetrations that connect 

the shield building annulus to the containment. Each vacuum relief line is 

isolated by a pneumatically operated butterfly valve in series with a check 

valve located on the containment side of the penetration. 

Each butterfly valve is actuated by a separate pressure controller that 

senses the differential pressure between the containment and the 

annulus. Each butterfly valve is provided with an air accumulator that 

allows the valve to open following a loss of instrument air. 

The combined pressure drop at rated flow through either vacuum relief 

line will not exceed the containment pressure vessel design external 

pressure differential of [0.65] psig with any prevailing atmospheric 

pressure. 

APPLICABLE Design of the vacuum relief lines involves calculating the effect of an 

SAFETY inadvertent containment spray actuation that can reduce the atmospheric 

ANALYSES temperature (and hence pressure) inside containment (Ref. 1). 

Conservative assumptions are used for all the pertinent parameters in the 

calculation. For example, the minimum spray water temperature is 

assumed, as well as maximum initial containment temperature, maximum 

spray flow, all trains of spray operating, etc. The resulting containment 

pressure versus time is calculated, including the effect of the vacuum 

relief valves opening when their negative pressure setpoint is reached. It 

is also assumed that one vacuum relief line fails to open. 

The containment was designed for an external pressure load equivalent 

to [0.65] psig. The inadvertent actuation of the Containment Spray 

System was analyzed to determine the resulting reduction in containment 

pressure. The initial pressure condition used in this analysis was 

[-0.368] psig. This resulted in a minimum pressure inside containment of 

[0.49] psig, which is less than the design load. 
Vacuum Relief Valves (Dual) 

B 3.6.12 

CEOG STS B 3.6.12-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The vacuum relief valves must also perform the containment isolation 

function in a containment high pressure event. For this reason, the 

system is designed to take the full containment positive design pressure 

and the containment design basis accident (DBA) environmental 

conditions (temperature, pressure, humidity, radiation, chemical attack, 

etc.) associated with the containment DBA. 

The vacuum relief valves satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The LCO establishes the minimum equipment required to accomplish the 

vacuum relief function following the inadvertent actuation of the 

Containment Spray System. Two vacuum relief lines are required to be 

OPERABLE to ensure that at least one is available, assuming one or both 

valves in the other line fail to open. 

APPLICABILITY In MODES 1, 2, 3, and 4, the containment cooling features, such as the 

Containment Spray System, are required to be OPERABLE to mitigate 

the effects of a DBA. Excessive negative pressure inside containment 

could occur whenever these systems are required to be OPERABLE due 

to inadvertent actuation of these systems. Therefore, the vacuum relief 

lines are required to be OPERABLE in MODES 1, 2, 3, and 4 to mitigate 

the effects of inadvertent actuation of the Containment Spray System or 

Containment Cooling System. 

In MODES 5 and 6, the probability and consequences of a DBA are 

reduced due to the pressure and temperature limitations of these 

MODES. The Containment Spray System and Containment Cooling 

System are not required to be OPERABLE in MODES 5 and 6. 

Therefore, maintaining OPERABLE vacuum relief lines is not required in 

MODE 5 or 6. 

ACTIONS A.1

With one of the required vacuum relief lines inoperable, the inoperable 

line must be restored to OPERABLE status within 72 hours. The 

specified time period is consistent with other LCOs for the loss of one 

train of a system required to mitigate the consequences of a LOCA or 

other DBA. 
Vacuum Relief Valves (Dual) 

B 3.6.12 

CEOG STS B 3.6.12-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1 and B.2

If the vacuum relief line cannot be restored to OPERABLE status within 

the required Completion Time, the plant must be brought to a MODE in 

which the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 5 within 

36 hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE SR 3.6.12.1

REQUIREMENTS 

This SR references the Inservice Testing Program, which establishes the 

requirement that inservice testing of the ASME Code Class 1, 2, and 3 

pumps and valves shall be performed in accordance with Section XI of 

the ASME Boiler and Pressure Vessel Code and applicable Addenda 

(Ref. 2). Therefore, SR Frequency is governed by the Inservice Testing 

Program. 

REFERENCES 1. FSAR, Section [6.2]. 

 2. ASME, Boiler and Pressure Vessel Code, Section XI. 
SBEACS (Dual) 

B 3.6.8 

CEOG STS B 3.6.8-1 Rev. 3.0, 03/31/04 

B 3.6 CONTAINMENT SYSTEMS 

B 3.6.8 Shield Building Exhaust Air Cleanup System (SBEACS) (Dual) 

BASES 

BACKGROUND The SBEACS is required by 10 CFR 50, Appendix A, GDC 41, 

"Containment Atmosphere Cleanup" (Ref. 1), to ensure that radioactive 

material leaking from the primary containment of a dual containment into 

the shield building (secondary containment) following a Design Basis 

Accident are filtered and adsorbed prior to exhausting to the environment. 

The containment has a secondary containment, the shield building, which 

is a concrete structure that surrounds the steel primary containment 

vessel. Between the containment vessel and the shield building inner 

wall is an annular space that collects any containment leakage that may 

occur following a loss of coolant accident (LOCA). This space also allows 

for periodic inspection of the outer surface of the steel containment 

vessel. 

Following a LOCA, the SBEACS establishes a negative pressure in the 

annulus between the shield building and the steel containment vessel. 

Filters in the system then control the release of radioactive contaminants 

to the environment. Shield building OPERABILITY is required to ensure 

retention of primary containment leakage and proper operation of the 

SBEACS. 

The SBEACS consists of two separate and redundant trains. Each train 

includes a heater, cooling coils, a prefilter, a moisture separator, a high 

efficiency particulate air (HEPA) filter, an activated charcoal adsorber 

section for removal of radioiodines, and a fan. Ductwork, valves and/or 

dampers, and instrumentation also form part of the system. The moisture 

separators function to reduce the moisture content of the airstream. A 

second bank of HEPA filters follows the adsorber section to collect carbon 

fines and provide backup in case of failure of the main HEPA filter bank. 

Only the upstream HEPA filter and the charcoal adsorber section are 

credited in the analysis. The system initiates and maintains a negative air 

pressure in the shield building by means of filtered exhaust ventilation of 

the shield building following receipt of a safety injection actuation signal 

(SIAS). The system is described in Reference 2. 

The prefilters remove any large particles in the air, and the moisture 

separators remove any entrained water droplets present, to prevent 

excessive loading of the HEPA filters and charcoal adsorbers. Heaters 

may be included to reduce the relative humidity of the airstream on 
SBEACS (Dual) 

B 3.6.8 

CEOG STS B 3.6.8-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

systems operating in high humidity. Continuous operation of each train 

for at least 10 hours per month with heaters on reduces moisture buildup 

on the HEPA filters and adsorbers. [The cooling coils cool the air to keep 

the charcoal beds from becoming too hot due to absorption of fission 

products.] 

During normal operation, the Shield Building Cooling System is aligned to 

bypass the SBEACS HEPA filters and charcoal adsorbers. For SBEACS 

operation following a DBA, however, the bypass dampers automatically 

reposition to draw the air through the filters and adsorbers. 

The SBEACS reduces the radioactive content in the shield building 

atmosphere following a DBA. Loss of the SBEACS could cause site 

boundary doses, in the event of a DBA, to exceed the values given in the 

licensing basis. 

APPLICABLE The SBEACS design basis is established by the consequences of the 

SAFETY limiting DBA, which is a LOCA. The accident analysis (Ref. 3) assumes 

ANALYSES that only one train of the SBEACS is functional due to a single failure that 

disables the other train. The accident analysis accounts for the reduction 

in airborne radioactive material provided by the remaining one train of this 

filtration system. The amount of fission products available for release 

from containment is determined for a LOCA. 

The modeled SBEACS actuation in the safety analysis is based on a 

worst case response time associated with exceeding an SIAS. The total 

response time from exceeding the signal setpoint to attaining the negative 

pressure of [≥ 0.25] inch water gauge in the shield building is [1 minute]. 

This response time is composed of signal delay, diesel generator startup 

and sequencing time, system startup time, and time for the system to 

attain the required pressure after starting. 

The SBEACS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO In the event of a DBA, one SBEACS train is required to provide the 

minimum particulate iodine removal assumed in the safety analysis. Two 

trains of the SBEACS must be OPERABLE to ensure that at least one 

train will operate, assuming that the other train is disabled by a single 

active failure. 
SBEACS (Dual) 

B 3.6.8 

CEOG STS B 3.6.8-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could lead to fission product release to 

containment that leaks to the shield building. The large break LOCA, on 

which this system's design is based, is a full power event. Less severe 

LOCAs and leakage still require the system to be OPERABLE throughout 

these MODES. The probability and severity of a LOCA decrease as core 

power and Reactor Coolant System pressure decrease. With the reactor 

shut down, the probability of release of radioactivity resulting from such 

an accident is low. 

In MODES 5 and 6, the probability and consequences of a DBA are low 

due to the pressure and temperature limitations in these MODES. Under 

these conditions, the Filtration System is not required to be OPERABLE. 

ACTIONS A.1

With one SBEACS train inoperable, the inoperable train must be restored 

to OPERABLE status within 7 days. The components in this degraded 

condition are capable of providing 100% of the iodine removal needs after 

a DBA. The 7 day Completion Time is based on consideration of such 

factors as the availability of the OPERABLE redundant SBEACS train and 

the low probability of a DBA occurring during this period. 

B.1 and B.2

If the SBEACS train cannot be restored to OPERABLE status within the 

required Completion Time, the plant must be brought to a MODE in which 

the LCO does not apply. To achieve this status, the plant must be 

brought to at least MODE 3 within 6 hours and to MODE 5 within 

36 hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required plant conditions from full 

power conditions in an orderly manner and without challenging plant 

systems. 

SURVEILLANCE SR 3.6.8.1

REQUIREMENTS 

Operating each SBEACS train for ≥ 15 minutes ensures that all trains are 

OPERABLE and that all associated controls are functioning properly. It 

also ensures that blockage, fan or motor failure, or excessive vibration 

can be detected for corrective action. For systems with heaters, 

operation with the heaters on (automatic heater cycling to maintain 

temperature) for ≥ 10 continuous hours eliminates moisture on the 

adsorbers and HEPA filters. Experience from filter testing at operating 

units indicates that the 10 hour period is adequate for moisture 
SBEACS (Dual) 

B 3.6.8 

CEOG STS B 3.6.8-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

elimination on the adsorbers and HEPA filters. The 31 day Frequency 

was developed considering the known reliability of fan motors and 

controls, the two train redundancy available, and the iodine removal 

capability of the Containment Spray System. 

SR 3.6.8.2

This SR verifies that the required SBEACS filter testing is performed in 

accordance with the Ventilation Filter Testing Program (VFTP). The 

VFTP includes testing of HEPA filter performance, charcoal adsorber 

efficiency, minimum system flow rate, and the physical properties of the 

activated charcoal (general use and following specific operations). 

Specific test frequencies and additional information are discussed in 

detail in the VFTP. 

SR 3.6.8.3

The automatic startup ensures that each SBEACS train responds 

properly. 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. Operating experience has shown that these 

components usually pass the Surveillance when performed at the 

[18] month Frequency. Therefore, the Frequency was concluded to be 

acceptable from a reliability standpoint. Furthermore, the SR interval was 

developed considering that the SBEACS equipment OPERABILITY is 

demonstrated at a 31 day Frequency by SR 3.6.8.1. 

[ SR 3.6.8.4

The filter bypass dampers are tested to verify OPERABILITY. The 

dampers are in the bypass position during normal operation and must 

reposition for accident operation to draw air through the filters. The 

[18] month Frequency is considered to be acceptable based on the 

damper reliability and design, the mild environmental conditions in the 

vicinity of the dampers, and the fact that operating experience has shown 

that the dampers usually pass the Surveillance when performed at the 

[18] month Frequency. ]
SBEACS (Dual) 

B 3.6.8 

CEOG STS B 3.6.8-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.6.8.5

The SBEACS train flow rate is verified ≥ [ ] cfm to ensure that the flow 

rate is adequate to "pull down" the shield building pressure as required. 

This test also will verify the proper functioning of the fans, dampers, 

filters, absorbers, etc., when this SR is performed in conjunction with 

SR 3.6.11.4. 

The [18] month on a STAGGERED TEST BASIS Frequency is consistent 

with the Regulatory Guide 1.52 (Ref. 4) guidance. 

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

 2. FSAR, Section [ ]. 

 3. FSAR, Section [ ]. 

 4. Regulatory Guide 1.52, Revision [2]. 
MSSVs 

B 3.7.1 

CEOG STS B 3.7.1-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.1 Main Steam Safety Valves (MSSVs) 

BASES 

BACKGROUND The primary purpose of the MSSVs is to provide overpressure protection 

for the secondary system. The MSSVs also provide protection against 

overpressurizing the reactor coolant pressure boundary (RCPB) by 

providing a heat sink for the removal of energy from the Reactor Coolant 

System (RCS) if the preferred heat sink, provided by the Condenser and 

Circulating Water System, is not available. 

Eight MSSVs are located on each main steam header, outside 

containment, upstream of the main steam isolation valves, as described 

in the FSAR, Section [5.2] (Ref. 1). The MSSV rated capacity passes the 

full steam flow at 102% RTP (100% + 2% for instrument error) with the 

valves full open. This meets the requirements of the ASME Code, 

Section III (Ref. 2). The MSSV design includes staggered setpoints, 

according to Table 3.7.1-1, in the accompanying LCO, so that only the 

number of valves needed will actuate. Staggered setpoints reduce the 

potential for valve chattering because of insufficient steam pressure to 

fully open all valves following a turbine reactor trip. 

APPLICABLE The design basis for the MSSVs comes from Reference 2. The MSSV's 

SAFETY purpose is to limit secondary system pressure to ≤ 110% of design 

ANALYSES pressure when passing 100% of design steam flow. This design basis is 

sufficient to cope with any anticipated operational occurrence (AOO) or 

accident considered in the Design Basis Accident (DBA) and transient 

analysis. 

The events that challenge the MSSV relieving capacity, and thus RCS 

pressure, are those characterized as decreased heat removal events, and 

are presented in the FSAR, Section [15.2] (Ref. 3). Of these, the full 

power loss of condenser vacuum (LOCV) event is the limiting AOO. An 

LOCV isolates the turbine and condenser, and terminates normal 

feedwater flow to the steam generators. Before delivery of auxiliary 

feedwater to the steam generators, RCS pressure reaches ≤ 2630 psig. 

This peak pressure is < 110% of the design pressure of 2500 psig, but 

high enough to actuate the pressurizer safety valves. The maximum 

relieving rate during the LOCV event is 2.5 E6 lb/hour, which is less than 

the rated capacity of two MSSVs. 
MSSVs 

B 3.7.1 

CEOG STS B 3.7.1-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The limiting accident for peak RCS pressure is the full power feedwater 

line break (FWLB), inside containment, with the failure of the backflow 

check valve in the feedwater line from the affected steam generator. 

Water from the affected steam generator is assumed to be lost through 

the break with minimal additional heat transfer from the RCS. With heat 

removal limited to the unaffected steam generator, the reduced heat 

transfer causes an increase in RCS temperature, and the resulting RCS 

fluid expansion causes an increase in pressure. The RCS pressure 

increases to ≤ 2730 psig, with the pressurizer safety valves providing 

relief capacity. The maximum relieving rate of the MSSVs during the 

FWLB event is ≤ 2.5 E6 lb/hour, which is less than the rated capacity of 

two MSSVs. 

Using conservative analysis assumptions, a small range of FWLB sizes 

less than a full double ended guillotine break produce an RCS pressure of 

2765 psig for a period of 20 seconds; exceeding 110% (2750 psig) of 

design pressure. This is considered acceptable as RCS pressure is still 

well below 120% of design pressure where deformation may occur. The 

probability of this event is in the range of 4 E-6/year. 

The MSSVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO This LCO requires all MSSVs to be OPERABLE in compliance with 

Reference 2, even though this is not a requirement of the DBA analysis. 

This is because operation with less than the full number of MSSVs 

requires limitations on allowable THERMAL POWER (to meet 

Reference 2 requirements), and adjustment to the Reactor Protection 

System trip setpoints. These limitations are according to those shown in 

Table 3.7.1-1, Required Action A.1, and Required Action A.2 in the 

accompanying LCO. An MSSV is considered inoperable if it fails to open 

upon demand. 

The OPERABILITY of the MSSVs is defined as the ability to open within 

the setpoint tolerances, relieve steam generator overpressure, and reseat 

when pressure has been reduced. The OPERABILITY of the MSSVs is 

determined by periodic surveillance testing in accordance with the 

Inservice Testing Program. 

The lift settings, according to Table 3.7.1-2 in the accompanying LCO, 

correspond to ambient conditions of the valve at nominal operating 

temperature and pressure. 

This LCO provides assurance that the MSSVs will perform their designed 

safety function to mitigate the consequences of accidents that could result 

in a challenge to the RCPB. 
MSSVs 

B 3.7.1 

CEOG STS B 3.7.1-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODE 1, a minimum of two MSSVs per steam generator are required 

to be OPERABLE, according to Table 3.7.1-1 in the accompanying LCO, 

which is limiting and bounds all lower MODES. In MODES 2 and 3, both 

the ASME Code and the accident analysis require only one MSSV per 

steam generator to provide overpressure protection. 

In MODES 4 and 5, there are no credible transients requiring the MSSVs. 

The steam generators are not normally used for heat removal in 

MODES 5 and 6, and thus cannot be overpressurized; there is no 

requirement for the MSSVs to be OPERABLE in these MODES. 

ACTIONS The ACTIONS Table is modified by a Note indicating that separate 

Condition entry is allowed for each MSSV. 

A.1 and A.2

An alternative to restoring the inoperable MSSV(s) to OPERABLE status 

is to reduce power so that the available MSSV relieving capacity meets 

Code requirements for the power level. Operation may continue provided 

the allowable THERMAL POWER is equal to the product of: 1) the ratio 

of the number of MSSVs available per steam generator to the total 

number of MSSVs per steam generator, and 2) the ratio of the available 

relieving capacity to total steam flow, multiplied by 100%. 

Allowable THERMAL POWER = (8 - N) x 109.2 

 8 

With one or more MSSVs inoperable, the ceiling on the variable 

overpower trip is reduced to an amount over the allowable THERMAL 

POWER equal to the band given for this trip, according to Table 3.7.1-1 in 

the accompanying LCO. 

SP = Allowable THERMAL POWER + 9.8 

where: 

SP = Reduced reactor trip setpoint in percent RTP. This is a 

ratio of the available relieving capacity over the total steam 

flow at rated power. 

8 = Total number of MSSVs per steam generator. 

N = Number of inoperable MSSVs on the steam generator with 

the greatest number of inoperable valves. 
MSSVs 

B 3.7.1 

CEOG STS B 3.7.1-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

109.2 = Ratio of MSSV relieving capacity at 110% steam generator 

design pressure to calculated steam flow rate at 

100% RTP + 2% instrument uncertainty expressed as a 

percentage (see text above). 

9.8 = Band between the maximum THERMAL POWER and the 

variable overpower trip setpoint ceiling (Table 3.7.1-1). 

The operator should limit the maximum steady state power level to some 

value slightly below this setpoint to avoid an inadvertent overpower trip. 

The 4 hour Completion Time for Required Action A.1 is a reasonable time 

period to reduce power level and is based on the low probability of an 

event occurring during this period that would require activation of the 

MSSVs. An additional 32 hours is allowed in Required Action A.2 to 

reduce the setpoints. The Completion Time of 36 hours for Required 

Action A.2 is based on a reasonable time to correct the MSSV 

inoperability, the time required to perform the power reduction, operating 

experience in resetting all channels of a protective function, and on the 

low probability of the occurrence of a transient that could result in steam 

generator overpressure during this period. 

B.1 and B.2

If the MSSVs cannot be restored to OPERABLE status in the associated 

Completion Time, or if one or more steam generators have less than two 

MSSVs OPERABLE, the unit must be placed in a MODE in which the 

LCO does not apply. To achieve this status, the unit must be placed in at 

least MODE 3 within 6 hours, and in MODE 4 within [12] hours. The 

allowed Completion Times are reasonable, based on operating 

experience, to reach the required unit conditions from full power 

conditions in an orderly manner and without challenging unit systems. 

SURVEILLANCE SR 3.7.1.1

REQUIREMENTS 

This SR verifies the OPERABILITY of the MSSVs by the verification of 

each MSSV lift setpoints in accordance with the Inservice Testing 

Program. The ASME Code, Section XI (Ref. 4), requires that safety and 

relief valve tests be performed in accordance with ANSI/ASME 

OM-1-1987 (Ref. 5). According to Reference 5, the following tests are 

required for MSSVs: 
MSSVs 

B 3.7.1 

CEOG STS B 3.7.1-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

a. Visual examination, 

b. Seat tightness determination, 

c. Setpoint pressure determination (lift setting), 

d. Compliance with owner's seat tightness criteria, and 

e. Verification of the balancing device integrity on balanced valves. 

The ANSI/ASME Standard requires that all valves be tested every 

5 years, and a minimum of 20% of the valves be tested every 24 months. 

The ASME Code specifies the activities and frequencies necessary to 

satisfy the requirements. Table 3.7.1-2 allows a + [3]% setpoint tolerance 

for OPERABILITY; however, the valves are reset to + 1% during the 

Surveillance to allow for drift. 

This SR is modified by a Note that allows entry into and operation in 

MODE 3 prior to performing the SR. This is to allow testing of the MSSVs 

at hot conditions. The MSSVs may be either bench tested or tested in 

situ at hot conditions using an assist device to simulate lift pressure. If 

the MSSVs are not tested at hot conditions, the lift setting pressure shall 

be corrected to ambient conditions of the valve at operating temperature 

and pressure. 

REFERENCES 1. FSAR, Section [5.2]. 

 2. ASME, Boiler and Pressure Vessel Code, Section III, Article 

NC-7000, Class 2 Components. 

 3. FSAR, Section [15.2]. 

 4. ASME, Boiler and Pressure Vessel Code, Section XI, Article 

IWV-3500. 

 5. ANSI/ASME OM-1-1987. 
MSIVs 

B 3.7.2 

CEOG STS B 3.7.2-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.2 Main Steam Isolation Valves (MSIVs) 

BASES 

BACKGROUND The MSIVs isolate steam flow from the secondary side of the steam 

generators following a high energy line break (HELB). MSIV closure 

terminates flow from the unaffected (intact) steam generator. 

One MSIV is located in each main steam line outside, but close to, 

containment. The MSIVs are downstream from the main steam safety 

valves (MSSVs), atmospheric dump valves, and auxiliary feedwater pump 

turbine steam supplies to prevent their being isolated from the steam 

generators by MSIV closure. Closing the MSIVs isolates each steam 

generator from the other, and isolates the turbine, Steam Bypass System, 

and other auxiliary steam supplies from the steam generators. 

The MSIVs close on a main steam isolation signal generated by either 

low steam generator pressure or high containment pressure. The MSIVs 

fail closed on loss of control or actuation power. The MSIS also actuates 

the main feedwater isolation valves (MFIVs) to close. The MSIVs may 

also be actuated manually. 

A description of the MSIVs is found in the FSAR, Section [10.3] (Ref. 1). 

APPLICABLE The design basis of the MSIVs is established by the containment analysis 

SAFETY for the large steam line break (SLB) inside containment, as discussed in 

ANALYSES the FSAR, Section [6.2] (Ref. 2). It is also influenced by the accident 

analysis of the SLB events presented in the FSAR, Section [15.1.5] 

(Ref. 3). The design precludes the blowdown of more than one steam 

generator, assuming a single active component failure (e.g., the failure of 

one MSIV to close on demand). 

The limiting case for the containment analysis is the hot zero power SLB 

inside containment with a loss of offsite power following turbine trip, and 

failure of the MSIV on the affected steam generator to close. At zero 

power, the steam generator inventory and temperature are at their 

maximum, maximizing the analyzed mass and energy release to the 

containment. Due to reverse flow, failure of the MSIV to close contributes 

to the total release of the additional mass and energy in the steam 

headers, which are downstream of the other MSIV. With the most 

reactive rod cluster control assembly assumed stuck in the fully 
MSIVs 

B 3.7.2 

CEOG STS B 3.7.2-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

withdrawn position, there is an increased possibility that the core will 

become critical and return to power. The core is ultimately shut down by 

the borated water injection delivered by the Emergency Core Cooling 

System. Other failures considered are the failure of an MFIV to close, 

and failure of an emergency diesel generator to start. 

The accident analysis compares several different SLB events against 

different acceptance criteria. The large SLB outside containment 

upstream of the MSIV is limiting for offsite dose, although a break in this 

short section of main steam header has a very low probability. The large 

SLB inside containment at hot zero power is the limiting case for a post 

trip return to power. The analysis includes scenarios with offsite power 

available and with a loss of offsite power following turbine trip. 

With offsite power available, the reactor coolant pumps continue to 

circulate coolant through the steam generators, maximizing the Reactor 

Coolant System (RCS) cooldown. With a loss of offsite power, the 

response of mitigating systems, such as the high pressure safety injection 

(HPSI) pumps, is delayed. Significant single failures considered include: 

failure of a MSIV to close, failure of an emergency diesel generator, and 

failure of a HPSI pump. 

The MSIVs serve only a safety function and remain open during power 

operation. These valves operate under the following situations: 

a. An HELB inside containment. In order to maximize the mass and 

energy release into the containment, the analysis assumes that the 

MSIV in the affected steam generator remains open. For this 

accident scenario, steam is discharged into containment from both 

steam generators until closure of the MSIV in the intact steam 

generator occurs. After MSIV closure, steam is discharged into 

containment only from the affected steam generator, and from the 

residual steam in the main steam header downstream of the closed 

MSIV in the intact loop. 

b. A break outside of containment and upstream from the MSIVs. This 

scenario is not a containment pressurization concern. The 

uncontrolled blowdown of more than one steam generator must be 

prevented to limit the potential for uncontrolled RCS cooldown and 

positive reactivity addition. Closure of the MSIVs isolates the break, 

and limits the blowdown to a single steam generator. 
MSIVs 

B 3.7.2 

CEOG STS B 3.7.2-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

c. A break downstream of the MSIVs. This type of break will be isolated 

by the closure of the MSIVs. Events such as increased steam flow 

through the turbine or the steam bypass valves will also terminate on 

closure of the MSIVs. 

d. A steam generator tube rupture. For this scenario, closure of the 

MSIV[s] isolates the affected steam generator from the intact steam 

generator. In addition to minimizing radiological releases, this 

enables the operator to maintain the pressure of the steam generator 

with the ruptured tube below the MSSV setpoints, a necessary step 

toward isolating the flow through the rupture. 

e. The MSIVs are also utilized during other events such as a feedwater 

line break. These events are less limiting so far as MSIV 

OPERABILITY is concerned. 

The MSIVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO This LCO requires that the MSIV in each of the [two] steam lines be 

OPERABLE. The MSIVs are considered OPERABLE when the isolation 

times are within limits, and they close on an isolation actuation signal. 

This LCO provides assurance that the MSIVs will perform their design 

safety function to mitigate the consequences of accidents that could result 

in offsite exposures comparable to the 10 CFR 100 (Ref. 4) limits or the 

NRC staff approved licensing basis. 

APPLICABILITY The MSIVs must be OPERABLE in MODE 1 and in MODES 2 and 3 

except when all MSIVs are closed and [deactivated]. In these MODES 

there is significant mass and energy in the RCS and steam generators. 

When the MSIVs are closed, they are already performing their safety 

function. 

In MODE 4, the steam generator energy is low; therefore, the MSIVs are 

not required to be OPERABLE. 

In MODES 5 and 6, the steam generators do not contain much energy 

because their temperature is below the boiling point of water; therefore, 

the MSIVs are not required for isolation of potential high energy 

secondary system pipe breaks in these MODES. 
MSIVs 

B 3.7.2 

CEOG STS B 3.7.2-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

With one MSIV inoperable in MODE 1, time is allowed to restore the 

component to OPERABLE status. Some repairs can be made to the 

MSIV with the unit hot. The [8] hour Completion Time is reasonable, 

considering the probability of an accident occurring during the time period 

that would require closure of the MSIVs. 

The [8] hour Completion Time is greater than that normally allowed for 

containment isolation valves because the MSIVs are valves that isolate a 

closed system penetrating containment. These valves differ from other 

containment isolation valves in that the closed system provides an 

additional means for containment isolation. 

B.1

If the MSIV cannot be restored to OPERABLE status within [8] hours, the 

unit must be placed in a MODE in which the LCO does not apply. To 

achieve this status, the unit must be placed in MODE 2 within 6 hours and 

Condition C would be entered. The Completion Time is reasonable, 

based on operating experience, to reach MODE 2, and close the MSIVs 

in an orderly manner and without challenging unit systems. 

C.1, C.2.1, and C.2.2

Condition C is modified by a Note indicating that separate Condition entry 

is allowed for each MSIV. 

Since the MSIVs are required to be OPERABLE in MODES 2 and 3, the 

inoperable MSIVs may either be restored to OPERABLE status or closed. 

When closed, the MSIVs are already in the position required by the 

assumptions in the safety analysis. 

The [8] hour Completion Time is consistent with that allowed in 

Condition A. 

Inoperable MSIVs that cannot be restored to OPERABLE status within 

the specified Completion Time, but are closed, must be verified on a 

periodic basis to be closed. This is necessary to ensure that the 

assumptions in the safety analysis remain valid. The 7 day Completion 

Time is reasonable, based on engineering judgment, MSIV status 

indications available in the control room, and other administrative 

controls, to ensure these valves are in the closed position. 
MSIVs 

B 3.7.2 

CEOG STS B 3.7.2-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

D.1 and D.2

If the MSIVs cannot be restored to OPERABLE status, or closed, within 

the associated Completion Time, the unit must be placed in a MODE in 

which the LCO does not apply. To achieve this status, the unit must be 

placed in at least MODE 3 within 6 hours, and in MODE 4 within 

[12] hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required unit conditions from MODE 2 

conditions in an orderly manner and without challenging unit systems. 

SURVEILLANCE SR 3.7.2.1

REQUIREMENTS 

This SR verifies that the closure time of each MSIV is ≤ [4.6] seconds. 

The MSIV isolation time is assumed in the accident and containment 

analyses. This SR is normally performed upon returning the unit to 

operation following a refueling outage. The MSIVs should not be tested 

at power since even a part stroke exercise increases the risk of a valve 

closure with the unit generating power. As the MSIVs are not tested at 

power, they are exempt from the ASME Code, Section XI (Ref. 5), 

requirements during operation in MODES 1 and 2. 

The Frequency for this SR is in accordance with the Inservice Testing 

Program. 

This test is conducted in MODE 3, with the unit at operating temperature 

and pressure. This SR is modified by a Note that allows entry into and 

operation in MODE 3 prior to performing the SR. This allows a delay of 

testing until MODE 3, in order to establish conditions consistent with 

those under which the acceptance criterion was generated. 

SR 3.7.2.2

This SR verifies that each MSIV can close on an actual or simulated 

actuation signal. This Surveillance is normally performed upon returning 

the plant to operation following a refueling outage. The Frequency of 

MSIV testing is every [18] months. 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. 
MSIVs 

B 3.7.2 

CEOG STS B 3.7.2-6 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Section [10.3]. 

 2. FSAR, Section [6.2]. 

 3. FSAR, Section [15.1.5]. 

 4. 10 CFR 100.11. 

 5. ASME, Boiler and Pressure Vessel Code, Section XI, Inservice 

Inspection, Article IWV-3400. 
MFIVs [and [MFIV] Bypass Valves] 

B 3.7.3 

CEOG STS B 3.7.3-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.3 Main Feedwater Isolation Valves (MFIVs) [and [MFIV] Bypass Valves] 

BASES 

BACKGROUND The MFIVs isolate main feedwater (MFW) flow to the secondary side of 

the steam generators following a high energy line break (HELB). Closure 

of the MFIVs and the bypass valves terminates flow to both steam 

generators, terminating the event for feedwater line breaks (FWLBs) 

occurring upstream of the MFIVs. The consequences of events occurring 

in the main steam lines or in the MFW lines downstream of the MFIVs will 

be mitigated by their closure. Closure of the MFIVs and bypass valves 

effectively terminates the addition of feedwater to an affected steam 

generator, limiting the mass and energy release for steam line breaks 

(SLBs) or FWLBs inside containment, and reducing the cooldown effects 

for SLBs. 

The MFIVs and bypass valves isolate the nonsafety related portions from 

the safety related portion of the system. In the event of a secondary side 

pipe rupture inside containment, the valves limit the quantity of high 

energy fluid that enters containment through the break, and provide a 

pressure boundary for the controlled addition of auxiliary feedwater 

(AFW) to the intact loop. 

One MFIV is located on each AFW line, outside, but close to, 

containment. The MFIVs are located upstream of the AFW injection point 

so that AFW may be supplied to a steam generator following MFIV 

closure. The piping volume from the valve to the steam generator must 

be accounted for in calculating mass and energy releases, and refilled 

prior to AFW reaching the steam generator following either an SLB or 

FWLB. 

The MFIVs and its bypass valves close on receipt of a main steam 

isolation signal (MSIS) generated by either low steam generator pressure 

or high containment pressure. The MSIS also actuates the main steam 

isolation valves (MSIVs) to close. The MFIVs and bypass valves may 

also be actuated manually. In addition to the MFIVs and the bypass 

valves, a check valve inside containment is available to isolate the 

feedwater line penetrating containment, and to ensure that the 

consequences of events do not exceed the capacity of the containment 

heat removal systems. 

A description of the MFIVs is found in the FSAR, Section [10.4.7] (Ref. 1). 
MFIVs [and [MFIV] Bypass Valves] 

B 3.7.3 

CEOG STS B 3.7.3-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The design basis of the MFIVs is established by the analysis for the large 

SAFETY SLB. It is also influenced by the accident analysis for the large FWLB. 

ANALYSES Closure of the MFIVs and their bypass valves may also be relied on to 

terminate a steam break for core response analysis and an excess 

feedwater flow event upon receipt of a MSIS on high steam generator 

level. 

Failure of an MFIV and the bypass valve to close following an SLB, 

FWLB, or excess feedwater flow event can result in additional mass and 

energy to the steam generators contributing to cooldown. This failure 

also results in additional mass and energy releases following an SLB or 

FWLB event. 

The MFIVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO This LCO ensures that the MFIVs and the bypass valves will isolate MFW 

flow to the steam generators. Following an FWLB or SLB, these valves 

will also isolate the nonsafety related portions from the safety related 

portions of the system. This LCO requires that [two] MFIVs [and [MFIV] 

bypass valves] in each feedwater line be OPERABLE. The MFIVs and 

the bypass valves are considered OPERABLE when the isolation times 

are within limits, and are closed on an isolation actuation signal. 

Failure to meet the LCO requirements can result in additional mass and 

energy being released to containment following an SLB or FWLB inside 

containment. If an MSIS on high steam generator level is relied on to 

terminate an excess feedwater flow event, failure to meet the LCO may 

result in the introduction of water into the main steam lines. 

APPLICABILITY The MFIVs and the bypass valves must be OPERABLE whenever there 

is significant mass and energy in the Reactor Coolant System and steam 

generators. This ensures that, in the event of an HELB, a single failure 

cannot result in the blowdown of more than one steam generator. 

In MODES 1, 2, and 3, the MFIV [or [MFIV] bypass valves] are required to 

be OPERABLE, except when they are closed and deactivated or isolated 

by a closed manual valve, in order to limit the amount of available fluid 

that could be added to containment in the case of a secondary system 

pipe break inside containment. When the valves are closed and 

deactivated or isolated by a closed manual valve, they are already 

performing their safety function. 

In MODES 4, 5, and 6, steam generator energy is low. Therefore, the 

MFIVs and the bypass valves are normally closed since MFW is not 

required. 
MFIVs [and [MFIV] Bypass Valves] 

B 3.7.3 

CEOG STS B 3.7.3-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS The ACTIONS Table is modified by a Note indicating that separate 

Condition entry is allowed for each value. 

A.1 and A.2

With one MFIV or the bypass valve inoperable, action must be taken to 

close or isolate the inoperable valves within [8 or 72] hours. When these 

valves are closed or isolated, they are performing their required safety 

function (e.g., to isolate the line). 

For units with only one MFIV per feedwater line: The [8] hour Completion 

Time is reasonable to close the MFIV or its bypass valve, which includes 

performing a controlled unit shutdown to MODE 2. 

The [72] hour Completion Time takes into account the redundancy 

afforded by the remaining OPERABLE valves, and the low probability of 

an event occurring during this time period that would require isolation of 

the MFW flow paths. 

B.1

If more than one MFIV or [MFIV] bypass valve in the same flow path 

cannot be restored to OPERABLE status, then there may be no 

redundant system to operate automatically and perform the required 

safety function. Although the containment can be isolated with the failure 

of two valves in parallel in the same flow path, the double failure can be 

an indication of a common mode failure in the valves of this flow path, 

and as such is treated the same as a loss of the isolation capability of this 

flow path. Under these conditions, valves in each flow path must be 

restored to OPERABLE status, closed, or the flow path isolated within 

8 hours. This action returns the system to the condition where at least 

one valve in each flow path is performing the required safety function. 

The 8 hour Completion Time is reasonable to close the MFIV or its 

bypass valve, or otherwise isolate the affected flow path. 

Inoperable MFIVs and [MFIV] bypass valves that cannot be restored to 

OPERABLE status within the Completion Time, but are closed or isolated, 

must be verified on a periodic basis that they are closed or isolated. This 

is necessary to ensure that the assumptions in the safety analysis remain 

valid. The 7 day Completion Time is reasonable, based on engineering 

judgment, in view of valve status indications available in the control room, 

and other administrative controls to ensure that these valves are closed 

or isolated. 
MFIVs [and [MFIV] Bypass Valves] 

B 3.7.3 

CEOG STS B 3.7.3-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1 and [C.2]

If the MFIVs and their bypass valves cannot be restored to OPERABLE 

status, closed, or isolated in the associated Completion Time, the unit 

must be placed in a MODE in which the LCO does not apply. To achieve 

this status, the unit must be placed in at least MODE 3 within 6 hours[, 

and in MODE 4 within [12] hours]. The allowed Completion Times are 

reasonable, based on operating experience, to reach the required unit 

conditions from full power conditions in an orderly manner and without 

challenging unit systems. 

SURVEILLANCE SR 3.7.3.1

REQUIREMENTS 

This SR ensures the verification of each MFIV [and [MFIV] bypass valve] 

is ≤ [7] seconds. The MFIV isolation time is assumed in the accident and 

containment analyses. This Surveillance is normally performed upon 

returning the unit to operation following a refueling outage. The MFIVs 

should not be tested at power since even a part stroke exercise increases 

the risk of a valve closure with the unit generating power. As these 

valves are not tested at power, they are exempt from the ASME Code, 

Section XI (Ref. 2) requirements during operation in MODES 1 and 2. 

The Frequency is in accordance with the Inservice Testing Program. 

SR 3.7.3.2

This SR verifies that each MFIV [and [MFIV] bypass valve] can close on 

an actual or simulated actuation signal. This Surveillance is normally 

performed upon returning the plant to operation following a refueling 

outage. 

The Frequency for this SR is every [18] months. 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. 

REFERENCES 1. FSAR, Section [10.4.7]. 

 2. ASME, Boiler and Pressure Vessel Code, Section XI, Inservice 

Inspection, Article IWV-3400. 
ADVs 

B 3.7.4 

CEOG STS B 3.7.4-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.4 Atmospheric Dump Valves (ADVs) 

BASES 

BACKGROUND The ADVs provide a safety grade method for cooling the unit to Shutdown 

Cooling (SDC) System entry conditions, should the preferred heat sink via 

the Steam Bypass System to the condenser not be available, as 

discussed in the FSAR, Section [10.3] (Ref. 1). This is done in 

conjunction with the Auxiliary Feedwater System providing cooling water 

from the condensate storage tank (CST). The ADVs may also be 

required to meet the design cooldown rate during a normal cooldown 

when steam pressure drops too low for maintenance of a vacuum in the 

condenser to permit use of the Steam Bypass System. 

Four ADV lines are provided. Each ADV line consists of one ADV and an 

associated block valve. Two ADV lines per steam generator are required 

to meet single failure assumptions following an event rendering one 

steam generator unavailable for Reactor Coolant System (RCS) heat 

removal. 

The ADVs are provided with upstream block valves to permit their being 

tested at power, and to provide an alternate means of isolation. The 

ADVs are equipped with pneumatic controllers to permit control of the 

cooldown rate. 

The ADVs are usually provided with a pressurized gas supply of bottled 

nitrogen that, on a loss of pressure in the normal instrument air supply, 

automatically supplies nitrogen to operate the ADVs. The nitrogen supply 

is sized to provide sufficient pressurized gas to operate the ADVs for the 

time required for RCS cooldown to the SDC System entry conditions. 

A description of the ADVs is found in Reference 1. The ADVs are 

OPERABLE with only a DC power source available. In addition, hand 

wheels are provided for local manual operation. 

APPLICABLE The design basis of the ADVs is established by the capability to cool the 

SAFETY unit to SDC System entry conditions. A cooldown rate of 75°F per hour 

ANALYSES is obtainable by one or both steam generators. This design is adequate 

to cool the unit to SDC System entry conditions with only one ADV and 

one steam generator, utilizing the cooling water supply available in the 

CST. 
ADVs 

B 3.7.4 

CEOG STS B 3.7.4-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

In the accident analysis presented in the FSAR, the ADVs are assumed 

to be used by the operator to cool down the unit to SDC System entry 

conditions for accidents accompanied by a loss of offsite power. Prior to 

the operator action, the main steam safety valves (MSSVs) are used to 

maintain steam generator pressure and temperature at the MSSV 

setpoint. This is typically 30 minutes following the initiation of an event. 

(This may be less for a steam generator tube rupture (SGTR) event.) The 

limiting events are those that render one steam generator unavailable for 

RCS heat removal, with a coincident loss of offsite power; this results 

from a turbine trip and the single failure of one ADV on the unaffected 

steam generator. Typical initiating events falling into this category are a 

main steam line break upstream of the main steam isolation valves, a 

feedwater line break, and an SGTR event (although the ADVs on the 

affected steam generator may still be available following a SGTR event). 

The design must accommodate the single failure of one ADV to open on 

demand; thus, each steam generator must have at least two ADVs. The 

ADVs are equipped with block valves in the event an ADV spuriously 

opens, or fails to close during use. 

The ADVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO [Two] ADV lines are required to be OPERABLE on each steam generator 

to ensure that at least one ADV is OPERABLE to conduct a unit cooldown 

following an event in which one steam generator becomes unavailable, 

accompanied by a single active failure of one ADV line on the unaffected 

steam generator. The block valves must be OPERABLE to isolate a 

failed open ADV. A closed block valve does not render it or its ADV line 

inoperable if operator action time to open the block valve is supported in 

the accident analysis. 

Failure to meet the LCO can result in the inability to cool the unit to SDC 

System entry conditions following an event in which the condenser is 

unavailable for use with the Steam Bypass System. 

An ADV is considered OPERABLE when it is capable of providing a 

controlled relief of the main steam flow, and is capable of fully opening 

and closing on demand. 
ADVs 

B 3.7.4 

CEOG STS B 3.7.4-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODES 1, 2, and 3, [and in MODE 4, when steam generator is being 

relied upon for heat removal,] the ADVs are required to be OPERABLE. 

In MODES 5 and 6, an SGTR is not a credible event. 

ACTIONS A.1

With one required ADV line inoperable, action must be taken to restore 

the OPERABLE status within 7 days. The 7 day Completion Time takes 

into account the redundant capability afforded by the remaining 

OPERABLE ADV lines, and a nonsafety grade backup in the Steam 

Bypass System and MSSVs. 

B.1

With [two] or more [required] ADV lines inoperable, action must be taken 

to restore [one] of the ADV lines to OPERABLE status. As the block 

valve can be closed to isolate an ADV, some repairs may be possible with 

the unit at power. The 24 hour Completion Time is reasonable to repair 

inoperable ADV lines, based on the availability of the Steam Bypass 

System and MSSVs, and the low probability of an event occurring during 

this period that requires the ADV lines. 

C.1 and C.2

If the ADV lines cannot be restored to OPERABLE status within the 

associated Completion Time, the unit must be placed in a MODE in which 

the LCO does not apply. To achieve this status, the unit must be placed 

in at least MODE 3 within 6 hours, and in MODE 4, without reliance upon 

the steam generator for heat removal, within [24] hours. The allowed 

Completion Times are reasonable, based on operating experience, to 

reach the required unit conditions from full power conditions in an orderly 

manner and without challenging unit systems. 

SURVEILLANCE SR 3.7.4.1

REQUIREMENTS 

To perform a controlled cooldown of the RCS, the ADVs must be able to 

be opened and throttled through their full range. This SR ensures the 

ADVs are tested through a full control cycle at least once per fuel cycle. 

Performance of inservice testing or use of an ADV during a unit cooldown 

may satisfy this requirement. Operating experience has shown that these 

components usually pass the SR when performed at the [18] month 

Frequency. Therefore, the Frequency is acceptable from a reliability 

standpoint. 
ADVs 

B 3.7.4 

CEOG STS B 3.7.4-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

[ SR 3.7.4.2

The function of the ADV block valve is to isolate a failed open ADV. 

Cycling the block valve closed and open demonstrates its capability to 

perform this function. Performance of inservice testing or use of the block 

valve during unit cooldown may satisfy this requirement. Operating 

experience has shown that these components usually pass the SR when 

performed at the [18] month Frequency. Therefore, the Frequency is 

acceptable from a reliability standpoint. ] 

REFERENCES 1. FSAR, Section [10.3]. 
AFW System 

B 3.7.5 

CEOG STS B 3.7.5-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.5 Auxiliary Feedwater (AFW) System 

BASES 

BACKGROUND The AFW System automatically supplies feedwater to the steam 

generators to remove decay heat from the Reactor Coolant System upon 

the loss of normal feedwater supply. The AFW pumps take suction 

through separate and independent suction lines from the condensate 

storage tank (CST) (LCO 3.7.6, "Condensate Storage Tank (CST)") and 

pump to the steam generator secondary side via separate and 

independent connections to the main feedwater (MFW) piping outside 

containment. The steam generators function as a heat sink for core 

decay heat. The heat load is dissipated by releasing steam to the 

atmosphere from the steam generators via the main steam safety valves 

(MSSVs) (LCO 3.7.1, "Main Steam Safety Valves (MSSVs)") or 

atmospheric dump valves (ADVs) (LCO 3.7.4, "Atmospheric Dump Valves 

(ADVs)"). If the main condenser is available, steam may be released via 

the steam bypass valves and recirculated to the CST. 

The AFW System consists of [two] motor driven AFW pumps and one 

steam turbine driven pump configured into three trains. Each motor 

driven pump provides 100% of AFW flow capacity; the turbine driven 

pump provides 100% of the required capacity to the steam generators as 

assumed in the accident analysis. The pumps are equipped with 

independent recirculation lines to prevent pump operation against a 

closed system. 

Each motor driven AFW pump is powered from an independent Class 1E 

power supply, and feeds one steam generator, although each pump has 

the capability to be realigned from the control room to feed the other 

steam generator. 

One pump at full flow is sufficient to remove decay heat and cool the unit 

to Shutdown Cooling (SDC) System entry conditions. 

The steam turbine driven AFW pump receives steam from either main 

steam header upstream of the main steam isolation valve (MSIV). Each 

of the steam feed lines will supply 100% of the requirements of the 

turbine driven AFW pump. The turbine driven AFW pump supplies a 

common header capable of feeding both steam generators, with DC 

powered control valves actuated to the appropriate steam generator by 

the Emergency Feedwater Actuation System (EFAS). 

The AFW System supplies feedwater to the steam generators during 

normal unit startup, shutdown, and hot standby conditions. 
AFW System 

B 3.7.5 

CEOG STS B 3.7.5-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The AFW System is designed to supply sufficient water to the steam 

generator(s) to remove decay heat with steam generator pressure at the 

setpoint of the MSSVs. Subsequently, the AFW System supplies 

sufficient water to cool the unit to SDC entry conditions, and steam is 

released through the ADVs. 

The AFW System actuates automatically on low steam generator level by 

the EFAS as described in LCO 3.3.2, "Engineered Safety Feature 

Actuation System (ESFAS) Instrumentation." The EFAS logic is designed 

to feed either or both steam generators with low levels, but will isolate the 

AFW System from a steam generator having a significantly lower steam 

pressure than the other steam generator. The EFAS automatically 

actuates the AFW turbine driven pump and associated DC operated 

valves and controls when required, to ensure an adequate feedwater 

supply to the steam generators. DC operated valves are provided for 

each AFW line to control the AFW flow to each steam generator. 

The AFW System is discussed in the FSAR, Section [10.4.9] (Ref. 1). 

APPLICABLE The AFW System mitigates the consequences of any event with a loss of 

SAFETY normal feedwater. 

ANALYSES 

The design basis of the AFW System is to supply water to the steam 

generator to remove decay heat and other residual heat, by delivering at 

least the minimum required flow rate to the steam generators at 

pressures corresponding to the lowest MSSV set pressure plus 3%. 

The limiting Design Basis Accidents (DBAs) and transients for the AFW 

System are as follows: 

a. Feedwater Line Break (FWLB) and 

b. Loss of normal feedwater. 

In addition, the minimum available AFW flow and system characteristics 

are serious considerations in the analysis of a small break loss of coolant 

accident. 
AFW System 

B 3.7.5 

CEOG STS B 3.7.5-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The AFW System design is such that it can perform its function following 

an FWLB between the MFW isolation valve and containment, combined 

with a loss of offsite power following turbine trip, and a single active 

failure of the steam turbine driven AFW pump. In such a case, the EFAS 

logic might not detect the affected steam generator if the backflow check 

valve to the affected MFW header worked properly. One motor driven 

AFW pump would deliver to the broken MFW header at the pump runout 

flow until the problem was detected, and flow was terminated by the 

operator. Sufficient flow would be delivered to the intact steam generator 

by the redundant AFW pump. 

The AFW System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO This LCO requires that [three] AFW trains be OPERABLE to ensure that 

the AFW System will perform the design safety function to mitigate the 

consequences of accidents that could result in overpressurization of the 

reactor coolant pressure boundary. Three independent AFW pumps, in 

two diverse trains, ensure availability of residual heat removal capability 

for all events accompanied by a loss of offsite power and a single failure. 

This is accomplished by powering two pumps from independent 

emergency buses. The third AFW pump is powered by a diverse means, 

a steam driven turbine supplied with steam from a source not isolated by 

the closure of the MSIVs. 

The AFW System is considered to be OPERABLE when the components 

and flow paths required to provide AFW flow to the steam generators are 

OPERABLE. This requires that the two motor driven AFW pumps be 

OPERABLE in two diverse paths, each supplying AFW to a separate 

steam generator. The turbine driven AFW pump shall be OPERABLE 

with redundant steam supplies from each of the two main steam lines 

upstream of the MSIVs and capable of supplying AFW flow to either of 

the two steam generators. The piping, valves, instrumentation, and 

controls in the required flow paths shall also be OPERABLE. 

The LCO is modified by a Note indicating that only one AFW train, which 

includes a motor driven pump, is required to be OPERABLE in MODE 4. 

This is because of reduced heat removal requirements, the short period 

of time in MODE 4 during which AFW is required, and the insufficient 

steam supply available in MODE 4 to power the turbine driven AFW 

pump. 
AFW System 

B 3.7.5 

CEOG STS B 3.7.5-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODES 1, 2, and 3, the AFW System is required to be OPERABLE 

and to function in the event that the MFW is lost. In addition, the AFW 

System is required to supply enough makeup water to replace steam 

generator secondary inventory, lost as the unit cools to MODE 4 

conditions. 

In MODE 4, the AFW System may be used for heat removal via the 

steam generator. 

In MODES 5 and 6, the steam generators are not normally used for decay 

heat removal, and the AFW System is not required. 

ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable AFW 

train. There is an increased risk associated with entering a MODE or 

other specified condition in the Applicability with an AFW train inoperable 

and the provisions of LCO 3.0.4.b, which allow entry into a MODE or 

other specified condition in the Applicability with the LCO not met after 

performance of a risk assessment addressing inoperable systems and 

components, should not be applied in this circumstance. 

 [ A.1

If one of the two steam supplies to the turbine driven AFW pumps is 

inoperable, or if a turbine driven pump is inoperable while in MODE 3 

immediately following refueling, action must be taken to restore the 

inoperable equipment to an OPERABLE status within 7 days. The 7 day 

Completion Time is reasonable based on the following reasons: 

a. For the inoperability of a steam supply to the turbine driven AFW 

pump, the 7 day Completion Time is reasonable since there is a 

redundant steam supply line for the turbine driven pump. 

b. For the inoperability of a turbine driven AFW pump while in MODE 3 

immediately subsequent to a refueling outage, the 7 day Completion 

Time is reasonable due to the minimal decay heat levels in this 

situation. 

c. For both the inoperability of a steam supply line to the turbine driven 

pump and an inoperable turbine driven AFW pump while in MODE 3 

immediately following a refueling outage, the 7 day Completion Time 

is reasonable due to the availability of redundant OPERABLE motor 

driven AFW pumps; and due to the low probability of an event 

requiring the use of the turbine driven AFW pump. 
AFW System 

B 3.7.5 

CEOG STS B 3.7.5-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

The second Completion Time for Required Action A.1 establishes a limit 

on the maximum time allowed for any combination of Conditions to be 

inoperable during any continuous failure to meet this LCO. 

The 10 day Completion Time provides a limitation time allowed in this 

specified Condition after discovery of failure to meet the LCO. This limit 

is considered reasonable for situations in which Conditions A and B are 

entered concurrently. The AND connector between 7 days and 10 days 

dictates that both Completion Times apply simultaneously and the more 

restrictive must be met. 

Condition A is modified by a Note which limits the applicability of the 

Condition to when the unit has not entered MODE 2 following a refueling. 

Condition A allows one AFW train to be inoperable for 7 days vice the 

72 hour Completion Time in Condition B. This longer Completion Time is 

based on the reduced decay heat following refueling and prior to the 

reactor being critical. ]

B.1

With one of the required AFW trains (pump or flow path) inoperable, 

action must be taken to restore OPERABLE status within 72 hours. This 

Condition includes the loss of two steam supply lines to the turbine driven 

AFW pump. The 72 hour Completion Time is reasonable based on the 

redundant capabilities afforded by the AFW System, the time needed for 

repairs, and the low probability of a DBA event occurring during this 

period. Two AFW pumps and flow paths remain to supply feedwater to 

the steam generators. The second Completion Time for Required 

Action B.1 establishes a limit on the maximum time allowed for any 

combination of Conditions to be inoperable during any continuous failure 

to meet this LCO. 

The 10 day Completion Time provides a limitation time allowed in this 

specified Condition after discovery of failure to meet the LCO. This limit 

is considered reasonable for situations in which Conditions A and B are 

entered concurrently. The AND connector between 72 hours and 10 days 

dictates that both Completion Times apply simultaneously, and the more 

restrictive must be met. 
AFW System 

B 3.7.5 

CEOG STS B 3.7.5-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1 and C.2

When either Required Action A.1 or B.1 cannot be completed within the 

required Completion Time, [or if two AFW trains are inoperable in 

MODES 1, 2, and 3], the unit must be placed in a MODE in which the 

LCO does not apply. To achieve this status, the unit must be placed in at 

least MODE 3 within 6 hours, and in MODE 4 within [18] hours. 

The allowed Completion Times are reasonable, based on operating 

experience, to reach the required unit conditions from full power 

conditions in an orderly manner and without challenging unit systems. 

In MODE 4, with [two AFW trains inoperable in MODES 1, 2, and 3], 

operation is allowed to continue because only one motor driven AFW 

pump is required in accordance with the Note that modifies the LCO. 

Although it is not required, the unit may continue to cool down and start 

the SDC. 

D.1

Required Action D.1 is modified by a Note indicating that all required 

MODE changes or power reductions are suspended until one AFW train 

is restored to OPERABLE status. 

With all [three] AFW trains inoperable in MODES 1, 2, and 3, the unit is in 

a seriously degraded condition with no safety related means for 

conducting a cooldown, and only limited means for conducting a 

cooldown with nonsafety grade equipment. In such a condition, the unit 

should not be perturbed by any action, including a power change, that 

might result in a trip. The seriousness of this condition requires that 

action be started immediately to restore one AFW train to OPERABLE 

status. LCO 3.0.3 is not applicable, as it could force the unit into a less 

safe condition. 

E.1

Required Action E.1 is modified by a Note indicating that all required 

MODE changes or power reductions are suspended until one AFW train 

is restored to OPERABLE status. 
AFW System 

B 3.7.5 

CEOG STS B 3.7.5-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

With one AFW train inoperable, action must be taken to immediately 

restore the inoperable train to OPERABLE status or to immediately verify, 

by administrative means, the OPERABILITY of a second train. LCO 3.0.3 

is not applicable, as it could force the unit into a less safe condition. 

In MODE 4, either the reactor coolant pumps or the SDC loops can be 

used to provide forced circulation as discussed in LCO 3.4.6, "RCS Loops 

- MODE 4." 

SURVEILLANCE SR 3.7.5.1

REQUIREMENTS 

Verifying the correct alignment for manual, power operated, and 

automatic valves in the AFW water and steam supply flow paths provides 

assurance that the proper flow paths exist for AFW operation. This SR 

does not apply to valves that are locked, sealed, or otherwise secured in 

position, since these valves are verified to be in the correct position prior 

to locking, sealing, or securing. This SR also does not apply to valves 

that cannot be inadvertently misaligned, such as check valves. This 

Surveillance does not require any testing or valve manipulations; rather, it 

involves verification that those valves capable of potentially being 

mispositioned are in the correct position. 

The 31 day Frequency is based on engineering judgment, is consistent 

with the procedural controls governing valve operation, and ensures 

correct valve positions. 

SR 3.7.5.2

Verifying that each AFW pump's developed head at the flow test point is 

greater than or equal to the required developed head ensures that AFW 

pump performance has not degraded during the cycle. Flow and 

differential head are normal tests of pump performance required by 

Section XI of the ASME Code (Ref. 2). Because it is undesirable to 

introduce cold AFW into the steam generators while they are operating, 

this testing is performed on recirculation flow. This test confirms one 

point on the pump design curve and is indicative of overall performance. 

Such inservice tests confirm component OPERABILITY, trend 

performance, and detect incipient failures by indicating abnormal 

performance. Performance of inservice testing, discussed in the ASME 

Code, Section XI (Ref. 2), at 3 month intervals satisfies this requirement. 

This SR is modified by a Note indicating that the SR should be deferred 

until suitable test conditions are established. This deferral is required 

because there is an insufficient steam pressure to perform the test. 
AFW System 

B 3.7.5 

CEOG STS B 3.7.5-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.7.5.3

This SR ensures that AFW can be delivered to the appropriate steam 

generator, in the event of any accident or transient that generates an 

EFAS signal, by demonstrating that each automatic valve in the flow path 

actuates to its correct position on an actual or simulated actuation signal. 

This Surveillance 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 

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 the design reliability and operating experience of the equipment. 

This SR is modified by a Note indicating that the SR should be deferred 

until suitable test conditions have been established. This deferral is 

required because there is an insufficient steam pressure to perform the 

test. 

Also, this SR is modified by a Note that states the SR is not required to be 

met in MODE 4. In MODE 4, the required AFW train is already aligned 

and operating. 

SR 3.7.5.4

This SR ensures that the AFW pumps will start in the event of any 

accident or transient that generates an EFAS signal by demonstrating 

that each AFW pump starts automatically on an actual or simulated 

actuation signal. The [18] month Frequency is based on the need to 

perform this Surveillance under the conditions that apply during a unit 

outage and the potential for an unplanned transient if the Surveillance 

were performed with the reactor at power. The 18 month Frequency is 

acceptable, based on the design reliability and operating experience of 

the equipment. 

[ This SR is modified by two Notes. Note 1 indicates that the SR be 

deferred until suitable test conditions are established. This deferral is 

required because there is insufficient steam pressure to perform the test. 

Note 2 states that the SR is not required to be met in MODE 4. [In 

MODE 4, the required pump is already operating and the autostart 

function is not required.] [In MODE 4, the heat removal requirements 

would be less providing more time for operator action to manually start 

the required AFW pump. ]
AFW System 

B 3.7.5 

CEOG STS B 3.7.5-9 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Some plants may not routinely use the AFW for heat removal in MODE 4. 

The second justification is provided for plants that use a startup feedwater 

pump rather than AFW for startup and shutdown. 

-------------------------------------------------------------------------------------------------- 

SR 3.7.5.5

This SR ensures that the AFW System is properly aligned by verifying the 

flow path to each steam generator prior to entering MODE 2 operation, 

after 30 days in any combination of MODE 5 or 6, or defueled. 

OPERABILITY of AFW flow paths must be verified before sufficient core 

heat is generated that would require the operation of the AFW System 

during a subsequent shutdown. The Frequency is reasonable, based on 

engineering judgment, and other administrative controls to ensure that 

flow paths remain OPERABLE. To further ensure AFW System 

alignment, the OPERABILITY of the flow paths is verified following 

extended outages to determine that no misalignment of valves has 

occurred. This SR ensures that the flow path from the CST to the steam 

generators is properly aligned by requiring a verification of minimum flow 

capacity of 750 gpm at 1270 psi. (This SR is not required by those units 

that use AFW for normal startup and shutdown.) 

REFERENCES 1. FSAR, Section [10.4.9]. 

 2. ASME, Boiler and Pressure Vessel Code, Section XI, Inservice 

Inspection, Article IWV-3400. 
CST 

B 3.7.6 

CEOG STS B 3.7.6-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.6 Condensate Storage Tank (CST) 

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). The CST provides a passive flow of water, by gravity, to the 

Auxiliary Feedwater (AFW) System (LCO 3.7.4, "Auxiliary Feedwater 

(AFW) System"). The steam produced is released to the atmosphere by 

the main steam safety valves (MSSVs) or the atmospheric dump valves. 

The AFW pumps operate with a continuous recirculation to the CST. 

When the main steam isolation valves are open, the preferred means of 

heat removal is to discharge steam to the condenser by the nonsafety 

grade path of the steam bypass valves. The condensed steam is 

returned to the CST by the condensate transfer pump. This has the 

advantage of conserving condensate while minimizing releases to the 

environment. 

Because the CST is a principal component in removing residual heat from 

the RCS, it is designed to withstand earthquakes and other natural 

phenomena. The CST is designed to Seismic Category I requirements to 

ensure availability of the feedwater supply. Feedwater is also available 

from an alternate source. 

A description of the CST is found in the FSAR, Section [9.2.6] (Ref. 1). 

APPLICABLE The CST provides cooling water to remove decay heat and to cool down 

SAFETY the unit following all events in the accident analysis, discussed in the 

ANALYSES FSAR, Chapters [6] and [15] (Refs. 2 and 3, respectively). For 

anticipated operational occurrences and accidents which do not affect the 

OPERABILITY of the steam generators, the analysis assumption is 

generally [30] minutes at MODE 3, steaming through the MSSVs followed 

by a cooldown to shutdown cooling (SDC) entry conditions at the design 

cooldown rate. 

The limiting event for the condensate volume is the large feedwater line 

break with a coincident loss of offsite power. Single failures that also 

affect this event include the following: 

a. The failure of the diesel generator powering the motor driven AFW 

pump to the unaffected steam generator (requiring additional steam 

to drive the remaining AFW pump turbine) and 
CST 

B 3.7.6 

CEOG STS B 3.7.6-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

b. The failure of the steam driven AFW pump (requiring a longer time 

for cooldown using only one motor driven AFW pump). 

These are not usually the limiting failures in terms of consequences for 

these events. 

A nonlimiting event considered in CST inventory determinations is a 

break either in the main feedwater, or AFW line near where the two join. 

This break has the potential for dumping condensate until terminated by 

operator action, as the Emergency Feedwater Actuation System would 

not detect a difference in pressure between the steam generators for this 

break location. This loss of condensate inventory is partially 

compensated by the retaining of steam generator inventory. 

The CST satisfies Criteria 2 and 3 of 10 CFR 50.36(c)(2)(ii). 

LCO To satisfy accident analysis assumptions, the CST must contain sufficient 

cooling water to remove decay heat for [30 minutes] following a reactor 

trip from 102% RTP, and then cool down the RCS to SDC entry 

conditions, assuming a coincident loss of offsite power and the most 

adverse single failure. In doing this it must retain sufficient water to 

ensure adequate net positive suction head for the AFW pumps during the 

cooldown, as well as to account for any losses from the steam driven 

AFW pump turbine, or before isolating AFW to a broken line. 

The CST level required is a usable volume of ≤ [350,000] gallons, which 

is based on holding the unit in MODE 3 for [4] hours, followed by a 

cooldown to SDC entry conditions at 75°F per hour. This basis is 

established by the NRC Standard Review Plan Branch Technical 

Position, Reactor Systems Branch 5-1 (Ref. 4) and exceeds the volume 

required by the accident analysis. 

OPERABILITY of the CST is determined by maintaining the tank level at 

or above the minimum required level. 

APPLICABILITY In MODES 1, 2, and 3, [and in MODE 4, when steam generator is being 

relied upon for heat removal,] the CST is required to be OPERABLE. 

In MODES 5 and 6, the CST is not required because the AFW System is 

not required. 
CST 

B 3.7.6 

CEOG STS B 3.7.6-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1 and A.2

If the CST is not OPERABLE, the OPERABILITY of the backup water 

supply must be verified by administrative means within 4 hours and once 

every 12 hours thereafter. 

OPERABILITY of the backup feedwater supply must include verification 

of the OPERABILITY of flow paths from the backup supply to the AFW 

pumps, and availability of the required volume of water in the backup 

supply. The CST must be returned to OPERABLE status within 7 days, 

as the backup supply may be performing this function in addition to its 

normal functions. The 4 hour 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 hours 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 

requiring the use of the water from the CST occurring during this period. 

B.1 and B.2

If the CST cannot be restored to OPERABLE status within the associated 

Completion Time, the unit must be placed in a MODE in which the LCO 

does not apply. To achieve this status, the unit must be placed in at least 

MODE 3 within 6 hours, and in MODE 4, without reliance on steam 

generator for heat removal, within [24] hours. The allowed Completion 

Times are reasonable, based on operating experience, to reach the 

required unit conditions from full power conditions in an orderly manner 

and without challenging unit systems. 

SURVEILLANCE SR 3.7.6.1

REQUIREMENTS 

This SR verifies that the CST contains the required volume of cooling 

water. (This level ≥ [350,000] gallons.) The 12 hour Frequency is based 

on operating experience, and the need for operator awareness of unit 

evolutions that may affect the CST inventory between checks. The 

12 hour Frequency is considered adequate in view of other indications in 

the control room, including alarms, to alert the operator to abnormal CST 

level deviations. 
CST 

B 3.7.6 

CEOG STS B 3.7.6-4 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Section [9.2.6]. 

 2. FSAR, Chapter [6]. 

 3. FSAR, Chapter [15]. 

 4. NRC Standard Review Plan Branch Technical Position RSB 5-1. 
CCW System 

B 3.7.7 

CEOG STS B 3.7.7-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.7 Component Cooling Water (CCW) System 

BASES 

BACKGROUND The CCW System provides a heat sink for the removal of process and 

operating heat from safety related components during a Design Basis 

Accident (DBA) or transient. During normal operation, the CCW System 

also provides this function for various nonessential components, as well 

as the spent fuel pool. The CCW System serves as a barrier to the 

release of radioactive byproducts between potentially radioactive systems 

and the Service Water System, and thus to the environment. 

The CCW System is arranged as two independent full capacity cooling 

loops, and has isolatable nonsafety related components. Each safety 

related train includes a full capacity pump, surge tank, heat exchanger, 

piping, valves, and instrumentation. Each safety related train is powered 

from a separate bus. An open surge tank in the system provides pump 

trip protective functions to ensure sufficient net positive suction head is 

available. The pump in each train is automatically started on receipt of a 

safety injection actuation signal, and all nonessential components are 

isolated. 

Additional information on the design and operation of the system, along 

with a list of the components served, is presented in the FSAR, 

Section [9.2.2], Reference 1. The principal safety related function of the 

CCW System is the removal of decay heat from the reactor via the 

Shutdown Cooling (SDC) System heat exchanger. This may utilize the 

SCS heat exchanger, during a normal or post accident cooldown and 

shutdown, or the Containment Spray System during the recirculation 

phase following a loss of coolant accident (LOCA). 

APPLICABLE The design basis of the CCW System is for one CCW train in conjunction 

SAFETY with a 100% capacity Containment Cooling System (containment spray, 

ANALYSES containment coolers, or a combination) removing core decay heat 

20 minutes after a design basis LOCA. This prevents the containment 

sump fluid from increasing in temperature during the recirculation phase 

following a LOCA, and provides a gradual reduction in the temperature of 

this fluid as it is supplied to the Reactor Coolant System (RCS) by the 

safety injection pumps. 

The CCW System is designed to perform its function with a single failure 

of any active component, assuming a loss of offsite power. 
CCW System 

B 3.7.7 

CEOG STS B 3.7.7-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

The CCW System also functions to cool the unit from SDC entry 

conditions (Tcold < [350]°F) to MODE 5 (Tcold < [200]°F) during normal and 

post accident operations. The time required to cool from [350]°F to 

[200]°F is a function of the number of CCW and SDC trains operating. 

One CCW train is sufficient to remove decay heat during subsequent 

operations with Tcold < [200]°F. This assumes that a maximum seawater 

temperature of 76°F occurs simultaneously with the maximum heat loads 

on the system. 

The CCW System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The CCW trains are independent of each other to the degree that each 

has separate controls and power supplies and the operation of one does 

not depend on the other. In the event of a DBA, one CCW train is 

required to provide the minimum heat removal capability assumed in the 

safety analysis for the systems to which it supplies cooling water. To 

ensure this requirement is met, two CCW trains must be OPERABLE. At 

least one CCW train will operate assuming the worst single active failure 

occurs coincident with the loss of offsite power. 

A CCW train is considered OPERABLE when the following: 

a. The associated pump and surge tank are OPERABLE and 

b. The associated piping, valves, heat exchanger and instrumentation 

and controls required to perform the safety related function are 

OPERABLE. 

The isolation of CCW from other components or systems not required for 

safety may render those components or systems inoperable, but does not 

affect the OPERABILITY of the CCW System. 

APPLICABILITY In MODES 1, 2, 3, and 4, the CCW System is a normally operating 

system that must be prepared to perform its post accident safety 

functions, primarily RCS heat removal by cooling the SDC heat 

exchanger. 

In MODES 5 and 6, the OPERABILITY requirements of the CCW System 

are determined by the systems it supports. 
CCW System 

B 3.7.7 

CEOG STS B 3.7.7-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

Required Action A.1 is modified by a Note indicating the requirement of 

entry into the applicable Conditions and Required Actions of LCO 3.4.6, 

"RCS Loops - MODE 4," for SDC made inoperable by CCW. This is an 

exception to LCO 3.0.6 and ensures the proper actions are taken for 

these components. 

With one CCW train inoperable, action must be taken to restore 

OPERABLE status within 72 hours. In this Condition, the remaining 

OPERABLE CCW train is adequate to perform the heat removal function. 

The 72 hour Completion Time is based on the redundant capabilities 

afforded by the OPERABLE train, and the low probability of a DBA 

occurring during this period. 

B.1 and B.2

If the CCW train cannot be restored to OPERABLE status within the 

associated Completion Time, the unit must be placed in a MODE in which 

the LCO does not apply. To achieve this status, the unit must be placed 

in at least MODE 3 within 6 hours and in MODE 5 within 36 hours. 

The allowed Completion Times are reasonable, based on operating 

experience, to reach the required unit conditions from full power 

conditions in an orderly manner and without challenging unit systems. 

SURVEILLANCE SR 3.7.7.1

REQUIREMENTS 

Verifying the correct alignment for manual, power operated, and 

automatic valves in the CCW flow path provides assurance that the 

proper flow paths exist for CCW operation. This SR does not apply to 

valves that are locked, sealed, or otherwise secured in position, since 

these valves are verified to be in the correct position prior to locking, 

sealing, or securing. This SR also does not apply to valves that cannot 

be inadvertently misaligned, such as check valves. This Surveillance 

does not require any testing or valve manipulation; rather, it involves 

verification that those valves capable of potentially being mispositioned 

are in their correct position. 

This SR is modified by a Note indicating that the isolation of the CCW 

components or systems may render those components inoperable but 

does not affect the OPERABILITY of the CCW System. 

The 31 day Frequency is based on engineering judgment, is consistent 

with the procedural controls governing valve operation, and ensures 

correct valve positions. 
CCW System 

B 3.7.7 

CEOG STS B 3.7.7-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.7.7.2

This SR verifies proper automatic operation of the CCW valves on an 

actual or simulated actuation signal. The CCW System is a normally 

operating system that cannot be fully actuated as part of routine testing 

during normal operation. This Surveillance 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 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. 

SR 3.7.7.3

This SR verifies proper automatic operation of the CCW pumps on an 

actual or simulated actuation signal. The CCW System is a normally 

operating system that cannot be fully actuated as part of routine testing 

during normal operation. 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 these components usually pass the Surveillance when performed 

at the [18] month Frequency. Therefore, the Frequency is acceptable 

from a reliability standpoint. 

REFERENCES 1. FSAR, Section [9.2.2]. 
SWS 

B 3.7.8 

CEOG STS B 3.7.8-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.8 Service Water System (SWS) 

BASES 

BACKGROUND The SWS provides a heat sink for the removal of process and operating 

heat from safety related components during a Design Basis Accident 

(DBA) or transient. During normal operation or a normal shutdown, the 

SWS also provides this function for various safety related and nonsafety 

related components. The safety related function is covered by this LCO. 

The SWS consists of two separate, 100% capacity safety related cooling 

water trains. Each train consists of two 100% capacity pumps, one 

component cooling water (CCW) heat exchanger, piping, valves, 

instrumentation, and two cyclone separators. The pumps and valves are 

remote manually aligned, except in the unlikely event of a loss of coolant 

accident (LOCA). The pumps aligned to the critical loops are 

automatically started upon receipt of a safety injection actuation signal 

and all essential valves are aligned to their post accident positions. The 

SWS also provides emergency makeup to the spent fuel pool and CCW 

System [and is the backup water supply to the Auxiliary Feedwater 

System]. 

Additional information about the design and operation of the SWS, along 

with a list of the components served, is presented in the FSAR, 

Section [9.2.1] (Ref. 1). The principal safety related function of the SWS 

is the removal of decay heat from the reactor via the [CCW System]. 

APPLICABLE The design basis of the SWS is for one SWS train, in conjunction with the 

SAFETY CCW System and a 100% capacity containment cooling system 

ANALYSES (containment spray, containment coolers, or a combination), removing 

core decay heat 20 minutes following a design basis LOCA, as discussed 

in the FSAR, Section [6.2] (Ref. 2). This prevents the containment sump 

fluid from increasing in temperature during the recirculation phase 

following a LOCA and provides for a gradual reduction in the temperature 

of this fluid as it is supplied to the Reactor Coolant System by the safety 

injection pumps. The SWS is designed to perform its function with a 

single failure of any active component, assuming the loss of offsite power. 

The SWS, in conjunction with the CCW System, also cools the unit from 

shutdown cooling (SDC), as discussed in the FSAR, Section [5.4.7] 

(Ref. 3) entry conditions to MODE 5 during normal and post accident 

operations. The time required for this evolution is a function of the 
SWS 

B 3.7.8 

CEOG STS B 3.7.8-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

number of CCW and SDC System trains that are operating. One SWS 

train is sufficient to remove decay heat during subsequent operations in 

MODES 5 and 6. This assumes that a maximum SWS temperature of 

95°F occurring simultaneously with maximum heat loads on the system. 

The SWS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Two SWS trains are required to be OPERABLE to provide the required 

redundancy to ensure that the system functions to remove post accident 

heat loads, assuming the worst single active failure occurs coincident with 

the loss of offsite power. 

An SWS train is considered OPERABLE when: 

a. The associated pump is OPERABLE and 

b. The associated piping, valves, heat exchanger, and instrumentation 

and controls required to perform the safety related function are 

OPERABLE. 

APPLICABILITY In MODES 1, 2, 3, and 4, the SWS System is a normally operating 

system, which is required to support the OPERABILITY of the equipment 

serviced by the SWS and required to be OPERABLE in these MODES. 

In MODES 5 and 6, the OPERABILITY requirements of the SWS are 

determined by the systems it supports. 

ACTIONS A.1

With one SSW train inoperable, action must be taken to restore 

OPERABLE status within 72 hours. In this Condition, the remaining 

OPERABLE SWS train is adequate to perform the heat removal function. 

However, the overall reliability is reduced because a single failure in the 

SWS train could result in loss of SWS function. Required Action A.1 is 

modified by two Notes. The first Note indicates that the applicable 

Conditions of LCO 3.8.1, "AC Sources - Operating," should be entered if 

the inoperable SWS train results in an inoperable emergency diesel 

generator. The second Note indicates that the applicable Conditions and 

Required Actions of LCO 3.4.6, "RCS Loops - MODE 4," should be 

entered if an inoperable SWS train results in an inoperable SDC. The 

72 hour Completion Time is based on the redundant capabilities afforded 

by the OPERABLE train, and the low probability of a DBA occurring 

during this time period. 
SWS 

B 3.7.8 

CEOG STS B 3.7.8-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1 and B.2

If the SWS train cannot be restored to OPERABLE status within the 

associated Completion Time, the unit must be placed in a MODE in which 

the LCO does not apply. To achieve this status, the unit must be placed 

in at least MODE 3 within 6 hours and in MODE 5 within 36 hours. 

The allowed Completion Times are reasonable, based on operating 

experience, to reach the required unit conditions from full power 

conditions in an orderly manner and without challenging unit systems. 

SURVEILLANCE SR 3.7.8.1

REQUIREMENTS 

Verifying the correct alignment for manual, power operated, and 

automatic valves in the SWS flow path ensures that the proper flow paths 

exist for SWS operation. This SR does not apply to valves that are 

locked, sealed, or otherwise secured in position, since they are verified to 

be in the correct position prior to locking, sealing, or securing. This SR 

also does not apply to valves that cannot be inadvertently misaligned, 

such as check valves. This Surveillance does not require any testing or 

valve manipulation; rather, it involves verification that those valves 

capable of potentially being mispositioned are in the correct position. 

This SR is modified by a Note indicating that the isolation of the SWS 

components or systems may render those components inoperable but 

does not affect the OPERABILITY of the SWS. 

The 31 day Frequency is based on engineering judgment, is consistent 

with the procedural controls governing valve operation, and ensures 

correct valve positions. 

SR 3.7.8.2

This SR verifies proper automatic operation of the SWS valves on an 

actual or simulated actuation signal. The SWS is a normally operating 

system that cannot be fully actuated as part of the normal testing. This 

Surveillance 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 

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. 
SWS 

B 3.7.8 

CEOG STS B 3.7.8-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.7.8.3

The SR verifies proper automatic operation of the SWS pumps on an 

actual or simulated actuation signal. The SWS is a normally operating 

system that cannot be fully actuated as part of the normal testing during 

normal operation. 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. 

REFERENCES 1. FSAR, Section [9.2.1]. 

 2. FSAR, Section [6.2]. 

 3. FSAR, Section [5.4.7]. 
UHS 

B 3.7.9 

CEOG STS B 3.7.9-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.9 Ultimate Heat Sink (UHS) 

BASES 

BACKGROUND The UHS provides a heat sink for process and operating heat from safety 

related components during a Design Basis Accident (DBA) or transient, 

as well as during normal operation. This is done utilizing the Service 

Water System. 

The UHS has been defined as that complex of water sources, including 

necessary retaining structures (e.g., a pond with its dam, or a river with its 

dam), and the canals or conduits connecting the sources with, but not 

including, the cooling water system intake structures as, discussed in the 

FSAR, Section [9.2.5] (Ref. 1). If cooling towers or portions thereof are 

required to accomplish the UHS safety functions, they should meet the 

same requirements as the sink. The two principal functions of the UHS 

are the dissipation of residual heat after reactor shutdown, and dissipation 

of residual heat after an accident. 

A variety of complexes is used to meet the requirements for a UHS. A 

lake or an ocean may qualify as a single source. If the complex includes 

a water source contained by a structure, it is likely that a second source 

will be required. 

The basic performance requirements are that a 30 day supply of water be 

available, and that the design basis temperatures of safety related 

equipment not be exceeded. Basins of cooling towers generally include 

less than a 30 day supply of water, typically 7 days or less. A 30 day 

supply would be dependent on another source(s) and a makeup 

system(s) for replenishing the source in the cooling tower basin. For 

smaller basin sources, which may be as small as a 1 day supply, the 

systems for replenishing the basin and the backup source(s) become of 

sufficient importance that the makeup system itself may be required to 

meet the same design criteria as an Engineered Safety Feature (e.g., 

single failure considerations, and multiple makeup water sources may be 

required). 

It follows that the many variations in the UHS configurations will result in 

many unit to unit variations in OPERABILITY determinations and SRs. 

The ACTIONS and SRs are illustrative of a cooling tower UHS without a 

makeup requirement. 

Additional information on the design and operation of the system along 

with a list of components served can be found in Reference 1. 
UHS 

B 3.7.9 

CEOG STS B 3.7.9-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The UHS is the sink for heat removed from the reactor core following all 

SAFETY accidents and anticipated operational occurrences in which the unit is 

ANALYSES cooled down and placed on shutdown cooling. For those units using it as 

the normal heat sink for condenser cooling via the Circulating Water 

System, unit operation at full power is its maximum heat load. Its 

maximum post accident heat load occurs 20 minutes after a design basis 

loss of coolant accident (LOCA). Near this time, the unit switches from 

injection to recirculation, and the containment cooling systems are 

required to remove the core decay heat. 

The operating limits are based on conservative heat transfer analyses for 

the worst case LOCA. Reference 1 provides the details of the 

assumptions used in the analysis. The assumptions include: worst 

expected meteorological conditions, conservative uncertainties when 

calculating decay heat, and the worst case failure (e.g., single failure of a 

manmade structure). The UHS is designed in accordance with 

Regulatory Guide 1.27 (Ref. 2), which requires a 30 day supply of cooling 

water in the UHS. 

The UHS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The UHS is required to be OPERABLE. The UHS is considered 

OPERABLE if it contains a sufficient volume of water at or below the 

maximum temperature that would allow the SWS to operate for at least 

30 days following the design basis LOCA without the loss of net positive 

suction head (NPSH), and without exceeding the maximum design 

temperature of the equipment served by the SWS. To meet this 

condition, the UHS temperature should not exceed [90]°F and the level 

should not fall below [562 ft mean sea level] during normal unit operation. 

APPLICABILITY In MODES 1, 2, 3, and 4, the UHS is a normally operating system that is 

required to support the OPERABILITY of the equipment serviced by the 

UHS and required to be OPERABLE in these MODES. 

In MODES 5 and 6, the OPERABILITY requirements of the UHS are 

determined by the systems it supports. 
UHS 

B 3.7.9 

CEOG STS B 3.7.9-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS [ A.1

If one or more cooling towers have one fan inoperable (i.e., up to one fan 

per cooling tower inoperable), action must be taken to restored the 

inoperable cooling tower fan(s) to OPERABLE status within 7 days. 

The 7 day Completion Time is reasonable, based on the low probability of 

an accident occurring during the 7 days that one cooling tower fan is 

inoperable, the number of available systems, and the time required to 

complete the action. ]

[ B.1

-----------------------------------REVIEWER’S NOTE----------------------------------- 

The [ ]°F is the maximum allowed UHS temperature value and is based 

on temperature limitations of the equipment that is relied upon for 

accident mitigation and safe shutdown of the unit. 

-------------------------------------------------------------------------------------------------- 

With water temperature of the UHS > [90]°F, the design basis assumption 

associated with initial UHS temperature are bounded provided the 

temperature of the UHS averaged over the previous 24 hour period is 

≤ [90]°F. With the water temperature of the UHS > [90]°F, long term 

cooling capability of the ECCS loads and DGs may be affected. 

Therefore, to ensure long term cooling capability is provided to the ECCS 

loads when water temperature of the UHS is > [90]°F, Required Action 

B.1 is provided to more frequently monitor the water temperature of the 

UHS and verify the temperature is ≤ [90]°F when averaged over the 

previous 24 hour period. The once per hour Completion Time takes into 

consideration UHS temperature variations and the increased monitoring 

frequency needed to ensure design basis assumptions and equipment 

limitations are not exceeded in this condition. If the water temperature of 

the UHS exceeds [90]°F when averaged over the previous 24 hour period 

or the water temperature of the UHS exceeds [ ]°F, Condition C must be 

entered immediately.]
UHS 

B 3.7.9 

CEOG STS B 3.7.9-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

[ C.1 and C.2

If the Required Actions or Completion Times of Conditions [A or B] are 

not met, or the UHS is inoperable [for reasons other than Condition A or 

B], the unit must be placed in a MODE in which the LCO does not apply. 

To achieve this status, the unit must be placed in at least MODE 3 within 

6 hours and in MODE 5 within 36 hours. The allowed Completion Times 

are reasonable, based on operating experience, to reach the required unit 

conditions from full power conditions in an orderly manner and without 

challenging unit systems. ] 

SURVEILLANCE [ SR 3.7.9.1

REQUIREMENTS 

This SR verifies adequate long term (30 days) cooling can be maintained. 

The level specified also ensures sufficient NPSH is available for operating 

the SWS pumps. The 24 hour Frequency is based on operating 

experience related to the trending of the parameter variations during the 

applicable MODES. This SR verifies that the UHS water level is ≥ [562] ft 

[mean sea level]. ]

[ SR 3.7.9.2

This SR verifies that the SWS is available to cool the CCW System to at 

least its maximum design temperature within the maximum accident or 

normal design heat loads for 30 days following a DBA. The 24 hour 

Frequency is based on operating experience related to the trending of the 

parameter variations during the applicable MODES. This SR verifies that 

the UHS water temperature is ≤ [92]°F. ]

[ SR 3.7.9.3

Operating each cooling tower fan for ≥ [15] minutes verifies that all fans 

are OPERABLE and that all associated controls are functioning properly. 

It also ensures that fan or motor failure, or excessive vibration can be 

detected for corrective action. The 31 day Frequency is based on 

operating experience, the known reliability of the fan units, the 

redundancy available, and the low probability of significant degradation of 

the UHS cooling tower fans occurring between surveillances. ] 

REFERENCES 1. FSAR, Section [9.2.5]. 

 2. Regulatory Guide 1.27. 
ECW System 

B 3.7.10 

CEOG STS B 3.7.10-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.10 Essential Chilled Water (ECW) System 

BASES 

BACKGROUND The ECW System provides a heat sink for the removal of process and 

operating heat from selected safety related air handling systems during a 

Design Basis Accident (DBA) or transient. 

The ECW System is a closed loop system consisting of two independent 

trains. Each 100% capacity train includes a heat exchanger, surge tank, 

pump, chemical addition tank, piping, valves, controls, and 

instrumentation. An independent 100% capacity chilled water 

refrigeration unit cools each train. The ECW System is actuated on a 

safety injection actuation signal (SIAS) and supplies chilled water to the 

heating, ventilation, and air conditioning (HVAC) units in Engineered 

Safety Feature (ESF) equipment areas (e.g., the main control room, 

electrical equipment room, and safety injection pump area). 

The flow path for the ECW System includes the closed loop of piping to 

all serviced equipment, and branch lines up to the first normally closed 

isolation valve. 

During normal operation, the normal HVAC System performs the cooling 

function of the ECW System. The normal HVAC System is a nonsafety 

grade system that automatically shuts down when the ECW System 

receives a start signal. Additional information about the design and 

operation of the system, along with a list of components served, can be 

found in the FSAR, Section [9.2.9] (Ref. 1). 

APPLICABLE The design basis of the ECW System is to remove the post accident heat 

SAFETY load from ESF spaces following a DBA coincident with a loss of offsite 

ANALYSES power. Each train provides chilled water to the HVAC units at the design 

temperature of 42°F and flow rate of 400 gpm. 

The maximum heat load in the ESF pump room area occurs during the 

recirculation phase following a loss of coolant accident. During 

recirculation, hot fluid from the containment sump is supplied to the high 

pressure safety injection and containment spray pumps. This heat load to 

the area atmosphere must be removed by the ECW System to ensure 

that these pumps remain OPERABLE. 

The ECW satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 
ECW System 

B 3.7.10 

CEOG STS B 3.7.10-2 Rev. 3.0, 03/31/04 

BASES 

LCO [Two] ECW trains are required to be OPERABLE to provide the required 

redundancy to ensure that the system functions to remove post accident 

heat loads, assuming the worst single failure. 

An ECW train is considered OPERABLE when: 

a. The associated pump and surge tank are OPERABLE and 

b. The associated piping, valves, heat exchanger, refrigeration unit, and 

instrumentation and controls required to perform the safety related 

function are OPERABLE. 

The isolation of the ECW from other components or systems may render 

those components or systems inoperable, but does not affect the 

OPERABILITY of the ECW System. 

APPLICABILITY In MODES 1, 2, 3, and 4, the ECW System is required to be OPERABLE 

when a LOCA or other accident would require ESF operation. 

In MODES 5 and 6, potential heat loads are smaller and the probability of 

accidents requiring the ECW System is low. 

ACTIONS A.1

If one ECW train is inoperable, action must be taken to restore 

OPERABLE status within 7 days. In this condition, one OPERABLE ECW 

train is adequate to perform the cooling function. The 7 day Completion 

Time is reasonable, based on the low probability of an event occurring 

during this time, the 100% capacity OPERABLE ECW train, and the 

redundant availability of the normal HVAC System. 

B.1 and B.2

If the ECW train cannot be restored to OPERABLE status within the 

associated Completion Time, the unit must be placed in a MODE in which 

the LCO does not apply. To achieve this status, the unit must be placed 

in at least MODE 3 within 6 hours, and in MODE 5 within 36 hours. The 

allowed Completion Times are reasonable, based on operating 

experience, to reach the required unit conditions from full power 

conditions in an orderly manner and without challenging unit systems. 
ECW System 

B 3.7.10 

CEOG STS B 3.7.10-3 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.7.10.1

REQUIREMENTS 

Verifying the correct alignment for manual, power operated, and 

automatic valves in the ECW flow path provides assurance that the 

proper flow paths exist for ECW operation. This SR does not apply to 

valves that are locked, sealed, or otherwise secured in position, since 

they are verified to be in the correct position prior to locking, sealing, or 

securing. This SR also does not apply to valves that cannot be 

inadvertently misaligned, such as check valves. This Surveillance does 

not require any testing or valve manipulation; rather, it involves 

verification that those valves capable of potentially being mispositioned 

are in the correct position. 

This SR is modified by a Note indicating that the isolation of ECW flow to 

components or systems may render those components inoperable but 

does not affect the OPERABILITY of the ECW System. 

The 31 day Frequency is based on engineering judgment, is consistent 

with the procedural controls governing valve operation, and ensures 

correct valve positions. 

SR 3.7.10.2

This SR verifies proper automatic operation of the ECW System 

components that the ECW pumps will start in the event of any accident or 

transient that generates an SIAS. This SR also ensures that each 

automatic valve in the flow paths actuates to its correct position on an 

actual or simulated SIAS. The ECW System cannot be fully actuated as 

part of the SIAS CHANNEL FUNCTIONAL TEST during normal 

operation. The actuation logic is tested as part of the SIAS functional test 

every 92 days, except for the subgroup relays that actuate the system 

that cannot be tested during normal unit operation. The [18] month 

Frequency is based on the need to perform this Surveillance under the 

conditions that apply during a unit outage and the potential for an 

unplanned transient if the Surveillance were performed with the reactor at 

power. The [18] month Frequency is based on operating experience and 

design reliability of the equipment. 

REFERENCES 1. FSAR, Section [9.2.9]. 
CREACS 

B 3.7.11 

CEOG STS B 3.7.11-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.11 Control Room Emergency Air Cleanup System (CREACS) 

BASES 

BACKGROUND The CREACS provides a protected environment from which operators 

can control the unit following an uncontrolled release of radioactivity, 

[chemicals, or toxic gas]. 

The CREACS consists of two independent, redundant trains that 

recirculate and filter the control room air. Each train consists of a prefilter 

and demister, a high efficiency particulate air (HEPA) filter, an activated 

charcoal adsorber section for removal of gaseous activity (principally 

iodine), and a fan. Ductwork, valves or dampers, and instrumentation 

also form part of the system, as do demisters that remove water droplets 

from the air stream. A second bank of HEPA filters follows the adsorber 

section to collect carbon fines, and to back up the main HEPA filter bank 

if it fails. 

The CREACS is an emergency system, part of which may also operate 

during normal unit operations in the standby mode of operation. Upon 

receipt of the actuating signal(s), normal air supply to the control room is 

isolated, and the stream of ventilation air is recirculated through the filter 

trains of the system. The prefilters and demisters remove any large 

particles in the air, and any entrained water droplets present to prevent 

excessive loading of the HEPA filters and charcoal adsorbers. 

Continuous operation of each train for at least 10 hours per month with 

the heaters on reduces moisture buildup on the HEPA filters and 

adsorbers. Both the demister and heater are important to the 

effectiveness of the charcoal adsorbers. 

Actuation of the CREACS places the system into either of two separate 

states of the emergency mode of operation, depending on the initiation 

signal. Actuation of the system to the emergency radiation state of the 

emergency mode of operation closes the unfiltered outside air intake and 

unfiltered exhaust dampers, and aligns the system for recirculation of 

control room air through the redundant trains of HEPA and charcoal 

filters. The emergency radiation state initiates pressurization and filtered 

ventilation of the air supply to the control room. 

Outside air is filtered, [diluted with building air from the electrical 

equipment and cable spreading rooms,] and then added to the air being 

recirculated from the control room. Pressurization of the control room 

prevents infiltration of unfiltered air from the surrounding areas of the 
CREACS 

B 3.7.11 

CEOG STS B 3.7.11-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

building. The actions taken in the toxic gas isolation state are the same, 

except that the signal switches control room ventilation to an isolation 

mode, preventing outside air from entering the control room. 

The air entering the control room is continuously monitored by radiation 

and toxic gas detectors. One detector output above the setpoint will 

cause actuation of the emergency radiation state or toxic gas isolation 

state as required. The actions of the toxic gas isolation state are more 

restrictive, and will override the actions of the emergency radiation state. 

A single train will pressurize the control room to about [0.125] inches 

water gauge, and provides an air exchange rate in excess of 25% per 

hour. The CREACS operation in maintaining the control room habitable 

is discussed in the FSAR, Section [9.4] (Ref. 1). 

Redundant supply and recirculation trains provide the required filtration 

should an excessive pressure drop develop across the other filter train. 

Normally open isolation dampers are arranged in series pairs so that the 

failure of one damper to shut will not result in a breach of isolation. The 

CREACS is designed in accordance with Seismic Category I 

requirements. 

The CREACS is designed to maintain the control room environment for 

30 days of continuous occupancy after a Design Basis Accident (DBA) 

without exceeding a 5 rem whole body dose or its equivalent to any part 

of the body. 

APPLICABLE The CREACS components are arranged in redundant safety related 

SAFETY ventilation trains. The location of components and ducting within the 

ANALYSES control room envelope ensures an adequate supply of filtered air to all 

areas requiring access. 

The CREACS provides airborne radiological protection for the control 

room operators, as demonstrated by the control room accident dose 

analyses for the most limiting design basis loss of coolant accident fission 

product release presented in the FSAR, Chapter [15] (Ref. 2). 

The analysis of toxic gas releases demonstrates that the toxicity limits are 

not exceeded in the control room following a toxic chemical release, as 

presented in Reference 1. 

The worst case single active failure of a component of the CREACS, 

assuming a loss of offsite power, does not impair the ability of the system 

to perform its design function. 

The CREACS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 
CREACS 

B 3.7.11 

CEOG STS B 3.7.11-3 Rev. 3.0, 03/31/04 

BASES (continued) 

LCO Two independent and redundant trains of the CREACS are required to be 

OPERABLE to ensure that at least one is available, assuming that a 

single failure disables the other train. Total system failure could result in 

a control room operator receiving a dose in excess of 5 rem in the event 

of a large radioactive release. 

The CREACS is considered OPERABLE when the individual components 

necessary to control operator exposure are OPERABLE in both trains. A 

CREACS train is considered OPERABLE when the associated: 

a. Fan is OPERABLE, 

b. HEPA filters and charcoal adsorber are not excessively restricting 

flow, and are capable of performing their filtration functions, and 

c. Heater, demister, ductwork, valves, and dampers are OPERABLE, 

and air circulation can be maintained. 

In addition, the control room boundary must be maintained, including the 

integrity of the walls, floors, ceilings, ductwork, and access doors. 

The LCO is modified by a Note allowing the control room boundary to be 

opened intermittently under administrative controls. For entry and exit 

through doors, the administrative control of the opening is performed by 

the person(s) entering or exiting the area. For other openings, these 

controls consist of stationing a dedicated individual at the opening who is 

in continuous communication with the control room. This individual will 

have a method to rapidly close the opening when a need for control room 

isolation is indicated. 

APPLICABILITY In MODES 1, 2, 3, and 4, the CREACS must be OPERABLE to limit 

operator exposure during and following a DBA. 

In MODES [5 and 6], the CREACS is required to cope with the release 

from a rupture of an outside waste gas tank. 

During movement of [recently] irradiated fuel assemblies, the CREACS 

must be OPERABLE to cope with the release from a fuel handling 

accident. [Due to radioactive decay, CREACS is only required to cope 

with fuel handling accidents involving handling recently irradiated fuel 

(i.e., fuel that has occupied part of a critical reactor core within the 

previous [X] days).] 
CREACS 

B 3.7.11 

CEOG STS B 3.7.11-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

With one CREACS train inoperable, action must be taken to restore 

OPERABLE status within 7 days. In this Condition, the remaining 

OPERABLE CREACS subsystem is adequate to perform control room 

radiation protection function. However, the overall reliability is reduced 

because a single failure in the OPERABLE CREACS train could result in 

loss of CREACS function. The 7 day Completion Time is based on the 

low probability of a DBA occurring during this time period, and the ability 

of the remaining train to provide the required capability. 

B.1

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Adoption of Condition B is dependent on a commitment from the licensee 

to have written procedures available describing compensatory measures 

to be taken in the event of an intentional or unintentional entry into 

Condition B. 

-------------------------------------------------------------------------------------------------- 

If the control room boundary is inoperable in MODES 1, 2, 3, and 4, the 

CREACS trains cannot perform their intended functions. Actions must be 

taken to restore an OPERABLE control room boundary within 24 hours. 

During the period that the control room boundary is inoperable, 

appropriate compensatory measures (consistent with the intent of GDC 

19) should be utilized to protect control room operators from potential 

hazards such as radioactive contamination, toxic chemicals, smoke, 

temperature and relative humidity, and physical security. Preplanned 

measures should be available to address these concerns for intentional 

and unintentional entry into the condition. The 24 hour Completion Time 

is reasonable based on the low probability of a DBA occurring during this 

time period, and the use of compensatory measures. The 24 hour 

Completion Time is a typically reasonable time to diagnose, plan and 

possibly repair, and test most problems with the control room boundary. 

C.1 and C.2

If the inoperable CREACS or control room boundary cannot be restored 

to OPERABLE status within the associated Completion Time in MODE 1, 

2, 3, or 4, the unit must be placed in a MODE that minimizes the accident 

risk. To achieve this status, the unit must be placed in at least MODE 3 

within 6 hours, and in MODE 5 within 36 hours. The allowed Completion 

Times are reasonable, based on operating experience, to reach the 

required unit conditions from full power conditions in an orderly manner 

and without challenging unit systems. 
CREACS 

B 3.7.11 

CEOG STS B 3.7.11-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

D.1 and D.2

Required Action D.1 is modified by a Note indicating to place the system 

in the emergency radiation protection mode if the automatic transfer to 

emergency mode is inoperable. 

In MODE 5 or 6, or during movement of [recently] irradiated fuel 

assemblies, if Required Action A.1 cannot be completed within the 

required Completion Time, the OPERABLE CREACS train must be 

immediately placed in the emergency mode of operation. This action 

ensures that the remaining train is OPERABLE, that no failures 

preventing automatic actuation will occur, and that any active failure will 

be readily detected. 

An alternative to Required Action D.1 is to immediately suspend activities 

that could result in a release of radioactivity that might require isolation of 

the control room. This places the unit in a condition that minimizes the 

accident risk. This does not preclude the movement of fuel assemblies to 

a safe position. 

E.1

When [in MODES 5 and 6, or] during movement of [recently] irradiated 

fuel assemblies, with two CREACS trains inoperable, action must be 

taken immediately to suspend activities that could result in a release of 

radioactivity that might require isolation of the control room. This places 

the unit in a condition that minimizes the accident risk. This does not 

preclude the movement of fuel to a safe position. 

F.1

If both CREACS trains are inoperable in MODE 1, 2, 3, or 4 for reasons 

other than an inoperable control room boundary (i.e., Condition B), the 

CREACS may not be capable of performing the intended function and the 

unit is in a condition outside the accident analyses. Therefore, LCO 3.0.3 

must be entered immediately. 
CREACS 

B 3.7.11 

CEOG STS B 3.7.11-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.7.11.1

REQUIREMENTS 

Standby systems should be checked periodically to ensure that they 

function properly. Since the environment and normal operating conditions 

on this system are not severe, testing each train once every month 

provides an adequate check on this system. 

Monthly heater operations dry out any moisture accumulated in the 

charcoal from humidity in the ambient air. [Systems with heaters must be 

operated for ≥ 10 continuous hours with the heaters energized. Systems 

without heaters need only be operated for ≥ 15 minutes to demonstrate 

the function of the system.] The 31 day Frequency is based on the 

known reliability of the equipment, and the two train redundancy 

available. 

SR 3.7.11.2

This SR verifies that the required CREACS testing is performed in 

accordance with the [Ventilation Filter Testing Program (VFTP)]. The 

[VFTP] includes testing HEPA filter performance, charcoal adsorber 

efficiency, minimum system flow rate, and the physical properties of the 

activated charcoal (general use and following specific operations). 

Specific test frequencies and additional information are discussed in 

detail in the [VFTP]. 

SR 3.7.11.3

This SR verifies each CREACS train starts and operates on an actual or 

simulated actuation signal. The Frequency of [18] months is consistent 

with that specified in Reference 3. 

SR 3.7.11.4

This SR verifies the integrity of the control room enclosure and the 

assumed inleakage rates of potentially contaminated air. The control 

room positive pressure, with respect to potentially contaminated adjacent 

areas, is periodically tested to verify proper function of the CREACS. 

During the emergency radiation state of the emergency mode of 

operation, the CREACS is designed to pressurize the control room 

≥ [0.125] inches water gauge positive pressure with respect to adjacent 

areas in order to prevent unfiltered inleakage. The CREACS is designed 

to maintain this positive pressure with one train at an emergency 

ventilation flow rate of [3000] cfm. The Frequency of [18] months on a 

STAGGERED TEST BASIS is consistent with the guidance provided in 

NUREG-0800, Section 6.4 (Ref. 4). 
CREACS 

B 3.7.11 

CEOG STS B 3.7.11-7 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Section [9.4]. 

 2. FSAR, Chapter [15]. 

 3. Regulatory Guide 1.52, Rev. [2]. 

 4. NUREG-0800, Section 6.4, Rev. 2, July 1981. 
CREATCS 

B 3.7.12 

CEOG STS B 3.7.12-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.12 Control Room Emergency Air Temperature Control System (CREATCS) 

BASES 

BACKGROUND The CREATCS provides temperature control for the control room 

following isolation of the control room. 

The CREATCS consists of two independent, redundant trains that provide 

cooling and heating of recirculated control room air. Each train consists 

of heating coils, cooling coils, instrumentation, and controls to provide for 

control room temperature control. 

The CREATCS is an emergency system, parts of which may also operate 

during normal unit operations. A single train will provide the required 

temperature control to maintain the control room between [70]°F and 

[85]°F. The CREATCS operation to maintain the control room 

temperature is discussed in the FSAR, Section [6.4] (Ref. 1). 

APPLICABLE The design basis of the CREATCS is to maintain temperature of the 

SAFETY control room environment throughout 30 days of continuous occupancy. 

ANALYSES 

The CREATCS components are arranged in redundant safety related 

trains. During emergency operation, the CREATCS maintains the 

temperature between [70]°F and [85]°F. A single active failure of a 

component of the CREATCS, assuming a loss of offsite power, does not 

impair the ability of the system to perform its design function. Redundant 

detectors and controls are provided for control room temperature control. 

The CREATCS is designed in accordance with Seismic Category I 

requirements. The CREATCS is capable of removing sensible and latent 

heat loads from the control room, considering equipment heat loads and 

personnel occupancy requirements, to ensure equipment OPERABILITY. 

The CREATCS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Two independent and redundant trains of the CREATCS are required to 

be OPERABLE to ensure that at least one is available, assuming a single 

failure disables the other train. Total system failure could result in the 

equipment operating temperature exceeding limits in the event of an 

accident. 

The CREATCS is considered OPERABLE when the individual 

components that are necessary to maintain the control room temperature 

are OPERABLE in both trains. These components include the cooling 

coils and associated temperature control instrumentation. In addition, 

the CREATCS must be OPERABLE to the extent that air circulation can 

be maintained. 
CREATCS 

B 3.7.12 

CEOG STS B 3.7.12-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODES 1, 2, 3, 4, [5, and 6,] and during movement of [recently] 

irradiated fuel assemblies [(i.e., fuel that has occupied part of a critical 

reactor core within the previous [X] days)], the CREATCS must be 

OPERABLE to ensure that the control room temperature will not exceed 

equipment OPERABILITY requirements following isolation of the control 

room. 

In MODES 5 and 6, CREATCS may not be required for those facilities 

which do not require automatic control room isolation. 

ACTIONS A.1

With one CREATCS train inoperable, action must be taken to restore 

OPERABLE status within 30 days. In this Condition, the remaining 

OPERABLE CREATCS train is adequate to maintain the control room 

temperature within limits. The 30 day Completion Time is reasonable, 

based on the low probability of an event occurring requiring control room 

isolation, consideration that the remaining train can provide the required 

capabilities, and the alternate safety or nonsafety related cooling means 

that are available. 

B.1 and B.2

In MODE 1, 2, 3, or 4, when Required Action A.1 cannot be completed 

within the required Completion Time, the unit must be placed in a MODE 

that minimizes the accident risk. To achieve this status, the unit must be 

placed in at least MODE 3 within 6 hours, and in MODE 5 within 

36 hours. The allowed Completion Times are reasonable, based on 

operating experience, to reach the required unit conditions from full power 

conditions in an orderly manner and without challenging unit systems. 

[ C.1 and C.2

In MODE 5 or 6, or during movement of [recently] irradiated fuel 

assemblies, when Required Action A.1 cannot be completed within the 

required Completion Time, the OPERABLE CREATCS train must be 

placed in operation immediately. This action ensures that the remaining 

train is OPERABLE, that no failures preventing automatic actuation will 

occur, and that any active failure will be readily detected. 

An alternative to Required Action C.1 is to immediately suspend activities 

that could result in a release of radioactivity that might require isolation of 

the control room. This places the unit in a condition that minimizes the 

accident risk. This does not preclude the movement of fuel assemblies to 

a safe position. ]
CREATCS 

B 3.7.12 

CEOG STS B 3.7.12-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

[ D.1

In [MODE 5 or 6, or] during movement of [recently] irradiated fuel 

assemblies, with two CREATCS trains inoperable, action must be taken 

immediately to suspend activities that could result in a release of 

radioactivity that might require isolation of the control room. This places 

the unit in a condition that minimizes the accident risk. This does not 

preclude the movement of fuel to a safe position. ]

E.1

If both CREATCS trains are inoperable in MODE 1, 2, 3, or 4, the 

CREATCS may not be capable of performing the intended function and 

the unit is in a condition outside the accident analysis. Therefore, 

LCO 3.0.3 must be entered immediately. 

SURVEILLANCE SR 3.7.12.1

REQUIREMENTS 

This SR verifies that the heat removal capability of the system is sufficient 

to meet design requirements. This SR consists of a combination of 

testing and calculations. An [18] month Frequency is appropriate, since 

significant degradation of the CREATCS is slow and is not expected over 

this time period. 

REFERENCES 1. FSAR, Section [6.4]. 
ECCS PREACS 

B 3.7.13 

CEOG STS B 3.7.13-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.13 Emergency Core Cooling System (ECCS) Pump Room Exhaust Air Cleanup 

 System (PREACS) 

BASES 

BACKGROUND The ECCS PREACS filters air from the area of the active ECCS 

components during the recirculation phase of a loss of coolant accident 

(LOCA). The ECCS PREACS, in conjunction with other, normally 

operating systems, also provides environmental control of temperature 

and humidity in the ECCS pump room area and the lower reaches of the 

Auxiliary Building. 

The ECCS PREACS consists of two independent and redundant trains. 

Each train consists of a heater, a prefilter or demister, a high efficiency 

particulate air (HEPA) filter, an activated charcoal adsorber section for 

removal of gaseous activity (principally iodines), and a fan. Ductwork, 

valves or dampers, and instrumentation also form part of the system, as 

well as demisters functioning to reduce the relative humidity of the air 

stream. A second bank of HEPA filters follows the adsorber section to 

collect carbon fines and provide backup in case the main HEPA filter 

bank fails. The downstream HEPA filter is not credited in the accident 

analysis, but serves to collect charcoal fines and to back up the upstream 

HEPA filter, should it develop a leak. The system initiates filtered 

ventilation of the pump room and lower region of the Auxiliary Building 

following receipt of a safety injection actuation signal or coolant injection 

actuation signal. 

The ECCS PREACS is a standby system, parts of which may also 

operate during normal unit operations. The Reactor Auxiliary Building 

Main Ventilation System provides normal cooling. During emergency 

operations, the ECCS PREACS dampers are realigned and fans are 

started to initiate filtration. Upon receipt of the actuating Engineered 

Safety Feature Actuation System signal(s), normal air discharges from 

the ECCS pump room, the pump room is isolated, and the stream of 

ventilation air discharges through the system filter trains. The prefilters or 

demisters remove any large particles in the air, and any entrained water 

droplets present, to prevent excessive loading of the HEPA filters and 

charcoal adsorbers. 

The ECCS PREACS is discussed in the FSAR, Sections [6.5.1], [9.4.5], 

and [15.6.5] (Refs. 1, 2, and 3, respectively), as it may be used for 

normal, as well as post accident, atmospheric cleanup functions. The 

primary purpose of the heaters is to maintain the relative humidity at an 

acceptable level consistent with iodine removal efficiencies, as discussed 

in the Regulatory Guide 1.52 (Ref. 4). 
ECCS PREACS 

B 3.7.13 

CEOG STS B 3.7.13-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The design basis of the ECCS PREACS is established by the large break 

SAFETY LOCA. The system evaluation assumes a passive failure of the ECCS 

ANALYSES outside containment, such as safety injection pump seal failure, during 

the recirculation mode. In such a case, the system limits the radioactive 

release to within 10 CFR 100 limits (Ref. 5), or the NRC staff approved 

licensing basis (e.g., a specified fraction of 10 CFR 100 limits). The 

analysis of the effects and consequences of a large break LOCA is 

presented in Reference 3. The ECCS PREACS also actuates following a 

small break LOCA, requiring the unit to go into the recirculation mode of 

long term cooling and to clean up releases of smaller leaks, such as from 

valve stem packing. 

The two types of system failures that are considered in the accident 

analysis are complete loss of function and excessive LEAKAGE. Either 

type of failure may result in a lower efficiency of removal for any gaseous 

and particulate activity released to the ECCS pump rooms following a 

LOCA. 

The ECCS PREACS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Two independent and redundant ECCS PREACS trains are required to 

be OPERABLE to ensure that at least one is available, assuming a single 

failure disables the other train coincident with a loss of offsite power. 

Total system failure could result in the atmospheric release from the 

ECCS pump room exceeding the required limits in the event of a Design 

Basis Accident (DBA). 

ECCS PREACS is considered OPERABLE when the individual 

components necessary to maintain the ECCS Pump Room filtration are 

OPERABLE in both trains. 

An ECCS PREACS train is considered OPERABLE when its associated: 

a. Fan is OPERABLE, 

b. HEPA filter and charcoal adsorber are not excessively restricting flow 

and are capable of performing their filtration functions, and 

c. Heater, demister, ductwork, valves, and dampers are OPERABLE, 

and air circulation can be maintained. 
ECCS PREACS 

B 3.7.13 

CEOG STS B 3.7.13-3 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The LCO is modified by a Note allowing the ECCS pump room boundary 

to be opened intermittently under administrative controls. For entry and 

exit through doors, the administrative control of the opening is performed 

by the person(s) entering or exiting the area. For other openings, these 

controls consist of stationing a dedicated individual at the opening who is 

in continuous communication with the control room. This individual will 

have a method to rapidly close the opening when a need for ECCS pump 

room isolation is indicated. 

APPLICABILITY In MODES 1, 2, 3, and 4, the ECCS PREACS is required to be 

OPERABLE consistent with the OPERABILITY requirements of the 

ECCS. 

In MODES 5 and 6, the ECCS PREACS is not required to be 

OPERABLE, since the ECCS is not required to be OPERABLE. 

ACTIONS A.1

With one ECCS PREACS train inoperable, action must be taken to 

restore OPERABLE status within 7 days. During this time, the remaining 

OPERABLE train is adequate to perform the ECCS PREACS function. 

The 7 day Completion Time is appropriate because the risk contribution is 

less than that for the ECCS (72 hour Completion Time) and this system is 

not a direct support system for the ECCS. The 7 day Completion Time is 

reasonable, based on the low probability of a DBA occurring during this 

time period, and the consideration that the remaining train can provide the 

required capability. 

B.1

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Adoption of Condition B is dependent on a commitment from the licensee 

to have guidance available describing compensatory measures to be 

taken in the event of an intentional and unintentional entry into 

Condition B. 

-------------------------------------------------------------------------------------------------- 
ECCS PREACS 

B 3.7.13 

CEOG STS B 3.7.13-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

If the ECCS pump room boundary is inoperable, the ECCS PREACS 

trains cannot perform their intended functions. Actions must be taken to 

restore an OPERABLE ECCS pump room boundary within 24 hours. 

During the period that the ECCS pump room boundary is inoperable, 

appropriate compensatory measures [consistent with the intent, as 

applicable, of GDC 19, 60, 64 and 10 CFR Part 100] should be utilized to 

protect plant personnel from potential hazards such as radioactive 

contamination, toxic chemicals, smoke, temperature and relative 

humidity, and physical security. Preplanned measures should be 

available to address these concerns for intentional and unintentional entry 

into the condition. The 24 hour Completion Time is reasonable based on 

the low probability of a DBA occurring during this time period, and the use 

of compensatory measures. The 24 hour Completion Time is a typically 

reasonable time to diagnose, plan and possibly repair, and test most 

problems with the ECCS pump room boundary. 

C.1 and C.2

If the ECCS PREACS train or ECCS pump room boundary cannot be 

restored to OPERABLE status within the associated Completion Time, 

the unit must be in a MODE in which the LCO does not apply. To achieve 

this status, the unit must be placed in at least MODE 3 within 6 hours, 

and in MODE 5 within 36 hours. The allowed Completion Times are 

reasonable, based on operating experience, to reach the required unit 

conditions from full power conditions in an orderly manner and without 

challenging unit systems. 

SURVEILLANCE SR 3.7.13.1

REQUIREMENTS 

Standby systems should be checked periodically to ensure that they 

function properly. Since the environment and normal operating conditions 

on this system are not severe, testing each train once a month provides 

an adequate check on this system. Monthly heater operations dry out 

any moisture that may have accumulated in the charcoal from humidity in 

the ambient air. [Systems with heaters must be operated for ≥ 10 

continuous hours with the heaters energized. Systems without heaters 

need only be operated for ≥ 15 minutes to demonstrate the function of the 

system.] The 31 day Frequency is based on the known reliability of 

equipment, and the two train redundancy available. 
ECCS PREACS 

B 3.7.13 

CEOG STS B 3.7.13-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.7.13.2

This SR verifies that the required ECCS PREACS testing is performed in 

accordance with the [Ventilation Filter Testing Program (VFTP)]. The 

[VFTP] includes testing HEPA filter performance, charcoal adsorber 

efficiency, minimum system flow rate, and the physical properties of the 

activated charcoal (general use and following specific operations). 

Specific test frequencies and additional information are discussed in 

detail in the [VFTP]. 

SR 3.7.13.3

This SR verifies that each ECCS PREACS train starts and operates on an 

actual or simulated actuation signal. The [18] month Frequency is 

consistent with that specified in Regulatory Guide 1.52 (Ref. 4). 

SR 3.7.13.4

This SR verifies the integrity of the ECCS pump room enclosure. The 

ability of the ECCS pump room to maintain a negative pressure, with 

respect to potentially uncontaminated adjacent areas, is periodically 

tested to verify proper function of the ECCS PREACS. During the post 

accident mode of operation, the ECCS PREACS is designed to maintain 

a slight negative pressure in the ECCS pump room with respect to 

adjacent areas to prevent unfiltered LEAKAGE. The ECCS PREACS is 

designed to maintain this negative pressure at a flow rate of 

≤ [20,000] cfm from the ECCS pump room. The Frequency of 

[18] months is consistent with the guidance provided in the 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 

other filtration SRs. 

[ SR 3.7.13.5

Operating the ECCS PREACS filter bypass damper is necessary to 

ensure that the system functions properly. The OPERABILITY of the 

bypass damper is verified if it can be closed. An [18] month Frequency is 

consistent with that specified in Reference 4. ] 
ECCS PREACS 

B 3.7.13 

CEOG STS B 3.7.13-6 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Section [6.5.1]. 

 2. FSAR, Section [9.4.5]. 

 3. FSAR, Section [15.6.5]. 

 4. Regulatory Guide 1.52, Rev. [2]. 

 5. 10 CFR 100.11. 

 6. NUREG-0800, Section 6.5.1, Rev. 2, July 1981. 
FBACS 

B 3.7.14 

CEOG STS B 3.7.14-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.14 Fuel Building Air Cleanup System (FBACS) 

BASES 

BACKGROUND The FBACS filters airborne radioactive particulates from the area of the 

fuel pool following a fuel handling accident or loss of coolant 

accident. The FBACS, in conjunction with other normally operating 

systems, also provides environmental control of temperature and humidity 

in the fuel pool area. 

The FBACS consists of two independent, redundant trains. Each train 

consists of a heater, a prefilter or demister, a high efficiency particulate air 

(HEPA) filter, an activated charcoal adsorber section for removal of 

gaseous activity (principally iodines), and a fan. Ductwork, valves or 

dampers, and instrumentation also form part of the system, as well as 

demisters, functioning to reduce the relative humidity of the air stream. A 

second bank of HEPA filters follows the adsorber section to collect carbon 

fines and provide backup in case of failure of the main HEPA filter bank. 

The downstream HEPA filter is not credited in the analysis, but serves to 

collect charcoal fines, and to back up the upstream HEPA filter should it 

develop a leak. The system initiates filtered ventilation of the fuel 

handling building following receipt of a high radiation signal. 

The FBACS is a standby system, part of which may also be operated 

during normal unit operations. Upon receipt of the actuating signal, 

normal air discharges from the fuel handling building, the fuel handling 

building is isolated, and the stream of ventilation air discharges through 

the system filter trains. The prefilters or demisters remove any large 

particles in the air, and any entrained water droplets present, to prevent 

excessive loading of the HEPA filters and charcoal adsorbers. 

The FBACS is discussed in the FSAR, Sections [6.5.1], [9.4.5], 

and [15.7.4] (Refs. 1, 2, and 3, respectively), because it may be used for 

normal, as well as post accident, atmospheric cleanup functions. 

APPLICABLE The FBACS is designed to mitigate the consequences of a fuel handling 

SAFETY accident [involving handling recently irradiated fuel (i.e., fuel that has 

ANALYSES occupied part of a critical reactor core within the previous [X] days)] in 

which [all] rods in the fuel assembly are assumed to be damaged. The 

analysis of the fuel handling accident is given in Reference 3. The 
FBACS 

B 3.7.14 

CEOG STS B 3.7.14-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

Design Basis Accident analysis of the fuel handling accident assumes 

that only one train of the FBACS is functional, due to a single failure that 

disables the other train. The accident analysis accounts for the reduction 

in airborne radioactive material provided by the remaining one train of this 

filtration system. The amount of fission products available for release 

from the fuel handling building is determined for a fuel handling accident. 

These assumptions and the analysis follow the guidance provided in 

Regulatory Guide 1.25 (Ref. 4). 

The FBACS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Two independent and redundant trains of the FBACS are required to be 

OPERABLE to ensure that at least one is available, assuming a single 

failure that disables the other train coincident with a loss of offsite power. 

Total system failure could result in the atmospheric release from the fuel 

building exceeding the 10 CFR 100 limits (Ref. 5) in the event of a fuel 

handling accident. 

The FBACS is considered OPERABLE when the individual components 

necessary to control exposure in the fuel handling building are 

OPERABLE in both trains. An FBACS train is considered OPERABLE 

when its associated: 

a. Fan is OPERABLE, 

b. HEPA filter and charcoal adsorber are not excessively restricting 

flow, and are capable of performing their filtration functions, and 

c. Heater, demister, ductwork, valves, and dampers are OPERABLE, 

and air circulation can be maintained. 

The LCO is modified by a Note allowing the fuel building boundary to be 

opened intermittently under administrative controls. For entry and exit 

through doors, the administrative control of the opening is performed by 

the person(s) entering and exiting the area. For other openings, these 

controls consist of stationing a dedicated individual at the opening who is 

in continuous communication with the control room. This individual will 

have a method to rapidly close the opening when a need for fuel building 

isolation is indicated. 
FBACS 

B 3.7.14 

CEOG STS B 3.7.14-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY In MODES 1, 2, 3, and 4, the FBACS is required to be OPERABLE to 

provide fission product removal associated with ECCS leaks due to a 

LOCA (refer to LCO 3.7.13, "Emergency Core Cooling System (ECCS) 

Pump Room Exhaust Air Cleanup System (PREACS)") for units that use 

this system as part of their ECCS PREACS. 

During movement of [recently] irradiated fuel assemblies in the fuel 

building, the FBACS is required to be OPERABLE to mitigate the 

consequences of a fuel handling accident [involving handling recently 

irradiated fuel. Due to radioactive decay, FBACS is only required to 

mitigate fuel handling accidents involving handling recently irradiated fuel 

(i.e., fuel that has occupied part of a critical reactor core within the 

previous [X] days)]. 

In MODES 5 and 6, the FBACS is not required to be OPERABLE, since 

the ECCS is not required to be OPERABLE. 

ACTIONS LCO 3.0.3 is not applicable while in MODE 5 or 6. However, since 

irradiated fuel assembly movement can occur in MODE 1, 2, 3, or 4, the 

ACTIONS have been modified by a Note stating that LCO 3.0.3 is not 

applicable. If moving irradiated fuel assemblies while in MODE 5 or 6, 

LCO 3.0.3 would not specify any action. If moving irradiated fuel 

assemblies while in MODE 1, 2, 3, or 4, the fuel movement is 

independent of reactor operations. Entering LCO 3.0.3, while in MODE 1, 

2, 3, or 4 would require the unit to be shutdown unnecessarily. 

A.1

If one FBACS train is inoperable, action must be taken to restore 

OPERABLE status within 7 days. During this time period, the remaining 

OPERABLE train is adequate to perform the FBACS function. The 7 day 

Completion Time is reasonable, based on the risk from an event 

occurring requiring the inoperable FBACS train, and ability of the 

remaining FBACS train to provide the required protection. 

B.1

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Adoption of Condition B is dependent on a commitment from the licensee 

to have guidance available describing compensatory measures to be 

taken in the event of an intentional and unintentional entry into 

Condition B. 

-------------------------------------------------------------------------------------------------- 
FBACS 

B 3.7.14 

CEOG STS B 3.7.14-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

If the fuel building boundary is inoperable in MODE 1, 2, 3, or 4, the 

FBACS trains cannot perform their intended functions. Actions must be 

taken to restore an OPERABLE fuel building boundary within 24 hours. 

During the period that the fuel building boundary is inoperable, 

appropriate compensatory measures [consistent with the intent, as 

applicable, of GDC 19, 60, 61, 63, 64 and 10 CFR Part 100] should be 

utilized to protect plant personnel from potential hazards such as 

radioactive contamination, toxic chemicals, smoke, temperature and 

relative humidity, and physical security. Preplanned measures should be 

available to address these concerns for intentional and unintentional entry 

into the condition. The 24 hour Completion Time is reasonable based on 

the low probability of a DBA occurring during this time period, and the use 

of compensatory measures. The 24 hour Completion Time is a typically 

reasonable time to diagnose, plan and possibility repair, and test most 

problems with the fuel building boundary. 

[ C.1 and C.2

In MODE 1, 2, 3, or 4, when Required Action A.1 or B.1 cannot be 

completed within the Completion Time, or when both FBACS trains are 

inoperable for reasons other than an inoperable fuel building boundary 

(i.e., Condition B), the unit must be placed in a MODE in which the 

LCO does not apply. To achieve this status, the unit must be placed in 

MODE 3 within 6 hours, and in MODE 5 within 36 hours. The allowed 

Completion Times are reasonable, based on operating experience, to 

reach the required unit conditions from full power conditions in an orderly 

manner and without challenging unit systems. ]

D.1 and D.2

When Required Action A.1 cannot be completed within the required 

Completion Time during movement of [recently] irradiated fuel assemblies 

in the fuel building, the OPERABLE FBACS train must be started 

immediately or fuel movement suspended. This action ensures that the 

remaining train is OPERABLE, that no undetected failures preventing 

system operation will occur, and that any active failure will be readily 

detected. 

If the system is not placed in operation, this action requires suspension of 

[recently] irradiated fuel movement, which precludes a fuel handling 

accident. This does not preclude the movement of fuel to a safe position. 
FBACS 

B 3.7.14 

CEOG STS B 3.7.14-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

E.1

When two trains of the FBACS are inoperable during movement of 

[recently] irradiated fuel assemblies in the fuel building, action must be 

taken to place the unit in a condition in which the LCO does not apply. 

This LCO involves immediately suspending movement of [recently] 

irradiated fuel assemblies in the fuel building. This does not preclude the 

movement of fuel to a safe position. 

SURVEILLANCE SR 3.7.14.1

REQUIREMENTS 

Standby systems should be checked periodically to ensure that they 

function properly. As the environment and normal operating conditions 

on this system are not severe, testing each train once every month 

provides an adequate check on this system. Monthly heater operation 

dries out any moisture accumulated in the charcoal from humidity in the 

ambient air. [Systems with heaters must be operated for ≥ 10 continuous 

hours with the heaters energized. Systems without heaters need only be 

operated for ≥ 15 minutes to demonstrate the function of the system.] 

The 31 day Frequency is based on the known reliability of the equipment 

and the two train redundancy available. 

SR 3.7.14.2

This SR verifies the performance of FBACS filter testing in accordance 

with the [Ventilation Filter Testing Program (VFTP)]. The [VFTP] includes 

testing HEPA filter performance, charcoal adsorber efficiency, minimum 

system flow rate, and the physical properties of the activated charcoal 

(general use and following specific operations). Specific test frequencies 

and additional information are discussed in detail in the [VFTP]. 

[ SR 3.7.14.3

This SR verifies that each FBACS train starts and operates on an actual 

or simulated actuation signal. The [18] month Frequency is consistent 

with that specified in Reference 6. ]
FBACS 

B 3.7.14 

CEOG STS B 3.7.14-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.7.14.4

This SR verifies the integrity of the fuel building enclosure. The ability of 

the fuel building to maintain negative pressure with respect to potentially 

uncontaminated adjacent areas is periodically tested to verify proper 

function of the FBACS. During the post accident mode of operation, the 

FBACS is designed to maintain a slight negative pressure in the fuel 

building, with respect to adjacent areas, to prevent unfiltered LEAKAGE. 

The FBACS is designed to maintain this negative pressure at a flow rate 

of ≤ [3000] cfm to the fuel building. The Frequency of [18] months is 

consistent with the guidance provided in NUREG-0800, Section 6.5.1 

(Ref. 7). 

This test is conducted with the tests for filter penetration; thus, an 

[18] month Frequency, on a STAGGERED TEST BASIS is consistent with 

other filtration SRs. 

[ SR 3.7.14.5

Operating the FBACS filter bypass damper is necessary to ensure that 

the system functions properly. The OPERABILITY of the FBACS filter 

bypass damper is verified if it can be closed. The 18 month Frequency is 

consistent with that specified in Reference 6. ] 

REFERENCES 1. FSAR, Section [6.5.1]. 

 2. FSAR, Section [9.4.5]. 

 3. FSAR, Section [15.7.4]. 

 4. Regulatory Guide 1.25. 

 5. 10 CFR 100. 

 6. Regulatory Guide 1.52, Rev. [2]. 

 7. NUREG-0800, Section 6.5.1, July 1981. 
PREACS 

B 3.7.15 

CEOG STS B 3.7.15-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.15 Penetration Room Exhaust Air Cleanup System (PREACS) 

BASES 

BACKGROUND The PREACS filters air from the penetration area between containment 

and the Auxiliary Building. 

The PREACS consists of two independent and redundant trains. Each 

train consists of a heater, a prefilter or demister, a high efficiency 

particulate air (HEPA) filter, an activated charcoal adsorber section for 

removal of gaseous activity (principally iodines), and a fan. Ductwork, 

valves or dampers, and instrumentation also form part of the system, as 

well as demisters functioning to reduce the relative humidity of the air 

stream. A second bank of HEPA filters, which follows the adsorber 

section, collects carbon fines and provides backup in case of failure of the 

main HEPA filter bank. The downstream HEPA filter, although not 

credited in the accident analysis, collects charcoal fines and serves as a 

backup should the upstream HEPA filter develop a leak. The system 

initiates filtered ventilation following receipt of a safety injection actuation 

signal or containment isolation actuation signal. 

The PREACS is a standby system, parts of which may also operate 

during normal unit operations. During emergency operations, the 

PREACS dampers are realigned, and fans are started to initiate filtration. 

Upon receipt of the actuating Engineered Safety Feature Actuation 

System signal(s), normal air discharges from the penetration room, the 

penetration room is isolated, and the stream of ventilation air discharges 

through the system filter trains. The prefilters or demisters remove any 

large particles in the air, as well as any entrained water droplets, to 

prevent excessive loading of the HEPA filters and charcoal adsorbers. 

The PREACS is discussed in the FSAR, Sections [6.5.1], [9.4.5], 

and [15.6.5] (Refs. 1, 2, and 3, respectively), as it may be used for 

normal, as well as post accident, atmospheric cleanup functions. Heaters 

may be included for moisture removal on systems operating in high 

humidity conditions. The primary purpose of the heaters is to maintain 

the relative humidity at an acceptable level, consistent with iodine 

removal efficiencies, as discussed in the Regulatory Guide 1.52 (Ref. 4). 
PREACS 

B 3.7.15 

CEOG STS B 3.7.15-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The design basis of the PREACS is established by the large break loss 

SAFETY of coolant accident (LOCA). The system evaluation assumes a passive 

ANALYSES failure outside containment, such as a valve packing leakage during a 

Design Basis Accident (DBA). In such a case, the system restricts the 

radioactive release to within 10 CFR 100 (Ref. 5) limits, or the NRC staff 

approved licensing basis (e.g., a specified fraction of 10 CFR 100 limits). 

The analysis of the effects and consequences of a large break LOCA are 

presented in Reference 3. 

There are two types of system failures considered in the accident 

analysis: a complete loss of function and an excessive LEAKAGE. Either 

type of failure may result in less efficient removal for any gaseous or 

particulate material released to the penetration rooms following a LOCA. 

The PREACS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Two independent and redundant trains of the PREACS are required to be 

OPERABLE to ensure that at least one train is available, assuming there 

is a single failure disabling the other train coincident with a loss of offsite 

power. 

The PREACS is considered OPERABLE when the individual components 

necessary to control radioactive releases are OPERABLE in both trains. 

A PREACS train is considered OPERABLE when its associated: 

a. Fan is OPERABLE, 

b. HEPA filter and charcoal absorber are not excessively restricting 

flow, and are capable of performing the filtration functions, and 

c. Heater, demister, ductwork, valves, and dampers are OPERABLE, 

and circulation can be maintained. 

The LCO is modified by a Note allowing the penetration room boundary to 

be opened intermittently under administrative controls. For entry and exit 

through doors, the administrative control of the opening is performed by 

the person(s) entering or exiting the area. For other openings, these 

controls consist of stationing a dedicated individual at the opening who is 

in continuous communication with the control room. This individual will 

have a method to rapidly close the opening when a need for penetration 

room isolation is indicated. 

APPLICABILITY In MODES 1, 2, 3, and 4, the PREACS is required to be OPERABLE, 

consistent with the OPERABILITY requirements of the Emergency Core 

Cooling System (ECCS). 

In MODES 5 and 6, the PREACS is not required to be OPERABLE, since 

the ECCS is not required to be OPERABLE. 
PREACS 

B 3.7.15 

CEOG STS B 3.7.15-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

With one PREACS train inoperable, action must be taken to restore 

OPERABLE status within 7 days. During this time period, the remaining 

OPERABLE train is adequate to perform the PREACS function. The 

7 day Completion Time is appropriate because the risk contribution of the 

PREACS is less than that for the ECCS (72 hour Completion Time), and 

because this system is not a direct support system for the ECCS. The 

7 day Completion Time is reasonable based on the low probability of a 

DBA occurring during this time period, and the consideration that the 

remaining train can provide the required capability. 

B.1

-----------------------------------REVIEWER’S NOTE----------------------------------- 

Adoption of Condition B is dependent on a commitment from the licensee 

to have guidance available describing compensatory measures to be 

taken in the event of an intentional and unintentional entry into 

Condition B. 

-------------------------------------------------------------------------------------------------- 

If the penetration room boundary is inoperable, the PREACS trains 

cannot perform their intended functions. Actions must be taken to restore 

an OPERABLE penetration room boundary within 24 hours. During the 

period that the penetration room boundary is inoperable, appropriate 

compensatory measures [consistent with the intent, as applicable, of 

GDC 19, 60, 64 and 10 CFR Part 100] should be utilized to protect plant 

personnel from potential hazards such as radioactive contamination, toxic 

chemicals, smoke, temperature and relative humidity, and physical 

security. Preplanned measures should be available to address these 

concerns for intentional and unintentional entry into the condition. The 

24 hour Completion Time is reasonable based on the low probability of a 

DBA occurring during this time period, and the use of compensatory 

measures. The 24 hour Completion Time is reasonable based on the low 

probability of a DBA occurring during this time period, and the use of 

compensatory measures. The 24 hour Completion Time is a typically 

reasonable time to diagnose, plan and possibly repair, and test most 

problems with the penetration room boundary. 
PREACS 

B 3.7.15 

CEOG STS B 3.7.15-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1 and C.2

If the inoperable PREACS train or penetration room boundary cannot be 

restored to OPERABLE status within the associated Completion Time, 

the unit must be placed in a MODE in which the LCO does not apply. To 

achieve this status, the unit must be placed in at least MODE 3 within 

6 hours, and in MODE 5 within 36 hours. The allowed Completion Times 

are reasonable, based on operating experience, to reach the required unit 

conditions from full power conditions in an orderly manner and without 

challenging unit systems. 

SURVEILLANCE SR 3.7.15.1

REQUIREMENTS 

Standby systems should be checked periodically to ensure that they 

function properly. As the environment and normal operating conditions 

on this system are not severe, testing each train once every month 

provides an adequate check on this system. 

Monthly heater operation dries out any moisture that may have 

accumulated in the charcoal as a result of humidity in the ambient air. 

[Systems with heaters must be operated for ≥ 10 continuous hours with 

the heaters energized. Systems without heaters need only be operated 

for ≥ 15 minutes to demonstrate the function of the system.] The 31 day 

Frequency is based on the known reliability of the equipment and the two 

train redundancy available. 

SR 3.7.15.2

This SR verifies the performance of PREACS filter testing in accordance 

with the [Ventilation Filter Testing Program (VFTP)]. The [VFTP] includes 

testing the performance of the HEPA filter, charcoal adsorber efficiency, 

minimum system flow rate, and the physical properties of the activated 

charcoal (general use and following specific operations). Specific test 

frequencies and additional information are discussed in detail in the 

[VFTP]. 

[ SR 3.7.15.3

This SR verifies that each PREACS train starts and operates on an actual 

or simulated actuation signal. The [18] month Frequency is consistent 

with that specified in Reference 4. ]
PREACS 

B 3.7.15 

CEOG STS B 3.7.15-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

[ SR 3.7.15.4

This SR verifies the integrity of the penetration room enclosure. The 

ability of the penetration room to maintain negative pressure, with respect 

to potentially uncontaminated adjacent areas, is periodically tested to 

verify proper function of the PREACS. During the post accident mode of 

operation, PREACS is designed to maintain a slightly negative pressure 

at a flow rate of ≤ [3000] cfm in the penetration room with respect to 

adjacent areas to prevent unfiltered LEAKAGE. The Frequency of 

[18] months is consistent with the guidance provided in NUREG-0800, 

Section 6.5.1 (Ref. 6). ]

[ The minimum system flow rate maintains a slight negative pressure in the 

penetration room area and provides sufficient air velocity to transport 

particulate contaminants, assuming only one filter train is operating. 

The number of filter elements is selected to limit the flow rate through any 

individual element to about [1000] cfm. This may vary based on filter 

housing geometry. The maximum limit ensures that flow through, and 

pressure drop across, each filter element is not excessive. 

The number and depth of the adsorber elements ensures that, at the 

maximum flow rate, the residence time of the air stream in the charcoal 

bed achieves the desired adsorption rate. At least a [0.125] second 

residence time is necessary for an assumed [99]% efficiency. 

The filters have a certain pressure drop at the design flow rate when 

clean. The magnitude of the pressure drop indicates acceptable 

performance, and is based on manufacturer's recommendations for the 

filter and adsorber elements at the design flow rate. An increase in 

pressure drop or decrease in flow indicates that the filter is being loaded 

or is indicative of other problems with the system. 

This test is conducted with the tests for filter penetration; thus, an 

[18] month Frequency on a STAGGERED TEST BASIS consistent with 

other filtration SRs. ]

[ SR 3.7.15.5

Operating the PREACS filter bypass damper is necessary to ensure that 

the system functions properly. The OPERABILITY of the PREACS filter 

bypass damper is verified if it can be closed. An [18] month Frequency is 

consistent with that specified in Reference 4. ] 
PREACS 

B 3.7.15 

CEOG STS B 3.7.15-6 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Section [6.5.1]. 

 2. FSAR, Section [9.4.5]. 

 3. FSAR, Section [15.6.5]. 

 4. Regulatory Guide 1.52 Rev. [2]. 

 5. 10 CFR 100.11. 

 6. NUREG-0800, Section 6.5.1. 
Fuel Storage Pool Water Level 

B 3.7.16 

CEOG STS B 3.7.16-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.16 Fuel Storage Pool Water Level 

BASES 

BACKGROUND The minimum water level in the fuel storage pool meets the assumptions 

of iodine decontamination factors following a fuel handling accident. The 

specified water level shields and minimizes the general area dose when 

the storage racks are filled to their maximum capacity. The water also 

provides shielding during the movement of spent fuel. 

A general description of the fuel storage pool design is given in the FSAR, 

Section [9.1.2], Reference 1, and the Spent Fuel Pool Cooling and 

Cleanup System is given in the FSAR, Section [9.1.3] (Ref. 2). The 

assumptions of the fuel handling accident are given in the FSAR, 

Section [15.7.4] (Ref. 3). 

APPLICABLE The minimum water level in the fuel storage pool meets the assumptions 

SAFETY of the fuel handling accident described in Regulatory Guide 1.25 (Ref. 4). 

ANALYSES The resultant 2 hour thyroid dose to a person at the exclusion area 

boundary is a small fraction of the 10 CFR 100 (Ref. 5) limits. 

According to Reference 4, there is 23 ft of water between the top of the 

damaged fuel bundle and the fuel pool surface for a fuel handling 

accident. With a 23 ft water level, the assumptions of Reference 4 can be 

used directly. In practice, this LCO preserves this assumption for the bulk 

of the fuel in the storage racks. In the case of a single bundle, dropped 

and lying horizontally on top of the spent fuel racks, however, there may 

be < 23 ft of water above the top of the bundle and the surface, by the 

width of the bundle. To offset this small nonconservatism, the analysis 

assumes that all fuel rods fail, although analysis shows that only the first 

few rods fail from a hypothetical maximum drop. 

The fuel storage pool water level satisfies Criteria 2 and 3 of 

10 CFR 50.36(c)(2)(ii). 

LCO The specified water level preserves the assumptions of the fuel handling 

accident analysis (Ref. 3). As such, it is the minimum required for fuel 

storage and movement within the fuel storage pool. 

APPLICABILITY This LCO applies during movement of irradiated fuel assemblies in the 

fuel storage pool since the potential for a release of fission products 

exists. 
Fuel Storage Pool Water Level 

B 3.7.16 

CEOG STS B 3.7.16-2 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

Required Action A.1 is modified by a Note indicating that LCO 3.0.3 does 

not apply. 

When the initial conditions for an accident cannot be met, steps should be 

taken to preclude the accident from occurring. When the fuel storage 

pool water level is lower than the required level, the movement of 

irradiated fuel assemblies in the fuel storage pool is immediately 

suspended. This effectively precludes a spent fuel handling accident 

from occurring. This does not preclude moving a fuel assembly to a safe 

position. 

If moving irradiated fuel assemblies while in MODE 5 or 6, LCO 3.0.3 

would not specify any action. If moving irradiated fuel assemblies while in 

MODES 1, 2, 3, and 4, the fuel movement is independent of reactor 

operations. Therefore, in either case, inability to suspend movement of 

irradiated fuel assemblies is not sufficient reason to require a reactor 

shutdown. 

SURVEILLANCE SR 3.7.16.1

REQUIREMENTS 

This SR verifies sufficient fuel storage pool water is available in the event 

of a fuel handling accident. The water level in the fuel storage pool must 

be checked periodically. The 7 day Frequency is appropriate because 

the volume in the pool is normally stable. Water level changes are 

controlled by unit procedures and are acceptable, based on operating 

experience. 

During refueling operations, the level in the fuel storage pool is at 

equilibrium with that of the refueling canal, and the level in the refueling 

canal is checked daily in accordance with LCO 3.7.17, "Fuel Storage Pool 

Boron Concentration." 

REFERENCES 1. FSAR, Section [9.1.2]. 

 2. FSAR, Section [9.1.3]. 

 3. FSAR, Section [15.7.4]. 

 4. Regulatory Guide 1.25. 

 5. 10 CFR 100.11. 
Fuel Storage Pool Boron Concentration 

B 3.7.17 

CEOG STS B 3.7.17-1 Rev. 2.2, 

B 3.7 PLANT SYSTEMS 

B 3.7.17 Fuel Storage Pool Boron Concentration 

BASES 

BACKGROUND As described in LCO 3.7.18, "Spent Fuel Assembly Storage," fuel 

assemblies are stored in the spent fuel racks [in a "checkerboard" pattern] 

in accordance with criteria based on [initial enrichment and discharge 

burnup]. Although the water in the spent fuel pool is normally borated to 

≥ [1800] ppm, the criteria that limit the storage of a fuel assembly to 

specific rack locations is conservatively developed without taking credit 

for boron. 

APPLICABLE A fuel assembly could be inadvertently loaded into a spent fuel rack 

SAFETY location not allowed by LCO 3.7.18 (e.g., an unirradiated fuel assembly 

ANALYSES or an insufficiently depleted fuel assembly). This accident is analyzed 

assuming the extreme case of completely loading the fuel pool racks with 

unirradiated assemblies of maximum enrichment. Another type of 

postulated accident is associated with a fuel assembly that is dropped 

onto the fully loaded fuel pool storage rack. Either incident could have a 

positive reactivity effect, decreasing the margin to criticality. However, 

the negative reactivity effect of the soluble boron compensates for the 

increased reactivity caused by either one of the two postulated accident 

scenarios. 

The concentration of dissolved boron in the fuel pool satisfies Criterion 2 

of 10 CFR 50.36(c)(2)(ii). 

LCO The specified concentration of dissolved boron in the fuel pool preserves 

the assumptions used in the analyses of the potential accident scenarios 

described above. This concentration of dissolved boron is the minimum 

required concentration for fuel assembly storage and movement within 

the fuel pool. 

APPLICABILITY This LCO applies whenever fuel assemblies are stored in the spent fuel 

pool until a complete spent fuel pool verification has been performed 

following the last movement of fuel assemblies in the spent fuel pool. 

This LCO does not apply following the verification since the verification 

would confirm that there are no misloaded fuel assemblies. With no 

further fuel assembly movements in progress, there is no potential for a 

misloaded fuel assembly or a dropped fuel assembly. 
Fuel Storage Pool Boron Concentration 

B 3.7.17 

CEOG STS B 3.7.17-2 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1, A.2.1, and A.2.2

The Required Actions are modified by a Note indicating that LCO 3.0.3 

does not apply. 

When the concentration of boron in the spent fuel pool is less than 

required, immediate action must be taken to preclude an accident from 

happening or to mitigate the consequences of an accident in progress. 

This is most efficiently achieved by immediately suspending the 

movement of fuel assemblies. This does not preclude the movement of 

fuel assemblies to a safe position. In addition, action must be 

immediately initiated to restore boron concentration to within limit. 

Alternately, beginning a verification of the fuel storage pool fuel locations, 

to ensure proper locations of the fuel, can be performed. 

If moving irradiated fuel assemblies while in MODE 5 or 6, LCO 3.0.3 

would not specify any action. If moving irradiated fuel assemblies while in 

MODE 1, 2, 3, or 4, the fuel movement is independent of reactor 

operation. Therefore, inability to suspend movement of fuel assemblies is 

not sufficient reason to require a reactor shutdown. 

SURVEILLANCE SR 3.7.17.1

REQUIREMENTS 

This SR verifies that the concentration of boron in the spent fuel pool is 

within the required limit. As long as this SR is met, the analyzed incidents 

are fully addressed. The 7 day Frequency is appropriate because no 

major replenishment of pool water is expected to take place over a short 

period of time. 

REFERENCES None. 
Spent Fuel Pool Storage 

B 3.7.18 

CEOG STS B 3.7.18-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.18 Spent Fuel Pool Storage 

BASES 

BACKGROUND The spent fuel storage facility is designed to store either new 

(nonirradiated) nuclear fuel assemblies, or burned (irradiated) fuel 

assemblies in a vertical configuration underwater. The storage pool is 

sized to store [735] fuel assemblies, which includes storage for [15] failed 

fuel containers. The spent fuel storage cells are installed in parallel rows 

with center to center spacing of [12 31/32] inches in one direction, and 

[13 3/16] inches in the other orthogonal direction. This spacing and "flux 

trap" construction, whereby the fuel assemblies are inserted into neutron 

absorbing stainless steel cans, is sufficient to maintain a keff of ≤ 0.95 for 

spent fuel of original enrichment of up to [3.3]%. However, as higher 

initial enrichment fuel assemblies are stored in the spent fuel pool, they 

must be stored in a checkerboard pattern taking into account fuel burnup 

to maintain a keff of 0.95 or less. 

APPLICABLE The spent fuel storage facility is designed for noncriticality by use of 

SAFETY adequate spacing, and "flux trap" construction whereby the fuel 

ANALYSES assemblies are inserted into neutron absorbing stainless steel cans. 

The spent fuel pool storage satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO The restrictions on the placement of fuel assemblies within the spent fuel 

pool, according to [Figure 3.7.18-1], in the accompanying LCO, ensures 

that the keff of the spent fuel pool will always remain < 0.95 assuming the 

pool to be flooded with unborated water. The restrictions are consistent 

with the criticality safety analysis performed for the spent fuel pool 

according to [Figure 3.7.18-1], in the accompanying LCO. Fuel 

assemblies not meeting the criteria of [Figure 3.7.18-1] shall be stored in 

accordance with Specification 4.3.1.1. 

APPLICABILITY This LCO applies whenever any fuel assembly is stored in [Region 2] of 

the spent fuel pool. 

ACTIONS A.1

Required Action A.1 is modified by a Note indicating that LCO 3.0.3 does 

not apply. 

When the configuration of fuel assemblies stored in [Region 2] the spent 

fuel pool is not in accordance with Figure [3.7.18-1], immediate action 

must be taken to make the necessary fuel assembly movement(s) to 

bring the configuration into compliance with Figure [3.7.18-1]. 
Spent Fuel Pool Storage 

B 3.7.18 

CEOG STS B 3.7.18-2 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

If moving irradiated fuel assemblies while in MODE 5 or 6, LCO 3.0.3 

would not specify any action. If moving irradiated fuel assemblies while in 

MODE 1, 2, 3, or 4, the fuel movement is independent of reactor 

operation. Therefore, in either case, inability to move fuel assemblies is 

not sufficient reason to require a reactor shutdown. 

SURVEILLANCE SR 3.7.18.1

REQUIREMENTS 

This SR verifies by administrative means that the initial enrichment and 

burnup of the fuel assembly is in accordance with Figure [3.7.18-1] in the 

accompanying LCO. For fuel assemblies in the unacceptable range of 

[Figure 3.7.18-1], performance of this SR will ensure compliance with 

Specification 4.3.1.1. 

REFERENCES None. 
Secondary Specific Activity 

B 3.7.19 

CEOG STS B 3.7.19-1 Rev. 3.0, 03/31/04 

B 3.7 PLANT SYSTEMS 

B 3.7.19 Secondary Specific Activity 

BASES 

BACKGROUND Activity in the secondary coolant results from steam generator tube 

outleakage from the Reactor Coolant System (RCS). Under steady state 

conditions, the activity is primarily iodines with relatively short half lives, 

and thus is indication of current conditions. During transients, I-131 

spikes have been observed as well as increased releases of some noble 

gases. Other fission product isotopes, as well as activated corrosion 

products in lesser amounts, may also be found in the secondary coolant. 

A limit on secondary coolant specific activity during power operation 

minimizes releases to the environment because of normal operation, 

anticipated operational occurrences, and accidents. 

This limit is lower than the activity value that might be expected from a 

1 gpm tube leak (LCO 3.4.13, "RCS Operational LEAKAGE") of primary 

coolant at the limit of 1.0 μCi/gm (LCO 3.4.16, "RCS Specific Activity"). 

The steam line failure is assumed to result in the release of the noble gas 

and iodine activity contained in the steam generator inventory, the 

feedwater, and reactor coolant LEAKAGE. Most of the isotopes have 

short half-lives (i.e., < 20 hours). 

With the specified activity level, the resultant 2 hour thyroid dose to a 

person at the exclusion area boundary (EAB) would be about [.13] rem 

should the main steam safety valves (MSSVs) open for the 2 hours 

following a trip from full power. 

Operating a unit at the allowable limits could result in a 2 hour EAB 

exposure of a small fraction of the 10 CFR 100 (Ref. 1) limits. 

APPLICABLE The accident analysis of the main steam line break (MSLB), as discussed 

SAFETY in the FSAR, Chapter [15] (Ref. 2), assumes the initial secondary coolant 

ANALYSES specific activity to have a radioactive isotope concentration of 

[0.10] μCi/gm DOSE EQUIVALENT I-131. This assumption is used in the 

analysis for determining the radiological consequences of the postulated 

accident. The accident analysis, based on this and other assumptions, 

shows that the radiological consequences of an MSLB do not exceed a 

small fraction of the unit EAB limits (Ref. 1) for whole body and thyroid 

dose rates. 
Secondary Specific Activity 

B 3.7.19 

CEOG STS B 3.7.19-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

With the loss of offsite power, the remaining steam generator is available 

for core decay heat dissipation by venting steam to the atmosphere 

through MSSVs and atmospheric dump valves (ADVs). The Auxiliary 

Feedwater System supplies the necessary makeup to the steam 

generator. Venting continues until the reactor coolant temperature and 

pressure have decreased sufficiently for the Shutdown Cooling System to 

complete the cooldown. 

In the evaluation of the radiological consequences of this accident, the 

activity released from the steam generator connected to the failed steam 

line is assumed to be released directly to the environment. The 

unaffected steam generator is assumed to discharge steam and any 

entrained activity through MSSVs and ADVs during the event. 

Secondary specific activity limits satisfy Criterion 2 of 

10 CFR 50.36(c)(2)(ii). 

LCO As indicated in the Applicable Safety Analyses, the specific activity limit in 

the secondary coolant system of ≤ [0.10] μCi/gm DOSE 

EQUIVALENT I-131 to limit the radiological consequences of a Design 

Basis Accident (DBA) to a small fraction of the required limit (Ref. 1). 

Monitoring the specific activity of the secondary coolant ensures that 

when secondary specific activity limits are exceeded, appropriate actions 

are taken in a timely manner to place the unit in an operational MODE 

that would minimize the radiological consequences of a DBA. 

APPLICABILITY In MODES 1, 2, 3, and 4, the limits on secondary specific activity apply 

due to the potential for secondary steam releases to the atmosphere. 

In MODES 5 and 6, the steam generators are not being used for heat 

removal. Both the RCS and steam generators are depressurized, and 

primary to secondary LEAKAGE is minimal. Therefore, monitoring of 

secondary specific activity is not required. 
Secondary Specific Activity 

B 3.7.19 

CEOG STS B 3.7.19-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1 and A.2

DOSE EQUIVALENT I-131 exceeding the allowable value in the 

secondary coolant, is an indication of a problem in the RCS, and 

contributes to increased post accident doses. If secondary specific 

activity cannot be restored to within limits in the associated Completion 

Time, the unit must be placed in a MODE in which the LCO does not 

apply. To achieve this status, the unit must be placed in at least MODE 3 

within 6 hours, and in MODE 5 within 36 hours. The allowed Completion 

Times are reasonable, based on operating experience, to reach the 

required unit conditions from full power conditions in an orderly manner 

and without challenging unit systems. 

SURVEILLANCE SR 3.7.19.1

REQUIREMENTS 

This SR ensures that the secondary specific activity is within the limits of 

the accident analysis. A gamma isotope analysis of the secondary 

coolant, which determines DOSE EQUIVALENT I-131, confirms the 

validity of the safety analysis assumptions as to the source terms in post 

accident releases. It also serves to identify and trend any unusual 

isotopic concentrations that might indicate changes in reactor coolant 

activity or LEAKAGE. 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. 

REFERENCES 1. 10 CFR 100.11. 

 2. FSAR, Chapter [15]. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-1 Rev. 3.0, 03/31/04 

B 3.8 ELECTRICAL POWER SYSTEMS 

B 3.8.1 AC Sources - Operating 

BASES 

BACKGROUND The unit Class 1E Electrical Power Distribution System AC sources 

consist of the offsite power sources (preferred power sources, normal and 

alternate(s)), and the onsite standby power sources (Train A and Train B 

diesel generators (DGs)). As required by 10 CFR 50, Appendix A, 

GDC 17 (Ref. 1), the design of the AC electrical power system provides 

independence and redundancy to ensure an available source of power to 

the Engineered Safety Feature (ESF) systems. 

The onsite Class 1E AC Distribution System is divided into redundant 

load groups (trains) so that the loss of any one group does not prevent 

the minimum safety functions from being performed. Each train has 

connections to two preferred offsite power sources and a single DG. 

Offsite power is supplied to the unit switchyard(s) from the transmission 

network by [two] transmission lines. From the switchyard(s), two 

electrically and physically separated circuits provide AC power, through 

[step down station auxiliary transformers], to the 4.16 kV ESF buses. A 

detailed description of the offsite power network and the circuits to the 

Class 1E ESF buses is found in the FSAR, Chapter [8] (Ref. 2). 

An offsite circuit consists of all breakers, transformers, switches, 

interrupting devices, cabling, and controls required to transmit power from 

the offsite transmission network to the onsite Class 1E ESF bus or buses. 

Certain required unit loads are returned to service in a predetermined 

sequence in order to prevent overloading the transformer supplying offsite 

power to the onsite Class 1E Distribution System. Within [1 minute] after 

the initiating signal is received, all automatic and permanently connected 

loads needed to recover the unit or maintain it in a safe condition are 

returned to service via the load sequencer. 

The onsite standby power source for each 4.16 kV ESF bus is a 

dedicated DG. DGs [11] and [12] are dedicated to ESF buses [11] 

and [12], respectively. A DG starts automatically on a safety injection (SI) 

signal (i.e., low pressurizer pressure or high containment pressure 

signals) or on an [ESF bus degraded voltage or undervoltage signal]. 

After the DG has started, it will automatically tie to its respective bus after 

offsite power is tripped as a consequence of ESF bus undervoltage or 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

degraded voltage, independent of or coincident with an SI signal. The 

DGs will also start and operate in the standby mode without tying to the 

ESF bus on an SI signal alone. Following the trip of offsite power, [a 

sequencer/an undervoltage signal] strips nonpermanent loads from the 

ESF bus. When the DG is tied to the ESF bus, loads are then 

sequentially connected to its respective ESF bus by the automatic load 

sequencer. The sequencing logic controls the permissive and starting 

signals to motor breakers to prevent overloading the DG by automatic 

load application. 

In the event of a loss of preferred power, the ESF electrical loads are 

automatically connected to the DGs in sufficient time to provide for safe 

reactor shutdown and to mitigate the consequences of a Design Basis 

Accident (DBA) such as a loss of coolant accident (LOCA). 

Certain required unit loads are returned to service in a predetermined 

sequence in order to prevent overloading the DG in the process. Within 

[1] minute after the initiating signal is received, all loads needed to 

recover the unit or maintain it in a safe condition are returned to service. 

Ratings for Train A and Train B DGs satisfy the requirements of 

Regulatory Guide 1.9 (Ref. 3). The continuous service rating of each DG 

is [7000] kW with [10]% overload permissible for up to 2 hours in any 

24 hour period. The ESF loads that are powered from the 4.16 kV 

ESF buses are listed in Reference 2. 

APPLICABLE The initial conditions of DBA and transient analyses in the FSAR, 

SAFETY Chapter [6] (Ref. 4) and Chapter [15] (Ref. 5), assume ESF systems are 

ANALYSES OPERABLE. The AC electrical power sources are designed to provide 

sufficient capacity, capability, redundancy, and reliability to ensure the 

availability of necessary power to ESF systems so that the fuel, Reactor 

Coolant System (RCS), and containment design limits are not exceeded. 

These limits are discussed in more detail in the Bases for Section 3.2, 

Power Distribution Limits; Section 3.4, Reactor Coolant System (RCS); 

and Section 3.6, Containment Systems. 

The OPERABILITY of the AC electrical power sources is consistent with 

the initial assumptions of the accident analyses and is based upon 

meeting the design basis of the unit. This results in maintaining at least 

one train of the onsite or offsite AC sources OPERABLE during accident 

conditions in the event of: 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

a. An assumed loss of all offsite power or all onsite AC power and 

b. A worst case single failure. 

The AC sources satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Two qualified circuits between the offsite transmission network and the 

onsite Class 1E Electrical Power Distribution System and separate and 

independent DGs for each train ensure availability of the required power 

to shut down the reactor and maintain it in a safe shutdown condition after 

an anticipated operational occurrence (AOO) or a postulated DBA. 

Qualified offsite circuits are those that are described in the FSAR and are 

part of the licensing basis for the unit. 

[ In addition, one required automatic load sequencer per train must be 

OPERABLE. ]

Each offsite circuit must be capable of maintaining rated frequency and 

voltage, and accepting required loads during an accident, while 

connected to the ESF buses. 

[ Offsite circuit #1 consists of Safeguards Transformer B, which is supplied 

from Switchyard Bus B, and is fed through breaker 52-3 powering the 

ESF transformer XNB01, which, in turn, powers the #1 ESF bus through 

its normal feeder breaker. Offsite circuit #2 consists of the Startup 

Transformer, which is normally fed from the Switchyard Bus A, and is fed 

through breaker PA 0201 powering the ESF transformer, which, in turn, 

powers the #2 ESF bus through its normal feeder breaker. ]

Each DG must be capable of starting, accelerating to rated speed and 

voltage, and connecting to its respective ESF bus on detection of bus 

undervoltage. This will be accomplished within [10] seconds. Each DG 

must also be capable of accepting required loads within the assumed 

loading sequence intervals, and continue to operate until offsite power 

can be restored to the ESF buses. These capabilities are required to be 

met from a variety of initial conditions such as DG in standby with the 

engine hot and DG in standby with the engine at ambient conditions. 

Additional DG capabilities must be demonstrated to meet required 

Surveillances, e.g., capability of the DG to revert to standby status on an 

ECCS signal while operating in parallel test mode. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-4 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

Proper sequencing of loads, [including tripping of nonessential loads,] is a 

required function for DG OPERABILITY. 

The AC sources in one train must be separate and independent (to the 

extent possible) of the AC sources in the other train. For the DGs, 

separation and independence are complete. 

For the offsite AC sources, separation and independence are to the 

extent practical. A circuit may be connected to more than one ESF bus, 

with fast transfer capability to the other circuit OPERABLE, and not 

violate separation criteria. A circuit that is not connected to an ESF bus is 

required to have OPERABLE fast transfer interlock mechanisms to at 

least two ESF buses to support OPERABILITY of that circuit. 

APPLICABILITY The AC sources [and sequencers] are required to be OPERABLE in 

MODES 1, 2, 3, and 4 to ensure that: 

a. Acceptable fuel design limits and reactor coolant pressure boundary 

limits are not exceeded as a result of AOOs or abnormal transients 

and 

b. Adequate core cooling is provided and containment OPERABILITY 

and other vital functions are maintained in the event of a postulated 

DBA. 

The AC power requirements for MODES 5 and 6 are covered in 

LCO 3.8.2, "AC Sources - Shutdown." 

ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable DG. 

There is an increased risk associated with entering a MODE or other 

specified condition in the Applicability with an inoperable DG and the 

provisions of LCO 3.0.4.b, which allow entry into a MODE or other 

specified condition in the Applicability with the LCO not met after 

performance of a risk assessment addressing inoperable systems and 

components, should not be applied in this circumstance. 

 A.1

To ensure a highly reliable power source remains with the one offsite circuit inoperable, it is 

necessary to verify the OPERABILITY of the remaining required offsite 

circuit on a more frequent basis. Since the Required Action only specifies 

"perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a 

Required Action not met. However, if a second required circuit fails 

SR 3.8.1.1, the second offsite circuit is inoperable, and Condition C, for 

two offsite circuits inoperable, is entered.
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

The turbine driven auxiliary feedwater pump is only required to be 

considered a redundant required feature, and, therefore, required to be 

determined OPERABLE by this Required Action, if the design is such that 

the remaining OPERABLE motor or turbine driven auxiliary feedwater 

pump(s) is not by itself capable (without any reliance on the motor driven 

auxiliary feedwater pump powered by the emergency bus associated with 

the inoperable diesel generator) of providing 100% of the auxiliary 

feedwater flow assumed in the safety analysis. 

-------------------------------------------------------------------------------------------------- 

A.2

Required Action A.2, which only applies if the train cannot be powered 

from an offsite source, is intended to provide assurance that an event 

coincident with a single failure of the associated DG will not result in a 

complete loss of safety function of critical redundant required features. 

These features are powered from the redundant AC electrical power train. 

This includes motor driven auxiliary feedwater pumps. Single train 

systems, such as turbine driven auxiliary feedwater pumps, may not be 

included. 

The Completion Time for Required Action A.2 is intended to allow the 

operator time to evaluate and repair any discovered inoperabilities. This 

Completion Time also allows for an exception to the normal "time zero" 

for beginning the allowed outage time "clock." In this Required Action, 

the Completion Time only begins on discovery that both: 

a. The train has no offsite power supplying its loads and 

b. A required feature on the other train is inoperable. 

If at any time during the existence of Condition A (one offsite circuit 

inoperable) a redundant required feature subsequently becomes 

inoperable, this Completion Time begins to be tracked. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

 Discovering no offsite power to one train of the onsite Class 1E Electrical 

Power Distribution System coincident with one or more inoperable 

required support or supported features, or both, that are associated with 

the other train that has offsite power, results in starting the Completion 

Times for the Required Action. Twenty-four hours is acceptable because 

it minimizes risk while allowing time for restoration before subjecting the 

unit to transients associated with shutdown. 

The remaining OPERABLE offsite circuit and DGs are adequate to supply 

electrical power to Train A and Train B of the onsite Class 1E Distribution 

System. The 24 hour Completion Time takes into account the component 

OPERABILITY of the redundant counterpart to the inoperable required 

feature. Additionally, the 24 hour Completion Time takes into account the 

capacity and capability of the remaining AC sources, a reasonable time 

for repairs, and the low probability of a DBA occurring during this period. 

A.3

According to Regulatory Guide 1.93 (Ref. 6), operation may continue in 

Condition A for a period that should not exceed 72 hours. With one 

offsite circuit inoperable, the reliability of the offsite system is degraded, 

and the potential for a loss of offsite power is increased, with attendant 

potential for a challenge to the unit safety systems. In this Condition, 

however, the remaining OPERABLE offsite circuit and DGs are adequate 

to supply electrical power to the onsite Class 1E Distribution System. 

The 72 hour Completion Time takes into account the capacity and 

capability of the remaining AC sources, a reasonable time for repairs, and 

the low probability of a DBA occurring during this period. 

The second Completion Time for Required Action A.3 establishes a limit 

on the maximum time allowed for any combination of required AC power 

sources to be inoperable during any single contiguous occurrence of 

failing to meet the LCO. If Condition A is entered while, for instance, a 

DG is inoperable, and that DG is subsequently returned OPERABLE, the 

LCO may already have been not met for up to 72 hours. This could lead 

to a total of 144 hours, since initial failure to meet the LCO, to restore the 

offsite circuit. At this time, a DG could again become inoperable, the 

circuit restored OPERABLE, and an additional 72 hours (for a total of 

9 days) allowed prior to complete restoration of the LCO. The 6 day 

Completion Time provides a limit on the time allowed in a specified 

condition after discovery of failure to meet the LCO. This limit is 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

considered reasonable for situations in which Conditions A and B are 

entered concurrently. The "AND" connector between the 72 hour and 

6 day Completion Time means that both Completion Times apply 

simultaneously, and the more restrictive Completion Time must be met. 

As in Required Action A.2, the Completion Time allows for an exception 

to the normal "time zero" for beginning the allowed outage time "clock." 

This will result in establishing the "time zero" at the time that the LCO was 

initially not met, instead of at the time Condition A was entered. 

B.1

To ensure a highly reliable power source remains with an inoperable DG, 

it is necessary to verify the availability of the offsite circuits on a more 

frequent basis. Since the Required Action only specifies "perform," a 

failure of SR 3.8.1.1 acceptance criteria does not result in a Required 

Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is 

inoperable. Upon offsite circuit inoperability, additional Conditions and 

Required Actions must then be entered. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

The turbine driven auxiliary feedwater pump is only required to be 

considered a redundant required feature, and, therefore, required to be 

determined OPERABLE by this Required Action, if the design is such that 

the remaining OPERABLE motor or turbine driven auxiliary feedwater 

pump(s) is not by itself capable (without any reliance on the motor driven 

auxiliary feedwater pump powered by the emergency bus associated with 

the inoperable diesel generator) of providing 100% of the auxiliary 

feedwater flow assumed in the safety analysis. 

-------------------------------------------------------------------------------------------------- 

B.2

Required Action B.2 is intended to provide assurance that a loss of offsite 

power, during the period that a DG is inoperable, does not result in a 

complete loss of safety function of critical systems. These features are 

designed with redundant safety related trains. This includes motor driven 

auxiliary feedwater pumps. Single train systems, such as turbine driven 

auxiliary feedwater pumps, are not included. Redundant required feature 

failures consist of inoperable features with a train, redundant to the train 

that has an inoperable DG. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-8 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

The Completion Time for Required Action B.2 is intended to allow the 

operator time to evaluate and repair any discovered inoperabilities. This 

Completion Time also allows for an exception to the normal "time zero" 

for beginning the allowed outage time "clock." In this Required Action, 

the Completion Time only begins on discovery that both: 

a. An inoperable DG exists and 

b. A required feature on the other train is inoperable. 

If at any time during the existence of this Condition (one DG inoperable) a 

required feature subsequently becomes inoperable, this Completion Time 

begins to be tracked. 

Discovering one required DG inoperable coincident with one or more 

inoperable required support or supported features, or both, that are 

associated with the OPERABLE DG, results in starting the Completion 

Time for the Required Action. Four hours from the discovery of these 

events existing concurrently, is acceptable because it minimizes risk while 

allowing time for restoration before subjecting the unit to transients 

associated with shutdown. 

In this Condition, the remaining OPERABLE DG and offsite circuits are 

adequate to supply electrical power to the onsite Class 1E Distribution 

System. Thus, on a component basis, single failure protection for the 

required feature's function may have been lost; however, function has not 

been lost. The 4 hour Completion Time takes into account the 

OPERABILITY of the redundant counterpart to the inoperable required 

feature. Additionally, the 4 hour Completion Time takes into account the 

capacity and capability of the remaining AC sources, a reasonable time 

for repairs, and the low probability of a DBA occurring during this period. 

B.3.1 and B.3.2

Required Action B.3.1 provides an allowance to avoid unnecessary 

testing of OPERABLE DGs. If it can be determined that the cause of the 

inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.2 does 

not have to be performed. If the cause of inoperability exists on other 

DG(s), the other DG(s) would be declared inoperable upon discovery and 

Condition E of LCO 3.8.1 would be entered. Once the failure is repaired, 

the common cause failure no longer exists and Required Action B.3.1 is 

satisfied. If the cause of the initial inoperable DG cannot be confirmed 

not to exist on the remaining DG(s), performance of SR 3.8.1.2 suffices to 

provide assurance of continued OPERABILITY of that DG. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-9 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

In the event the inoperable DG is restored to OPERABLE status prior to 

completing either B.3.1 or B.3.2, the [plant corrective action program] will 

continue to evaluate the common cause possibility. This continued 

evaluation, however, is no longer under the 24 hour constraint imposed 

while in Condition B. 

According to Generic Letter 84-15 (Ref. 7), [24] hours is reasonable to 

confirm that the OPERABLE DG(s) is not affected by the same problem 

as the inoperable DG. 

B.4

According to Regulatory Guide 1.93 (Ref. 6), operation may continue in 

Condition B for a period that should not exceed 72 hours. 

In Condition B, the remaining OPERABLE DG and offsite circuits are 

adequate to supply electrical power to the onsite Class 1E Distribution 

System. The 72 hour Completion Time takes into account the capacity 

and capability of the remaining AC sources, a reasonable time for repairs, 

and the low probability of a DBA occurring during this period. 

The second Completion Time for Required Action B.4 establishes a limit 

on the maximum time allowed for any combination of required AC power 

sources to be inoperable during any single contiguous occurrence of 

failing to meet the LCO. If Condition B is entered while, for instance, an 

offsite circuit is inoperable and that circuit is subsequently returned 

OPERABLE, the LCO may already have been not met for up to 72 hours. 

This could lead to a total of 144 hours, since initial failure to meet the 

LCO, to restore the DG. At this time, an offsite circuit could again 

become inoperable, the DG restored OPERABLE, and an additional 

72 hours (for a total of 9 days) allowed prior to complete restoration of the 

LCO. The 6 day Completion Time provides a limit on time allowed in a 

specified condition after discovery of failure to meet the LCO. This limit is 

considered reasonable for situations in which Conditions A and B are 

entered concurrently. The "AND" connector between the 72 hour and 

6 day Completion Times means that both Completion Times apply 

simultaneously, and the more restrictive Completion Time must be met. 

As in Required Action B.2, the Completion Time allows for an exception 

to the normal "time zero" for beginning the allowed time "clock." This will 

result in establishing the "time zero" at the time that the LCO was initially 

not met, instead of at the time Condition B was entered. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-10 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1 and C.2

Required Action C.1, which applies when two offsite circuits are 

inoperable, is intended to provide assurance that an event with a 

coincident single failure will not result in a complete loss of redundant 

required safety functions. The Completion Time for this failure of 

redundant required features is reduced to 12 hours from that allowed for 

one train without offsite power (Required Action A.2). The rationale for 

the reduction to 12 hours is that Regulatory Guide 1.93 (Ref. 6) allows a 

Completion Time of 24 hours for two required offsite circuits inoperable, 

based upon the assumption that two complete safety trains are 

OPERABLE. When a concurrent redundant required feature failure 

exists, this assumption is not the case, and a shorter Completion Time of 

12 hours is appropriate. These features are powered from redundant AC 

safety trains. This includes motor driven auxiliary feedwater pumps. 

Single train features, such as turbine driven auxiliary pumps, are not 

included in the list. 

The Completion Time for Required Action C.1 is intended to allow the 

operator time to evaluate and repair any discovered inoperabilities. This 

Completion Time also allows for an exception to the normal "time zero" 

for beginning the allowed outage time "clock." In this Required Action, 

the Completion Time only begins on discovery that both: 

a. All required offsite circuits are inoperable and 

b. A required feature is inoperable. 

If at any time during the existence of Condition C (two offsite circuits 

inoperable) and a required feature becomes inoperable, this Completion 

Time begins to be tracked. 

According to Regulatory Guide 1.93 (Ref. 6), operation may continue in 

Condition C for a period that should not exceed 24 hours. This level of 

degradation means that the offsite electrical power system does not have 

the capability to effect a safe shutdown and to mitigate the effects of an 

accident; however, the onsite AC sources have not been degraded. This 

level of degradation generally corresponds to a total loss of the 

immediately accessible offsite power sources. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-11 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Because of the normally high availability of the offsite sources, this level 

of degradation may appear to be more severe than other combinations of 

two AC sources inoperable that involve one or more DGs inoperable. 

However, two factors tend to decrease the severity of this level of 

degradation: 

a. The configuration of the redundant AC electrical power system that 

remains available is not susceptible to a single bus or switching 

failure and 

b. The time required to detect and restore an unavailable offsite power 

source is generally much less than that required to detect and restore 

an unavailable onsite AC source. 

With both of the required offsite circuits inoperable, sufficient onsite AC 

sources are available to maintain the unit in a safe shutdown condition in 

the event of a DBA or transient. In fact, a simultaneous loss of offsite AC 

sources, a LOCA, and a worst case single failure were postulated as a 

part of the design basis in the safety analysis. Thus, the 24 hour 

Completion Time provides a period of time to effect restoration of one of 

the offsite circuits commensurate with the importance of maintaining an 

AC electrical power system capable of meeting its design criteria. 

According to Reference 6, with the available offsite AC sources, two less 

than required by the LCO, operation may continue for 24 hours. If two 

offsite sources are restored within 24 hours, unrestricted operation may 

continue. If only one offsite source is restored within 24 hours, power 

operation continues in accordance with Condition A. 

D.1 and D.2

Pursuant to LCO 3.0.6, the Distribution System ACTIONS would not be 

entered even if all AC sources to it were inoperable resulting in deenergization. Therefore, the Required Actions of Condition D are 

modified by a Note to indicate that when Condition D is entered with no 

AC source to any train, the Conditions and Required Actions for 

LCO 3.8.9, "Distribution Systems - Operating," must be immediately 

entered. This allows Condition D to provide requirements for the loss of 

one offsite circuit and one DG without regard to whether a train is deenergized. LCO 3.8.9 provides the appropriate restrictions for a deenergized train. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-12 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

According to Regulatory Guide 1.93 (Ref. 6), operation may continue in 

Condition D for a period that should not exceed 12 hours. 

In Condition D, individual redundancy is lost in both the offsite electrical 

power system and the onsite AC electrical power system. Since power 

system redundancy is provided by two diverse sources of power, 

however, the reliability of the power systems in this Condition may appear 

higher than that in Condition C (loss of both required offsite circuits). This 

difference in reliability is offset by the susceptibility of this power system 

configuration to a single bus or switching failure. The 12 hour Completion 

Time takes into account the capacity and capability of the remaining AC 

sources, a reasonable time for repairs, and the low probability of a DBA 

occurring during this period. 

E.1

With Train A and Train B DGs inoperable, there are no remaining standby 

AC sources. Thus, with an assumed loss of offsite electrical power, 

insufficient standby AC sources are available to power the minimum 

required ESF functions. Since the offsite electrical power system is the 

only source of AC power for this level of degradation, the risk associated 

with continued operation for a short time could be less than that 

associated with an immediate controlled shutdown (the immediate 

shutdown could cause grid instability, which could result in a total loss of 

AC power). Since any inadvertent generator trip could also result in a 

total loss of offsite AC power, however, the time allowed for continued 

operation is severely restricted. The intent here is to avoid the risk 

associated with an immediate controlled shutdown and to minimize the 

risk associated with this level of degradation. 

According to Regulatory Guide 1.93 (Ref. 6), with both DGs inoperable, 

operation may continue for a period that should not exceed 2 hours. 

[ F.1

The sequencer(s) is an essential support system to [both the offsite circuit 

and the DG associated with a given ESF bus]. [Furthermore, the 

sequencer is on the primary success path for most major AC electrically 

powered safety systems powered from the associated ESF bus.] 

Therefore, loss of an [ESF bus sequencer] affects every major ESF 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-13 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

system in the [division]. The [12] hour Completion Time provides a period 

of time to correct the problem commensurate with the importance of 

maintaining sequencer OPERABILITY. This time period also ensures 

that the probability of an accident (requiring sequencer OPERABILITY) 

occurring during periods when the sequencer is inoperable is minimal. 

This Condition is preceded by a Note that allows the Condition to be 

deleted if the unit design is such that any sequencer failure mode will only 

affect the ability of the associated DG to power its respective safety loads 

under any conditions. Implicit in this Note is the concept that the 

Condition must be retained if any sequencer failure mode results in the 

inability to start all or part of the safety loads when required, regardless of 

power availability, or results in overloading the offsite power circuit to a 

safety bus during an event, thereby causing its failure. Also implicit in the 

Note, is that the Condition is not applicable to any train that does not have 

a sequencer. ]

G.1 and G.2

If the inoperable AC electrical power sources cannot be restored to 

OPERABLE status within the required Completion Time, the unit must be 

brought to a MODE in which the LCO does not apply. To achieve this 

status, the unit must be brought to at least MODE 3 within 6 hours and to 

MODE 5 within 36 hours. The allowed Completion Times are reasonable, 

based on operating experience, to reach the required unit conditions from 

full power conditions in an orderly manner and without challenging unit 

systems. 

H.1

Condition H corresponds to a level of degradation in which all redundancy in the AC electrical 

power supplies has been lost. At this severely degraded level, any further 

losses in the AC electrical power system will cause a loss of function. 

Therefore, no additional time is justified for continued operation. The unit 

is required by LCO 3.0.3 to commence a controlled shutdown. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-14 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE The AC sources are designed to permit inspection and testing of all 

REQUIREMENTS important areas and features, especially those that have a standby 

function, in accordance with 10 CFR 50, Appendix A, GDC 18 (Ref. 8). 

Periodic component tests are supplemented by extensive functional tests 

during refueling outages (under simulated accident conditions). The SRs 

for demonstrating the OPERABILITY of the DGs are in accordance with 

the recommendations of Regulatory Guide 1.9 (Ref. 3), Regulatory 

Guide 1.108 (Ref. 9), and Regulatory Guide 1.137 (Ref. 10), as 

addressed in the FSAR. 

Where the SRs discussed herein specify voltage and frequency 

tolerances, the following is applicable. The minimum steady state output 

voltage of [3740] V is 90% of the nominal 4160 V output voltage. This 

value, which is specified in ANSI C84.1-1982 (Ref. 11), allows for voltage 

drop to the terminals of 4000 V motors whose minimum operating voltage 

is specified as 90% or 3600 V. It also allows for voltage drops to motors 

and other equipment down through the 120 V level where minimum 

operating voltage is also usually specified as 80% of name plate rating. 

The specified maximum steady state output voltage of [4756] V is equal 

to the maximum operating voltage specified for 4000 V motors. It ensures 

that for a lightly loaded distribution system, the voltage at the terminals of 

4000 V motors is no more than the maximum rated operating voltages. 

The specified minimum and maximum frequencies of the DG are 58.8 Hz 

and 61.2 Hz, respectively. These values are equal to ± 2% of the 60 Hz 

nominal frequency and are derived from the recommendations given in 

Regulatory Guide 1.9 (Ref. 3). 

SR 3.8.1.1

This SR assures proper circuit continuity for the offsite AC electrical 

power supply to the onsite distribution network and availability of offsite 

AC electrical power. The breaker alignment verifies that each breaker is 

in its correct position to ensure that distribution buses and loads are 

connected to their preferred power source, and that appropriate 

independence of offsite circuits is maintained. The 7 day Frequency is 

adequate since breaker position is not likely to change without the 

operator being aware of it and because its status is displayed in the 

control room. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-15 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.8.1.2 and SR 3.8.1.7

These SRs help to ensure the availability of the standby electrical power 

supply to mitigate DBAs and transients and to maintain the unit in a safe 

shutdown condition. 

To minimize the wear on moving parts that do not get lubricated when the 

engine is not running, these SRs are modified by a Note (Note 1 for 

SR 3.8.1.2 and Note for SR 3.8.1.7) to indicate that all DG starts for these 

Surveillances may be preceded by an engine prelube period and followed 

by a warmup period prior to loading by an engine prelube period. 

For the purposes of SR 3.8.1.2 and SR 3.8.1.7 testing, the DGs are 

started from standby conditions. Standby conditions for a DG mean the 

diesel engine coolant and oil are being continuously circulated and 

temperature is being maintained consistent with manufacturer 

recommendations. 

[ In order to reduce stress and wear on diesel engines, the DG 

manufacturers recommend a modified start in which the starting speed of 

DGs is limited, warmup is limited to this lower speed, and the DGs are 

gradually accelerated to synchronous speed prior to loading. This is the 

intent of Note 2, which is only applicable when such modified start 

procedures are recommended by the manufacturer. 

SR 3.8.1.7 requires that, at a 184 day Frequency, the DG starts from 

standby conditions and achieves required voltage and frequency within 

10 seconds. The 10 second start requirement supports the assumptions 

of the design basis LOCA analysis in the FSAR, Chapter [15] (Ref. 5). ] 

The 10 second start requirement is not applicable to SR 3.8.1.2 (see 

Note 2) when a modified start procedure as described above is used. If a 

modified start is not used, 10 second start requirement of SR 3.8.1.7 

applies. 

Since SR 3.8.1.7 requires a 10 second start, it is more restrictive than 

SR 3.8.1.2, and it may be performed in lieu of SR 3.8.1.2. 

In addition to the SR requirements, the time for the DG to reach steady 

state operation, unless the modified DG start method is employed, is 

periodically monitored and the trend evaluated to identify degradation of 

governor and voltage regulator performance. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-16 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The 31 day Frequency for SR 3.8.1.2 is consistent with Regulatory 

Guide 1.9 (Ref. 3). 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. 

SR 3.8.1.3

This Surveillance verifies that the DGs are capable of synchronizing with 

the offsite electrical system and accepting loads greater than or equal to 

the equivalent of the maximum expected accident loads. A minimum run 

time of 60 minutes is required to stabilize engine temperatures, while 

minimizing the time that the DG is connected to the offsite source. 

Although no power factor requirements are established by this SR, the 

DG is normally operated at a power factor between [0.8 lagging] and 

[1.0]. The 0.8 value is the design rating of the machine, while [1.0] is an 

operational limitation [to ensure circulating currents are minimized]. The 

31 day Frequency for this Surveillance is consistent with Regulatory 

Guide 1.9 (Ref. 3). 

This SR is modified by four Notes. Note 1 indicates that diesel engine 

runs for this Surveillance may include gradual loading, as recommended 

by the manufacturer, so that mechanical stress and wear on the diesel 

engine are minimized. Note 2 states that momentary transients because 

of changing bus loads do not invalidate this test. Similarly, momentary 

power factor transients above the limit will not invalidate the test. Note 3 

indicates that this Surveillance should be conducted on only one DG at a 

time in order to avoid common cause failures that might result from offsite 

circuit or grid perturbations. Note 4 stipulates a prerequisite requirement 

for performance of this SR. A successful DG start must precede this test 

to credit satisfactory performance. 

SR 3.8.1.4

This SR provides verification that the level of fuel oil in the day tank [and 

engine mounted tank] is at or above the level at which fuel oil is 

automatically added. The level is expressed as an equivalent volume in 

gallons, and is selected to ensure adequate fuel oil for a minimum of 

1 hour of DG operation at full load plus 10%. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-17 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The 31 day Frequency is adequate to assure 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. 

SR 3.8.1.5

Microbiological fouling is a major cause of fuel oil degradation. There are 

numerous bacteria that can grow in fuel oil and cause fouling, but all 

must have a water environment in order to survive. Removal of water 

from the fuel oil day [and engine mounted] tanks once every [31] days 

eliminates the necessary environment for bacterial survival. This is the 

most effective means of controlling microbiological fouling. In addition, it 

eliminates the potential for water entrainment in the fuel oil during DG 

operation. Water may come from any of several sources, including 

condensation, ground water, rain water, contaminated fuel oil, and from 

breakdown of the fuel oil by bacteria. Frequent checking for and removal 

of accumulated water minimizes fouling and provides data regarding the 

watertight integrity of the fuel oil system. The Surveillance Frequencies 

are established by Regulatory Guide 1.137 (Ref. 10). This SR is for 

preventive maintenance. The presence of water does not necessarily 

represent failure of this SR provided the accumulated water is removed 

during the performance of this Surveillance. 

SR 3.8.1.6

This Surveillance demonstrates that each required fuel oil transfer pump 

operates and transfers fuel oil from its associated storage tank to its 

associated day tank. This is required to support continuous operation of 

standby power sources. This Surveillance provides assurance that the 

fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, 

the fuel delivery piping is not obstructed, and the controls and control 

systems for automatic fuel transfer systems are OPERABLE. 

[ The Frequency for this SR is variable, depending on individual system 

design, with up to a [92] day interval. The [92] day Frequency 

corresponds to the testing requirements for pumps as contained in the 

ASME Code, Section XI (Ref. 12); however, the design of fuel transfer 

systems is such that pumps will operate automatically or must be started 

manually in order to maintain an adequate volume of fuel oil in the day 

[and engine mounted] tanks during or following DG testing. In such a 

case, a 31 day Frequency is appropriate. Since proper operation of fuel 

transfer systems is an inherent part of DG OPERABILITY, the Frequency 

of this SR should be modified to reflect individual designs. ] 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-18 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.8.1.7

See SR 3.8.1.2. 

[ SR 3.8.1.8

Transfer of each [4.16 kV ESF bus] power supply from the normal offsite 

circuit to the alternate offsite circuit demonstrates the OPERABILITY of 

the alternate circuit distribution network to power the shutdown loads. 

The [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. 

This SR is modified by a Note. The reason for the Note is that during 

operation with the reactor critical, performance of this SR could cause 

perturbations to the electrical distribution systems that could challenge 

continued steady state operation and, as a result, unit safety systems. 

This restriction from normally performing the Surveillance in MODE 1 or 2 

is further amplified to allow the Surveillance to be performed for the 

purpose of reestablishing OPERABILITY (e.g., post work testing following 

corrective maintenance, corrective modification, deficient or incomplete 

surveillance testing, and other unanticipated OPERABILITY concerns) 

provided an assessment determines plant safety is maintained or 

enhanced. This assessment shall, as a minimum, consider the potential 

outcomes and transients associated with a failed Surveillance, a 

successful Surveillance, and a perturbation of the offsite or onsite system 

when they are tied together or operated independently for the 

Surveillance; as well as the operator procedures available to cope with 

these outcomes. These shall be measured against the avoided risk of a 

plant shutdown and startup to determine that plant safety is maintained or 

enhanced when the Surveillance is performed in MODE 1 or 2. Risk 

insights or deterministic methods may be used for this assessment. 

Credit may be taken for unplanned events that satisfy this SR .]
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-19 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.8.1.9

Each DG is provided with an engine overspeed trip to prevent damage to 

the engine. Recovery from the transient caused by the loss of a large 

load could cause diesel engine overspeed, which, if excessive, might 

result in a trip of the engine. This Surveillance demonstrates the DG load 

response characteristics and capability to reject the largest single load 

without exceeding predetermined voltage and frequency and while 

maintaining a specified margin to the overspeed trip. [For this unit, the 

single load for each DG and its horsepower rating is as follows:] This 

Surveillance may be accomplished by: 

a. Tripping the DG output breaker with the DG carrying greater than or 

equal to its associated single largest post-accident load while 

paralleled to offsite power or while solely supplying the bus, or 

b. Tripping its associated single largest post-accident load with the DG 

solely supplying the bus. 

As required by IEEE-308 (Ref. 13), the load rejection test is acceptable if 

the increase in diesel speed does not exceed 75% of the difference 

between synchronous speed and the overspeed trip setpoint, or 15% 

above synchronous speed, whichever is lower. 

The time, voltage, and frequency tolerances specified in this SR are 

derived from Regulatory Guide 1.9 (Ref. 3) recommendations for 

response during load sequence intervals. The [3] seconds specified is 

equal to 60% of a typical 5 second load sequence interval associated with 

sequencing of the largest load. The voltage and frequency specified are 

consistent with the design range of the equipment powered by the DG. 

SR 3.8.1.9.a corresponds to the maximum frequency excursion, while 

SR 3.8.1.9.b and SR 3.8.1.9.c are steady state voltage and frequency 

values to which the system must recover following load rejection. The 

[18 month] Frequency is consistent with the recommendation of 

Regulatory Guide 1.108 (Ref. 9). 

This SR is modified by two Notes. The reason for Note 1 is that during 

operation with the reactor critical, performance of this SR could cause 

perturbations to the electrical distribution systems that could challenge 

continued steady state operation and, as a result, unit safety systems. 

This restriction from normally performing the Surveillance in MODE 1 or 2 

is further amplified to allow the Surveillance to be performed for the 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-20 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

purpose of reestablishing OPERABILITY (e.g., post work testing following 

corrective maintenance, corrective modification, deficient or incomplete 

surveillance testing, and other unanticipated OPERABILITY concerns) 

provided an assessment determines plant safety is maintained or 

enhanced. This assessment shall, as a minimum, consider the potential 

outcomes and transients associated with a failed Surveillance, a 

successful Surveillance, and a perturbation of the offsite or onsite system 

when they are tied together or operated independently for the 

Surveillance; as well as the operator procedures available to cope with 

these outcomes. These shall be measured against the avoided risk of a 

plant shutdown and startup to determine that plant safety is maintained or 

enhanced when the Surveillance is performed in MODE 1 or 2. Risk 

insights or deterministic methods may be used for this assessment. 

Credit may be taken for unplanned events that satisfy this SR. Note 2 

ensures that the DG is tested under load conditions that are as close to 

design basis conditions as possible. When synchronized with offsite 

power, testing should be performed at a power factor of ≤ [0.9]. This 

power factor is representative of the actual inductive loading a DG would 

see under design basis accident conditions. Under certain conditions, 

however, Note 2 allows the Surveillance to be conducted at a power 

factor other than ≤ [0.9]. These conditions occur when grid voltage is 

high, and the additional field excitation needed to get the power factor to 

≤ [0.9] results in voltages on the emergency busses that are too high. 

Under these conditions, the power factor should be maintained as close 

as practicable to [0.9] while still maintaining acceptable voltage limits on 

the emergency busses. In other circumstances, the grid voltage may be 

such that the DG excitation levels needed to obtain a power factor of [0.9] 

may not cause unacceptable voltages on the emergency busses, but the 

excitation levels are in excess of those recommended for the DG. In such 

cases, the power factor shall be maintained as close as practicable to 

[0.9] without exceeding the DG excitation limits. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

The above MODE restrictions may be deleted if it can be demonstrated to 

the staff, on a plant specific basis, that performing the SR with the reactor 

in any of the restricted MODES can satisfy the following criteria, as 

applicable: 

a. Performance of the SR will not render any safety system or 

component inoperable, 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-21 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

b. Performance of the SR will not cause perturbations to any of the 

electrical distribution systems that could result in a challenge to 

steady state operation or to plant safety systems, and 

c. Performance of the SR or failure of the SR will not cause or result in 

an AOO with attendant challenge to plant safety systems. 

-------------------------------------------------------------------------------------------------- 

SR 3.8.1.10

This Surveillance demonstrates the DG capability to reject a full load 

without overspeed tripping or exceeding the predetermined voltage limits. 

The DG full load rejection may occur because of a system fault or 

inadvertent breaker tripping. This Surveillance ensures proper engine 

generator load response under the simulated test conditions. This test 

simulates the loss of the total connected load that the DG experiences 

following a full load rejection and verifies that the DG will not trip upon 

loss of the load. These acceptance criteria provide DG damage 

protection. While the DG is not expected to experience this transient 

during an event and continues to be available, this response ensures that 

the DG is not degraded for future application, including reconnection to 

the bus if the trip initiator can be corrected or isolated. 

The [18 month] Frequency is consistent with the recommendation of 

Regulatory Guide 1.108 (Ref. 9) and is intended to be consistent with 

expected fuel cycle lengths. 

This SR is modified by two Notes. The reason for Note 1 is that during 

operation with the reactor critical, performance of this SR could cause 

perturbation to the electrical distribution systems that could challenge 

continued steady state operation and, as a result, unit safety systems. 

This restriction from normally performing the Surveillance in MODE 1 or 2 

is further amplified to allow the Surveillance to be performed for the 

purpose of reestablishing OPERABILITY (e.g., post work testing following 

corrective maintenance, corrective modification, deficient or incomplete 

surveillance testing, and other unanticipated OPERABILITY concerns) 

provided an assessment determines plant safety is maintained or 

enhanced. This assessment shall, as a minimum, consider the potential 

outcomes and transients associated with a failed Surveillance, a 

successful Surveillance, and a perturbation of the offsite or onsite system 

when they are tied together or operated independently for the 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-22 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

Surveillance; as well as the operator procedures available to cope with 

these outcomes. These shall be measured against the avoided risk of a 

plant shutdown and startup to determine that plant safety is maintained or 

enhanced when the Surveillance is performed in MODE 1 or 2. Risk 

insights or deterministic methods may be used for this assessment. 

Credit may be taken for unplanned events that satisfy this SR. Note 2 

ensures that the DG is tested under load conditions that are as close to 

design basis conditions as possible. When synchronized with offsite 

power, testing should be performed at a power factor of ≤ [0.9]. This 

power factor is representative of the actual inductive loading a DG would 

see under design basis accident conditions. Under certain conditions, 

however, Note 2 allows the Surveillance to be conducted at a power 

factor other than ≤ [0.9]. These conditions occur when grid voltage is 

high, and the additional field excitation needed to get the power factor to 

≤ [0.9] results in voltages on the emergency busses that are too high. 

Under these conditions, the power factor should be maintained as close 

as practicable to [0.9] while still maintaining acceptable voltage limits on 

the emergency busses. In other circumstances, the grid voltage may be 

such that the DG excitation levels needed to obtain a power factor of [0.9] 

may not cause unacceptable voltages on the emergency busses, but the 

excitation levels are in excess of those recommended for the DG. In such 

cases, the power factor shall be maintained as close as practicable to 

[0.9] without exceeding the DG excitation limits. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

The above MODE restrictions may be deleted if it can be demonstrated to 

the staff, on a plant specific basis, that performing the SR with the reactor 

in any of the restricted MODES can satisfy the following criteria, as 

applicable: 

a. Performance of the SR will not render any safety system or 

component inoperable, 

b. Performance of the SR will not cause perturbations to any of the 

electrical distribution systems that could result in a challenge to 

steady state operation or to plant safety systems, and 

c. Performance of the SR or failure of the SR will not cause or result in 

an AOO with attendant challenge to plant safety systems. 

-------------------------------------------------------------------------------------------------- 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-23 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.8.1.11

As required by Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(1), this 

Surveillance demonstrates the as designed operation of the standby 

power sources during loss of the offsite source. This test verifies all 

actions encountered from the loss of offsite power, including shedding of 

the nonessential loads and energization of the emergency buses and 

respective loads from the DG. It further demonstrates the capability of 

the DG to automatically achieve the required voltage and frequency within 

the specified time. 

The DG auto-start time of [10] seconds is derived from requirements of 

the accident analysis to respond to a design basis large break LOCA. 

The Surveillance should be continued for a minimum of 5 minutes in order 

to demonstrate that all starting transients have decayed and stability has 

been achieved. 

The requirement to verify the connection and power supply of permanent 

and auto-connected loads is intended to satisfactorily show the 

relationship of these loads to the DG loading logic. In certain 

circumstances, many of these loads cannot actually be connected or 

loaded without undue hardship or potential for undesired operation. For 

instance, Emergency Core Cooling Systems (ECCS) injection valves are 

not desired to be stroked open, high pressure injection systems are not 

capable of being operated at full flow, or shutdown cooling (SDC) 

systems performing a decay heat removal function are not desired to be 

realigned to the ECCS mode of operation. In lieu of actual demonstration 

of connection and loading of loads, testing that adequately shows the 

capability of the DG system to perform these functions is acceptable. 

This testing may include any series of sequential, overlapping, or total 

steps so that the entire connection and loading sequence is verified. 

The Frequency of [18 months] is consistent with the recommendations of 

Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(1), takes into 

consideration unit conditions required to perform the Surveillance, and is 

intended to be consistent with expected fuel cycle lengths. 

This SR is modified by two Notes. The reason for Note 1 is to minimize 

wear and tear on the DGs during testing. For the purpose of this testing, 

the DGs must be started from standby conditions, that is, with the engine 

coolant and oil continuously circulated and temperature maintained 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-24 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

consistent with manufacturer recommendations. The reason for Note 2 is 

that performing the Surveillance would remove a required offsite circuit 

from service, perturb the electrical distribution system, and challenge 

safety systems. This restriction from normally performing the 

Surveillance in MODE 1 or 2 is further amplified to allow portions of the 

Surveillance to be performed for the purpose of reestablishing 

OPERABILITY (e.g., post work testing following corrective maintenance, 

corrective modification, deficient or incomplete surveillance testing, and 

other unanticipated OPERABILITY concerns) provided an assessment 

determines plant safety is maintained or enhanced. This assessment 

shall, as a minimum, consider the potential outcomes and transients 

associated with a failed partial Surveillance, a successful partial 

Surveillance, and a perturbation of the offsite or onsite system when they 

are tied together or operated independently for the partial Surveillance; as 

well as the operator procedures available to cope with these outcomes. 

These shall be measured against the avoided risk of a plant shutdown 

and startup to determine that plant safety is maintained or enhanced 

when portions of the Surveillance are performed in MODE 1 or 2. Risk 

insights or deterministic methods may be used for the assessment. 

Credit may be taken for unplanned events that satisfy this SR. 

[ SR 3.8.1.12

This Surveillance demonstrates that the DG automatically starts and 

achieves the required voltage and frequency within the specified time 

([10] seconds) from the design basis actuation signal (LOCA signal) and 

operates for ≥ 5 minutes. The 5 minute period provides sufficient time to 

demonstrate stability. SR 3.8.1.12.d and SR 3.8.1.12.e ensure that 

permanently connected loads and emergency loads are energized from 

the offsite electrical power system on an ESF signal without loss of offsite 

power. 

The requirement to verify the connection of permanent and 

autoconnected loads is intended to satisfactorily show the relationship of 

these loads to the DG loading logic. In certain circumstances, many of 

these loads cannot actually be connected or loaded without undue 

hardship or potential for undesired operation. For instance, ECCS 

injection valves are not desired to be stroked open, high pressure 

injection systems are not capable of being operated at full flow, or SDC 

systems performing a decay heat removal function are not desired to be 

realigned to the ECCS mode of operation. In lieu of actual demonstration 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-25 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

of connection and loading of loads, testing that adequately shows the 

capability of the DG system to perform these functions is acceptable. 

This testing may include any series of sequential, overlapping, or total 

steps so that the entire connection and loading sequence is verified. 

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. 

This SR is modified by two Notes. The reason for Note 1 is to minimize 

wear and tear on the DGs during testing. For the purpose of this testing, 

the DGs must be started from standby conditions, that is, with the engine 

coolant and oil continuously circulated and temperature maintained 

consistent with manufacturer recommendations. The reason for Note 2 is 

that during operation with the reactor critical, performance of this 

Surveillance could cause perturbations to the electrical distribution 

systems that could challenge continued steady state operation and, as a 

result, unit safety systems. This restriction from normally performing the 

Surveillance in MODE 1 or 2 is further amplified to allow portions of the 

Surveillance to be performed for the purpose of reestablishing 

OPERABILITY (e.g., post work testing following corrective maintenance, 

corrective modification, deficient or incomplete surveillance testing, and 

other unanticipated OPERABILITY concerns) provided an assessment 

determines plant safety is maintained or enhanced. This assessment 

shall, as a minimum, consider the potential outcomes and transients 

associated with a failed partial Surveillance, a successful partial 

Surveillance, and a perturbation of the offsite or onsite system when they 

are tied together or operated independently for the partial Surveillance; as 

well as the operator procedures available to cope with these outcomes. 

These shall be measured against the avoided risk of a plant shutdown 

and startup to determine that plant safety is maintained or enhanced 

when portions of the Surveillance are performed in MODE 1 or 2. Risk 

insights or deterministic methods may be used for the assessment. 

Credit may be taken for unplanned events that satisfy this SR. ]
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-26 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.8.1.13

This Surveillance demonstrates that DG noncritical protective functions 

(e.g., high jacket water temperature) are bypassed on a loss of voltage 

signal concurrent with an ESF actuation test signal. The noncritical trips 

are bypassed during DBAs and provide an alarm on an abnormal engine 

condition. This alarm provides the operator with sufficient time to react 

appropriately. The DG availability to mitigate the DBA is more critical 

than protecting the engine against minor problems that are not 

immediately detrimental to emergency operation of the DG. 

The [18 month] Frequency is based on engineering judgment, taking into 

consideration unit conditions required to perform the Surveillance, and is 

intended to be consistent with expected fuel cycle lengths. Operating 

experience has shown that these components usually pass the SR when 

performed at the [18 month] Frequency. Therefore, the Frequency was 

concluded to be acceptable from a reliability standpoint. 

The SR is modified by a Note. The reason for the Note is that performing 

the Surveillance would remove a required DG from service. This 

restriction from normally performing the Surveillance in MODE 1 or 2 is 

further amplified to allow the Surveillance to be performed for the purpose 

of reestablishing OPERABILITY (e.g., post work testing following 

corrective maintenance, corrective modification, deficient or incomplete 

surveillance testing, and other unanticipated OPERABILITY concerns) 

provided an assessment determines plant safety is maintained or 

enhanced. This assessment shall, as a minimum, consider the potential 

outcomes and transients associated with a failed Surveillance, a 

successful Surveillance, and a perturbation of the offsite or onsite system 

when they are tied together or operated independently for the 

Surveillance; as well as the operator procedures available to cope with 

these outcomes. These shall be measured against the avoided risk of a 

plant shutdown and startup to determine that plant safety is maintained or 

enhanced when the Surveillance is performed in MODE 1 or 2. Risk 

insights or deterministic methods may be used for this assessment. 

Credit may be taken for unplanned events that satisfy this SR. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-27 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

The above MODE restrictions may be deleted if it can be demonstrated to 

the staff, on a plant specific basis, that performing the SR with the reactor 

in any of the restricted MODES can satisfy the following criteria, as 

applicable: 

a. Performance of the SR will not render any safety system or 

component inoperable, 

b. Performance of the SR will not cause perturbations to any of the 

electrical distribution systems that could result in a challenge to 

steady state operation or to plant safety systems, and 

c. Performance of the SR or failure of the SR will not cause or result in 

an AOO with attendant challenge to plant safety systems. 

-------------------------------------------------------------------------------------------------- 

SR 3.8.1.14

Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(3), requires 

demonstration once per 18 months that the DGs can start and run 

continuously at full load capability for an interval of not less than 24 hours, 

≥ [2] hours of which is at a load equivalent to 110% of the continuous duty 

rating and the remainder of the time at a load equivalent to the continuous 

duty rating of the DG. The DG starts for this Surveillance can be 

performed either from standby or hot conditions. The provisions for 

prelubricating and warmup, discussed in SR 3.8.1.2, and for gradual 

loading, discussed in SR 3.8.1.3, are applicable to this SR. 

The load band is provided to avoid routine overloading of the DG. 

Routine overloading may result in more frequent teardown inspections in 

accordance with vendor recommendations in order to maintain DG 

OPERABILITY. 

The [18 month] Frequency is consistent with the recommendations of 

Regulatory Guide 1.108 (Ref. 7), paragraph 2.a.(3), takes into 

consideration unit conditions required to perform the Surveillance, and is 

intended to be consistent with expected fuel cycle lengths. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-28 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

This Surveillance is modified by three Notes. Note 1 states that 

momentary transients due to changing bus loads do not invalidate this 

test. Similarly, momentary power factor transients above the power factor 

limit will not invalidate the test. The reason for Note 2 is that during 

operation with the reactor critical, performance of this Surveillance could 

cause perturbations to the electrical distribution systems that could 

challenge continued steady state operation and, as a result, unit safety 

systems. This restriction from normally performing the Surveillance in 

MODE 1 or 2 is further amplified to allow the Surveillance to be performed 

for the purpose of reestablishing OPERABILITY (e.g., post work testing 

following corrective maintenance, corrective modification, deficient or 

incomplete surveillance testing, and other unanticipated OPERABILITY 

concerns) provided an assessment determines plant safety is maintained 

or enhanced. This assessment shall, as a minimum, consider the 

potential outcomes and transients associated with a failed Surveillance, a 

successful Surveillance, and a perturbation of the offsite or onsite system 

when they are tied together or operated independently for the 

Surveillance; as well as the operator procedures available to cope with 

these outcomes. These shall be measured against the avoided risk of a 

plant shutdown and startup to determine that plant safety is maintained or 

enhanced when the Surveillance is performed in MODE 1 or 2. Risk 

insights or deterministic methods may be used for this assessment. 

Credit may be taken for unplanned events that satisfy this SR. Note 3 

ensures that the DG is tested under load conditions that are as close to 

design basis conditions as possible. When synchronized with offsite 

power, testing should be performed at a power factor of ≤ [0.9]. This 

power factor is representative of the actual inductive loading a DG would 

see under design basis accident conditions. Under certain conditions, 

however, Note 3 allows the Surveillance to be conducted at a power 

factor other than ≤ [0.9]. These conditions occur when grid voltage is 

high, and the additional field excitation needed to get the power factor to 

≤ [0.9] results in voltages on the emergency busses that are too high. 

Under these conditions, the power factor should be maintained as close 

as practicable to [0.9] while still maintaining acceptable voltage limits on 

the emergency busses. In other circumstances, the grid voltage may be 

such that the DG excitation levels needed to obtain a power factor of [0.9] 

may not cause unacceptable voltages on the emergency busses, but the 

excitation levels are in excess of those recommended for the DG. In such 

cases, the power factor shall be maintained as close practicable to [0.9] 

without exceeding the DG excitation limits. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-29 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.8.1.15

This Surveillance demonstrates that the diesel engine can restart from a 

hot condition, such as subsequent to shutdown from normal 

Surveillances, and achieve the required voltage and frequency within 

[10] seconds. The [10] second time is derived from the requirements of 

the accident analysis to respond to a design basis large break LOCA. 

The [18 month] Frequency is consistent with the recommendations of 

Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(5). 

This SR is modified by two Notes. Note 1 ensures that the test is 

performed with the diesel sufficiently hot. The load band is provided to 

avoid routine overloading of the DG. Routine overloads may result in 

more frequent teardown inspections in accordance with vendor 

recommendations in order to maintain DG OPERABILITY. The 

requirement that the diesel has operated for at least [2] hours at full load 

conditions prior to performance of this Surveillance is based on 

manufacturer recommendations for achieving hot conditions. Momentary 

transients due to changing bus loads do not invalidate this test. Note 2 

allows all DG starts to be preceded by an engine prelube period to 

minimize wear and tear on the diesel during testing. 

SR 3.8.1.16

As required by Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(6), this 

Surveillance ensures that the manual synchronization and automatic load 

transfer from the DG to the offsite source can be made and that the DG 

can be returned to ready to load status when offsite power is restored. It 

also ensures that the auto-start logic is reset to allow the DG to reload if a 

subsequent loss of offsite power occurs. The DG is considered to be in 

ready to load status when the DG is at rated speed and voltage, the 

output breaker is open and can receive and autoclose signal on bus 

undervoltage, and the load sequence timers are reset. 

The Frequency of [18 months] is consistent with the recommendations of 

Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(6), and takes into 

consideration unit conditions required to perform the Surveillance. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-30 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

This SR is modified by a Note. The reason for the Note is that performing 

the Surveillance would remove a required offsite circuit from service, 

perturb the electrical distribution system, and challenge safety systems. 

This restriction from normally performing the Surveillance in MODE 1 or 2 

is further amplified to allow the Surveillance to be performed for the 

purpose of reestablishing OPERABILITY (e.g., post work testing following 

corrective maintenance, corrective modification, deficient or incomplete 

surveillance testing, and other unanticipated OPERABILITY concerns) 

provided an assessment determines plant safety is maintained or 

enhanced. This assessment shall, as a minimum, consider the potential 

outcomes and transients associated with a failed Surveillance, a 

successful Surveillance, and a perturbation of the offsite or onsite system 

when they are tied together or operated independently for the 

Surveillance; as well as the operator procedures available to cope with 

these outcomes. These shall be measured against the avoided risk of a 

plant shutdown and startup to determine that plant safety is maintained or 

enhanced when the Surveillance is performed in MODE 1 or 2. Risk 

insights or deterministic methods may be used for this assessment. 

Credit may be taken for unplanned events that satisfy this SR. 

[ SR 3.8.1.17

Demonstration of the test mode override ensures that the DG availability 

under accident conditions will not be compromised as the result of testing 

and the DG will automatically reset to ready to load operation if a LOCA 

actuation signal is received during operation in the test mode. Ready to 

load operation is defined as the DG running at rated speed and voltage 

with the DG output breaker open. These provisions for automatic 

switchover are required by IEEE-308 (Ref. 13), paragraph 6.2.6(2). 

The requirement to automatically energize the emergency loads with 

offsite power is essentially identical to that of SR 3.8.1.12. The intent in 

the requirement associated with SR 3.8.1.17.b is to show that the 

emergency loading was not affected by the DG operation in test mode. In 

lieu of actual demonstration of connection and loading of loads, testing 

that adequately shows the capability of the emergency loads to perform 

these functions is acceptable. This testing may include any series of 

sequential, overlapping, or total steps so that the entire connection and 

loading sequence is verified. 

The [18 month] Frequency is consistent with the recommendations of 

Regulatory Guide 1.108 (Ref. 9), paragraph 2.a.(8); takes into 

consideration unit conditions required to perform the Surveillance; and is 

intended to be consistent with expected fuel cycle lengths. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-31 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

This SR is modified by a Note. The reason for the Note is that performing 

the Surveillance would remove a required offsite circuit from service, 

perturb the electrical distribution system, and challenge safety systems. 

This restriction from normally performing the Surveillance in MODE 1 or 2 

is further amplified to allow portions of the Surveillance to be performed 

for the purpose of reestablishing OPERABILITY (e.g., post work testing 

following corrective maintenance, corrective modification, deficient or 

incomplete surveillance testing, and other unanticipated OPERABILITY 

concerns) provided an assessment determines plant safety is maintained 

or enhanced. This assessment shall, as a minimum, consider the 

potential outcomes and transients associated with a failed partial 

Surveillance, a successful partial Surveillance, and a perturbation of the 

offsite or onsite system when they are tied together or operated 

independently for the partial Surveillance; as well as the operator 

procedures available to cope with these outcomes. These shall be 

measured against the avoided risk of a plant shutdown and startup to 

determine that plant safety is maintained or enhanced when portions of 

the Surveillance are performed in MODE 1 or 2. Risk insights or 

deterministic methods may be used for the assessment. Credit may be 

taken for unplanned events that satisfy this SR. ]

SR 3.8.1.18

Under accident [and loss of offsite power] conditions loads are 

sequentially connected to the bus by the [automatic load sequencer]. The 

sequencing logic controls the permissive and starting signals to motor 

breakers to prevent overloading of the DGs due to high motor starting 

currents. The [10]% load sequence time interval tolerance ensures that 

sufficient time exists for the DG to restore frequency and voltage prior to 

applying the next load and that safety analysis assumptions regarding 

ESF equipment time delays are not violated. Reference 1 provides a 

summary of the automatic loading of ESF buses. 

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. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-32 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

This SR is modified by a Note. The reason for the Note is that performing 

the Surveillance would remove a required offsite circuit from service, 

perturb the electrical distribution system, and challenge safety systems. 

This restriction from normally performing the Surveillance in MODE 1 or 2 

is further amplified to allow the Surveillance to be performed for the 

purpose of reestablishing OPERABILITY (e.g., post work testing following 

corrective maintenance, corrective modification, deficient or incomplete 

surveillance testing, and other unanticipated OPERABILITY concerns) 

provided an assessment determines plant safety is maintained or 

enhanced. This assessment shall, as a minimum, consider the potential 

outcomes and transients associated with a failed Surveillance, a 

successful Surveillance, and a perturbation of the offsite or onsite system 

when they are tied together or operated independently for the 

Surveillance; as well as the operator procedures available to cope with 

these outcomes. These shall be measured against the avoided risk of a 

plant shutdown and startup to determine that plant safety is maintained or 

enhanced when the Surveillance is performed in MODE 1 or 2. Risk 

insights or deterministic methods may be used for this assessment. 

Credit may be taken for unplanned events that satisfy this SR. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

The above MODE restrictions may be deleted if it can be demonstrated to 

the staff, on a plant specific basis, that performing the SR with the reactor 

in any of the restricted MODES can satisfy the following criteria, as 

applicable: 

a. Performance of the SR will not render any safety system or 

component inoperable, 

b. Performance of the SR will not cause perturbations to any of the 

electrical distribution systems that could result in a challenge to 

steady state operation or to plant safety systems, and 

c. Performance of the SR or failure of the SR will not cause or result in 

an AOO with attendant challenge to plant safety systems. 

-------------------------------------------------------------------------------------------------- 

SR 3.8.1.19

In the event of a DBA coincident with a loss of offsite power, the DGs are 

required to supply the necessary power to ESF systems so that the fuel, 

RCS, and containment design limits are not exceeded. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-33 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

This Surveillance demonstrates the DG operation, as discussed in the 

Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal 

in conjunction with an ESF actuation signal. In lieu of actual 

demonstration of connection and loading of loads, testing that adequately 

shows the capability of the DG system to perform these functions is 

acceptable. This testing may include any series of sequential, 

overlapping, or total steps so that the entire connection and loading 

sequence is verified. 

The Frequency of [18 months] takes into consideration unit conditions 

required to perform the Surveillance and is intended to be consistent with 

an expected fuel cycle length of [18 months]. 

This SR is modified by two Notes. The reason for Note 1 is to minimize 

wear and tear on the DGs during testing. For the purpose of this testing, 

the DGs must be started from standby conditions, that is, with the engine 

coolant and oil continuously circulated and temperature maintained 

consistent with manufacturer recommendations for DGs. The reason for 

Note 2 is that performing the Surveillance would remove a required offsite 

circuit from service, perturb the electrical distribution system, and 

challenge safety systems. This restriction from normally performing the 

Surveillance in MODE 1 or 2 is further amplified to allow portions of the 

Surveillance to be performed for the purpose of reestablishing 

OPERABILITY (e.g., post work testing following corrective maintenance, 

corrective modification, deficient or incomplete surveillance testing, and 

other unanticipated OPERABILITY concerns) provided an assessment 

determines plant safety is maintained or enhanced. This assessment 

shall, as a minimum, consider the potential outcomes and transients 

associated with a failed partial Surveillance, a successful partial 

Surveillance, and a perturbation of the offsite or onsite system when they 

are tied together or operated independently for the partial Surveillance; as 

well as the operator procedures available to cope with these outcomes. 

These shall be measured against the avoided risk of a plant shutdown 

and startup to determine that plant safety is maintained or enhanced 

when portions of the Surveillance are performed in MODE 1 or 2. Risk 

insights or deterministic methods may be used for the assessment. 

Credit may be taken for unplanned events that satisfy this SR. 
AC Sources - Operating 

B 3.8.1 

CEOG STS B 3.8.1-34 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.8.1.20

This Surveillance demonstrates that the DG starting independence has 

not been compromised. Also, this Surveillance demonstrates that each 

engine can achieve proper speed within the specified time when the DGs 

are started simultaneously. 

The 10 year Frequency is consistent with the recommendations of 

Regulatory Guide 1.108 (Ref. 9). 

This SR is modified by a Note. The reason for the Note is to minimize 

wear on the DG during testing. For the purpose of this testing, the DGs 

must be started from standby conditions, that is, with the engine coolant 

and oil continuously circulated, and temperature maintained consistent 

with manufacturer recommendations. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 17. 

 2. FSAR, Chapter [8]. 

 3. Regulatory Guide 1.9, Rev. [3]. 

 4. FSAR, Chapter [6]. 

 5. FSAR, Chapter [15]. 

 6. Regulatory Guide 1.93, Rev. [ ], [date]. 

 7. Generic Letter 84-15. 

 8. 10 CFR 50, Appendix A, GDC 18. 

 9. Regulatory Guide 1.108, Rev. [1], [August 1977]. 

 10. Regulatory Guide 1.137, Rev. [ ], [date]. 

 11. ANSI C84.1-1982. 

 12. ASME, Boiler and Pressure Vessel Code, Section XI. 

 13. IEEE Standard 308-[1978]. 
AC Sources - Shutdown 

B 3.8.2 

CEOG STS B 3.8.2-1 Rev. 3.0, 03/31/04 

B 3.8 ELECTRICAL POWER SYSTEMS 

B 3.8.2 AC Sources - Shutdown 

BASES 

BACKGROUND A description of the AC sources is provided in the Bases for LCO 3.8.1, 

"AC Sources - Operating." 

APPLICABLE The OPERABILITY of the minimum AC sources during MODES 5 and 6 

SAFETY and during movement of [recently] irradiated fuel assemblies ensures 

ANALYSES that: 

a. The unit can be maintained in the shutdown or refueling condition for 

extended periods, 

b. Sufficient instrumentation and control capability is available for 

monitoring and maintaining the unit status, and 

c. Adequate AC electrical power is provided to mitigate events 

postulated during shutdown, such as a fuel handling accident 

[involving handling recently irradiated fuel. Due to radioactive decay, 

AC electrical power is only required to mitigate fuel handling 

accidents involving handling recently irradiated fuel (i.e., fuel that has 

occupied part of a critical reactor core within the previous [X] days)]. 

In general, when the unit is shut down, the Technical Specifications 

requirements ensure that the unit has the capability to mitigate the 

consequences of postulated accidents. However, assuming a single 

failure and concurrent loss of all offsite or all onsite power is not required. 

The rationale for this is based on the fact that many Design Basis 

Accidents (DBAs) that are analyzed in MODES 1, 2, 3, and 4 have no 

specific analyses in MODES 5 and 6. Worst case bounding events are 

deemed not credible in MODES 5 and 6 because the energy contained 

within the reactor pressure boundary, reactor coolant temperature and 

pressure, and the corresponding stresses result in the probabilities of 

occurrence being significantly reduced or eliminated, and in minimal 

consequences. These deviations from DBA analysis assumptions and 

design requirements during shutdown conditions are allowed by the LCO 

for required systems. 
AC Sources - Shutdown 

B 3.8.2 

CEOG STS B 3.8.2-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

During MODES 1, 2, 3, and 4, various deviations from the analysis 

assumptions and design requirements are allowed within the Required 

Actions. This allowance is in recognition that certain testing and 

maintenance activities must be conducted provided an acceptable level of 

risk is not exceeded. During MODES 5 and 6, performance of a 

significant number of required testing and maintenance activities is also 

required. In MODES 5 and 6, the activities are generally planned and 

administratively controlled. Relaxations from MODE 1, 2, 3, and 4 LCO 

requirements are acceptable during shutdown modes based on: 

a. The fact that time in an outage is limited. This is a risk prudent goal 

as well as a utility economic consideration. 

b. Requiring appropriate compensatory measures for certain conditions. 

These may include administrative controls, reliance on systems that 

do not necessarily meet typical design requirements applied to 

systems credited in operating MODE analyses, or both. 

c. Prudent utility consideration of the risk associated with multiple 

activities that could affect multiple systems. 

d. Maintaining, to the extent practical, the ability to perform required 

functions (even if not meeting MODE 1, 2, 3, and 4 OPERABILITY 

requirements) with systems assumed to function during an event. 

In the event of an accident during shutdown, this LCO ensures the 

capability to support systems necessary to avoid immediate difficulty, 

assuming either a loss of all offsite power or a loss of all onsite diesel 

generator (DG) power. 

The AC sources satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO One offsite circuit capable of supplying the onsite Class 1E power 

distribution subsystem(s) of LCO 3.8.10, "Distribution Systems - 

Shutdown," ensures that all required loads are powered from offsite 

power. An OPERABLE DG, associated with a distribution system train 

required to be OPERABLE by LCO 3.8.10, ensures a diverse power 

source is available to provide electrical power support, assuming a loss of 

the offsite circuit. Together, OPERABILITY of the required offsite circuit 

and DG ensures the availability of sufficient AC sources to operate the 

unit in a safe manner and to mitigate the consequences of postulated 

events during shutdown (e.g., fuel handling accidents [involving handling 

recently irradiated fuel]). 
AC Sources - Shutdown 

B 3.8.2 

CEOG STS B 3.8.2-3 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

The qualified offsite circuit must be capable of maintaining rated 

frequency and voltage, and accepting required loads during an accident, 

while connected to the Engineered Safety Feature (ESF) bus(es). 

Qualified offsite circuits are those that are described in the FSAR and are 

part of the licensing basis for the unit. 

 [ Offsite circuit #1 consists of Safeguards Transformer B, which is supplied 

from Switchyard Bus B, and is fed through breaker 52-3 powering the 

ESF transformer XNBO1, which, in turn, powers the #1 ESF bus through 

its normal feeder breaker. The second offsite circuit consists of the 

Startup Transformer, which is normally fed from the Switchyard Bus A, 

and is fed through breaker PA 0201 powering the ESF transformer, 

which, in turn, powers the #2 ESF bus through its normal feeder 

breaker. ]

The DG must be capable of starting, accelerating to rated speed and 

voltage, connecting to its respective ESF bus on detection of bus 

undervoltage, and accepting required loads. This sequence must be 

accomplished within [10] seconds. The DG must be capable of accepting 

required loads within the assumed loading sequence intervals, and must 

continue to operate until offsite power can be restored to the ESF buses. 

These capabilities are required to be met from a variety of initial 

conditions such as DG in standby with the engine hot and DG in standby 

at ambient conditions. 

Proper sequencing of loads, including tripping of nonessential loads, is a 

required function for DG OPERABILITY. 

[ In addition, proper sequencer operation is an integral part of offsite circuit 

OPERABILITY since its inoperability impacts on the ability to start and 

maintain energized loads required OPERABLE by LCO 3.8.10. ]

It is acceptable for trains to be cross tied during shutdown conditions, 

allowing a single offsite power circuit to supply all required trains. 

APPLICABILITY The AC sources required to be OPERABLE in MODES 5 and 6 and 

during movement of [recently] irradiated fuel assemblies provide 

assurance that: 

a. Systems to provide adequate coolant inventory makeup are available 

for the irradiated fuel assemblies, 
AC Sources - Shutdown 

B 3.8.2 

CEOG STS B 3.8.2-4 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY (continued) 

b. Systems needed to mitigate a fuel handling accident [involving 

handling [recently] irradiated fuel (i.e., fuel that has occupied part of a 

critical reactor core within the previous [X] days)] are available, 

c. Systems necessary to mitigate the effects of events that can lead to 

core damage during shutdown are available, and 

d. Instrumentation and control capability is available for monitoring and 

maintaining the unit in a cold shutdown condition or refueling 

condition. 

The AC power requirements for MODES 1, 2, 3, and 4 are covered in 

LCO 3.8.1. 

ACTIONS LCO 3.0.3 is not applicable while in MODE 5 or 6. However, since 

irradiated fuel assembly movement can occur in MODE 1, 2, 3, or 4, the 

ACTIONS have been modified by a Note stating that LCO 3.0.3 is not 

applicable. If moving irradiated fuel assemblies while in MODE 5 or 6, 

LCO 3.0.3 would not specify any action. If moving irradiated fuel 

assemblies while in MODE 1, 2, 3, or 4, the fuel movement is 

independent of reactor operations. Entering LCO 3.0.3, while in MODE 1, 

2, 3, or 4 would require the unit to be shutdown unnecessarily. 

A.1

An offsite circuit would be considered inoperable if it were not available to 

one required ESF train. Although two trains may be required by 

LCO 3.8.10, the remaining train with offsite power available may be 

capable of supporting sufficient required features to allow continuation of 

CORE ALTERATIONS and [recently] irradiated fuel movement. By the 

allowance of the option to declare required features inoperable, with no 

offsite power available, appropriate restrictions will be implemented in 

accordance with the affected required features LCO's ACTIONS. 

A.2.1, A.2.2, A.2.3, A.2.4, B.1, B.2, B.3, and B.4

With the offsite circuit not available to all required trains, the option would 

still exist to declare all required features inoperable. Since this option 

may involve undesired administrative efforts, the allowance for sufficiently 

conservative actions is made. With the required DG inoperable, the 
AC Sources - Shutdown 

B 3.8.2 

CEOG STS B 3.8.2-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

minimum required diversity of AC power sources is not available. It is, 

therefore, required to suspend CORE ALTERATIONS, movement of 

[recently] irradiated fuel assemblies, and operations involving positive 

reactivity additions that could result in loss of required SDM (MODE 5) or 

boron concentration (MODE 6). 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 must be from sources that have a boron 

concentration greater than that what would be required in the RCS for 

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. 

Suspension of these activities does not preclude completion of actions to 

establish a safe conservative condition. These actions minimize the 

probability or the occurrence of postulated events. It is further required to 

immediately initiate action to restore the required AC sources and to 

continue this action until restoration is accomplished in order to provide 

the necessary AC power to the unit safety systems. 

The Completion Time of immediately is consistent with the required times 

for actions requiring prompt attention. The restoration of the required AC 

electrical power sources should be completed as quickly as possible in 

order to minimize the time during which the unit safety systems may be 

without sufficient power. 

Pursuant to LCO 3.0.6, the Distribution System's ACTIONS are not 

entered even if all AC sources to it are inoperable, resulting in deenergization. Therefore, the Required Actions of Condition A are 

modified by a Note to indicate that when Condition A is entered with no 

AC power to any required ESF bus, the ACTIONS for LCO 3.8.10 must 

be immediately entered. This Note allows Condition A to provide 

requirements for the loss of the offsite circuit, whether or not a train is deenergized. LCO 3.8.10 provides the appropriate restrictions for the 

situation involving a de-energized train. 
AC Sources - Shutdown 

B 3.8.2 

CEOG STS B 3.8.2-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.8.2.1

REQUIREMENTS 

SR 3.8.2.1 requires the SRs from LCO 3.8.1 that are necessary for 

ensuring the OPERABILITY of the AC sources in other than MODES 1, 2, 

3, and 4. SR 3.8.1.8 is not required to be met since only one offsite 

circuit is required to be OPERABLE. SR 3.8.1.12 and SR 3.8.1.19 are 

not required to be met because the ESF actuation signal is not required to 

be OPERABLE. SR 3.8.1.17 is not required to be met because the 

required OPERABLE DG(s) is not required to undergo periods of being 

synchronized to the offsite circuit. SR 3.8.1.20 is excepted because 

starting independence is not required with DG(s) that are not required to 

be OPERABLE. 

This SR is modified by a Note. The reason for the Note is to preclude 

requiring the OPERABLE DG(s) from being paralleled with the offsite 

power network or otherwise rendered inoperable during performance of 

SRs, and to preclude deenergizing a required 4160 V ESF bus or 

disconnecting a required offsite circuit during performance of SRs. With 

limited AC Sources available, a single event could compromise both the 

required circuit and the DG. It is the intent that these SRs must still be 

capable of being met, but actual performance is not required during 

periods when the DG and offsite circuit is required to be OPERABLE. 

Refer to the corresponding Bases for LCO 3.8.1 for a discussion of each 

SR. 

REFERENCES None. 
Diesel Fuel Oil, Lube Oil, and Starting Air 

B 3.8.3 

CEOG STS B 3.8.3-1 Rev. 3.0, 03/31/04 

B 3.8 ELECTRICAL POWER SYSTEMS 

B 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air 

BASES 

BACKGROUND Each diesel generator (DG) is provided with a storage tank having a fuel 

oil capacity sufficient to operate that diesel for a period of 7 days, while 

the DG is supplying maximum post loss of coolant accident load demand 

as discussed in the FSAR, Section [9.5.4.2] (Ref. 1). The maximum load 

demand is calculated using the assumption that at least two DGs are 

available. This onsite fuel oil capacity is sufficient to operate the DGs for 

longer than the time to replenish the onsite supply from outside sources. 

Fuel oil is transferred from storage tank to day tank by either of two 

transfer pumps associated with each storage tank. Redundancy of 

pumps and piping precludes the failure of one pump, or the rupture of any 

pipe, valve, or tank to result in the loss of more than one DG. All outside 

tanks, pumps, and piping are located underground. 

For proper operation of the standby DGs, it is necessary to ensure the 

proper quality of the fuel oil. Regulatory Guide 1.137 (Ref. 2) addresses 

the recommended fuel oil practices as supplemented by ANSI N195-1976 

(Ref. 3). The fuel oil properties governed by these SRs are the water and 

sediment content, the kinematic viscosity, specific gravity (or API gravity), 

and impurity level. 

The DG lubrication system is designed to provide sufficient lubrication to 

permit proper operation of its associated DG under all loading conditions. 

The system is required to circulate the lube oil to the diesel engine 

working surfaces and to remove excess heat generated by friction during 

operation. Each engine oil sump contains an inventory capable of 

supporting a minimum of [7] days of operation. [The onsite storage in 

addition to the engine oil sump is sufficient to ensure 7 days of continuous 

operation.] This supply is sufficient supply to allow the operator to 

replenish lube oil from outside sources. 

Each DG has an air start system with adequate capacity for five 

successive start attempts on the DG without recharging the air start 

receiver(s). 
Diesel Fuel Oil, Lube Oil, and Starting Air 

B 3.8.3 

CEOG STS B 3.8.3-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The initial conditions of Design Basis Accident (DBA) and transient 

SAFETY analyses in the FSAR, Chapter [6] (Ref. 4), and in the FSAR, 

ANALYSES Chapter [15] (Ref. 5), assume Engineered Safety Feature (ESF) systems 

are OPERABLE. The DGs are designed to provide sufficient capacity, 

capability, redundancy, and reliability to ensure the availability of 

necessary power to ESF systems so that fuel, Reactor Coolant System 

and containment design limits are not exceeded. These limits are 

discussed in more detail in the Bases for LCO Section 3.2, Power 

Distribution Limits; Section 3.4, Reactor Coolant System (RCS); and 

Section 3.6, Containment Systems. 

Since diesel fuel oil, lube oil, and the air start subsystems support the 

operation of the standby AC power sources, they satisfy Criterion 3 of 

10 CFR 50.36(c)(2)(ii). 

LCO Stored diesel fuel oil is required to have sufficient supply for 7 days of full 

load operation. It is also required to meet specific standards for quality. 

Additionally, sufficient lubricating oil supply must be available to ensure 

the capability to operate at full load for 7 days. This requirement, in 

conjunction with an ability to obtain replacement supplies within 7 days, 

supports the availability of DGs required to shut down the reactor and to 

maintain it in a safe condition for an anticipated operational occurrence 

(AOO) or a postulated DBA with loss of offsite power. DG day tank fuel 

requirements, as well as transfer capability from the storage tank to the 

day tank, are addressed in LCO 3.8.1, "AC Sources - Operating," and 

LCO 3.8.2, "AC Sources - Shutdown." 

The starting air system is required to have a minimum capacity for five 

successive DG start attempts without recharging the air start receivers. 

APPLICABILITY The AC sources (LCO 3.8.1 and LCO 3.8.2) are required to ensure the 

availability of the required power to shut down the reactor and maintain it 

in a safe shutdown condition after an AOO or a postulated DBA. Since 

stored diesel fuel oil, lube oil, and starting air subsystems support 

LCO 3.8.1 and LCO 3.8.2, stored diesel fuel oil, lube oil and starting air 

are required to be within limits when the associated DG is required to be 

OPERABLE. 

ACTIONS The ACTIONS Table is modified by a Note indicating that separate 

Condition entry is allowed for each DG. This is acceptable, since the 

Required Actions for each Condition provide appropriate compensatory 

actions for each inoperable DG subsystem. Complying with the Required 

Actions for one inoperable DG subsystem may allow for continued 

operation, and subsequent inoperable DG subsystem(s) are governed by 

separate Condition entry and application of associated Required Actions. 
Diesel Fuel Oil, Lube Oil, and Starting Air 

B 3.8.3 

CEOG STS B 3.8.3-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

A.1

In this Condition, the 7 day fuel oil supply for a DG is not available. 

However, the Condition is restricted to fuel oil level reductions, that 

maintain at least a 6 day supply. These circumstances may be caused by 

events such as full load operation required after an inadvertent start while 

at minimum required level; or feed and bleed operations, which may be 

necessitated by increasing particulate levels or any number of other oil 

quality degradations. This restriction allows sufficient time for obtaining 

the requisite replacement volume and performing the analyses required 

prior to addition of fuel oil to the tank. A period of 48 hours is considered 

sufficient to complete restoration of the required level prior to declaring 

the DG inoperable. This period is acceptable based on the remaining 

capacity (≥ 6 days), the fact that procedures will be initiated to obtain 

replenishment, and the low probability of an event during this brief period. 

B.1

With lube oil inventory < 500 gal, sufficient lubricating oil to support 

7 days of continuous DG operation at full load conditions may not be 

available. However, the Condition is restricted to lube oil volume 

reductions that maintain at least a 6 day supply. This restriction allows 

sufficient time to obtain the requisite replacement volume. A period of 

48 hours is considered sufficient to complete restoration of the required 

volume prior to declaring the DG inoperable. This period is acceptable 

based on the remaining capacity (> 6 days), the low rate of usage, the 

fact that procedures will be initiated to obtain replenishment, and the low 

probability of an event during this brief period. 

C.1

This Condition is entered as a result of a failure to meet the acceptance 

criterion of SR 3.8.3.5. Normally, trending of particulate levels allows 

sufficient time to correct high particulate levels prior to reaching the limit 

of acceptability. Poor sample procedures (bottom sampling), 

contaminated sampling equipment, and errors in laboratory analysis can 

produce failures that do not follow a trend. Since the presence of 

particulates does not mean failure of the fuel oil to burn properly in the 

diesel engine, and particulate concentration is unlikely to change 
Diesel Fuel Oil, Lube Oil, and Starting Air 

B 3.8.3 

CEOG STS B 3.8.3-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

significantly between Surveillance Frequency intervals, and proper engine 

performance has been recently demonstrated (within 31 days), it is 

prudent to allow a brief period prior to declaring the associated DG 

inoperable. The 7 day Completion Time allows for further evaluation, 

resampling, and re-analysis of the DG fuel oil. 

D.1

With the new fuel oil properties defined in the Bases for SR 3.8.3.4 not 

within the required limits, a period of 30 days is allowed for restoring the 

stored fuel oil properties. This period provides sufficient time to test the 

stored fuel oil to determine that the new fuel oil, when mixed with 

previously stored fuel oil, remains acceptable, or restore the stored fuel oil 

properties. This restoration may involve feed and bleed procedures, 

filtering, or combinations of these procedures. Even if a DG start and 

load was required during this time interval and the fuel oil properties were 

outside limits, there is a high likelihood that the DG would still be capable 

of performing its intended function. 

E.1

With starting air receiver pressure < [225] psig, sufficient capacity for five 

successive DG start attempts does not exist. However, as long as the 

receiver pressure is > [125] psig, there is adequate capacity for at least 

one start attempt, and the DG can be considered OPERABLE while the 

air receiver pressure is restored to the required limit. A period of 48 hours 

is considered sufficient to complete restoration to the required pressure 

prior to declaring the DG inoperable. This period is acceptable based on 

the remaining air start capacity, the fact that most DG starts are 

accomplished on the first attempt, and the low probability of an event 

during this brief period. 

F.1

With a Required Action and associated Completion Time not met, or one 

or more DGs with diesel fuel oil, lube oil, or starting air subsystem not 

within limits for reasons other than addressed by Conditions A through E, 

the associated DG may be incapable of performing its intended function 

and must be immediately declared inoperable. 
Diesel Fuel Oil, Lube Oil, and Starting Air 

B 3.8.3 

CEOG STS B 3.8.3-5 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.8.3.1

REQUIREMENTS 

This SR provides verification that there is an adequate inventory of fuel oil 

in the storage tanks to support each DG's operation for 7 days at full load. 

The 7 day period is sufficient time to place the unit in a safe shutdown 

condition and to bring in replenishment fuel from an offsite location. 

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. 

SR 3.8.3.2

This Surveillance ensures that sufficient lube oil inventory is available to 

support at least 7 days of full load operation for each DG. The [500] gal 

requirement is based on the DG manufacturer consumption values for the 

run time of the DG. Implicit in this SR is the requirement to verify the 

capability to transfer the lube oil from its storage location to the DG, when 

the DG lube oil sump does not hold adequate inventory for 7 days of full 

load operation without the level reaching the manufacturer recommended 

minimum level. 

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. 

SR 3.8.3.3

The tests listed below are a means of determining whether new fuel oil is 

of the appropriate grade and has not been contaminated with substances 

that would have an immediate, detrimental impact on diesel engine 

combustion. If results from these tests are within acceptable limits, the 

fuel oil may be added to the storage tanks without concern for 

contaminating the entire volume of fuel oil in the storage tanks. These 

tests are to be conducted prior to adding the new fuel to the storage 

tank(s), but in no case is the time between receipt of new fuel and 

conducting the tests to exceed 31 days. The tests, limits, and applicable 

ASTM Standards are as follows: 

a. Sample the new fuel oil in accordance with ASTM D4057-[ ] (Ref. 6), 
Diesel Fuel Oil, Lube Oil, and Starting Air 

B 3.8.3 

CEOG STS B 3.8.3-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

b. Verify in accordance with the tests specified in ASTM D975-[ ] 

(Ref. 6) that the sample has an absolute specific gravity at 60/60°F of 

≥ 0.83 and ≤ 0.89, or an API gravity at 60°F of ≥ 27° and ≤ 39° when 

tested in accordance with ASTM D1298-[ ] (Ref. 6), a kinematic 

viscosity at 40°C of ≥ 1.9 centistokes and ≤ 4.1 centistokes, and a 

flash point ≥ 125°F, and 

c. Verify that the new fuel oil has a clear and bright appearance with 

proper color when tested in accordance with ASTM D4176-[ ] or a 

water and sediment content within limits when tested in accordance 

with [ASTM D2709-[ ]] (Ref. 6). 

Failure to meet any of the above limits is cause for rejecting the new fuel 

oil, but does not represent a failure to meet the LCO concern since the 

fuel oil is not added to the storage tanks. 

Within 31 days following the initial new fuel oil sample, the fuel oil is 

analyzed to establish that the other properties specified in Table 1 of 

ASTM D975-[ ] (Ref. 7) are met for new fuel oil when tested in 

accordance with ASTM D975-[ ] (Ref. 6), except that the analysis for 

sulfur may be performed in accordance with ASTM D1552-[ ], 

ASTM D2622-[ ], or ASTM D4294-[ ] (Ref. 6). The 31 day period is 

acceptable because the fuel oil properties of interest, even if they were 

not within stated limits, would not have an immediate effect on DG 

operation. This Surveillance ensures the availability of high quality fuel oil 

for the DGs. 

Fuel oil degradation during long term storage shows up as an increase in 

particulate, due mostly to oxidation. The presence of particulate does not 

mean the fuel oil will not burn properly in a diesel engine. The particulate 

can cause fouling of filters and fuel oil injection equipment, however, 

which can cause engine failure. 

Particulate concentrations should be determined in accordance with 

ASTM D5452-[ ] (Ref. 6). This method involves a gravimetric 

determination of total particulate concentration in the fuel oil and has a 

limit of 10 mg/l. It is acceptable to obtain a field sample for subsequent 

laboratory testing in lieu of field testing. [For those designs in which the 

total stored fuel oil volume is contained in two or more interconnected 

tanks, each tank must be considered and tested separately.] 

The Frequency of this test takes into consideration fuel oil degradation 

trends that indicate that particulate concentration is unlikely to change 

significantly between Frequency intervals. 
Diesel Fuel Oil, Lube Oil, and Starting Air 

B 3.8.3 

CEOG STS B 3.8.3-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.8.3.4

This Surveillance ensures that, without the aid of the refill compressor, 

sufficient air start capacity for each DG is available. The system design 

requirements provide for a minimum of [five] engine start cycles without 

recharging. [A start cycle is defined by the DG vendor, but usually is 

measured in terms of time (seconds or cranking) or engine cranking 

speed.] The pressure specified in this SR is intended to reflect the 

lowest value at which the [five] starts can be accomplished. 

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. 

SR 3.8.3.5

Microbiological fouling is a major cause of fuel oil degradation. There are 

numerous bacteria that can grow in fuel oil and cause fouling, but all must 

have a water environment in order to survive. Removal of water from the 

fuel storage tanks once every [31] days eliminates the necessary 

environment for bacterial survival. This is the most effective means of 

controlling microbiological fouling. In addition, it eliminates the potential 

for water entrainment in the fuel oil during DG operation. Water may 

come from any of several sources, including condensation, ground water, 

rain water, and contaminated fuel oil, and from breakdown of the fuel oil 

by bacteria. Frequent checking for and removal of accumulated water 

minimizes fouling and provides data regarding the watertight integrity of 

the fuel oil system. The Surveillance Frequencies are established by 

Regulatory Guide 1.137 (Ref. 2). This SR is for preventative 

maintenance. The presence of water does not necessarily represent 

failure of this SR provided the accumulated water is removed during 

performance of the Surveillance. 

REFERENCES 1. FSAR, Section [9.5.4.2]. 

 2. Regulatory Guide 1.137. 

 3. ANSI N195-1976, Appendix B. 

 4. FSAR, Chapter [6]. 
Diesel Fuel Oil, Lube Oil, and Starting Air 

B 3.8.3 

CEOG STS B 3.8.3-8 Rev. 3.0, 03/31/04 

BASES 

REFERENCES (continued) 

 5. FSAR, Chapter [15]. 

 6. ASTM Standards: D4057-[ ]; D975-[ ]; D1298-[ ]; D4176-[ ]; 

[D2709-[ ];] D1552-[ ]; D2622-[ ]; D4294-[ ]; D5452-[ ]. 

 7. ASTM Standards, D975-[ ], Table 1. 
DC Sources - Operating 

B 3.8.4 

CEOG STS B 3.8.4-1 Rev. 3.0, 03/31/04 

B 3.8 ELECTRICAL POWER SYSTEMS 

B 3.8.4 DC Sources - Operating 

BASES 

BACKGROUND The station DC electrical power system provides the AC emergency 

power system with control power. It also provides both motive and 

control power to selected safety related equipment and preferred AC vital 

bus power (via inverters). As required by 10 CFR 50, Appendix A, 

GDC 17 (Ref. 1), the DC electrical power system is designed to have 

sufficient independence, redundancy, and testability to perform its safety 

functions, assuming a single failure. The DC electrical power system also 

conforms to the recommendations of Regulatory Guide 1.6 (Ref. 2) and 

IEEE-308 (Ref. 3). 

The [125/250] VDC electrical power system consists of two independent 

and redundant safety related Class 1E DC electrical power subsystems 

([Train A and Train B]). Each subsystem consists of [two] 125 VDC 

batteries [(each battery [50]% capacity)], the associated battery 

charger(s) for each battery, and all the associated control equipment and 

interconnecting cabling. 

[ The 250 VDC source is obtained by use of the two 125 VDC batteries 

connected in series. Additionally there is [one] spare battery charger per 

subsystem, which provides backup service in the event that the preferred 

battery charger is out of service. If the spare battery charger is 

substituted for one of the preferred battery chargers, then the 

requirements of independence and redundancy between subsystems are 

maintained. ]

During normal operation, the [125/250] VDC load is powered from the 

battery chargers with the batteries floating on the system. In case of loss 

of normal power to the battery charger, the DC load is automatically 

powered from the station batteries. 

The [Train A and Train B] DC electrical power subsystems provide the 

control power for its associated Class 1E AC power load group, [4.16] kV 

switchgear, and [480] V load centers. The DC electrical power 

subsystems also provide DC electrical power to the inverters, which in 

turn power the AC vital buses. 

The DC power distribution system is described in more detail in the Bases 

for LCO 3.8.9, "Distributions System Operating," and for LCO 3.8.10, 

"Distribution Systems - Shutdown." 
DC Sources - Operating 

B 3.8.4 

CEOG STS B 3.8.4-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

Each 125/250 VDC battery is separately housed in a ventilated room 

apart from its charger and distribution centers. Each subsystem is 

located in an area separated physically and electrically from the other 

subsystem to ensure that a single failure in one subsystem does not 

cause a failure in a redundant subsystem. There is no sharing between 

redundant Class 1E subsystems, such as batteries, battery chargers, or 

distribution panels. 

Each battery has adequate storage capacity to meet the duty cycle(s) 

discussed in the FSAR, Chapter [8] (Ref 4). The battery is designed with 

additional capacity above that required by the design duty cycle to allow 

for temperature variations and other factors. 

The batteries for Train A and Train B DC electrical power subsystems are 

sized to produce required capacity at 80% of nameplate rating, 

corresponding to warranted capacity at end of life cycles and the 100% 

design demand. The minimum design voltage limit is 105/210 V. 

The battery cells are of flooded lead acid construction with a nominal 

specific gravity of [1.215]. This specific gravity corresponds to an open 

circuit battery voltage of approximately 120 V for a [58] cell battery (i.e., 

cell voltage of [2.065] volts per cell (Vpc)). The open circuit voltage is the 

voltage maintained when there is no charging or discharging. Once fully 

charged with its open circuit voltage ≥ [2.065] Vpc, the battery cell will 

maintain its capacity for [30] days without further charging per 

manufacturer's instructions. Optimal long term performance however, is 

obtained by maintaining a float voltage [2.20 to 2.25] Vpc. This provides 

adequate over-potential, which limits the formation of lead sulfate and self 

discharge. The nominal float voltage of [2.22] Vpc corresponds to a total 

float voltage output of [128.8] V for a [58] cell battery as discussed in the 

FSAR, Chapter [8] (Ref. 4). 

Each Train A and Train B DC electrical power subsystem battery charger 

has ample power output capacity for the steady state operation of 

connected loads required during normal operation, while at the same time 

maintaining its battery bank fully charged. Each battery charger also has 

sufficient excess capacity to restore the battery from the design minimum 

charge to its fully charged state within 24 hours while supplying normal 

steady state loads discussed in the FSAR, Chapter [8] (Ref. 4). 
DC Sources - Operating 

B 3.8.4 

CEOG STS B 3.8.4-3 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The battery charger is normally in the float-charge mode. Float-charge is 

the condition in which the charger is supplying the connected loads and 

the battery cells are receiving adequate current to optimally charge the 

battery. This assures the internal losses of a battery are overcome and 

the battery is maintained in a fully charged state. 

When desired, the charger can be placed in the equalize mode. The 

equalize mode is at a higher voltage than the float mode and charging 

current is correspondingly higher. The battery charger is operated in the 

equalize mode after a battery discharge or for routine maintenance. 

Following a battery discharge, the battery recharge characteristic accepts 

current at the current limit of the battery charger (if the discharge was 

significant, e.g., following a battery service test) until the battery terminal 

voltage approaches the charger voltage setpoint. Charging current then 

reduces exponentially during the remainder of the recharge cycle. Leadcalcium batteries have recharge efficiencies of greater than 95%, so once 

at least 105% of the ampere-hours discharged have been returned, the 

battery capacity would be restored to the same condition as it was prior to 

the discharge. This can be monitored by direct observation of the 

exponentially decaying charging current or by evaluating the amp-hours 

discharged from the battery and amp-hours returned to the battery. 

APPLICABLE The initial conditions of Design Basis Accident (DBA) and transient 

SAFETY analyses in the FSAR, Chapter [6] (Ref. 5) and Chapter [15] (Ref. 6), 

ANALYSES assume that Engineered Safety Feature (ESF) systems are OPERABLE. 

The DC electrical power system provides normal and emergency DC 

electrical power for the DGs, emergency auxiliaries, and control and 

switching during all MODES of operation. 

The OPERABILITY of the DC sources is consistent with the initial 

assumptions of the accident analyses and is based upon meeting the 

design basis of the unit. This includes maintaining the DC sources 

OPERABLE during accident conditions in the event of: 

a. An assumed loss of all offsite AC power or all onsite AC power and 

b. A worst-case single failure. 

The DC sources satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 
DC Sources - Operating 

B 3.8.4 

CEOG STS B 3.8.4-4 Rev. 3.0, 03/31/04 

BASES 

LCO The DC electrical power subsystems, each subsystem consisting of [two] 

batteries, battery charger [for each battery] and the corresponding control 

equipment and interconnecting cabling supplying power to the associated 

bus within the train are required to be OPERABLE to ensure the 

availability of the required power to shut down the reactor and maintain it 

in a safe condition after an anticipated operational occurrence (AOO) or a 

postulated DBA. Loss of any train DC electrical power subsystem does 

not prevent the minimum safety function from being performed (Ref. 4). 

An OPERABLE DC electrical power subsystem requires all required 

batteries and respective chargers to be operating and connected to the 

associated DC bus(es). 

APPLICABILITY The DC electrical power sources are required to be OPERABLE in 

MODES 1, 2, 3, and 4 to ensure safe unit operation and to ensure that: 

a. Acceptable fuel design limits and reactor coolant pressure boundary 

limits are not exceeded as a result of AOOs or abnormal transients 

and 

b. Adequate core cooling is provided, and containment integrity and 

other vital functions are maintained in the event of a postulated DBA. 

The DC electrical power requirements for MODES 5 and 6 are addressed 

in the Bases for LCO 3.8.5, "DC Sources - Shutdown." 

ACTIONS A.1, A.2, and A.3

Condition A represents one train with one [or two] battery chargers 

inoperable (e.g., the voltage limit of SR 3.8.4.1 is not maintained). The 

ACTIONS provide a tiered response that focuses on returning the battery 

to the fully charged state and restoring a fully qualified charger to 

OPERABLE status in a reasonable time period. Required Action A.1 

requires that the battery terminal voltage be restored to greater than or 

equal to the minimum established float voltage within 2 hours. This time 

provides for returning the inoperable charger to OPERABLE status or 

providing an alternate means of restoring battery terminal voltage to 

greater than or equal to the minimum established float voltage. Restoring 

the battery terminal voltage to greater than or equal to the minimum 

established float voltage provides good assurance that, within [12] hours, 

the battery will be restored to its fully charged condition (Required 

Action A.2) from any discharge that might have occurred due to the 

charger inoperability. 
DC Sources - Operating 

B 3.8.4 

CEOG STS B 3.8.4-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

A plant that cannot meet the 12 hour Completion Time due to an inherent 

battery charging characteristic can propose an alternate time equal to 

2 hours plus the time experienced to accomplish the exponential charging 

current portion of the battery charge profile following the service test 

(SR 3.8.4.3). 

-------------------------------------------------------------------------------------------------- 

A discharged battery having terminal voltage of at least the minimum 

established float voltage indicates that the battery is on the exponential 

charging current portion (the second part) of its recharge cycle. The time 

to return a battery to its fully charged state under this condition is simply a 

function of the amount of the previous discharge and the recharge 

characteristic of the battery. Thus there is good assurance of fully 

recharging the battery within [12] hours, avoiding a premature shutdown 

with its own attendant risk. 

If established battery terminal float voltage cannot be restored to greater 

than or equal to the minimum established float voltage within 2 hours, and 

the charger is not operating in the current-limiting mode, a faulty charger 

is indicated. A faulty charger that is incapable of maintaining established 

battery terminal float voltage does not provide assurance that it can revert 

to and operate properly in the current limit mode that is necessary during 

the recovery period following a battery discharge event that the DC 

system is designed for. 

If the charger is operating in the current limit mode after 2 hours that is an 

indication that the battery is partially discharged and its capacity margins 

will be reduced. The time to return the battery to its fully charged 

condition in this case is a function of the battery charger capacity, the 

amount of loads on the associated DC system, the amount of the 

previous discharge, and the recharge characteristic of the battery. The 

charge time can be extensive, and there is not adequate assurance that it 

can be recharged within [12] hours (Required Action A.2). 

Required Action A.2 requires that the battery float current be verified as 

less than or equal to [2] amps. This indicates that, if the battery had been 

discharged as the result of the inoperable battery charger, it has now 

been fully recharged. If at the expiration of the initial [12] hour period the 

battery float current is not less than or equal to [2] amps this indicates 

there may be additional battery problems and the battery must be 

declared inoperable. 
DC Sources - Operating 

B 3.8.4 

CEOG STS B 3.8.4-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Required Action A.3 limits the restoration time for the inoperable battery 

charger to 7 days. This action is applicable if an alternate means of 

restoring battery terminal voltage to greater than or equal to the minimum 

established float voltage has been used (e.g., balance of plant non-Class 

1E battery charger). The 7 day Completion Time reflects a reasonable 

time to effect restoration of the qualified battery charger to OPERABLE 

status. 

B.1

-----------------------------------REVIEWER’S NOTE----------------------------------- 

The 2 hour Completion Times of Required Actions B.1 and C.1 are in 

brackets. Any licensee wishing to request a longer Completion Time will 

need to demonstrate that the longer Completion Time is appropriate for 

the plant in accordance with the guidance in Regulatory Guide (RG) 

1.177, "An Approach for Plant-Specific, Risk-Informed Decision Making: 

Technical Specifications." 

-------------------------------------------------------------------------------------------------- 

Condition B represents one train with one [or two] batter[y][ies] 

inoperable. With one [or two] batter[y][ies] inoperable, the DC bus is 

being supplied by the OPERABLE battery charger[s]. Any event that 

results in a loss of the AC bus supporting the battery charger[s] will also 

result in loss of DC to that train. Recovery of the AC bus, especially if it is 

due to a loss of offsite power, will be hampered by the fact that many of 

the components necessary for the recovery (e.g., diesel generator control 

and field flash, AC load shed and diesel generator output circuit breakers, 

etc.) likely rely upon the batter[y][ies]. In addition the energization 

transients of any DC loads that are beyond the capability of the battery 

charger[s] and normally require the assistance of the batter[y][ies] will not 

be able to be brought online. The [2] hour limit allows sufficient time to 

effect restoration of an inoperable battery given that the majority of the 

conditions that lead to battery inoperability (e.g., loss of battery charger, 

battery cell voltage less than [2.07] V, etc.) are identified in 

Specifications 3.8.4, 3.8.5, and 3.8.6 together with additional specific 

completion times. 
DC Sources - Operating 

B 3.8.4 

CEOG STS B 3.8.4-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

C.1

Condition C represents one train with a loss of ability to completely 

respond to an event, and a potential loss of ability to remain energized 

during normal operation. It is therefore, imperative that the operator's 

attention focus on stabilizing the unit, minimizing the potential for 

complete loss of DC power to the affected train. The 2 hour limit is 

consistent with the allowed time for an inoperable DC distribution system 

train. 

If one of the required DC electrical power subsystems is inoperable for 

reasons other than Condition A or B (e.g., inoperable battery charger and 

associated inoperable battery), the remaining DC electrical power 

subsystem has the capacity to support a safe shutdown and to mitigate 

an accident condition. Since a subsequent worst case single failure 

could, however, result in the loss of minimum necessary DC electrical 

subsystems to mitigate a worst case accident, continued power operation 

should not exceed 2 hours. The 2 hour Completion Time is based on 

Regulatory Guide 1.93 (Ref. 7) and reflects a reasonable time to assess 

unit status as a function of the inoperable DC electrical power subsystem 

and, if the DC electrical power subsystem is not restored to OPERABLE 

status, to prepare to effect an orderly and safe unit shutdown. 

D.1 and D.2

If the inoperable DC electrical power subsystem cannot be restored to 

OPERABLE status within the required Completion Time, the unit must be 

brought to a MODE in which the LCO does not apply. To achieve this 

status, the unit must be brought to at least MODE 3 within 6 hours and to 

MODE 5 within 36 hours. The allowed Completion Times are reasonable, 

based on operating experience, to reach the required unit conditions from 

full power conditions in an orderly manner and without challenging plant 

systems. The Completion Time to bring the unit to MODE 5 is consistent 

with the time required in Regulatory Guide 1.93 (Ref. 7). 

SURVEILLANCE SR 3.8.4.1

REQUIREMENTS 

Verifying battery terminal voltage while on float charge helps to ensure 

the effectiveness of the battery chargers, which support the ability of the 

batteries to perform their intended function. Float charge is the condition 

in which the charger is supplying the continuous charge required to 

overcome the internal losses of a battery and maintain the battery in a 
DC Sources - Operating 

B 3.8.4 

CEOG STS B 3.8.4-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

fully charged state while supplying the continuous steady state loads of 

the associated DC subsystem. On float charge, battery cells will receive 

adequate current to optimally charge the battery. The voltage 

requirements are based on the nominal design voltage of the battery and 

are consistent with the minimum float voltage established by the battery 

manufacturer ([2.20] Vpc or [127.6] V at the battery terminals). This 

voltage maintains the battery plates in a condition that supports 

maintaining the grid life (expected to be approximately 20 years). The 

7 day Frequency is consistent with manufacturer recommendations and 

IEEE-450 (Ref. 8). 

SR 3.8.4.2

This SR verifies the design capacity of the battery chargers. According to 

Regulatory Guide 1.32 (Ref. 9), the battery charger supply is 

recommended to be based on the largest combined demands of the 

various steady state loads and the charging capacity to restore the 

battery from the design minimum charge state to the fully charged state, 

irrespective of the status of the unit during these demand occurrences. 

The minimum required amperes and duration ensure that these 

requirements can be satisfied. 

This SR provides two options. One option requires that each battery 

charger be capable of supplying [400] amps at the minimum established 

float voltage for [8] hours. The ampere requirements are based on the 

output rating of the chargers. The voltage requirements are based on the 

charger voltage level after a response to a loss of AC power. The time 

period is sufficient for the charger temperature to have stabilized and to 

have been maintained for at least [2] hours. 

The other option requires that each battery charger be capable of 

recharging the battery after a service test coincident with supplying the 

largest coincident demands of the various continuous steady state loads 

(irrespective of the status of the plant during which these demands 

occur). This level of loading may not normally be available following the 

battery service test and will need to be supplemented with additional 

loads. The duration for this test may be longer than the charger sizing 

criteria since the battery recharge is affected by float voltage, 

temperature, and the exponential decay in charging current. The battery 

is recharged when the measured charging current is ≤ [2] amps. 
DC Sources - Operating 

B 3.8.4 

CEOG STS B 3.8.4-9 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

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. 

SR 3.8.4.3

A battery service test is a special test of the battery capability, as found, 

to satisfy the design requirements (battery duty cycle) of the DC electrical 

power system. The discharge rate and test length should correspond to 

the design duty cycle requirements as specified in Reference 4. 

The Surveillance Frequency of [18 months] is consistent with the 

recommendations of Regulatory Guide 1.32 (Ref. 9) and Regulatory 

Guide 1.129 (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]. 

This SR is modified by two Notes. Note 1 allows the performance of a 

modified performance discharge test in lieu of a service test. 

The reason for Note 2 is that performing the Surveillance would perturb 

the electrical distribution system and challenge safety systems. This 

restriction from normally performing the Surveillance in MODE 1 or 2 is 

further amplified to allow portions of the Surveillance to be performed for 

the purpose of reestablishing OPERABILITY (e.g., post work testing 

following corrective maintenance, corrective modification, deficient or 

incomplete surveillance testing, and other unanticipated OPERABILITY 

concerns) provided an assessment determines plant safety is maintained 

or enhanced. This assessment shall, as a minimum, consider the 

potential outcomes and transients associated with a failed partial 

Surveillance, a successful partial Surveillance, and a perturbation of the 

offsite or onsite system when they are tied together or operated 

independently for the partial Surveillance; as well as the operator 

procedures available to cope with these outcomes. These shall be 

measured against the avoided risk of a plant shutdown and startup to 

determine that plant safety is maintained or enhanced when portions of 

the Surveillance are performed in MODE 1 or 2. Risk insights or 

deterministic methods may be used for the assessment. Credit may be 

taken for unplanned events that satisfy this SR. 
DC Sources - Operating 

B 3.8.4 

CEOG STS B 3.8.4-10 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 17. 

 2. Regulatory Guide 1.6, March 10, 1971. 

 3. IEEE-308-[1978]. 

 4. FSAR, Chapter [8]. 

 5. FSAR, Chapter [6]. 

 6. FSAR, Chapter [15]. 

 7. Regulatory Guide 1.93, December 1974. 

 8. IEEE-450-[1995]. 

 9. Regulatory Guide 1.32, February 1977. 

 10. Regulatory Guide 1.129, December 1974. 
DC Sources - Shutdown 

B 3.8.5 

CEOG STS B 3.8.5-1 Rev. 3.0, 03/31/04 

B 3.8 ELECTRICAL POWER SYSTEMS 

B 3.8.5 DC Sources - Shutdown 

BASES 

BACKGROUND A description of the DC sources is provided in the Bases for LCO 3.8.4, 

"DC Sources - Operating." 

APPLICABLE The initial conditions of Design Basis Accident (DBA) and transient 

SAFETY analyses in the FSAR, Chapter [6] (Ref. 1) and Chapter [15] (Ref. 2), 

ANALYSES assume that Engineered Safety Feature (ESF) systems are OPERABLE. 

The DC electrical power system provides normal and emergency DC 

electrical power for the DGs, emergency auxiliaries, and control and 

switching during all MODES of operation. 

The OPERABILITY of the DC subsystems is consistent with the initial 

assumptions of the accident analyses and the requirements for the 

supported systems' OPERABILITY. 

The OPERABILITY of the minimum DC electrical power sources during 

MODES 5 and 6 and during movement of [recently] irradiated fuel 

assemblies ensures that: 

a. The unit can be maintained in the shutdown or refueling condition for 

extended periods, 

b. Sufficient instrumentation and control capability is available for 

monitoring and maintaining the unit status, and 

c. Adequate DC electrical power is provided to mitigate events 

postulated during shutdown, such as a fuel handling accident 

[involving handling recently irradiated fuel. Due to radioactive decay, 

DC electrical power is only required to mitigate fuel handling 

accidents involving handling recently irradiated fuel (i.e., fuel that has 

occupied part of a critical reactor core within the previous [X] days)]. 

In general, when the unit is shut down, the Technical Specifications 

requirements ensure that the unit has the capability to mitigate the 

consequences of postulated accidents. However, assuming a single 

failure and concurrent loss of all offsite or all onsite power is not required. 

The rationale for this is based on the fact that many DBAs that are 
DC Sources - Shutdown 

B 3.8.5 

CEOG STS B 3.8.5-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

analyzed in MODES [1, 2, 3, and 4] have no specific analyses in MODES 

[5 and 6] because the energy contained within the reactor pressure 

boundary, reactor coolant temperature and pressure, and the 

corresponding stresses result in the probabilities of occurrence being 

significantly reduced or eliminated, and in minimal consequences. These 

deviations from DBA analysis assumptions and design requirements 

during shutdown conditions are allowed by the LCO for required systems. 

The shutdown Technical Specification requirements are designed to 

ensure that the unit has the capability to mitigate the consequences of 

certain postulated accidents. Worst case DBAs which are analyzed for 

operating MODES are generally viewed not to be a significant concern 

during shutdown MODES due to the lower energies involved. The 

Technical Specifications therefore require a lesser complement of 

electrical equipment to be available during shutdown than is required 

during operating MODES. More recent work completed on the potential 

risks associated with shutdown, however, have found significant risk 

associated with certain shutdown evolutions. As a result, in addition to 

the requirements established in the Technical Specifications, the industry 

has adopted NUMARC 91-06, "Guidelines for Industry Actions to Assess 

Shutdown Management," as an Industry initiative to manage shutdown 

tasks and associated electrical support to maintain risk at an acceptable 

low level. This may require the availability of additional equipment 

beyond that required by the shutdown Technical Specifications. 

The DC sources satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The DC electrical power subsystems, [each required] [the required] 

subsystem consisting of two batteries, one battery charger per battery, 

and the corresponding control equipment and interconnecting cabling 

within the train, [are] [is] required to be OPERABLE to support [required] 

[one] train[s] of distribution systems required [OPERABLE by LCO 3.8.10, 

"Distribution Systems - Shutdown."] This ensures the availability of 

sufficient DC electrical power sources to operate the unit in a safe 

manner and to mitigate the consequences of postulated events during 

shutdown (e.g., fuel handling accidents [involving handling recently 

irradiated fuel]). 
DC Sources - Shutdown 

B 3.8.5 

CEOG STS B 3.8.5-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY The DC electrical power sources required to be OPERABLE in MODES 5 

and 6, and during movement of [recently] irradiated fuel assemblies 

provide assurance that: 

a. Required features needed to mitigate a fuel handling [involving 

handling recently irradiated fuel (i.e., fuel that has occupied part of a 

critical reactor core within the previous [X] days)] accident are 

available, 

b. Required features necessary to mitigate the effects of events that can 

lead to core damage during shutdown are available, and 

c. Instrumentation and control capability is available for monitoring and 

maintaining the unit in a cold shutdown condition or refueling 

condition. 

The DC electrical power requirements for MODES 1, 2, 3, and 4 are 

covered in LCO 3.8.4. 

ACTIONS LCO 3.0.3 is not applicable while in MODE 5 or 6. However, since 

irradiated fuel assembly movement can occur in MODE 1, 2, 3, or 4, the 

ACTIONS have been modified by a Note stating that LCO 3.0.3 is not 

applicable. If moving irradiated fuel assemblies while in MODE 5 or 6, 

LCO 3.0.3 would not specify any action. If moving irradiated fuel 

assemblies while in MODE 1, 2, 3, or 4, the fuel movement is 

independent of reactor operations. Entering LCO 3.0.3, while in MODE 1, 

2, 3, or 4 would require the unit to be shutdown unnecessarily. 

A.1, A.2, and A.3

-----------------------------------REVIEWER’S NOTE----------------------------------- 

ACTION A is included only when plant-specific implementation of LCO 

3.8.5 includes the potential to require both trains of the DC System to be 

OPERABLE. If plant-specific implementation results in LCO 3.8.5 

requiring only one train of the DC System to be OPERABLE, then 

ACTION A is omitted and ACTION B is renumbered as ACTION A. 

-------------------------------------------------------------------------------------------------- 

Condition A represents one train with one [or two] battery chargers 

inoperable (e.g., the voltage limit of SR 3.8.4.1 is not maintained). The 

ACTIONS provide a tiered response that focuses on returning the battery 

to the fully charged state and restoring a fully qualified charger to 

OPERABLE status in a reasonable time period. Required Action A.1 

requires that the battery terminal voltage be restored to greater than or 
DC Sources - Shutdown 

B 3.8.5 

CEOG STS B 3.8.5-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

equal to the minimum established float voltage within 2 hours. This time 

provides for returning the inoperable charger to OPERABLE status or 

providing an alternate means of restoring battery terminal voltage to 

greater than or equal to the minimum established float voltage. Restoring 

the battery terminal voltage to greater than or equal to the minimum 

established float voltage provides good assurance that, within [12] hours, 

the battery will be restored to its fully charged condition (Required Action 

A.2) from any discharge that might have occurred due to the charger 

inoperability. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

A plant that cannot meet the 12 hour Completion Time due to an inherent 

battery charging characteristic can propose an alternate time equal to 

2 hours plus the time experienced to accomplish the exponential charging 

current portion of the battery charge profile following the service test 

(SR 3.8.4.3). 

-------------------------------------------------------------------------------------------------- 

A discharged battery having terminal voltage of at least the minimum 

established float voltage indicates that the battery is on the exponential 

charging current portion (the second part) of its recharge cycle. The time 

to return a battery to its fully charged state under this condition is simply a 

function of the amount of the previous discharge and the recharge 

characteristic of the battery. Thus there is good assurance of fully 

recharging the battery within [12] hours, avoiding a premature shutdown 

with its own attendant risk. 

If established battery terminal float voltage cannot be restored to greater 

than or equal to the minimum established float voltage within 2 hours, and 

the charger is not operating in the current-limiting modes, a faulty charger 

is indicated. A faulty charger that is incapable of maintaining established 

battery terminal float voltage does not provide assurance that it can revert 

to and operate properly in the current limit modes that is necessary during 

the recovery period following a battery discharge event that the DC 

system is designed for. 

If the charger is operating in the current limit mode after 2 hours that is an 

indication that the battery is partially discharged and its capacity margins 

will be reduced. The time to return the battery to its fully charged 

condition in this case is a function of the battery charger capacity, the 

amount of loads on the associated DC system, the amount of the 

previous discharge, and the recharge characteristic of the battery. The 

charge time can be extensive, and there is not adequate assurance that it 

can be recharged within [12] hours (Required Action A.2). 
DC Sources - Shutdown 

B 3.8.5 

CEOG STS B 3.8.5-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Required Action A.2 requires that the battery float current be verified as 

less than or equal to [2] amps. This indicates that, if the battery had been 

discharged as the result of the inoperable battery charger, it has now 

been fully recharged. If at the expiration of the initial [12] hour period the 

battery float current is not less than or equal to [2] amps this indicates 

there may be additional battery problems and the battery must be 

declared inoperable. 

Required Action A.3 limits the restoration time for the inoperable battery 

charger to 7 days. This action is applicable if an alternate means of 

restoring battery terminal voltage to greater than or equal to the minimum 

established float voltage has been used (e.g., balance of plant non-Class 

1E battery charger). The 7 day Completion Time reflects a reasonable 

time to effect restoration of the qualified battery charger to OPERABLE 

status. 

B.1, B.2.1, B.2.2, B.2.3, and B.2.4

[If two trains are required by LCO 3.8.10, the remaining train with DC 

power available may be capable of supporting sufficient systems to allow 

continuation of CORE ALTERATIONS and [recently] irradiated fuel 

movement]. By allowing the option to declare required features 

inoperable with the associated DC power source(s) inoperable, 

appropriate restrictions will be implemented in accordance with the 

affected required features LCO ACTIONS. In many instances this option 

may involve undesired administrative efforts. Therefore, the allowance 

for sufficiently conservative actions is made (i.e., to suspend CORE 

ALTERATIONS, movement of [recently] irradiated fuel assemblies, and 

operations involving positive reactivity additions) that could result in loss 

of required SDM (MODE 5) or boron concentration (MODE 6). 

Suspending positive reactivity additions that could result in failure to meet 

the minimum SDM or boron concentration limit is required to assure 

continued safety operation. Introduction of coolant inventory must be 

from sources that have a boron concentration greater than that what 

would be required in the RCS for 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. 
DC Sources - Shutdown 

B 3.8.5 

CEOG STS B 3.8.5-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Suspension of these activities shall not preclude completion of actions to 

establish a safe conservative condition. These actions minimize 

probability of the occurrence of postulated events. It is further required to 

immediately initiate action to restore the required DC electrical power 

subsystem[s] and to continue this action until restoration is accomplished 

in order to provide the necessary DC electrical power to the unit safety 

systems. 

The Completion Time of immediately is consistent with the required times 

for actions requiring prompt attention. The restoration of the required DC 

electrical power subsystems should be completed as quickly as possible 

in order to minimize the time during which the unit safety systems may be 

without sufficient power. 

SURVEILLANCE SR 3.8.5.1

REQUIREMENTS 

SR 3.8.5.1 states that Surveillances required by SR 3.8.4.1 through 

SR 3.8.4.3 are applicable in these MODES. See the corresponding 

Bases for LCO 3.8.4 for a discussion of each SR. 

This SR is modified by a Note. The reason for the Note is to preclude 

requiring the OPERABLE DC sources from being discharged below their 

capability to provide the required power supply or otherwise rendered 

inoperable during the performance of SRs. It is the intent that these SRs 

must still be capable of being met, but actual performance is not required. 

REFERENCES 1. FSAR, Chapter [6]. 

 2. FSAR, Chapter [15]. 
Battery Parameters 

B 3.8.6 

CEOG STS B 3.8.6-1 Rev. 3.0, 03/31/04 

B 3.8 ELECTRICAL POWER SYSTEMS 

B 3.8.6 Battery Parameters 

BASES 

BACKGROUND This LCO delineates the limits on battery float current as well as 

electrolyte temperature, level, and float voltage for the DC power 

subsystem batteries. A discussion of these batteries and their 

OPERABILITY requirements is provided in the Bases for LCO 3.8.4, "DC 

Sources - Operating," and LCO 3.8.5, "DC Sources - Shutdown." In 

addition to the limitations of this Specification, the [licensee controlled 

program] also implements a program specified in Specification 5.5.17 for 

monitoring various battery parameters that is based on the 

recommendations of IEEE Standard 450-1995, "IEEE Recommended 

Practice For Maintenance, Testing, And Replacement Of Vented LeadAcid Batteries For Stationary Applications" (Ref. 1). 

The battery cells are of flooded lead acid construction with a nominal 

specific gravity of [1.215]. This specific gravity corresponds to an open 

circuit battery voltage of approximately 120 V for [58] cell battery (i.e., cell 

voltage of [2.065] volts per cell (Vpc)). The open circuit voltage is the 

voltage maintained when there is no charging or discharging. Once fully 

charged with its open circuit voltage ≥ [2.065] Vpc, the battery cell will 

maintain its capacity for [30] days without further charging per 

manufacturer's instructions. Optimal long term performance however, is 

obtained by maintaining a float voltage [2.20 to 2.25] Vpc. This provides 

adequate over-potential which limits the formation of lead sulfate and self 

discharge. The nominal float voltage of [2.22] Vpc corresponds to a total 

float voltage output of [128.8] V for a [58] cell battery as discussed in the 

FSAR, Chapter [8] (Ref. 2). 

APPLICABLE The initial conditions of Design Basis Accident (DBA) and transient 

SAFETY analyses in the FSAR, Chapter [6] (Ref. 3) and Chapter [15] (Ref. 4), 

ANALYSES assume Engineered Safety Feature systems are OPERABLE. The DC 

electrical power system provides normal and emergency DC electrical 

power for the DGs, emergency auxiliaries, and control and switching 

during all MODES of operation. 

The OPERABILITY of the DC subsystems is consistent with the initial 

assumptions of the accident analyses and is based upon meeting the 

design basis of the unit. This includes maintaining at least one train of 

DC sources OPERABLE during accident conditions, in the event of: 

a. An assumed loss of all offsite AC power or all onsite AC power and 
Battery Parameters 

B 3.8.6 

CEOG STS B 3.8.6-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

b. A worst-case single failure. 

Battery parameters satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO Battery parameters must remain within acceptable limits to ensure 

availability of the required DC power to shut down the reactor and 

maintain it in a safe condition after an anticipated operational occurrence 

or a postulated DBA. Battery parameter limits are conservatively 

established, allowing continued DC electrical system function even with 

limits not met. Additional preventative maintenance, testing, and 

monitoring performed in accordance with the [licensee controlled 

program] is conducted as specified in Specification 5.5.17. 

APPLICABILITY The battery parameters are required solely for the support of the 

associated DC electrical power subsystems. Therefore, battery 

parameter limits are only required when the DC power source is required 

to be OPERABLE. Refer to the Applicability discussion in Bases for 

LCO 3.8.4 and LCO 3.8.5. 

ACTIONS A.1, A.2, and A.3

With one or more cells in one or more batteries in one train < [2.07] V, the 

battery cell is degraded. Within 2 hours verification of the required battery 

charger OPERABILITY is made by monitoring the battery terminal voltage 

(SR 3.8.4.1) and of the overall battery state of charge by monitoring the 

battery float charge current (SR 3.8.6.1). This assures that there is still 

sufficient battery capacity to perform the intended function. Therefore, 

the affected battery is not required to be considered inoperable solely as 

a result of one or more cells in one or more batteries < [2.07] V, and 

continued operation is permitted for a limited period up to 24 hours. 

Since the Required Actions only specify "perform," a failure of SR 3.8.4.1 

or SR 3.8.6.1 acceptance criteria does not result in this Required Action 

not met. However, if one of the SRs is failed the appropriate Condition(s), 

depending on the cause of the failures, is entered. If SR 3.8.6.1 is failed 

then there is not assurance that there is still sufficient battery capacity to 

perform the intended function and the battery must be declared 

inoperable immediately. 
Battery Parameters 

B 3.8.6 

CEOG STS B 3.8.6-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1 and B.2

One or more batteries in one train with float current > [2] amps indicates 

that a partial discharge of the battery capacity has occurred. This may be 

due to a temporary loss of a battery charger or possibly due to one or 

more battery cells in a low voltage condition reflecting some loss of 

capacity. Within 2 hours verification of the required battery charger 

OPERABILITY is made by monitoring the battery terminal voltage. If the 

terminal voltage is found to be less than the minimum established float 

voltage there are two possibilities, the battery charger is inoperable or is 

operating in the current limit mode. Condition A addresses charger 

inoperability. If the charger is operating in the current limit mode after 

2 hours that is an indication that the battery has been substantially 

discharged and likely cannot perform its required design functions. The 

time to return the battery to its fully charged condition in this case is a 

function of the battery charger capacity, the amount of loads on the 

associated DC system, the amount of the previous discharge, and the 

recharge characteristic of the battery. The charge time can be extensive, 

and there is not adequate assurance that it can be recharged within 

[12] hours (Required Action B.2). The battery must therefore be declared 

inoperable. 

If the float voltage is found to be satisfactory but there are one or more 

battery cells with float voltage less than [2.07] V, the associated "OR" 

statement in Condition F is applicable and the battery must be declared 

inoperable immediately. If float voltage is satisfactory and there are no 

cells less than [2.07] V there is good assurance that, within [12] hours, the 

battery will be restored to its fully charged condition (Required Action B.2) 

from any discharge that might have occurred due to a temporary loss of 

the battery charger. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

A plant that cannot meet the 12 hour Completion Time due to an inherent 

battery charging characteristic can propose an alternate time equal to 

2 hours plus the time experienced to accomplish the exponential charging 

current portion of the battery charge profile following the service test 

(SR 3.8.4.3). 

-------------------------------------------------------------------------------------------------- 
Battery Parameters 

B 3.8.6 

CEOG STS B 3.8.6-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

A discharged battery with float voltage (the charger setpoint) across its 

terminals indicates that the battery is on the exponential charging current 

portion (the second part) of its recharge cycle. The time to return a 

battery to its fully charged state under this condition is simply a function of 

the amount of the previous discharge and the recharge characteristic of 

the battery. Thus there is good assurance of fully recharging the battery 

within [12] hours, avoiding a premature shutdown with its own attendant 

risk. 

If the condition is due to one or more cells in a low voltage condition but 

still greater than [2.07] V and float voltage is found to be satisfactory, this 

is not indication of a substantially discharged battery and [12] hours is a 

reasonable time prior to declaring the battery inoperable. 

Since Required Action B.1 only specifies "perform," a failure of SR 3.8.4.1 

acceptance criteria does not result in the Required Action not met. 

However, if SR 3.8.4.1 is failed, the appropriate Condition(s), depending 

on the cause of the failure, is entered. 

C.1, C.2, and C.3

With one or more batteries in one train with one or more cells electrolyte 

level above the top of the plates, but below the minimum established 

design limits, the battery still retains sufficient capacity to perform the 

intended function. Therefore, the affected battery is not required to be 

considered inoperable solely as a result of electrolyte level not met. 

Within 31 days the minimum established design limits for electrolyte level 

must be re-established. 

With electrolyte level below the top of the plates there is a potential for 

dryout and plate degradation. Required Actions C.1 and C.2 address this 

potential (as well as provisions in Specification 5.5.17, Battery Monitoring 

and Maintenance Program). They are modified by a Note that indicates 

they are only applicable if electrolyte level is below the top of the plates. 

Within 8 hours level is required to be restored to above the top of the 

plates. The Required Action C.2 requirement to verify that there is no 

leakage by visual inspection and the Specification 5.5.17.b item to initiate 

action to equalize and test in accordance with manufacturer's 

recommendation are taken from Annex D of IEEE Standard 450-1995. 

They are performed following the restoration of the electrolyte level to 

above the top of the plates. Based on the results of the manufacturer's 

recommended testing the batter[y][ies] may have to be declared 

inoperable and the affected cell[s] replaced. 
Battery Parameters 

B 3.8.6 

CEOG STS B 3.8.6-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

D.1

With one or more batteries in one train with pilot cell temperature less 

than the minimum established design limits, 12 hours is allowed to restore 

the temperature to within limits. A low electrolyte temperature limits the 

current and power available. Since the battery is sized with margin, while 

battery capacity is degraded, sufficient capacity exists to perform the 

intended function and the affected battery is not required to be considered 

inoperable solely as a result of the pilot cell temperature not met. 

E.1

With one or more batteries in redundant trains with battery parameters 

not within limits there is not sufficient assurance that battery capacity has 

not been affected to the degree that the batteries can still perform their 

required function, given that redundant batteries are involved. With 

redundant batteries involved this potential could result in a total loss of 

function on multiple systems that rely upon the batteries. The longer 

Completion Times specified for battery parameters on non-redundant 

batteries not within limits are therefore not appropriate, and the 

parameters must be restored to within limits on at least one train within 

2 hours. 

F.1

With one or more batteries with any battery parameter outside the 

allowances of the Required Actions for Condition A, B, C, D, or E, 

sufficient capacity to supply the maximum expected load requirement is 

not assured and the corresponding battery must be declared inoperable. 

Additionally, discovering one or more batteries in one train with one or 

more battery cells float voltage less than [2.07] V and float current greater 

than [2] amps indicates that the battery capacity may not be sufficient to 

perform the intended functions. The battery must therefore be declared 

inoperable immediately. 
Battery Parameters 

B 3.8.6 

CEOG STS B 3.8.6-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.8.6.1

REQUIREMENTS 

Verifying battery float current while on float charge is used to determine 

the state of charge of the battery. Float charge is the condition in which 

the charger is supplying the continuous charge required to overcome the 

internal losses of a battery and maintain the battery in a charged state. 

The float current requirements are based on the float current indicative of 

a charged battery. Use of float current to determine the state of charge of 

the battery is consistent with IEEE-450 (Ref. 1). The 7 day Frequency is 

consistent with IEEE-450 (Ref. 1). 

This SR is modified by a Note that states the float current requirement is 

not required to be met when battery terminal voltage is less than the 

minimum established float voltage of SR 3.8.4.1. When this float voltage 

is not maintained the Required Actions of LCO 3.8.4 ACTION A are being 

taken, which provide the necessary and appropriate verifications of the 

battery condition. Furthermore, the float current limit of [2] amps is 

established based on the nominal float voltage value and is not directly 

applicable when this voltage is not maintained. 

SR 3.8.6.2 and SR 3.8.6.5

Optimal long term battery performance is obtained by maintaining a float 

voltage greater than or equal to the minimum established design limits 

provided by the battery manufacturer, which corresponds to [130.5] V at 

the battery terminals, or [2.25] Vpc. This provides adequate overpotential, which limits the formation of lead sulfate and self discharge, 

which could eventually render the battery inoperable. Float voltages in 

this range or less, but greater than [2.07] Vpc, are addressed in 

Specification 5.5.17. SRs 3.8.6.2 and 3.8.6.5 require verification that the 

cell float voltages are equal to or greater than the short term absolute 

minimum voltage of [2.07] V. 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. 1). 

SR 3.8.6.3

The limit specified for electrolyte level ensures that the plates suffer no 

physical damage and maintains adequate electron transfer capability. 

The Frequency is consistent with IEEE-450 (Ref. 1). 
Battery Parameters 

B 3.8.6 

CEOG STS B 3.8.6-7 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

SR 3.8.6.4

This Surveillance verifies that the pilot cell temperature is greater than or 

equal to the minimum established design limit (i.e., [40]°F). Pilot cell 

electrolyte temperature is maintained above this temperature to assure 

the battery can provide the required current and voltage to meet the 

design requirements. Temperatures lower than assumed in battery sizing 

calculations act to inhibit or reduce battery capacity. The Frequency is 

consistent with IEEE-450 (Ref. 1). 

SR 3.8.6.6

A battery performance discharge test is a test of constant current capacity 

of a battery, normally done in the as found condition, after having been in 

service, to detect any change in the capacity determined by the 

acceptance test. The test is intended to determine overall battery 

degradation due to age and usage. 

Either the battery performance discharge test or the modified 

performance discharge test is acceptable for satisfying SR 3.8.6.6; 

however, only the modified performance discharge test may be used to 

satisfy the battery service test requirements of SR 3.8.4.3. 

A modified discharge test is a test of the battery capacity and its ability to 

provide a high rate, short duration load (usually the highest rate of the 

duty cycle). This will often confirm the battery's ability to meet the critical 

period of the load duty cycle, in addition to determining its percentage of 

rated capacity. Initial conditions for the modified performance discharge 

test should be identical to those specified for a service test. 

It may consist of just two rates; for instance the one minute rate for the 

battery or the largest current load of the duty cycle, followed by the test 

rate employed for the performance test, both of which envelope the duty 

cycle of the service test. Since the ampere-hours removed by a one 

minute discharge represents a very small portion of the battery capacity, 

the test rate can be changed to that for the performance test without 

compromising the results of the performance discharge test. The battery 

terminal voltage for the modified performance discharge test must remain 

above the minimum battery terminal voltage specified in the battery 

service test for the duration of time equal to that of the service test. 
Battery Parameters 

B 3.8.6 

CEOG STS B 3.8.6-8 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

The acceptance criteria for this Surveillance are consistent with IEEE-450 

(Ref. 1) and IEEE-485 (Ref. 5). These references recommend that the 

battery be replaced if its capacity is below 80% of the manufacturer's 

rating. A capacity of 80% shows that the battery rate of deterioration is 

increasing, even if there is ample capacity to meet the load requirements. 

Furthermore, the battery is sized to meet the assumed duty cycle loads 

when the battery design capacity reaches this [80]% limit. 

The Surveillance Frequency for this test is normally 60 months. If the 

battery shows degradation, or if the battery has reached 85% of its 

expected life and capacity is < 100% of the manufacturer's rating, the 

Surveillance Frequency is reduced to 12 months. However, if the battery 

shows no degradation but has reached 85% of its expected life, the 

Surveillance Frequency is only reduced to 24 months for batteries that 

retain capacity ≥ 100% of the manufacturer's ratings. Degradation is 

indicated, according to IEEE-450 (Ref. 1), when the battery capacity 

drops by more than 10% relative to its capacity on the previous 

performance test or when it is ≥ [10%] below the manufacturer's rating. 

These Frequencies are consistent with the recommendations in IEEE-450 

(Ref. 1). 

This SR is modified by a Note. The reason for the Note is that performing 

the Surveillance would perturb the electrical distribution system and 

challenge safety systems. This restriction from normally performing the 

Surveillance in MODE 1 or 2 is further amplified to allow portions of the 

Surveillance to be performed for the purpose of reestablishing 

OPERABILITY (e.g., post work testing following corrective maintenance, 

corrective modification, deficient or incomplete surveillance testing, and 

other unanticipated OPERABILITY concerns) provided an assessment 

determines plant safety is maintained or enhanced. This assessment 

shall, as a minimum, consider the potential outcomes and transients 

associated with a failed partial Surveillance, a successful partial 

Surveillance, and a perturbation of the offsite or onsite system when they 

are tied together or operated independently for the partial Surveillance; as 

well as the operator procedures available to cope with these outcomes. 

These shall be measured against the avoided risk of a plant shutdown 

and startup to determine that plant safety is maintained or enhanced 

when portions of the Surveillance are performed in MODE 1 or 2. Risk 

insights or deterministic methods may be used for the assessment. 

Credit may be taken for unplanned events that satisfy this SR. 
Battery Parameters 

B 3.8.6 

CEOG STS B 3.8.6-9 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. IEEE-450-[1995]. 

 2. FSAR, Chapter [8]. 

 3. FSAR, Chapter [6]. 

 4. FSAR, Chapter [15]. 

 5. IEEE-485-[1983], June 1983. 
Inverters - Operating 

B 3.8.7 

CEOG STS B 3.8.7-1 Rev. 3.0, 03/31/04 

B 3.8 ELECTRICAL POWER SYSTEMS 

B 3.8.7 Inverters - Operating 

BASES 

BACKGROUND The inverters are the preferred source of power for the AC vital buses 

because of the stability and reliability they achieve. The function of the 

inverter is to provide AC electrical power to the vital buses. The inverters 

can be powered from an internal AC source/rectifier or from the station 

battery. The station battery provides an uninterruptible power source for 

the instrumentation and controls for the Reactor Protective System (RPS) 

and the Engineered Safety Feature Actuation System (ESFAS). Specific 

details on inverters and their operating characteristics are found in the 

FSAR, Chapter [8] (Ref. 1). 

APPLICABLE The initial conditions of Design Basis Accident (DBA) and transient 

SAFETY analyses in the FSAR, Chapter [6] (Ref. 2) and Chapter [15] (Ref. 3), 

ANALYSES assume Engineered Safety Feature systems are OPERABLE. The 

inverters are designed to provide the required capacity, capability, 

redundancy, and reliability to ensure the availability of necessary power to 

the RPS and ESFAS instrumentation and controls so that the fuel, 

Reactor Coolant System, and containment design limits are not 

exceeded. These limits are discussed in more detail in the Bases for 

Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coolant 

System (RCS); and Section 3.6, Containment Systems. 

The OPERABILITY of the inverters is consistent with the initial 

assumptions of the accident analyses and is based on meeting the design 

basis of the unit. This includes maintaining required AC vital buses 

OPERABLE during accident conditions in the event of: 

a. An assumed loss of all offsite AC electrical power or all onsite AC 

electrical power and 

b. A worst case single failure. 

Inverters are a part of the distribution system and, as such, satisfy 

Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The inverters ensure the availability of AC electrical power for the 

systems instrumentation required to shut down the reactor and maintain it 

in a safe condition after an anticipated operational occurrence (AOO) or a 

postulated DBA. 
Inverters - Operating 

B 3.8.7 

CEOG STS B 3.8.7-2 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

Maintaining the required inverters OPERABLE ensures that the 

redundancy incorporated into the design of the RPS and ESFAS 

instrumentation and controls is maintained. The four inverters [(two per 

train)] ensure an uninterruptible supply of AC electrical power to the AC 

vital buses even if the 4.16 kV safety buses are de-energized. 

OPERABLE inverters require the associated vital bus to be powered by 

the inverter with output voltage and frequency within tolerances, and 

power input to the inverter from a [125 VDC] station battery. Alternatively, 

power supply may be from an internal AC source via rectifier as long as 

the station battery is available as the uninterruptible power supply. 

This LCO is modified by a Note that allows [one/two] inverters to be 

disconnected from a [common] battery for ≤ 24 hours, if the vital bus(es) 

is powered from a [Class 1E constant voltage transformer or inverter 

using internal AC source] during the period and all other inverters are 

operable. This allows an equalizing charge to be placed on one battery. 

If the inverter(s) were not disconnected, the resulting voltage condition 

might damage the inverter(s). These provisions minimize the loss of 

equipment that would occur in the event of a loss of offsite power. The 

24 hour time period for the allowance minimizes the time during which a 

loss of offsite power could result in the loss of equipment energized from 

the affected AC vital bus while taking into consideration the time required 

to perform an equalizing charge on the battery bank. 

The intent of this Note is to limit the number of inverters that may be 

disconnected. Only those inverters associated with the single battery 

undergoing an equalizing charge may be disconnected. All other 

inverters must be aligned to their associated batteries, regardless of the 

number of inverters or unit design. 

APPLICABILITY The inverters are required to be OPERABLE in MODES 1, 2, 3, and 4 to 

ensure that: 

a. Acceptable fuel design limits and reactor coolant pressure boundary 

limits are not exceeded as a result of AOOs or abnormal transients 

and 

b. Adequate core cooling is provided, and containment OPERABILITY 

and other vital functions are maintained in the event of a postulated 

DBA. 

Inverter requirements for MODES 5 and 6 are covered in the Bases for 

LCO 3.8.8, "Inverters - Shutdown." 
Inverters - Operating 

B 3.8.7 

CEOG STS B 3.8.7-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1

With a required inverter inoperable, its associated AC vital bus becomes 

inoperable until it is [manually] re-energized from its [Class 1E constant 

voltage source transformer or inverter using internal AC source]. 

Required Action A.1 is modified by a Note, which states to enter the 

applicable conditions and Required Actions of LCO 3.8.9, "Distribution 

Systems - Operating," when Condition A is entered with one AC vital bus 

de-energized. This ensures the vital bus is re-energized within 2 hours. 

Required Action A.1 allows 24 hours to fix the inoperable inverter and 

return it to service. The 24 hour limit is based upon engineering 

judgment, taking into consideration the time required to repair an inverter 

and the additional risk to which the unit is exposed because of the 

inverter inoperability. This has to be balanced against the risk of an 

immediate shutdown, along with the potential challenges to safety 

systems such a shutdown might entail. When the AC vital bus is powered 

from its constant voltage source, it is relying upon interruptible AC 

electrical power sources (offsite and onsite). The uninterruptible inverter 

source to the AC vital buses is the preferred source for powering 

instrumentation trip setpoint devices. 

B.1 and B.2

If the inoperable devices or components cannot be restored to 

OPERABLE status within the required Completion Time, the unit must be 

brought to a MODE in which the LCO does not apply. To achieve this 

status, the unit must be brought to at least MODE 3 within 6 hours and to 

MODE 5 within 36 hours. The allowed Completion Times are reasonable, 

based on operating experience, to reach the required unit conditions from 

full power conditions in an orderly manner and without challenging unit 

systems. 

SURVEILLANCE SR 3.8.7.1

REQUIREMENTS 

This Surveillance verifies that the inverters are functioning properly with 

all required circuit breakers closed and AC vital buses energized from the 

inverter. The verification of proper voltage and frequency output ensures 

that the required power is readily available for the instrumentation of the 

RPS and ESFAS connected to the AC vital buses. 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. 
Inverters - Operating 

B 3.8.7 

CEOG STS B 3.8.7-4 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. FSAR, Chapter [8]. 

 2. FSAR, Chapter [6]. 

 3. FSAR, Chapter [14]. 
Inverters - Shutdown 

B 3.8.8 

CEOG STS B 3.8.8-1 Rev. 3.0, 03/31/04 

B 3.8 ELECTRICAL POWER SYSTEMS 

B 3.8.8 Inverters - Shutdown 

BASES 

BACKGROUND A description of the inverters is provided in the Bases for LCO 3.8.7, 

"Inverters - Operating." 

APPLICABLE The initial conditions of Design Basis Accident (DBA) and transient 

SAFETY analyses in the FSAR, Chapter [6] (Ref. 1) and Chapter [15] (Ref. 2), 

ANALYSES assume Engineered Safety Feature systems are OPERABLE. The DC to 

AC inverters are designed to provide the required capacity, capability, 

redundancy, and reliability to ensure the availability of necessary power to 

the Reactor Protective System and Engineered Safety Features Actuation 

System instrumentation and controls so that the fuel, Reactor Coolant 

System, and containment design limits are not exceeded. 

The OPERABILITY of the inverters is consistent with the initial 

assumptions of the accident analyses and the requirements for the 

supported systems' OPERABILITY. 

The OPERABILITY of the minimum inverters to each AC vital bus during 

MODES 5 and 6 ensures that: 

a. The unit can be maintained in the shutdown or refueling condition for 

extended periods, 

b. Sufficient instrumentation and control capability is available for 

monitoring and maintaining the unit status, and 

c. Adequate power is available to mitigate events postulated during 

shutdown, such as a fuel handling accident [involving handling 

recently irradiated fuel. Due to radioactive decay, the inverters are 

only required to mitigate fuel handling accidents involving handling 

recently irradiated fuel (i.e., fuel that has occupied part of a critical 

reactor core within the previous [X] days)]. 

In general, when the unit is shut down, the Technical Specification 

requirements ensure that the unit has the capability to mitigate the 

consequences of postulated accidents. However, assuming a single 

failure and concurrent loss of all offsite or all onsite power is not required. 

The rationale for this is based on the fact that many DBAs that are 

analyzed in MODES [1, 2, 3, and 4] have no specific analyses in 

MODES [5 and 6] because the energy contained within the reactor 
Inverters - Shutdown 

B 3.8.8 

CEOG STS B 3.8.8-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

pressure boundary, reactor coolant temperature and pressure, and the 

corresponding stresses result in the probabilities of occurrence being 

significantly reduced or eliminated, and in minimal consequences. These 

deviations from DBA analysis assumptions and design requirements 

during shutdown conditions are allowed by the LCO for required systems. 

The shutdown Technical Specification requirements are designed to 

ensure that the unit has the capability to mitigate the consequences of 

certain postulated accidents. Worst case DBAs which are analyzed for 

operating MODES are generally viewed not to be a significant concern 

during shutdown MODES due to the lower energies involved. The 

Technical Specifications therefore require a lesser complement of 

electrical equipment to be available during shutdown than is required 

during operating MODES. More recent work completed on the potential 

risks associated with shutdown, however, have found significant risk 

associated with certain shutdown evolutions. As a result, in addition to 

the requirements established in the Technical Specifications, the industry 

has adopted NUMARC 91-06, "Guidelines for Industry Actions to Assess 

Shutdown Management," as an Industry initiative to manage shutdown 

tasks and associated electrical support to maintain risk at an acceptable 

low level. This may require the availability of additional equipment 

beyond that required by the shutdown Technical Specifications. 

The inverters were previously identified as part of the distribution system 

and, as such, satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The inverter[s] ensure the availability of electrical power for the 

instrumentation for systems required to shut down the reactor and 

maintain it in a safe condition after an anticipated operational occurrence 

or a postulated DBA. The battery powered inverter[s] provide[s] 

uninterruptible supply of AC electrical power to the AC vital bus[es] even 

if the 4.16 kV safety buses are de-energized. OPERABILITY of the 

inverter[s] requires that the vital bus be powered by the inverter. This 

ensures the availability of sufficient inverter power sources to operate the 

unit in a safe manner and to mitigate the consequences of postulated 

events during shutdown (e.g., fuel handling accidents [involving handling 

recently irradiated fuel]). 
Inverters - Shutdown 

B 3.8.8 

CEOG STS B 3.8.8-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY The inverter[s] required to be OPERABLE in MODES 5 and 6 during 

movement of [recently] irradiated fuel assemblies provide assurance that: 

a. Systems to provide adequate coolant inventory makeup are available 

for the irradiated fuel in the core, 

b. Systems needed to mitigate a fuel handling accident [involving 

handling recently irradiated fuel (i.e., fuel that has occupied part of a 

critical reactor core within the previous [X] days)] are available, 

c. Systems necessary to mitigate the effects of events that can lead to 

core damage during shutdown are available, and 

d. Instrumentation and control capability is available for monitoring and 

maintaining the unit in a cold shutdown condition or refueling 

condition. 

Inverter requirements for MODES 1, 2, 3, and 4 are covered in 

LCO 3.8.7. 

ACTIONS LCO 3.0.3 is not applicable while in MODE 5 or 6. However, since 

irradiated fuel assembly movement can occur in MODE 1, 2, 3, or 4, the 

ACTIONS have been modified by a Note stating that LCO 3.0.3 is not 

applicable. If moving irradiated fuel assemblies while in MODE 5 or 6, 

LCO .0.3 would not specify any action. If moving irradiated fuel 

assemblies while in MODE 1, 2, 3, or 4, the fuel movement is 

independent of reactor operations. Entering LCO 3.0.3, while in MODE 1, 

2, 3, or 4 would require the unit to be shutdown unnecessarily. 

A.1, A.2.1, A.2.2, A.2.3, and A.2.4

[If two trains are required by LCO 3.8.10, "Distribution Systems - 

Shutdown," the remaining OPERABLE inverters may be capable of 

supporting sufficient required features to allow continuation of CORE 

ALTERATIONS, [recently] irradiated fuel movement, operations with a 

potential for draining the reactor vessel, and operations with a potential 

for positive reactivity additions that could result in loss of required SDM 

(MODE 5) or boron concentration (MODE 6).] Suspending positive 

reactivity additions that could result in failure to meet the minimum SDM 

or boron concentration limit is required to assure continued safe 
Inverters - Shutdown 

B 3.8.8 

CEOG STS B 3.8.8-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

operation. Introduction of coolant inventory must be from sources that 

have a boron concentration greater than that what would be required in 

the RCS for 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. By the allowance of the option to declare 

required features inoperable with the associated inverter(s) inoperable, 

appropriate restrictions will be implemented in accordance with the 

affected required features LCOs' Required Actions. In many instances, 

this option may involve undesired administrative efforts. Therefore, the 

allowance for sufficiently conservative actions is made (i.e., to suspend 

CORE ALTERATIONS, movement of [recently] irradiated fuel assemblies, 

and operations involving positive reactivity additions). 

Suspension of these activities shall not preclude completion of actions to 

establish a safe conservative condition. These actions minimize the 

probability of the occurrence of postulated events. It is further required to 

immediately initiate action to restore the required inverter[s] and to 

continue this action until restoration is accomplished in order to provide 

the necessary inverter power to the unit safety systems. 

The Completion Time of immediately is consistent with the required times 

for actions requiring prompt attention. The restoration of the required 

inverters should be completed as quickly as possible in order to minimize 

the time the unit safety systems may be without power or powered from a 

constant voltage source transformer. 

SURVEILLANCE SR 3.8.8.1

REQUIREMENTS 

This Surveillance verifies that the inverters are functioning properly with 

all required circuit breakers closed and AC vital buses energized from the 

inverter. The verification of proper voltage and frequency output ensures 

that the required power is readily available for the instrumentation 

connected to the AC vital buses. 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. 

REFERENCES 1. FSAR, Chapter [6]. 

 2. FSAR, Chapter [15]. 
Distribution Systems - Operating 

B 3.8.9 

CEOG STS B 3.8.9-1 Rev. 3.0, 03/31/04 

B 3.8 ELECTRICAL POWER SYSTEMS 

B 3.8.9 Distribution Systems - Operating 

BASES 

BACKGROUND The onsite Class 1E AC, DC, and AC vital bus electrical power 

distribution systems are divided by train into [two] redundant and 

independent AC, DC, and AC vital bus electrical power distribution 

subsystems. 

The AC electrical power subsystem for each train consists of a 4.16 kV 

Engineered Safety Feature (ESF) bus, having at least [one separate and 

independent offsite source of power] as well as a dedicated onsite diesel 

generator (DG) source. Each [4.16 kV ESF bus] is normally connected to 

a preferred offsite source. After a loss of the preferred offsite power 

source to a 4.16 kV ESF bus, a transfer to the alternate offsite source is 

accomplished by utilizing a time delayed bus undervoltage relay. If all 

offsite sources are unavailable, the onsite emergency DG supplies power 

to the 4.16 kV ESF bus. Control power for the 4.16 kV breakers is 

supplied from the Class 1E batteries. Additional description of this 

system may be found in the Bases for LCO 3.8.1, "AC Sources - 

Operating," and the Bases for LCO 3.8.4, "DC Sources - Operating." 

The secondary AC electrical power distribution subsystem for each train 

includes the safety related load centers, motor control centers, and 

distribution panels shown in Table B 3.8.9-1. 

The 120 VAC vital buses are arranged in two load groups per train and 

are normally powered from the inverters. The alternate power supply for 

the vital buses are Class 1E constant voltage source transformers 

powered from the same train as the associated inverter, and its use is 

governed by LCO 3.8.7, "Inverters - Operating." Each constant voltage 

source transformer is powered from a Class 1E AC bus. 

The DC electrical power distribution subsystem consists of [125] V 

bus(es) and distribution panel(s). 

The list of all required DC and vital AC distribution buses [and panels] is 

presented in Table B 3.8.9-1. 
Distribution Systems - Operating 

B 3.8.9 

CEOG STS B 3.8.9-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE The initial conditions of Design Basis Accident (DBA) and transient 

SAFETY analyses in the FSAR, Chapter [6] (Ref. 1) and Chapter [15] (Ref. 2), 

ANALYSES assume ESF systems are OPERABLE. The AC, DC, and AC vital bus 

electrical power distribution systems are designed to provide sufficient 

capacity, capability, redundancy, and reliability to ensure the availability of 

necessary power to ESF systems so that the fuel, Reactor Coolant 

System, and containment design limits are not exceeded. These limits 

are discussed in more detail in the Bases for Section 3.2, Power 

Distribution Limits; Section 3.4, Reactor Coolant System (RCS); and 

Section 3.6, Containment Systems. 

The OPERABILITY of the AC, DC, and AC vital bus electrical power 

distribution systems is consistent with the initial assumptions of the 

accident analyses and is based upon meeting the design basis of the unit. 

This includes maintaining power distribution systems OPERABLE during 

accident conditions in the event of: 

a. An assumed loss of all offsite power or all onsite AC electrical power 

and 

b. A worst case single failure. 

The distribution systems satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO The required power distribution subsystems listed in Table B 3.8.9-1 

ensure the availability of AC, DC, and AC vital bus electrical power for the 

systems required to shut down the reactor and maintain it in a safe 

condition after an anticipated operational occurrence (AOO) or a 

postulated DBA. The AC, DC, and AC vital bus electrical power 

distribution subsystems are required to be OPERABLE. 

Maintaining the Train A and Train B AC, DC, and AC vital bus electrical 

power distribution subsystems OPERABLE ensures that the redundancy 

incorporated into the design of ESF is not defeated. Therefore, a single 

failure within any system or within the electrical power distribution 

subsystems will not prevent safe shutdown of the reactor. 

OPERABLE AC electrical power distribution subsystems require the 

associated buses, load centers, motor control centers, and distribution 

panels to be energized to their proper voltages. OPERABLE DC 

electrical power distribution subsystems require the associated buses and 

distribution panels to be energized to their proper voltage from either the 

associated battery or charger. OPERABLE vital bus electrical power 

distribution subsystems require the associated buses to be energized to 

their proper voltage from the associated [inverter via inverted DC voltage, 

inverter using internal AC source, or Class 1E constant voltage 

transformer]. 
Distribution Systems - Operating 

B 3.8.9 

CEOG STS B 3.8.9-3 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

In addition, tie breakers between redundant safety related AC, DC, and 

AC vital bus power distribution subsystems, if they exist, must be open. 

This prevents any electrical malfunction in any power distribution 

subsystem from propagating to the redundant subsystem, which could 

cause the failure of a redundant subsystem and a loss of essential safety 

function(s). If any tie breakers are closed, the affected redundant 

electrical power distribution subsystems are considered inoperable. This 

applies to the onsite, safety related redundant electrical power distribution 

subsystems. It does not, however, preclude redundant Class 1E 4.16 kV 

buses from being powered from the same offsite circuit. 

APPLICABILITY The electrical power distribution subsystems are required to be 

OPERABLE in MODES 1, 2, 3, and 4 to ensure that: 

a. Acceptable fuel design limits and reactor coolant pressure boundary 

limits are not exceeded as a result of AOOs or abnormal transients 

and 

b. Adequate core cooling is provided, and containment OPERABILITY 

and other vital functions are maintained in the event of a postulated 

DBA. 

Electrical power distribution subsystem requirements for MODES 5 and 6 

are covered in the Bases for LCO 3.8.10, "Distribution Systems - 

Shutdown." 

ACTIONS A.1

With one or more Train A and B required AC buses, load centers, motor 

control centers, or distribution panels (except AC vital buses), in one train 

inoperable and a loss of function has not occurred, the remaining AC 

electrical power distribution subsystems are capable of supporting the 

minimum safety functions necessary to shut down the reactor and 

maintain it in a safe shutdown condition, assuming no single failure. The 

overall reliability is reduced, however, because a single failure in the 

remaining power distribution subsystems could result in the minimum 

required ESF functions not being supported. Therefore, the required AC 

buses, load centers, motor control centers, and distribution panels must 

be restored to OPERABLE status within 8 hours. 
Distribution Systems - Operating 

B 3.8.9 

CEOG STS B 3.8.9-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

Condition A worst scenario is one train without AC power (i.e., no offsite 

power to the train and the associated DG inoperable). In this condition, 

the unit is more vulnerable to a complete loss of AC power. It is, 

therefore, imperative that the unit operator's attention be focused on 

minimizing the potential for loss of power to the remaining train by 

stabilizing the unit, and on restoring power to the affected train. The 

8 hour time limit before requiring a unit shutdown in this condition is 

acceptable because of: 

a. The potential for decreased safety if the unit operator's attention is 

diverted from the evaluations and actions necessary to restore power 

to the affected train, to the actions associated with taking the unit to 

shutdown within this time limit and 

b. The potential for an event in conjunction with a single failure of a 

redundant component in the train with AC power. 

The second Completion Time for Required Action A.1 establishes a limit 

on the maximum time allowed for any combination of required distribution 

subsystems to be inoperable during any single contiguous occurrence of 

failing to meet the LCO. If Condition A is entered while, for instance, a 

DC bus is inoperable and subsequently restored OPERABLE, the LCO 

may already have been not met for up to 2 hours. This could lead to a 

total of 10 hours, since initial failure of the LCO, to restore the AC 

distribution system. At this time, a DC circuit could again become 

inoperable, and AC distribution restored OPERABLE. This could 

continue indefinitely. 

The Completion Time allows for an exception to the normal "time zero" for 

beginning the allowed outage time "clock." This will result in establishing 

the "time zero" at the time the LCO was initially not met, instead of the 

time Condition A was entered. The 16 hour Completion Time is an 

acceptable limitation on this potential to fail to meet the LCO indefinitely. 

Required Action A.1 is modified by a Note that requires the applicable 

Conditions and Required Actions of LCO 3.8.4, "DC Sources - Operating," 

to be entered for DC trains made inoperable by inoperable power 

distribution subsystems. This is an exception to LCO 3.0.6 and ensures 

the proper actions are taken for these components. Inoperability of a 

distribution system can result in loss of charging power to batteries and 

eventual loss of DC power. This Note ensures that the appropriate 

attention is given to restoring charging power to batteries, if necessary, 

after loss of distribution systems. 
Distribution Systems - Operating 

B 3.8.9 

CEOG STS B 3.8.9-5 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

B.1

With one or more AC vital buses inoperable, and a loss of function has 

not yet occurred, the remaining OPERABLE AC vital buses are capable 

of supporting the minimum safety functions necessary to shut down the 

unit and maintain it in the safe shutdown condition. Overall reliability is 

reduced, however, since an additional single failure could result in the 

minimum required ESF functions not being supported. Therefore, the 

[required] AC vital bus must be restored to OPERABLE status within 

2 hours by powering the bus from the associated [inverter via inverted 

DC, inverter using internal AC source, or Class 1E constant voltage 

transformer]. 

Condition B represents one or more AC vital buses without power; 

potentially both the DC source and the associated AC source are 

nonfunctioning. In this situation, the unit is significantly more vulnerable 

to a complete loss of all noninterruptible power. It is, therefore, 

imperative that the operator's attention focus on stabilizing the unit, 

minimizing the potential for loss of power to the remaining vital buses, 

and restoring power to the affected vital bus. 

This 2 hour limit is more conservative than Completion Times allowed for 

the vast majority of components that are without adequate vital AC power. 

Taking exception to LCO 3.0.2 for components without adequate vital AC 

power, which would have the Required Action Completion Times shorter 

than 2 hours if declared inoperable, is acceptable because of: 

a. The potential for decreased safety by requiring a change in unit 

conditions (i.e., requiring a shutdown) and not allowing stable 

operations to continue, 

b. The potential for decreased safety by requiring entry into numerous 

Applicable Conditions and Required Actions for components without 

adequate vital AC power and not providing sufficient time for the 

operators to perform the necessary evaluations and actions for 

restoring power to the affected train, and 

c. The potential for an event in conjunction with a single failure of a 

redundant component. 

The 2 hour Completion Time takes into account the importance to safety 

of restoring the AC vital bus to OPERABLE status, the redundant 

capability afforded by the other OPERABLE vital buses, and the low 

probability of a DBA occurring during this period. 
Distribution Systems - Operating 

B 3.8.9 

CEOG STS B 3.8.9-6 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

The second Completion Time for Required Action B.1 establishes a limit 

on the maximum allowed for any combination of required distribution 

subsystems to be inoperable during any single contiguous occurrence of 

failing to meet the LCO. If Condition B is entered while, for instance, an 

AC bus is inoperable and subsequently returned OPERABLE, the LCO 

may already have been not met for up to 8 hours. This could lead to a 

total of 10 hours, since initial failure of the LCO, to restore the vital bus 

distribution system. At this time, an AC train could again become 

inoperable, and vital bus distribution restored OPERABLE. This could 

continue indefinitely. 

This Completion Time allows for an exception to the normal "time zero" 

for beginning the allowed outage time "clock." This will result in 

establishing the "time zero" at the time the LCO was initially not met, 

instead of the time Condition B was entered. The 16 hour Completion 

Time is an acceptable limitation on this potential to fail to meet the LCO 

indefinitely. 

C.1

With one or more DC buses or distribution panels inoperable, and a loss 

of function has not yet occurred, the remaining DC electrical power 

distribution subsystems are capable of supporting the minimum safety 

functions necessary to shut down the reactor and maintain it in a safe 

shutdown condition, assuming no single failure. The overall reliability is 

reduced, however, because a single failure in the remaining DC electrical 

power distribution subsystem could result in the minimum required ESF 

functions not being supported. Therefore, the [required] DC buses and 

distribution panels must be restored to OPERABLE status within 2 hours 

by powering the bus from the associated battery or charger. 

Condition C represents one or more DC buses or distribution panels 

without adequate DC power; potentially both with the battery significantly 

degraded and the associated charger nonfunctioning. In this situation, 

the unit is significantly more vulnerable to a complete loss of all DC 

power. It is, therefore, imperative that the operator's attention focus on 

stabilizing the unit, minimizing the potential for loss of power to the 

remaining trains and restoring power to the affected train. 
Distribution Systems - Operating 

B 3.8.9 

CEOG STS B 3.8.9-7 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

This 2 hour limit is more conservative than Completion Times allowed for 

the vast majority of components which would be without power. Taking 

exception to LCO 3.0.2 for components without adequate DC power, 

which would have Required Action Completion Times shorter than 

2 hours, is acceptable because of: 

a. The potential for decreased safety by requiring a change in unit 

conditions (i.e., requiring a shutdown) while allowing stable 

operations to continue, 

b. The potential for decreased safety by requiring entry into numerous 

applicable Conditions and Required Actions for components without 

DC power and not providing sufficient time for the operators to 

perform the necessary evaluations and actions for restoring power to 

the affected train, and 

c. The potential for an event in conjunction with a single failure of a 

redundant component. 

The 2 hour Completion Time for DC buses is consistent with Regulatory 

Guide 1.93 (Ref. 3). 

The second Completion Time for Required Action C.1 establishes a limit 

on the maximum time allowed for any combination of required distribution 

subsystems to be inoperable during any single contiguous occurrence of 

failing to meet the LCO. If Condition C is entered while, for instance, an 

AC bus is inoperable and subsequently returned OPERABLE, the LCO 

may already have been not met for up to 8 hours. This could lead to a 

total of 10 hours, since initial failure of the LCO, to restore the DC 

distribution system. At this time, an AC train could again become 

inoperable, and DC distribution restored OPERABLE. This could 

continue indefinitely. 

This Completion Time allows for an exception to the normal "time zero" 

for beginning the allowed outage time "clock." This will result in 

establishing the "time zero" at the time the LCO was initially not met, 

instead of the time Condition C was entered. The 16 hour Completion 

Time is an acceptable limitation on this potential to fail to meet the LCO 

indefinitely. 
Distribution Systems - Operating 

B 3.8.9 

CEOG STS B 3.8.9-8 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

D.1 and D.2

If the inoperable distribution subsystem cannot be restored to 

OPERABLE status within the required Completion Time, the unit must be 

brought to a MODE in which the LCO does not apply. To achieve this 

status, the unit must be brought to at least MODE 3 within 6 hours and to 

MODE 5 within 36 hours. The allowed Completion Times are reasonable, 

based on operating experience, to reach the required unit conditions from 

full power conditions in an orderly manner and without challenging unit 

systems. 

E.1

Condition E corresponds to a level of degradation in the electrical 

distribution system that causes a required safety function to be lost. 

When more than one inoperable electrical power distribution subsystem 

results in the loss of a required function, the plant is in a condition outside 

the accident analysis. Therefore, no additional time is justified for 

continued operation. LCO 3.0.3 must be entered immediately to 

commence a controlled shutdown. 

SURVEILLANCE SR 3.8.9.1

REQUIREMENTS 

This Surveillance verifies that the AC, DC, and AC vital bus electrical 

power distribution systems are functioning properly, with the correct 

circuit breaker alignment. The correct breaker alignment ensures the 

appropriate separation and independence of the electrical divisions is 

maintained, and the appropriate voltage is available to each required bus. 

The verification of proper voltage availability on the buses ensures that 

the required voltage is readily available for motive as well as control 

functions for critical system loads connected to these buses. The 7 day 

Frequency takes into account the redundant capability of the AC, DC, and 

AC vital bus electrical power distribution subsystems, and other 

indications available in the control room that alert the operator to 

subsystem malfunctions. 

REFERENCES 1. FSAR, Chapter [6]. 

 2. FSAR, Chapter [15]. 

3. Regulatory Guide 1.93, December 1974. 
Distribution Systems - Operating 

B 3.8.9 

CEOG STS B 3.8.9-9 Rev. 3.0, 03/31/04 

Table B 3.8.9-1 (page 1 of 1) 

AC and DC Electrical Power Distribution Systems 

TYPE VOLTAGE TRAIN A* TRAIN B* 

AC safety buses [4160 V] [ESF Bus] [NB01] [ESF Bus] [NB02] 

 

[480 V] Load Centers 

[NG01, NG03] 

Load Centers 

[NG02, NG04] 

 

[480 V] Motor Control 

Centers 

[NG01A, NG01I, 

NG01B, NG03C, 

NG03I, NG03D] 

Motor Control 

Centers 

[NG02A, NG02I, 

NG02B, NG04C, 

NG04I, NG04D] 

 

[120 V] Distribution Panels 

[NP01, NP03] 

Distribution Panels 

[NP02, NP04] 

DC buses [125 V] Bus [NK01] Bus [NK02] 

 

Bus [NK03] Bus [NK04] 

Distribution Panels 

[NK41, NK43, NK51] 

Distribution Panels 

[NK42, NK44, NK52] 

AC vital buses [120 V] Bus [NN01] Bus [NN02] 

 

Bus [NN03] Bus [NN04] 

* Each train of the AC and DC electrical power distribution systems is a subsystem. 
Distribution Systems - Shutdown 

B 3.8.10 

CEOG STS B 3.8.10-1 Rev. 3.0, 03/31/04 

B 3.8 ELECTRICAL POWER SYSTEMS 

B 3.8.10 Distribution Systems - Shutdown 

BASES 

BACKGROUND A description of the AC, DC, and AC vital bus electrical power distribution 

systems is provided in the Bases for LCO 3.8.9, "Distribution Systems - 

Operating." 

APPLICABLE The initial conditions of Design Basis Accident and transient analyses in 

SAFETY the FSAR, Chapter [6] (Ref. 1) and Chapter [15] (Ref. 2), assume 

ANALYSES Engineered Safety Feature (ESF) systems are OPERABLE. The AC, DC, 

and AC vital bus electrical power distribution systems are designed to 

provide sufficient capacity, capability, redundancy, and reliability to 

ensure the availability of necessary power to ESF systems so that the 

fuel, Reactor Coolant System, and containment design limits are not 

exceeded. 

The OPERABILITY of the AC, DC, and AC vital bus electrical power 

distribution system is consistent with the initial assumptions of the 

accident analyses and the requirements for the supported systems' 

OPERABILITY. 

The OPERABILITY of the minimum AC, DC, and AC vital bus electrical 

power distribution subsystems during MODES 5 and 6, and during 

movement of [recently] irradiated fuel assemblies, ensures that: 

a. The unit can be maintained in the shutdown or refueling condition for 

extended periods, 

b. Sufficient instrumentation and control capability is available for 

monitoring and maintaining the unit status, and 

c. Adequate power is provided to mitigate events postulated during 

shutdown, such as a fuel handling accident [involving handling 

recently irradiated fuel. Due to radioactive decay, AC, DC, and AC 

vital bus electrical power is only required to mitigate fuel handling 

accidents involving handling recently irradiated fuel (i.e., fuel that has 

occupied part of a critical reactor core within the previous [X] days)]. 

The AC and DC electrical power distribution systems satisfy Criterion 3 of 

10 CFR 50.36(c)(2)(ii). 
Distribution Systems - Shutdown 

B 3.8.10 

CEOG STS B 3.8.10-2 Rev. 3.0, 03/31/04 

BASES 

LCO Various combinations of subsystems, equipment, and components are 

required OPERABLE by other LCOs, depending on the specific unit 

condition. Implicit in those requirements is the required OPERABILITY of 

necessary support required features. This LCO explicitly requires 

energization of the portions of the electrical distribution system necessary 

to support OPERABILITY of required systems, equipment and 

components - all specifically addressed in each LCO and implicitly 

required via the definition of OPERABILITY. 

Maintaining these portions of the distribution system energized ensures 

the availability of sufficient power to operate the unit in a safe manner to 

mitigate the consequences of postulated events during shutdown (e.g., 

fuel handling accidents [involving handling recently irradiated fuel]). 

APPLICABILITY The AC and DC electrical power distribution subsystems required to be 

OPERABLE in MODES 5 and 6, and during movement of [recently] 

irradiated fuel assemblies, provide assurance that: 

a. Systems to provide adequate coolant inventory makeup are available 

for the irradiated fuel in the core, 

b. Systems needed to mitigate a fuel handling accident [involving 

handling recently irradiated fuel (i.e., fuel that has occupied part of a 

critical reactor core within the previous [X] days)] are available, 

c. Systems necessary to mitigate the effects of events that can lead to 

core damage during shutdown are available, and 

d. Instrumentation and control capability is available for monitoring and 

maintaining the unit in a cold shutdown condition and refueling 

condition. 

The AC, DC, and AC vital bus electrical power distribution subsystem 

requirements for MODES 1, 2, 3, and 4 are covered in LCO 3.8.9. 

ACTIONS LCO 3.0.3 is not applicable while in MODE 5 or 6. However, since 

irradiated fuel assembly movement can occur in MODE 1, 2, 3, or 4, the 

ACTIONS have been modified by a Note stating that LCO 3.0.3 is not 

applicable. If moving irradiated fuel assemblies while in MODE 5 or 6, 

LCO 3.0.3 would not specify any action. If moving irradiated fuel 

assemblies while in MODE 1, 2, 3, or 4, the fuel movement is 

independent of reactor operations. Entering LCO 3.0.3, while in MODE 1, 

2, 3, or 4 would require the unit to be shutdown unnecessarily. 
Distribution Systems - Shutdown 

B 3.8.10 

CEOG STS B 3.8.10-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

A.1, A.2.1, A.2.2, A.2.3, A.2.4, and A.2.5

Although redundant required features may require redundant trains of 

electrical power distribution subsystems to be OPERABLE, one 

OPERABLE distribution subsystem train may be capable of supporting 

sufficient required features to allow continuation of CORE ALTERATIONS 

and [recently] irradiated fuel movement. By allowing the option to declare 

required features associated with an inoperable distribution subsystem 

inoperable, appropriate restrictions are implemented in accordance with 

the affected distribution subsystems LCO's Required Actions. In many 

instances, this option may involve undesired administrative efforts. 

Therefore, the allowance for sufficiently conservative actions is made 

(i.e., to suspend CORE ALTERATIONS, movement of [recently] irradiated 

fuel assemblies, and operations involving positive reactivity additions that 

could result in loss of required SDM (MODE 5) or boron concentration 

(MODE 6). 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 

must be from sources that have a boron concentration greater than that 

what would be required in the RCS for 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. 

Suspension of these activities shall not preclude completion of actions to 

establish a safe conservative condition. These actions minimize the 

probability of the occurrence of postulated events. It is further required to 

immediately initiate action to restore the required AC and DC electrical 

power distribution subsystems and to continue this action until restoration 

is accomplished in order to provide the necessary power to the unit safety 

systems. 

Notwithstanding performance of the above conservative Required 

Actions, a required shutdown cooling (SDC) subsystem may be 

inoperable. In this case, Required Actions A.2.1 through A.2.4 do not 

adequately address the concerns relating to coolant circulation and heat 

removal. Pursuant to LCO 3.0.6, the SDC ACTIONS would not be 

entered. Therefore, Required Action A.2.5 is provided to direct declaring 

SDC inoperable, which results in taking the appropriate SDC actions. 
Distribution Systems - Shutdown 

B 3.8.10 

CEOG STS B 3.8.10-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

The Completion Time of immediately is consistent with the required times 

for actions requiring prompt attention. The restoration of the required 

distribution subsystems should be completed as quickly as possible in 

order to minimize the time the unit safety systems may be without power. 

SURVEILLANCE SR 3.8.10.1

REQUIREMENTS 

This Surveillance verifies that the AC, DC, and AC vital bus electrical 

power distribution system is functioning properly, with all the buses 

energized. The verification of proper voltage availability on the buses 

ensures that the required power is readily available for motive as well as 

control functions for critical system loads connected to these buses. The 

7 day Frequency takes into account the redundant capability of the 

electrical power distribution subsystems, and other indications available in 

the control room that alert the operator to subsystem malfunctions. 

REFERENCES 1. FSAR, Chapter [6]. 

 2. FSAR, Chapter [15]. 
Boron Concentration 

B 3.9.1 

CEOG STS B 3.9.1-1 Rev. 3.0, 03/31/04 

B 3.9 REFUELING OPERATIONS 

B 3.9.1 Boron Concentration 

BASES 

BACKGROUND The limit on the boron concentrations of the Reactor Coolant System 

(RCS), the refueling canal, and refueling cavity during refueling ensures 

that the reactor remains subcritical during MODE 6. Refueling boron 

concentration is the soluble boron concentration in the coolant in each of 

these volumes having direct access to the reactor core during refueling. 

The soluble boron concentration offsets the core reactivity and is 

measured by chemical analysis of a representative sample of the coolant 

in each of the volumes. The refueling boron concentration limit is 

specified in the COLR. Unit procedures ensure the specified boron 

concentration in order to maintain an overall core reactivity of keff ≤ 0.95 

during fuel handling, with control element assemblies (CEAs) and fuel 

assemblies assumed to be in the most adverse configuration (least 

negative reactivity) allowed by unit procedures. 

GDC 26 of 10 CFR 50, Appendix A, requires that two independent 

reactivity control systems of different design principles be provided 

(Ref. 1). One of these systems must be capable of holding the reactor 

core subcritical under cold conditions. The Chemical and Volume Control 

System (CVCS) is the system capable of maintaining the reactor 

subcritical in cold conditions by maintaining the boron concentration. 

The reactor is brought to shutdown conditions before beginning 

operations to open the reactor vessel for refueling. After the RCS is 

cooled and depressurized and the vessel head is unbolted, the head is 

slowly removed to form the refueling cavity. The refueling canal and the 

refueling cavity are then flooded with borated water from the refueling 

water tank into the open reactor vessel by gravity feeding or by the use of 

the Shutdown Cooling (SDC) System pumps. 

The pumping action of the SDC System in the RCS and the natural 

circulation due to thermal driving heads in the reactor vessel and the 

refueling cavity mix the added concentrated boric acid with the water in 

the refueling canal. The SDC System is in operation during refueling (see 

LCO 3.9.4, "Shutdown Cooling and Coolant Circulation - High Water 

Level," and LCO 3.9.5, "Shutdown Cooling and Coolant Circulation - Low 

Water Level") to provide forced circulation in the RCS and assist in 

maintaining the boron concentrations in the RCS, the refueling canal, and 

the refueling cavity above the COLR limit. 
Boron Concentration 

B 3.9.1 

CEOG STS B 3.9.1-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE During refueling operations, the reactivity condition of the core is 

SAFETY consistent with the initial conditions assumed for the boron dilution 

ANALYSES accident in the accident analysis and is conservative for MODE 6. The 

boron concentration limit specified in the COLR is based on the core 

reactivity at the beginning of each fuel cycle (the end of refueling) and 

includes an uncertainty allowance. 

The required boron concentration and the unit refueling procedures that 

demonstrate the correct fuel loading plan (including full core mapping) 

ensure the keff of the core will remain ≤ 0.95 during the refueling 

operation. Hence, at least a 5% ∆k/k margin of safety is established 

during refueling. 

During refueling, the water volume in the spent fuel pool, the transfer 

canal, the refueling canal, the refueling cavity, and the reactor vessel form 

a single mass. As a result, the soluble boron concentration is relatively 

the same in each of these volumes. 

The limiting boron dilution accident analyzed occurs in MODE 5 (Ref. 2). 

A detailed discussion of this event is provided in B 3.1.1, “SHUTDOWN 

MARGIN (SDM).” 

The RCS boron concentration satisfies Criterion 2 of 

10 CFR 50.36(c)(2)(ii). 

LCO The LCO requires that a minimum boron concentration be maintained in 

the RCS, the refueling canal, and refueling cavity while in MODE 6. The 

boron concentration limit specified in the COLR ensures a core keff of 

≤ 0.95 is maintained during fuel handling operations. Violation of the LCO 

could lead to an inadvertent criticality during MODE 6. 

APPLICABILITY This LCO is applicable in MODE 6 to ensure that the fuel in the reactor 

vessel will remain subcritical. The required boron concentration ensures 

a keff ≤ 0.95. Above MODE 6, LCO 3.1.1, "SHUTDOWN MARGIN 

(SDM)," ensures that an adequate amount of negative reactivity is 

available to shut down the reactor and to maintain it subcritical. 

The Applicability is modified by a Note. The Note states that the limits on 

boron concentration are only applicable to the refueling canal and the 

refueling cavity when those volumes are connected to the RCS. When 

the refueling canal and the refueling cavity are isolated from the RCS, no 

potential path for boron dilution exists. 
Boron Concentration 

B 3.9.1 

CEOG STS B 3.9.1-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1 and A.2

Continuation of CORE ALTERATIONS or positive reactivity additions 

(including actions to reduce boron concentration) is contingent upon 

maintaining the unit in compliance with the LCO. If the boron 

concentration of any coolant volume in the RCS, the refueling canal, or 

the refueling cavity is less than its limit, all operations involving CORE 

ALTERATIONS or positive reactivity additions must be suspended 

immediately. Operations that individually add limited positive reactivity 

(e.g., temperature fluctuations from inventory addition or temperature 

control fluctuations), but when combined with all other operations 

affecting core reactivity (e.g., intentional boration) result in overall net 

negative reactivity addition, are not precluded by this action. 

Suspension of CORE ALTERATIONS and positive reactivity additions 

shall not preclude moving a component to a safe position. 

A.3

In addition to immediately suspending CORE ALTERATIONS and 

positive reactivity additions, boration to restore the concentration must be 

initiated immediately. 

In determining the required combination of boration flow rate and 

concentration, there is no unique design basis event that must be 

satisfied. The only requirement is to restore the boron concentration to its 

required value as soon as possible. In order to raise the boron 

concentration as soon as possible, the operator should begin boration 

with the best source available for unit conditions. 

Once boration is initiated, it must be continued until the boron 

concentration is restored. The restoration time depends on the amount of 

boron that must be injected to reach the required concentration. 

SURVEILLANCE SR 3.9.1.1

REQUIREMENTS 

This SR ensures the coolant boron concentration in the RCS, and 

connected portions of the refueling canal and the refueling cavity, is within 

the COLR limits. The boron concentration of the coolant in each required 

volume is determined periodically by chemical analysis. Prior to reconnecting portions of the refueling canal or the refueling cavity to the 

RCS, this SR must be met per SR 3.0.4. If any dilution activity has 

occurred while the cavity or canal were disconnected from the RCS, this 

SR ensures the correct boron concentration prior to communication with 

the RCS. 
Boron Concentration 

B 3.9.1 

CEOG STS B 3.9.1-4 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE REQUIREMENTS (continued) 

A minimum Frequency of once every 72 hours is therefore a reasonable 

amount of time to verify the boron concentration of representative 

samples. The Frequency is based on operating experience, which has 

shown 72 hours to be adequate. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26. 

 2. FSAR, Section [ ]. 
Nuclear Instrumentation 

B 3.9.2 

CEOG STS B 3.9.2-1 Rev. 3.0, 03/31/04 

B 3.9 REFUELING OPERATIONS 

B 3.9.2 Nuclear Instrumentation 

BASES 

BACKGROUND The source range monitors (SRMs) are used during refueling operations 

to monitor the core reactivity condition. The installed SRMs are part of 

the Nuclear Instrumentation System (NIS). These detectors are located 

external to the reactor vessel and detect neutrons leaking from the core. 

The use of portable detectors is permitted, provided the 

LCO requirements are met. 

The installed SRMs are BF3 detectors operating in the proportional region 

of the gas filled detector characteristic curve. The detectors monitor the 

neutron flux in counts per second. The instrument range covers five 

decades of neutron flux (1E+5 cps) with a [5%] instrument accuracy. The 

detectors also provide continuous visual indication in the control room 

and an audible alarm to alert operators to a possible dilution accident. 

The NIS is designed in accordance with the criteria presented in 

Reference 1. 

If used, portable detectors should be functionally equivalent to the NIS 

SRMs. 

APPLICABLE Two OPERABLE SRMs are required to provide a signal to alert the 

SAFETY operator to unexpected changes in core reactivity such as by a boron 

ANALYSES dilution accident or an improperly loaded fuel assembly. The safety 

analysis of the uncontrolled boron dilution accident is described in 

Reference 2. The analysis of the uncontrolled boron dilution accident 

shows that normally available SHUTDOWN MARGIN would be reduced, 

but there is sufficient time for the operator to take corrective actions. 

The SRMs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO This LCO requires two SRMs OPERABLE to ensure that redundant 

monitoring capability is available to detect changes in core reactivity. 

APPLICABILITY In MODE 6, the SRMs must be OPERABLE to determine changes in core 

reactivity. There is no other direct means available to check core 

reactivity levels. 

In MODES 2, 3, 4, and 5, the installed source range detectors and 

circuitry are required to be OPERABLE by LCO 3.3.2, "RPS 

Instrumentation Shutdown." 
Nuclear Instrumentation 

B 3.9.2 

CEOG STS B 3.9.2-2 Rev. 3.0, 03/31/04 

BASES 

ACTIONS A.1 and A.2

With only one SRM OPERABLE, redundancy has been lost. Since these 

instruments are the only direct means of monitoring core reactivity 

conditions, CORE ALTERATIONS and introduction of coolant into the 

RCS with boron concentration less than required to meet the minimum 

boron concentration of LCO 3.9.1 must be suspended immediately. 

Suspending positive reactivity additions that could result in failure to meet 

the minimum boron concentration limit is required to assure continued 

safe operation. Introduction of coolant inventory must be from sources 

that have a boron concentration greater than that what would be required 

in the RCS for minimum refueling boron concentration. This may result in 

an overall reduction in RCS boron concentration, but provides acceptable 

margin to maintaining subcritical operation. Performance of Required 

Action A.1 shall not preclude completion of movement of a component to 

a safe position. 

B.1

With no SRM OPERABLE, action to restore a monitor to OPERABLE 

status shall be initiated immediately. Once initiated, action shall be 

continued until an SRM is restored to OPERABLE status. 

B.2

With no SRM OPERABLE, there is no direct means of detecting changes 

in core reactivity. However, since CORE ALTERATIONS and positive 

reactivity additions are not to be made, the core reactivity condition is 

stabilized until the SRMs are OPERABLE. This stabilized condition is 

determined by performing SR 3.9.1.1 to verify that the required boron 

concentration exists. 

The Completion Time of once per 12 hours is sufficient to obtain and 

analyze a reactor coolant sample for boron concentration and ensures 

that unplanned changes in boron concentration would be identified. The 

12 hour Frequency is reasonable, considering the low probability of a 

change in core reactivity during this period. 
Nuclear Instrumentation 

B 3.9.2 

CEOG STS B 3.9.2-3 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.9.2.1

REQUIREMENTS 

SR 3.9.2.1 is the performance of a CHANNEL CHECK, which is a 

comparison of the parameter indicated on one channel to a similar 

parameter on other channels. It is based on the assumption that the two 

indication channels should be consistent with core conditions. Changes 

in fuel loading and core geometry can result in significant differences 

between source range channels, but each channel should be consistent 

with its local conditions. 

The Frequency of 12 hours is consistent with the CHANNEL CHECK 

Frequency specified similarly for the same instruments in LCO 3.3.1, 

"Reactor Protection System." 

SR 3.9.2.2

SR 3.9.2.2 is the performance of a CHANNEL CALIBRATION every 

18 months. This SR is modified by a Note stating that neutron detectors 

are excluded from the CHANNEL CALIBRATION. The CHANNEL 

CALIBRATION for the source range neutron flux monitors consists of 

obtaining the detector plateau or preamp discriminator curves, evaluating 

those curves, and comparing the curves to the manufacturer's data. 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 on the 18 month Frequency. 

REFERENCES 1. 10 CFR 50, Appendix A, GDC 13, GDC 26, GDC 28, and GDC 29. 

 2. FSAR, Section [ ]. 
Containment Penetrations 

B 3.9.3 

CEOG STS B 3.9.3-1 Rev. 3.0, 03/31/04 

B 3.9 REFUELING OPERATIONS 

B 3.9.3 Containment Penetrations 

BASES 

BACKGROUND During movement of [recently] irradiated fuel assemblies within 

containment, a release of fission product radioactivity within the 

containment will be restricted from escaping to the environment when the 

LCO requirements are met. In MODES 1, 2, 3, and 4, this is 

accomplished by maintaining containment OPERABLE as described in 

LCO 3.6.1, "Containment." In MODE 6, the potential for containment 

pressurization as a result of an accident is not likely; therefore, 

requirements to isolate the containment from the outside atmosphere can 

be less stringent. The LCO requirements are referred to as "containment 

closure" rather than "containment OPERABILITY." Containment closure 

means that all potential escape paths are closed or capable of being 

closed. Since there is no potential for containment pressurization, the 

Appendix J leakage criteria and tests are not required. 

The containment serves to contain fission product radioactivity that may 

be released from the reactor core following an accident, such that offsite 

radiation exposures are maintained well within the requirements of 

10 CFR 100. Additionally, the containment structure provides radiation 

shielding from the fission products that may be present in the containment 

atmosphere following accident conditions. 

The containment equipment hatch, which is part of the containment 

pressure boundary, provides a means for moving large equipment and 

components into and out of containment. During movement of [recently] 

irradiated fuel assemblies within containment, the equipment hatch must 

be held in place by at least four bolts. Good engineering practice dictates 

that the bolts required by this LCO be approximately equally spaced. 

The containment air locks, which are also part of the containment 

pressure boundary, provide a means for personnel access during 

MODES 1, 2, 3, and 4 operation in accordance with LCO 3.6.2, 

"Containment Air Locks." Each air lock has a door at both ends. The 

doors are normally interlocked to prevent simultaneous opening when 

containment OPERABILITY is required. During periods of shutdown 

when containment closure is not required, the door interlock mechanism 

may be disabled, allowing both doors of an air lock to remain open for 

extended periods when frequent containment entry is necessary. During 

movement of [recently] irradiated fuel assemblies within containment, 

containment closure is required; therefore, the door interlock mechanism 

may remain disabled, but one air lock door must always remain [capable 

of being] closed. 
Containment Penetrations 

B 3.9.3 

CEOG STS B 3.9.3-2 Rev. 3.0, 03/31/04 

BASES 

BACKGROUND (continued) 

The requirements on containment penetration closure ensure that a 

release of fission product radioactivity within containment will be restricted 

to within regulatory limits. 

The Containment Purge and Exhaust System includes two subsystems. 

The normal subsystem includes a 42 inch purge penetration and a 

42 inch exhaust penetration. The second subsystem, a minipurge 

system, includes an 8 inch purge penetration and an 8 inch exhaust 

penetration. During MODES 1, 2, 3, and 4, the two valves in each of the 

normal purge and exhaust penetrations are secured in the closed 

position. The two valves in each of the two minipurge penetrations can 

be opened intermittently, but are closed automatically by the Engineered 

Safety Features Actuation System (ESFAS). Neither of the subsystems 

is subject to a Specification in MODE 5. 

In MODE 6, large air exchanges are necessary to conduct refueling 

operations. The normal 42 inch purge system is used for this purpose 

and all valves are closed by the ESFAS in accordance with LCO 3.3.2, 

"Reactor Protective System (RPS) - Shutdown." 

[ The minipurge system remains operational in MODE 6 and all four valves 

are also closed by the ESFAS. 

[or] 

The minipurge system is not used in MODE 6. All four [8] inch valves are 

secured in the closed position. ]

The other containment penetrations that provide direct access from 

containment atmosphere to outside atmosphere must be isolated on at 

least one side. Isolation may be achieved by an OPERABLE automatic 

isolation valve, or by a manual isolation valve, blind flange, or equivalent. 

Equivalent isolation methods must be approved and may include use of a 

material that can provide a temporary, atmospheric pressure ventilation 

barrier for the other containment penetrations during [recently] irradiated 

fuel movements (Ref. 1). 

APPLICABLE During CORE ALTERATIONS or movement of irradiated fuel assemblies 

SAFETY within containment, the most severe radiological consequences result 

ANALYSES from a fuel handling accident [involving handling recently irradiated fuel]. 

The fuel handling accident is a postulated event that involves damage to 

irradiated fuel (Ref. 2). Fuel handling accidents, analyzed in Ref. 3, 
Containment Penetrations 

B 3.9.3 

CEOG STS B 3.9.3-3 Rev. 3.0, 03/31/04 

BASES 

APPLICABLE SAFETY ANALYSES (continued) 

include dropping a single irradiated fuel assembly and handling tool or a 

heavy object onto other irradiated fuel assemblies. The requirements of 

LCO 3.9.6, "Refueling Water Level," in conjunction with minimum decay 

time of [72] hours prior to [irradiated fuel movement with containment 

closure capability or a minimum decay time of [x] days without 

containment closure capability], ensure that the release of fission product 

radioactivity, subsequent to a fuel handling accident, results in doses that 

are well within the guideline values specified in 10 CFR 100. The 

acceptance limits for offsite radiation exposure are contained in Standard 

Review Plan Section 15.7.4, Rev. 1 (Ref. 3), which defines "well within" 

10 CFR 100 to be 25% or less of the 10 CFR 100 values. 

Containment penetrations satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii). 

LCO -----------------------------------REVIEWER’S NOTE----------------------------------- 

The allowance to have containment personnel air lock doors open and 

penetration flow paths with direct access from the containment 

atmosphere to the outside atmosphere to be unisolated during fuel 

movement and CORE ALTERATIONS is based on (1) confirmatory dose 

calculations of a fuel handling accident as approved by the NRC staff 

which indicate acceptable radiological consequences and 

(2) commitments from the licensee to implement acceptable 

administrative procedures that ensure in the event of a refueling accident 

(even though the containment fission product control function is not 

required to meet acceptable dose consequences) that the open air lock 

can and will be promptly closed following containment evacuation and 

that the open penetration(s) can and will be promptly closed. The time to 

close penetrations or combination of penetrations shall be included in the 

confirmatory dose calculations. 

 -------------------------------------------------------------------------------------------------- 

This LCO limits the consequences of a fuel handling accident [involving 

handling recently irradiated fuel] in containment by limiting the potential 

escape paths for fission product radioactivity released within containment. 

The LCO requires any penetration providing direct access from the 

containment atmosphere to the outside atmosphere to be closed except 

for the OPERABLE containment purge and exhaust penetrations [and the 

containment personnel air locks]. For the OPERABLE containment purge 

and exhaust penetrations, this LCO ensures that these penetrations are 

isolable by the Containment Purge and Exhaust Isolation System. The 
Containment Penetrations 

B 3.9.3 

CEOG STS B 3.9.3-4 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

OPERABILITY requirements for this LCO ensure that the automatic purge 

and exhaust valve closure times specified in the FSAR can be achieved 

and therefore meet the assumptions used in the safety analysis to ensure 

releases through the valves are terminated, such that the radiological 

doses are within the acceptance limit. The LCO is modified by a Note 

allowing penetration flow paths with direct access from the containment 

atmosphere to the outside atmosphere to be unisolated under 

administrative controls. Administrative controls ensure that 1) appropriate 

personnel are aware of the open status of the penetration flow path 

during CORE ALTERATIONS or movement of irradiated fuel assemblies 

within containment, and 2) specified individuals are designated and 

readily available to isolate the flow path in the event of a fuel handling 

accident. 

The containment personnel air lock doors may be open during movement 

of [recently] irradiated fuel in the containment provided that one door is 

capable of being closed in the event of a fuel handling accident. Should a 

fuel handling accident occur inside containment, one personnel airlock 

door will be closed following an evacuations of containment. 

APPLICABILITY The containment penetration requirements are applicable during 

movement of [recently] irradiated fuel assemblies within containment 

because this is when there is a potential for the limiting fuel handling 

accident. In MODES 1, 2, 3, and 4, containment penetration 

requirements are addressed by LCO 3.6.1, "Containment." In MODES 5 

and 6, when movement of irradiated fuel assemblies within containment is 

not being conducted, the potential for a fuel handling accident does not 

exist. [Additionally, due to radioactive decay, a fuel handling accident 

involving handling recently irradiated fuel (i.e., fuel that has occupied part 

of a critical reactor core within the previous [X] days) will result in doses 

that are well within the guideline values specified in 10 CFR 100 even 

without containment closure capability.] Therefore, under these 

conditions no requirements are placed on containment penetration status. 

-----------------------------------REVIEWER’S NOTE----------------------------------- 

The addition of the term "recently" associated with handling irradiated fuel 

in all of the containment function Technical Specification requirements is 

only applicable to those licensees who have demonstrated by analysis 

that after sufficient radioactive decay has occurred, off-site doses 

resulting from a fuel handling accident remain below the Standard Review 

Plan limits (well within 10 CFR 100). 
Containment Penetrations 

B 3.9.3 

CEOG STS B 3.9.3-5 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY (continued) 

Additionally, licensees adding the term "recently" must make the following 

commitment which is consistent with NUMARC 93-01, Revision 4, 

Section 11.3.6.5 "Safety Assessment for Removal of Equipment from 

Service During Shutdown Conditions," subheading "Containment - 

Primary (PWR)/Secondary (BWR)." 

"The following guidelines are included in the assessment of systems 

removed from service during movement of irradiated fuel: 

- During fuel handling/core alterations, ventilation system and 

radiation monitor availability (as defined in NUMARC 91-06) should 

be assessed, with respect to filtration and monitoring of releases from 

the fuel. Following shutdown, radioactivity in the fuel decays away 

fairly rapidly. The basis of the Technical Specification operability 

amendment is the reduction in doses due to such decay. The goal of 

maintaining ventilation system and radiation monitor availability is to 

reduce doses even further below that provided by the natural decay. 

- A single normal or contingency method to promptly close primary or 

secondary containment penetrations should be developed. Such 

prompt methods need not completely block the penetration or be 

capable of resisting pressure. 

The purpose of the "prompt methods" mentioned above are to enable 

ventilation systems to draw the release from a postulated fuel handling 

accident in the proper direction such that it can be treated and 

monitored." 

 -------------------------------------------------------------------------------------------------- 

ACTIONS A.1 and A.2

With the containment equipment hatch, air locks, or any containment 

penetration that provides direct access from the containment atmosphere 

to the outside atmosphere not in the required status, including the 

Containment Purge and Exhaust Isolation System not capable of 

automatic actuation when the purge and exhaust valves are open, the 

unit must be placed in a condition in which the isolation function is not 

needed. This is accomplished by immediately suspending movement of 

[recently] irradiated fuel assemblies within containment. Performance of 

these actions shall not preclude completion of movement of a component 

to a safe position. 
Containment Penetrations 

B 3.9.3 

CEOG STS B 3.9.3-6 Rev. 3.0, 03/31/04 

BASES 

SURVEILLANCE SR 3.9.3.1

REQUIREMENTS 

This Surveillance demonstrates that each of the containment penetrations 

required to be in its closed position is in that position. The Surveillance 

on the open purge and exhaust valves will demonstrate that the valves 

are not blocked from closing. Also, the Surveillance will demonstrate that 

each valve operator has motive power, which will ensure each valve is 

capable of being closed by an OPERABLE automatic containment purge 

and exhaust isolation signal. 

The Surveillance is performed every 7 days during movement of [recently] 

irradiated fuel assemblies within the 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 [involving handling 

recently irradiated fuel] that releases fission product radioactivity within 

the containment will not result in a release of significant fission product 

radioactivity to the environment in excess of those recommended by 

Standard Review Plan Section 15.7.4 (Ref. 3). 

SR 3.9.3.2

This Surveillance demonstrates that each containment purge and exhaust 

valve actuates to its isolation position on manual initiation or on an actual 

or simulated high radiation signal. The 18 month Frequency maintains 

consistency with other similar ESFAS instrumentation and valve testing 

requirements. In LCO 3.3.4 [(Digital) or 3.3.3 (Analog)], "Miscellaneous 

Actuations," the Containment Purge Isolation Signal System requires a 

CHANNEL CHECK every 7 days and a CHANNEL FUNCTIONAL TEST 

every 31 days to ensure the channel OPERABILITY during refueling 

operations. Every 18 months a CHANNEL CALIBRATION is performed. 

The system actuation response time is demonstrated every 18 months, 

during refueling, on a STAGGERED TEST BASIS. SR 3.6.3.5 

demonstrates that the isolation time of each valve is in accordance with 

the Inservice Testing Program requirements. These surveillances 

performed during MODE 6 will ensure that the valves are capable of 

closing after a postulated fuel handling accident [involving handling 

recently irradiated fuel] to limit a release of fission product radioactivity 

from the containment. 

The SR is modified by a Note stating that this Surveillance is not required 

to be met for valves in isolated penetrations. The LCO provides the 

option to close penetrations in lieu of requiring automatic actuation 

capability. 
Containment Penetrations 

B 3.9.3 

CEOG STS B 3.9.3-7 Rev. 3.0, 03/31/04 

BASES 

REFERENCES 1. GPU Nuclear Safety Evaluation SE-0002000-001, Rev. 0, May 20, 

1988. 

 2. FSAR, Section [ ]. 

 3. NUREG-0800, Section 15.7.4, Rev. 1, July 1981. 
SDC and Coolant Circulation - High Water Level 

B 3.9.4 

CEOG STS B 3.9.4-1 Rev. 3.0, 03/31/04 

B 3.9 REFUELING OPERATIONS 

B 3.9.4 Shutdown Cooling (SDC) and Coolant Circulation - High Water Level 

BASES 

BACKGROUND The purposes of the SDC System in MODE 6 are to remove decay heat 

and sensible heat from the Reactor Coolant System (RCS), as required 

by GDC 34, to provide mixing of borated coolant, to provide sufficient 

coolant circulation to minimize the effects of a boron dilution accident, and 

to prevent boron stratification (Ref. 1). Heat is removed from the RCS by 

circulating reactor coolant through the SDC heat exchanger(s), where the 

heat is transferred to the Component Cooling Water System via the SDC 

heat exchanger(s). The coolant is then returned to the RCS via the RCS 

cold leg(s). Operation of the SDC System for normal cooldown or decay 

heat removal is manually accomplished from the control room. The heat 

removal rate is adjusted by controlling the flow of reactor coolant through 

the SDC heat exchanger(s) and bypassing the heat exchanger(s). Mixing 

of the reactor coolant is maintained by this continuous circulation of 

reactor coolant through the SDC System. 

APPLICABLE If the reactor coolant temperature is not maintained below 200°F, boiling 

SAFETY of the reactor coolant could result. This could lead to inadequate cooling 

ANALYSES of the reactor fuel due to a resulting loss of coolant in the reactor vessel. 

Additionally, boiling of the reactor coolant could lead to a reduction in 

boron concentration in the coolant due to the boron plating out on 

components near the areas of the boiling activity, and because of the 

possible addition of water to the reactor vessel with a lower boron 

concentration than is required to keep the reactor subcritical. The loss of 

reactor coolant and the reduction of boron concentration in the reactor 

coolant would eventually challenge the integrity of the fuel cladding, which 

is a fission product barrier. One train of the SDC System is required to be 

operational in MODE 6, with the water level ≥ 23 ft above the top of the 

reactor vessel flange, to prevent this challenge. The LCO does permit the 

SDC pump to be removed from operation for short durations under the 

condition that the boron concentration is not diluted. This conditional 

stopping of the SDC pump does not result in a challenge to the fission 

product barrier. 

SDC and Coolant Circulation - High Water Level satisfies Criterion 2 of 

10 CFR 50.36(c)(2)(ii). 
SDC and Coolant Circulation - High Water Level 

B 3.9.4 

CEOG STS B 3.9.4-2 Rev. 3.0, 03/31/04 

BASES 

LCO Only one SDC loop is required for decay heat removal in MODE 6, with 

water level ≥ 23 ft above the top of the reactor vessel flange. Only one 

SDC loop is required because the volume of water above the reactor 

vessel flange provides backup decay heat removal capability. At least 

one SDC loop must be OPERABLE and in operation to provide: 

a. Removal of decay heat, 

b. Mixing of borated coolant to minimize the possibility of a criticality, 

and 

c. Indication of reactor coolant temperature. 

An OPERABLE SDC loop includes an SDC pump, a heat exchanger, 

valves, piping, instruments, and controls to ensure an OPERABLE flow 

path and to determine the low end temperature. The flow path starts in 

one of the RCS hot legs and is returned to the RCS cold legs. 

Both SDC pumps may be aligned to the Refueling Water Storage Tank to 

support filing or draining the refueling cavity or for performance of 

required testing. 

The LCO is modified by a Note that allows the required operating SDC 

loop to be removed from operation for up to 1 hour in each 8 hour period, 

provided no operations are permitted that would dilute the RCS boron 

concentration by introduction of coolant into the RCS with boron 

concentration less than required to meet the minimum boron 

concentration of LCO 3.9.1. Boron concentration reduction with coolant 

at boron concentrations less than required to assure the RCS boron 

concentration is maintained is prohibited because uniform concentration 

distribution cannot be ensured without forced circulation. This permits 

operations such as core mapping or alterations in the vicinity of the 

reactor vessel hot leg nozzles, and RCS to SDC isolation valve testing. 

During this 1 hour period, decay heat is removed by natural convection to 

the large mass of water in the refueling cavity. 

APPLICABILITY One SDC loop must be in operation in MODE 6, with the water level 

≥ 23 ft above the top of the reactor vessel flange, to provide decay heat 

removal. The 23 ft level was selected because it corresponds to the 23 ft 

requirement established for fuel movement in LCO 3.9.6, "Refueling 

Water Level." Requirements for the SDC System in other MODES are 

covered by LCOs in Section 3.4, Reactor Coolant System (RCS), and 

Section 3.5, Emergency Core Cooling Systems (ECCS). SDC loop 

requirements in MODE 6, with the water level < 23 ft above the top of the 

reactor vessel flange, are located in LCO 3.9.5, "Shutdown Cooling 

(SDC) and Coolant Circulation - Low Water Level." 
SDC and Coolant Circulation - High Water Level 

B 3.9.4 

CEOG STS B 3.9.4-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS SDC loop requirements are met by having one SDC loop OPERABLE 

and in operation, except as permitted in the Note to the LCO. 

A.1

If one required SDC loop is inoperable or not in operation, action shall be 

immediately initiated and continued until the SDC loop is restored to 

OPERABLE status and to operation. An immediate Completion Time is 

necessary for an operator to initiate corrective actions. 

A.2

If SDC loop requirements are not met, there will be no forced circulation 

to provide mixing to establish uniform boron concentrations. Suspending 

positive reactivity additions that could result in failure to meet the 

minimum boron concentration limit is required to assure continued safe 

operation. Introduction of coolant inventory must be from sources that 

have a boron concentration greater than that what would be required in 

the RCS for minimum refueling boron concentration. This may result in 

an overall reduction in RCS boron concentration, but provides acceptable 

margin to maintaining subcritical operation. 

A.3

If SDC loop requirements are not met, actions shall be taken immediately 

to suspend loading irradiated fuel assemblies in the core. With no forced 

circulation cooling, decay heat removal from the core occurs by natural 

convection to the heat sink provided by the water above the core. A 

minimum refueling water level of 23 ft above the reactor vessel flange 

provides an adequate available heat sink. Suspending any operation that 

would increase the decay heat load, such as loading a fuel assembly, is a 

prudent action under this condition. 

A.4, A.5, A.6.1, and A.6.2

If no SDC loop is in operation, the following actions must be taken: 

a. The equipment hatch must be closed and secured with [four] bolts, 

b. One door in each air lock must be closed, and 
SDC and Coolant Circulation - High Water Level 

B 3.9.4 

CEOG STS B 3.9.4-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

c. Each penetration providing direct access from the containment 

atmosphere to the outside atmosphere must be either closed by a 

manual or automatic isolation valve, blind flange, or equivalent, or 

verified to be capable of being closed by an OPERABLE 

Containment Purge and Exhaust Isolation System. 

With SDC loop requirements not met, the potential exists for the coolant 

to boil and release radioactive gas to the containment atmosphere. 

Performing the actions described above ensures that all containment 

penetrations are either closed or can be closed so that the dose limits are 

not exceeded. 

The Completion Time of 4 hours allows fixing of most SDC problems and 

is reasonable, based on the low probability of the coolant boiling in that 

time. 

SURVEILLANCE SR 3.9.4.1

REQUIREMENTS 

This Surveillance demonstrates that the SDC loop is in operation and 

circulating reactor coolant. The flow rate is determined by the flow rate 

necessary to provide sufficient decay heat removal capability and to 

prevent thermal and boron stratification in the core. The Frequency of 

12 hours is sufficient, considering the flow, temperature, pump control, 

and alarm indications available to the operator in the control room for 

monitoring the SDC System. 

REFERENCES 1. FSAR, Section [ ]. 
SDC and Coolant Circulation - Low Water Level 

B 3.9.5 

CEOG STS B 3.9.5-1 Rev. 3.0, 03/31/04 

B 3.9 REFUELING OPERATIONS 

B 3.9.5 Shutdown Cooling (SDC) and Coolant Circulation - Low Water Level 

BASES 

BACKGROUND The purposes of the SDC System in MODE 6 are to remove decay heat 

and sensible heat from the Reactor Coolant System (RCS), as required 

by GDC 34, to provide mixing of borated coolant, to provide sufficient 

coolant circulation to minimize the effects of a boron dilution accident, and 

to prevent boron stratification (Ref. 1). Heat is removed from the RCS by 

circulating reactor coolant through the SDC heat exchanger(s), where the 

heat is transferred to the Component Cooling Water System via the SDC 

heat exchanger(s). The coolant is then returned to the RCS via the RCS 

cold leg(s). Operation of the SDC System for normal cooldown or decay 

heat removal is manually accomplished from the control room. The heat 

removal rate is adjusted by controlling the flow of reactor coolant through 

the SDC heat exchanger(s) and bypassing the heat exchanger(s). Mixing 

of the reactor coolant is maintained by this continuous circulation of 

reactor coolant through the SDC System. 

APPLICABLE If the reactor coolant temperature is not maintained below 200°F, boiling 

SAFETY of the reactor coolant could result. This could lead to inadequate cooling 

ANALYSES of the reactor fuel due to the resulting loss of coolant in the reactor 

vessel. Additionally, boiling of the reactor coolant could lead to a 

reduction in boron concentration in the coolant due to the boron plating 

out on components near the areas of the boiling activity, and because of 

the possible addition of water to the reactor vessel with a lower boron 

concentration than is required to keep the reactor subcritical. The loss of 

reactor coolant and the reduction of boron concentration in the reactor 

coolant would eventually challenge the integrity of the fuel cladding, which 

is a fission product barrier. Two trains of the SDC System are required to 

be OPERABLE, and one train is required to be in operation in MODE 6, 

with the water level < 23 ft above the top of the reactor vessel flange, to 

prevent this challenge. 

SDC and Coolant Circulation - Low Water Level satisfies Criterion 2 of 

10 CFR 50.36(c)(2)(ii). 

LCO In MODE 6, with the water level < 23 ft above the top of the reactor vessel 

flange, both SDC loops must be OPERABLE. Additionally, one loop of the 

SDC System must be in operation in order to provide: 

a. Removal of decay heat, 

b. Mixing of borated coolant to minimize the possibility of a criticality, 

and 
SDC and Coolant Circulation - Low Water Level 

B 3.9.5 

CEOG STS B 3.9.5-2 Rev. 3.0, 03/31/04 

BASES 

LCO (continued) 

c. Indication of reactor coolant temperature. 

This LCO is modified by two Notes. Note 1 permits the SDC pumps to be 

removed from operation for ≤ 15 minutes when switching from one train to 

another. The circumstances for stopping both SDC pumps are to be 

limited to situations when the outage time is short [and the core outlet 

temperature is maintained > 10 degrees F below saturation temperature]. 

The Note prohibits boron dilution by introduction of coolant into the RCS 

with boron concentration less than that required to meet the minimum 

boron concentration of LCO 3.9.1, or draining operations when SDC 

forced flow is stopped. 

Note 2 allows one SDC loop to be inoperable for a period of 2 hours 

provided the other loop is OPERABLE and in operation. Prior to 

declaring the loop inoperable, consideration should be given to the 

existing plant configuration. This consideration should include that the 

core time to boil is short, there is no draining operation to further reduce 

RCS water level and that the capability exists to inject borated water into 

the reactor vessel. This permits surveillance tests to be performed on the 

inoperable loop during a time when these tests are safe and possible. 

An OPERABLE SDC loop consists of an SDC pump, a heat exchanger, 

valves, piping, instruments, and controls to ensure an OPERABLE flow 

path and to determine the low end temperature. The flow path starts in 

one of the RCS hot legs and is returned to the RCS cold legs. 

Both SDC pumps may be aligned to the Refueling Water Storage Tank to 

support filling or draining the refueling cavity or for performance of 

required testing. 

APPLICABILITY Two SDC loops are required to be OPERABLE, and one SDC loop must 

be in operation in MODE 6, with the water level < 23 ft above the top of 

the reactor vessel flange, to provide decay heat removal. Requirements 

for the SDC System in other MODES are covered by LCOs in 

Section 3.4, Reactor Coolant System. MODE 6 requirements, with a 

water level ≥ 23 ft above the reactor vessel flange, are covered in 

LCO 3.9.4, "Shutdown Cooling and Coolant Circulation - High Water 

Level." 

ACTIONS A.1 and A.2

If one SDC loop is inoperable, action shall be immediately initiated and 

continued until the SDC loop is restored to OPERABLE status and to 

operation, or until ≥ 23 ft of water level is established above the reactor 

vessel flange. When the water level is established at ≥ 23 ft above the 
SDC and Coolant Circulation - Low Water Level 

B 3.9.5 

CEOG STS B 3.9.5-3 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

reactor vessel flange, the Applicability will change to that of LCO 3.9.4, 

"Shutdown Cooling and Coolant Circulation - High Water Level," and only 

one SDC loop is required to be OPERABLE and in operation. An 

immediate Completion Time is necessary for an operator to initiate 

corrective actions. 

B.1

If no SDC loop is in operation or no SDC loops are OPERABLE, there will 

be no forced circulation to provide mixing to establish uniform boron 

concentrations. Suspending positive reactivity additions that could result 

in failure to meet the minimum boron concentration limit is required to 

assure continued safe operation. Introduction of coolant inventory must 

be from sources that have a boron concentration greater than that what 

would be required in the RCS for minimum refueling boron concentration. 

This may result in an overall reduction in RCS boron concentration, but 

provides acceptable margin to maintaining subcritical operation. 

B.2

If no SDC loop is in operation or no SDC loops are OPERABLE, action 

shall be initiated immediately and continued without interruption to restore 

one SDC loop to OPERABLE status and operation. Since the unit is in 

Conditions A and B concurrently, the restoration of two OPERABLE SDC 

loops and one operating SDC loop should be accomplished expeditiously. 

B.3, B.4, B.5.1, and B.5.2

If no SDC loop is in operation, the following actions must be taken: 

a. The equipment hatch must be closed and secured with [four] bolts, 

b. One door in each air lock must be closed, and 

c. Each penetration providing direct access from the containment 

atmosphere to the outside atmosphere must be either closed by a 

manual or automatic isolation valve, blind flange, or equivalent, or 

verified to be capable of being closed by an OPERABLE 

Containment Purge and Exhaust Isolation System. 

.
SDC and Coolant Circulation - Low Water Level 

B 3.9.5 

CEOG STS B 3.9.5-4 Rev. 3.0, 03/31/04 

BASES 

ACTIONS (continued) 

With SDC loop requirements not met, the potential exists for the coolant 

to boil and release radioactive gas to the containment atmosphere. 

Performing the actions stated above ensures that all containment 

penetrations are either closed or can be closed so that the dose limits are 

not exceeded. 

The Completion Time of 4 hours allows fixing of most SDC problems and 

is reasonable, based on the low probability of the coolant boiling in that 

time 

SURVEILLANCE SR 3.9.5.1

REQUIREMENTS 

This Surveillance demonstrates that one SDC loop is operating and 

circulating reactor coolant. The flow rate is determined by the flow rate 

necessary to provide sufficient decay heat removal capability and to 

prevent thermal and boron stratification in the core. In addition, this 

Surveillance demonstrates that the other SDC loop is OPERABLE. 

In addition, during operation of the SDC loop with the water level in the 

vicinity of the reactor vessel nozzles, the SDC loop flow rate 

determination must also consider the SDC pump suction requirements. 

The Frequency of 12 hours is sufficient, considering the flow, 

temperature, pump control, and alarm indications available to the 

operator to monitor the SDC System in the control room. 

Verification that the required loops are OPERABLE and in operation 

ensures that loops can be placed in operation as needed, to maintain 

decay heat and retain forced circulation. The Frequency of 12 hours is 

considered reasonable, since other administrative controls are available 

and have proven to be acceptable by operating experience. 

SR 3.9.5.2

Verification that the required pump is OPERABLE ensures that an 

additional SDC pump can be placed in operation, if needed, to maintain 

decay heat removal and reactor coolant circulation. Verification is 

performed by verifying proper breaker alignment and power available to 

the required pump. 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. 

REFERENCES 1. FSAR, Section [ ]. 
Refueling Water Level 

B 3.9.6 

CEOG STS B 3.9.6-1 Rev. 3.0, 03/31/04 

B 3.9 REFUELING OPERATIONS 

B 3.9.6 Refueling Water Level 

BASES 

BACKGROUND The movement of irradiated fuel assemblies within containment requires a 

minimum water level of 23 ft above the top of the reactor vessel flange. 

During refueling this maintains sufficient water level in the containment, 

the refueling canal, the fuel transfer canal, the refueling cavity, and the 

spent fuel pool. Sufficient water is necessary to retain iodine fission 

product activity in the water in the event of a fuel handling accident 

(Refs. 1 and 2). Sufficient iodine activity would be retained to limit offsite 

doses from the accident to < 25% of 10 CFR 100 limits, as provided by 

the guidance of Reference 3. 

APPLICABLE During movement of irradiated fuel assemblies, the water level in the 

SAFETY refueling canal and refueling cavity is an initial condition design 

ANALYSES parameter in the analysis of the fuel handling accident in containment 

postulated by Regulatory Guide 1.25 (Ref. 1). A minimum water level of 

23 ft (Regulatory Position C.1.c of Ref. 1) allows a decontamination factor 

of 100 (Regulatory Position C.1.g of Ref. 1) to be used in the accident 

analysis for iodine. This relates to the assumption that 99% of the total 

iodine released from the pellet to cladding gap of all the dropped fuel 

assembly rods is retained by the refueling cavity water. The fuel pellet to 

cladding gap is assumed to contain 10% of the total fuel rod iodine 

inventory (Ref. 1). 

The fuel handling accident analysis inside containment is described in 

Reference 2. With a minimum water level of 23 ft and a minimum decay 

time of [X] hours prior to fuel handling, the analysis and test programs 

demonstrate that the iodine release due to a postulated fuel handling 

accident is adequately captured by the water and offsite doses are 

maintained within allowable limits (Ref. 4). 

Refueling water level satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii). 

LCO A minimum refueling water level of 23 ft above the reactor vessel flange is 

required to ensure that the radiological consequences of a postulated fuel 

handling accident inside containment are within acceptable limits as 

provided by the guidance of Reference 3. 
Refueling Water Level 

B 3.9.6 

CEOG STS B 3.9.6-2 Rev. 3.0, 03/31/04 

BASES 

APPLICABILITY LCO 3.9.6 is applicable when moving fuel assemblies in the presence of 

irradiated fuel assemblies. The LCO minimizes the possibility of a fuel 

handling accident in containment that is beyond the assumptions of the 

safety analysis. If irradiated fuel is not present in containment, there can 

be no significant radioactivity release as a result of a postulated fuel 

handling accident. Requirements for fuel handling accidents in the spent 

fuel pool are covered by LCO 3.7.10, "Fuel Storage Pool Water Level." 

ACTIONS A.1

With a water level of < 23 ft above the top of the reactor vessel flange, all 

operations involving movement of irradiated fuel assemblies shall be 

suspended immediately to ensure that a fuel handling accident cannot 

occur. 

The suspension of fuel movement shall not preclude completion of 

movement of a component to a safe position. 

SURVEILLANCE SR 3.9.6.1

REQUIREMENTS 

Verification of a minimum water level of 23 ft above the top of the reactor 

vessel flange ensures that the design basis for the postulated fuel 

handling accident analysis during refueling operations is met. Water at 

the required level above the top of the reactor vessel flange limits the 

consequences of damaged fuel rods that are postulated to result from a 

fuel handling accident inside containment (Ref. 2). 

The Frequency of 24 hours 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. 

REFERENCES 1. Regulatory Guide 1.25, March 23, 1972. 

 2. FSAR, Section [ ]. 

 3. NUREG-0800, Section 15.7.4. 

 4. 10 CFR 100.10.