NUREG-1434 Volume 2, Rev. 5, Standard Technical Specifications, General Electric BWR/6 Plants: Bases: Difference between revisions

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{{#Wiki_filter:NUREG-1434 Volume 2 Revision 5.0 Standard Technical Specifications General Electric BWR/6 Plants Revision 5.0 Volume 2, Bases Office of Nuclear Reactor Regulation
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AVAILABILITY OF REFERENCE MATERIALS IN NRC PUBLICATIONS NRC Reference Material                                      Non-NRC Reference Material As of November 1999, you may electronically access          Documents available from public and special technical NUREG-series publications and other NRC records at the      libraries include all open literature items, such as books, NRCs Library at www.nrc.gov/reading-rm.html. Publicly      journal articles, transactions, Federal Register notices, released records include, to name a few, NUREG-series        Federal and State legislation, and congressional reports.
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NUREG-1434 Volume 2 Revision 5.0 Standard Technical Specifications General Electric BWR/6 Plants Revision 5.0 Volume 2, Bases Manuscript Completed: March 2021 Date Published: September 2021 Office of Nuclear Reactor Regulation
 
ABSTRACT This NUREG contains the improved Standard Technical Specifications (STS) for Babcock and Wilcox (B&W) plants. The changes reflected in Revision 5 result from the experience gained from plant operation using the improved STS and extensive public technical meetings and discussions among the Nuclear Regulatory Commission (NRC) staff and various nuclear power plant licensees and the Nuclear Steam Supply System (NSSS) Owners Groups.
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 5 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.
Users may access the STS NUREGs in the PDF format at https://www.nrc.gov/reading-rm/doc-collections/nuregs/staff/. Users may print or download copies from the NRC Web site.
PAPERWORK REDUCTION ACT STATEMENT This NUREG contains voluntary guidance for implementing the mandatory information collections covered by 10 CFR Part 50 that are subject to the Paperwork Reduction Act of 1995 (44 U.S.C. 3501 et. seq.). These information collections were approved by the Office of Management and Budget (OMB), under control number 3150-0011. Send comments regarding this information collection to the FOIA, Library, and Information Collections Branch (T6-A10M),
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PUBLIC PROTECTION NOTIFICATION The NRC may not conduct or sponsor, and a person is not required to respond to, a collection of information unless the document requesting or requiring the collection displays a currently valid OMB control number.
General Electric BWR/6 STS                    iii                                        Rev. 5.0
 
TABLE OF CONTENTS                                                                                                      Page ABSTRACT ...................................................................................................... iii B 2.0 SAFETY LIMITS (SLs) .................................................................................... B 2.1.1-1 B 2.1.1  Reactor Core SLs ....................................................................................... B 2.1.1-1 B 2.1.2  Reactor Coolant System (RCS) Pressure SL ............................................. B 2.1.2-1 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY ................ B 3.0-1 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY ............................... B 3.0-17 B 3.1 REACTIVITY CONTROL SYSTEMS .............................................................. B 3.1.1-1 B 3.1.1  SHUTDOWN MARGIN (SDM) ................................................................... B 3.1.1-1 B 3.1.2  Reactivity Anomalies .................................................................................. B 3.1.2-1 B 3.1.3  Control Rod OPERABILITY........................................................................ B 3.1.3-1 B 3.1.4  Control Rod Scram Times .......................................................................... B 3.1.4-1 B 3.1.5  Control Rod Scram Accumulators .............................................................. B 3.1.5-1 B 3.1.6  Rod Pattern Control.................................................................................... B 3.1.6-1 B 3.1.7  Standby Liquid Control (SLC) System ........................................................ B 3.1.7-1 B 3.1.8  Scram Discharge Volume (SDV) Vent and Drain Valves ........................... B 3.1.8-1 B 3.2 POWER DISTRIBUTION LIMITS .................................................................... B 3.2.1-1 B 3.2.1  AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) .................................................................................................. B 3.2.1-1 B 3.2.2  MINIMUM CRITICAL POWER RATIO (MCPR) ......................................... B 3.2.2-1 B 3.2.3  LINEAR HEAT GENERATION RATE (LHGR) (Optional) .......................... B 3.2.3-1 B 3.2.4  Average Power Range Monitor (APRM) Gain and Setpoints ..................... B 3.2.4-1 B 3.3 INSTRUMENTATION ...................................................................................... B 3.3.1.1-1 B 3.3.1.1 Reactor Protection System (RPS) Instrumentation .................................... B 3.3.1.1-1 B 3.3.1.2 Source Range Monitor (SRM) Instrumentation .......................................... B 3.3.1.2-1 B 3.3.2.1 Control Rod Block Instrumentation ............................................................. B 3.3.2.1-1 B 3.3.3.1 Post Accident Monitoring (PAM) Instrumentation ....................................... B 3.3.3.1-1 B 3.3.3.2 Remote Shutdown System ......................................................................... B 3.3.3.2-1 B 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT)
Instrumentation........................................................................................... B 3.3.4.1-1 B 3.3.4.2 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation ............................................................. B 3.3.4.2-1 B 3.3.5.1 Emergency Core Cooling System (ECCS) Instrumentation ....................... B 3.3.5.1-1 B 3.3.5.2 Reactor Pressure Vessel (RPV) Water Inventory Control Instrumentation........................................................................................... B 3.3.5.2-1 B 3.3.5.3 Reactor Core Isolation Cooling (RCIC) System Instrumentation........................................................................................... B 3.3.5.3-1 B 3.3.6.1 Primary Containment Isolation Instrumentation ......................................... B 3.3.6.1-1 B 3.3.6.2 Secondary Containment Isolation Instrumentation ..................................... B 3.3.6.2-1 B 3.3.6.3 Residual Heat Removal (RHR) Containment Spray System Instrumentation........................................................................................... B 3.3.6.3-1 B 3.3.6.4 Suppression Pool Makeup (SPMU) System Instrumentation ..................... B 3.3.6.4-1 B 3.3.6.5 Relief and Low-Low Set (LLS) Instrumentation .......................................... B 3.3.6.5-1 B 3.3.7.1 [Control Room Fresh Air (CRFA)] System Instrumentation ........................ B 3.3.7.1-1 B 3.3.8.1 Loss of Power (LOP) Instrumentation ........................................................ B 3.3.8.1-1 B 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring .................... B 3.3.8.2-1 General Electric BWR/6 STS                            v                                                                    Rev. 5.0
 
TABLE OF CONTENTS                                                                                                        Page B 3.4 REACTOR COOLANT SYSTEM (RCS) .......................................................... B 3.4.1-1 B 3.4.1    Recirculation Loops Operating ................................................................... B 3.4.1-1 B 3.4.2    Flow Control Valves (FCVs) ....................................................................... B 3.4.2-1 B 3.4.3    Jet Pumps .................................................................................................. B 3.4.3-1 B 3.4.4    Safety/Relief Valves (S/RVs) ...................................................................... B 3.4.4-1 B 3.4.5    RCS Operational LEAKAGE ...................................................................... B 3.4.5-1 B 3.4.6    RCS Pressure Isolation Valve (PIV) Leakage ............................................ B 3.4.6-1 B 3.4.7    RCS Leakage Detection Instrumentation ................................................... B 3.4.7-1 B 3.4.8    RCS Specific Activity .................................................................................. B 3.4.8-1 B 3.4.9    Residual Heat Removal (RHR) Shutdown Cooling System
            - Hot Shutdown ......................................................................................... B 3.4.9-1 B 3.4.10 Residual Heat Removal (RHR) Shutdown Cooling System
            - Cold Shutdown ....................................................................................... B 3.4.10-1 B 3.4.11 RCS Pressure and Temperature (P/T) Limits ............................................ B 3.4.11-1 B 3.4.12 Reactor Steam Dome Pressure ................................................................. B 3.4.12-1 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ............................................................................................. B 3.5.1-1 B 3.5.1    ECCS - Operating ...................................................................................... B 3.5.1-1 B 3.5.2    RPV Water Inventory Control ..................................................................... B 3.5.2-1 B 3.5.3    RCIC System.............................................................................................. B 3.5.3-1 B 3.6 CONTAINMENT SYSTEMS ............................................................................ B 3.6.1.1-1 B 3.6.1.1 Primary Containment.................................................................................. B 3.6.1.1-1 B 3.6.1.2 Primary Containment Air Locks .................................................................. B 3.6.1.2-1 B 3.6.1.3 Primary Containment Isolation Valves (PCIVs) .......................................... B 3.6.1.3-1 B 3.6.1.4 Primary Containment Pressure .................................................................. B 3.6.1.4-1 B 3.6.1.5 Primary Containment Air Temperature ....................................................... B 3.6.1.5-1 B 3.6.1.6 Low-Low Set (LLS) Valves ......................................................................... B 3.6.1.6-1 B 3.6.1.7 Residual Heat Removal (RHR) Containment Spray System ...................... B 3.6.1.7-1 B 3.6.1.8 Penetration Valve Leakage Control System (PVLCS) ............................... B 3.6.1.8-1 B 3.6.1.9 Main Steam Isolation Valve (MSIV) Leakage Control System (LCS) ............................................................................................. B 3.6.1.9-1 B 3.6.2.1 Suppression Pool Average Temperature ................................................... B 3.6.2.1-1 B 3.6.2.2 Suppression Pool Water Level ................................................................... B 3.6.2.2-1 B 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling ........................ B 3.6.2.3-1 B 3.6.2.4 Suppression Pool Makeup (SPMU) System ............................................... B 3.6.2.4-1 B 3.6.3.1 Primary Containment and Drywell Hydrogen Ignitors ................................ B 3.6.3.1-1 B 3.6.3.2 [Drywell Purge System] .............................................................................. B 3.6.3.2-1 B 3.6.4.1 [Secondary Containment] ........................................................................... B 3.6.4.1-1 B 3.6.4.2 Secondary Containment Isolation Valves (SCIVs) ..................................... B 3.6.4.2-1 B 3.6.4.3 Standby Gas Treatment (SGT) System ..................................................... B 3.6.4.3-1 B 3.6.5.1 Drywell........................................................................................................ B 3.6.5.1-1 B 3.6.5.2 Drywell Air Lock.......................................................................................... B 3.6.5.2-1 B 3.6.5.3 Drywell Isolation Valves ............................................................................. B 3.6.5.3-1 B 3.6.5.4 Drywell Pressure ........................................................................................ B 3.6.5.4-1 B 3.6.5.5 Drywell Air Temperature............................................................................. B 3.6.5.5-1 B 3.6.5.6 Drywell Vacuum Relief System .................................................................. B 3.6.5.6-1 General Electric BWR/6 STS                              vi                                                                  Rev. 5.0
 
TABLE OF CONTENTS                                                                                                    Page B 3.7 PLANT SYSTEMS .......................................................................................... B 3.7.1-1 B 3.7.1  [Standby Service Water (SSW)] System and [Ultimate Heat Sink (UHS)] ................................................................................................ B 3.7.1-1 B 3.7.2  High Pressure Core Spray (HPCS) Service Water System (SWS) ............ B 3.7.2-1 B 3.7.3  [Control Room Fresh Air (CRFA)] System ................................................. B 3.7.3-1 B 3.7.4  [Control Room Air Conditioning (AC)] System ........................................... B 3.7.4-1 B 3.7.5  Main Condenser Offgas ............................................................................. B 3.7.5-1 B 3.7.6  Main Turbine Bypass System ..................................................................... B 3.7.6-1 B 3.7.7  Fuel Pool Water Level ................................................................................ B 3.7.7-1 B 3.8 ELECTRICAL POWER SYSTEMS ................................................................. B 3.8.1-1 B 3.8.1  AC Sources - Operating ............................................................................. B 3.8.1-1 B 3.8.2  AC Sources - Shutdown ............................................................................. B 3.8.2-1 B 3.8.3  Diesel Fuel Oil, Lube Oil, and Starting Air ................................................. B 3.8.3-1 B 3.8.4  DC Sources - Operating ............................................................................. B 3.8.4-1 B 3.8.5  DC Sources - Shutdown ............................................................................. B 3.8.5-1 B 3.8.6  Battery Parameters .................................................................................... B 3.8.6-1 B 3.8.7  Inverters - Operating .................................................................................. B 3.8.7-1 B 3.8.8  Inverters - Shutdown .................................................................................. B 3.8.8-1 B 3.8.9  Distribution Systems - Operating................................................................ B 3.8.9-1 B 3.8.10 Distribution Systems - Shutdown ............................................................... B 3.8.10-1 B 3.9 REFUELING OPERATIONS ........................................................................... B 3.9.1-1 B 3.9.1  Refueling Equipment Interlocks.................................................................. B 3.9.1-1 B 3.9.2  Refuel Position One-Rod-Out Interlock ...................................................... B 3.9.2-1 B 3.9.3  Control Rod Position .................................................................................. B 3.9.3-1 B 3.9.4  Control Rod Position Indication .................................................................. B 3.9.4-1 B 3.9.5  Control Rod OPERABILITY - Refueling ..................................................... B 3.9.5-1 B 3.9.6  [RPV] Water Level [- Irradiated Fuel] ......................................................... B 3.9.6-1 B 3.9.7  [RPV] Water Level - New Fuel or Control Rods ......................................... B 3.9.7-1 B 3.9.8  Residual Heat Removal (RHR) - High Water Level .................................... B 3.9.8-1 B 3.9.9  Residual Heat Removal (RHR) - Low Water Level .................................... B 3.9.9-1 B 3.10 SPECIAL OPERATIONS ................................................................................ B 3.10.1-1 B 3.10.1 Inservice Leak and Hydrostatic Testing Operation ..................................... B 3.10.1-1 B 3.10.2 Reactor Mode Switch Interlock Testing ...................................................... B 3.10.2-1 B 3.10.3 Single Control Rod Withdrawal - Hot Shutdown ......................................... B 3.10.3-1 B 3.10.4 Single Control Rod Withdrawal - Cold Shutdown ....................................... B 3.10.4-1 B 3.10.5 Single Control Rod Drive (CRD) Removal - Refueling ............................... B 3.10.5-1 B 3.10.6 Multiple Control Rod Withdrawal - Refueling.............................................. B 3.10.6-1 B 3.10.7 Control Rod Testing - Operating ................................................................ B 3.10.7-1 B 3.10.8 SHUTDOWN MARGIN (SDM) Test - Refueling ......................................... B 3.10.8-1 B 3.10.9 Recirculation Loops - Testing ..................................................................... B 3.10.9-1 B 3.10.10 Training Startups ........................................................................................ B 3.10.10-1 General Electric BWR/6 STS                          vii                                                                  Rev. 5.0
 
Reactor Core SLs B 2.1.1 B 2.0 SAFETY LIMITS (SLs)
B 2.1.1 Reactor Core SLs 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).
The fuel cladding integrity SL is set such that no significant fuel damage is calculated to occur if the limit is not violated. Because fuel damage is not directly observable, a stepback approach is used to establish an SL, such that the MCPR is not less than the limit specified in Specification 2.1.1.2 for [both General Electric Company (GE) and Advanced Nuclear Fuel Corporation (ANF) fuel]. MCPR greater than the specified limit represents a conservative margin relative to the conditions required to maintain fuel cladding integrity.
The fuel cladding is one of the physical barriers that separate the radioactive materials from the environs. The integrity of this cladding barrier is related to its relative freedom from perforations or cracking.
Although some corrosion or use related cracking may occur during the life of the cladding, fission product migration from this source is incrementally cumulative and continuously measurable. Fuel cladding perforations, however, can result from thermal stresses, which occur from reactor operation significantly above design conditions.
                    ----------------------------------- REVIEWER'S NOTE ------------------------------
In the Background and Applicable Safety Analysis sections, select the SLMCPR95/95 discussion or the 99.9% of the fuel rods discussion as the applicable SL 2.1.1.2 basis.
While fission product migration from cladding perforation is just as measurable as that from use related cracking, the thermally caused cladding perforations signal a threshold beyond which still greater thermal stresses may cause gross, rather than incremental, cladding deterioration. Therefore, the fuel cladding SL is defined with a margin to the conditions that would produce onset of transition boiling (i.e.,
MCPR = 1.00). These conditions represent a significant departure from the condition intended by design for planned operation. [This is accomplished by having a Safety Limit Minimum Critical Power Ratio (SLMCPR) design basis, referred to as SLMCPR95/95, which corresponds to a 95% probability at a 95% confidence level (the 95/95 MCPR criterion) that transition boiling will not occur.] [The MCPR fuel cladding integrity SL ensures that during normal operation and during AOOs, at least 99.9% of the fuel rods in the core are not susceptible to boiling transiton.]
General Electric BWR/6 STS                  B 2.1.1-1                                                      Rev. 5.0
 
Reactor Core SLs B 2.1.1 BASES BACKGROUND (continued)
Operation above the boundary of the nucleate boiling regime could result in excessive cladding temperature because of the onset of transition boiling 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.
APPLICABLE          The fuel cladding must not sustain damage as a result of normal SAFETY              operation and AOOs. [The Tech Spec SL is set generically on a fuel ANALYSES            product MCPR correlation basis as the MCPR which corresponds to a 95% probability at a 95% confidence level that transition boiling will not occur, referred to as SLMCPR95/95.] [The reactor core SLs are established to preclude violation of the fuel design criterion that an MCPR limit is to be established, such that at least 99.9% of the fuel rods in the are not susceptible to boiling transition.]
The Reactor Protection System setpoints (LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation"), in combination with other LCOs, are designed to prevent any anticipated combination of transient conditions for Reactor Coolant System water level, pressure, and THERMAL POWER level that would result in reaching the MCPR limit.
2.1.1.1a Fuel Cladding Integrity [General Electric Company (GE) Fuel]
GE critical power correlations are applicable for all critical power calculations at pressures  785 psig and core flows  10% of rated flow.
For operation at low pressures or low flows, another basis is used, as follows:
Since the pressure drop in the bypass region is essentially all elevation head, the core pressure drop at low power and flows will always be > 4.5 psi. Analyses (Ref. 2) show that with a bundle flow of 28 x 103 lb/hr, bundle pressure drop is nearly independent of bundle power and has a value of 3.5 psi. Thus, the bundle flow with a 4.5 psi driving head will be > 28 x 103 lb/hr. Full scale ATLAS test data taken at pressures from 14.7 psia to 800 psia indicate that the fuel assembly critical power at this flow is approximately 3.35 MWt.
With the design peaking factors, this corresponds to a THERMAL POWER > 50% RTP. Thus, a THERMAL POWER limit of 25% RTP for reactor pressure < 785 psig is conservative.
General Electric BWR/6 STS              B 2.1.1-2                                        Rev. 5.0
 
Reactor Core SLs B 2.1.1 BASES APPLICABLE SAFETY ANALYSES (continued) 2.1.1.1b Fuel Cladding Integrity [Advanced Nuclear Fuel Corporation (ANF) Fuel]
The use of the XN-3 correlation is valid for critical power calculations at pressures > 580 psig and bundle mass fluxes > 0.25 x 106 lb/hr-ft2 (Ref. 3). For operation at low pressures or low flows, the fuel cladding integrity SL is established by a limiting condition on core THERMAL POWER, with the following basis:
Provided that the water level in the vessel downcomer is maintained above the top of the active fuel, natural circulation is sufficient to ensure a minimum bundle flow for all fuel assemblies that have a relatively high power and potentially can approach a critical heat flux condition. For the ANF 9x9 fuel design, the minimum bundle flow is > 30 x 103 lb/hr. For the ANF 8x8 fuel design, the minimum bundle flow is > 28 x 103 lb/hr. For all designs, the coolant minimum bundle flow and maximum flow area are such that the mass flux is always
                        > 0.25 x 106 lb/hr-ft2. Full scale critical power tests taken at pressures down to 14.7 psia indicate that the fuel assembly critical power at 0.25 x 106 lb/hr-ft2 is approximately 3.35 MWt. At 25% RTP, a bundle power of approximately 3.35 MWt corresponds to a bundle radial peaking factor of > 3.0, which is significantly higher than the expected peaking factor. Thus, a THERMAL POWER limit of 25% RTP for reactor pressures < 785 psig is conservative.
2.1.1.2a MCPR [GE and Westinghouse Fuel]
The fuel cladding integrity SL is set such that no significant fuel damage is calculated to occur if the limit is not violated. Since the parameters that result in fuel damage are not directly observable during reactor operation, the thermal and hydraulic conditions that result in the onset of transition boiling have been used to mark the beginning of the region in which fuel damage could occur. Although it is recognized that the onset of transition boiling would not result in damage to BWR fuel rods, the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit. [The Technical Specification SL value is dependent on the fuel product line and the corresponding MCPR correlation, which is cycle independent. The value is based on the Critical Power Ratio (CPR) data statistics and a 95% probability with 95% confidence that rods are not susceptible to boiling transition, referred to as MCPR95/95.]
General Electric BWR/6 STS            B 2.1.1-3                                          Rev. 5.0
 
Reactor Core SLs B 2.1.1 BASES APPLICABLE SAFETY ANALYSES (continued)
                    -------------------------------------- Reviewer's Note --------------------------------
The MCPR95/95 Values by Vendor and Fuel Product Type:
Vendor            Fuel Type          MCPR95/95 Global                GE14                1.06 Nuclear Fuel Global              GNF2                1.07 Nuclear Fuel Global              GNF3                1.07 Nuclear Fuel Westinghouse              Optima2              1.06
[The SL is based on [Fuel Type] fuel. For cores with a single fuel product line, the SLMCPR95/95 is the MCPR95/95 for the fuel type. For cores loaded with a mix of applicable fuel types, the SLMCPR95/95 is based on the largest (i.e., most limiting) of the MCPR values for the fuel product lines that are fresh or once-burnt at the start of the cycle.]
[However, the uncertainties in monitoring the core operating state and in the procedures used to calculate the critical power result in an uncertainty in the value of the critical power. Therefore, the fuel cladding integrity SL is defined as the critical power ratio in the limiting fuel assembly for which more than 99.9% of the fuel rods in the core are expected to avoid boiling transition, considering the power distribution within the core and all uncertainties.
The MCPR SL is determined using a statistical model that combines all the uncertainties in operating parameters and the procedures used to calculate critical power. The probability of the occurrence of boiling transition is determined using the approved General Electric Critical Power correlations. Details of the fuel cladding integrity SL calculation are given in Reference 2. Reference 2 also includes a tabulation of the uncertainties used in the determination of the MCPR SL and of the nominal values of the parameters used in the MCPR SL statistical analysis.]
General Electric BWR/6 STS                B 2.1.1-4                                                      Rev. 5.0
 
Reactor Core SLs B 2.1.1 BASES APPLICABLE SAFETY ANALYSES (continued) 2.1.1.2b MCPR [ANF Fuel]
The MCPR SL ensures sufficient conservatism in the operating MCPR limit that, in the event of an AOO from the limiting condition of operation, at least 99.9% of the fuel rods in the core would be expected to avoid boiling transition. The margin between calculated boiling transition (i.e.,
MCPR = 1.00) and the MCPR SL is based on a detailed statistical procedure that considers the uncertainties in monitoring the core operating state. One specific uncertainty included in the SL is the uncertainty inherent in the XN-3 critical power correlation. Reference 3 describes the methodology used in determining the MCPR SL.
The XN-3 critical power correlation is based on a significant body of practical test data, providing a high degree of assurance that the critical power, as evaluated by the correlation, is within a small percentage of the actual critical power being estimated. As long as the core pressure and flow are within the range of validity of the XN-3 correlation, the assumed reactor conditions used in defining the SL introduce conservatism into the limit because bounding high radial power factors and bounding flat local peaking distributions are used to estimate the number of rods in boiling transition. Still further conservatism is induced by the tendency of the XN-3 correlation to overpredict the number of rods in boiling transition.
These conservatisms and the inherent accuracy of the XN-3 correlation provide a reasonable degree of assurance that there would be no transition boiling in the core during sustained operation at the MCPR SL.
If boiling transition were to occur, there is reason to believe that the integrity of the fuel would not be compromised. Significant test data accumulated by the NRC and private organizations indicate that the use of a boiling transition limitation to protect against cladding failure is a very conservative approach. Much of the data indicate that BWR fuel can survive for an extended period of time in an environment of boiling transition.
2.1.1.3 Reactor Vessel Water Level During MODES 1 and 2, the reactor vessel water level is required to be above the top of the active fuel to provide core cooling capability. With fuel in the reactor vessel during periods when the reactor is shut down, consideration must be given to water level requirements due to the effect of decay heat. If the water level should drop below the top of the active irradiated fuel during this period, the ability to remove decay heat is reduced. This reduction in cooling capability could lead to elevated General Electric BWR/6 STS              B 2.1.1-5                                          Rev. 5.0
 
Reactor Core SLs B 2.1.1 BASES APPLICABLE SAFETY ANALYSES (continued) cladding temperatures and clad perforation in the event that the water level becomes < 2/3 of the core height. The reactor vessel water level SL has been established at the top of the active irradiated fuel to provide a point that can be monitored and to also provide adequate margin for effective action.
SAFETY LIMITS      The reactor core SLs are established to protect the integrity of the fuel clad barrier to the release of radioactive materials to the environs.
SL 2.1.1.1 and SL 2.1.1.2 ensure that the core operates within the fuel design criteria. SL 2.1.1.3 ensures that the reactor vessel water level is greater than the top of the active irradiated fuel in order to prevent elevated clad temperatures and resultant clad perforations.
APPLICABILITY      SLs 2.1.1.1, 2.1.1.2, and 2.1.1.3 are applicable in all MODES.
SAFETY LIMIT        Exceeding an SL may cause fuel damage and create a potential for VIOLATIONS          radioactive releases in excess of 10 CFR 100, "Reactor Site Criteria,"
limits (Ref. 4). Therefore, it is required to insert all insertable control rods and restore compliance with the SL within 2 hours. The 2 hour Completion Time ensures that the operators take prompt remedial action and the probability of an accident occurring during this period is minimal.
REFERENCES          1. 10 CFR 50, Appendix A, GDC 10.
: 2. NEDE-24011-P-A, (latest approved revision).
: 3. XN-NF524(A), Revision 1, November 1983.
: 4. 10 CFR 100.
General Electric BWR/6 STS            B 2.1.1-6                                          Rev. 5.0
 
RCS Pressure SL B 2.1.2 B 2.0 SAFETY LIMITS (SLs)
B 2.1.2 Reactor Coolant System (RCS) Pressure SL BASES BACKGROUND          The SL on reactor steam dome pressure protects 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. Establishing an upper limit on reactor steam dome pressure ensures continued RCS integrity. 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) shall be designed with sufficient margin to ensure that the design conditions are not exceeded during normal operation and anticipated operational occurrences (AOOs).
During normal operation and AOOs, RCS pressure is limited 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, in accordance with ASME Code requirements, prior to initial operation when there is no fuel in the core. Any further hydrostatic testing with fuel in the core may be done under LCO 3.10.1, "Inservice Leak and Hydrostatic Testing Operation." 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, reducing the number of protective barriers designed to prevent radioactive releases from exceeding the limits specified in 10 CFR 100, "Reactor Site Criteria" (Ref. 4). If this occurred in conjunction with a fuel cladding failure, the number of protective barriers designed to prevent radioactive releases from exceeding the limits would be reduced.
APPLICABLE          The RCS safety/relief valves and the Reactor Protection System Reactor SAFETY              Vessel Steam Dome Pressure - High Function have settings established ANALYSES            to ensure that the RCS pressure SL will not be exceeded.
The RCS pressure SL has been selected such that it is at a pressure below which it can be shown that the integrity of the system is not endangered. The reactor pressure vessel is designed to ASME, Boiler and Pressure Vessel Code, Section III, [1971 Edition], including Addenda through the [winter of 1972] (Ref. 5), which permits a maximum pressure transient of 110%, 1375 psig, of design pressure 1250 psig. The SL of General Electric BWR/6 STS            B 2.1.2-1                                          Rev. 5.0
 
RCS Pressure SL B 2.1.2 BASES APPLICABLE SAFETY ANALYSES (continued) 1325 psig, as measured in the reactor steam dome, is equivalent to 1375 psig at the lowest elevation of the RCS. The RCS is designed to ASME Code, Section III, 1974 Edition (Ref. 6), for the reactor recirculation piping, which permits a maximum pressure transient of 110% of design pressures of 1250 psig for suction piping and 1650 psig for discharge piping. The RCS pressure SL is selected to be the lowest transient overpressure allowed by the applicable codes.
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 is 110% of design pressures of 1250 psig for suction piping and 1500 psig for discharge piping. The most limiting of these allowances is the 110% of the suction piping design pressure; therefore, the SL on maximum allowable RCS pressure is established at 1325 psig as measured at the reactor steam dome.
APPLICABILITY      SL 2.1.2 applies in all MODES.
SAFETY LIMIT        Exceeding the RCS pressure SL may cause immediate RCS failure and VIOLATIONS          create a potential for radioactive releases in excess of 10 CFR 100, "Reactor Site Criteria," limits (Ref. 4). Therefore, it is required to insert all insertable control rods and restore compliance with the SL within 2 hours.
The 2 hour Completion Time ensures that the operators take prompt remedial action and also assures that the probability of an accident occurring during this period is minimal.
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 IW-5000
: 4. 10 CFR 100.
: 5. ASME, Boiler and Pressure Vessel Code, [1971 Edition], Addenda,
[winter of 1972].
: 6. ASME, Boiler and Pressure Vessel Code, [1974 Edition].
General Electric BWR/6 STS              B 2.1.2-2                                          Rev. 5.0
 
LCO Applicability B 3.0 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY BASES LCOs                LCO 3.0.1 through LCO 3.0.9 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, unless otherwise specified.
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.
General Electric BWR/6 STS              B 3.0-1                                          Rev. 5.0
 
LCO Applicability B 3.0 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 3.4.11, "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 ACTIONS for not meeting a single LCO adequately manage any increase in plant risk, provided any unusual external conditions (e.g., severe weather, offsite power instability) are considered. In addition, the increased risk associated with simultaneous removal of multiple structures, systems, trains or components from service is assessed and managed in accordance with 10 CFR 50.65(a)(4). 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:
: 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.
General Electric BWR/6 STS              B 3.0-2                                        Rev. 5.0
 
LCO Applicability B 3.0 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. Planned entry into LCO 3.0.3 should be avoided. If it is not practicable to avoid planned entry into LCO 3.0.3, plant risk should be assessed and managed in accordance with 10 CFR 50.65(a)(4), and the planned entry into LCO 3.0.3 should have less effect on plant safety than other practicable alternatives.
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 enter 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. The LCO is no longer applicable,
: c. A Condition exists for which the Required Actions have now been performed, or
: d. 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 4 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 entering the next lower MODE applies. If a lower MODE is entered in less time than allowed, however, the total allowable time to enter MODE 4, or other applicable MODE, is not reduced. For example, if General Electric BWR/6 STS              B 3.0-3                                          Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.3 (continued)
MODE 2 is entered in 2 hours, then the time allowed for entering MODE 3 is the next 11 hours, because the total time for entering MODE 3 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 enter a lower MODE of operation in less than the total time allowed.
In MODES 1, 2, and 3, 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 4 and 5 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, or 3) 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 3.7.7, "Fuel Pool Water Level." LCO 3.7.7 has an Applicability of "During movement of irradiated fuel assemblies in the associated fuel storage pool." Therefore, this LCO can be applicable in any or all MODES. If the LCO and the Required Actions of LCO 3.7.7 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 3.7.7 of "Suspend movement of irradiated fuel assemblies in the associated fuel storage pool(s)" 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.
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 either LCO 3.0.4.a, LCO 3.0.4.b, or LCO 3.0.4.c.
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 following entry into the MODE or other specified condition in the Applicability will permit continued operation within the MODE or other specified condition for an unlimited period of time. Compliance with 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 General Electric BWR/6 STS              B 3.0-4                                        Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.4 (continued) 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 and the Required Actions followed after entry into the Applicability.
For example, LCO 3.0.4.a may be used when the Required Action to be entered states that an inoperable instrument channel must be placed in the trip condition within the Completion Time. Transition into a MODE or other specified in condition in the Applicability may be made in accordance with LCO 3.0.4 and the channel is subsequently placed in the tripped condition within the Completion Time, which begins when the Applicability is entered. If the instrument channel cannot be placed in the tripped condition and the subsequent default ACTION ("Required Action and associated Completion Time not met") allows the OPERABLE train to be placed in operation, use of LCO 3.0.4.a is acceptable because the subsequent ACTIONS to be entered following entry into the MODE include ACTIONS (place the OPERABLE train in operation) that permit safe plant operation for an unlimited period of time in the MODE or other specified condition to be entered.
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 1.160, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." Regulatory Guide 1.160 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 General Electric BWR/6 STS              B 3.0-5                                        Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.4 (continued) 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 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., RCS Specific Activity), and may be applied to other Specifications based on NRC plant specific approval.
General Electric BWR/6 STS              B 3.0-6                                          Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.4 (continued)
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.
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, and MODE 3 to MODE 4.
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:
: 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 General Electric BWR/6 STS              B 3.0-7                                          Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.5 (continued) other preventive or corrective maintenance. LCO 3.0.5 should not be used in lieu of other practicable alternatives that comply with Required Actions and that do not require changing the MODE or other specified conditions in the Applicability in order to demonstrate equipment is OPERABLE. LCO 3.0.5 is not intended to be used repeatedly.
An example of demonstrating equipment is OPERABLE with the Required Actions not met is opening a manual valve that was closed to comply with Required Actions to isolate a flowpath with excessive Reactor Coolant System (RCS) Pressure Isolation Valve (PIV) leakage in order to perform testing to demonstrate that RCS PIV leakage is now within limit.
Examples of demonstrating equipment OPERABILITY include instances in which it is necessary to take an inoperable channel or trip system out of a tripped condition that was directed by a Required Action, if there is no Required Action Note for this purpose. An example of verifying OPERABILITY of equipment removed from service is taking a tripped channel out of the tripped condition to permit the logic to function and indicate the appropriate response during performance of required testing on the inoperable channel. Examples of demonstrating the OPERABILITY of other equipment are taking an inoperable channel or trip system out of the tripped condition 1) to prevent the trip function from occurring during the performance of required testing on another channel in the other trip system, or 2) 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.
The administrative controls in LCO 3.0.5 apply in all cases to systems or components in Chapter 3 of the Technical Specifications, as long as the testing could not be conducted while complying with the Required Actions. This includes the realignment or repositioning of redundant or alternate equipment or trains previously manipulated to comply with ACTIONS, as well as equipment removed from service or declared inoperable to comply with ACTIONS.
General Electric BWR/6 STS              B 3.0-8                                          Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.6          LCO 3.0.6 establishes an exception to LCO 3.0.2 for supported systems that have a support system 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 plant 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 plant 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 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 5.5.11, "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.
General Electric BWR/6 STS            B 3.0-9                                            Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.6 (continued)
The following examples use Figure B 3.0-1 to illustrate loss of safety function conditions that may result when a TS support system is inoperable. In this figure, the fifteen systems that comprise Train A are independent and redundant to the fifteen systems that comprise Train B.
To correctly use the figure to illustrate the SFDP provisions for a cross train check, the figure establishes a relationship between support and supported systems as follows: the figure shows System 1 as a support system for System 2 and System 3; System 2 as a support system for System 4 and System 5; and System 4 as a support system for System 8 and System 9. Specifically, a loss of safety function may exist when a support system is inoperable and:
: a. A system redundant to system(s) supported by the inoperable support system is also inoperable (EXAMPLE B 3.0.6-1),
: b. A 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 system redundant to support system(s) for the supported systems (a) and (b) above is also inoperable (EXAMPLE B 3.0.6-3).
For the following examples, refer to Figure B 3.0-1.
EXAMPLE B 3.0.6-1 If System 2 of Train A is inoperable and System 5 of TrainB is inoperable, a loss of safety function exists in Systems 5, 10, and 11.
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.
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 an 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.
General Electric BWR/6 STS              B 3.0-10                                        Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.6 (continued)
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 are 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).
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 General Electric BWR/6 STS              B 3.0-11                                            Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.6 (continued) address 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          There are certain special tests and operations required to be performed at various times over the life of the unit. These special tests and operations are necessary to demonstrate select unit performance characteristics, to perform special maintenance activities, and to perform special evolutions.
Special Operations LCOs in Section 3.10 allow specified TS requirements to be changed to permit performances of these special tests and operations, which otherwise could not be performed if required to comply with the requirements of these TS. Unless otherwise specified, all the other TS requirements remain unchanged. This will ensure all appropriate requirements of the MODE or other specified condition not directly associated with or required to be changed to perform the special test or operation will remain in effect.
The Applicability of a Special Operations LCO represents a condition not necessarily in compliance with the normal requirements of the TS.
Compliance with Special Operations LCOs is optional. A special operation may be performed either under the provisions of the appropriate Special Operations LCO or under the other applicable TS requirements. If it is desired to perform the special operation under the provisions of the Special Operations LCO, the requirements of the Special Operations LCO shall be followed. When a Special Operations LCO requires another LCO to be met, only the requirements of the LCO statement are required to be met regardless of that LCO's Applicability (i.e., should the requirements of this other LCO not be met, the ACTIONS of the Special Operations LCO apply, not the ACTIONS of the other LCO). However, there are instances where the Special Operations LCO ACTIONS may direct the other LCOs' ACTIONS be met. The Surveillances of the other LCO are not required to be met, unless specified in the Special Operations LCO. If conditions exist such that the Applicability of any other LCO is met, all the other LCO's requirements (ACTIONS and SRs) are required to be met concurrent with the requirements of the Special Operations LCO.
LCO 3.0.8          LCO 3.0.8 establishes conditions under which systems are considered to remain capable of performing their intended safety function when associated snubbers are not capable of providing their associated support function(s). This LCO states that the supported system is not considered to be inoperable solely due to one or more snubbers not capable of performing their associated support function(s). This is appropriate because a limited length of time is allowed for maintenance, testing, or General Electric BWR/6 STS              B 3.0-12                                      Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.8 (continued) repair of one or more snubbers not capable of performing their associated support function(s) and appropriate compensatory measures are specified in the snubber requirements, which are located outside of the Technical Specifications (TS) under licensee control. The snubber requirements do not meet the criteria in 10 CFR 50.36(c)(2)(ii), and, as such, are appropriate for control by the licensee.
If the allowed time expires and the snubber(s) are unable to perform their associated support function(s), the affected supported systems LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3.0.2.
LCO 3.0.8.a applies when one or more snubbers are not capable of providing their associated support function(s) to a single train or subsystem of a multiple train or subsystem supported system or to a single train or subsystem supported system. LCO 3.0.8.a allows 72 hours to restore the snubber(s) before declaring the supported system inoperable. The 72 hour Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function and due to the availability of the redundant train of the supported system.
LCO 3.0.8.b applies when one or more snubbers are not capable of providing their associated support function(s) to more than one train or subsystem of a multiple train or subsystem supported system.
LCO 3.0.8.b allows 12 hours to restore the snubber(s) before declaring the supported system inoperable. The 12 hour Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function.
LCO 3.0.8 requires that risk be assessed and managed. Industry and NRC guidance on the implementation of 10 CFR 50.65(a)(4) (the Maintenance Rule) does not address seismic risk. However, use of LCO 3.0.8 should be considered with respect to other plant maintenance activities, and integrated into the existing Maintenance Rule process to the extent possible so that maintenance on any unaffected train or subsystem is properly controlled, and emergent issues are properly addressed. The risk assessment need not be quantified, but may be a qualitative awareness of the vulnerability of systems and components when one or more snubbers are not able to perform their associated support function.
General Electric BWR/6 STS              B 3.0-13                                        Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.9          -----------------------------------REVIEWER'S NOTE-----------------------------------
Adoption of LCO 3.0.9 requires the licensee to make the following commitments:
: 1. [LICENSEE] commits to the guidance of NUMARC 93-01, Revision [4F], Section 11, which provides guidance and details on the assessment and management of risk during maintenance.
: 2. [LICENSEE] commits to the guidance of NEI 04-08, "Allowance for Non Technical Specification Barrier Degradation on Supported System OPERABILITY (TSTF-427) Industry Implementation Guidance," March 2006.
LCO 3.0.9 establishes conditions under which systems described in the Technical Specifications are considered to remain OPERABLE when required barriers are not capable of providing their related support function(s).
Barriers are doors, walls, floor plugs, curbs, hatches, installed structures or components, or other devices, not explicitly described in Technical Specifications, that support the performance of the safety function of systems described in the Technical Specifications. This LCO states that the supported system is not considered to be inoperable solely due to required barriers not capable of performing their related support function(s) under the described conditions. LCO 3.0.9 allows 30 days before declaring the supported system(s) inoperable and the LCO(s) associated with the supported system(s) not met. A maximum time is placed on each use of this allowance to ensure that as required barriers are found or are otherwise made unavailable, they are restored.
However, the allowable duration may be less than the specified maximum time based on the risk assessment.
If the allowed time expires and the barriers are unable to perform their related support function(s), the supported systems LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3.0.2.
This provision does not apply to barriers which support ventilation systems or to fire barriers. The Technical Specifications for ventilation systems provide specific Conditions for inoperable barriers. Fire barriers are addressed by other regulatory requirements and associated plant programs. This provision does not apply to barriers which are not required to support system OPERABILITY (see NRC Regulatory Issue Summary 2001-09, "Control of Hazard Barriers," dated April 2, 2001).
General Electric BWR/6 STS                  B 3.0-14                                                      Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.9 (continued)
The provisions of LCO 3.0.9 are justified because of the low risk associated with required barriers not being capable of performing their related support function. This provision is based on consideration of the following initiating event categories:
                    -----------------------------------REVIEWER'S NOTE-----------------------------------
LCO 3.0.9 may be expanded to other initiating event categories provided plant-specific analysis demonstrates that the frequency of the additional initiating events is bounded by the generic analysis or if plant-specific approval is obtained from the NRC.
* Loss of coolant accidents;
* High energy line breaks;
* Feedwater line breaks;
* Internal flooding;
* External flooding;
* Turbine missile ejection; and
* Tornado or high wind.
The risk impact of the barriers which cannot perform their related support function(s) must be addressed pursuant to the risk assessment and management provision of the Maintenance Rule, 10 CFR 50.65 (a)(4),
and the associated implementation guidance, Regulatory Guide 1.160, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."
Regulatory Guide 1.160 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." This guidance provides for the consideration of dynamic plant configuration issues, emergent conditions, and other aspects pertinent to plant operation with the barriers unable to perform their related support function(s). These considerations may result in risk management and other compensatory actions being required during the period that barriers are unable to perform their related support function(s).
LCO 3.0.9 may be applied to one or more trains or subsystems of a system supported by barriers that cannot provide their related support function(s), provided that risk is assessed and managed (including consideration of the effects on Large Early Release and from external events). If applied concurrently to more than one train or subsystem of a multiple train or subsystem supported system, the barriers supporting each of these trains or subsystems must provide their related support function(s) for different categories of initiating events. For example, LCO 3.0.9 may be applied for up to 30 days for more than one trains of a multiple trains supported system if the affected barrier for General Electric BWR/6 STS                  B 3.0-15                                                      Rev. 5.0
 
LCO Applicability B 3.0 BASES LCO 3.0.9 (continued) one train protects against internal flooding and the affected barrier for the other train protects against tornado missiles. In this example, the affected barrier may be the same physical barrier but serve different protection functions for each train.
[The [HPCI (High Pressure Coolant Injection) / HPCS (High Pressure Core Spray)] and RCIC (Reactor Core Isolation Cooling) systems are single train systems for injecting makeup water into the reactor during an accident or transient event. The RCIC System is not a safety system, nor required to operate during a transient, therefore, it does not have to meet the single failure criterion. The [HPCI / HPCS] System provides backup in case of a RCIC System failure. The ADS (Automatic Depressurization System) and low pressure ECCS coolant injection provide the core cooling function in the event of failure of the [HPCI / HPCS] System during an accident. Thus, for the purposes of LCO 3.0.9, the [HPCI /
HPCS] System, the RCIC System, and the ADS are considered independent subsystems of a single system and LCO 3.0.9 can be used on these single train systems in a manner similar to multiple train or subsystem systems.]
If during the time that LCO 3.0.9 is being used, the required OPERABLE train or subsystem becomes inoperable, it must be restored to OPERABLE status within 24 hours. Otherwise, the train(s) or subsystem(s) supported by barriers that cannot perform their related support function(s) must be declared inoperable and the associated LCOs declared not met. This 24 hour period provides time to respond to emergent conditions that would otherwise likely lead to entry into LCO 3.0.3 and a rapid plant shutdown, which is not justified given the low probability of an initiating event which would require the barrier(s) not capable of performing their related support function(s). During this 24 hour period, the plant risk associated with the existing conditions is assessed and managed in accordance with 10 CFR 50.65(a)(4).
General Electric BWR/6 STS              B 3.0-16                                        Rev. 5.0
 
SR Applicability B 3.0 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 3.0.2 and SR 3.0.3 apply in Chapter 5 when invoked by a Chapter 5 Specification.
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:
: 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 Operations LCO are only applicable when the Special Operations LCO 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.
General Electric BWR/6 STS              B 3.0-17                                        Rev. 5.0
 
SR Applicability B 3.0 BASES SR 3.0.1 (continued)
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.
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. Control Rod Drive maintenance during refueling that requires scram testing at > [800 psi]. However, if other appropriate testing is satisfactorily completed and the scram time testing of SR 3.1.4.3 is satisfied, the control rod can be considered OPERABLE. This allows startup to proceed to reach [800 psi] to perform other necessary testing.
: b. Reactor Core Isolation Cooling (RCIC) maintenance during shutdown that requires system functional tests at a specified pressure.
Provided other appropriate testing is satisfactorily completed, startup can proceed with RCIC 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).
General Electric BWR/6 STS                B 3.0-18                                          Rev. 5.0
 
SR Applicability B 3.0 BASES SR 3.0.2 (continued)
When a Section 5.5, "Programs and Manuals," specification states that the provisions of SR 3.0.2 are applicable, a 25% extension of the testing interval, whether stated in the specification or incorporated by reference, is permitted.
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. Examples of where SR 3.0.2 does not apply are the Primary Containment Leakage Rate Testing Program required by 10 CFR 50, Appendix J, and the inservice testing of pumps and valves in accordance with applicable American Society of Mechanical Engineers Operation and Maintenance Code, as required by 10 CFR 50.55a. These programs establish 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 directly or by reference.
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 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 performed 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 General Electric BWR/6 STS                B 3.0-19                                        Rev. 5.0
 
SR Applicability B 3.0 BASES SR 3.0.3 (continued) 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.
When a Section 5.5, "Programs and Manuals," specification states that the provisions of SR 3.0.3 are applicable, it permits the flexibility to defer declaring the testing requirement not met in accordance with SR 3.0.3 when the testing has not been completed within the testing interval (including the allowance of SR 3.0.2 if invoked by the Section 5.5 specification).
This delay period provides adequate time to perform Surveillances that have been missed. This delay period permits the performance of a Surveillance before complying with Required Actions or other remedial measures that might preclude performance of the Surveillance.
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.
SR 3.0.3 is only applicable if there is a reasonable expectation the associated equipment is OPERABLE or that variables are within limits, and it is expected that the Surveillance will be met when performed.
Many factors should be considered, such as the period of time since the Surveillance was last performed, or whether the Surveillance, or a portion thereof, has ever been performed, and any other indications, tests, or activities that might support the expectation that the Surveillance will be met when performed. An example of the use of SR 3.0.3 would be a General Electric BWR/6 STS              B 3.0-20                                            Rev. 5.0
 
SR Applicability B 3.0 BASES SR 3.0.3 (continued) relay contact that was not tested as required in accordance with a particular SR, but previous successful performances of the SR included the relay contact; the adjacent, physically connected relay contacts were tested during the SR performance; the subject relay contact has been tested by another SR; or historical operation of the subject relay contact has been successful. It is not sufficient to infer the behavior of the associated equipment from the performance of similar equipment. The rigor of determining whether there is a reasonable expectation a Surveillance will be met when performed should increase based on the length of time since the last performance of the Surveillance. If the Surveillance has been performed recently, a review of the Surveillance history and equipment performance may be sufficient to support a reasonable expectation that the Surveillance will be met when performed.
For Surveillances that have not been performed for a long period or that have never been performed, a rigorous evaluation based on objective evidence should provide a high degree of confidence that the equipment is OPERABLE. The evaluation should be documented in sufficient detail to allow a knowledgeable individual to understand the basis for the determination.
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 repeatedly 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 1.160, "Monitoring the Effectiveness of Maintenance 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 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 General Electric BWR/6 STS                B 3.0-21                                        Rev. 5.0
 
SR Applicability B 3.0 BASES SR 3.0.3 (continued) 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 licensees 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 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 General Electric BWR/6 STS              B 3.0-22                                          Rev. 5.0
 
SR Applicability B 3.0 BASES SR 3.0.4 (continued) 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, and MODE 3 to MODE 4.
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 LCOs 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.
General Electric BWR/6 STS                B 3.0-23                                        Rev. 5.0
 
SDM B 3.1.1 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.1 SHUTDOWN MARGIN (SDM)
BASES BACKGROUND          SDM requirements are specified to ensure:
: a. The reactor can be made subcritical from all operating conditions and transients and Design Basis Events,
: b. The reactivity transients associated with postulated accident conditions are controllable within acceptable limits, and
: c. The reactor will be maintained sufficiently subcritical to preclude inadvertent criticality in the shutdown condition.
These requirements are satisfied by the control rods, as described in GDC 26 (Ref. 1), which can compensate for the reactivity effects of the fuel and water temperature changes experienced during all operating conditions.
APPLICABLE          The control rod drop accident (CRDA) analysis (Refs. 2 and 3) assumes SAFETY              the core is subcritical with the highest worth control rod withdrawn.
ANALYSES            Typically, the first control rod withdrawn has a very high reactivity worth and, should the core be critical during the withdrawal of the first control rod, the consequences of a CRDA could exceed the fuel damage limits for a CRDA (see Bases for LCO 3.1.6, "Rod Pattern Control"). Also, SDM is assumed as an initial condition for the control rod removal error during a refueling accident (Ref. 4). The analysis of this reactivity insertion event assumes the refueling interlocks are OPERABLE when the reactor is in the refueling mode of operation. These interlocks prevent the withdrawal of more than one control rod from the core during refueling. (Special consideration and requirements for multiple control rod withdrawal during refueling are covered in Special Operations LCO 3.10.6, "Multiple Control Rod Withdrawal - Refueling.") The analysis assumes this condition is acceptable since the core will be shut down with the highest worth control rod withdrawn, if adequate SDM has been demonstrated.
Prevention or mitigation of reactivity insertion events is necessary to limit energy deposition in the fuel to prevent significant fuel damage, which could result in undue release of radioactivity. Adequate SDM ensures inadvertent criticalities and potential CRDAs involving high worth control rods (namely the first control rod withdrawn) will not cause significant fuel damage.
SDM satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS              B 3.1.1-1                                        Rev. 5.0
 
SDM B 3.1.1 BASES LCO                The specified SDM limit accounts for the uncertainty in the demonstration of SDM by testing. Separate SDM limits are provided for testing where the highest worth control rod is determined analytically or by measurement. This is due to the reduced uncertainty in the SDM test when the highest worth control rod is determined by measurement.
When SDM is demonstrated by calculations not associated with a test (e.g., to confirm SDM during the fuel loading sequence), additional margin is included to account for uncertainties in the calculation. To ensure adequate SDM during the design process, a design margin is included to account for uncertainties in the design calculations (Ref. 5).
APPLICABILITY      In MODES 1 and 2, SDM must be provided because subcriticality with the highest worth control rod withdrawn is assumed in the CRDA analysis (Ref. 3). In MODES 3 and 4, SDM is required to ensure the reactor will be held subcritical with margin for a single withdrawn control rod. SDM is required in MODE 5 to prevent an inadvertent criticality during the withdrawal of a single control rod from a core cell containing one or more fuel assemblies.
ACTIONS            A.1 With SDM not within the limits of the LCO in MODE 1 or 2, SDM must be restored within 6 hours. Failure to meet the specified SDM may be caused by a control rod that cannot be inserted. The 6 hour Completion Time is acceptable, considering that the reactor can still be shut down, assuming no additional failures of control rods to insert, and the low probability of an event occurring during this interval.
B.1 If the SDM cannot be restored, the plant must be brought to MODE 3 within 12 hours, to prevent the potential for further reductions in available SDM (e.g., additional stuck control rods). The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.
C.1 With SDM not within limits in MODE 3, the operator must immediately initiate action to fully insert all insertable control rods. Action must continue until all insertable control rods are fully inserted. This action results in the least reactive condition for the core.
General Electric BWR/6 STS              B 3.1.1-2                                        Rev. 5.0
 
SDM B 3.1.1 BASES ACTIONS (continued)
D.1, D.2, D.3, and D.4 With SDM not within limits in MODE 4, the operator must immediately initiate action to fully insert all insertable control rods. Action must continue until all insertable control rods are fully inserted. This action results in the least reactive condition for the core. Actions must also be initiated within 1 hour to provide means for control of potential radioactive releases. This includes ensuring secondary containment is OPERABLE; at least one Standby Gas Treatment (SGT) subsystem is OPERABLE; and [secondary containment] isolation capability (i.e., at least one secondary containment isolation valve and associated instrumentation are OPERABLE, or other acceptable administrative controls to assure isolation capability) in each associated penetration flow path not isolated that is assumed to be isolated to mitigate radioactivity releases. This may be performed as an administrative check, by examining logs or other information, to determine if the components are out of service for maintenance or other reasons. It is not necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the components. If, however, any required component is inoperable, then it must be restored to OPERABLE status. In this case, SRs may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE.
E.1, E.2, E.3, E.4, and E.5 With SDM not within limits in MODE 5, the operator must immediately suspend CORE ALTERATIONS that could reduce SDM, e.g., insertion of fuel in the core or the withdrawal of control rods. Suspension of these activities shall not preclude completion of movement of a component to a safe condition. Inserting control rods or removing fuel from the core will reduce the total reactivity and are therefore excluded from the suspended actions.
Action must also be immediately initiated to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies have been fully inserted. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and therefore do not have to be inserted.
General Electric BWR/6 STS              B 3.1.1-3                                        Rev. 5.0
 
SDM B 3.1.1 BASES ACTIONS (continued)
Action must also be initiated within 1 hour to provide means for control of potential radioactive releases. This includes ensuring secondary containment is OPERABLE; at least one SGT subsystem is OPERABLE; and [secondary containment] isolation capability (i.e., at least one secondary containment isolation valve and associated instrumentation are OPERABLE, or other acceptable administrative controls to assure isolation capability) in each associated penetration flow path not isolated that is assumed to be isolated to mitigate radioactivity releases. This may be performed as an administrative check, by examining logs or other information, to determine if the components are out of service for maintenance or other reasons. It is not necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the components. If, however, any required component is inoperable, then it must be restored to OPERABLE status. In this case, SRs may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE.
SURVEILLANCE        SR 3.1.1.1 REQUIREMENTS Adequate SDM must be demonstrated to ensure the reactor can be made subcritical from any initial operating condition. Adequate SDM is demonstrated by testing before or during the first startup after fuel movement, control rod replacement, or shuffling within the reactor pressure vessel. Control rod replacement refers to the decoupling and removal of a control rod from a core location, and subsequent replacement with a new control rod or a control rod from another core location. Since core reactivity will vary during the cycle as a function of fuel depletion and poison burnup, the beginning of cycle (BOC) test must also account for changes in core reactivity during the cycle. Therefore, to obtain the SDM, the initial measured value must be increased by an adder, "R", which is the difference between the calculated value of maximum core reactivity during the operating cycle and the calculated BOC core reactivity. If the value of R is negative (i.e., BOC is the most reactive point in the cycle), no correction to the BOC measured value is required (Ref. 6). For the SDM demonstrations that rely solely on calculation of the highest worth control rod, additional margin (0.10% k/k) must be added to the SDM limit as specified in the COLR to account for uncertainties in the calculation.
General Electric BWR/6 STS            B 3.1.1-4                                        Rev. 5.0
 
SDM B 3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The SDM may be demonstrated during an in sequence control rod withdrawal, in which the highest worth control rod is analytically determined, or during local criticals, where the highest worth control rod is determined by testing. Local critical tests require the withdrawal of out of sequence control rods. This testing would therefore require bypassing of the Rod Pattern Control System to allow the out of sequence withdrawal, and therefore additional requirements must be met (see LCO 3.10.7, "Control Rod Testing - Operating").
The Frequency of 4 hours after reaching criticality is allowed to provide a reasonable amount of time to perform the required calculations and appropriate verification.
During MODE 5, adequate SDM is also required to ensure the reactor does not reach criticality during control rod withdrawals. An evaluation of each in vessel fuel movement during fuel loading (including shuffling fuel within the core) is required to ensure adequate SDM is maintained during refueling. This evaluation ensures the intermediate loading patterns are bounded by the safety analyses for the final core loading pattern. For example, bounding analyses that demonstrate adequate SDM for the most reactive configurations during the refueling may be performed to demonstrate acceptability of the entire fuel movement sequence. These bounding analyses include additional margins to the associated uncertainties. Spiral offload or reload sequences inherently satisfy the SR, provided the fuel assemblies are reloaded in the same configuration analyzed for the new cycle. Removing fuel from the core will always result in an increase in SDM.
REFERENCES          1. 10 CFR 50, Appendix A, GDC 26.
: 2. FSAR, Section [15.4.9].
: 3. NEDO-21231, "Banked Position Withdrawal Sequence 111,"
Section 4.1, January 1977.
: 4. FSAR, Section [15.4.1.1].
: 5. FSAR, Section [4.3.2.4.1].
: 6. NDE-24011-P-A-9, "GE Standard Application for Reactor Fuel,"
Section 3.2.4.1, Sept. 1988.
General Electric BWR/6 STS            B 3.1.1-5                                        Rev. 5.0
 
Reactivity Anomalies B 3.1.2 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.2 Reactivity Anomalies BASES BACKGROUND          In accordance with 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. Reactivity anomaly is used as a measure of the predicted versus measured core reactivity during power operation. The continual confirmation of core reactivity is necessary to ensure that the Design Basis Accident (DBA) and transient safety analyses remain valid. A large reactivity anomaly could be the result of unanticipated changes in fuel reactivity, control rod 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.
In order to achieve the required fuel cycle energy output, the uranium enrichment in the new fuel loading and the fuel loaded in the previous cycles provide excess positive reactivity beyond that required to sustain steady state operation at the beginning of cycle (BOC). When the reactor is critical at RTP and operating moderator temperature, the excess positive reactivity is compensated by burnable absorbers (if any), control rods, and whatever neutron poisons (mainly xenon and samarium) are present in the fuel.
The predicted core reactivity, as represented by k effective (keff), is calculated by a 3D core simulator code as a function of cycle exposure.
This calculation is performed for projected operating states and conditions throughout the cycle. The monitored keff is calculated by the core monitoring system for actual plant conditions and is then compared to the predicted value for the cycle exposure.
General Electric BWR/6 STS              B 3.1.2-1                                          Rev. 5.0
 
Reactivity Anomalies B 3.1.2 BASES APPLICABLE          Accurate prediction of core reactivity is either an explicit or implicit SAFETY              assumption in the accident analysis evaluations (Ref. 2). In particular, ANALYSES            SDM and reactivity transients, such as control rod withdrawal accidents or rod drop 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 anomaly provides additional assurance that the nuclear methods provide an accurate representation of the core reactivity.
The comparison between measured and predicted initial core reactivity provides a normalization for the calculational models used to predict core reactivity. If the measured and predicted keff for identical core conditions at BOC do not reasonably agree, then the assumptions used in the reload cycle design analysis or the calculation models used to predict keff 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 value. Thereafter, any significant deviations in the measured keff from the predicted keff that develop during fuel depletion may be an indication that the assumptions of the DBA and transient analyses are no longer valid, or that an unexpected change in core conditions has occurred.
Reactivity anomalies satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO                The reactivity anomaly limit is established to ensure plant operation is maintained within the assumptions of the safety analyses. Large differences between monitored 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 difference between the monitored core keff and the predicted core keff 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.
APPLICABILITY      In MODE 1, most of the control rods are withdrawn and steady state operation is typically achieved. Under these conditions, the comparison between predicted and monitored core reactivity provides an effective measure of the reactivity anomaly. In MODE 2, control rods are typically being withdrawn during a startup. In MODES 3 and 4, all control rods are fully inserted, and, therefore, the reactor is in the least reactive state, where monitoring core reactivity is not necessary. In MODE 5, fuel loading results in a continually changing core reactivity. SDM General Electric BWR/6 STS              B 3.1.2-2                                          Rev. 5.0
 
Reactivity Anomalies B 3.1.2 BASES APPLICABILITY (continued) requirements (LCO 3.1.1) ensure that fuel movements are performed within the bounds of the safety analysis, and an SDM demonstration is required during the first startup following operations that could have altered core reactivity (e.g., fuel movement, control rod replacement, control rod shuffling). The SDM test, required by LCO 3.1.1, provides a direct comparison of the predicted and monitored core reactivity at cold conditions; therefore, reactivity anomaly is not required during these conditions.
ACTIONS            A.1 Should an anomaly develop between measured and predicted core reactivity, the core reactivity difference must be restored to within the limit to ensure continued operation is within the core design assumptions.
Restoration to within the limit could be performed by an evaluation of the core design and safety analysis to determine the reason for the anomaly.
This evaluation normally reviews the core conditions to determine their consistency with input to design calculations. Measured core and process parameters are also normally evaluated to determine that they are within the bounds of the safety analysis, and safety analysis calculational models may be reviewed to verify that they are adequate for representation of the core conditions. The required Completion Time of 72 hours is based on the low probability of a DBA 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.
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 12 hours. The allowed Completion Time of 12 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 3.1.2.1 REQUIREMENTS Verifying the reactivity difference between the monitored and predicted core keff is within the limits of the LCO provides further assurance that plant operation is maintained within the assumptions of the DBA and transient analyses. The Core Monitoring System calculates the core keff for the reactor conditions obtained from plant instrumentation. A General Electric BWR/6 STS              B 3.1.2-3                                        Rev. 5.0
 
Reactivity Anomalies B 3.1.2 BASES SURVEILLANCE REQUIREMENTS (continued) comparison of the monitored core keff to the predicted core keff at the same cycle exposure is used to calculate the reactivity difference. The comparison is required when the core reactivity has potentially changed by a significant amount. This may occur following a refueling in which new fuel assemblies are loaded, fuel assemblies are shuffled within the core, or control rods are replaced or shuffled. Control rod replacement refers to the decoupling and removal of a control rod from a core location, and subsequent replacement with a new control rod or a control rod from another core location. Also, core reactivity changes during the cycle.
The 24 hour interval after reaching equilibrium conditions following a startup is based on the need for equilibrium xenon concentrations in the core, such that an accurate comparison between the monitored and predicted core keff values can be made. For the purposes of this SR, the reactor is assumed to be at equilibrium conditions when steady state operations (no control rod movement or core flow changes) at  75% RTP have been obtained. The 1000 MWD/T Frequency was developed, considering the relatively slow change in core reactivity with exposure and operating experience related to variations in core reactivity. This comparison requires the core to be operating at power levels which minimize the uncertainties and measurement errors, in order to obtain meaningful results. Therefore, the comparison is only done when in MODE 1.
REFERENCES          1. 10 CFR 50, Appendix A, GDC 26, GDC 28, and GDC 29.
: 2. FSAR, Chapter [15].
General Electric BWR/6 STS            B 3.1.2-4                                        Rev. 5.0
 
Control Rod OPERABILITY B 3.1.3 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.3 Control Rod OPERABILITY BASES BACKGROUND          Control rods are components of the Control Rod Drive (CRD) System, which is the primary reactivity control system for the reactor. In conjunction with the Reactor Protection System, the CRD System provides the means for the reliable control of reactivity changes to ensure that under conditions of normal operation, including anticipated operational occurrences, specified acceptable fuel design limits are not exceeded. In addition, the control rods provide the capability to hold the reactor core subcritical under all conditions and to limit the potential amount and rate of reactivity increase caused by a malfunction in the CRD System. The CRD System is designed to satisfy the requirements of GDC 26, GDC 27, GDC 28, and GDC 29, (Ref. 1).
The CRD System consists of 193 locking piston control rod drive mechanisms (CRDMs) and a hydraulic control unit for each drive mechanism. The locking piston type CRDM is a double acting hydraulic piston, which uses condensate water as the operating fluid.
Accumulators provide additional energy for scram. An index tube and piston, coupled to the control rod, are locked at fixed increments by a collet mechanism. The collet fingers engage notches in the index tube to prevent unintentional withdrawal of the control rod, but without restricting insertion.
This Specification, along with LCO 3.1.4, "Control Rod Scram Times," and LCO 3.1.5, "Control Rod Scram Accumulators," ensure that the performance of the control rods in the event of a Design Basis Accident (DBA) or transient meets the assumptions used in the safety analyses of References 2, 3, 4, 5, and 6.
APPLICABLE          The analytical methods and assumptions used in the evaluations SAFETY              involving control rods are presented in References 2, 3, 4, 5, and 6. The ANALYSES            control rods provide the primary means for rapid reactivity control (reactor scram), for maintaining the reactor subcritical, and for limiting the potential effects of reactivity insertion events caused by malfunctions in the CRD System.
The capability of inserting the control rods provides assurance that the assumptions for scram reactivity in the DBA and transient analyses are not violated. Since the SDM ensures the reactor will be subcritical with the highest worth control rod withdrawn (assumed single failure), the additional failure of a second control rod to insert could invalidate the demonstrated SDM and potentially limit the ability of the CRD System to hold the reactor subcritical. If the control rod is stuck at an inserted position and becomes decoupled from the CRD, a control rod drop General Electric BWR/6 STS              B 3.1.3-1                                          Rev. 5.0
 
Control Rod OPERABILITY B 3.1.3 BASES APPLICABLE SAFETY ANALYSES (continued) accident (CRDA) can possibly occur. Therefore, the requirement that all control rods be OPERABLE ensures the CRD System can perform its intended function.
The control rods also protect the fuel from damage that could result in release of radioactivity. The limits protected are the MCPR Safety Limit (SL) (see Bases for SL 2.1.1, "Reactor Core SLs," and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), the 1% cladding plastic strain fuel design limit (see Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)" and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"), and the fuel damage limit (see Bases for LCO 3.1.6, "Rod Pattern Control") during reactivity insertion events.
The negative reactivity insertion (scram) provided by the CRD System provides the analytical basis for determination of plant thermal limits and provides protection against fuel damage limits during a CRDA. Bases for LCO 3.1.4, LCO 3.1.5, and LCO 3.1.6 discuss in more detail how the SLs are protected by the CRD System.
Control rod OPERABILITY satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                OPERABILITY of an individual control rod is based on a combination of factors, primarily the scram insertion times, the control rod coupling integrity, and the ability to determine the control rod position.
Accumulator OPERABILITY is addressed by LCO 3.1.5. The associated scram accumulator status for a control rod only affects the scram insertion times and therefore an inoperable accumulator does not immediately require declaring a control rod inoperable. Although not all control rods are required to be OPERABLE to satisfy the intended reactivity control requirements, strict control over the number and distribution of inoperable control rods is required to satisfy the assumptions of the DBA and transient analyses.
APPLICABILITY      In MODES 1 and 2, the control rods are assumed to function during a DBA or transient and are therefore required to be OPERABLE in these MODES. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate requirements for control rod OPERABILITY during these conditions. Control rod requirements in MODE 5 are located in LCO 3.9.5, "Control Rod OPERABILITY -
Refueling."
General Electric BWR/6 STS              B 3.1.3-2                                        Rev. 5.0
 
Control Rod OPERABILITY B 3.1.3 BASES ACTIONS            The ACTIONS Table is modified by a Note indicating that a separate Condition entry is allowed for each control rod. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable control rod. Complying with the Required Actions may allow for continued operation, and subsequent inoperable control rods are governed by subsequent Condition entry and application of associated Required Actions.
A.1, A.2, A.3, and A.4 A control rod is considered stuck if it will not insert by either CRD drive water or scram pressure. With a fully inserted control rod stuck, no actions are required as long as the control rod remains fully inserted. The Required Actions are modified by a Note that allows a stuck control rod to be bypassed in the Rod Action Control System (RACS) to allow continued operation. SR 3.3.2.1.9 provides additional requirements when control rods are bypassed in RACS to ensure compliance with the CRDA analysis. With one withdrawn control rod stuck, the local scram reactivity rate assumptions may not be met if the stuck control rod separation criteria are not met. Therefore, a verification that the separation criteria are met must be performed immediately. The separation criteria are not met if: a) the stuck control rod occupies a location adjacent to two "slow" control rods, b) the stuck control rod occupies a location adjacent to one "slow" control rod, and the one "slow" control rod is also adjacent to another "slow" control rod, or c) if the stuck control rod occupies a location adjacent to one "slow" control rod when there is another pair of "slow" control rods adjacent to one another. The description of "slow" control rods is provided in LCO 3.1.4, "Control Rod Scram Times." In addition, the associated control rod drive must be disarmed within 2 hours. The allowed Completion Time of 2 hours is acceptable, considering the reactor can still be shut down, assuming no additional control rods fail to insert, and provides a reasonable amount of time to perform the Required Action in an orderly manner. Isolating the control rod from scram prevents damage to the CRDM. The control rod can be isolated from scram by isolating the hydraulic control unit from scram and normal insert and withdraw pressure, yet still maintain cooling water to the CRD.
Monitoring of the insertion capability for each withdrawn control rod must also be performed within 24 hours from discovery of Condition A concurrent with THERMAL POWER greater than the low power setpoint (LPSP) of the rod pattern controller (RPC). SR 3.1.3.2 performs periodic tests of the control rod insertion capability of withdrawn control rods.
Testing each withdrawn control rod ensures that a generic problem does not exist. This Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." The Required Action A.2 Completion Time only begins upon discovery of Condition A General Electric BWR/6 STS              B 3.1.3-3                                        Rev. 5.0
 
Control Rod OPERABILITY B 3.1.3 BASES ACTIONS (continued) concurrent with THERMAL POWER greater than the actual LPSP of the RPC, since the notch insertions may not be compatible with the requirements of rod pattern control (LCO 3.1.6) and the RPC (LCO 3.3.2.1, "Control Rod Block Instrumentation"). The allowed Completion Time of 24 hours from discovery of Condition A, concurrent with THERMAL POWER greater than the LPSP of the RPC, provides a reasonable time to test the control rods, considering the potential for a need to reduce power to perform the tests.
To allow continued operation with a withdrawn control rod stuck, an evaluation of adequate SDM is also required within 72 hours. Should a DBA or transient require a shutdown, to preserve the single failure criterion an additional control rod would have to be assumed to have failed to insert when required. Therefore, the original SDM demonstration may not be valid. The SDM must therefore be evaluated (by measurement or analysis) with the stuck control rod at its stuck position and the highest worth OPERABLE control rod assumed to be fully withdrawn.
The allowed Completion Time of 72 hours to verify SDM is adequate, considering that with a single control rod stuck in a withdrawn position, the remaining OPERABLE control rods are capable of providing the required scram and shutdown reactivity. Failure to reach MODE 4 is only likely if an additional control rod adjacent to the stuck control rod also fails to insert during a required scram. Even with the postulated additional single failure of an adjacent control rod to insert, sufficient reactivity control remains to reach and maintain MODE 3 conditions (Ref. 7).
B.1 With two or more withdrawn control rods stuck, the plant must be brought to MODE 3 within 12 hours. The occurrence of more than one control rod stuck at a withdrawn position increases the probability that the reactor cannot be shut down if required. Insertion of all insertable control rods eliminates the possibility of an additional failure of a control rod to insert.
The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.
General Electric BWR/6 STS              B 3.1.3-4                                          Rev. 5.0
 
Control Rod OPERABILITY B 3.1.3 BASES ACTIONS (continued)
C.1 and C.2 With one or more control rods inoperable for reasons other than being stuck in the withdrawn position, operation may continue, provided the control rods are fully inserted within 3 hours and disarmed (electrically or hydraulically) within 4 hours. Inserting a control rod ensures the shutdown and scram capabilities are not adversely affected. The control rod is disarmed to prevent inadvertent withdrawal during subsequent operations. The control rods can be hydraulically disarmed by closing the drive water and exhaust water isolation valves. Electrically, the control rods can be disarmed by disconnecting power from all four directional control valve solenoids. Required Action C.1 is modified by a Note that allows control rods to be bypassed in the RACS if required to allow insertion of the inoperable control rods and continued operation.
SR 3.3.2.1.9 provides additional requirements when the control rods are bypassed to ensure compliance with the CRDA analysis.
The allowed Completion Times are reasonable, considering the small number of allowed inoperable control rods, and provide time to insert and disarm the control rods in an orderly manner and without challenging plant systems.
D.1 and D.2 Out of sequence control rods may increase the potential reactivity worth of a dropped control rod during a CRDA. At  10% RTP, the generic banked position withdrawal sequence (BPWS) analysis (Ref. 7) requires inserted control rods not in compliance with BPWS to be separated by at least two OPERABLE control rods in all directions, including the diagonal.
Therefore, if two or more inoperable control rods are not in compliance with BPWS and not separated by at least two OPERABLE control rods, action must be taken to restore compliance with BPWS or restore the control rods to OPERABLE status. A Note has been added to the Condition to clarify that the Condition is not applicable when > 10% RTP since the BPWS is not required to be followed under these conditions, as described in the Bases for LCO 3.1.6. The allowed Completion Time of 4 hours is acceptable, considering the low probability of a CRDA occurring.
General Electric BWR/6 STS            B 3.1.3-5                                        Rev. 5.0
 
Control Rod OPERABILITY B 3.1.3 BASES ACTIONS (continued)
E.1 In addition to the separation requirements for inoperable control rods, an assumption in the CRDA analysis for ANF fuel is that no more than three inoperable control rods are allowed in any one BPWS group. Therefore, with one or more BPWS groups having four or more inoperable control rods, the control rods must be restored to OPERABLE status. Required Action E.1 is modified by a Note indicating that the Condition is not applicable when THERMAL POWER is > 10% RTP since the BPWS is not required to be followed under these conditions, as described in the Bases for LCO 3.1.6. The allowed Completion Time of 4 hours is acceptable, considering the low probability of a CRDA occurring.
F.1 If any Required Action and associated Completion Time of Condition A, C, D, or E are not met or nine or more inoperable control rods exist, 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 12 hours.
This ensures all insertable control rods are inserted and places the reactor in a condition that does not require the active function (i.e., scram) of the control rods. The number of control rods permitted to be inoperable when operating above 10% RTP (i.e., no CRDA considerations) could be more than the value specified, but the occurrence of a large number of inoperable control rods could be indicative of a generic problem, and investigation and resolution of the potential problem should be undertaken. The allowed Completion Time of 12 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 3.1.3.1 REQUIREMENTS The position of each control rod must be determined, to ensure adequate information on control rod position is available to the operator for determining CRD OPERABILITY and controlling rod patterns. Control rod position may be determined by the use of OPERABLE position indicators, by moving control rods to a position with an OPERABLE indicator, or by the use of other appropriate methods. [ The 24 hour Frequency of this SR is based on operating experience related to expected changes in control rod position and the availability of control rod position indications in the control room.
OR General Electric BWR/6 STS            B 3.1.3-6                                          Rev. 5.0
 
Control Rod OPERABILITY B 3.1.3 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.1.3.2 Control rod insertion capability is demonstrated by inserting each partially or fully withdrawn control rod at least one notch and observing that the control rod moves. The control rod may then be returned to its original position. This ensures the control rod is not stuck and is free to insert on a scram signal. These Surveillances are not required when THERMAL POWER is less than or equal to the actual LPSP of the RPC since the notch insertions may not be compatible with the requirements of the Banked Position-Withdrawal Sequence (BPWS) (LCO 3.1.6) and the RPC (LCO 3.3.2.1). [ Withdrawn control rods are tested at a 31 day Frequency, based on the potential power reduction required to allow the control rod movement. Furthermore, the 31 day Frequency takes into account operating experience related to changes in CRD performance.
At any time, if a control rod is immovable, a determination of that control rod's trippability (OPERABILITY) must be made and appropriate action taken.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.1.3-7                                                      Rev. 5.0
 
Control Rod OPERABILITY B 3.1.3 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.1.3.3 Verifying the scram time for each control rod to notch position 13 is
[ ] seconds provides reasonable assurance that the control rod will insert when required during a DBA or transient, thereby completing its shutdown function. This SR is performed in conjunction with the control rod scram time testing of SR 3.1.4.1, SR 3.1.4.2, SR 3.1.4.3, and SR 3.1.4.4. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," and the functional testing of SDV vent and drain valves in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain Valves," overlap this Surveillance to provide complete testing of the assumed safety function. The associated Frequencies are acceptable, considering the more frequent testing performed to demonstrate other aspects of control rod OPERABILITY and operating experience, which shows scram times do not significantly change over an operating cycle.
SR 3.1.3.4 Coupling verification is performed to ensure the control rod is connected to the CRDM and will perform its intended function when necessary. The Surveillance requires verifying that a control rod does not go to the withdrawn overtravel position when it is fully withdrawn. The overtravel position feature provides a positive check on the coupling integrity, since only an uncoupled CRD can reach the overtravel position. The verification is required to be performed anytime a control rod is withdrawn to the "full out" position (notch position 48) or prior to declaring the control rod OPERABLE after work on the control rod or CRD System that could affect coupling. This includes control rods inserted one notch and then returned to the "full out" position during the performance of SR 3.1.3.2.
This Frequency is acceptable, considering the low probability that a control rod will become uncoupled when it is not being moved and operating experience related to uncoupling events.
REFERENCES          1. 10 CFR 50, Appendix A, GDC 26, GDC 27, GDC 28, and GDC 29.
: 2. FSAR, Section [4.3.2.5.5].
: 3. FSAR, Section [4.6.1.1.2.5.3].
: 4. FSAR, Section [5.2.2.2.3].
: 5. FSAR, Section [15.4.1].
General Electric BWR/6 STS              B 3.1.3-8                                          Rev. 5.0
 
Control Rod OPERABILITY B 3.1.3 BASES REFERENCES (continued)
: 6. FSAR, Section [15.4.9].
: 7. NEDO-21231, "Banked Position Withdrawal Sequence," Section 7.2, January 1977.
General Electric BWR/6 STS          B 3.1.3-9                                  Rev. 5.0
 
Control Rod Scram Times B 3.1.4 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.4 Control Rod Scram Times BASES BACKGROUND          The scram function of the Control Rod Drive (CRD) System controls reactivity changes during abnormal operational transients to ensure that specified acceptable fuel design limits are not exceeded (Ref. 1). The control rods are scrammed by positive means, using hydraulic pressure exerted on the CRD piston.
When a scram signal is initiated, control air is vented from the scram valves, allowing them to open by spring action. Opening the exhaust valves reduces the pressure above the main drive piston to atmospheric pressure, and opening the inlet valve applies the accumulator or reactor pressure to the bottom of the piston. Since the notches in the index tube are tapered on the lower edge, the collet fingers are forced open by cam action, allowing the index tube to move upward without restriction because of the high differential pressure across the piston. As the drive moves upward and accumulator pressure drops below the reactor pressure, a ball check valve opens, letting the reactor pressure complete the scram action. If the reactor pressure is low, such as during startup, the accumulator will fully insert the control rod within the required time without assistance from reactor pressure.
APPLICABLE          The analytical methods and assumptions used in evaluating the control SAFETY              rod scram function are presented in References 2, 3, 4, and 5. The ANALYSES            Design Basis Accident (DBA) and transient analyses assume that all of the control rods scram at a specified insertion rate. The resulting negative scram reactivity forms the basis for the determination of plant thermal limits (e.g., the MCPR). Other distributions of scram times (e.g.,
several control rods scramming slower than the average time, with several control rods scramming faster than the average time) can also provide sufficient scram reactivity. Surveillance of each individual control rod's scram time ensures the scram reactivity assumed in the DBA and transient analyses can be met.
The scram function of the CRD System protects the MCPR Safety Limit (SL) (see Bases for SL 2.1.1, "Reactor Core SLs," and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), and the 1% cladding plastic strain fuel design limit (see Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"), which ensure that no fuel damage will occur if these limits are not exceeded. Above 950 psig, the scram function is designed to insert negative reactivity at a rate fast enough to prevent the actual MCPR from becoming less than the MCPR SL during the analyzed limiting power transient. Below 950 psig, General Electric BWR/6 STS              B 3.1.4-1                                        Rev. 5.0
 
Control Rod Scram Times B 3.1.4 BASES APPLICABLE SAFETY ANALYSES (continued) the scram function is assumed to perform during the control rod drop accident (Ref. 6) and, therefore, also provides protection against violating fuel damage limits during reactivity insertion accidents (see Bases for LCO 3.1.6, "Rod Pattern Control"). For the reactor vessel overpressure protection analysis, the scram function, along with the safety/relief valves, ensure that the peak vessel pressure is maintained within the applicable ASME Code limits.
Control rod scram times satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                The scram times specified in Table 3.1.4-1 (in the accompanying LCO) are required to ensure that the scram reactivity assumed in the DBA and transient analysis is met. To account for single failure and "slow" scramming control rods, the scram times specified in Table 3.1.4-1 are faster than those assumed in the design basis analysis. The scram times have a margin to allow up to 7.5% of the control rods (e.g., 193 x 7.5%
                    = 14) to have scram times that exceed the specified limits (i.e., "slow" control rods) assuming a single stuck control rod (as allowed by LCO 3.1.3, "Control Rod OPERABILITY") and an additional control rod failing to scram per the single failure criterion. The scram times are specified as a function of reactor steam dome pressure to account for the pressure dependence of the scram times. The scram times are specified relative to measurements based on reed switch positions, which provide the control rod position indication. The reed switch closes ("pickup")
when the index tube passes a specific location and then opens
("dropout") as the index tube travels upward. Verification of the specified scram times in Table 3.1.4-1 is accomplished through measurement of the "dropout" times.
To ensure that local scram reactivity rates are maintained within acceptable limits, no more than two of the allowed "slow" control rods may occupy adjacent locations.
Table 3.1.4-1 is modified by two Notes, which state control rods with scram times not within the limits of the Table are considered "slow" and that control rods with scram times > [ ] seconds are considered inoperable as required by SR 3.1.3.3.
This LCO applies only to OPERABLE control rods since inoperable control rods will be inserted and disarmed (LCO 3.1.3). Slow scramming control rods may be conservatively declared inoperable and not accounted for as "slow" control rods.
General Electric BWR/6 STS            B 3.1.4-2                                        Rev. 5.0
 
Control Rod Scram Times B 3.1.4 BASES APPLICABILITY      In MODES 1 and 2, a scram is assumed to function during transients and accidents analyzed for these plant conditions. These events are assumed to occur during startup and power operation; therefore, the scram function of the control rods is required during these MODES. In MODES 3 and 4, the control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied.
This provides adequate requirements for control rod scram capability during these conditions. Scram requirements in MODE 5 are contained in LCO 3.9.5, "Control Rod OPERABILITY - Refueling."
ACTIONS            A.1 When the requirements of this LCO are not met, the rate of negative reactivity insertion during a scram may not be within the assumptions of the safety analyses. Therefore, 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 12 hours. The allowed Completion Time of 12 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        The four SRs of this LCO are modified by a Note stating that during a REQUIREMENTS        single control rod scram time surveillance, the CRD pumps shall be isolated from the associated scram accumulator. With the CRD pump isolated (i.e., charging valve closed), the influence of the CRD pump head does not affect the single control rod scram times. During a full core scram, the CRD pump head would be seen by all control rods and would have a negligible effect on the scram insertion times.
SR 3.1.4.1 The scram reactivity used in DBA and transient analyses is based on assumed control rod scram time. Measurement of the scram times with reactor steam dome pressure  950 psig demonstrates acceptable scram times for the transients analyzed in References 3 and 4.
Scram insertion times increase with increasing reactor pressure because of the competing effects of reactor steam dome pressure and stored accumulator energy. Therefore, demonstration of adequate scram times at reactor steam dome pressure  950 psig ensures that the scram times will be within the specified limits at higher pressures. Limits are specified as a function of reactor pressure to account for the sensitivity of the scram insertion times with pressure and to allow a range of pressures over which scram time testing can be performed. To ensure scram time testing is performed within a reasonable time following a shutdown 120 days, control rods are required to be tested before exceeding General Electric BWR/6 STS              B 3.1.4-3                                        Rev. 5.0
 
Control Rod Scram Times B 3.1.4 BASES SURVEILLANCE REQUIREMENTS (continued) 40% RTP. This Frequency is acceptable, considering the additional surveillances performed for control rod OPERABILITY, the frequent verification of adequate accumulator pressure, and the required testing of control rods affected by fuel movement within the associated core cell and by work on control rods or the CRD System.
SR 3.1.4.2 Additional testing of a sample of control rods is required to verify the continued performance of the scram function during the cycle. A representative sample contains at least 10% of the control rods. The sample remains representative if no more than 7.5% of the control rods in the sample tested are determined to be "slow." If more than 7.5% of the sample is declared to be "slow" per the criteria in Table 3.1.4-1, additional control rods are tested until this 7.5% criterion (e.g., 7.5% of the entire sample size) is satisfied, or until the total number of "slow" control rods (throughout the core, from all Surveillances) exceeds the LCO limit. For planned testing, the control rods selected for the sample should be different for each test. Data from inadvertent scrams should be used whenever possible to avoid unnecessary testing at power, even if the control rods with data were previously tested in a sample. [ The [200] day Frequency is based on operating experience that has shown control rod scram times do not significantly change over an operating cycle. This Frequency is also reasonable, based on the additional Surveillances done on the CRDs at more frequent intervals in accordance with LCO 3.1.3 and LCO 3.1.5, "Control Rod Scram Accumulators."
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.1.4-4                                                      Rev. 5.0
 
Control Rod Scram Times B 3.1.4 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.1.4.3 When work that could affect the scram insertion time is performed on a control rod or the CRD System, testing must be done to demonstrate that each affected control rod retains adequate scram performance over the range of applicable reactor pressures from zero to the maximum permissible pressure. The scram testing must be performed once before declaring the control rod OPERABLE. The required scram time testing must demonstrate that the affected control rod is still within acceptable limits. The limits for reactor pressures < 950 psig are established based on a high probability of meeting the acceptance criteria at reactor pressures  950 psig. Limits for reactor pressures  950 psig are found in Table 3.1.4-1. If testing demonstrates the affected control rod does not meet these limits, but is within 7-second limit of Table 3.1.4-1, Note 2, the control rod can be declared OPERABLE and "slow."
Specific examples of work that could affect the scram times include (but are not limited to) the following: removal of any CRD for maintenance or modification; replacement of a control rod; and maintenance or modification of a scram solenoid pilot valve, scram valve, accumulator isolation valve, or check valves in the piping required for scram.
The Frequency of once prior to declaring the affected control rod OPERABLE is acceptable because of the capability of testing the control rod over a range of operating conditions and the more frequent surveillances on other aspects of control rod OPERABILITY.
SR 3.1.4.4 When work that could affect the scram insertion time is performed on a control rod or CRD System, or when fuel movement within the reactor pressure vessel occurs, testing must be done to demonstrate each affected control rod is still within the limits of Table 3.1.4-1 with the reactor steam dome pressure  950 psig. Where work has been performed at high reactor pressure, the requirements of SR 3.1.4.3 and SR 3.1.4.4 will be satisfied with one test. For a control rod affected by work performed while shut down, however, a zero pressure and a high pressure test may be required. This testing ensures that the control rod scram performance is acceptable for operating reactor pressure conditions prior to withdrawing the control rod for continued operation.
Alternatively, a test during hydrostatic pressure testing could also satisfy both criteria. When fuel movement within the reactor pressure vessel occurs, only those control rods associated with the core cells affected by the fuel movement are required to be scram time tested. During a routine refueling outage, it is expected that all control rods will be affected.
General Electric BWR/6 STS            B 3.1.4-5                                            Rev. 5.0
 
Control Rod Scram Times B 3.1.4 BASES SURVEILLANCE REQUIREMENTS (continued)
The Frequency of once prior to exceeding 40% RTP is acceptable because of the capability of testing the control rod at the different conditions and the more frequent surveillances on other aspects of control rod OPERABILITY.
REFERENCES          1. 10 CFR 50, Appendix A, GDC 10.
: 2. FSAR, Section [4.3.2.5.5].
: 3. FSAR, Section [4.6.1.1.2.5.3].
: 4. FSAR, Section [5.2.2.2.2.3].
: 5. FSAR, Section [15.4.1].
: 6. FSAR, Section [15.4.9].
General Electric BWR/6 STS          B 3.1.4-6                                            Rev. 5.0
 
Control Rod Scram Accumulators B 3.1.5 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.5 Control Rod Scram Accumulators BASES BACKGROUND          The control rod scram accumulators are part of the Control Rod Drive (CRD) System and are provided to ensure that the control rods scram under varying reactor conditions. The control rod scram accumulators store sufficient energy to fully insert a control rod at any reactor vessel pressure. The accumulator is a hydraulic cylinder with a free floating piston. The piston separates the water used to scram the control rods from the nitrogen, which provides the required energy. The scram accumulators are necessary to scram the control rods within the required insertion times of LCO 3.1.4, "Control Rod Scram Times."
APPLICABLE          The analytical methods and assumptions used in evaluating the control SAFETY              rod scram function are presented in References 1, 2, 3, and 4. The ANALYSES            Design Basis Accident (DBA) and transient analyses assume that all of the control rods scram at a specified insertion rate. OPERABILITY of each individual control rod scram accumulator, along with LCO 3.1.3, "Control Rod OPERABILITY," and LCO 3.1.4, ensures that the scram reactivity assumed in the DBA and transient analyses can be met. The existence of an inoperable accumulator may invalidate prior scram time measurements for the associated control rod.
The scram function of the CRD System, and, therefore, the OPERABILITY of the accumulators, protects the MCPR Safety Limit (see Bases for LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)")
and the 1% cladding plastic strain fuel design limit (see Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"), which ensure that no fuel damage will occur if these limits are not exceeded (see Bases for LCO 3.1.4). Also, the scram function at low reactor vessel pressure (i.e., startup conditions) provides protection against violating fuel design limits during reactivity insertion accidents (see Bases for LCO 3.1.6, "Rod Pattern Control").
Control rod scram accumulators satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                  The OPERABILITY of the control rod scram accumulators is required to ensure that adequate scram insertion capability exists when needed over the entire range of reactor pressures. The OPERABILITY of the scram accumulators is based on maintaining adequate accumulator pressure.
General Electric BWR/6 STS              B 3.1.5-1                                          Rev. 5.0
 
Control Rod Scram Accumulators B 3.1.5 BASES APPLICABILITY      In MODES 1 and 2, the scram function is required for mitigation of DBAs and transients and, therefore, the scram accumulators must be OPERABLE to support the scram function. In MODES 3 and 4, control rods are not allowed to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate requirements for control rod scram accumulator OPERABILITY under these conditions. Requirements for scram accumulators in MODE 5 are contained in LCO 3.9.5, "Control Rod OPERABILITY - Refueling."
ACTIONS            The ACTIONS table is modified by a Note indicating that a separate Condition entry is allowed for each control rod. This is acceptable since the Required Actions for each Condition provide appropriate compensatory action for each affected control rod. Complying with the Required Actions may allow for continued operation and subsequent affected control rods governed by subsequent Condition entry and application of associated Required Actions.
A.1 and A.2 With one control rod scram accumulator inoperable and the reactor steam dome pressure  900 psig, the control rod may be declared "slow," since the control rod will still scram at the reactor operating pressure but may not satisfy the required scram times in Table 3.1.4-1. Required Action A.1 is modified by a Note, which clarifies that declaring the control rod "slow" is only applicable if the associated control scram time was within the limits of Table 3.1.4-1 during the last scram time test.
Otherwise, the control rod would already be considered "slow" and the further degradation of scram performance with an inoperable accumulator could result in excessive scram times. In this event, the associated control rod is declared inoperable (Required Action A.2) and LCO 3.1.3 entered. This would result in requiring the affected control rod to be fully inserted and disarmed, thereby satisfying its intended function in accordance with ACTIONS of LCO 3.1.3.
The allowed Completion Time of 8 hours is considered reasonable, based on the large number of control rods available to provide the scram function and the ability of the affected control rod to scram only with reactor pressure at high reactor pressures.
B.1, B.2.1, and B.2.2 With two or more control rod scram accumulators inoperable and reactor steam dome pressure  900 psig, adequate pressure must be supplied to the charging water header. With inadequate charging water pressure, all of the accumulators could become inoperable, resulting in a potentially General Electric BWR/6 STS              B 3.1.5-2                                        Rev. 5.0
 
Control Rod Scram Accumulators B 3.1.5 BASES ACTIONS (continued) severe degradation of the scram performance. Therefore, within 20 minutes from discovery of charging water header pressure < 1520 psig concurrent with Condition B, adequate charging water header pressure must be restored. The allowed Completion Time of 20 minutes is considered a reasonable time to place a CRD pump into service to restore the charging header pressure, if required. This Completion Time also recognizes the ability of the reactor pressure alone to fully insert all control rods.
The control rod may be declared "slow," since the control rod will still scram using only reactor pressure, but may not satisfy the times in Table 3.1.4-1. Required Action B.2.1 is modified by a Note indicating that declaring the control rod "slow" is only applicable if the associated control scram time was within the limits of Table 3.1.4-1 during the last scram time test. Otherwise, the control rod would already be considered "slow" and the further degradation of scram performance with an inoperable accumulator could result in excessive scram times. In this event, the associated control rod is declared inoperable (Required Action B.2.2) and LCO 3.1.3 entered. This would result in requiring the affected control rod to be fully inserted and disarmed, thereby satisfying its intended function in accordance with ACTIONS of LCO 3.1.3.
The allowed Completion Time of 1 hour is considered reasonable, based on the ability of only the reactor pressure to scram the control rods and the low probability of a DBA or transient occurring while the affected accumulators are inoperable.
C.1 and C.2 With one or more control rod scram accumulators inoperable and the reactor steam dome pressure < 900 psig, the pressure supplied to the charging water header must be adequate to ensure that accumulators remain charged. With the reactor steam dome pressure < 900 psig, the function of the accumulators in providing the scram force becomes much more important since the scram function could become severely degraded during a depressurization event or at low reactor pressures.
Therefore, immediately upon discovery of charging water header pressure < [1520] psig, concurrent with Condition C, all control rods associated with inoperable accumulators must be verified to be fully inserted. Withdrawn control rods with inoperable scram accumulators may fail to scram under these low pressure conditions. The associated control rods must also be declared inoperable within 1 hour. The allowed Completion Time of 1 hour is reasonable for Required Action C.2, considering the low probability of a DBA or transient occurring during the time the accumulator is inoperable.
General Electric BWR/6 STS            B 3.1.5-3                                        Rev. 5.0
 
Control Rod Scram Accumulators B 3.1.5 BASES ACTIONS (continued)
D.1 The reactor mode switch must be immediately placed in the shutdown position if either Required Action and associated Completion Time associated with loss of the CRD charging pump (Required Actions B.1 and C.1) cannot be met. This ensures that all insertable control rods are inserted and that the reactor is in a condition that does not require the active function (i.e., scram) of the control rods. This Required Action is modified by a Note stating that the Required Action is not applicable if all control rods associated with the inoperable scram accumulators are fully inserted, since the function of the control rods has been performed.
SURVEILLANCE        SR 3.1.5.1 REQUIREMENTS SR 3.1.5.1 requires that the accumulator pressure be checked periodically to ensure adequate accumulator pressure exists to provide sufficient scram force. The primary indicator of accumulator OPERABILITY is the accumulator pressure. A minimum accumulator pressure is specified, below which the capability of the accumulator to perform its intended function becomes degraded and the accumulator is considered inoperable. The minimum accumulator pressure of 1520 psig is well below the expected pressure of 1750 psig to 2000 psig (Ref. 2).
Declaring the accumulator inoperable when the minimum pressure is not maintained ensures that significant degradation in scram times does not occur. [ The 7 day Frequency has been shown to be acceptable through operating experience and takes into account indications available in the control room.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.1.5-4                                                      Rev. 5.0
 
Control Rod Scram Accumulators B 3.1.5 BASES REFERENCES          1. FSAR, Section [4.3.2.5.5].
: 2. FSAR, Section [4.6.1.1.2.5.3].
: 3. FSAR, Section [5.2.2.2.2.3].
: 4. FSAR, Section [15.4.1].
General Electric BWR/6 STS          B 3.1.5-5                                Rev. 5.0
 
Rod Pattern Control B 3.1.6 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.6 Rod Pattern Control BASES BACKGROUND          Control rod patterns during startup conditions are controlled by the operator and the rod pattern controller (RPC) (LCO 3.3.2.1, "Control Rod Block Instrumentation"), so that only specified control rod sequences and relative positions are allowed over the operating range of all control rods inserted to [10]% RTP. The sequences effectively limit the potential amount of reactivity addition that could occur in the event of a control rod drop accident (CRDA).
This Specification assures that the control rod patterns are consistent with the assumptions of the CRDA analyses of References 1, 2, and 3.
APPLICABLE          The analytical methods and assumptions used in evaluating the CRDA SAFETY              are summarized in References 1, 2, and 3. CRDA analyses assume that ANALYSES            the reactor operator follows prescribed withdrawal sequences. These sequences define the potential initial conditions for the CRDA analysis.
The RPC (LCO 3.3.2.1) provides backup to operator control of the withdrawal sequences to ensure that the initial conditions of the CRDA analysis are not violated.
Prevention or mitigation of positive reactivity insertion events is necessary to limit the energy deposition in the fuel, thereby preventing significant fuel damage, which could result in undue release of radioactivity. Since the failure consequences for UO2 have been shown to be insignificant below fuel energy depositions of 300 cal/gm (Ref. 4), the fuel damage limit of 280 cal/gm provides a margin of safety from significant core damage, which would result in release of radioactivity (Refs. 5 and 6).
Generic evaluations (Refs. 1 and 7) of a design basis CRDA (i.e., a CRDA resulting in a peak fuel energy deposition of 280 cal/gm) have shown that if the peak fuel enthalpy remains below 280 cal/gm, then the maximum reactor pressure will be less than the required ASME Code limits (Ref. 8) and the calculated offsite doses will be well within the required limits (Ref. 6).
Control rod patterns analyzed in Reference 1 follow the banked position withdrawal sequence (BPWS) described in Reference 9. The BPWS is applicable from the condition of all control rods fully inserted to 10% RTP (Ref. 2). For the BPWS, the control rods are required to be moved in groups, with all control rods assigned to a specific group required to be within specified banked positions (e.g., between notches 08 and 12). The banked positions are defined to minimize the maximum incremental control rod worths without being overly restrictive during normal plant operation. The generic BPWS analysis (Ref. 9) also evaluated the effect General Electric BWR/6 STS              B 3.1.6-1                                          Rev. 5.0
 
Rod Pattern Control B 3.1.6 BASES APPLICABLE SAFETY ANALYSES (continued) of fully inserted, inoperable control rods not in compliance with the sequence, to allow a limited number (i.e., eight) and distribution of fully inserted, inoperable control rods.
                    -----------------------------------REVIEWER'S NOTE-----------------------------------
Adoption of the use of Reference 10 requires implementation of the following commitments:
: 1. Before reducing power to the low power setpoint (LPSP), operators shall confirm control rod coupling integrity for all rods that are fully withdrawn. Control rods that have not been confirmed coupled and are in intermediate positions must be fully inserted prior to power reduction to the LPSP. No action is required for fully-inserted control rods. If a shutdown is required and all rods, which are not confirmed coupled, cannot be fully inserted prior to the power dropping below the LPSP, then the original/standard BPWS must be used. The original/standard BPWS can be found in Licensing Topical Report NEDO-21231, "Banked Position Withdrawal Sequence," January 1977, and is referred to in NUREG-1433 and NUREG-1434.
: 2. After reactor power drops below the LPSP, rods may be inserted from notch position 48 to notch position 00 without stopping at the intermediate positions. However, GE Nuclear Energy recommends that operators insert rods in the same order as specified for the original/standard BPWS as much as is reasonably possible. If a plant is in the process of shutting down following improved BPWS with the power below the LPSP, no control rod shall be withdrawn unless the control rod pattern is in compliance with standard BPWS requirements.
When performing a shutdown of the plant, an optional BPWS control rod sequence (Ref. 10) may be used provided that all withdrawn control rods have been confirmed to be coupled. The rods may be inserted without the need to stop at intermediate positions since the possibility of a CRDA is eliminated by the confirmation that withdrawn control rods are coupled.
When using the Reference 10 control rod sequence for shutdown, the rod pattern controller may be reprogrammed to enforce the requirements of the improved BPWS control rod insertion process [or bypassed in accordance with the allowance provided in the Applicability Note for the rod pattern controller in Table 3.3.2.1-1.]
General Electric BWR/6 STS                B 3.1.6-2                                                      Rev. 5.0
 
Rod Pattern Control B 3.1.6 BASES APPLICABLE SAFETY ANALYSES (continued)
In order to use the Reference 10 BPWS shutdown process, an extra check is required in order to consider a control rod to be "confirmed" to be coupled. This extra check ensures that no Single Operator Error can result in an incorrect coupling check. For purposes of this shutdown process, the method for confirming that control rods are coupled varies depending on the position of the control rod in the core. Details on this coupling confirmation requirement are provided in Reference 10. If the requirements for use of the BPWS control rod insertion process contained in Reference 10 are followed, the plant is considered to be in compliance with BPWS requirements, as required by LCO 3.1.6.
Rod pattern control satisfies the requirements of Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                Compliance with the prescribed control rod sequences minimizes the potential consequences of a CRDA by limiting the initial conditions to those consistent with the BPWS. This LCO only applies to OPERABLE control rods. For inoperable control rods required to be inserted, separate requirements are specified in LCO 3.1.3, "Control Rod OPERABILITY," consistent with the allowances for inoperable control rods in the BPWS.
APPLICABILITY      In MODES 1 and 2, when THERMAL POWER is  10% RTP, the CRDA is a Design Basis Accident (DBA) and, therefore, compliance with the assumptions of the safety analysis is required. When THERMAL POWER is > 10% RTP, there is no credible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA (Ref. 2). In MODES 3, 4, and 5, since the reactor is shut down and only a single control rod can be withdrawn from a core cell containing fuel assemblies, adequate SDM ensures that the consequences of a CRDA are acceptable, since the reactor will remain subcritical with a single control rod withdrawn.
General Electric BWR/6 STS            B 3.1.6-3                                        Rev. 5.0
 
Rod Pattern Control B 3.1.6 BASES ACTIONS            A.1 and A.2 With one or more OPERABLE control rods not in compliance with the prescribed control rod sequence, action may be taken to either correct the control rod pattern or declare the associated control rods inoperable within 8 hours. Noncompliance with the prescribed sequence may be the result of "double notching," drifting from a control rod drive cooling water transient, leaking scram valves, or a power reduction to  [10]% RTP before establishing the correct control rod pattern. The number of OPERABLE control rods not in compliance with the prescribed sequence is limited to eight to prevent the operator from attempting to correct a control rod pattern that significantly deviates from the prescribed sequence. When the control rod pattern is not in compliance with the prescribed sequence, all control rod movement should be stopped except for moves needed to correct the control rod pattern, or scram if warranted.
Required Action A.1 is modified by a Note, which allows control rods to be bypassed in Rod Action Control System (RACS) to allow the affected control rods to be returned to their correct position. This ensures that the control rods will be moved to the correct position. A control rod not in compliance with the prescribed sequence is not considered inoperable except as required by Required Action A.2. OPERABILITY of control rods is determined by compliance with LCO 3.1.3; LCO 3.1.4, "Control Rod Scram Times," and LCO 3.1.5, "Control Rod Scram Accumulators."
The allowed Completion Time of 8 hours is reasonable, considering the restrictions on the number of allowed out of sequence control rods and the low probability of a CRDA occurring during the time the control rods are out of sequence.
B.1 and B.2 If nine or more OPERABLE control rods are out of sequence, the control rod pattern significantly deviates from the prescribed sequence. Control rod withdrawal should be suspended immediately to prevent the potential for further deviation from the prescribed sequence. Control rod insertion to correct control rods withdrawn beyond their allowed position is allowed since, in general, insertion of control rods has less impact on control rod worth than withdrawals have. Required Action B.1 is modified by a Note that allows the affected control rods to be bypassed in RACS in accordance with SR 3.3.2.1.8 to allow insertion only.
General Electric BWR/6 STS              B 3.1.6-4                                        Rev. 5.0
 
Rod Pattern Control B 3.1.6 BASES ACTIONS (continued)
With nine or more OPERABLE control rods not in compliance with BPWS, the reactor mode switch must be placed in the shutdown position within 1 hour. With the reactor mode switch in shutdown, the reactor is shut down, and therefore does not meet the applicability requirements of this LCO. The allowed Completion Time of 1 hour is reasonable to allow insertion of control rods to restore compliance, and is appropriate relative to the low probability of a CRDA occurring with the control rods out of sequence.
SURVEILLANCE        SR 3.1.6.1 REQUIREMENTS The control rod pattern is periodically verified to be in compliance with the BPWS, ensuring the assumptions of the CRDA analyses are met. [ The 24 hour Frequency of this Surveillance was developed considering that the primary check of the control rod pattern compliance with the BPWS is performed by the RPC (LCO 3.3.2.1).
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
The RPC provides control rod blocks to enforce the required control rod sequence and is required to be OPERABLE when operating at 10% RTP.
REFERENCES          1. Current Cycle Safety Analysis.
: 2.    "Modifications to the Requirements for Control Rod Drop Accident Mitigating Systems," BWR Owners Group, July 1987.
: 3. FSAR, Section 15.4.9.
: 4. NUREG-0979, "NRC Safety Evaluation Report for GESSAR II BWR/6 Nuclear Island Design, Docket No. 50-447," Section 4.2.1.3.2, April 1983.
General Electric BWR/6 STS                B 3.1.6-5                                                      Rev. 5.0
 
Rod Pattern Control B 3.1.6 BASES REFERENCES (continued)
: 5. NUREG-0800, "Standard Review Plan," Section 15.4.9, "Radiological Consequences of Control Rod Drop Accident (BWR)," Revision 2, July 1981.
: 6. 10 CFR 100.11, "Determination of Exclusion Area Low Population Zone and Population Center Distance."
: 7. NEDO-21778-A, "Transient Pressure Rises Affected Fracture Toughness Requirements for Boiling Water Reactors,"
December 1978.
: 8. ASME, Boiler and Pressure Vessel Code.
: 9. NEDO-21231, "Banked Position Withdrawal Sequence,"
January 1977.
: 10. NEDO-33091-A, Revision 2, "Improved BPWS Control Rod Insertion Process," July 2004.
General Electric BWR/6 STS          B 3.1.6-6                                    Rev. 5.0
 
SLC System B 3.1.7 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.7 Standby Liquid Control (SLC) System BASES BACKGROUND          The SLC System is designed to provide the capability of bringing the reactor, at any time in a fuel cycle, from full power and minimum control rod inventory (which is at the peak of the xenon transient) to a subcritical condition with the reactor in the most reactive xenon free state without taking credit for control rod movement. The SLC System satisfies the requirements of 10 CFR 50.62 (Ref. 1) on anticipated transient without scram (ATWS).
The SLC System consists of a boron solution storage tank, two positive displacement pumps, two explosive valves, which are provided in parallel for redundancy, and associated piping and valves used to transfer borated water from the storage tank to the reactor pressure vessel (RPV).
The borated solution is discharged through the high pressure core spray system sparger.
APPLICABLE          The SLC System is manually initiated from the main control room, as SAFETY              directed by the emergency operating procedures, if the operator believes ANALYSES            the reactor cannot be shut down, or kept shut down, with the control rods.
The SLC System is used in the event that not enough control rods can be inserted to accomplish shutdown and cooldown in the normal manner.
The SLC System injects borated water into the reactor core to compensate for all of the various reactivity effects that could occur during plant operation. To meet this objective, it is necessary to inject a quantity of boron that produces a concentration of 660 ppm of natural boron in the reactor core at 68&deg;F. To allow for potential leakage and imperfect mixing in the reactor system, an additional amount of boron equal to 25% of the amount cited above is added (Ref. 2). The temperature versus concentration limits in Figure 3.1.7-1 are calculated such that the required concentration is achieved accounting for dilution in the RPV with normal water level and including the water volume in the residual heat removal shutdown cooling piping and in the recirculation loop piping. This quantity of borated solution is the amount that is above the pump suction shutoff level in the boron solution storage tank. No credit is taken for the portion of the tank volume that cannot be injected.
The SLC System satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS              B 3.1.7-1                                        Rev. 5.0
 
SLC System B 3.1.7 BASES LCO                The OPERABILITY of the SLC System provides backup capability for reactivity control, independent of normal reactivity control provisions provided by the control rods. The OPERABILITY of the SLC System is based on the conditions of the borated solution in the storage tank and the availability of a flow path to the RPV, including the OPERABILITY of the pumps and valves. Two SLC subsystems are required to be OPERABLE, each containing an OPERABLE pump, an explosive valve and associated piping, valves, and instruments and controls to ensure an OPERABLE flow path.
APPLICABILITY      In MODES 1 and 2, shutdown capability is required. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate controls to ensure the reactor remains subcritical. In MODE 5, only a single control rod can be withdrawn from a core cell containing fuel assemblies. Demonstration of adequate SDM (LCO 3.1.1, "SHUTDOWN MARGIN (SDM)") ensures that the reactor will not become critical.
Therefore, the SLC System is not required to be OPERABLE during these conditions, when only a single control rod can be withdrawn.
ACTIONS            A.1 If the boron solution concentration is less than the required limits for ATWS mitigation but greater than the concentration required for cold shutdown (original licensing basis), the concentration must be restored to within limits in 72 hours. It is not necessary under these conditions to enter Condition C for both SLC subsystems inoperable, since they are capable of performing their original design basis function. Because of the low probability of an ATWS event and that the SLC System capability still exists for vessel injection under these conditions, the allowed Completion Time of 72 hours is acceptable and provides adequate time to restore concentration to within limits.
B.1 If one SLC System subsystem is inoperable for reasons other than Condition A, the inoperable subsystem must be restored to OPERABLE status within 7 days [or in accordance with the Risk Informed Completion Time Program]. In this condition, the remaining OPERABLE subsystem is adequate to perform the shutdown function. However, the overall reliability is reduced because a single failure in the remaining OPERABLE subsystem could result in reduced SLC System shutdown capability. The 7 day Completion Time is based on the availability of an OPERABLE subsystem capable of performing the intended SLC System function and the low probability of a Design Basis Accident (DBA) or severe transient occurring concurrent with the failure of the Control Rod Drive System to shut down the plant.
General Electric BWR/6 STS              B 3.1.7-2                                        Rev. 5.0
 
SLC System B 3.1.7 BASES ACTIONS (continued)
C.1 If both SLC subsystems are inoperable for reasons other than Condition A, at least one subsystem must be restored to OPERABLE status within 8 hours. The allowed Completion Time of 8 hours is considered acceptable, given the low probability of a DBA or transient occurring concurrent with the failure of the control rods to shut down the reactor.
D.1 If any Required Action and associated Completion Time is 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 MODE 3 within 12 hours.
The allowed Completion Time of 12 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 3.1.7.1, SR 3.1.7.2, and SR 3.1.7.3 REQUIREMENTS SR 3.1.7.1 through SR 3.1.7.3 verify certain characteristics of the SLC System (e.g., the volume and temperature of the borated solution in the storage tank), thereby ensuring the SLC System OPERABILITY without disturbing normal plant operation. These Surveillances ensure the proper borated solution and temperature, including the temperature of the pump suction piping, are maintained. Maintaining a minimum specified borated solution temperature is important in ensuring that the boron remains in solution and does not precipitate out in the storage tank or in the pump suction piping. [ The 24 hour Frequency of these SRs is based on operating experience that has shown there are relatively slow variations in the measured parameters of volume and temperature.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.1.7-3                                                      Rev. 5.0
 
SLC System B 3.1.7 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.1.7.4 and SR 3.1.7.6 SR 3.1.7.4 verifies the continuity of the explosive charges in the injection valves to ensure proper operation will occur if required. Other administrative controls, such as those that limit the shelf life of the explosive charges, must be followed. [ The 31 day Frequency is based on operating experience that has demonstrated the reliability of the explosive charge continuity.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.1.7.6 verifies each valve in the system is in its correct position, but does not apply to the squib (i.e., explosive) valves. Verifying the correct alignment for manual, power operated, and automatic valves in the SLC System flow path ensures that the proper flow paths will exist for system operation. A valve is also allowed to be in the nonaccident position, provided it can be aligned to the accident position from the control room, or locally by a dedicated operator at the valve control. This is acceptable since the SLC System is a manually initiated system. This Surveillance does not apply to valves that are locked, sealed, or otherwise secured in position, since they were verified to be in the correct position prior to locking, sealing, or securing. This verification of valve alignment 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 capable of being mispositioned are in the correct positions. [ The 31 day Frequency is based on engineering judgment and is consistent with the procedural controls governing valve operation that ensure correct valve positions.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.1.7-4                                                      Rev. 5.0
 
SLC System B 3.1.7 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.1.7.5 This Surveillance requires an examination of the sodium pentaborate solution by using chemical analysis to ensure the proper concentration of boron exists in the storage tank. SR 3.1.7.5 must be performed anytime boron or water is added to the storage tank solution to establish that the boron solution concentration is within the specified limits. This Surveillance must be performed anytime the temperature is restored to within the limits of Figure 3.1.7-1, to ensure no significant boron precipitation occurred. [ The 31 day Frequency of this Surveillance is appropriate because of the relatively slow variation of boron concentration between surveillances.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.1.7.7 Demonstrating each SLC System pump develops a flow rate  41.2 gpm at a discharge pressure  1300 psig ensures that pump performance has not degraded during the fuel cycle. This minimum pump flow rate requirement ensures that, when combined with the sodium pentaborate solution concentration requirements, the rate of negative reactivity insertion from the SLC System will adequately compensate for the positive reactivity effects encountered during power reduction, cooldown of the moderator, and xenon decay. This test confirms one point on the pump design curve, and is indicative of overall performance. Such General Electric BWR/6 STS                B 3.1.7-5                                                      Rev. 5.0
 
SLC System B 3.1.7 BASES SURVEILLANCE REQUIREMENTS (continued) inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
If the testing is within the scope of the licensee's INSERVICE TESTING PROGRAM, the Frequency "In accordance with the INSERVICE TESTING PROGRAM" should be used. Otherwise, the periodic Frequency of 92 days or the reference to the Surveillance Frequency Control Program should be used.
The Frequency of this Surveillance is [ in accordance with the INSERVICE TESTING PROGRAM] [92 days.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
SR 3.1.7.8 and SR 3.1.7.9 These Surveillances ensure that there is a functioning flow path from the boron solution storage tank to the RPV, including the firing of an explosive valve. The replacement charge for the explosive valve shall be from the same manufactured batch as the one fired or from another batch that has been certified by having one of that batch successfully fired. The Surveillance may be performed in separate steps to prevent injecting boron into the RPV. An acceptable method for verifying flow from the pump to the RPV is to pump demineralized water from a test tank through one SLC subsystem and into the RPV. [ The pump and explosive valve tested should be alternated such that both complete flow paths are tested every 36 months, at alternating 18 month intervals. 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 test when performed at the 18 month Frequency; General Electric BWR/6 STS                B 3.1.7-6                                                      Rev. 5.0
 
SLC System B 3.1.7 BASES SURVEILLANCE REQUIREMENTS (continued) therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
Demonstrating that all heat traced piping between the boron solution storage tank and the suction inlet to the injection pumps is unblocked ensures that there is a functioning flow path for injecting the sodium pentaborate solution. An acceptable method for verifying that the suction piping is unblocked is to pump from the storage tank to the test tank.
[ The 18 month Frequency is acceptable since there is a low probability that the subject piping will be blocked due to precipitation of the boron from solution in the heat traced piping.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
This is especially true in light of the temperature verification of this piping required by SR 3.1.7.3. However, if, in performing SR 3.1.7.3, it is determined that the temperature of this piping has fallen below the specified minimum, SR 3.1.7.9 must be performed once within 24 hours after the piping temperature is restored within the limits of Figure 3.1.7-1.
General Electric BWR/6 STS                B 3.1.7-7                                                      Rev. 5.0
 
SLC System B 3.1.7 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.1.7.10 Enriched sodium pentaborate solution is made by mixing granular, enriched sodium pentaborate with water. Isotopic tests on the granular sodium pentaborate to verify the actual B-10 enrichment must be performed prior to addition to the SLC tank in order to ensure that the proper B-10 atom percentage is being used.
REFERENCES          1. 10 CFR 50.62.
: 2. FSAR, Section [9.3.5.3].
General Electric BWR/6 STS            B 3.1.7-8                                        Rev. 5.0
 
SDV Vent and Drain Valves B 3.1.8 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves BASES BACKGROUND          The SDV vent and drain valves are normally open and discharge any accumulated water in the SDV to ensure that sufficient volume is available at all times to allow a complete scram. During a scram, the SDV vent and drain valves close to contain reactor water. The SDV consists of header piping that connects to each hydraulic control unit (HCU) and drains into an instrument volume. There are two headers and two instrument volumes, each receiving approximately one half of the control rod drive (CRD) discharges. The two instrument volumes are connected to a common drain line with two valves in series. Each header is connected to a common vent line with two valves in series. The header piping is sized to receive and contain all the water discharged by the CRDs during a scram. The design and functions of the SDV are described in Reference 1.
APPLICABLE          The Design Basis Accident and transient analyses assume all the control SAFETY              rods are capable of scramming. The primary function of the SDV is to ANALYSES            limit the amount of reactor coolant discharged during a scram. The acceptance criteria for the SDV vent and drain valves are that they operate automatically to:
: a. Close during scram to limit the amount of reactor coolant discharged so that adequate core cooling is maintained and offsite doses remain within the limits of 10 CFR 100 (Ref. 2) and
: b. Open on scram reset to maintain the SDV vent and drain path open so there is sufficient volume to accept the reactor coolant discharged during a scram.
Isolation of the SDV can also be accomplished by manual closure of the SDV valves. Additionally, the discharge of reactor coolant to the SDV can be terminated by scram reset or closure of the HCU manual isolation valves. For a bounding leakage case, the offsite doses are well within the limits of 10 CFR 100 (Ref. 2) and adequate core cooling is maintained (Ref. 3). The SDV vent and drain valves also allow continuous drainage of the SDV during normal plant operation to ensure the SDV has sufficient capacity to contain the reactor coolant discharge during a full core scram.
To automatically ensure this capacity, a reactor scram (LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation") is initiated if the SDV water level exceeds a specified setpoint. The setpoint is chosen such that all control rods are inserted before the SDV has insufficient volume to accept a full scram.
SDV vent and drain valves satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS              B 3.1.8-1                                        Rev. 5.0
 
SDV Vent and Drain Valves B 3.1.8 BASES LCO                The OPERABILITY of all SDV vent and drain valves ensures that, during a scram, the SDV vent and drain valves will close to contain reactor water discharged to the SDV piping. Since the vent and drain lines are provided with two valves in series, the single failure of one valve in the open position will not impair the isolation function of the system.
Additionally, the valves are required to be open to ensure that a path is available for the SDV piping to drain freely at other times.
APPLICABILITY      In MODES 1 and 2, scram may be required, and therefore, the SDV vent and drain valves must be OPERABLE. In MODES 3 and 4, control rods are not able to be withdrawn since the reactor mode switch is in shutdown and a control rod block is applied. This provides adequate controls to ensure that only a single control rod can be withdrawn. Also, during MODE 5, only a single control rod can be withdrawn from a core cell containing fuel assemblies. Therefore, the SDV vent and drain valves are not required to be OPERABLE in these MODES since the reactor is subcritical and only one rod may be withdrawn and subject to scram.
ACTIONS            The ACTIONS table is modified by Note 1 indicating that a separate Condition entry is allowed for each SDV vent and drain line. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable SDV line.
Complying with the Required Actions may allow for continued operation, and subsequent inoperable SDV lines are governed by subsequent Condition entry and application of associated Required Actions.
When a line is isolated, the potential for an inadvertent scram due to high SDV level is increased. During these periods, the line may be unisolated under administrative control. This allows any accumulated water in the line to be drained, to preclude a reactor scram on SDV high level. This is acceptable, since the administrative controls ensure the valve can be closed quickly, by a dedicated operator, if a scram occurs with the valve open.
A.1 When one SDV vent or drain valve is inoperable in one or more lines, the associated line must be isolated to contain the reactor coolant during a scram. The 7 day Completion Time is reasonable, given the level of redundancy in the lines and the low probability of a scram occurring during the time the valve(s) are inoperable and the line is not isolated.
The SDV is still isolable since the redundant valve in the affected line is OPERABLE. During these periods, the single failure criterion may not be preserved, and a higher risk exists to allow reactor water out of the primary system during a scram.
General Electric BWR/6 STS            B 3.1.8-2                                        Rev. 5.0
 
SDV Vent and Drain Valves B 3.1.8 BASES ACTIONS (continued)
B.1 If both valves in a line are inoperable, the line must be isolated to contain the reactor coolant during a scram.
The 8 hour Completion Time to isolate the line is based on the low probability of a scram occurring while the line is not isolated and unlikelihood of significant CRD seal leakage.
C.1 If any Required Action and associated Completion Time is 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 MODE 3 within 12 hours.
The allowed Completion Time of 12 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 3.1.8.1 REQUIREMENTS During normal operation, the SDV vent and drain valves should be in the open position (except when performing SR 3.1.8.2) to allow for drainage of the SDV piping. Verifying that each valve is in the open position ensures that the SDV vent and drain valves will perform their intended function during normal operation. This SR does not require any testing or valve manipulation; rather, it involves verification that the valves are in the correct position. [ The 31 day Frequency is based on engineering judgment and is consistent with the procedural controls governing valve operation, which ensure correct valve positions. Improper valve position (closed) would not affect the isolation function.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.1.8-3                                                      Rev. 5.0
 
SDV Vent and Drain Valves B 3.1.8 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.1.8.2 During a scram, the SDV vent and drain valves should close to contain the reactor water discharged to the SDV piping. Cycling each valve through its complete range of motion (closed and open) ensures that the valve will function properly during a scram. [ The 92 day Frequency is based on operating experience and takes into account the level of redundancy in the system design.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.1.8.3 SR 3.1.8.3 is an integrated test of the SDV vent and drain valves to verify total system performance. After receipt of a simulated or actual scram signal, the closure of the SDV vent and drain valves is verified. The closure time of [30] seconds after a receipt of a scram signal is based on the bounding leakage case evaluated in the accident analysis. Similarly, after receipt of a simulated or actual scram reset signal, the opening of the SDV vent and drain valves is verified. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.1.1 and the scram time testing of control rods in LCO 3.1.3 overlap this Surveillance to provide complete testing of the assumed safety function. [ The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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 was concluded to be acceptable from a reliability standpoint.
OR General Electric BWR/6 STS                B 3.1.8-4                                                      Rev. 5.0
 
SDV Vent and Drain Valves B 3.1.8 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [4.6.1.1.2.4.2.6].
: 2. 10 CFR 100.
: 3. NUREG-0803, "Generic Safety Evaluation Report Regarding Integrity of BWR Scram System Piping," August 1981.
General Electric BWR/6 STS                B 3.1.8-5                                                      Rev. 5.0
 
APLHGR B 3.2.1 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)
BASES BACKGROUND          The APLHGR is a measure of the average LHGR of all the fuel rods in a fuel assembly at any axial location. Limits on the APLHGR are specified to ensure that the fuel design limits identified in Reference 1 are not exceeded during anticipated operational occurrences (AOOs) and that the peak cladding temperature (PCT) during the postulated design basis loss of coolant accident (LOCA) does not exceed the limits specified in 10 CFR 50.46.
APPLICABLE          The analytical methods and assumptions used in evaluating the fuel SAFETY              design limits are presented in the FSAR, Chapters 4, 6, and 15, and in ANALYSES            References 1 and 2. The analytical methods and assumptions used in evaluating Design Basis Accidents (DBAs), anticipated operational transients, and normal operations that determine APLHGR limits are presented in FSAR, Chapters 4, 6, and 15, and in References 1, 2, and 3.
Fuel design evaluations are performed to demonstrate that the 1% limit on the fuel cladding plastic strain and other fuel design limits described in Reference 1 are not exceeded during AOOs for operation with LHGR up to the operating limit LHGR. APLHGR limits are equivalent to the LHGR limit for each fuel rod divided by the local peaking factor of the fuel assembly. APLHGR limits are developed as a function of exposure and the various operating core flow and power states to ensure adherence to fuel design limits during the limiting AOOs (Refs. 2 and 3). Flow dependent APLHGR limits are determined using the three dimensional BWR simulator code (Ref. 4) to analyze slow flow runout transients. The flow dependent multiplier, MAPFACf, is dependent on the maximum core flow runout capability. MAPFACf curves are provided based on the maximum credible flow runout transient for Loop Manual and Non Loop Manual operation. The result of a single failure or single operator error during Loop Manual operation is the runout of only one loop because both recirculation loops are under independent control. Non Loop Manual operational modes allow simultaneous runout of both loops because a single controller regulates core flow.
Based on analyses of limiting plant transients (other than core flow increases) over a range of power and flow conditions, power dependent multipliers, MAPFACp, are also generated. Due to the sensitivity of the transient response to initial core flow levels at power levels below those at which turbine stop valve closure and turbine control valve fast closure scram signals are bypassed, both high and low core flow MAPFACp limits are provided for operation at power levels between 25% RTP and the previously mentioned bypass power level. The exposure dependent General Electric BWR/6 STS              B 3.2.1-1                                        Rev. 5.0
 
APLHGR B 3.2.1 BASES APPLICABLE SAFETY ANALYSES (continued)
APLHGR limits are reduced by MAPFACp and MAPFACf at various operating conditions to ensure that all fuel design criteria are met for normal operation and AOOs. A complete discussion of the analysis code is provided in References 1 and 3.
LOCA analyses are then performed to ensure that the above determined APLHGR limits are adequate to meet the PCT and maximum oxidation limits of 10 CFR 50.46. The analysis is performed using calculational models that are consistent with the requirements of 10 CFR 50, Appendix K. A complete discussion of the analysis code is provided in Reference 5. The PCT following a postulated LOCA is a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is not strongly influenced by the rod to rod power distribution within an assembly. The APLHGR limits specified are equivalent to the LHGR of the highest powered fuel rod assumed in the LOCA analysis divided by its local peaking factor. A conservative multiplier is applied to the LHGR assumed in the LOCA analysis to account for the uncertainty associated with the measurement of the APLHGR.
For single recirculation loop operation, the MAPFAC multiplier is limited to a maximum of 0.86 (Ref. 2). This limit is due to the conservative analysis assumption of an earlier departure from nucleate boiling with one recirculation loop available, resulting in a more severe cladding heatup during a LOCA.
The APLHGR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO                The APLHGR limits specified in the COLR are the result of fuel design, DBA, and transient analyses. For two recirculation loops operating, the limit is determined by multiplying the smaller of the MAPFACf and MAPFACp factors times the exposure dependent APLHGR limits. With only one recirculation loop in operation, in conformance with the requirements of LCO 3.4.1, "Recirculation Loops Operating," the limit is determined by multiplying the exposure dependent APLHGR limit by the smallest of MAPFACf, MAPFACp, and 0.86, where 0.86 has been determined by a specific single recirculation loop analysis (Ref. 2).
APPLICABILITY      The APLHGR limits are primarily derived from fuel design evaluations and LOCA and transient analyses that are assumed to occur at high power levels. Design calculations (Ref. 4) and operating experience have shown that as power is reduced, the margin to the required APLHGR limits increases. This trend continues down to the power range of 5% to 15% RTP when entry into MODE 2 occurs. When in MODE 2, the intermediate range monitor (IRM) scram function provides prompt scram General Electric BWR/6 STS              B 3.2.1-2                                        Rev. 5.0
 
APLHGR B 3.2.1 BASES APPLICABILITY (continued) initiation during any significant transient, thereby effectively removing any APLHGR limit compliance concern in MODE 2. Therefore, at THERMAL POWER levels  25% RTP, the reactor operates with substantial margin to the APLHGR limits; thus, this LCO is not required.
ACTIONS            A.1 If any APLHGR exceeds the required limits, an assumption regarding an initial condition of the DBA and transient analyses may not be met.
Therefore, prompt action is taken to restore the APLHGR(s) to within the required limits such that the plant will be operating within analyzed conditions and within the design limits of the fuel rods. The 2 hour Completion Time is sufficient to restore the APLHGR(s) to within its limits and is acceptable based on the low probability of a transient or DBA occurring simultaneously with the APLHGR out of specification.
B.1 If the APLHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 25% RTP within 4 hours. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.
SURVEILLANCE        SR 3.2.1.1 REQUIREMENTS APLHGRs are required to be initially calculated within 12 hours after THERMAL POWER is  25% RTP and periodically thereafter. They are compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 12 hour allowance after THERMAL POWER  25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.
[ The 24 hour Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution under normal conditions.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS              B 3.2.1-3                                        Rev. 5.0
 
APLHGR B 3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1.    [Plant specific current cycle safety analysis].
: 2. FSAR, [Chapter 15, Appendix C].
: 3. FSAR, [Chapter 15, Appendix D].
: 4. XN-NF-80-19(P)(A), "Exxon Nuclear Methodology for Boiling Water Reactors, Neutronics Methods for Design and Analysis," Volume 1, June 1981.
: 5. XN-NF-80-19(A), "Exxon Nuclear Methodology for Boiling Water Reactors, ECCS Evaluation Model," Volume 2, Revision 1, June 1981.
General Electric BWR/6 STS                B 3.2.1-4                                                      Rev. 5.0
 
MCPR B 3.2.2 B 3.2 POWER DISTRIBUTIONS LIMITS B 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR)
BASES BACKGROUND          MCPR is a ratio of the fuel assembly power that would result in the onset of boiling transition to the actual fuel assembly power. The operating limit MCPR is established to ensure that no fuel damage results during anticipated operational occurrences (AOOs), and that 99.9% of the fuel rods are not susceptible to boiling transition if the limit is not violated.
Although fuel damage does not necessarily occur if a fuel rod actually experiences boiling transition (Ref. 1), the critical power at which boiling transition is calculated to occur has been adopted as a fuel design criterion.
The onset of transition boiling is a phenomenon that is readily detected during the testing of various fuel bundle designs. Based on these experimental data, correlations have been developed to predict critical bundle power (i.e., the bundle power level at the onset of transition boiling) for a given set of plant parameters (e.g., reactor vessel pressure, flow, and subcooling). Because plant operating conditions and bundle power levels are monitored and determined relatively easily, monitoring the MCPR is a convenient way of ensuring that fuel failures due to inadequate cooling do not occur.
APPLICABLE          ----------------------------------- REVIEWER'S NOTE -------------------------------
SAFETY              Incorporate the MCPR95/95 discussion if applicable.
ANALYSES            ------------------------------------------------------------------------------------------------
The analytical methods and assumptions used in evaluating the AOOs to establish the operating limit MCPR are presented in the FSAR, Chapters 4, 6, and 15, and References 2, 3, 4, and 5. To ensure that the MCPR Safety Limit (SL) is not exceeded during any transient event that occurs with moderate frequency, limiting transients have been analyzed to determine the largest reduction in critical power ratio (CPR). The types of transients evaluated are loss of flow, increase in pressure and power, positive reactivity insertion, and coolant temperature decrease. The limiting transient yields the largest change in CPR (CPR). When the largest CPR is combined with the [SL] MCPR[99.9%], the required operating limit MCPR is obtained.
[MCPR99.9% is determined to ensure more than 99.9% of the fuel rods in the core are not susceptible to boiling transition using a statistical model that combines all the uncertainties in operating parameters and the procedures used to calculate critical power. The probability of the occurrence of boiling transition is determined using the approved Critical Power correlations. Details of the MCPR99.9% calculation are given in General Electric BWR/6 STS                B 3.2.2-1                                                      Rev. 5.0
 
MCPR B 3.2.2 BASES APPLICABLE SAFETY ANALYSES (continued)
Reference 2. Reference 2 also includes a tabulation of the uncertainties and the nominal values of the parameters used in the MCPR99.9%
statistical analysis.]
The MCPR operating limits are derived from [the MCPR99.9% value and]
the transient analysis, and are dependent on the operating core flow and power state (MCPRf and MCPRp, respectively) to ensure adherence to fuel design limits during the worst transient that occurs with moderate frequency (Refs. 3, 4, and 5). Flow dependent MCPR limits are determined by steady state thermal hydraulic methods using the three dimensional BWR simulator code (Ref. 6) and the multichannel thermal hydraulic code (Ref. 7). MCPRf curves are provided based on the maximum credible flow runout transient for Loop Manual and Non Loop Manual operation. The result of a single failure or single operator error during Loop Manual operation is the runout of only one loop because both recirculation loops are under independent control. Non Loop Manual operational modes allow simultaneous runout of both loops because a single controller regulates core flow.
Power dependent MCPR limits (MCPRp) are determined by approved transient analysis models (Ref. 8). Due to the sensitivity of the transient response to initial core flow levels at power levels below those at which the turbine stop valve closure and turbine control valve fast closure scram trips are bypassed, high and low flow MCPRp operating limits are provided for operating between 25% RTP and the previously mentioned bypass power level.
The MCPR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO                The MCPR operating limits specified in the COLR [(MCPR99.9% value, MCPRf values, and MCPRp values)] are the result of the Design Basis Accident (DBA) and transient analysis. The MCPR operating limits are determined by the larger of the MCPRf and MCPRp limits[, which are based on the MCPR99.9% limit specified in the COLR].
APPLICABILITY      The MCPR operating limits are primarily derived from transient analyses that are assumed to occur at high power levels. Below 25% RTP, the reactor is operating at a slow recirculation pump speed and the moderator void ratio is small. Surveillance of thermal limits below 25% RTP is unnecessary due to the large inherent margin that ensures that the MCPR SL is not exceeded even if a limiting transient occurs.
Statistical analyses documented in Reference 9 indicate that the nominal value of the initial MCPR expected at 25% RTP is > 3.5. Studies of the variation of limiting transient behavior have been performed over the General Electric BWR/6 STS              B 3.2.2-2                                        Rev. 5.0
 
MCPR B 3.2.2 BASES APPLICABILITY (continued) range of power and flow conditions. These studies (Ref. 5) encompass the range of key actual plant parameter values important to typically limiting transients. The results of these studies demonstrate that a margin is expected between performance and the MCPR requirements, and that margins increase as power is reduced to 25% RTP. This trend is expected to continue to the 5% to 15% power range when entry into MODE 2 occurs. When in MODE 2, the intermediate range monitor (IRM) provides rapid scram initiation for any significant power increase transient, which effectively eliminates any MCPR compliance concern.
Therefore, at THERMAL POWER levels < 25% RTP, the reactor is operating with substantial margin to the MCPR limits and this LCO is not required.
ACTIONS            A.1 If any MCPR is outside the required limits, an assumption regarding an initial condition of the design basis transient analyses may not be met.
Therefore, prompt action should be taken to restore the MCPR(s) to within the required limits such that the plant remains operating within analyzed conditions. The 2 hour Completion Time is normally sufficient to restore the MCPR(s) to within its limits and is acceptable based on the low probability of a transient or DBA occurring simultaneously with the MCPR out of specification.
B.1 If the MCPR cannot be restored to within the required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 25% RTP within 4 hours. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.
SURVEILLANCE        SR 3.2.2.1 REQUIREMENTS The MCPR is required to be initially calculated within 12 hours after THERMAL POWER is  25% RTP and periodically thereafter. It is compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 12 hour allowance after THERMAL POWER reaches  25% RTP is acceptable given the large inherent margin to operating limits at low power levels.
[ The 24 hour Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation.
General Electric BWR/6 STS              B 3.2.2-3                                      Rev. 5.0
 
MCPR B 3.2.2 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. NUREG-0562, June 1979.
: 2.    [Plant specific current cycle safety analysis].
: 3. FSAR, [Appendix 15B].
: 4. FSAR, [Appendix 15C].
: 5. FSAR, [Appendix 15D].
: 6. XN-NF-80-19(P)(A), "Exxon Nuclear Methodology for Boiling Water Reactors, Neutronics Methods for Design and Analysis," Volume 1 (as supplemented).
: 7. XN-NF-80-19(P)(A), "Exxon Nuclear Methodology for Boiling Water Reactors, THERMEX Thermal Limits Methodology Summary Description," Volume 3, Revision 2, January 1987.
: 8. XN-NF-79-71(P), "Exxon Nuclear Plant Methodology for Boiling Water Reactors," Revision 2, November 1981.
: 9.    "BWR/6 Generic Rod Withdrawal Error Analysis," General Electric Standard Safety Analysis Report, GESSAR-II, Appendix 15B.
General Electric BWR/6 STS                B 3.2.2-4                                                      Rev. 5.0
 
LHGR (Optional)
B 3.2.3 B 3.2 POWER DISTRIBUTIONS LIMITS B 3.2.3 LINEAR HEAT GENERATION RATE (LHGR) (Optional)
BASES BACKGROUND          The LHGR is a measure of the heat generation rate of a fuel rod in a fuel assembly at any axial location. Limits on the LHGR are specified to ensure that fuel design limits are not exceeded anywhere in the core during normal operation, including anticipated operational occurrences (AOOs). Exceeding the LHGR limit could potentially result in fuel damage and subsequent release of radioactive materials. Fuel design limits are specified to ensure that fuel system damage, fuel rod failure or inability to cool the fuel does not occur during the anticipated operating conditions identified in Reference 1.
APPLICABLE          The analytical methods and assumptions used in evaluating the fuel SAFETY              system design are presented in References 1 and 2. The fuel assembly ANALYSES            is designed to ensure (in conjunction with the core nuclear and thermal hydraulic design, plant equipment, instrumentation, and protection system) that fuel damage will not result in the release of radioactive materials in excess of the guidelines of 10 CFR, Parts 20, 50, and 100.
The mechanisms that could cause fuel damage during operational transients and that are considered in fuel evaluations are:
: a. Rupture of the fuel rod cladding caused by strain from the relative expansion of the UO2 pellet and
: b. Severe overheating of the fuel rod cladding caused by inadequate cooling.
A value of [1%] plastic strain of the fuel cladding has been defined as the limit below which fuel damage caused by overstraining of the fuel cladding is not expected to occur (Ref. 3).
Fuel design evaluations have been performed and demonstrate that the
[1%] fuel cladding plastic strain design limit is not exceeded during continuous operation with LHGRs up to the operating limit specified in the COLR. The analysis also includes allowances for short term transient operation above the operating limit to account for AOOs, plus an allowance for densification power spiking.
The LHGR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO                The LHGR is a basic assumption in the fuel design analysis. The fuel has been designed to operate at rated core power with sufficient design margin to the LHGR calculated to cause a 1% fuel cladding plastic strain.
The operating limit to accomplish this objective is specified in the COLR.
General Electric BWR/6 STS            B 3.2.3-1                                        Rev. 5.0
 
LHGR (Optional)
B 3.2.3 BASES APPLICABILITY      The LHGR limits are derived from fuel design analysis that is limiting at high power level conditions. At core thermal power levels < 25% RTP, the reactor is operating with a substantial margin to the LHGR limits and, therefore, the Specification is only required when the reactor is operating at  25% RTP.
ACTIONS            A.1 If any LHGR exceeds its required limit, an assumption regarding an initial condition of the fuel design analysis is not met. Therefore, prompt action should be taken to restore the LHGR(s) to within its required limits such that the plant is operating within analyzed conditions. The 2 hour Completion Time is normally sufficient to restore the LHGR(s) to within its limits and is acceptable based on the low probability of a transient or Design Basis Accident occurring simultaneously with the LHGR out of specification.
B.1 If the LHGR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 25% RTP within 4 hours. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to < 25% RTP in an orderly manner and without challenging plant systems.
SURVEILLANCE        SR 3.2.3.1 REQUIREMENTS The LHGR is required to be initially calculated within 12 hours after THERMAL POWER is  25% RTP and periodically thereafter. It is compared with the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 12 hour allowance after THERMAL POWER  25% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels.
[ The 24 hour Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution under normal conditions.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS            B 3.2.3-2                                        Rev. 5.0
 
LHGR (Optional)
B 3.2.3 BASES SRVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1.    [Non GE Fuel Analysis].
: 2. FSAR, Chapter [4].
: 3. NUREG-0800, Section II A.2(g), Revision 2, July 1981.
General Electric BWR/6 STS                B 3.2.3-3                                                      Rev. 5.0
 
APRM Gain and Setpoints B 3.2.4 B 3.2 POWER DISTRIBUTIONS LIMITS B 3.2.4 Average Power Range Monitor (APRM) Gain and Setpoints BASES BACKGROUND          The OPERABILITY of the APRMs and their setpoints is an initial condition of all safety analyses that assure rod insertion upon reactor scram.
Applicable GDCs are GDC 10, "Reactor Design," GDC 13, "Instrumentation and Control," GDC 20, "Protection System Functions,"
and GDC 29, "Protection against Anticipated Operation Occurrences" (Ref. 1). This LCO is provided to require the APRM gain or APRM flow biased scram setpoints to be adjusted when operating under conditions of excessive power peaking to maintain acceptable margin to the fuel cladding integrity Safety Limit (SL) and the fuel cladding 1% plastic strain limit.
The condition of excessive power peaking is determined by the ratio of the actual power peaking to the limiting power peaking at RTP. This ratio is equal to the ratio of the core limiting MFLPD to the Fraction of RTP (FRTP) where FRTP is the measured THERMAL POWER divided by the RTP. Excessive power peaking exists when:
MFLPD
                                                              > 1, FRTP indicating that MFLPD is not decreasing proportionately to the overall power reduction, or conversely, that power peaking is increasing. To maintain margins similar to those at RTP conditions, the excessive power peaking is compensated by gain adjustment on the APRMs or adjustment of the APRM setpoints. Either of these adjustments has effectively the same result as maintaining MFLPD less than or equal to FRTP and thus maintains RTP margins for APLHGR and MCPR.
The normally selected APRM setpoints position the scram above the upper bound of the normal power/flow operating region that has been considered in the design of the fuel rods. The setpoints are flow biased with a slope that approximates the upper flow control line, such that an approximately constant margin is maintained between the flow biased trip level and the upper operating boundary for core flows in excess of about 45% of rated core flow. In the range of infrequent operations below 45%
of rated core flow, the margin to scram or rod blocks is reduced because of the nonlinear core flow versus drive flow relationship. The normally selected APRM setpoints are supported by the analyses presented in References 1 and 2 that concentrate on events initiated from rated conditions. Design experience has shown that minimum deviations occur within expected margins to operating limits (APLHGR and MCPR), at General Electric BWR/6 STS              B 3.2.4-1                                        Rev. 5.0
 
APRM Gain and Setpoints B 3.2.4 BASES BACKGROUND (continued) rated conditions for normal power distributions. However, at other than rated conditions, control rod patterns can be established that significantly reduce the margin to thermal limits. Therefore, the flow biased APRM scram setpoints may be reduced during operation when the combination of THERMAL POWER and MFLPD indicates an excessive power peaking distribution.
The APRM neutron flux signal is also adjusted to more closely follow the fuel cladding heat flux during power transients. The APRM neutron flux signal is a measure of the core thermal power during steady state operation. During power transients, the APRM signal leads the actual core thermal power response because of the fuel thermal time constant.
Therefore, on power increase transients, the APRM signal provides a conservatively high measure of core thermal power. By passing the APRM signal through an electronic filter with a time constant less than, but approximately equal to, that of the fuel thermal time constant, an APRM transient response that more closely follows actual fuel cladding heat flux is obtained, while a conservative margin is maintained. The delayed response of the filtered APRM signal allows the flow biased APRM scram levels to be positioned closer to the upper bound of the normal power and flow range, without unnecessarily causing reactor scrams during short duration neutron flux spikes. These spikes can be caused by insignificant transients such as performance of main steam line valve surveillances or momentary flow increases of only several percent.
APPLICABLE          The acceptance criteria for the APRM gain or setpoint adjustments are SAFETY              that acceptable margins (to APLHGR and MCPR) be maintained to the ANALYSES            fuel cladding integrity SL and the fuel cladding 1% plastic strain limit.
FSAR safety analyses (Refs. 2 and 3) concentrate on the rated power condition for which the minimum expected margin to the operating limits (APLHGR and MCPR) occurs. LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," and LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)," limit the initial margins to these operating limits at rated conditions so that specified acceptable fuel design limits are met during transients initiated from rated conditions. At initial power levels less than rated levels, the margin degradation of either the APLHGR or the MCPR during a transient can be greater than at the rated condition event. This greater margin degradation during the transient is primarily offset by the larger initial margin to limits at the lower than rated power levels. However, power distributions can be hypothesized that would result in reduced margins to the pretransient operating limit. When combined with the increased severity of certain transients at other than rated conditions, the SLs could be approached.
At substantially reduced power levels, highly peaked power distributions General Electric BWR/6 STS            B 3.2.4-2                                              Rev. 5.0
 
APRM Gain and Setpoints B 3.2.4 BASES APPLICABLE SAFETY ANALYSES (continued) could be obtained that could reduce thermal margins to the minimum levels required for transient events. To prevent or mitigate such situations, either the APRM gain is adjusted upward by the ratio of the core limiting MFLPD to the FRTP, or the flow biased APRM scram level is required to be reduced by the ratio of FRTP to the core limiting MFLPD.
Either of these adjustments effectively counters the increased severity of some events at other than rated conditions by proportionally increasing the APRM gain or proportionally lowering the flow biased APRM scram setpoints dependent on the increased peaking that may be encountered.
The APRM gain and setpoints satisfy Criteria 2 and 3 of 10 CFR 50.36(c)(2)(ii).
LCO                Meeting any one of the following conditions ensures acceptable operating margins for events described above:
: a. Limiting excess power peaking,
: b. Reducing the APRM flow biased neutron flux upscale scram setpoints by multiplying the APRM setpoints by the ratio of FRTP and the core limiting value of MFLPD, or
: c. Increasing the APRM gains to cause the APRM to read greater than 100(%) times MFLPD. This Condition is to account for the reduction in margin to the fuel cladding integrity SL and the fuel cladding 1%
plastic strain limit.
MFLPD is the ratio of the limiting LHGR to the LHGR limit for the specific bundle type. As power is reduced, if the design power distribution is maintained, MFLPD is reduced in proportion to the reduction in power.
However, if power peaking increases above the design value, the MFLPD is not reduced in proportion to the reduction in power. Under these conditions, the APRM gain is adjusted upward or the APRM flow biased scram setpoints are reduced accordingly. When the reactor is operating with peaking less than the design value, it is not necessary to modify the APRM flow biased scram setpoints. Adjusting the APRM gain or setpoints is equivalent to maintaining MFLPD less than or equal to FRTP, as stated in the LCO.
For compliance with LCO Item b (APRM setpoint adjustment) or Item c (APRM gain adjustment), only APRMs required to be OPERABLE per LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," are required to be adjusted. In addition, each APRM may be allowed to have its gain or setpoints adjusted independently of other APRMs that are having their gain or setpoints adjusted.
General Electric BWR/6 STS              B 3.2.4-3                                        Rev. 5.0
 
APRM Gain and Setpoints B 3.2.4 BASES APPLICABILITY      The MFLPD limit, APRM gain adjustment, or APRM flow biased scram and associated setdowns are provided to ensure that the fuel cladding integrity SL and the fuel cladding 1% plastic strain limit are not violated during design basis transients. As discussed in the Bases for LCO 3.2.1 and LCO 3.2.2 sufficient margin to these limits exists below 25% RTP and, therefore, these requirements are only necessary when the plant is operating at  25% RTP.
ACTIONS            A.1 If the APRM gain or setpoints are not within limits while the MFLPD has exceeded FRTP, the margin to the fuel cladding integrity SL and the fuel cladding 1% plastic strain limit may be reduced. Therefore, prompt action should be taken to restore the MFLPD to within its required limit or make acceptable APRM adjustments such that the plant is operating within the assumed margin of the safety analyses.
The 6 hour Completion Time is normally sufficient to restore either the MFLPD to within limits or the APRM gain or setpoints to within limits and is acceptable based on the low probability of a transient or Design Basis Accident occurring simultaneously with the LCO not met.
B.1 If the APRM gain or setpoints cannot be restored to within their required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply.
To achieve this status, THERMAL POWER must be reduced to
                    < 25% RTP within 4 hours. The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to
                    < 25% RTP in an orderly manner and without challenging plant systems.
SURVEILLANCE        SR 3.2.4.1 and SR 3.2.4.2 REQUIREMENTS The MFLPD is required to be calculated and compared to FRTP or APRM gain or setpoints to ensure that the reactor is operating within the assumptions of the safety analysis. These SRs are required only to determine the MFLPD and, assuming MFLPD is greater than FRTP, the appropriate gain or setpoint, and is not intended to be a CHANNEL FUNCTIONAL TEST for the APRM gain or flow biased neutron flux scram circuitry. The 12 hour allowance after THERMAL POWER  25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.
General Electric BWR/6 STS            B 3.2.4-4                                          Rev. 5.0
 
APRM Gain and Setpoints B 3.2.4 BASES SURVEILLANCE REQUIREMENTS (continued)
[ The 24 hour Frequency of SR 3.2.4.1 is chosen to coincide with the determination of other thermal limits, specifically those for the APLHGR (LCO 3.2.1). The 24 hour Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation. The 12 hour Frequency of SR 3.2.4.2 requires a more frequent verification than if MFLPD is less than or equal to fraction of rated power (FRP). When MFLPD is greater than FRP, more rapid changes in power distribution are typically expected.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. 10 CFR 50, Appendix A, GDC 10, GDC 13, GDC 20, and GDC 29.
: 2. FSAR, Section [ ].
: 3. FSAR, Section [ ].
General Electric BWR/6 STS                B 3.2.4-5                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 B 3.3 INSTRUMENTATION B 3.3.1.1 Reactor Protection System (RPS) Instrumentation BASES BACKGROUND          The RPS initiates a reactor scram when one or more monitored parameters exceed their specified limit, to preserve the integrity of the fuel cladding and the Reactor Coolant System (RCS), and minimize the energy that must be absorbed following a loss of coolant accident (LOCA). This can be accomplished either automatically or manually.
The protection and monitoring functions of the RPS 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 action will correct the abnormal situation before a Safety Limit (SL) is exceeded."
Technical Specifications are required by 10 CFR 50.36 to include LSSS for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the process variable at which a protective 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 Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protective channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur.
                    ---------------------------------REVIEWER'S NOTE-------------------------------------
The term "Limiting Trip Setpoint" [LTSP] is generic terminology for the calculated trip setting (setpoint) value calculated by means of the plant specific setpoint methodology documented in a document controlled under 10 CFR 50.59. The term [LTSP] indicates that no additional margin has been added between the Analytical Limit and the calculated trip setting.
General Electric BWR/6 STS                B 3.3.1.1-1                                        Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES BACKGROUND (continued)
                    "Nominal Trip Setpoint [NTSP]" is the suggested terminology for the actual setpoint implemented in the plant surveillance procedures where margin has been added to the calculated [LTSP]. The as-found and as-left tolerances will apply to the [NTSP] implemented in the Surveillance procedures to confirm channel performance.
Licensees are to insert the name of the document(s) controlled under 10 CFR 50.59 that contain the methodology for calculating the as-left and as-found tolerances in Note b of Table 3.3.1.1-1, for the phrase "[insert the name of a document controlled under 10 CFR 50.59 such as the Technical Requirements Manual or any document incorporated into the facility FSAR]" throughout these Bases.
If the [LTSP] is not included in Table 3.3.1.1-1, the plant specific location for the [LTSP] or [NTSP] must be cited in Note b of Table 3.3.1.1-1. The brackets indicate plant specific terms may apply, as reviewed and approved by the NRC.
The [LTSP] specified in Table 3.3.1.1-1, is a predetermined setting for a protection channel chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the SL would not be exceeded. As such, the [LTSP] accounts for uncertainties in setting the channel (e.g., calibration), uncertainties in how the channel might actually perform (e.g., repeatability), changes in the point of action of the channel 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
[LTSP] ensures that SLs are not exceeded. As such, the [LTSP] meets the definition of an LSSS (Ref. 1).
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)." Relying solely on the [LTSP] to define OPERABILITY in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as found" value of a protection channel 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 protection channel with a setting that has been found to be different from the [LTSP] due to some drift of the setting may still be OPERABLE because drift is to be expected. This General Electric BWR/6 STS                B 3.3.1.1-2                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES BACKGROUND (continued) expected drift would have been specifically accounted for in the setpoint methodology for calculating the [LTSP] and thus the automatic protective action would still have ensured that the SL would not be exceeded with the "as found" setting of the protection channel. Therefore, the channel would still be OPERABLE because it would have performed its safety function and the only corrective action required would be to reset the channel within the established as-left tolerance around the [LTSP] to account for further drift during the next surveillance interval.
Note that, although the channel is OPERABLE under these circumstances, the trip setpoint must be left adjusted to a value within the as-left tolerance, 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 (as-found criteria).
However, there is also some point beyond which the channel may not be able to perform its function due to, for example, greater than expected drift. This value needs to be specified in the Technical Specifications in order to define OPERABILITY of the channels and is designated as the Allowable Value.
If the actual setting (as-found setpoint) of the channel is found to be conservative with respect to the Allowable Value but is beyond the as-found tolerance band, the channel is OPERABLE, but degraded. The degraded condition will be further evaluated during performance of the SR. This evaluation will consist of resetting the channel setpoint to the
[LTSP] (within the allowed tolerance), and evaluating the channel response. If the channel is functioning as required and expected to pass the next surveillance, then the channel is OPERABLE and can be restored to service at the completion of the surveillance. After the surveillance is completed, the channel as-found condition will be entered into the Corrective Action Program for further evaluation.
The RPS, as shown in the FSAR, Figure [ ] (Ref. 2), includes sensors, relays, bypass circuits, and switches that are necessary to cause initiation of a reactor scram. Functional diversity is provided by monitoring a wide range of dependent and independent parameters. The input parameters to the scram logic are from instrumentation that monitors reactor vessel water level, reactor vessel pressure, neutron flux main steam line isolation valve position, turbine control valve (TCV) fast closure trip oil pressure low, turbine stop valve (TSV) trip oil pressure low, drywell pressure and scram discharge volume (SDV) water level, as well as reactor mode switch in shutdown position and manual scram signals.
There are at least four redundant sensor input signals from each of these General Electric BWR/6 STS            B 3.3.1.1-3                                        Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES BACKGROUND (continued) parameters (with the exception of the reactor mode switch in shutdown scram signal). Most channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs an RPS trip signal to the trip logic.
Table B 3.3.1.1-1 summarizes the diversity of sensors capable of initiating scrams during anticipated operating transients typically analyzed.
The RPS is comprised of two independent trip systems (A and B), with two logic channels in each trip system (logic channels A1 and A2, B1 and B2), as shown in Reference 2. The outputs of the logic channels in a trip system are combined in a one-out-of-two logic so either channel can trip the associated trip system. The tripping of both trip systems will produce a reactor scram. This logic arrangement is referred to as one-out-of-two taken twice logic. Each trip system can be reset by use of a reset switch. If a full scram occurs (both trip systems trip), a relay prevents reset of the trip systems for 10 seconds after the full scram signal is received. This 10 second delay on reset ensures that the scram function will be completed.
Two scram pilot valves are located in the hydraulic control unit (HCU) for each control rod drive (CRD). Each scram pilot valve is solenoid operated, with the solenoids normally energized. The scram pilot valves control the air supply to the scram inlet and outlet valves for the associated CRD. When either scram pilot valve solenoid is energized, air pressure holds the scram valves closed and, therefore, both scram pilot valve solenoids must be de-energized to cause a control rod to scram.
The scram valves control the supply and discharge paths for the CRD water during a scram. One of the scram pilot valve solenoids for each CRD is controlled by trip system A, and the other solenoid is controlled by trip system B. Any trip of trip system A in conjunction with any trip in trip system B results in de-energizing both solenoids, air bleeding off, scram valves opening, and control rod scram.
The backup scram valves, which energize on a scram signal to depressurize the scram air header, are also controlled by the RPS.
Additionally, the RPS System controls the SDV vent and drain valves such that when both trip systems trip, the SDV vent and drain valves close to isolate the SDV.
APPLICABLE          The actions of the RPS are assumed in the safety analyses of SAFETY              References 3, 4, and 5. The RPS initiates a reactor scram when ANALYSES, LCO,      monitored parameter values are exceeded to preserve the integrity of the and APPLICABILITY  fuel cladding, the reactor coolant pressure boundary (RCPB), and the containment by minimizing the energy that must be absorbed following a LOCA.
General Electric BWR/6 STS            B 3.3.1.1-4                                        Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
RPS instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
Functions not specifically credited in the accident analysis are retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
Permissive and interlock setpoints allow the blocking of trips during plant startups, and restoration of trips when the permissive conditions are not satisfied, but they are not explicitly modeled in the Safety Analyses.
These permissives and interlocks ensure that the starting conditions are consistent with the safety analysis, before preventive or mitigating actions occur. Because these permissives or interlocks are only one of multiple conservative starting assumptions for the accident analysis, they are generally considered as nominal values without regard to measurement accuracy.
The OPERABILITY of the RPS is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.1.1-1.
Each Function must have a required number of OPERABLE channels per RPS trip system, with their setpoints set within the setting tolerance of the
[LTSPs], where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Each channel must also respond within its assumed response time.
Allowable Values for RPS Instrumentation Functions are specified in the Table 3.3.1.1-1. [LTSPs] and the methodologies for calculation of the as-left and as-found tolerances are described in [insert the name of a document controlled under 10 CFR 50.59 such as the Technical Requirements Manual or any document incorporated into the facility FSAR]. The [LTSPs] are selected to ensure that the actual setpoints remain conservative with respect to the as-found tolerance band between successive CHANNEL CALIBRATIONS. After each calibration the trip setpoint shall be left within the as-left band around the [LTSP].
[LTSPs] are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The Analytical Limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytical limits, corrected for calibration, process, and some of the instrument errors. The [LTSPs] are then determined, accounting for the remaining instrument errors (e.g., drift). The [LTSPs] derived in this manner provide adequate protection because instrumentation uncertainties, process General Electric BWR/6 STS            B 3.3.1.1-5                                        Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
The OPERABILITY of scram pilot valves and associated solenoids, backup scram valves, and SDV valves, described in the Background section, are not addressed by this LCO.
The individual Functions are required to be OPERABLE in the MODES specified in the Table that may require an RPS trip to mitigate the consequences of a design basis accident or transient. To ensure a reliable scram function, a combination of Functions is required in each MODE to provide primary and diverse initiation signals.
RPS is required to be OPERABLE in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies.
Control rods withdrawn from a core cell containing no fuel assemblies do not affect the reactivity of the core and therefore are not required to have the capability to scram. Provided all other control rods remain inserted, the RPS function is not required. In this condition, the required SDM (LCO 3.1.1) and refuel position one-rod-out interlock (LCO 3.9.2) ensure that no event requiring RPS will occur. During normal operation in MODES 3 and 4, all control rods are fully inserted and the Reactor Mode Switch Shutdown Position control rod withdrawal block (LCO 3.3.2.1) does not allow any control rod to be withdrawn. Under these conditions, the RPS function is not required to be OPERABLE.
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
1.a. Intermediate Range Monitor (IRM) Neutron Flux - High The IRMs monitor neutron flux levels from the upper range of the source range monitors (SRMs) to the lower range of the average power range monitors (APRMs). The IRMs are capable of generating trip signals that can be used to prevent fuel damage resulting from abnormal operating transients in the intermediate power range. In this power range, the most significant source of reactivity change is due to control rod withdrawal.
The IRM provides diverse protection for the rod withdrawal limiter (RWL),
which monitors and controls the movement of control rods at low power.
The RWL prevents the withdrawal of an out of sequence control rod during startup that could result in an unacceptable neutron flux excursion (Ref. 6). The IRM provides mitigation of the neutron flux excursion. To demonstrate the capability of the IRM System to mitigate control rod General Electric BWR/6 STS            B 3.3.1.1-6                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) withdrawal events, generic analyses have been performed (Ref. 7) to evaluate the consequences of control rod withdrawal events during startup that are mitigated only by the IRM. This analysis, which assumes that one IRM channel in each trip system is bypassed, demonstrates that the IRMs provide protection against local control rod withdrawal errors and results in peak fuel energy depositions below the 170 cal/gm fuel failure threshold criterion.
The IRMs are also capable of limiting other reactivity excursions during startup, such as cold water injection events, although no credit is specifically assumed.
The IRM System is divided into two groups of IRM channels, with four IRM channels inputting to each trip system. The analysis of Reference 7 assumes that one channel in each trip system is bypassed. Therefore, six channels with three channels in each trip system are required for IRM OPERABILITY to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This trip is active in each of the 10 ranges of the IRM, which must be selected by the operator to maintain the neutron flux within the monitored level of an IRM range.
The analysis of Reference 7 has adequate conservation to permit an IRM Allowable Value of 120 divisions of a 125 division scale.
The Intermediate Range Monitor Neutron Flux - High Function must be OPERABLE during MODE 2 when control rods may be withdrawn and the potential for criticality exists. In MODE 5, when a cell with fuel has its control rod withdrawn, the IRMs provide monitoring for and protection against unexpected reactivity excursions. In MODE 1, the APRM System, the RWL, and the Rod Pattern Controller (RPC) provide protection against control rod withdrawal error events and the IRMs are not required.
1.b. Intermediate Range Monitor - Inop This trip signal provides assurance that a minimum number of IRMs are OPERABLE. Anytime an IRM mode switch is moved to any position other than "Operate," the detector voltage drops below a preset level, or a module is not plugged in, an inoperative trip signal will be received by the RPS unless the IRM is bypassed. Since only one IRM in each trip system may be bypassed, only one IRM in each RPS trip system may be inoperable without resulting in an RPS trip signal.
This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
General Electric BWR/6 STS              B 3.3.1.1-7                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Six channels of Intermediate Range Monitor - Inop with three channels in each trip system are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.
Since this Function is not assumed in the safety analysis, there is no Allowable Value for this Function.
This Function is required to be OPERABLE when the Intermediate Range Monitor Neutron Flux - High Function is required.
2.a. Average Power Range Monitor Neutron Flux - High, Setdown The APRM channels receive input signals from the local power range monitors (LPRM) within the reactor core to provide an indication of the power distribution and local power changes. The APRM channels average these LPRM signals to provide a continuous indication of average reactor power from a few percent to greater than RTP. For operation at low power (i.e., MODE 2), the Average Power Range Monitor Neutron Flux - High, Setdown Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operating transients in this power range. For most operation at low power levels, the Average Power Range Monitor Neutron Flux - High, Setdown Function will provide a secondary scram to the Intermediate Range Monitor Neutron Flux - High Function because of the relative setpoints.
With the IRMs at Range 9 or 10, it is possible that the Average Power Range Monitor Neutron Flux - High, Setdown Function will provide the primary trip signal for a corewide increase in power.
No specific safety analyses take direct credit for the Average Power Range Monitor Neutron Flux - High, Setdown Function. However, this Function indirectly ensures that, before the reactor mode switch is placed in the run position, reactor power does not exceed 25% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow. Therefore, it indirectly prevents fuel damage during significant reactivity increases with THERMAL POWER < 25% RTP.
The APRM System is divided into two groups of channels with three APRM channel inputs to each trip system. The system is designed to allow one channel in each trip system to be bypassed. Any one APRM channel in a trip system can cause the associated trip system to trip. Six channels of Average Power Range Monitor Neutron Flux - High, Setdown, with three channels in each trip system are required to be OPERABLE to ensure that no single failure will preclude a scram from this Function on a valid signal. In addition, to provide adequate coverage General Electric BWR/6 STS            B 3.3.1.1-8                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) of the entire core, at least 11 LPRM inputs are required for each APRM channel, with at least two LPRM inputs from each of the four axial levels at which the LPRMs are located.
The Allowable Value is based on preventing significant increases in power when THERMAL POWER is < 25% RTP.
The Average Power Range Monitor Neutron Flux - High, Setdown Function must be OPERABLE during MODE 2 when control rods may be withdrawn, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since the potential for criticality exists. In MODE 1, the Average Power Range Monitor Neutron Flux - High Function provides protection against reactivity transients and the RWL and RPC protect against control rod withdrawal error events.
2.b. Average Power Range Monitor Flow Biased Simulated Thermal Power - High The Average Power Range Monitor Flow Biased Simulated Thermal Power - High Function monitors neutron flux to approximate the THERMAL POWER being transferred to the reactor coolant. The APRM neutron flux is electronically filtered with a time constant representative of the fuel heat transfer dynamics to generate a signal proportional to the THERMAL POWER in the reactor. The trip level is varied as a function of recirculation drive flow (i.e., at lower core flows the setpoint is reduced proportional to the reduction in power experienced as core flow is reduced with a fixed control rod pattern) but is clamped at an upper limit that is always lower than the Average Power Range Monitor Fixed Neutron Flux - High Function Allowable Value. The Average Power Range Monitor Flow Biased Simulated Thermal Power - High Function provides protection against transients where THERMAL POWER increases slowly (such as the loss of feedwater heating event) and protects the fuel cladding integrity by ensuring that the MCPR SL is not exceeded. During these events, the THERMAL POWER increase does not significantly lag the neutron flux response and, because of a lower trip setpoint, will initiate a scram before the high neutron flux scram. For rapid neutron flux increase events, the THERMAL POWER lags the neutron flux and the Average Power Range Monitor Fixed Neutron Flux -
High Function will provide a scram signal before the Average Power Range Monitor Flow Biased Simulated Thermal Power - High Function setpoint is exceeded.
The APRM System is divided into two groups of channels with four APRM inputs to each trip system. The system is designed to allow one channel in each trip system to be bypassed. Any one Average Power Range Monitor channel in a trip system can cause the associated trip system to General Electric BWR/6 STS              B 3.3.1.1-9                                        Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) trip. Six channels of Average Power Range Monitor Flow Biased Simulated Thermal Power - High, with three channels in each trip system arranged in one-out-of-three logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. In addition, to provide adequate coverage of the entire core, at least 11 LPRM inputs are required for each APRM channel, with at least two LPRM inputs from each of the four axial levels at which the LPRMs are located. Each APRM channel receives one total drive flow signal representative of total core flow. The recirculation loop drive flow signals are generated by eight flow units. One flow unit from each recirculation loop is provided to each APRM channel. Total drive flow is determined by each APRM by summing up the flow signals provided to the APRM from the two recirculation loops.
The clamped Allowable Value is based on analyses that take credit for the Average Power Range Monitor Flow Biased Simulated Thermal Power - High Function for the mitigation of the loss of feedwater heater event. The THERMAL POWER time constant of < 7 seconds is based on the fuel heat transfer dynamics and provides a signal that is proportional to the THERMAL POWER.
The Average Power Range Monitor Flow Biased Simulated Thermal Power - High Function is required to be OPERABLE in MODE 1 when there is the possibility of generating excessive THERMAL POWER and potentially exceeding the SL applicable to high pressure and core flow conditions (MCPR SL). During MODES 2 and 5, other IRM and APRM Functions provide protection for fuel cladding integrity.
2.c. Average Power Range Monitor Fixed Neutron Flux - High The APRM channels provide the primary indication of neutron flux within the core and respond almost instantaneously to neutron flux increases.
The Average Power Range Monitor Fixed Neutron Flux - High Function is capable of generating a trip signal to prevent fuel damage or excessive RCS pressure. For the overpressurization protection analysis of Reference 3, the Average Power Range Monitor Fixed Neutron Flux -
High Function is assumed to terminate the main steam isolation valve (MSIV) closure event and, along with the safety/relief valves (S/RVs),
limits the peak reactor pressure vessel (RPV) pressure to less than the ASME Code limits. The control rod drop accident (CRDA) analysis (Ref. 8) takes credit for the Average Power Range Monitor Fixed Neutron Flux - High Function to terminate the CRDA.
The APRM System is divided into two groups of channels with four APRM channels inputting to each trip system. The system is designed to allow one channel in each trip system to be bypassed. Any one APRM channel General Electric BWR/6 STS          B 3.3.1.1-10                                        Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) in a trip system can cause the associated trip system to trip. Six channels of Average Power Range Monitor Fixed Neutron Flux - High with three channels in each trip system arranged in a one-out-of-three logic are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. In addition, to provide adequate coverage of the entire core, at least 11 LPRM inputs are required for each APRM channel, with at least two LPRM inputs from each of the four axial levels at which the LPRMs are located.
The Allowable Value is based on the Analytical Limit assumed in the CRDA analyses.
The Average Power Range Monitor Fixed Neutron Flux - High Function is required to be OPERABLE in MODE 1 where the potential consequences of the analyzed transients could result in the SLs (e.g., MCPR and RCS pressure) being exceeded. Although the Average Power Range Monitor Fixed Neutron Flux - High Function is assumed in the CRDA analysis that is applicable in MODE 2, the Average Power Range Monitor Neutron Flux
                    - High, Setdown Function conservatively bounds the assumed trip and, together with the assumed IRM trips, provides adequate protection.
Therefore, the Average Power Range Monitor Fixed Neutron Flux - High Function is not required in MODE 2.
2.d. Average Power Range Monitor - Inop This signal provides assurance that a minimum number of APRMs are OPERABLE. Anytime an APRM mode switch is moved to any position other than Operate, an APRM module is unplugged, the electronic operating voltage is low, or the APRM has too few LPRM inputs (< 11), an inoperative trip signal will be received by the RPS, unless the APRM is bypassed. Since only one APRM in each trip system may be bypassed, only one APRM in each trip system may be inoperable without resulting in an RPS trip signal. This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
Four channels of Average Power Range Monitor - Inop with two channels in each trip system are required to be OPERABLE to ensure that no single failure will preclude a scram from this Function on a valid signal.
There is no Allowable Value for this Function.
This Function is required to be OPERABLE in the MODES where the APRM Functions are required.
General Electric BWR/6 STS            B 3.3.1.1-11                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
: 3. Reactor Vessel Steam Dome Pressure - High An increase in the RPV pressure during reactor operation compresses the steam voids and results in a positive reactivity insertion. This causes the neutron flux and THERMAL POWER transferred to the reactor coolant to increase, which could challenge the integrity of the fuel cladding and the RCPB. No specific safety analysis takes direct credit for this Function. However, the Reactor Vessel Steam Dome Pressure -
High Function initiates a scram for transients that results in a pressure increase, counteracting the pressure increase by rapidly reducing core power. For the overpressurization protection analysis of Reference 3, the reactor scram (the analyses conservatively assume scram on the Average Power Range Monitor Fixed Neutron Flux - High signal, not the Reactor Vessel Steam Dome Pressure-High signal), along with the S/RVs, limits the peak RPV pressure to less than the ASME Section III Code limits.
High reactor pressure signals are initiated from four pressure transmitters that sense reactor pressure. The Reactor Vessel Steam Dome Pressure
                    - High Allowable Value is chosen to provide a sufficient margin to the ASME Section III Code limits during the event.
Four channels of Reactor Vessel Steam Dome Pressure - High Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. The Function is required to be OPERABLE in MODES 1 and 2 when the RCS is pressurized and the potential for pressure increase exists.
: 4. Reactor Vessel Water Level - Low, Level 3 Low RPV water level indicates the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, a reactor scram is initiated at Level 3 to substantially reduce the heat generated in the fuel from fission. The Reactor Vessel Water Level - Low, Level 3 Function is assumed in the analysis of the recirculation line break (Ref. 4). The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the Emergency Core Cooling Systems (ECCS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Reactor Vessel Water Level - Low, Level 3 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.
General Electric BWR/6 STS            B 3.3.1.1-12                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Four channels of Reactor Vessel Water Level - Low, Level 3 Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal.
The Reactor Vessel Water Level - Low, Level 3 Allowable Value is selected to ensure that, for transients involving loss of all normal feedwater flow, initiation of the low pressure ECCS at RPV Water Level 1 will not be required.
The Function is required in MODES 1 and 2 where considerable energy exists in the RCS resulting in the limiting transients and accidents. ECCS initiations at Reactor Vessel Water Level - Low Low, Level 2 and Low Low Low, Level 1 provide sufficient protection for level transients in all other MODES.
: 5. Reactor Vessel Water Level - High, Level 8 High RPV water level indicates a potential problem with the feedwater level control system, resulting in the addition of reactivity associated with the introduction of a significant amount of relatively cold feedwater.
Therefore, a scram is initiated at Level 8 to ensure that MCPR is maintained above the MCPR SL. The Reactor Vessel Water Level -
High, Level 8 Function is one of the many Functions assumed to be OPERABLE and capable of providing a reactor scram during transients analyzed in Reference 4. It is directly assumed in the analysis of feedwater controller failure, maximum demand (Ref. 5).
Reactor Vessel Water Level - High, Level 8 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. The Reactor Vessel Water Level - High, Level 8 Allowable Value is specified to ensure that the MCPR SL is not violated during the assumed transient.
Four channels of the Reactor Vessel Water Level - High, Level 8 Function, with two channels in each trip system arranged in a one-out-of-two logic, are available and are required to be OPERABLE when THERMAL POWER is  25% RTP to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. With THERMAL POWER < 25% RTP, this Function is not required since MCPR is not a concern below 25% RTP.
General Electric BWR/6 STS            B 3.3.1.1-13                                        Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
: 6. Main Steam Isolation Valve - Closure MSIV closure results in loss of the main turbine and the condenser as a heat sink for the Nuclear Steam Supply System and indicates a need to shut down the reactor to reduce heat generation. Therefore, a reactor scram is initiated on a Main Steam Isolation Valve - Closure signal before the MSIVs are completely closed in anticipation of the complete loss of the normal heat sink and subsequent overpressurization transient.
However, for the overpressurization protection analysis of Reference 3, the Average Power Range Monitor Fixed Neutron Flux - High Function, along with the S/RVs, limits the peak RPV pressure to less than the ASME Code limits. That is, the direct scram on position switches for MSIV closure events is not assumed in the overpressurization analysis.
Additionally, MSIV closure is assumed in the transients analyzed in Reference 5 (e.g., low steam line pressure, manual closure of MSIVs, high steam line flow). The reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the ECCS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
MSIV closure signals are initiated from position switches located on each of the eight MSIVs. Each MSIV has two position switches; one inputs to RPS trip system A while the other inputs to RPS trip system B. Each inboard and outboard MSIV inputs to a main steam line channel in each trip system, and each of the two trip logics within each RPS trip system receive parallel inputs from two of the four main steam lines. Thus, each RPS trip system receives an input from eight Main Steam Isolation Valve
                    - Closure channels, each consisting of one position switch. The logic for the Main Steam Isolation Valve - Closure Function is arranged such that either the inboard or outboard valve on both of the main steam lines (MSLs) in one of the two logics in each RPS trip system must close in order for a scram to occur.
The Main Steam Isolation Valve - Closure Allowable Value is specified to ensure that a scram occurs prior to a significant reduction in steam flow, thereby reducing the severity of the subsequent pressure transient.
Sixteen channels of the Main Steam Isolation Valve - Closure Function with eight channels in each trip system are required to be OPERABLE to ensure that no single instrument failure will preclude the scram from this Function on a valid signal. This Function is only required in MODE 1 since, with the MSIVs open and the heat generation rate high, a pressurization transient can occur if the MSIVs close. In MODE 2, the heat generation rate is low enough so that the other diverse RPS functions provide sufficient protection.
General Electric BWR/6 STS          B 3.3.1.1-14                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
: 7. Drywell Pressure - High High pressure in the drywell could indicate a break in the RCPB. A reactor scram is initiated to minimize the possibility of fuel damage and to reduce the amount of energy being added to the coolant and the drywell.
The Drywell Pressure - High Function is a secondary scram signal to Reactor Vessel Water Level - Low, Level 3 for LOCA events inside the drywell. The value is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
High drywell pressure signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside primary containment.
Four channels of Drywell Pressure - High Function, with two channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. The Function is required in MODES 1 and 2 where considerable energy exists in the RCS, resulting in the limiting transients and accidents.
8.a, 8.b. Scram Discharge Volume Water Level - High The SDV receives the water displaced by the motion of the CRD pistons during a reactor scram. Should this volume fill to a point where there is insufficient volume to accept the displaced water, control rod insertion would be hindered. Therefore, a reactor scram is initiated when the remaining free volume is still sufficient to accommodate the water from a full core scram. However, even though the two types of Scram Discharge Volume Water Level - High Functions are an input to the RPS logic, no credit is taken for a scram initiated from these Functions for any of the design basis accidents or transients analyzed in the FSAR. However, they are retained to ensure that the RPS remains OPERABLE.
SDV water level is measured by two diverse methods. The level in each of the two SDVs is measured by two float type level switches and two transmitters and trip units for a total of eight level signals. The outputs of these devices are arranged so that there is a signal from a level switch and a transmitter and trip unit to each RPS logic channel. The level measurement instrumentation satisfies the recommendations of Reference 9.
The Allowable Value is chosen low enough to ensure that there is sufficient volume in the SDV to accommodate the water from a full scram.
General Electric BWR/6 STS            B 3.3.1.1-15                                        Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Four channels of each type of Scram Discharge Volume Water Level -
High Function, with two channels of each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from these Functions on a valid signal. These Functions are required in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn. At all other times, this Function may be bypassed.
: 9. Turbine Stop Valve Closure, Trip Oil Pressure - Low Closure of the TSVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated at the start of TSV closure in anticipation of the transients that would result from the closure of these valves. The Turbine Stop Valve Closure, Trip Oil Pressure - Low Function is the primary scram signal for the turbine trip event analyzed in Reference 5. For this event, the reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the End of Cycle Recirculation Pump Trip (EOC-RPT) System, ensures that the MCPR SL is not exceeded.
Turbine Stop Valve Closure, Trip Oil Pressure - Low signals are initiated by the electrohydraulic control (EHC) fluid pressure at each stop valve.
Two independent pressure transmitters are associated with each stop valve. One of the two transmitters provides input to RPS trip system A; the other, to RPS trip system B. Each of the two trip logics within each RPS trip system receives parallel inputs from two of the four turbine stop valves. Thus, each RPS trip system receives an input from four Turbine Stop Valve Closure, Trip Oil Pressure - Low channels, each consisting of one pressure transmitter. The logic for the Turbine Stop Valve Closure, Trip Oil Pressure - Low Function is such that two TSVs in one of the two trip logics in each RPS trip system must close to produce a scram.
This Function must be enabled at THERMAL POWER  40% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, to consider this Function OPERABLE, the turbine bypass valves must remain shut at THERMAL POWER  40% RTP. The setpoint is feedwater temperature dependent as a result of the subcooling changes that affect the turbine first stage pressure/reactor power relationship. For RTP operation with feedwater temperature  420&deg;F, an allowable setpoint of  26.9% of control valve wide open turbine first stage pressure is provided by the bypass function.
The allowable setpoint is reduced to  22.5% of control valve wide open turbine first stage pressure for RTP operation with feedwater temperature
                    > 370&deg;F and < 420&deg;F.
General Electric BWR/6 STS            B 3.3.1.1-16                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Turbine Stop Valve Closure, Trip Oil Pressure - Low Allowable Value is selected to be high enough to detect imminent TSV closure thereby reducing the severity of the subsequent pressure transient.
Eight channels of Turbine Stop Valve Closure, Trip Oil Pressure - Low Function, with four channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is 40% RTP. This Function is not required when THERMAL POWER is
                    < 40% RTP since the Reactor Vessel Steam Dome Pressure - High and the Average Power Range Monitor Fixed Neutron Flux - High Functions are adequate to maintain the necessary safety margins.
: 10. Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Fast closure of the TCVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated on TCV fast closure in anticipation of the transients that would result from the closure of these valves. The Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Function is the primary scram signal for the generator load rejection event analyzed in Reference 5. For this event, the reactor scram reduces the amount of energy required to be absorbed and, along with the actions of the EOC-RPT System, ensures that the MCPR SL is not exceeded.
Turbine Control Valve Fast Closure, Trip Oil Pressure - Low signals are initiated by the EHC fluid pressure at each control valve. There is one pressure transmitter associated with each control valve, the signal from each transmitter being assigned to a separate RPS logic channel. This Function must be enabled at THERMAL POWER  40% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, to consider this Function OPERABLE, the turbine bypass valves must remain shut at THERMAL POWER  40% RTP. The basis for the setpoint of this automatic bypass is identical to that described for the Turbine Stop Valve Closure, Trip Oil Pressure - Low Function.
The Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Allowable Value is selected high enough to detect imminent TCV fast closure.
General Electric BWR/6 STS            B 3.3.1.1-17                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Four channels of Turbine Control Valve Fast Closure, Trip Oil Pressure -
Low Function, with two channels in each trip system arranged in a one-out-of-two logic, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This Function is required, consistent with the analysis assumptions, whenever THERMAL POWER is  40% RTP. This Function is not required when THERMAL POWER is < 40% RTP since the Reactor Vessel Steam Dome Pressure - High and the Average Power Range Monitor Fixed Neutron Flux - High Functions are adequate to maintain the necessary safety margins.
: 11. Reactor Mode Switch - Shutdown Position The Reactor Mode Switch - Shutdown Position Function provides signals, via the manual scram logic channels, that are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability. This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
The reactor mode switch is a single switch with four channels, each of which inputs into one of the RPS logic channels.
There is no Allowable Value for this Function since the channels are mechanically actuated based solely on reactor mode switch position.
Four channels of Reactor Mode Switch - Shutdown Position Function, with two channels in each trip system, are available and required to be OPERABLE. The Reactor Mode - Switch Shutdown Position Function is required to be OPERABLE in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.
: 12. Manual Scram The Manual Scram push button channels provide signals, via the manual scram logic channels, to each of the four RPS logic channels that are redundant to the automatic protective instrumentation channels and provide manual reactor trip capability. This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.
General Electric BWR/6 STS            B 3.3.1.1-18                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
There is one Manual Scram push button channel for each of the four RPS logic channels. In order to cause a scram it is necessary that at least one channel in each trip system be actuated.
There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.
Four channels of Manual Scram with two channels in each trip system arranged in a one-out-of-two logic, are available and required to be OPERABLE in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn.
ACTIONS            -----------------------------------REVIEWERS NOTE-----------------------------------
Certain LCO Completion Times are based on approved topical reports. In order for a licensee to use the times, the licensee must justify the Completion Times as required by the staff Safety Evaluation Report (SER) for the topical report.
A Note has been provided to modify the ACTIONS related to RPS instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable RPS instrumentation channels provide appropriate compensatory measures for separate, inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable RPS instrumentation channel.
A.1 and A.2 Because of the diversity of sensors available to provide trip signals and the redundancy of the RPS design, an allowable out of service time of 12 hours has been shown to be acceptable (Ref. 10) to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the associated Function's inoperable channel is in one trip system and the Function still maintains RPS trip capability (refer to Required Actions B.1, B.2, and C.1 Bases).
General Electric BWR/6 STS              B 3.3.1.1-19                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES ACTIONS (continued)
[Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel or the associated trip system must be placed in the tripped condition per Required Actions A.1 and A.2. Placing the inoperable channel in trip (or the associated trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.
Alternately, if it is not desired to place the channel (or trip system) in trip (e.g., as in the case where placing the inoperable channel in trip would result in a full scram), Condition D must be entered and its Required Action taken.
B.1 and B.2 Condition B exists when, for any one or more Functions, at least one required channel is inoperable in each trip system. In this condition, provided at least one channel per trip system is OPERABLE, the RPS still maintains trip capability for that Function, but cannot accommodate a single failure in either trip system.
Required Actions B.1 and B.2 limit the time the RPS scram logic for any Function would not accommodate single failure in both trip systems (e.g.,
one-out-of-one and one-out-of-one arrangement for a typical four channel Function). The reduced reliability of this logic arrangement was not evaluated in Reference 10 for the 12 hour Completion Time. Within the 6 hour allowance, the associated Function will have all required channels either OPERABLE or in trip (or in any combination) in one trip system.
Completing one of these Required Actions restores RPS to an equivalent reliability level as that evaluated in Reference 10, which justified a 12 hour allowable out of service time as presented in Condition A. The trip system in the more degraded state should be placed in trip or, alternatively, all the inoperable channels in that trip system should be placed in trip (e.g., a trip system with two inoperable channels could be in a more degraded state than a trip system with four inoperable channels, if the two inoperable channels are in the same Function while the four inoperable channels are all in different Functions). The decision as to which trip system is in the more degraded state should be based on prudent judgment and current plant conditions (i.e., what MODE the plant is in). If this action would result in a scram or recirculation pump trip, it is permissible to place the other trip system or its inoperable channels in trip.
General Electric BWR/6 STS              B 3.3.1.1-20                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES ACTIONS (continued)
The 6 hour Completion Time is judged acceptable based on the remaining capability to trip, the diversity of the sensors available to provide the trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of a scram. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.]
Alternately, if it is not desired to place the inoperable channels (or one trip system) in trip (e.g., as in the case where placing the inoperable channel or associated trip system in trip would result in a scram [or RPT]),
Condition D must be entered and its Required Action taken.
C.1 Required Action C.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same trip system for the same Function result in the Function not maintaining RPS trip capability. A Function is considered to be maintaining RPS trip capability when sufficient channels are OPERABLE or in trip (or the associated trip system is in trip), such that both trip systems will generate a trip signal from the given Function on a valid signal. For the typical Function with one-out-of-two taken twice logic and the IRM and APRM Functions, this would require both trip systems to have one channel OPERABLE or in trip (or the associated trip system in trip). For Function 6 (Main Steam Isolation Valve - Closure), maintaining RPS trip capability would require at least one trip logic in both trip systems to have each channel associated with the MSIVs in two MSLs (at least three different main steam lines total for both trip systems), OPERABLE or in trip (or the associated trip system in trip).
For Function 9 (Turbine Stop Valve Closure, Trip Oil Pressure - Low),
maintaining RPS trip capability would require at least one trip system logic in both trip systems to have two channels (at least three different turbine stop valves total for both trip systems) OPERABLE or in trip (or the associated trip system in trip).
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
General Electric BWR/6 STS              B 3.3.1.1-21                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES ACTIONS (continued)
D.1 Required Action D.1 directs entry into the appropriate Condition referenced in Table 3.3.1.1-1. The applicable Condition specified in the Table is Function and MODE or other specified condition dependent and may change as the Required Action of a previous Condition is completed.
Each time an inoperable channel has not met any Required Action of Condition A, B, or C, and the associated Completion Time has expired, Condition D will be entered for that channel and provides for transfer to the appropriate subsequent Condition.
E.1, F.1, G.1, and H.1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. The Completion Times are reasonable, based on operating experience, to reach the specified condition from full power conditions in an orderly manner and without challenging plant systems. In addition, the Completion Time of Required Action E.1 is consistent with the Completion Time provided in LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)."
I.1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by immediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are, therefore, not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.
SURVEILLANCE        -----------------------------------REVIEWERS NOTE-----------------------------------
REQUIREMENTS        Certain Frequencies are based on approved topical reports. In order for a licensee to use these Frequencies, the licensee must justify the Frequencies as required by the staff SER for the topical report.
General Electric BWR/6 STS              B 3.3.1.1-22                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Notes a and b are applied to the setpoint verification Surveillances for all RPS Instrumentation Functions in Table 3.3.1.1-1 unless one or more of the following exclusions apply:
: 1. Manual actuation circuits, automatic actuation logic circuits or instrument functions that derive input from contacts which have no associated sensor or adjustable device, e.g., limit switches, breaker position switches, manual actuation switches, float switches, proximity detectors, etc. are excluded. In addition, those permissives and interlocks that derive input from a sensor or adjustable device that is tested as part of another TS function are excluded.
: 2. Settings associated with safety relief valves are excluded. The performance of these components is already controlled (i.e., trended with as-left and as-found limits) under the ASME Code for Operation and Maintenance of Nuclear Power Plants testing program.
: 3. Functions and Surveillance Requirements which test only digital components are normally excluded. There is no expected change in result between SR performances for these components. Where separate as-left and as-found tolerance is established for digital component SRs, the requirements would apply.
As noted at the beginning of the SRs, the SRs for each RPS instrument Function are located in the SRs column of Table 3.3.1.1-1.
The Surveillances are modified by a Note to indicate that, when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the RPS reliability analysis (Ref. 10) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the RPS will trip when necessary.
General Electric BWR/6 STS                B 3.3.1.1-23                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.1.1.1 Performance of the CHANNEL CHECK 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 on one of the channels or 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 instrument has drifted outside its limit.
The agreement criteria includes an expectation of one decade of overlap when transitioning between neutron flux instrumentation. The overlap between SRMs and IRMs must be demonstrated prior to withdrawing SRMs from the fully inserted position since indication is being transitioned from the SRMs to the IRMs. This will ensure that reactor power will not be increased into a neutron flux region without adequate indication. The overlap between IRMs and APRMs is of concern when reducing power into the IRM range (entry into MODE 2 from MODE 1). On power increases, the system design will prevent further increases (by initiating a rod block) if adequate overlap is not maintained. Overlap between IRMs and APRMs exists when sufficient IRMs and APRMs concurrently have onscale readings such that the transition between MODE 1 and MODE 2 can be made without either APRM downscale rod block or IRM upscale rod block. Overlap between SRMs and IRMs similarly exists when, prior to withdrawing the SRMs from the fully inserted position, IRMs are above mid-scale on Range 1 before SRMs have reached the upscale rod block.
If overlap for a group of channels is not demonstrated (e.g., IRM/APRM overlap), the reason for the failure of the Surveillance should be determined and the appropriate channels(s) declared inoperable. Only those appropriate channels that are required in the current MODE or condition should be declared inoperable.
[ The Frequency of 12 hours is based upon operating experience that demonstrates channel failure is rare.
OR General Electric BWR/6 STS            B 3.3.1.1-24                                        Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
SR 3.3.1.1.2 To ensure that the APRMs are accurately indicating the true core average power, the APRMs are adjusted to the reactor power calculated from a heat balance if the heat balance calculated reactor power exceeds the APRM channel output by more than 2% RTP. If the heat balance calculated reactor power exceeds the APRM channel output by more than 2% RTP, the APRM is not declared inoperable, but must be adjusted consistent with the heat balance calculated power. If the APRM channel output cannot be properly adjusted, the channel is declared inoperable.
This Surveillance does not preclude making APRM channel adjustments, if desired, when the heat balance calculated reactor power is less than the APRM channel output. To provide close agreement between the APRM indicated power and to preserve operating margin, the APRM channels are normally adjusted to within +/-2% of the heat balance calculated reactor power [plus any gain adjustment required by LCO 3.2.4, "Average Power Range Monitor (APRM Setpoints)"].
However, this agreement is not required for OPERABILITY when APRM output indicates a higher reactor power than the heat balance calculated reactor power.
[ The Frequency of once per 7 days is based on minor changes in LPRM sensitivity, which could affect the APRM reading between performances of SR 3.3.1.1.6.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS              B 3.3.1.1-25                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
A restriction to satisfying this SR when < 25% RTP is provided that requires the SR to be met only at  25% RTP because it is difficult to accurately maintain APRM indication of core THERMAL POWER consistent with a heat balance when < 25% RTP. At low power levels, a high degree of accuracy is unnecessary because of the large inherent margin to thermal limits (MCPR and APLHGR). At  25% RTP, the Surveillance is required to have been satisfactorily performed in accordance with SR 3.0.2. A Note is provided which allows an increase in THERMAL POWER above 25% if the Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours after reaching or exceeding 25% RTP. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.
SR 3.3.1.1.3 The Average Power Range Monitor Flow Biased Simulated Thermal Power - High Function uses the recirculation loop drive flows to vary the trip setpoint. This SR ensures that the total loop drive flow signals from the flow unit used to vary the setpoint are appropriately compared to a calibrated flow signal and therefore the APRM Function accurately reflects the required setpoint as a function of flow. Each flow signal from the respective flow unit must be  105% of the calibrated flow signal. If the flow unit signal is not within the limit, the APRMs that receive an input from the inoperable flow unit must be declared inoperable.
[ The Frequency of 7 days is based on engineering judgment, operating experience, and the reliability of this instrumentation.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.3.1.1-26                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.1.1.4 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the 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 methodology.
As noted, SR 3.3.1.1.4 is not required to be performed when entering MODE 2 from MODE 1 since testing of the MODE 2 required IRM and APRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This allows entry into MODE 2 if the Frequency is not met per SR 3.0.2. In this event, the SR must be performed within 12 hours after entering MODE 2 from MODE 1. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.
[ A Frequency of 7 days provides an acceptable level of system average unavailability over the Frequency interval and is based on reliability analysis (Ref. 10).
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.3.1.1-27                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.1.1.5 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended Function. A 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 accordance with Reference 10, the scram contacts must be tested as part of the Manual Scram Function. [ A Frequency of 7 days provides an acceptable level of system average availability over the Frequency and is based on the reliability analysis of Reference 10. (The Manual Scram Function's CHANNEL FUNCTIONAL TEST Frequency was credited in the analysis to extend many automatic scram Functions' Frequencies.)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.1.1.6 LPRM gain settings are determined from the local flux profiles measured by the Traversing Incore Probe (TIP) System. This establishes the relative local flux profile for appropriate representative input to the APRM System. [ The 1000 MWD/T Frequency is based on operating experience with LPRM sensitivity changes.
General Electric BWR/6 STS              B 3.3.1.1-28                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.1.1.7 and SR 3.3.1.1.10 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the 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 methodology. [ The 92 day Frequency of SR 3.3.1.1.7 is based on the reliability analysis of Reference 10.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
[ The 18 month Frequency of SR 3.3.1.1.10 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.
General Electric BWR/6 STS                B 3.3.1.1-29                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.1.1.7 for the designated function is modified by two Notes as identified in Table 3.3.1.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the [LTSP] is used in the plant surveillance procedures [Nominal Trip Setpoint (NTSP)], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP], then the channel shall be declared inoperable.
The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
General Electric BWR/6 STS              B 3.3.1.1-30                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.1.1.8 The calibration of trip units provides a check of the actual trip setpoints.
The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.1.1-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is conservative with respect to the Allowable Value, the channel performance is still within the requirements of the plant safety analysis.
Under these conditions, the setpoint must be readjusted to the [LTSP]
within the as-left tolerance as accounted for in the appropriate setpoint methodology.
[ The Frequency of 92 days for SR 3.3.1.1.8 is based on the reliability analysis of Reference 10.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.1.1.8 for the designated functions is modified by two Notes as identified in Table 3.3.1.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the General Electric BWR/6 STS                B 3.3.1.1-31                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued) channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the [LTSP] is used in the plant surveillance procedures [NTSP], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP], then the channel shall be declared inoperable.
The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
SR 3.3.1.1.9 and SR 3.3.1.1.11 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to the [LTSP] within the as-left tolerance to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
Note 1 states that 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. Changes in neutron detector sensitivity are compensated for by performing the calorimetric calibration (SR 3.3.1.1.2) and the LPRM calibration against the TIPs (SR 3.3.1.1.6). A second Note is provided that requires the APRM and IRM SRs to be performed within 12 hours of entering MODE 2 from MODE 1. Testing of the MODE 2 APRM and IRM Functions cannot be performed in MODE 1 without utilizing jumpers, lifted leads, or movable links. This Note allows entry into MODE 2 from MODE 1 if the associated Frequency is not met per SR 3.0.2. Twelve hours is based on operating experience and in consideration of providing a reasonable time in which to complete the SR.
[ The Frequency of SR 3.3.1.1.9 is based upon the assumption of a 184 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis. The Frequency of SR 3.3.1.1.11 is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
OR General Electric BWR/6 STS            B 3.3.1.1-32                                        Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SRs 3.3.1.1.9 and 3.3.1.1.11 for the designated functions are modified by two Notes as identified in Table 3.3.1.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the
[LTSP] is used in the plant surveillance procedures [NTSP], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP],
then the channel shall be declared inoperable.
The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
General Electric BWR/6 STS              B 3.3.1.1-33                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.1.1.12 The Average Power Range Monitor Flow Biased Simulated Thermal Power - High Function uses an electronic filter circuit to generate a signal proportional to the core THERMAL POWER from the APRM neutron flux signal. This filter circuit is representative of the fuel heat transfer dynamics that produce the relationship between the neutron flux and the core THERMAL POWER. The filter time constant must be verified to ensure that the channel is accurately reflecting the desired parameter.
[ The Frequency of 18 months is based on engineering judgment and reliability of the components.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.1.1.12 is modified by two Notes as identified in Table 3.3.1.1-1.
The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value.
Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition.
The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the [LTSP] is used in the plant surveillance procedures [NTSP], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP], then the channel shall be declared inoperable.
General Electric BWR/6 STS                B 3.3.1.1-34                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
SR 3.3.1.1.13 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The functional testing of control rods, in LCO 3.1.3, "Control Rod OPERABILITY," and SDV vent and drain valves, in LCO 3.1.8, "Scram Discharge Volume (SDV) Vent and Drain Valves," overlaps this Surveillance to provide complete testing of the assumed safety function.
[ The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.1.1.14 This SR ensures that scrams initiated from the Turbine Stop Valve Closure, Trip Oil Pressure - Low and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions will not be inadvertently bypassed when THERMAL POWER is  40% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint General Electric BWR/6 STS                B 3.3.1.1-35                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued) methodology are incorporated into the actual setpoint. Because main turbine bypass flow can affect this setpoint nonconservatively (THERMAL POWER is derived from turbine first stage pressure), the main turbine bypass valves must remain closed at THERMAL POWER  40% RTP to ensure that the calibration remains valid.
If any bypass channel setpoint is nonconservative (i.e., the Functions are bypassed at  40% RTP, either due to open main turbine bypass valve(s) or other reasons), then the affected Turbine Stop Valve, Trip Oil Pressure
                    - Low and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions are considered inoperable. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met and the channel is considered OPERABLE.
[ The Frequency of 18 months is based on engineering judgment and reliability of the components.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.1.1.15 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The RPS RESPONSE TIME acceptance criteria are included in Reference 11.
RPS RESPONSE TIME may be verified by actual response time measurements in any series of sequential, overlapping, or total channel measurements.
General Electric BWR/6 STS                B 3.3.1.1-36                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)
[-----------------------------------REVIEWERS NOTE----------------------------------
The following Bases are applicable for plants adopting NEDO-32291-A and/or Supplement 1.
However, the sensors for Functions 3, 4, and 5 are allowed to be excluded from specific RPS RESPONSE TIME measurement if the conditions of Reference 12 are satisfied. If these conditions are satisfied, sensor response time may be allocated based on either assumed design sensor response time or the manufacturer's stated design response time.
When the requirements of Reference 12 are not satisfied, sensor response time must be measured. Furthermore, measurement of the instrument loops response times for Functions 3, 4, and 5 is not required if the conditions of Reference 13 are satisfied.]
As noted, neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an instantaneous response time.
[ RPS RESPONSE TIME tests are conducted on an 18 month STAGGERED TEST BASIS. Note 2 requires STAGGERED TEST BASIS Frequency to be determined based on 4 channels per trip system, in lieu of the 8 channels specified in Table 3.3.1.1-1 for the MSIV Closure Function. This Frequency is based on the logic interrelationships of the various channels required to produce an RPS scram signal. Therefore, staggered testing results in response time verification of these channels 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 time degradation, but not channel failure, are infrequent.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.3.1.1-37                                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 BASES REFERENCES          1. Regulatory Guide 1.105, Revision 3, "Setpoints for Safety-Related Instrumentation."
: 2. FSAR, Figure [ ].
: 3. FSAR, Section [5.2.2].
: 4. FSAR, Section [6.3.3].
: 5. FSAR, Chapter [15].
: 6. FSAR, Section [15.4.1].
: 7. NEDO-23842, "Continuous Control Rod Withdrawal in the Startup Range," April 18, 1978.
: 8. FSAR, Section [15.4.9].
: 9. Letter, P. Check (NRC) to G. Lainas (NRC), "BWR Scram Discharge System Safety Evaluation," December 1, 1980.
: 10. NEDO-30851-P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System," March 1988.
: 11. FSAR, Table [ ].
[12. NEDO-32291-A, "System Analyses For the Elimination of Selected Response Time Testing Requirements," October 1995.
: 13. NEDO-32291-A, Supplement 1, "System Analyses for The Elimination of Selected Response Time Testing Requirements,"
October 1999.]
General Electric BWR/6 STS          B 3.3.1.1-38                                    Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 Table B 3.3.1.1-1 (page 1 of 2)
RPS Instrumentation Sensor Diversity Scram Sensors for Initiating Events RPV Variables            Anticipatory        Fuel Initiation Events              (a)    (b)  (c)    (d)    (e)      (f)    (g)
MSIV Closure                                x            x                        x      x Turbine Trip (w/bypass)                      x                    x      x                x Generator Trip (w/bypass)                    x                    x                        x Pressure Regulator Failure                  x      x    x                        x      x (primary pressure decrease)
(MSIV closure trip)
Pressure Regulator Failure                  x                            x                x (primary pressure decrease)
(Level 8 trip)
Pressure Regulator Failure                  x                                              x (primary pressure increase)
Feedwater Controller Failure                x      x                    x                x (high reactor water level)
Feedwater Controller Failure                x            x                        x (low reactor water level)
Loss of Condenser Vacuum                    x                            x        x      x Loss of AC Power (loss of                    x            x              x        x transformer)
Loss of AC Power (loss of                    x            x      x      x        x      x grid connections)
(a)    Reactor Vessel Steam Dome Pressure - High (b)    Reactor Vessel Water Level - High, Level 8 (c)    Reactor Vessel Water Level - Low, Level 3 (d)    Turbine Control Valve Fast Closure (e)    Turbine Stop Valve - Closure (f)    Main Steam Isolation Valve - Closure (g)    Average Power Range Monitor Neutron Flux - High General Electric BWR/6 STS              B 3.3.1.1-39                                      Rev. 5.0
 
RPS Instrumentation B 3.3.1.1 Table B 3.3.1.1-1 (page 2 of 2)
RPS Instrumentation Sensor Diversity
---------------------------------------------REVIEWERS NOTE--------------------------------------------
This Table for illustration purposes only.
General Electric BWR/6 STS                    B 3.3.1.1-40                                                Rev. 5.0
 
SRM Instrumentation B 3.3.1.2 B 3.3 INSTRUMENTATION B 3.3.1.2 Source Range Monitor (SRM) Instrumentation BASES BACKGROUND          The SRMs provide the operator with information relative to the neutron level at very low flux levels in the core. As such, the SRM indication is used by the operator to monitor the approach to criticality and to determine when criticality is achieved. The SRMs are maintained fully inserted until the count rate is greater than a minimum allowed count rate (a control rod block is set at this condition). After SRM to intermediate range monitor (IRM) overlap is demonstrated (as required by SR 3.3.1.1.1), the SRMs are normally fully withdrawn from the core.
The SRM subsystem of the Neutron Monitoring System (NMS) consists of five channels. Each of the SRM channels can be bypassed, but only one at any given time, by the operation of a bypass switch. Each channel includes one detector that can be physically positioned in the core. Each detector assembly consists of a miniature fission chamber with associated cabling, signal conditioning equipment, and electronics associated with the various SRM functions. The signal conditioning equipment converts the current pulses from the fission chamber to analog DC currents that correspond to the count rate. Each channel also includes indication, alarm, and control rod blocks. However, this LCO specifies OPERABILITY requirements only for the monitoring and indication functions of the SRMs.
During refueling, shutdown, and low power operations, the primary indication of neutron flux levels is provided by the SRMs or special movable detectors connected to the normal SRM circuits. The SRMs provide monitoring of reactivity changes during fuel or control rod movement and give the control room operator early indication of unexpected subcritical multiplication that could be indicative of an approach to criticality.
APPLICABLE          Prevention and mitigation of prompt reactivity excursions during refueling SAFETY              and low power operation are provided by:
ANALYSES LCO 3.9.1,      "Refueling Equipment Interlocks,"
LCO 3.1.1,      "SHUTDOWN MARGIN (SDM),"
LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation,"
Intermediate Range Monitor (IRM) Neutron Flux High and Average Power Range Monitor (APRM) Neutron Flux -
High, Setdown Functions, and LCO 3.3.2.1, "Control Rod Block Instrumentation."
General Electric BWR/6 STS            B 3.3.1.2-1                                      Rev. 5.0
 
SRM Instrumentation B 3.3.1.2 BASES APPLICABLE SAFETY ANALYSES (continued)
The SRMs have no safety function and are not assumed to function during any design basis accident or transient analysis. However, the SRMs provide the only on scale monitoring of neutron flux levels during startup and refueling. Therefore, they are being retained in the Technical Specifications.
LCO                During startup in MODE 2, four of the five SRM channels are required to be OPERABLE to monitor the reactor flux level prior to and during control rod withdrawal, to monitor subcritical multiplication and reactor criticality, and to monitor neutron flux level and reactor period until the flux level is sufficient to maintain the IRM on Range 3 or above. All channels but one are required in order to provide a representation of the overall core response during those periods when reactivity changes are occurring throughout the core.
In MODES 3 and 4, with the reactor shut down, two SRM channels provide redundant monitoring of flux levels in the core.
In MODE 5, during a spiral offload or reload, an SRM outside the fueled region will no longer be required to be OPERABLE, since it is not capable of monitoring neutron flux in the fueled region of the core. Thus, CORE ALTERATIONS are allowed in a quadrant with no OPERABLE SRM in an adjacent quadrant, as provided in the Table 3.3.1.2-1, footnote (b),
requirement that the bundles being spiral reloaded or spiral offloaded are all in a single fueled region containing at least one OPERABLE SRM is met. Spiral reloading and offloading encompass reloading or offloading a cell on the edges of a continuous fueled region (the cell can be reloaded or offloaded in any sequence).
In nonspiral routine operations, two SRMs are required to be OPERABLE to provide redundant monitoring of reactivity changes occurring in the reactor core. Because of the local nature of reactivity changes during refueling, adequate coverage is provided by requiring one SRM to be OPERABLE in the quadrant of the reactor core where CORE ALTERATIONS are being performed and the other SRM to be OPERABLE in an adjacent quadrant containing fuel. These requirements ensure that the reactivity of the core will be continuously monitored during CORE ALTERATIONS.
Special movable detectors, according to Table 3.3.1.2-1, footnote (c),
may be used during CORE ALTERATIONS in place of the normal SRM nuclear detectors. These special detectors must be connected to the normal SRM circuits in the NMS such that the applicable neutron flux indication can be generated. These special detectors provide more General Electric BWR/6 STS            B 3.3.1.2-2                                      Rev. 5.0
 
SRM Instrumentation B 3.3.1.2 BASES LCO (continued) flexibility in monitoring reactivity changes during fuel loading, since they can be positioned anywhere within the core during refueling. They must still meet the location requirements of SR 3.3.1.2.2, and all other required SRs for SRMs.
For an SRM channel to be considered OPERABLE, it must be providing neutron flux monitoring indication.
APPLICABILITY      The SRMs are required to be OPERABLE in MODES 2, 3, 4, and 5, prior to the IRMs being on scale on Range 3 to provide for neutron monitoring.
In MODE 1, the APRMs provide adequate monitoring of reactivity changes in the core; therefore, the SRMs are not required. In MODE 2, with IRMs on Range 3 or above, the IRMs provide adequate monitoring and the SRMs are not required.
ACTIONS            A.1 and B.1 In MODE 2, with the IRMs on Range 2 or below, SRMs provide the means of monitoring core reactivity and criticality. With any number of the required SRMs inoperable, the ability to monitor is degraded.
Therefore, a limited time is allowed to restore the inoperable channels to OPERABLE status.
Providing that at least one SRM remains OPERABLE, Required Action A.1 allows 4 hours to restore the required SRMs to OPERABLE status. This is a reasonable time since there is adequate capability remaining to monitor the core, limited risk of an event during this time, and sufficient time to take corrective actions to restore the required SRMs to OPERABLE status or to establish alternate IRM monitoring capability.
During this time, control rod withdrawal and power increase are not precluded by this Required Action. Having the ability to monitor the core with at least one SRM, proceeding to IRM Range 3 or greater (with overlap verified by SR 3.3.1.1.1) and thereby exiting the Applicability of this LCO, is acceptable for ensuring adequate core monitoring and allowing continued operation. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.]
With four required SRMs inoperable, Required Action B.1 allows no positive changes in reactivity (control rod withdrawal must be immediately suspended) due to the inability to monitor the changes. Required Action A.1 still applies and allows 4 hours to restore monitoring capability prior to requiring control rod insertion. This allowance is based on the limited risk of an event during this time, provided that no control rod withdrawals are allowed, and the desire to concentrate efforts on repair, rather than to immediately shut down, with no SRMs OPERABLE.
General Electric BWR/6 STS            B 3.3.1.2-3                                        Rev. 5.0
 
SRM Instrumentation B 3.3.1.2 BASES ACTIONS (continued)
C.1 In MODE 2, if the required number of SRMs is not restored to OPERABLE status within the allowed Completion Time, the reactor shall be placed in MODE 3. With all control rods fully inserted, the core is in its least reactive state with the most margin to criticality. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 in an orderly manner and without challenging plant systems.
D.1 and D.2 With one or more required SRM channels inoperable in MODE 3 or 4, the neutron flux monitoring capability is degraded or nonexistent. The requirement to fully insert all insertable control rods ensures that the reactor will be at its minimum reactivity level while no neutron monitoring capability is available. Placing the reactor mode switch in the shutdown position prevents subsequent control rod withdrawal by maintaining a control rod block. The allowed Completion Time of 1 hour is sufficient to accomplish the Required Action, and takes into account the low probability of an event requiring the SRM occurring during this time.
E.1 and E.2 With one or more required SRMs inoperable in MODE 5, the capability to detect local reactivity changes in the core during refueling is degraded.
CORE ALTERATIONS must be immediately suspended, and action must be immediately initiated to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Suspending CORE ALTERATIONS prevents the two most probable causes of reactivity changes, fuel loading and control rod withdrawal, from occurring.
Inserting all insertable control rods ensures that the reactor will be at its minimum reactivity, given that fuel is present in the core. Suspension of CORE ALTERATIONS shall not preclude completion of the movement of a component to a safe, conservative position.
Action (once required to be initiated) to insert control rods must continue until all insertable rods in core cells containing one or more fuel assemblies are inserted.
General Electric BWR/6 STS            B 3.3.1.2-4                                          Rev. 5.0
 
SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE        The SRs for each SRM Applicable MODE or other specified condition are REQUIREMENTS        found in the SRs column of Table 3.3.1.2-1.
SR 3.3.1.2.1 and SR 3.3.1.2.3 Performance of the CHANNEL CHECK 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 the same parameter indicated on other similar 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 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 instrument has drifted outside its limit.
[ The Frequency of once every 12 hours for SR 3.3.1.2.1 is based on operating experience that demonstrates channel failure is rare. While in MODES 3 and 4, reactivity changes are not expected; therefore, the 12 hour Frequency is relaxed to 24 hours for SR 3.3.1.2.3.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
General Electric BWR/6 STS                B 3.3.1.2-5                                                      Rev. 5.0
 
SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.1.2.2 To provide adequate coverage of potential reactivity changes in the core, one SRM is required to be OPERABLE in the quadrant where CORE ALTERATIONS are being performed, and the other OPERABLE SRM must be in an adjacent quadrant containing fuel. Note 1 states that this SR is required to be met only during CORE ALTERATIONS. It is not required to be met at other times in MODE 5 since core reactivity changes are not occurring. This Surveillance consists of a review of plant logs to ensure that SRMs required to be OPERABLE for given CORE ALTERATIONS are, in fact, OPERABLE. In the event that only one SRM is required to be OPERABLE, per Table 3.3.1.2-1, footnote (b), only the
: a. portion of this SR is required. Note 2 clarifies that more than one of the three requirements can be met by the same OPERABLE SRM. [ The 12 hour Frequency is based upon operating experience and supplements operational controls over refueling activities, which include steps to ensure that the SRMs required by the LCO are in the proper quadrant.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.1.2.4 This Surveillance consists of a verification of the SRM instrument readout to ensure that the SRM reading is greater than a specified minimum count rate. This ensures that the detectors are indicating count rates indicative of neutron flux levels within the core. With few fuel assemblies loaded, the SRMs will not have a high enough count rate to satisfy the SR.
Therefore, allowances are made for loading sufficient "source" material, in the form of irradiated fuel assemblies, to establish the minimum count rate.
General Electric BWR/6 STS                B 3.3.1.2-6                                                      Rev. 5.0
 
SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE REQUIREMENTS (continued)
To accomplish this, the SR is modified by a Note that states that the count rate is not required to be met on an SRM that has less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies are in the associated core quadrant. With four or less fuel assemblies loaded around each SRM and no other fuel assemblies in the associated quadrant, even with a control rod withdrawn the configuration will not be critical.
[ The Frequency is based upon channel redundancy and other information available in the control room, and ensures that the required channels are frequently monitored while core reactivity changes are occurring. When no reactivity changes are in progress, the Frequency is relaxed from 12 hours to 24 hours.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.1.2.5 and SR 3.3.1.2.6 Performance of a CHANNEL FUNCTIONAL TEST demonstrates the associated channel will function properly. 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. SR 3.3.1.2.5 is required in MODE 5 and ensures that the channels are OPERABLE while core reactivity changes could be in progress. [ This 7 day Frequency is reasonable, based on operating experience and on other Surveillances (such as a CHANNEL CHECK) that ensure proper functioning between CHANNEL FUNCTIONAL TESTS.
General Electric BWR/6 STS                B 3.3.1.2-7                                                      Rev. 5.0
 
SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.1.2.6 is required in MODE 2 with IRMs on Range 2 or below and in MODES 3 and 4. [ Since core reactivity changes do not normally take place, the Frequency has been extended from 7 days to 31 days. The 31 day Frequency is based on operating experience and on other Surveillances (such as (CHANNEL CHECK) that ensure proper functioning between CHANNEL FUNCTIONAL TESTS.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
Verification of the signal to noise ratio also ensures that the detectors are inserted to a normal operating level. In a fully withdrawn condition, the detectors are sufficiently removed from the fueled region of the core to essentially eliminate neutrons from reaching the detector. Any count rate obtained while fully withdrawn is assumed to be "noise" only.
The Note to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability. The SR must be performed in MODE 2 within 12 hours of entering MODE 2 with IRMs on Range 2 or below. The allowance to enter the Applicability with the Frequency not met is reasonable, based on the limited time of 12 hours allowed after entering the Applicability and the inability to perform the General Electric BWR/6 STS                B 3.3.1.2-8                                                      Rev. 5.0
 
SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE REQUIREMENTS (continued)
Surveillance while at higher power levels. Although the Surveillance could be performed while on IRM Range 3, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances.
SR 3.3.1.2.7 Performance of a CHANNEL CALIBRATION verifies the performance of the SRM detectors and associated circuitry. [ The Frequency considers the plant conditions required to perform the test, the ease of performing the test, and the likelihood of a change in the system or component status.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
The neutron detectors are excluded from the CHANNEL CALIBRATION because they cannot readily be adjusted. The detectors are fission chambers that are designed to have a relatively constant sensitivity over the range, and with an accuracy specified for a fixed useful life.
Note 2 to the Surveillance allows the Surveillance to be delayed until entry into the specified condition of the Applicability. The SR must be performed in MODE 2 within 12 hours of entering MODE 2 with IRMs on Range 2 or below. The allowance to enter the Applicability with the Frequency not met is reasonable, based on the limited time of 12 hours allowed after entering the Applicability and the inability to perform the Surveillance while at higher power levels. Although the Surveillance could be performed while on IRM Range 3, the plant would not be expected to maintain steady state operation at this power level. In this event, the 12 hour Frequency is reasonable, based on the SRMs being otherwise verified to be OPERABLE (i.e., satisfactorily performing the CHANNEL CHECK) and the time required to perform the Surveillances.
There is a plant specific program which verifies that the instrument General Electric BWR/6 STS                B 3.3.1.2-9                                                      Rev. 5.0
 
SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE REQUIREMENTS (continued) channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology.
REFERENCES          None.
General Electric BWR/6 STS          B 3.3.1.2-10                                      Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 B 3.3 INSTRUMENTATION B 3.3.2.1 Control Rod Block Instrumentation BASES BACKGROUND          Control rods provide the primary means for control of reactivity changes.
Control rod block instrumentation includes channel sensors, logic circuitry, switches, and relays that are designed to ensure that specified fuel design limits are not exceeded for postulated transients and accidents. During high power operation, the rod withdrawal limiter (RWL) provides protection for control rod withdrawal error events. During low power operations, control rod blocks from the rod pattern controller (RPC) enforce specific control rod sequences designed to mitigate the consequences of the control rod drop accident (CRDA). During shutdown conditions, control rod blocks from the Reactor Mode Switch - Shutdown Position ensure that all control rods remain inserted to prevent inadvertent criticalities.
The protection and monitoring functions of the control rod block instrumentation 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 include LSSSs for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical 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 Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur.
                    -------------------------------- REVIEWER'S NOTE ----------------------------------
The term "Limiting Trip Setpoint" [LTSP] is generic terminology for the calculated trip setting (setpoint) value calculated by means of the plant specific setpoint methodology documented in a document controlled under 10 CFR 50.59. The term [LTSP] indicates that no additional margin has been added between the Analytical Limit and the calculated trip setting.
General Electric BWR/6 STS                B 3.3.2.1-1                                          Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES BACKGROUND (continued)
                    "Nominal Trip Setpoint [NTSP]" is the suggested terminology for the actual setpoint implemented in the plant surveillance procedures where margin has been added to the calculated [LTSP]. The as-found and as-left tolerances will apply to the [NTSP] implemented in the Surveillance procedures to confirm channel performance.
Licensees are to insert the name of the document(s) controlled under 10 CFR 50.59 that contain the methodology for calculating the as-left and as-found tolerances in Note c of Table 3.3.2.1-1, for the phrase "[insert the name of a document controlled under 10 CFR 50.59 such as the Technical Requirements Manual or any document incorporated into the facility FSAR]" throughout these Bases.
If the [LTSP] is not included in SR 3.3.2.1.7, the plant specific location for the [LTSP] or [NTSP] must be cited in Note c of Table 3.3.2.1-1. The brackets indicate plant specific terms may apply, as reviewed and approved by the NRC.
The [Limiting Trip Setpoint (LTSP)] specified in Table 3.3.2.1-1 is a predetermined setting for a protection channel chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the SL would not be exceeded. As such, the
[LTSP] accounts for uncertainties in setting the channel (e.g., calibration),
uncertainties in how the channel might actually perform (e.g.,
repeatability), changes in the point of action of the channel 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 [LTSP] ensures that SLs are not exceeded. Therefore, the [LTSP] meets the definition of an LSSS (Ref. 1).
The Allowable Values specified in SR 3.3.2.1.7 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 surveillance interval.
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)." Relying solely on the [LTSP] to define OPERABILITY General Electric BWR/6 STS                B 3.3.2.1-2                                                      Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES BACKGROUND (continued) in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as found" value of a protection channel 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 protection channel with a setting that has been found to be different from the [LTSP] due to some drift of the setting may still be OPERABLE because drift is to be expected. This expected drift would have been specifically accounted for in the setpoint methodology for calculating the [LTSP] and thus the automatic protective action would still have ensured that the SL would not be exceeded with the "as found" setting of the protection channel. Therefore, the channel would still be OPERABLE because it would have performed its safety function and the only corrective action required would be to reset the channel within the established as-left tolerance around [LTSP] to account for further drift during the next surveillance interval. Note that, although the channel is OPERABLE under these circumstances, the trip setpoint must be left adjusted to a value within the as-left tolerance, 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 (as-found criteria).
However, there is also some point beyond which the channel may not be able to perform its function due to, for example, greater than expected drift. This value needs to be specified in the Technical Specifications in order to define OPERABILITY of the channels and is designated as the Allowable Value.
If the actual setting (as-found setpoint) of the channel is found to be conservative with respect to the Allowable Value but is beyond the as-found tolerance band, the channel is OPERABLE, but degraded. The degraded condition will be further evaluated during performance of the SR. This evaluation will consist of resetting the channel setpoint to the
[Nominal Trip Setpoint (NTSP)] (within the allowed tolerance), and evaluating the channel response. If the channel is functioning as required and is expected to pass the next surveillance, then the channel is OPERABLE and can be restored to service at the completion of the surveillance. After the surveillance is completed, the channel as-found condition will be entered into the Corrective Action Program for further evaluation.
The purpose of the RWL is to limit control rod withdrawal to preclude a MCPR Safety Limit (SL) violation. The RWL supplies a trip signal to the Rod Control and Information System (RCIS) to appropriately inhibit control rod withdrawal during power operation equal to or greater than the General Electric BWR/6 STS            B 3.3.2.1-3                                        Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES BACKGROUND (continued) low power setpoint (LPSP). The RWL has two channels, either of which can initiate a control rod block when the channel output exceeds the control rod block setpoint. The rod block logic circuitry in the RCIS is arranged as two redundant and separate logic circuits. These circuits are energized when control rod movement is allowed. The output of each logic circuit is coupled to a comparator by the use of isolation devices in the rod drive control cabinet. The two logic circuit signals are compared and rod blocks are applied when either circuit trip signal is present.
Control rod withdrawal is permitted only when the two signals agree.
Each rod block logic circuit receives control rod position indication from a separate channel of the Rod Position Information System, each with a set of reed switches for control rod position indication. Control rod position is the primary data input for the RWL. First stage turbine pressure is used to determine reactor power level, with an LPSP and a high power setpoint (HPSP) used to determine allowable control rod withdrawal distances.
Below the LPSP, the RWL is automatically bypassed (Ref. 2).
The purpose of the RPC is to ensure control rod patterns during startup are such that only specified control rod sequences and relative positions are allowed over the operating range from all control rods inserted to 10% RTP. The sequences effectively limit the potential amount and rate of reactivity increase during a CRDA. The RPC, in conjunction with the RCIS, will initiate control rod withdrawal and insert blocks when the actual sequence deviates beyond allowances from the specified sequence. The rod block logic circuitry is the same as that described above. The RPC also uses the turbine first stage pressure to determine when reactor power is above the power at which the RPC is automatically bypassed (Ref. 2).
With the reactor mode switch in the shutdown position, a control rod withdrawal block is applied to all control rods to ensure that the shutdown condition is maintained. This function prevents criticality resulting from inadvertent control rod withdrawal during MODE 3 or 4, or during MODE 5 when the reactor mode switch is required to be in the shutdown position. The reactor mode switch has two channels, with each providing inputs into a separate rod block circuit. A rod block in either circuit will provide a control rod block to all control rods.
Permissive and interlock setpoints allow the blocking of trips during plant startups, and restoration of trips when the permissive conditions are not satisfied, but they are not explicitly modeled in the Safety Analyses.
These permissives and interlocks ensure that the starting conditions are consistent with the safety analysis, before preventive or mitigating actions General Electric BWR/6 STS            B 3.3.2.1-4                                        Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES BACKGROUND (continued) occur. Because these permissives or interlocks are only one of multiple conservative starting assumptions for the accident analysis, they are generally considered as nominal values without regard to measurement accuracy.
APPLICABLE          Allowable Values are specified for each Rod Block Function specified in SAFETY              SR 3.3.2.1.7. [LTSPs] and the methodologies for calculation of the as-left ANALYSES, LCO,      and as-found tolerances are described in [insert the name of a document and APPLICABILITY  controlled under 10 CFR 50.59 such as the Technical Requirements Manual or any document incorporated into the facility FSAR]. The
[LTSP]s are selected to ensure that the actual setpoints remain conservative with respect to the as-found tolerance band between successive CHANNEL CALIBRATIONS. After each calibration the trip setpoint shall be left within the as-left band around the [LTSP].
[LTSPs] are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated channel (e.g., trip unit) changes state. The analytical limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytical limits, corrected for calibration, process, and some of the instrument errors. The [LTSPs] are then determined accounting for the remaining instrument errors (e.g., drift). The [LTSPs] derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.59) are accounted for.
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
1.a. Rod Withdrawal Limiter The RWL is designed to prevent violation of the MCPR SL and the cladding 1% plastic strain fuel design limit that may result from a single control rod withdrawal error (RWE) event. The analytical methods and assumptions used in evaluating the RWE event are summarized in Reference 3. A statistical analysis of RWE events was performed to determine the MCPR response as a function of withdrawal distance and initial operating conditions. From these responses, the fuel thermal performance was determined as a function of RWL allowable control rod withdrawal distance and power level.
General Electric BWR/6 STS            B 3.3.2.1-5                                      Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The RWL satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). Two channels of the RWL are available and are required to be OPERABLE to ensure that no single instrument failure can preclude a rod block from this Function.
The RWL is assumed to mitigate the consequences of an RWE event when operating > 35% RTP. Below this power level, the consequences of an RWE event will not exceed the MCPR, and therefore the RWL is not required to be OPERABLE (Ref. 4).
1.b. Rod Pattern Controller The RPC enforces the banked position withdrawal sequence (BPWS) to ensure that the initial conditions of the CRDA analysis are not violated.
The analytical methods and assumptions used in evaluating the CRDA are summarized in References 5, 6, 7, and 8. The standard BPWS requires that control rods be moved in groups, with all control rods assigned to a specific group required to be within specified banked positions. Requirements that the control rod sequence is in compliance with BPWS are specified in LCO 3.1.6, "Rod Pattern Control."
                    -----------------------------------REVIEWER'S NOTE-----------------------------------
Adoption of the use of Reference 7 requires implementation of the following commitments:
: 1. Before reducing power to the low power setpoint (LPSP), operators shall confirm control rod coupling integrity for all rods that are fully withdrawn. Control rods that have not been confirmed coupled and are in intermediate positions must be fully inserted prior to power reduction to the LPSP. No action is required for fully-inserted control rods. If a shutdown is required and all rods, which are not confirmed coupled, cannot be fully inserted prior to the power dropping below the LPSP, then the original/standard BPWS must be used. The original/standard BPWS can be found in Licensing Topical Report NEDO-21231, "Banked Position Withdrawal Sequence,"
January 1977, and is referred to in NUREG-1433 and NUREG-1434.
: 2. After reactor power drops below the LPSP, rods may be inserted from notch position 48 to notch position 00 without stopping at the intermediate positions. However, GE Nuclear Energy recommends that operators insert rods in the same order as specified for the original/standard BPWS as much as is reasonably possible. If a plant is in the process of shutting down following improved BPWS with the power below the LPSP, no control rod shall be withdrawn unless the control rod pattern is in compliance with standard BPWS requirements.
General Electric BWR/6 STS                B 3.3.2.1-6                                                      Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
When performing a shutdown of the plant, an optional BPWS control rod sequence (Ref. 7) may be used if the coupling of each withdrawn control rod has been confirmed. The rods may be inserted without the need to stop at intermediate positions. When using the Reference 7 control rod insertion sequence for shutdown, the rod pattern controller may be reprogrammed to enforce the requirements of the improved BPWS control rod insertion process [, or it can be bypassed if it is not programmed to reflect the optional BPWS shutdown sequence, as permitted by the Applicability Note for the RPC in Table 3.3.1.1-1].
The Rod Pattern Controller Function satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
Since the RPC is a backup to operator control of control rod sequences, only a single channel would be required OPERABLE to satisfy Criterion 3 (Ref. 8). However, the RPC is designed as a dual channel system and will not function without two OPERABLE channels. Required Actions of LCO 3.1.3, "Control Rod OPERABILITY," and LCO 3.1.6 may necessitate bypassing individual control rods in the Rod Action Control System (RACS) to allow continued operation with inoperable control rods or to allow correction of a control rod pattern not in compliance with the BPWS.
The individual control rods may be bypassed as required by the conditions, and the RPC is not considered inoperable provided SR 3.3.2.1.9 is met.
Compliance with the BPWS, and therefore OPERABILITY of the RPC, is required in MODES 1 and 2 with THERMAL POWER  10% RTP. When THERMAL POWER is > 10% RTP, there is no possible control rod configuration that results in a control rod worth that could exceed the 280 cal/gm fuel damage limit during a CRDA. In MODES 3 and 4, all control rods are required to be inserted in the core. In MODE 5, since only a single control rod can be withdrawn from a core cell containing fuel assemblies, adequate SDM ensures that the consequences of a CRDA are acceptable, since the reactor will be subcritical.
: 2. Reactor Mode Switch - Shutdown Position During MODES 3 and 4, and during MODE 5 when the reactor mode switch is required to be in the shutdown position, the core is assumed to be subcritical; therefore, no positive reactivity insertion events are analyzed. The Reactor Mode Switch - Shutdown Position control rod withdrawal block ensures that the reactor remains subcritical by blocking control rod withdrawal, thereby preserving the assumptions of the safety analysis.
General Electric BWR/6 STS            B 3.3.2.1-7                                          Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Reactor Mode Switch - Shutdown Position Function satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
Two channels are required to be OPERABLE to ensure that no single channel failure will preclude a rod block when required. No Allowable Value is applicable for this Function since the channels are mechanically actuated based solely on reactor mode switch position.
During shutdown conditions (MODE 3, 4, or 5) no positive reactivity insertion events are analyzed because assumptions are that control rod withdrawal blocks are provided to prevent criticality. Therefore, when the reactor mode switch is in the shutdown position, the control rod withdrawal block is required to be OPERABLE. During MODE 5, with the reactor mode switch in the refueling position, the required position one-rod-out interlock (LCO 3.9.2) provides the required control rod withdrawal blocks.
ACTIONS            -----------------------------------REVIEWERS NOTE-----------------------------------
Certain LCO Completion Times are based on approved topical reports. In order for a licensee to use the times, the licensee must justify the Completion Times as required by the staff Safety Evaluation Report (SER) for the topical report.
A.1 If either RWL channel is inoperable, the RWL may not be capable of performing its intended function. In most cases, with an inoperable channel, the RWL will initiate a control rod withdrawal block because the two channels will not agree. To ensure erroneous control rod withdrawal does not occur, however, Required Action A.1 requires that further control rod withdrawal be suspended immediately.
B.1 If the RPC is inoperable, it may not be capable of performing its intended function even though, in most cases, all control rod movement will be blocked. All control rod movement should be suspended under these conditions until the RPC is restored to OPERABLE status. This action does not preclude a reactor scram. The RPC is not considered inoperable if individual control rods are bypassed in the RACS as required by LCO 3.1.3 or LCO 3.1.6. Under these conditions, continued General Electric BWR/6 STS                B 3.3.2.1-8                                                      Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES ACTIONS (continued) operation is allowed if the bypassing of control rods and movement of control rods is verified by a second licensed operator or other qualified member of the technical staff per SR 3.3.2.1.9.
C.1 and C.2 If one Reactor Mode Switch - Shutdown Position control rod withdrawal block channel is inoperable, the remaining OPERABLE channel is adequate to perform the control rod withdrawal block function. Required Action C.1 and Required Action C.2 are consistent with the normal action of an OPERABLE Reactor Mode Switch - Shutdown Position Function to maintain all control rods inserted. Therefore, there is no distinction between Required Actions for the Conditions of one or two channels inoperable. In both cases (one or both channels inoperable), suspending all control rod withdrawal immediately, and immediately fully inserting all insertable control rods in core cells containing one or more fuel assemblies will ensure that the core is subcritical, with adequate SDM ensured by LCO 3.1.1, "SHUTDOWN MARGIN (SDM)." Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are therefore not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.
SURVEILLANCE        -----------------------------------REVIEWERS NOTE-----------------------------------
REQUIREMENTS        Certain Frequencies are based on approved topical reports. In order for a licensee to use these Frequencies, the licensee must justify the Frequencies as required by the staff SER for the topical report.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Notes b and c are applied to the setpoint verification Surveillances for the rod withdrawal limiter functions in SR 3.3.2.1.7 unless one or more of the following exclusions apply:
: 1. Manual actuation circuits, automatic actuation logic circuits or instrument functions that derive input from contacts which have no associated sensor or adjustable device, e.g., limit switches, breaker position switches, manual actuation switches, float switches, proximity detectors, etc. are excluded. In addition, those permissives and interlocks that derive input from a sensor or adjustable device that is tested as part of another TS function are excluded.
General Electric BWR/6 STS                B 3.3.2.1-9                                                      Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued)
: 2. Settings associated with safety relief valves are excluded. The performance of these components is already controlled (i.e., trended with as-left and as-found limits) under the ASME Code for Operation and Maintenance of Nuclear Power Plants testing program.
: 3. Functions and Surveillance Requirements which test only digital components are normally excluded. There is no expected change in result between SR performances for these components. Where separate as-left and as-found tolerance is established for digital component SRs, the requirements would apply.
As noted at the beginning of the SR, the SRs for each Control Rod Block instrumentation Function are found in the SRs column of Table 3.3.2.1-1.
The Surveillances are also modified by a Note to indicate that when an RWL channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains control rod block capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 10) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that a control rod block will be initiated when necessary.
SR 3.3.2.1.1, SR 3.3.2.1.2, SR 3.3.2.1.3, and SR 3.3.2.1.4 The CHANNEL FUNCTIONAL TESTS for the RPC and RWL are performed by attempting to withdraw a control rod not in compliance with the prescribed sequence and verifying that a control rod block occurs. 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 methodology. As noted, the SRs are not required to be performed until 1 hour after specified conditions are met (e.g., after any control rod is withdrawn in General Electric BWR/6 STS              B 3.3.2.1-10                                                      Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued)
MODE 2). This allows entry into the appropriate conditions needed to perform the required SRs. [ The Frequencies are based on reliability analysis (Ref. 9).
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.2.1.5 The LPSP is the point at which the RPCS makes the transition between the function of the RPC and the RWL. This transition point is automatically varied as a function of power. This power level is inferred from the first stage turbine pressure (one channel to each trip system).
These power setpoints must be verified periodically to be within the Allowable Values. If any LPSP is nonconservative, then the affected Functions are considered inoperable. Since this channel has both upper and lower required limits, it is not allowed to be placed in a condition to enable either the RPC or RWL Function. Because main turbine bypass steam flow can affect the LPSP nonconservatively for the RWL, the RWL is considered inoperable with any main turbine bypass valves open.
[ The Frequency of 92 days is based on the setpoint methodology utilized for these channels.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS              B 3.3.2.1-11                                                      Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.2.1.5 for the rod withdrawal limiter functions is modified by two Notes as identified in Table 3.3.2.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the [LTSP] is used in the plant surveillance procedures [NTSP], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP], then the channel shall be declared inoperable.
The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
SR 3.3.2.1.6 This SR ensures the high power function of the RWL is not bypassed when power is above the HPSP. The power level is inferred from turbine first stage pressure signals. Periodic testing of the HPSP channels is required to verify the setpoint to be less than or equal to the limit.
Adequate margins in accordance with setpoint methodologies are included. If the HPSP is nonconservative, then the RWL is considered inoperable. Alternatively, the HPSP can be placed in the conservative condition (nonbypass). If placed in the nonbypassed condition, the SR is met and the RWL would not be considered inoperable. Because main turbine bypass steam flow can affect the HPSP nonconservatively for the RWL, the RWL is considered inoperable with any main turbine bypass valve open. [ The Frequency of 92 days is based on the setpoint methodology utilized for these channels.
General Electric BWR/6 STS            B 3.3.2.1-12                                        Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.2.1.7 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy.
CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology. Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.
[ The Frequency is based upon the assumption of the magnitude of equipment drift in the setpoint analysis.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.2.1.7 for the rod withdrawal limiter functions is modified by two Notes as identified in Table 3.3.2.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with General Electric BWR/6 STS                B 3.3.2.1-13                                                      Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued) safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the [LTSP] is used in the plant surveillance procedures [NTSP], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP], then the channel shall be declared inoperable.
The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
SR 3.3.2.1.8 The CHANNEL FUNCTIONAL TEST for the Reactor Mode Switch -
Shutdown Position Function is performed by attempting to withdraw any control rod with the reactor mode switch in the shutdown position and verifying a control rod block occurs. 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.
As noted in the SR, the Surveillance is not required to be performed until 1 hour after the reactor mode switch is in the shutdown position, since testing of this interlock with the reactor mode switch in any other position cannot be performed without using jumpers, lifted leads, or movable limits. This allows entry into MODES 3 and 4 if the Frequency is not met per SR 3.0.2. The 1 hour allowance is based on operating experience and in consideration of providing a reasonable time in which to complete the SRs.
General Electric BWR/6 STS            B 3.3.2.1-14                                      Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES SURVEILLANCE REQUIREMENTS (continued)
[ 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 18 month Frequency.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.2.1.9 LCO 3.1.3 and LCO 3.1.6 may require individual control rods to be bypassed in RACS to allow insertion of an inoperable control rod or correction of a control rod pattern not in compliance with BPWS. With the control rods bypassed in the RACS, the RPC will not control the movement of these bypassed control rods. To ensure the proper bypassing and movement of those affected control rods, a second licensed operator or other qualified member of the technical staff must verify the bypassing and movement of these control rods. Compliance with this SR allows the RPC to be OPERABLE with these control rods bypassed.
REFERENCES          1. Regulatory Guide 1.105, "Setpoints for Safety-Related Instrumentation," Revision 3.
: 2. FSAR, Section [7.6.1.7.3].
: 3. FSAR, Section [15.4.2].
: 4. NEDE-24011-P-A-9-US, "General Electrical Standard Application for Reload Fuel," Supplement for United States, Section S 2.2.3.1, September 1988.
General Electric BWR/6 STS                B 3.3.2.1-15                                                      Rev. 5.0
 
Control Rod Block Instrumentation B 3.3.2.1 BASES REFERENCES (continued)
: 5.  "Modifications to the Requirements for Control Rod Drop Accident Mitigating Systems," BWR Owners Group, July 1986.
: 6. NEDO-21231, "Banked Position Withdrawal Sequence,"
January 1977.
: 7. NEDO-33091-A, Revision 2, "Improved BPWS Control Rod Insertion Process," July 2004.
: 8. NRC SER, Acceptance of Referencing of Licensing Topical Report NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel, Revision 8, Amendment 17," December 27, 1987.
: 9. NEDC-30851-P-A, "Technical Specification Improvement Analysis for BWR Control Rod Block Instrumentation," October 1988.
: 10. GENE-770-06-1, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
General Electric BWR/6 STS          B 3.3.2.1-16                                    Rev. 5.0
 
PAM Instrumentation B 3.3.3.1 B 3.3 INSTRUMENTATION B 3.3.3.1 Post Accident Monitoring (PAM) Instrumentation 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 and that are required for safety systems to accomplish their safety functions for Design Basis Events. The instruments that monitor these variables are designated as Type A, Category I, and non-Type A, Category I in accordance with Regulatory Guide 1.97 (Ref. 1).
The OPERABILITY of the accident monitoring instrumentation ensures that there is sufficient information available on selected plant parameters to monitor and assess plant status and behavior following an accident.
This capability is consistent with the recommendations of Reference 1.
APPLICABLE          The PAM instrumentation LCO 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 (EOP). These variables are restricted to preplanned actions for the primary success path of Design Basis Accidents (DBAs) (e.g., loss of coolant accident (LOCA)) and
* Take the specified, preplanned, manually controlled actions for which no automatic control is provided, which are required for safety systems to accomplish their safety function.
The PAM instrumentation LCO also ensures OPERABILITY of Category I, non-Type 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 whether a gross breach of a barrier has occurred, and
* Initiate action necessary to protect the public and to obtain an estimate of the magnitude of any impending threat.
General Electric BWR/6 STS              B 3.3.3.1-1                                      Rev. 5.0
 
PAM Instrumentation B 3.3.3.1 BASES APPLICABLE SAFETY ANALYSES (continued)
The plant specific Regulatory Guide 1.97 analysis (Ref. 2) documents the process that identified Type A and Category I, non-Type A, variables.
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, instrumentation is retained in the Technical Specifications (TS) because it is intended to assist operators in minimizing the consequences of accidents. Therefore, these Category I, non-Type A, variables are important for reducing public risk.
LCO                LCO 3.3.3.1 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 unit and to bring the unit 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 accident monitoring channel results in information ambiguity (e.g., the redundant displays disagree) that could lead operators to defeat or to fail to accomplish a required safety function.]
The exception of the two channel requirement is primary containment isolation valve (PCIV) position. In this case, the important information is the status of the primary containment penetrations. The LCO requires one position indicator for each active PCIV. 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 passive valve or via system boundary status. If a normally active PCIV 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 is a discussion of the specified instrument Functions listed in Table 3.3.3.1-1, in the accompanying LCO. These discussions are intended as examples of what should be provided for each Function when the plant specific Bases are prepared.
General Electric BWR/6 STS            B 3.3.3.1-2                                        Rev. 5.0
 
PAM Instrumentation B 3.3.3.1 BASES LCO (continued)
: 1. Reactor Steam Dome Pressure Reactor steam dome pressure is a Category I variable provided to support monitoring of Reactor Coolant System (RCS) integrity and to verify operation of the Emergency Core Cooling Systems (ECCS). Two independent pressure transmitters with a range of 0 psig to 1500 psig monitor pressure. Wide range recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel.
: 2. Reactor Vessel Water Level Reactor vessel water level is a Category I variable provided to support monitoring of core cooling and to verify operation of the ECCS. The wide range water level channels provide the PAM Reactor Vessel Water Level Function. The wide range water level channels measure from 17 inches below the dryer skirt down to a point just below the bottom of the active fuel. Wide range water level is measured by two independent differential pressure transmitters. The output from these channels is recorded on two independent pen recorders. These recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel.
The wide range water level instruments are uncompensated for variation in reactor water density and are calibrated to be most accurate at operational pressure and temperature.
: 3. Suppression Pool Water Level Suppression pool water level is a Category I variable provided to detect a breach in the reactor coolant pressure boundary (RCPB). This variable is also used to verify and provide long term surveillance of ECCS function.
The wide range suppression pool water level measurement provides the operator with sufficient information to assess the status of the RCPB and to assess the status of the water supply to the ECCS. The wide range water level indicators monitor the suppression pool level from the center line of the ECCS suction lines to the top of the pool. Two wide range suppression pool water level signals are transmitted from separate differential pressure transmitters and are continuously recorded on two recorders in the control room. These recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel.
General Electric BWR/6 STS            B 3.3.3.1-3                                        Rev. 5.0
 
PAM Instrumentation B 3.3.3.1 BASES LCO (continued)
: 4. Drywell Pressure Drywell pressure is a Category I variable provided to detect breach of the RCPB and to verify ECCS functions that operate to maintain RCS integrity. Two wide range drywell pressure signals are transmitted from separate pressure transmitters and are continuously recorded and displayed on two control room recorders. These recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel.
: 5. Primary Containment Area Radiation (High Range)
Primary containment area radiation (high range) 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 plant, primary containment area radiation (high range) PAM instrumentation consists of the following: ]
: 6. Drywell Sump Level Drywell sump level is a Category I variable provided for verification of ECCS functions that operate to maintain RCS integrity.
[ For this plant, the drywell sump level PAM instrumentation consists of the following: ]
: 7. Drywell Drain Sump Level Drywell drain sump level is a Category I variable provided to detect breach of the RCPB and for verification and long term surveillance of ECCS functions that operate to maintain RCS integrity.
[ For this plant, the drywell drain sump level PAM instrumentation consists of the following: ]
General Electric BWR/6 STS              B 3.3.3.1-4                                      Rev. 5.0
 
PAM Instrumentation B 3.3.3.1 BASES LCO (continued)
: 8. Primary Containment Isolation Valve (PCIV) Position 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 verify redundantly 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 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 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 plant, the PCIV position PAM instrumentation consists of the following: ]
: 9. Wide Range Neutron Flux Wide range neutron flux is a Category I variable provided to verify reactor shutdown.
[ For this plant, wide range neutron flux PAM instrumentation consists of the following: ]
: 10. Primary Containment Pressure Primary containment pressure is a Category I variable provided to verify RCS and containment integrity and to verify the effectiveness of ECCS actions taken to prevent containment breach. Two wide range primary containment pressure signals are transmitted from separate pressure transmitters and are continuously recorded and displayed on two control room recorders. These recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channel.
General Electric BWR/6 STS              B 3.3.3.1-5                                      Rev. 5.0
 
PAM Instrumentation B 3.3.3.1 BASES LCO (continued)
: 11. Suppression Pool Water Temperature Suppression pool water temperature is a Category I variable provided to detect a condition that could potentially lead to containment breach, and to verify the effectiveness of ECCS actions taken to prevent containment breach. The suppression pool water temperature instrumentation allows operators to detect trends in suppression pool water temperature in sufficient time to take action to prevent steam quenching vibrations in the suppression pool. Twenty-four temperature sensors are arranged in six groups of four independent and redundant channels, located such that there is a group of sensors within a 30 ft line of sight of each relief valve discharge location.
Thus, six groups of sensors are sufficient to monitor each relief valve discharge location. Each group of four sensors includes two sensors for normal suppression pool temperature monitoring and two sensors for PAM. The outputs for the PAM sensors are recorded on four independent recorders in the control room. (Channels A and C are redundant to channels B and D, respectively.) All four of these recorders must be OPERABLE to furnish two channels of PAM indication for each of the relief valve discharge locations. These recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with this portion of the instrument channels. Each suppression pool water temperature [relief valve discharge location] is treated separately and each [relief valve discharge location] is considered to be a separate function. Therefore, separate Condition entry is allowed for each inoperable [relief valve discharge location].
APPLICABILITY      The PAM instrumentation LCO is applicable in MODES 1 and 2. These variables are related to the diagnosis and preplanned actions required to mitigate DBAs. The applicable DBAs are assumed to occur in MODES 1 and 2. In MODES 3, 4, and 5, plant conditions are such that the likelihood of an event that would require PAM instrumentation is extremely low; therefore, PAM instrumentation is not required to be OPERABLE in these MODES.
ACTIONS            A Note has been provided to modify the ACTIONS related to PAM instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required General Electric BWR/6 STS            B 3.3.3.1-6                                        Rev. 5.0
 
PAM Instrumentation B 3.3.3.1 BASES ACTIONS (continued)
Actions for inoperable PAM instrumentation channels provide appropriate compensatory measures for separate inoperable functions. As such, a Note has been provided that allows separate Condition entry for each inoperable PAM Function. When the Required Channels in Table 3.3.3.1-1 are specified (e.g., on a per steam line, per loop, etc.,
basis) then the Condition may be entered separately for each steam line, loop, etc., as appropriate.
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 If a channel has not been restored to OPERABLE status in 30 days, this Required Action specifies initiation of actions in accordance with Specification 5.6.5, which requires a written report to be submitted to the NRC. This report discusses the cause of the inoperability and identifies proposed restorative actions. This Action is appropriate in lieu of a shutdown requirement since alternative Actions are identified before loss of functional capability, and given the likelihood of plant conditions that would require information provided by this instrumentation.
C.1 When one or more Functions have two required channels that are 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 instrument operation and the availability of alternate means to obtain the required information.
Continuous operation 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 General Electric BWR/6 STS              B 3.3.3.1-7                                      Rev. 5.0
 
PAM Instrumentation B 3.3.3.1 BASES ACTIONS (continued) 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. Condition C is modified by a Note that excludes hydrogen monitor channels. Condition D provides appropriate Required Actions for two inoperable hydrogen monitor channels.
D.1 This Required Action directs entry into the appropriate Condition referenced in Table 3.3.3.1-1. The applicable Condition referenced in the Table is Function dependent. Each time an inoperable channel has not met the Required Action of Condition C, 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 For the majority of Functions in Table 3.3.3.1-1, if the Required Action and associated Completion Time of Condition C is not met, the plant must be placed in a MODE in which the LCO does not apply. This is done by placing the plant in at least MODE 3 within 12 hours.
The allowed Completion Times are reasonable, based on operating experience, to reach the required plant condition from full power conditions in an orderly manner and without challenging plant systems.
F.1 Since alternate means of monitoring primary containment area radiation have been developed and tested, the Required Action is not to shut down the plant but rather to follow the directions of Specification 5.6.5. These alternate means may be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. 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.
General Electric BWR/6 STS            B 3.3.3.1-8                                        Rev. 5.0
 
PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE        The following SRs apply to each PAM instrumentation Function in REQUIREMENTS        Table 3.3.3.1-1.
SR 3.3.3.1.1 Performance of the CHANNEL CHECK ensures that a gross instrumentation failure has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between 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.
The high radiation instrumentation should be compared to similar plant instruments located throughout the plant.
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 sensor or the signal processing equipment has drifted outside its limit.
[ 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 rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of those displays associated with the required channels of this LCO.
General Electric BWR/6 STS                B 3.3.3.1-9                                                      Rev. 5.0
 
PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.3.1.2 CHANNEL CALIBRATION is a complete check of the instrument loop including the sensor. The test verifies that the channel responds to the measured parameter with the necessary range and accuracy. [ The Frequency is based on operating experience and consistency with the typical industry refueling cycles.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. Regulatory Guide 1.97, "Instrumentation for Light-Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident," [Date].
[ 2. Plant specific documents (e.g., FSAR, NRC Regulatory Guide 1.97, SER letter). ]
General Electric BWR/6 STS              B 3.3.3.1-10                                                      Rev. 5.0
 
Remote Shutdown System B 3.3.3.2 B 3.3 INSTRUMENTATION B 3.3.3.2 Remote Shutdown System BASES BACKGROUND          The Remote Shutdown System provides the control room operator with sufficient instrumentation and controls to place and maintain the plant in a safe shutdown condition from a location other than the control room. This capability is necessary to protect against the possibility of the control room becoming inaccessible. A safe shutdown condition is defined as MODE 3. With the plant in MODE 3, the Reactor Core Isolation Cooling (RCIC) System, the safety/relief valves, and the Residual Heat Removal Shutdown Cooling System can be used to remove core decay heat and meet all safety requirements. The long term supply of water for the RCIC and the ability to operate shutdown cooling 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 plant in MODE 3. Not all controls and necessary transfer switches are located at the remote shutdown panel. Some controls and transfer switches will have to be operated locally at the switchgear, motor control panels, or other local stations. The plant automatically reaches MODE 3 following a plant 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 design capability to ANALYSES            promptly shut down the reactor to MODE 3, including the necessary instrumentation and controls, to 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 (Ref. 1).
The Remote Shutdown System satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS            B 3.3.3.2-1                                        Rev. 5.0
 
Remote Shutdown System B 3.3.3.2 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 3.3.3.2-1.
The controls, instrumentation, and transfer switches are those required for:
* Reactor pressure vessel (RPV) pressure control,
* Decay heat removal,
* RPV inventory control, and
* Safety support systems for the above functions, including service water, component cooling water, and onsite power, including the diesel generators.
The Remote Shutdown System is OPERABLE if all instrument and control channels needed to support the remote shutdown function are OPERABLE. In some cases, Table B 3.3.3.2-1 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 instruments 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 instruments 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 and 2.
This is required so that the plant 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 MODES 3, 4, and 5. In these MODES, the plant is already subcritical and in a condition of reduced Reactor Coolant System energy. Under these conditions, considerable time is available to restore necessary instrument control Functions if control room instruments or control becomes unavailable. Consequently, the TS do not require OPERABILITY in MODES 3, 4, and 5.
General Electric BWR/6 STS            B 3.3.3.2-2                                        Rev. 5.0
 
Remote Shutdown System B 3.3.3.2 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 provided to modify the ACTIONS related to Remote Shutdown System Functions. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable Remote Shutdown System Functions provide appropriate compensatory measures for separate Functions.
As such, a Note has been provided that allows separate Condition entry for each inoperable Remote Shutdown System Function.
A.1 Condition A addresses the situation where one or more required Functions of the Remote Shutdown System is inoperable. This includes the control and transfer switches for any required Function.
The Required Action is to restore the Function (both divisions, if applicable) 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 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 12 hours. The allowed Completion Time is reasonable, based on operating experience, to reach the required MODE from full power conditions in an orderly manner and without challenging plant systems.
General Electric BWR/6 STS            B 3.3.3.2-3                                          Rev. 5.0
 
Remote Shutdown System B 3.3.3.2 BASES SURVEILLANCE        SR 3.3.3.2.1 REQUIREMENTS Performance of the CHANNEL CHECK 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 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. As specified in the Surveillance, a CHANNEL CHECK is only required for those channels that are normally energized.
[ The Frequency of 31 days is based upon plant operating experience that demonstrates channel failure is rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.3.2.2 SR 3.3.3.2.2 verifies each required Remote Shutdown System transfer switch and control circuit performs the intended function. This verification is performed from the remote 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 General Electric BWR/6 STS                B 3.3.3.2-4                                                      Rev. 5.0
 
Remote Shutdown System B 3.3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) remote shutdown panel and the local control stations. However, this Surveillance is not required to be performed only during a plant outage.
[ Operating experience demonstrates that Remote Shutdown System control channels usually pass the Surveillance when performed at the 18 month Frequency.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.3.2.3 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. The test verifies the channel responds to measured parameter values with the necessary range and accuracy.
[ The 18 month Frequency is based upon operating experience and is consistent with the typical industry refueling cycle.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. 10 CFR 50, Appendix A, GDC 19.
General Electric BWR/6 STS                B 3.3.3.2-5                                                      Rev. 5.0
 
Remote Shutdown System B 3.3.3.2 Table B 3.3.3.2-1 (page 1 of 1)
Remote Shutdown System Instrumentation FUNCTION (INSTRUMENT OR CONTROL                                            REQUIRED NUMBER OF PARAMETER)                                                        DIVISIONS
: 1. Reactor Pressure Vessel Pressure Control
: a. Reactor Pressure                                                                            [1]
: 2. Decay Heat Removal
: a. RCIC Flow                                                                                  [1]
: b. RCIC Controls                                                                              [1]
: c. RHR Flow                                                                                    [1]
: d. RHR Controls                                                                                [1]
: 3. Reactor Pressure Vessel Inventory Control
: a. RCIC Flow                                                                                  [1]
: b. RCIC Controls                                                                              [1]
: c. RHR Flow                                                                                    [1]
: d. RHR Controls                                                                                [1]
--------------------------------------------------REVIEWERS NOTE-------------------------------------------------
For channels that fulfill GDC 19 requirements, the number of OPERABLE channels required depends upon the plant's licensing basis as described in the NRC plant specific Safety Evaluation Report (SER). Generally, two divisions are required to be OPERABLE. However, only one channel per given Function is required if the plant has justified such a design and the NRC SER has accepted the justification.
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.
General Electric BWR/6 STS                          B 3.3.3.2-6                                                    Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 B 3.3 INSTRUMENTATION B 3.3.4.1 End of Cycle Recirculation Pump Trip (EOC-RPT) Instrumentation BASES BACKGROUND          The EOC-RPT instrumentation initiates a recirculation pump trip (RPT) to reduce the peak reactor pressure and power resulting from turbine trip or generator load rejection transients to provide additional margin to core thermal MCPR Safety Limits (SLs).
The need for the additional negative reactivity in excess of that normally inserted on a scram reflects end of cycle reactivity considerations. Flux shapes at the end of cycle are such that the control rods may not be able to ensure that thermal limits are maintained by inserting sufficient negative reactivity during the first few feet of rod travel upon a scram caused by Turbine Control Valve (TCV) Fast Closure, Trip Oil Pressure -
Low, or Turbine Stop Valve Closure, Trip Oil Pressure - Low (TSV). The physical phenomenon involved is that the void reactivity feedback due to a pressurization transient can add positive reactivity at a faster rate than the control rods can add negative reactivity.
The protection functions of the EOC-RPT have been designed to ensure safe operation of the reactor during load rejection transients. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the EOC-RPT, as well as LCOs on other system parameters and equipment performance.
Technical Specifications are required by 10 CFR 50.36 to include LSSSs for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical 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 Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur.
                    ---------------------------------REVIEWER'S NOTE-----------------------------------
The term "Limiting Trip Setpoint" [LTSP] is generic terminology for the calculated trip setting (setpoint) value calculated by means of the plant specific setpoint methodology documented in a document controlled General Electric BWR/6 STS                B 3.3.4.1-1                                        Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES BACKGROUND (continued) under 10 CFR 50.59. The term [LTSP] indicates that no additional margin has been added between the Analytical Limit and the calculated trip setting.
                    "Nominal Trip Setpoint [NTSP]" is the suggested terminology for the actual setpoint implemented in the plant surveillance procedures where margin has been added to the calculated [LTSP]. The as-found and as-left tolerances will apply to the [NTSP] implemented in the Surveillance procedures to confirm channel performance.
Licensees are to insert the name of the document controlled under 10 CFR 50.59 that contain the methodology for calculating the as-left and as-found tolerances in Note 2 of the SRs, for the phrase "[insert the name of a document controlled under 10 CFR 50.59 such as the Technical Requirements Manual or any document incorporated into the facility FSAR]" throughout these Bases.
If the [LTSP] is not included in SR 3.3.4.1.2 or SR 3.3.4.1.3 for the purpose of compliance with 10 CFR 50.36, the plant specific location for the [LTSP] or [NTSP] must be cited in Note 2 of the SRs in the SR table.
The brackets indicate plant specific terms may apply, as reviewed and approved by the NRC.
The [Limiting Trip Setpoint (LTSP)] specified in SR 3.3.4.1.3 is a predetermined setting for a protection channel chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the SL would not be exceeded. As such, the
[LTSP] accounts for uncertainties in setting the channel (e.g., calibration),
uncertainties in how the channel might actually perform (e.g.,
repeatability), changes in the point of action of the channel over time (e.g., drift during surveillance intervals), and any other factors which may influence its actual performance (e.g., harsh accident environments).
Therefore, the [LTSP] ensures that SLs are not exceeded. As such, the
[LTSP] meets the definition of an LSSS (Ref. 1).
The Allowable Value specified in SR 3.3.4.1.3 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 surveillance interval.
General Electric BWR/6 STS                B 3.3.4.1-2                                                      Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 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)." Relying solely on the [LTSP] to define OPERABILITY in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as found" value of a protection channel 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 protection channel with a setting that has been found to be different from the [LTSP] due to some drift of the setting may still be OPERABLE because drift is to be expected. This expected drift would have been specifically accounted for in the setpoint methodology for calculating the [LTSP] and thus the automatic protective action would still have ensured that the SL would not be exceeded with the "as found" setting of the protection channel. Therefore, the channel would still be OPERABLE because it would have performed its safety function and the only corrective action required would be to reset the channel within the established as-left tolerance around [LTSP] to account for further drift during the next surveillance interval. Note that, although the channel is OPERABLE under these circumstances, the trip setpoint must be left adjusted to a value within the as-left tolerance, 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 (as-found criteria).
However, there is also some point beyond which the channel may not be able to perform its function due to, for example, greater than expected drift. This value needs to be specified in the Technical Specifications in order to define OPERABILITY of the channels and is designated as the Allowable Value.
If the actual setting (as-found setpoint) of the channel is found to be conservative with respect to the Allowable Value but is beyond the as-found tolerance band, the channel is OPERABLE, but degraded. The degraded condition will be further evaluated during performance of the SR. This evaluation will consist of resetting the channel setpoint to the
[LTSP] (within the allowed tolerance), and evaluating the channel response. If the channel is functioning as required and expected to pass the next surveillance, then the channel is OPERABLE and can be restored to service at the completion of the surveillance. After the surveillance is completed, the channel as-found condition will be entered into the Corrective Action Program for further evaluation.
General Electric BWR/6 STS            B 3.3.4.1-3                                        Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES BACKGROUND (continued)
The EOC-RPT instrumentation as shown in Reference 2 is comprised of sensors that detect initiation of closure of the TSVs, or fast closure of the TCVs, combined with relays, logic circuits, and fast acting circuit breakers that interrupt the power from the recirculation pump motor generator (MG) set generators to each of the recirculation pump motors. The channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs an EOC-RPT signal to the trip logic. When the RPT breakers trip open, the recirculation pumps coast down under their own inertia. The EOC-RPT has two identical trip systems, either of which can actuate an RPT.
Each EOC-RPT trip system is a two-out-of-two logic for each Function; thus, either two TSV Closure, Trip Oil Pressure - Low or two TCV Fast Closure, Trip Oil Pressure - Low signals are required for a trip system to actuate. If either trip system actuates, both recirculation pumps will trip.
There are two EOC-RPT breakers in series per recirculation pump. One trip system trips one of the two EOC-RPT breakers for each recirculation pump and the second trip system trips the other EOC-RPT breaker for each recirculation pump.
APPLICABLE          The TSV Closure, Trip Oil Pressure - Low and the TCV Fast Closure, Trip SAFETY              Oil Pressure - Low Functions are designed to trip the recirculation pumps ANALYSES, LCO,      in the event of a turbine trip or generator load rejection to mitigate the and APPLICABILITY  neutron flux, heat flux and pressurize transients, and to increase the margin to the MCPR SL. The analytical methods and assumptions used in evaluating the turbine trip and generator load rejection, as well as other safety analyses that assume EOC-RPT, are summarized in References 3, 4, and 5.
To mitigate pressurization transient effects, the EOC-RPT must trip the recirculation pumps after initiation of initial closure movement of either the TSVs or the TCVs. The combined effects of this trip and a scram reduce fuel bundle power more rapidly than does a scram alone, resulting in an increased margin to the MCPR SL. Alternatively, MCPR limits for an inoperable EOC-RPT as specified in the COLR are sufficient to mitigate pressurization transient effects. The EOC-RPT function is automatically disabled when turbine first stage pressure is < [40%] RTP.
EOC-RPT instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
Permissive and interlock setpoints allow the blocking of trips during plant startups, and restoration of trips when the permissive conditions are not satisfied, but they are not explicitly modeled in the Safety Analyses.
These permissives and interlocks ensure that the starting conditions are General Electric BWR/6 STS            B 3.3.4.1-4                                        Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) consistent with the safety analysis, before preventive or mitigating actions occur. Because these permissives or interlocks are only one of multiple conservative starting assumptions for the accident analysis, they are generally considered as nominal values without regard to measurement accuracy.
The OPERABILITY of the EOC-RPT is dependent on the OPERABILITY of the individual instrumentation channel Functions. Each Function must have a required number of OPERABLE channels in each trip system, with their setpoints set within the setting tolerance of the [LTSP] where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Channel OPERABILITY also includes the associated EOC-RPT breakers. Each channel (including the associated EOC-RPT breakers) must also respond within its assumed response time.
Allowable Values are specified for each EOC-RPT Function specified in the LCO. [LTSPs] and the methodologies for calculation of the as-left and as-found tolerances are described in [insert the name of a document controlled under 10 CFR 50.59 such as the Technical Requirements Manual or any document incorporated into the facility FSAR]. The
[LTSPs] are selected to ensure that the setpoints remain conservative with respect to the as-found tolerance band between successive CHANNEL CALIBRATIONS. After each calibration the trip setpoint shall be left within the as-left band around the [LTSP].
[LTSPs] are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., TSV position), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g.,
trip unit) changes state. The analytical limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytical limits, corrected for calibration, process, and some of the instrument errors. The [LTSPs] are then determined accounting for the remaining instrument errors (e.g.,
drift). The [LTSPs] derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
The specific Applicable Safety Analysis, LCO, and Applicability discussions are listed below on a Function by Function basis.
General Electric BWR/6 STS            B 3.3.4.1-5                                      Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Alternately, since this instrumentation protects against a MCPR SL violation with the instrumentation inoperable, modifications to the MCPR limits (LCO 3.2.2) may be applied to allow this LCO to be met. The MCPR penalty for the Condition EOC-RPT inoperable is specified in the COLR.
Turbine Stop Valve Closure, Trip Oil Pressure - Low Closure of the TSVs and a main turbine trip result in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, an RPT is initiated on TSV Closure, Trip Oil Pressure - Low in anticipation of the transients that would result from closure of these valves. EOC-RPT decreases reactor power and aids the reactor scram in ensuring the MCPR SL is not exceeded during the worst case transient.
Closure of the TSVs is determined by measuring the EHC fluid pressure at each stop valve. There is one pressure transmitter associated with each stop valve, and the signal from each transmitter is assigned to a separate trip channel. The logic for the TSV Closure, Trip Oil Pressure -
Low Function is such that two or more TSVs must be closed to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 40% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, to consider this Function OPERABLE, the turbine bypass valves must remain shut at THERMAL POWER  40% RTP. Four channels of TSV Closure, with two channels in each trip system, are available and required to be OPERABLE to ensure that no single instrument failure will preclude an EOC-RPT from this Function on a valid signal. The TSV Closure, Trip Oil Pressure - Low Allowable Value is selected high enough to detect imminent TSV closure.
This protection is required, consistent with the safety analysis assumptions, whenever THERMAL POWER is  40% RTP with any recirculating pump in fast speed. Below 40% RTP or with the recirculation in slow speed, the Reactor Vessel Steam Dome Pressure -
High and the Average Power Range Monitor (APRM) Fixed Neutron Flux
                    - High Functions of the Reactor Protection System (RPS) are adequate to maintain the necessary safety margins.
The automatic enable setpoint is feedwater temperature dependent as a result of the subcooling changes that affect the turbine first stage pressure/reactor power relationship. For operation with feedwater temperature  420&deg;F, an Allowable Value setpoint of  26.9% of control valves wide open turbine first stage pressure is provided for the bypass General Electric BWR/6 STS            B 3.3.4.1-6                                      Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) function. The Allowable Value setpoint is reduced to  22.5% of control valve wide open turbine first stage pressure for operation with a feedwater temperature between 370&deg;F and 420&deg;F.
TCV Fast Closure, Trip Oil Pressure - Low Fast closure of the TCVs during a generator load rejection results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, an RPT is initiated on TCV Fast Closure, Trip Oil Pressure - Low in anticipation of the transients that would result from the closure of these valves. The EOC-RPT decreases reactor power and aids the reactor scram in ensuring that the MCPR SL is not exceeded during the worst case transient.
Fast closure of the TCVs is determined by measuring the EHC fluid pressure at each control valve. There is one pressure transmitter associated with each control valve, and the signal from each transmitter is assigned to a separate trip channel. The logic for the TCV Fast Closure, Trip Oil Pressure - Low Function is such that two or more TCVs must be closed (pressure transmitter trips) to produce an EOC-RPT. This Function must be enabled at THERMAL POWER  40% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, to consider this Function OPERABLE, the turbine bypass valves must remain shut at THERMAL POWER  40% RTP. Four channels of TCV Fast Closure, Trip Oil Pressure - Low, with two channels in each trip system, are available and required to be OPERABLE to ensure that no single instrument failure will preclude an EOC-RPT from this Function on a valid signal. The TCV Fast Closure, Trip Oil Pressure - Low Allowable Value is selected high enough to detect imminent TCV fast closure.
This protection is required consistent with the analysis, whenever the THERMAL POWER is  40% RTP with any recirculating pump in fast speed. Below 40% RTP or with recirculation pumps in slow speed, the Reactor Vessel Steam Dome Pressure - High and the APRM Fixed Neutron Flux - High Functions of the RPS are adequate to maintain the necessary safety margins. The turbine first stage pressure/reactor power relationship for the setpoint of the automatic enable is identical to that described for TSV closure.
ACTIONS            -----------------------------------REVIEWERS NOTE-----------------------------------
Certain LCO Completion Times are based on approved topical reports. In order for a licensee to use the times, the licensee must justify the Completion Times as required by the staff Safety Evaluation Report (SER) for the topical report.
General Electric BWR/6 STS                B 3.3.4.1-7                                                      Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES ACTIONS (continued)
A Note has been provided to modify the ACTIONS related to EOC-RPT instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable EOC-RPT instrumentation channels provide appropriate compensatory measures for separate inoperable channels.
As such, a Note has been provided that allows separate Condition entry for each inoperable EOC-RPT instrumentation channel.
A.1 and A.2 With one or more required channels inoperable, but with EOC-RPT trip capability maintained (refer to Required Action B.1 and B.2 Bases), the EOC-RPT System is capable of performing the intended function.
However, the reliability and redundancy of the EOC-RPT instrumentation is reduced such that a single failure in the remaining trip system could result in the inability of the EOC-RPT System to perform the intended function. Therefore, only a limited time is allowed to restore compliance with the LCO. Because of the diversity of sensors available to provide trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of an EOC-RPT, 72 hours is allowed to restore the inoperable channels (Required Action A.1) [or apply the EOC-RPT inoperable MCPR limit]. Alternately, the inoperable channels may be placed in trip (Required Action A.2) since this would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. As noted in Required Action A.2, placing the channel in trip with no further restrictions is not allowed if the inoperable channel is the result of an inoperable breaker, since this may not adequately compensate for the inoperable breaker (e.g., the breaker may be inoperable such that it will not open).
[Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an RPT), or if the inoperable channel is the result of an inoperable breaker, Condition C must be entered and its Required Actions taken.
General Electric BWR/6 STS            B 3.3.4.1-8                                        Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES ACTIONS (continued)
B.1 and B.2 Required Actions B.1 and B.2 are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in the Function not maintaining EOC-RPT trip capability. A Function is considered to be maintaining EOC-RPT trip capability when sufficient channels are OPERABLE or in trip, such that the EOC-RPT System will generate a trip signal from the given Function on a valid signal and both recirculation pumps can be tripped. This requires two channels of the Function, in the same trip system, to each be OPERABLE or in trip, and the associated EOC-RPT breakers to be OPERABLE or in trip. Alternatively, Required Action B.2 requires the MCPR limit for inoperable EOC-RPT, as specified in the COLR, to be applied. This also restores the margin to MCPR assumed in the safety analysis.
The 2 hour Completion Time is sufficient for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of the EOC-RPT instrumentation during this period. It is also consistent with the 2 hour Completion Time provided in LCO 3.2.2, Required Action A.1, since this instrumentation's purpose is to preclude a MCPR violation.
C.1 and C.2 With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to < 40% RTP within 4 hours.
Alternately, the associated recirculation pump may be removed from service since this performs the intended function of the instrumentation.
The allowed Completion Time of 4 hours is reasonable, based on operating experience, to reduce THERMAL POWER to < 40% RTP from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE        -----------------------------------REVIEWERS NOTE-----------------------------------
REQUIREMENTS        Certain Frequencies are based on approved topical reports. In order for a licensee to use these Frequencies, the licensee must justify the Frequencies as required by the staff SER for the topical report.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Notes 1 and 2 are applied to the setpoint verification Surveillances for all EOC-RPT Instrumentation Functions unless one or more of the following exclusions apply:
General Electric BWR/6 STS                B 3.3.4.1-9                                                      Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE REQUIREMENTS (continued)
: 1. Manual actuation circuits, automatic actuation logic circuits or instrument functions that derive input from contacts which have no associated sensor or adjustable device, e.g., limit switches, breaker position switches, manual actuation switches, float switches, proximity detectors, etc. are excluded. In addition, those permissives and interlocks that derive input from a sensor or adjustable device that is tested as part of another TS function are excluded.
: 2. Settings associated with safety relief valves are excluded. The performance of these components is already controlled (i.e., trended with as-left and as-found limits) under the ASME Code for Operation and Maintenance of Nuclear Power Plants testing program.
: 3. Functions and Surveillance Requirements which test only digital components are normally excluded. There is no expected change in result between SR performances for these components. Where separate as-left and as-found tolerance is established for digital component SRs, the requirements would apply.
The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains EOC-RPT trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 6) assumption of the average time required to perform channel surveillance.
That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the recirculation pumps will trip when necessary.
SR 3.3.4.1.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the 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 methodology.
General Electric BWR/6 STS              B 3.3.4.1-10                                                      Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE REQUIREMENTS (continued)
[ The Frequency of 92 days is based on reliability analysis (Ref. 6).
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.4.1.2 The calibration of trip units provides a check of the actual trip setpoints.
The channel must be declared inoperable if the setting is discovered to be less conservative than the Allowable Value specified in SR 3.3.4.1.3. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is conservative with respect to the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.
[ The Frequency of 92 days is based on assumptions of the reliability analysis (Ref. 6) and on the methodology included in the determination of the trip setpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.3.4.1-11                                                      Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.4.1.2 is modified by two Notes in the SR table. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the
[LTSP] is used in the plant surveillance procedures [Nominal Trip Setpoint (NTSP)], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained.
If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP], then the channel shall be declared inoperable. The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
SR 3.3.4.1.3 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
[ 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS            B 3.3.4.1-12                                      Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.4.1.3 is modified by two Notes in the SR table. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the
[LTSP] is used in the plant surveillance procedures [NTSP], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP],
then the channel shall be declared inoperable. The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
SR 3.3.4.1.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The system functional test of the pump breakers is included as a part of this test, overlapping the LOGIC SYSTEM FUNCTIONAL TEST, to provide complete testing of the associated safety function. Therefore, if a breaker is incapable of operating, the associated instrument channel would also be inoperable.
General Electric BWR/6 STS              B 3.3.4.1-13                                                      Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE REQUIREMENTS (continued)
[ 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 test when performed at the 18 month Frequency.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.4.1.5 This SR ensures that an EOC-RPT initiated from the TSV Closure, Trip Oil Pressure - Low and TCV Fast Closure, Trip Oil Pressure - Low Functions will not be inadvertently bypassed when THERMAL POWER is 40% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint. Because main turbine bypass flow can affect this setpoint nonconservatively (THERMAL POWER is derived from first stage pressure), the main turbine bypass valves must remain closed at THERMAL POWER  40% RTP to ensure that the calibration remains valid. If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at  40% RTP either due to open main turbine bypass valves or other reasons), the affected TSV Closure, Trip Oil Pressure - Low and TCV Fast Closure, Trip Oil Pressure - Low Functions are considered inoperable. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met and the channel considered OPERABLE.
[ The Frequency of 18 months has shown that channel bypass failures between successive tests are rare.
OR General Electric BWR/6 STS                B 3.3.4.1-14                                                      Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.4.1.6 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. The EOC-RPT SYSTEM RESPONSE TIME acceptance criteria are included in Reference 7.
A Note to the Surveillance states that breaker interruption time may be assumed from the most recent performance of SR 3.3.4.1.7. This is allowed since the time to open the contacts after energization of the trip coil and the arc suppression time are short and do not appreciably change, due to the design of the breaker opening device and the fact that the breaker is not routinely cycled.
Response times cannot be determined at power because operation of final actuated devices is required. [ Therefore, 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 that cause serious response time degradation, but not channel failure, are infrequent occurrences.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS              B 3.3.4.1-15                                                      Rev. 5.0
 
EOC-RPT Instrumentation B 3.3.4.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.4.1.7 This SR ensures that the RPT breaker interruption time (arc suppression time plus time to open the contacts) is provided to the EOC-RPT SYSTEM RESPONSE TIME test. [ The 60 month Frequency of the testing is based on the difficulty of performing the test and the reliability of the circuit breakers.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. Regulatory Guide 1.105, "Setpoints for Safety-Related Instrumentation," Revision 3.
: 2. FSAR, Figure [ ] (EOC-RPT instrumentation logic).
: 3. FSAR, Section [5.2.2].
: 4. FSAR, Sections [15.1.1], [15.1.2], and [15.1.3].
: 5. FSAR, Sections [5.5.16.1] and [7.6.10].
: 6. GENE-770-06-1, "Bases for Changes To Surveillance Test Intervals And Allowed Out-Of-Service Times For Selected Instrumentation Technical Specifications," February 1991.
: 7. FSAR, Section [5.5.16.2].
General Electric BWR/6 STS              B 3.3.4.1-16                                                      Rev. 5.0
 
ATWS-RPT Instrumentation B 3.3.4.2 B 3.3 INSTRUMENTATION B 3.3.4.2  Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) Instrumentation BASES BACKGROUND            The ATWS-RPT System initiates a recirculation pump trip, adding negative reactivity, following events in which a scram does not (but should) occur, to lessen the effects of an ATWS event. Tripping the recirculation pumps adds negative reactivity from the increase in steam voiding in the core area as core flow decreases. When Reactor Vessel Water Level - Low Low, Level 2 or Reactor Steam Dome Pressure - High setpoint is reached, the recirculation pump motor breakers trip.
The ATWS-RPT System (Ref. 1) includes sensors, relays, bypass capability, circuit breakers, and switches that are necessary to cause initiation of a recirculation pump trip. The channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs an ATWS-RPT signal to the trip logic.
The ATWS-RPT consists of two independent trip systems, with two channels of Reactor Steam Dome Pressure - High and two channels of Reactor Vessel Water Level - Low Low, Level 2, in each trip system.
Each ATWS-RPT trip system is a two-out-of-two logic for each Function.
Thus, either two Reactor Water Level - Low Low, Level 2 or two Reactor Pressure - High signals are needed to trip a trip system. The outputs of the channels in a trip system are combined in a logic so that either trip system will trip both recirculation pumps (by tripping the respective fast speed and low frequency motor generator (LFMG) motor breakers).
There is one fast speed motor breaker and one LFMG breaker provided for each of the two recirculation pumps for a total of four breakers. The output of each trip system is provided to all four breakers.
APPLICABLE            The ATWS-RPT initiates an RPT to aid in preserving the integrity of the SAFETY                fuel cladding following events in which scram does not, but should, occur.
ANALYSES, LCO,        ATWS-RPT instrumentation satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).
and APPLICABILITY The OPERABILITY of the ATWS-RPT is dependent on the OPERABILITY of the individual instrumentation channel Functions. Each Function must have a required number of OPERABLE channels in each trip system, with their setpoints within the specified Allowable Value of SR 3.3.4.2.4. The actual setpoint is calibrated consistent with applicable General Electric BWR/6 STS              B 3.3.4.2-1                                      Rev. 5.0
 
ATWS-RPT Instrumentation B 3.3.4.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) setpoint methodology assumptions. Channel OPERABILITY also includes the associated recirculation pump drive motor breakers. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value.
Allowable Values are specified for each ATWS-RPT Function specified in the LCO. Nominal trip setpoints are specified in the setpoint calculations.
The nominal setpoints are selected to ensure the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift).
The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
The individual Functions are required to be OPERABLE in MODE 1 to protect against common mode failures of the Reactor Protection System by providing a diverse trip to mitigate the consequences of a postulated ATWS event. The Reactor Steam Dome Pressure - High and Reactor Vessel Water Level - Low Low, Level 2 Functions are required to be OPERABLE in MODE 1, since the reactor is producing significant power and the recirculation system could be at high flow. During this MODE, the potential exists for pressure increases or low water level, assuming an ATWS event. In MODE 2, the reactor is at low power and the recirculation system is at low flow; thus, the potential is low for a pressure increase or low water level, assuming an ATWS event. Therefore, the ATWS-RPT is not necessary. In MODES 3 and 4, the reactor is shut down with all control rods inserted; thus, an ATWS event is not significant and the possibility of a significant pressure increase or low water level is negligible. In MODE 5, the one-rod-out interlock ensures the reactor remains subcritical; thus, an ATWS event is not significant. In addition, the reactor pressure vessel (RPV) head is not fully tensioned and no pressure transient threat to the reactor coolant pressure boundary (RCPB) exists.
General Electric BWR/6 STS            B 3.3.4.2-2                                          Rev. 5.0
 
ATWS-RPT Instrumentation B 3.3.4.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The specific Applicable Safety Analyses and LCO discussions are listed below on a Function by Function basis.
: a. Reactor Vessel Water Level - Low Low, Level 2 Low RPV water level indicates the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, the ATWS-RPT System is initiated at Level 2 to aid in maintaining level above the top of the active fuel. The reduction of core flow reduces the neutron flux and THERMAL POWER and, therefore, the rate of coolant boiloff.
Reactor vessel water level signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.
Four channels of Reactor Vessel Level - Low Low, Level 2, with two channels in each trip system, are available and required to be OPERABLE to ensure that no single instrument failure can preclude an ATWS-RPT from this Function on a valid signal. The Reactor Vessel Water Level - Low Low, Level 2, Allowable Value is chosen so that the system will not initiate after a Level 3 scram with feedwater still available, and for convenience with the reactor core isolation cooling (RCIC) initiation.
: b. Reactor Steam Dome Pressure - High Excessively high RPV pressure may rupture the RCPB. An increase in the RPV pressure during reactor operation compresses the steam voids and results in a positive reactivity insertion. This increases neutron flux and THERMAL POWER, which could potentially result in fuel failure and RPV overpressurization. The Reactor Steam Dome Pressure - High Function initiates an RPT for transients that result in a pressure increase, counteracting the pressure increase by rapidly reducing core power generation. For the overpressurization event, the RPT aids in the termination of the ATWS event and, along with the safety/relief valves (S/RVs), limits the peak RPV pressure to less than the ASME Section III Code Service Level C limits (1500 psig).
The Reactor Steam Dome Pressure - High signals are initiated from four pressure transmitters that monitor reactor steam dome pressure. Four channels of Reactor Steam Dome Pressure - High, with two channels in each trip system, are available and required to be OPERABLE to ensure that no single instrument failure can preclude an ATWS-RPT from this General Electric BWR/6 STS            B 3.3.4.2-3                                        Rev. 5.0
 
ATWS-RPT Instrumentation B 3.3.4.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Function on a valid signal. The Reactor Steam Dome Pressure - High Allowable Value is chosen to provide an adequate margin to the ASME Section III Code Service Level C allowable Reactor Coolant System pressure.
ACTIONS            A Note has been provided to modify the ACTIONS related to ATWS-RPT instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable ATWS-RPT instrumentation channels provide appropriate compensatory measures for separate inoperable channels.
As such, a Note has been provided that allows separate Condition entry for each inoperable ATWS-RPT instrumentation channel.
A.1 and A.2 With one or more channels inoperable, but with ATWS-RPT capability for each Function maintained (refer to Required Action B.1 and C.1 Bases),
the ATWS-RPT System is capable of performing the intended function.
However, the reliability and redundancy of the ATWS-RPT instrumentation is reduced, such that a single failure in the remaining trip system could result in the inability of the ATWS-RPT System to perform the intended function. Therefore, only a limited time is allowed to restore the inoperable channels to OPERABLE status. Because of the diversity of sensors available to provide trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of ATWS-RPT, 14 days is provided to restore the inoperable channel (Required Action A.1). Alternately, the inoperable channel may be placed in trip (Required Action A.2), since this would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. As noted, placing the channel in trip with no further restrictions is not allowed if the inoperable channel is the result of an inoperable breaker, since this may not adequately compensate for the inoperable breaker (e.g., the breaker may be inoperable such that it will not open). [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If it is not desirable to place the channel in trip (e.g., as in the case where placing the inoperable channel would result in an RPT), or if the inoperable channel is the result of an inoperable breaker, Condition D must be entered and its Required Actions taken.
General Electric BWR/6 STS            B 3.3.4.2-4                                        Rev. 5.0
 
ATWS-RPT Instrumentation B 3.3.4.2 BASES ACTIONS (continued)
B.1 Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in the Function not maintaining ATWS-RPT trip capability. A Function is considered to be maintaining ATWS-RPT trip capability when sufficient channels are OPERABLE or in trip such that the ATWS-RPT System will generate a trip signal from the given Function on a valid signal, and both recirculation pumps can be tripped. This requires two channels of the Function in the same trip system to each be OPERABLE or in trip, and the four motor breakers (two fast speed and two LFMG) to be OPERABLE or in trip.
The 72 hour Completion Time is sufficient for the operator to take corrective action (e.g., restoration or tripping of channels) and takes into account the likelihood of an event requiring actuation of the ATWS-RPT instrumentation during this period and the fact that one Function is still maintaining ATWS-RPT trip capability.
C.1 Required Action C.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within both Functions result in both Functions not maintaining ATWS-RPT trip capability. The description of a Function maintaining ATWS-RPT trip capability is discussed in the Bases for Required Action B.1, above.
The 1 hour Completion Time is sufficient for the operator to take corrective action and takes into account the likelihood of an event requiring actuation of the ATWS-RPT instrumentation during this period.
D.1 and D.2 With any Required Action and associated Completion Time not met, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 2 within 6 hours (Required Action D.2). Alternately, the associated recirculation pump may be removed from service since this performs the intended Function of the instrumentation (Required Action D.1). The allowed Completion Time of 6 hours is reasonable, based on operating experience, both to reach MODE 2 from full power conditions and to remove a recirculation pump from service in an orderly manner and without challenging plant systems.
General Electric BWR/6 STS            B 3.3.4.2-5                                      Rev. 5.0
 
ATWS-RPT Instrumentation B 3.3.4.2 BASES ACTIONS (continued)
Required Action D.1 is modified by a Note which states that the Required Action is only applicable if the inoperable channel is the result of an inoperable RPT breaker. The Note clarifies the situations under which the associated Required Action would be the appropriate Required Action.
SURVEILLANCE        -----------------------------------REVIEWERS NOTE-----------------------------------
REQUIREMENTS        Certain Frequencies are based on approved topical reports. In order for a licensee to use these Frequencies, the licensee must justify the Frequencies as required by the staff SER for the topical report.
The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours provided the associated Function maintains ATWS-RPT trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 2) assumption of the average time required to perform channel surveillance.
That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the recirculation pumps will trip when necessary.
SR 3.3.4.2.1 Performance of the CHANNEL CHECK 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 instrument channels could be an indication of excessive instrument drift in one of the channels or 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 instrument has drifted outside its limit.
General Electric BWR/6 STS                B 3.3.4.2-6                                                      Rev. 5.0
 
ATWS-RPT Instrumentation B 3.3.4.2 BASES SURVEILLANCE REQUIREMENTS (continued)
[ The Frequency of 12 hours is based upon operating experience that demonstrates channel failure is rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the required channels of this LCO.
SR 3.3.4.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the 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 methodology.
[ The Frequency of 92 days is based on the reliability analysis of Reference 2.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.3.4.2-7                                                      Rev. 5.0
 
ATWS-RPT Instrumentation B 3.3.4.2 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.4.2.3 Calibration of trip units provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in SR 3.3.4.2.4.
There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology. If the trip setting is discovered to be less conservative than the setting accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.
[ The Frequency of 92 days is based on the reliability analysis of Reference 2.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.3.4.2-8                                                      Rev. 5.0
 
ATWS-RPT Instrumentation B 3.3.4.2 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.4.2.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology.
CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
[ 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.4.2.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required trip logic for a specific channel. The system functional test of the pump breakers, included as part of this Surveillance, overlaps the LOGIC SYSTEM FUNCTIONAL TEST to provide complete testing of the assumed safety function. Therefore, if a breaker is incapable of operating, the associated instrument channel(s) would be inoperable.
[ 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.
General Electric BWR/6 STS                B 3.3.4.2-9                                                      Rev. 5.0
 
ATWS-RPT Instrumentation B 3.3.4.2 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Figure [ ].
: 2. GENE-770-06-1, "Bases For Changes To Surveillance Test Intervals and Allowed Out-of-Service Times For Selected Instrumentation Technical Specifications," February 1991.
General Electric BWR/6 STS              B 3.3.4.2-10                                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 B 3.3 INSTRUMENTATION B 3.3.5.1  Emergency Core Cooling System (ECCS) Instrumentation BASES BACKGROUND          The purpose of the ECCS instrumentation is to initiate appropriate responses from the systems to ensure that fuel is adequately cooled in the event of a design basis accident or transient. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the ECCS, as well as LCOs on other reactor system parameters and equipment performance.
Technical Specifications are required by 10 CFR 50.36 to include LSSSs for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical 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 Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur.
                    -------------------------------- REVIEWER'S NOTE ------------------------------------
The term "Limiting Trip Setpoint" [LTSP] is generic terminology for the calculated trip setting (setpoint) value calculated by means of the plant specific setpoint methodology documented in a document controlled under 10 CFR 50.59. The term [LTSP] indicates that no additional margin has been added between the Analytical Limit and the calculated trip setting.
                    "Nominal Trip Setpoint [NTSP]" is the suggested terminology for the actual setpoint implemented in the plant surveillance procedures where margin has been added to the calculated [LTSP]. The as-found and as-left tolerances will apply to the [NTSP] implemented in the Surveillance procedures to confirm channel performance.
Licensees are to insert the name of the document(s) controlled under 10 CFR 50.59 that contain the methodology for calculating the as-left and as-found tolerances in Note f of Table 3.3.5.1-1, for the phrase "[insert the name of a document controlled under 10 CFR 50.59 such as the Technical Requirements Manual or any document incorporated into the facility FSAR]" throughout these Bases.
General Electric BWR/6 STS                B 3.3.5.1-1                                          Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued)
If the [LTSP] is not included in Table 3.3.5.1-1 for the purpose of compliance with 10 CFR 50.36, the plant specific location for the [LTSP]
or [NTSP] must be cited in Note f of Table 3.3.5.1-1. The brackets indicate plant specific terms may apply, as reviewed and approved by the NRC.
The [Limiting Trip Setpoint (LTSP)] specified in Table 3.3.5.1-1 is a predetermined setting for a protection channel chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the SL would not be exceeded. As such, the
[LTSP] accounts for uncertainties in setting the channel (e.g., calibration),
uncertainties in how the channel might actually perform (e.g.,
repeatability), changes in the point of action of the channel 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 [LTSP] ensures that SLs are not exceeded. Therefore the [LTSP] meets the definition of an LSSS (Ref. 1).
The Allowable Value specified in Table 3.3.5.1-1 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 surveillance interval.
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)." Relying solely on the [LTSP] to define OPERABILITY in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as found" value of a protection channel 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 protection channel with a setting that has been found to be different from the [LTSP] due to some drift of the setting may still be OPERABLE because drift is to be expected. This expected drift would have been specifically accounted for in the setpoint methodology for calculating the [LTSP] and thus the automatic protective action would still have ensured that the SL would not be exceeded with General Electric BWR/6 STS                B 3.3.5.1-2                                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued) the "as found" setting of the protection channel. Therefore, the channel would still be OPERABLE because it would have performed its safety function and the only corrective action required would be to reset the channel within the established as-left tolerance around [LTSP] to account for further drift during the next surveillance interval. Note that, although the channel is OPERABLE under these circumstances, the trip setpoint must be left adjusted to a value within the as-left tolerance, 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 (as-found criteria).
However, there is also some point beyond which the channel may not be able to perform its function due to, for example, greater than expected drift. This value needs to be specified in the Technical Specifications in order to define OPERABILITY of the channels and is designated as the Allowable Value.
If the actual setting (as-found setpoint) of the channel is found to be conservative with respect to the Allowable Value but is beyond the as-found tolerance band, the channel is OPERABLE, but degraded. The degraded condition will be further evaluated during performance of the SR. This evaluation will consist of resetting the channel setpoint to the
[LTSP] (within the allowed tolerance), and evaluating the channel response. If the channel is functioning as required and expected to pass the next surveillance, then the channel is OPERABLE and can be restored to service at the completion of the surveillance. After the surveillance is completed, the channel as-found condition will be entered into the Corrective Action Program for further evaluation.
For most anticipated operational occurrences (AOOs) and Design Basis Accidents (DBAs), a wide range of dependent and independent parameters are monitored.
The ECCS instrumentation actuates low pressure core spray (LPCS), low pressure coolant injection (LPCI), high pressure core spray (HPCS),
Automatic Depressurization System (ADS), and the diesel generators (DGs). The equipment involved with each of these systems is described in the Bases for LCO 3.5.1, "ECCS - Operating."
General Electric BWR/6 STS            B 3.3.5.1-3                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued)
Low Pressure Core Spray System The LPCS System may be initiated by either automatic or manual means.
Automatic initiation occurs for conditions of Reactor Vessel Water Level -
Low Low Low, Level 1 or Drywell Pressure - High. Each of these diverse variables is monitored by two redundant transmitters, which are, in turn, connected to two trip units. The outputs of the four trip units (two trip units from each of the two variables) are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic. The high drywell pressure initiation signal is a sealed in signal and must be manually reset. The logic can also be initiated by use of a manual push button. Upon receipt of an initiation signal, the LPCS pump is started immediately after power is available.
The LPCS test line isolation valve, which is also a primary containment isolation valve (PCIV), is closed on a LPCS initiation signal to allow full system flow assumed in the accident analysis and maintains containment isolation in the event LPCS is not operating.
The LPCS pump discharge flow is monitored by a flow transmitter. When the pump is running and discharge flow is low enough that pump overheating may occur, the minimum flow return line valve is opened.
The valve is automatically closed if flow is above the minimum flow setpoint to allow the full system flow assumed in the accident analysis.
The LPCS System also monitors the pressure in the reactor vessel to ensure that, before the injection valve opens, the reactor pressure has fallen to a value below the LPCS System's maximum design pressure.
The variable is monitored by four redundant transmitters, which are, in turn, connected to trip units. The outputs of the trip units are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic.
Low Pressure Coolant Injection Subsystems The LPCI is an operating mode of the Residual Heat Removal (RHR)
System, with three LPCI subsystems. The LPCI subsystems may be initiated by automatic or manual means. Automatic initiation occurs for conditions of Reactor Vessel Water Level - Low Low Low, Level 1 or Drywell Pressure - High. Each of these diverse variables is monitored by two redundant transmitters per Division, which are, in turn, connected to two trip units. The outputs of the four Division 2 LPCI (loops B and C) trip units (two trip units from each of the two variables) are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic.
The Division 1 LPCI (loop A) receives its initiation signal from the LPCS General Electric BWR/6 STS            B 3.3.5.1-4                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued) logic, which uses a similar one-out-of-two taken twice logic. The two Divisions can also be initiated by use of a manual push button (one per Division). Once an initiation signal is received by the LPCI control circuitry, the signal is sealed in until manually reset.
Upon receipt of an initiation signal, the LPCI Pump C is started immediately after power is available while LPCI A and LPCI B pumps are started after a 5 second delay, to limit the loading on the standby power sources.
Each LPCI subsystem's discharge flow is monitored by a flow transmitter.
When a pump is running and discharge flow is low enough that pump overheating may occur, the respective minimum flow return line valve is opened. The valve is automatically closed if flow is above the minimum flow setpoint to allow the full system flow assumed in the analyses.
The RHR test line suppression pool cooling isolation and suppression pool spray isolation valves (which are also PCIVs) are closed on a LPCI initiation signal to allow full system flow assumed in the accident analysis and maintain containment isolated in the event LPCI is not operating.
The LPCI subsystems monitor the pressure in the reactor vessel to ensure that, prior to an injection valve opening, the reactor pressure has fallen to a value below the LPCI subsystem's maximum design pressure.
The variable is monitored by four redundant transmitters per Division, which are, in turn, connected to four trip units. The outputs of the four Division 2 LPCI (loops B and C) trip units are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic. The Division 1 LPCI (loop A) receives its signal from the LPCS logic, which uses a similar one-out-of-two taken twice logic.
High Pressure Core Spray System The HPCS System may be initiated by either automatic or manual means.
Automatic initiation occurs for conditions of Reactor Vessel Water Level -
Low Low, Level 2 or Drywell Pressure - High. The outputs of the trip units are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic for each variable. The HPCS System initiation signal is a sealed in signal and must be manually reset.
The HPCS pump discharge flow is monitored by a flow transmitter. When the pump is running and discharge flow is low enough that pump overheating may occur, the minimum flow return line valve is opened.
The valve is automatically closed if flow is above the minimum flow setpoint to allow full system flow assumed in the accident analyses.
General Electric BWR/6 STS            B 3.3.5.1-5                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued)
The HPCS test line isolation valve (which is also a PCIV) is closed on a HPCS initiation signal to allow full system flow assumed in the accident analyses and maintain containment isolated in the event HPCS is not operating.
The HPCS System also monitors the water levels in the condensate storage tank (CST) and the suppression pool, since these are the two sources of water for HPCS operation. Reactor grade water in the CST is the normal and preferred source. Upon receipt of a HPCS initiation signal, the CST suction valve is automatically signaled to open (it is normally in the open position), unless the suppression pool suction valve is open. If the water level in the CST falls below a preselected level, first the suppression pool suction valve automatically opens, and then the CST suction valve automatically closes. Two level transmitters are used to detect low water level in the CST. Either transmitter and associated trip unit can cause the suppression pool suction valve to open and the CST suction valve to close. The suppression pool suction valve also automatically opens and the CST suction valve closes if high water level is detected in the suppression pool. To prevent losing suction to the pump, the suction valves are interlocked so that one suction path must be open before the other automatically closes.
The HPCS System provides makeup water to the reactor until the reactor vessel water level reaches the high water level (Level 8) trip, at which time the HPCS injection valve closes. The HPCS pump will continue to run on minimum flow. The logic is two-out-of-two to provide high reliability of the HPCS System. The injection valve automatically reopens if a low low water level signal is subsequently received.
Automatic Depressurization System ADS may be initiated by either automatic or manual means. Automatic initiation occurs when signals indicating Reactor Vessel Water Level -
Low Low Low, Level 1; Drywell Pressure - High or ADS Bypass Timer; confirmed Reactor Vessel Water Level - Low, Level 3; and either LPCS or LPCI Pump Discharge Pressure - High are all present, and the ADS Initiation Timer has timed out. There are two transmitters each for Reactor Vessel Water Level - Low Low Low, Level 1 and Drywell Pressure - High, and one transmitter for confirmed Reactor Vessel Water Level - Low, Level 3 in each of the two ADS trip systems. Each of these transmitters connects to a trip unit, which then drives a relay whose contacts form the initiation logic.
General Electric BWR/6 STS              B 3.3.5.1-6                                    Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued)
Each ADS trip system (trip system A and trip system B) includes a time delay between satisfying the initiation logic and the actuation of the ADS valves. The time delay chosen is long enough that the HPCS has time to operate to recover to a level above Level 1, yet not so long that the LPCI and LPCS systems are unable to adequately cool the fuel if the HPCS fails to maintain level. An alarm in the control room is annunciated when either of the timers is running. Resetting the ADS initiation signals resets the ADS Initiation Timers.
The ADS also monitors the discharge pressures of the three LPCI pumps and the LPCS pump. Each ADS trip system includes two discharge pressure permissive transmitters from each of the two low pressure ECCS pumps in the associated Division (i.e., Division 1 ECCS inputs to ADS trip system A and Division 2 ECCS inputs to ADS trip system B).
The signals are used as a permissive for ADS actuation, indicating that there is a source of core coolant available once the ADS has depressurized the vessel. Any one of the four low pressure pumps provides sufficient core coolant flow to permit automatic depressurization.
The ADS logic in each trip system is arranged in two strings. One string has a contact from each of the following variables: Reactor Vessel Water Level - Low Low Low, Level 1; Drywell Pressure - High or ADS Bypass Timer; Reactor Vessel Water Level - Low, Level 3; ADS Initiation Timer; and two low pressure ECCS Discharge Pressure - High contacts. The other string has a contact from each of the following variables: Reactor Vessel Water Level - Low Low Low, Level 1; Drywell Pressure - High; ADS Bypass Timer; and two low pressure ECCS Discharge Pressure -
High contacts. To initiate an ADS trip system, the following applicable contacts must close in the associated string: Reactor Vessel Water Level
                    - Low Low Low, Level 1; Drywell Pressure - High or ADS Bypass Timer; Reactor Vessel Water Level - Low, Level 3; ADS Initiation Timer; and one of the two low pressure ECCS Discharge Pressure - High contacts.
Either ADS trip system A or trip system B will cause all the ADS relief valves to open. Once the Drywell Pressure - High or ADS initiation signals are present, they are individually sealed in until manually reset.
Manual initiation is accomplished by operating the control switch for each safety/relief valve (S/RV) associated with the ADS. Manual inhibit switches are provided in the control room for ADS; however, their function is not required for ADS OPERABILITY (provided ADS is not inhibited when required to be OPERABLE).
General Electric BWR/6 STS            B 3.3.5.1-7                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued)
Diesel Generators The Division 1, 2, and 3 DGs may be initiated by either automatic or manual means. Automatic initiation occurs for conditions of Reactor Vessel Water Level - Low Low Low, Level 1 or Drywell Pressure - High for DGs 11 and 12, and Reactor Vessel Water Level - Low Low, Level 2 or Drywell Pressure - High for DG 13. The DGs are also initiated upon loss of voltage signals. (Refer to Bases for LCO 3.3.8.1, "Loss of Power (LOP) Instrumentation," for a discussion of these signals.) Each of these diverse variables is monitored by two redundant transmitters per DG, which are, in turn, connected to two trip units. The outputs of the four divisionalized trip units (two trip units from each of the two variables) are connected to relays whose contacts are connected to a one-out-of-two taken twice logic. The DGs receive their initiation signals from the associated Divisions' ECCS logic (i.e., DG 11 receives an initiation signal from Division 1 ECCS (LPCS and LPCI A); DG 12 receives an initiation signal from Division 2 ECCS (LPCI B and LPCI C); and DG 13 receives an initiation signal from Division 3 ECCS (HPCS)). The DGs can also be started manually from the control room and locally in the associated DG room. The DG initiation signal is a sealed in signal and must be manually reset. The DG initiation logic is reset by resetting the associated ECCS initiation logic. Upon receipt of a LOCA initiation signal, each DG is automatically started, is ready to load in approximately 10 seconds, and will run in standby conditions (rated voltage and speed, with the DG output breaker open). The DGs will only energize their respective Engineered Safety Feature (ESF) buses if a loss of offsite power occurs.
(Refer to Bases for LCO 3.3.8.1.)
APPLICABLE          The actions of the ECCS are explicitly assumed in the safety analyses of SAFETY              References 2, 3, and 4. The ECCS is initiated to preserve the integrity of ANALYSES, LCO,      the fuel cladding by limiting the post LOCA peak cladding temperature to and APPLICABILITY    less than the 10 CFR 50.46 limits.
ECCS instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.
Permissive and interlock setpoints allow the blocking of trips during plant startups, and restoration of trips when the permissive conditions are not satisfied, but they are not explicitly modeled in the Safety Analyses.
These permissives and interlocks ensure that the starting conditions are consistent with the safety analysis, before preventive or mitigating actions occur. Because these permissives or interlocks are only one of multiple conservative starting assumptions for the accident analysis, they are generally considered as nominal values without regard to measurement accuracy.
General Electric BWR/6 STS            B 3.3.5.1-8                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The OPERABILITY of the ECCS instrumentation is dependent upon the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.5.1-1. Each Function must have a required number of OPERABLE channels, with their setpoints set within the setting tolerance of the [LTSP], where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
Each ECCS subsystem must also respond within its assumed response time.
Allowable Values are specified for each ECCS Function specified in Table 3.3.5.1-1. [LTSPs] and the methodologies for calculation of the as-left and as-found tolerances are described in [insert the name of a document controlled under 10 CFR 50.59 such as the Technical Requirements Manual or any document incorporated into the facility FSAR]. The [LTSPs] are selected to ensure that the setpoints remain conservative with respect to the as-found tolerance band between CHANNEL CALIBRATIONS. After each calibration the trip setpoint shall be left within the as-left band around the [LTSP].
Table 3.3.5.1-1 is modified by a footnote which is added to show that certain ECCS instrumentation Functions also perform DG initiation and actuation of other Technical Specifications (TS) equipment.
[LTSPs] are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytical limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytical limits, corrected for calibration, process, and some of the instrument errors. The [LTSPs] are then determined, accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
In general, the individual Functions are required to be OPERABLE in the MODES or other specified conditions that may require ECCS (or DG) initiation to mitigate the consequences of a design basis accident or transient. To ensure reliable ECCS and DG function, a combination of Functions is required to provide primary and secondary initiation signals.
General Electric BWR/6 STS            B 3.3.5.1-9                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
Low Pressure Core Spray and Low Pressure Coolant Injection Systems 1.a, 2.a. Reactor Vessel Water Level - Low Low Low, Level 1 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. The low pressure ECCS and associated DGs are initiated at Level 1 to ensure that core spray and flooding functions are available to prevent or minimize fuel damage. The Reactor Vessel Water Level - Low Low Low, Level 1 is one of the Functions assumed to be OPERABLE and capable of initiating the ECCS during the transients analyzed in References 2 and 4. In addition, the Reactor Vessel Water Level - Low Low Low, Level 1 Function is directly assumed in the analysis of the recirculation line break (Ref. 3). The core cooling function of the ECCS, along with the scram action of the Reactor Protection System (RPS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Reactor Vessel Water Level - Low Low Low, Level 1 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. The Reactor Vessel Water Level - Low Low Low, Level 1 Allowable Value is chosen to allow time for the low pressure core flooding systems to activate and provide adequate cooling.
Two channels of Reactor Vessel Water Level - Low Low Low, Level 1 Function per associated Division are only required to be OPERABLE when the associated ECCS is required to be OPERABLE, to ensure that no single instrument failure can preclude ECCS initiation. (Two channels input to LPCS and LPCI A, while the other two channels input to LPCI B and LPCI C.)
General Electric BWR/6 STS            B 3.3.5.1-10                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 1.b, 2.b. Drywell Pressure - High High pressure in the drywell could indicate a break in the reactor coolant pressure boundary (RCPB). The low pressure ECCS and associated DGs are initiated upon receipt of the Drywell Pressure - High Function in order to minimize the possibility of fuel damage. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
High drywell pressure signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside primary containment.
Negative barometric fluctuations are accounted for in the Allowable Value.
The Drywell Pressure - High Function is required to be OPERABLE when the associated ECCS and DGs are required to be OPERABLE in conjunction with times when the primary containment is required to be OPERABLE. Thus, four channels of the LPCS and LPCI Drywell Pressure - High Function are required to be OPERABLE in MODES 1, 2, and 3 to ensure that no single instrument failure can preclude ECCS initiation. (Two channels input to LPCS and LPCI A, while the other two channels input to LPCI B and LPCI C.) In MODES 4 and 5, the Drywell Pressure - High Function is not required since there is insufficient energy in the reactor to pressurize the primary containment to Drywell Pressure -
High setpoint. Refer to LCO 3.5.1 for Applicability Bases for the low pressure ECCS subsystems and to LCO 3.8.1 for Applicability Bases for the DGs.
1.c, 2.c. Low Pressure Coolant Injection Pump A and Pump B Start -
Time Delay Relay The purpose of this time delay is to stagger the start of the two ECCS pumps that are in each of Divisions 1 and 2, thus limiting the starting transients on the 4.16 kV emergency buses. This Function is only necessary when power is being supplied from the standby power sources (DG). However, since the time delay does not degrade ECCS operation, it remains in the pump start logic at all times. The LPCI Pump Start -
Time Delay Relays are assumed to be OPERABLE in the accident and transient analyses requiring ECCS initiation. That is, the analysis assumes that the pumps will initiate when required and excess loading will not cause failure of the power sources.
General Electric BWR/6 STS            B 3.3.5.1-11                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
There are two LPCI Pump Start - Time Delay Relays, one in each of the RHR "A" and RHR "B" pump start logic circuits. While each time delay relay is dedicated to a single pump start logic, a single failure of a LPCI Pump Start - Time Delay Relay could result in the failure of the two low pressure ECCS pumps, powered from the same ESF bus, to perform their intended function within the assumed ECCS RESPONSE TIMES (e.g., as in the case where both ECCS pumps on one ESF bus start simultaneously due to an inoperable time delay relay). This still leaves two of the four low pressure ECCS pumps OPERABLE; thus, the single failure criterion is met (i.e., loss of one instrument does not preclude ECCS initiation). The Allowable Value for the LPCI Pump Start - Time Delay Relay is chosen to be long enough so that most of the starting transient of the first pump is complete before starting the second pump on the same 4.16 kV emergency bus and short enough so that ECCS operation is not degraded.
Each LPCI Pump Start - Time Delay Relay Function is only required to be OPERABLE when the associated LPCI subsystem is required to be OPERABLE.
1.d, 2.d. Reactor Steam Dome Pressure - Low (Injection Permissive)
Low reactor steam dome pressure signals are used as permissives for the low pressure ECCS subsystems. This ensures that, prior to opening the injection valves of the low pressure ECCS subsystems, the reactor pressure has fallen to a value below these subsystems' maximum design pressure. The Reactor Steam Dome Pressure - Low is one of the Functions assumed to be OPERABLE and capable of permitting initiation of the ECCS during the transients analyzed in References 2 and 4. In addition, the Reactor Steam Dome Pressure - Low Function is directly assumed in the analysis of the recirculation line break (Ref. 3). The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
The Reactor Steam Dome Pressure - Low signals are initiated from four pressure transmitters that sense the reactor dome pressure. The four pressure transmitters each drive a master and slave trip unit (for a total of eight trip units).
General Electric BWR/6 STS            B 3.3.5.1-12                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Allowable Value is low enough to prevent overpressurizing the equipment in the low pressure ECCS, but high enough to ensure that the ECCS injection prevents the fuel peak cladding temperature from exceeding the limits of 10 CFR 50.46.
Three channels of Reactor Steam Dome Pressure - Low Function per associated Division are only required to be OPERABLE when the associated ECCS is required to be OPERABLE to ensure that no single instrument failure can preclude ECCS initiation. (Three channels are required for LPCS and LPCI A, while three other channels are required for LPCI B and LPCI C.)
1.e, 1.f, 2.e. Low Pressure Coolant Injection and Low Pressure Core Spray Pump Discharge Flow - Low (Bypass)
The minimum flow instruments are provided to protect the associated low pressure ECCS pump from overheating when the pump is operating and the associated injection valve is not fully open. The minimum flow line valve is opened when low flow is sensed, and the valve is automatically closed when the flow rate is adequate to protect the pump. The LPCI and LPCS Pump Discharge Flow - Low Functions are assumed to be OPERABLE and capable of closing the minimum flow valves to ensure that the low pressure ECCS flows assumed during the transients and accidents analyzed in References 2, 3, and 4 are met. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
One flow transmitter per ECCS pump is used to detect the associated subsystems' flow rates. The logic is arranged such that each transmitter causes its associated minimum flow valve to open. The logic will close the minimum flow valve once the closure setpoint is exceeded. The LPCI minimum flow valves are time delayed such that the valves will not open for 10 seconds after the switches detect low flow. The time delay is provided to limit reactor vessel inventory loss during the startup of the RHR shutdown cooling mode (for RHR A and RHR B). The Pump Discharge Flow - Low Allowable Values are high enough to ensure that the pump flow rate is sufficient to protect the pump, yet low enough to ensure that the closure of the minimum flow valve is initiated to allow full flow into the core.
General Electric BWR/6 STS          B 3.3.5.1-13                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Each channel of Pump Discharge Flow - Low Function (one LPCS channel and three LPCI channels) is only required to be OPERABLE when the associated ECCS is required to be OPERABLE, to ensure that no single instrument failure can preclude the ECCS function. Refer to LCO 3.5.1 and LCO 3.5.2 for Applicability Bases for the low pressure ECCS subsystems.
1.g, 2.f. Manual Initiation The Manual Initiation push button channels introduce signals into the appropriate ECCS logic to provide manual initiation capability and are redundant to the automatic protective instrumentation. There is one push button for each of the two Divisions of low pressure ECCS (i.e., Division 1 ECCS, LPCS and LPCI A; Division 2 ECCS, LPCI B and LPCI C).
The Manual Initiation Function is not assumed in any accident or transient analyses in the FSAR. However, the Function is retained for overall redundancy and diversity of the low pressure ECCS function as required by the NRC in the plant licensing basis.
There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.
Each channel of the Manual Initiation Function (one channel per Division) is only required to be OPERABLE when the associated ECCS is required to be OPERABLE.
High Pressure Core Spray System 3.a. Reactor Vessel Water Level - Low Low, Level 2 Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, the HPCS System and associated DG is initiated at Level 2 to maintain level above the top of the active fuel. The Reactor Vessel Water Level - Low Low, Level 2 is one of the Functions assumed to be OPERABLE and capable of initiating HPCS during the transients analyzed in References 2 and 4. The Reactor Vessel Water Level - Low Low, Level 2 Function associated with HPCS is directly assumed in the analysis of the recirculation line break (Ref. 3). The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
General Electric BWR/6 STS          B 3.3.5.1-14                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Reactor Vessel Water Level - Low Low, Level 2 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.
The Reactor Vessel Water Level - Low Low, Level 2 Allowable Value is chosen such that for complete loss of feedwater flow, the Reactor Core Isolation Cooling (RCIC) System flow with HPCS assumed to fail will be sufficient to avoid initiation of low pressure ECCS at Reactor Vessel Water Level - Low Low Low, Level 1.
Four channels of Reactor Vessel Water Level - Low Low, Level 2 Function are only required to be OPERABLE when HPCS is required to be OPERABLE to ensure that no single instrument failure can preclude HPCS initiation. Refer to LCO 3.5.1 and LCO 3.5.2 for HPCS Applicability Bases.
3.b. Drywell Pressure - High High pressure in the drywell could indicate a break in the RCPB. The HPCS System and associated DG are initiated upon receipt of the Drywell Pressure - High Function in order to minimize the possibility of fuel damage. The Drywell Pressure - High Function is not assumed in the analysis of the recirculation line break (Ref. 3); that is, HPCS is assumed to be initiated on Reactor Water Level - Low Low, Level 2. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Drywell Pressure - High signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside primary containment.
The Drywell Pressure - High Function is required to be OPERABLE when HPCS is required to be OPERABLE in conjunction with times when the primary containment is required to be OPERABLE. Thus, four channels of the HPCS Drywell Pressure - High Function are required to be OPERABLE in MODES 1, 2, and 3, to ensure that no single instrument failure can preclude ECCS initiation. In MODES 4 and 5, the Drywell Pressure - High Function is not required since there is insufficient energy in the reactor to pressurize the drywell to the Drywell Pressure - High Function's setpoint. Refer to LCO 3.5.1 for the Applicability Bases for the HPCS System.
General Electric BWR/6 STS            B 3.3.5.1-15                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 3.c. Reactor Vessel Water Level - High, Level 8 High RPV water level indicates that sufficient cooling water inventory exists in the reactor vessel such that there is no danger to the fuel.
Therefore, the Level 8 signal is used to close the HPCS injection valve to prevent overflow into the main steam lines (MSLs). The Reactor Vessel Water Level - High, Level 8 Function is not assumed in the accident and transient analyses. It was retained since it is a potentially significant contributor to risk. Reactor Vessel Water Level - High, Level 8 signals for HPCS are initiated from two level transmitters from the narrow range water level measurement instrumentation. Both Level 8 signals are required in order to close the HPCS injection valve. This ensures that no single instrument failure can preclude HPCS initiation. The Reactor Vessel Water Level - High, Level 8 Allowable Value is chosen to isolate flow from the HPCS System prior to water overflowing into the MSLs.
Two channels of Reactor Vessel Water Level - High, Level 8 Function are only required to be OPERABLE when HPCS is required to be OPERABLE. Refer to LCO 3.5.1 for HPCS Applicability Bases.
3.d. Condensate Storage Tank Level - Low Low level in the CST indicates the unavailability of an adequate supply of makeup water from this normal source. Normally the suction valves between HPCS and the CST are open and, upon receiving a HPCS initiation signal, water for HPCS injection would be taken from the CST.
However, if the water level in the CST falls below a preselected level, first the suppression pool suction valve automatically opens, and then the CST suction valve automatically closes. This ensures that an adequate supply of makeup water is available to the HPCS pump. To prevent losing suction to the pump, the suction valves are interlocked so that the suppression pool suction valve must be open before the CST suction valve automatically closes. The Function is implicitly assumed in the accident and transient analyses (which take credit for HPCS) since the analyses assume that the HPCS suction source is the suppression pool.
Condensate Storage Tank Level - Low signals are initiated from two level transmitters. The logic is arranged such that either transmitter and associated trip unit can cause the suppression pool suction valve to open and the CST suction valve to close. The Condensate Storage Tank Level
                    - Low Function Allowable Value is high enough to ensure adequate pump suction head while water is being taken from the CST.
General Electric BWR/6 STS            B 3.3.5.1-16                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Two channels of the Condensate Storage Tank Level - Low Function are only required to be OPERABLE when HPCS is required to be OPERABLE to ensure that no single instrument failure can preclude HPCS swap to suppression pool source. Thus, the Function is required to be OPERABLE in MODES 1, 2, and 3. In MODES 4 and 5, the Function is required to be OPERABLE only when HPCS is required to be OPERABLE to fulfill the requirements of LCO 3.5.2, HPCS is aligned to the CST, and the CST water level is not within the limits of SR 3.5.2.2.
With CST water level within limits, a sufficient supply of water exists for injection to minimize the consequences of a vessel draindown event.
Refer to LCO 3.5.1 and LCO 3.5.2 for HPCS Applicability Bases.
3.e. Suppression Pool Water Level - High Excessively high suppression pool water could result in the loads on the suppression pool exceeding design values should there be a blowdown of the reactor vessel pressure through the S/RVs. Therefore, signals indicating high suppression pool water level are used to transfer the suction source of HPCS from the CST to the suppression pool to eliminate the possibility of HPCS continuing to provide additional water from a source outside containment. To prevent losing suction to the pump, the suction valves are interlocked so that the suppression pool suction valve must be open before the CST suction valve automatically closes. This Function is implicitly assumed in the accident and transient analyses (which take credit for HPCS) since the analyses assume that the HPCS suction source is the suppression pool.
Suppression Pool Water Level - High signals are initiated from two level transmitters. The logic is arranged such that either transmitter and associated trip unit can cause the suppression pool suction valve to open and the CST suction valve to close. The Allowable Value for the Suppression Pool Water Level - High Function is chosen to ensure that HPCS will be aligned for suction from the suppression pool before the water level reaches the point at which suppression pool design loads would be exceeded.
Two channels of Suppression Pool Water Level - High Function are only required to be OPERABLE in MODES 1, 2, and 3 when HPCS is required to be OPERABLE to ensure that no single instrument failure can preclude HPCS swap to suppression pool source. In MODES 4 and 5, the Function is not required to be OPERABLE since the reactor is depressurized and vessel blowdown, which could cause the design values of the containment to be exceeded, cannot occur. Refer to LCO 3.5.1 for HPCS Applicability Bases.
General Electric BWR/6 STS          B 3.3.5.1-17                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 3.f, 3.g. HPCS Pump Discharge Pressure - High (Bypass) and HPCS System Flow Rate - Low (Bypass)
The minimum flow instruments are provided to protect the HPCS pump from overheating when the pump is operating and the associated injection valve is not fully open. The minimum flow line valve is opened when low flow and high pump discharge pressure are sensed, and the valve is automatically closed when the flow rate is adequate to protect the pump or the discharge pressure is low (indicating the HPCS pump is not operating). The HPCS System Flow Rate - Low and HPCS Pump Discharge Pressure - High Functions are assumed to be OPERABLE and capable of closing the minimum flow valve to ensure that the ECCS flow assumed during the transients and accidents analyzed in References 2, 3, and 4 are met. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
One flow transmitter is used to detect the HPCS System's flow rate. The logic is arranged such that the transmitter causes the minimum flow valve to open, provided the HPCS pump discharge pressure, sensed by another transmitter, is high enough (indicating the pump is operating).
The logic will close the minimum flow valve once the closure setpoint is exceeded. (The valve will also close upon HPCS pump discharge pressure decreasing below the setpoint.)
The HPCS System Flow Rate - Low and HPCS Pump Discharge Pressure - High Allowable Value is high enough to ensure that pump flow rate is sufficient to protect the pump, yet low enough to ensure that the closure of the minimum flow valve is initiated to allow full flow into the core. The HPCS Pump Discharge Pressure - High Allowable Value is set high enough to ensure that the valve will not be open when the pump is not operating.
One channel of each Function is required to be OPERABLE when the HPCS is required to be OPERABLE. Refer to LCO 3.5.1 and LCO 3.5.2 for HPCS Applicability Bases.
3.h. Manual Initiation The Manual Initiation push button channel introduces a signal into the HPCS logic to provide manual initiation capability and is redundant to the automatic protective instrumentation. There is one push button for the HPCS System.
General Electric BWR/6 STS            B 3.3.5.1-18                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Manual Initiation Function is not assumed in any accident or transient analysis in the FSAR. However, the Function is retained for overall redundancy and diversity of the HPCS function as required by the NRC in the plant licensing basis.
There is no Allowable Value for this Function since the channel is mechanically actuated based solely on the position of the push button.
One channel of the Manual Initiation Function is only required to be OPERABLE when the HPCS System is required to be OPERABLE.
Refer to LCO 3.5.1 and LCO 3.5.2 for HPCS Applicability Bases.
Automatic Depressurization System 4.a, 5.a. Reactor Vessel Water Level - Low Low Low, Level 1 Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, ADS receives one of the signals necessary for initiation from this Function. The Reactor Vessel Water Level - Low Low Low, Level 1 is one of the Functions assumed to be OPERABLE and capable of initiating the ADS during the accidents analyzed in Reference 3. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Reactor Vessel Water Level - Low Low Low, Level 1 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level - Low Low Low, Level 1 Function are only required to be OPERABLE when ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. (Two channels input to ADS trip system A while the other two channels input to ADS trip system B). Refer to LCO 3.5.1 for ADS Applicability Bases.
The Reactor Vessel Water Level - Low Low Low, Level 1 Allowable Value is high enough to allow time for the low pressure core flooding systems to initiate and provide adequate cooling.
General Electric BWR/6 STS            B 3.3.5.1-19                                    Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 4.b, 5.b. Drywell Pressure - High High pressure in the drywell could indicate a break in the RCPB.
Therefore, ADS receives one of the signals necessary for initiation from this Function in order to minimize the possibility of fuel damage. The Drywell Pressure - High is assumed to be OPERABLE and capable of initiating the ADS during the accidents analyzed in Reference 3. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Drywell Pressure - High signals are initiated from four pressure transmitters that sense drywell pressure. The Allowable Value was selected to be as low as possible and be indicative of a LOCA inside primary containment.
Four channels of Drywell Pressure - High Function are only required to be OPERABLE when ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. (Two channels input to ADS trip system A while the other two channels input to ADS trip system B.) Refer to LCO 3.5.1 for ADS Applicability Bases.
4.c, 5.c. ADS Initiation Timer The purpose of the ADS Initiation Timer is to delay depressurization of the reactor vessel to allow the HPCS System time to maintain reactor vessel water level. Since the rapid depressurization caused by ADS operation is one of the most severe transients on the reactor vessel, its occurrence should be limited. By delaying initiation of the ADS Function, the operator is given the chance to monitor the success or failure of the HPCS System to maintain water level, and then to decide whether or not to allow ADS to initiate, to delay initiation further by recycling the timer, or to inhibit initiation permanently. The ADS Initiation Timer Function is assumed to be OPERABLE for the accident analyses of Reference 3 that require ECCS initiation and assume failure of the HPCS System.
There are two ADS Initiation Timer relays, one in each of the two ADS trip systems. The Allowable Value for the ADS Initiation Timer is chosen to be short enough so that there is still time after depressurization for the low pressure ECCS subsystems to provide adequate core cooling.
Two channels of the ADS Initiation Timer Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. (One channel inputs to ADS trip system A while the other channel inputs to ADS trip system B.) Refer to LCO 3.5.1 for ADS Applicability Bases.
General Electric BWR/6 STS              B 3.3.5.1-20                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 4.d, 5.d. Reactor Vessel Water Level - Low, Level 3 The Reactor Vessel Water Level - Low, Level 3 Function is used by the ADS only as a confirmatory low water level signal. ADS receives one of the signals necessary for initiation from Reactor Vessel Water Level - Low Low Low, Level 1 signals. In order to prevent spurious initiation of the ADS due to spurious Level 1 signals, a Level 3 signal must also be received before ADS initiation commences.
Reactor Vessel Water Level - Low, Level 3 signals are initiated from two level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. The Allowable Value for Reactor Vessel Water Level - Low, Level 3 is selected at the RPS Level 3 scram Allowable Value for convenience. Refer to LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," for Bases discussion of this Function.
Two channels of Reactor Vessel Water Level - Low, Level 3 Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. (One channel inputs to ADS trip system A while the other channel inputs to ADS trip system B.) Refer to LCO 3.5.1 for ADS Applicability Bases.
4.e, 4.f, 5.e. Low Pressure Core Spray and Low Pressure Coolant Injection Pump Discharge Pressure - High The Pump Discharge Pressure - High signals from the LPCS and LPCI pumps are used as permissives for ADS initiation, indicating that there is a source of low pressure cooling water available once the ADS has depressurized the vessel. Pump Discharge Pressure - High is one of the Functions assumed to be OPERABLE and capable of permitting ADS initiation during the events analyzed in References 3 and 4 with an assumed HPCS failure. For these events, the ADS depressurizes the reactor vessel so that the low pressure ECCS can perform the core cooling functions. This core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Pump discharge pressure signals are initiated from eight pressure transmitters, two on the discharge side of each of the four low pressure ECCS pumps. In order to generate an ADS permissive in one trip system, it is necessary that only one pump (both channels for the pump) indicate the high discharge pressure condition. The Pump Discharge General Electric BWR/6 STS            B 3.3.5.1-21                                    Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Pressure - High Allowable Value is less than the pump discharge pressure when the pump is operating in a full flow mode, and high enough to avoid any condition that results in a discharge pressure permissive when the LPCS and LPCI pumps are aligned for injection and the pumps are not running. The actual operating point of this Function is not assumed in any transient or accident analysis.
Eight channels of LPCS and LPCI Pump Discharge Pressure - High Function (two LPCS and two LPCI A channels input to ADS trip system A, while two LPCI B and two LPCI C channels input to ADS trip system B) are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Refer to LCO 3.5.1 for ADS Applicability Bases.
4.g, 5.f. ADS Bypass Timer (High Drywell Pressure)
One of the signals required for ADS initiation is Drywell Pressure - High.
However, if the event requiring ADS initiation occurs outside the drywell (for example, main steam line break outside primary containment), a high drywell pressure signal may never be present. Therefore, the ADS Bypass Timer is used to bypass the Drywell Pressure - High Function after a certain time period has elapsed. Operation of the ADS Bypass Timer Function is not assumed in any accident or transient analysis. The instrumentation is retained in the TS because ADS is part of the primary success path for mitigation of a DBA.
There are four ADS Bypass Timer relays, two in each of the two ADS trip systems. The Allowable Value for the ADS Timer is chosen to be short enough that so that there is still time after depressurization for the low pressure ECCS subsystems to provide adequate core cooling.
Four channels of the ADS Bypass Timer Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. Refer to LCO 3.5.1 for ADS Applicability Bases.
4.h, 5.g. Manual Initiation The Manual Initiation push button channels introduce signals into the ADS logic to provide manual initiation capability and are redundant to the automatic protective instrumentation. There are two push buttons for each ADS trip system (total of four).
General Electric BWR/6 STS            B 3.3.5.1-22                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Manual Initiation Function is not assumed in any accident or transient analyses in the FSAR. However, the Function is retained for overall redundancy and diversity of the ADS function as required by the NRC in the plant licensing basis.
There is no Allowable Value for this Function since the channel is mechanically actuated based solely on the position of the push buttons.
Four channels of the Manual Initiation Function (two channels per ADS trip system) are only required to be OPERABLE when the ADS is required to be OPERABLE. Refer to LCO 3.5.1 for ADS Applicability Bases.
ACTIONS            -----------------------------------REVIEWERS NOTE-----------------------------------
Certain LCO Completion Times are based on approved topical reports. In order for a licensee to use the times, the licensee must justify the Completion Times as required by the staff Safety Evaluation Report (SER) for the topical report.
A Note has been provided to modify the ACTIONS related to ECCS instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable ECCS instrumentation channels provide appropriate compensatory measures for separate inoperable Condition entry for each inoperable ECCS instrumentation channel. When the Required Channels in Table 3.3.3.1-1 are specified (e.g., on a per steam line, per loop, etc., basis) then the Condition may be entered separately for each steam line, loop, etc., as appropriate.
A.1 Required Action A.1 directs entry into the appropriate Condition referenced in Table 3.3.5.1-1. The applicable Condition specified in the Table is Function dependent. Each time a channel is discovered to be inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition.
General Electric BWR/6 STS              B 3.3.5.1-23                                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued)
B.1, B.2, and B.3 Required Actions B.1 and B.2 are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function (or in some cases, within the same variable) result in redundant automatic initiation capability being lost for the feature(s).
Required Action B.1 features would be those that are initiated by Functions 1.a, 1.b, 2.a, and 2.b (e.g., low pressure ECCS). The Required Action B.2 feature would be HPCS. For Required Action B.1, redundant automatic initiation capability is lost if either (a) one or more Function 1.a channels and one or more Function 2.a channels are inoperable and untripped, or (b) one or more Function 1.b channels and one or more Function 2.b channels are inoperable and untripped.
For Divisions 1 and 2, since each inoperable channel would have Required Action B.1 applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associated Division of low pressure ECCS and DG to be declared inoperable. However, since channels in both Divisions are inoperable and untripped, and the Completion Times started concurrently for the channels in both Divisions, this results in the affected portions in both Divisions of ECCS and DG being concurrently declared inoperable.
For Required Action B.2, redundant automatic initiation capability is lost if two Function 3.a or two Function 3.b channels are inoperable and untripped in the same trip system. In this situation (loss of redundant automatic initiation capability), the 24 hour allowance of Required Action B.3 is not appropriate and the feature(s) associated with the inoperable, untripped channels must be declared inoperable within 1 hour. Notes are also provided (the Note to Required Action B.1 and Required Action B.2) to delineate which Required Action is applicable for each Function that requires entry into Condition B if an associated channel is inoperable. This ensures that the proper loss of initiation capability check is performed.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action B.1, the Completion Time only begins upon discovery that a redundant feature in both General Electric BWR/6 STS            B 3.3.5.1-24                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued)
Divisions (e.g., any Division 1 ECCS and Division 2 ECCS) cannot be automatically initiated due to inoperable, untripped channels within the same variable as described in the paragraph above. For Required Action B.2, the Completion Time only begins upon discovery that the HPCS System cannot be automatically initiated due to two inoperable, untripped channels for the associated Function in the same trip system.
The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE status.
[Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action B.3. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.
Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition H must be entered and its Required Action taken.
C.1 and C.2 Required Action C.1 is intended to ensure that appropriate actions are taken if multiple, inoperable channels within the same Function (or in some cases, within the same variable) result in redundant automatic initiation capability being lost for the feature(s). Required Action C.1 features would be those that are initiated by Functions 1.c, 1.d, 2.c, and 2.d (i.e., low pressure ECCS). For Functions 1.c and 2.c, redundant automatic initiation capability is lost if the Function 1.c and Function 2.c channels are inoperable. For Functions 1.d and 2.d, redundant automatic initiation capability is lost if two Function 1.d channels in the same trip system and two Function 2.d channels in the same trip system (but not necessarily the same trip system as the Function 1.d channels) are inoperable. Since each inoperable channel would have Required Action C.1 applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associated Division to be declared inoperable. However, since channels in both Divisions are inoperable, and the Completion Times started concurrently for the channels in both Divisions, this results in the affected portions in both Divisions being concurrently declared inoperable. For Functions 1.c General Electric BWR/6 STS              B 3.3.5.1-25                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued) and 2.c, the affected portions of the Division are LPCI A and LPCI B, respectively. For Functions 1.d and 2.d, the affected portions of the Division are the low pressure ECCS pumps (Divisions 1 and 2, respectively).
In this situation (loss of redundant automatic initiation capability), the 24 hour allowance of Required Action C.2 is not appropriate and the feature(s) associated with the inoperable channels must be declared inoperable within 1 hour.
The Note states that Required Action C.1 is only applicable for Functions 1.c, 1.d, 2.c, and 2.d. The Required Action is not applicable to Functions 1.g, 2.f, and 3.h (which also require entry into this Condition if a channel in these Functions is inoperable), since they are the Manual Initiation Functions and are not assumed in any accident or transient analysis. Thus, a total loss of manual initiation capability for 24 hours (as allowed by Required Action C.2) is allowed. Required Action C.1 is also not applicable to Function 3.c (which also requires entry into this Condition if a channel in this Function is inoperable), since the loss of one channel results in a loss of the Function (two-out-of-two logic). This loss was considered during the development of Reference 5 and considered acceptable for the 24 hours allowed by Required Action C.2.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action C.1, the Completion Time only begins upon discovery that the same feature in both Divisions (e.g., any Division 1 ECCS and Division 2 ECCS) cannot be automatically initiated due to inoperable channels within the same variable as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels.
Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE status.
[Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If the inoperable channel General Electric BWR/6 STS            B 3.3.5.1-26                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued) cannot be restored to OPERABLE status within the allowable out of service time, Condition H must be entered and its Required Action taken.
The Required Actions do not allow placing the channel in trip since this action would either cause the initiation or would not necessarily result in a safe state for the channel in all events.
D.1, D.2.1, and D.2.2 Required Action D.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in a complete loss of automatic component initiation capability for the HPCS System. Automatic component initiation capability is lost if two Function 3.d channels or two Function 3.e channels are inoperable and untripped. In this situation (loss of automatic suction swap), the 24 hour allowance of Required Actions D.2.1 and D.2.2 is not appropriate and the HPCS System must be declared inoperable within 1 hour after discovery of loss of HPCS initiation capability. As noted, the Required Action is only applicable if the HPCS pump suction is not aligned to the suppression pool, since, if aligned, the Function is already performed.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action D.1, the Completion Time only begins upon discovery that the HPCS System cannot be automatically aligned to the suppression pool due to two inoperable, untripped channels in the same Function. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE status.
[Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action D.2.1 or the suction source must be aligned to the suppression pool within 24 hours per Required Action D.2.2. Placing the inoperable channel in trip performs the intended function of the channel (shifting the suction source to the suppression pool). Performance of either of these two Required Actions will allow operation to continue. If Required Action D.2.1 or Required Action D.2.2 is performed, measures should be taken to ensure that the HPCS System piping remains filled General Electric BWR/6 STS            B 3.3.5.1-27                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued) with water. Alternately, if it is not desired to perform Required Actions D.2.1 and D.2.2 (e.g., as in the case where shifting the suction source could drain down the HPCS suction piping), Condition H must be entered and its Required Action taken.
E.1 and E.2 Required Action E.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the LPCS and LPCI Pump Discharge Flow - Low (Bypass) Functions result in redundant automatic initiation capability being lost for the feature(s). For Required Action E.1, the features would be those that are initiated by Functions 1.e, 1.f, and 2.e (e.g., low pressure ECCS). Redundant automatic initiation capability is lost if three of the four channels associated with Functions 1.e, 1.f, and 2.e are inoperable. Since each inoperable channel would have Required Action E.1 applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected low pressure ECCS pump to be declared inoperable. However, since channels for more than one low pressure ECCS pump are inoperable, and the Completion Times started concurrently for the channels of the low pressure ECCS pumps, this results in the affected low pressure ECCS pumps being concurrently declared inoperable.
In this situation (loss of redundant automatic initiation capability), the 7 day allowance of Required Action E.2 is not appropriate and the feature(s) associated with each inoperable channel must be declared inoperable within 1 hour after discovery of loss of initiation capability for feature(s) in both Divisions. A Note is also provided (the Note to Required Action E.1) to delineate that Required Action E.1 is only applicable to low pressure ECCS Functions. Required Action E.1 is not applicable to HPCS Functions 3.f and 3.g since the loss of one channel results in a loss of the Function (one-out-of-one logic). This loss was considered during the development of Reference 5 and considered acceptable for the 7 days allowed by Required Action E.2.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action E.1, the Completion Time only begins upon discovery that three channels of the variable General Electric BWR/6 STS            B 3.3.5.1-28                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued)
(Pump Discharge Flow - Low) cannot be automatically initiated due to inoperable channels. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels.
If the instrumentation that controls the pump minimum flow valve is inoperable such that the valve will not automatically open, extended pump operation with no injection path available could lead to pump overheating and failure. If there were a failure of the instrumentation such that the valve would not automatically close, a portion of the pump flow could be diverted from the reactor injection path, causing insufficient core cooling.
These consequences can be averted by the operator's manual control of the valve, which would be adequate to maintain ECCS pump protection and required flow. Furthermore, other ECCS pumps would be sufficient to complete the assumed safety function if no additional single failure were to occur. The 7 day Completion Time of Required Action E.2 to restore the inoperable channel to OPERABLE status is reasonable based on the remaining capability of the associated ECCS subsystems, the redundancy available in the ECCS design, and the low probability of a DBA occurring during the allowed out of service time. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition H must be entered and its Required Action taken. The Required Actions do not allow placing the channel in trip since this action would not necessarily result in a safe state for the channel in all events. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.]
F.1 and F.2 Required Action F.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within similar ADS trip system Functions result in automatic initiation capability being lost for the ADS. Automatic initiation capability is lost if either (a) more than one Function 4.a channel and one Function 5.a channel are inoperable and untripped, (b) one Function 4.b channel and one Function 5.b channel are inoperable and untripped, or (c) one Function 4.d channel and one Function 5.d channel are inoperable and untripped.
In this situation (loss of automatic initiation capability), the 96 hour or 8 day allowance, as applicable, of Required Action F.2 is not appropriate, and all ADS valves must be declared inoperable within 1 hour after discovery of loss of ADS initiation capability in both trip systems.
General Electric BWR/6 STS            B 3.3.5.1-29                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued)
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action F.1, the Completion Time only begins upon discovery that the ADS cannot be automatically initiated due to inoperable, untripped channels within similar ADS trip system Functions as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 8 days has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE status if both HPCS and RCIC are OPERABLE. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If either HPCS or RCIC is inoperable, the time is shortened to 96 hours.
[Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If the status of HPCS or RCIC changes such that the Completion Time changes from 8 days to 96 hours, the 96 hours begins upon discovery of HPCS or RCIC inoperability. However, total time for an inoperable, untripped channel cannot exceed 8 days. If the status of HPCS or RCIC changes such that the Completion Time changes from 96 hours to 8 days, the "time zero" for beginning the 8 day "clock" begins upon discovery of the inoperable, untripped channel. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action F.2. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition H must be entered and its Required Action taken.
G.1 and G.2 Required Action G.1 is intended to ensure that appropriate actions are taken if multiple, inoperable channels within similar ADS trip system Functions result in automatic initiation capability being lost for the ADS.
Automatic initiation capability is lost if either (a) one Function 4.c channel and one Function 5.c channel are inoperable, (b) one or more Function 4.e channels and one or more Function 5.e channels are General Electric BWR/6 STS            B 3.3.5.1-30                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued) inoperable, (c) one or more Function 4.f channels and one or more Function 5.e channels are inoperable, or (d) one or more Function 4.g channels and one or more Function 5.f channels are inoperable.
In this situation (loss of automatic initiation capability), the 96 hour or 8 day allowance, as applicable, of Required Action G.2 is not appropriate, and all ADS valves must be declared inoperable within 1 hour after discovery of loss of ADS initiation capability in both trip systems. The Note to Required Action G.1 states that Required Action G.1 is only applicable for Functions 4.c, 4.e, 4.f, 4.g, 5.c, 5.e, and 5.f. Required Action G.1 is not applicable to Functions 4.h and 5.g (which also require entry into this Condition if a channel in these Functions is inoperable),
since they are the Manual Initiation Functions and are not assumed in any accident or transient analysis. Thus, a total loss of manual initiation capability for 96 hours or 8 days (as allowed by Required Action G.2) is allowed.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action G.1, the Completion Time only begins upon discovery that the ADS cannot be automatically initiated due to inoperable channels within similar ADS trip system Functions, as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 8 days has been shown to be acceptable (Ref. 5) to permit restoration of any inoperable channel to OPERABLE status if both HPCS and RCIC are OPERABLE (Required Action G.2). [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If either HPCS or RCIC is inoperable, the time is reduced to 96 hours. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If the status of HCPS or RCIC changes such that the Completion Time changes from 8 days to 96 hours, the 96 hours begins upon discovery of HPCS or RCIC inoperability. However, total time for an inoperable channel cannot exceed 8 days. If the status of HPCS or RCIC changes such that the Completion Time changes from 96 hours to 8 days, the "time zero" for beginning the 8 day "clock" begins upon discovery of the inoperable channel. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition H must be General Electric BWR/6 STS            B 3.3.5.1-31                                        Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued) entered and its Required Action taken. The Required Actions do not allow placing the channel in trip since this action would not necessarily result in a safe state for the channel in all events.
H.1 With any Required Action and associated Completion Time not met, the associated feature(s) may be incapable of performing the intended function and the supported feature(s) associated with the inoperable untripped channels must be declared inoperable immediately.
SURVEILLANCE        -----------------------------------REVIEWERS NOTE-----------------------------------
REQUIREMENTS        Certain Frequencies are based on approved topical reports. In order for a licensee to use these Frequencies, the licensee must justify the Frequencies as required by the staff SER for the topical report.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Notes b and c are applied to the setpoint verification Surveillances for each ECCS Instrumentation Functions in Table 3.3.5.1-1 unless one or more of the following exclusions apply:
: 1. Manual actuation circuits, automatic actuation logic circuits or instrument functions that derive input from contacts which have no associated sensor or adjustable device, e.g., limit switches, breaker position switches, manual actuation switches, float switches, proximity detectors, etc. are excluded. In addition, those permissives and interlocks that derive input from a sensor or adjustable device that is tested as part of another TS function are excluded.
: 2. Settings associated with safety relief valves are excluded. The performance of these components is already controlled (i.e., trended with as-left and as-found limits) under the ASME Code for Operation and Maintenance of Nuclear Power Plants testing program.
: 3. Functions and Surveillance Requirements which test only digital components are normally excluded. There is no expected change in result between SR performances for these components. Where separate as-left and as-found tolerance is established for digital component SRs, the requirements would apply.
A generic evaluation of ECCS Instrumentation Functions resulted in Notes e and f being applied to the Functions shown in TS 3.3.5.1. Each licensee adopting this change must review the list of potential Functions to identify whether any of the identified functions meet any of the General Electric BWR/6 STS              B 3.3.5.1-32                                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued) exclusion criteria based on the plant specific design and safety analysis (AOOs). The footnotes applied to Function 3.3.5.1-1.[3.c], Reactor Vessel Water Level - High, Level 8 are optional.
Functions 3.3.5.1-1.[3.f], High Pressure Coolant System Pump Discharge Pressure - High (Bypass) and 3.3.5.1-1 [3.g] High Pressure Coolant System Flow Rate - Low (Bypass) can be removed from Technical Specifications if the corresponding valve is locked open.
As noted at the beginning of the SRs, the SRs for each ECCS instrument Function are found in the SRs column of Table 3.3.5.1-1.
The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours as follows: (a) for Functions 3.c, 3.f, 3.g, and 3.h; and (b) for Functions other than 3.c, 3.f, 3.g, and 3.h provided the associated Function or redundant Function maintains ECCS initiation capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 5) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the ECCS will initiate when necessary.
SR 3.3.5.1.1 Performance of the CHANNEL CHECK 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 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 instrument has drifted outside its limit.
General Electric BWR/6 STS              B 3.3.5.1-33                                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
[ The Frequency of 12 hours is based upon operating experience that demonstrates channel failure is rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
SR 3.3.5.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the 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 methodology.
[ The Frequency of 92 days is based on the reliability analyses of Reference 5.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.3.5.1-34                                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.5.1.3 The calibration of trip units provides a check of the actual trip setpoints.
The channel must be declared inoperable if the trip setting is discovered to be not within its required Allowable Value specified in Table 3.3.5.1-1.
If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analyses. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than the setting accounted for in the appropriate setpoint methodology.
[ The Frequency of 92 days is based on the reliability analysis of Reference 5.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.5.1.3 for designated functions is modified by two Notes as identified in Table 3.3.5.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the General Electric BWR/6 STS                B 3.3.5.1-35                                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued) channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the [LTSP] is used in the plant surveillance procedures [Nominal Trip Setpoint (NTSP)], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP], then the channel shall be declared inoperable.
The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
SR 3.3.5.1.4 and SR 3.3.5.1.5 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
For SR 3.3.5.1.4 there is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology.
SR 3.3.5.1.5 for designated functions is modified by two Notes as identified in Table 3.3.5.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective General Electric BWR/6 STS            B 3.3.5.1-36                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
Action Program will ensure required review and documentation of the condition.
The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the [LTSP] is used in the plant surveillance procedures [NTSP], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP], then the channel shall be declared inoperable.
The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
[ The Frequency of SR 3.3.5.1.4 is based upon the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
The Frequency of SR 3.3.5.1.5 is based upon the assumption of an
[18] month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.5.1.6 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance to provide complete testing of the assumed safety function.
General Electric BWR/6 STS              B 3.3.5.1-37                                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
[ 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 unplanned transients 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.5.1.7 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis.
Response time testing acceptance criteria are included in Reference 6.
ECCS RESPONSE TIME may be verified by actual response time measurements in any series of sequential, overlapping, or total channel measurements.
[-----------------------------------REVIEWERS NOTE----------------------------------
The following Bases are applicable for plants adopting NEDO-32291-A.
However, the measurement of instrument loop response times may be excluded if the conditions of Reference 7 are satisfied.]
[ ECCS RESPONSE TIME tests are conducted on an [18] month STAGGERED TEST BASIS. 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.
OR General Electric BWR/6 STS                B 3.3.5.1-38                                                      Rev. 5.0
 
ECCS Instrumentation B 3.3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. Regulatory Guide 1.105, "Setpoints for Safety-Related Instrumentation," Revision 3.
: 2. FSAR, Section [5.2].
: 3. FSAR, Section [6.3].
: 4. FSAR, Chapter [15].
: 5. NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation, Part 2,"
December 1988.
: 6. FSAR, Section [6.3], Table [6.3-2].
[7. NEDO-32291-A, "System Analyses for the Elimination of Selected Response Time Testing Requirements," October 1995.]
General Electric BWR/6 STS              B 3.3.5.1-39                                                      Rev. 5.0
 
RPV Water Inventory Control Instrumentation B 3.3.5.2 B 3.3 INSTRUMENTATION B 3.3.5.2  Reactor Pressure Vessel (RPV) Water Inventory Control Instrumentation BASES BACKGROUND          The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF.
If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.
Technical Specifications are required by 10 CFR 50.36 to include limiting safety system settings (LSSS) for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the process variable at which a safety action is initiated to ensure that a SL is not exceeded. Any automatic protection action that occurs on reaching the Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur. The actual settings for the automatic isolation channels are the same as those established for the same functions in MODES 1, 2, and 3 in LCO 3.3.6.1, "Primary Containment Isolation instrumentation."
With the unit in MODE 4 or 5, RPV water inventory control is not required to mitigate any events or accidents evaluated in the safety analyses.
RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur. Under the definition of DRAIN TIME, some penetration flow paths may be excluded from the DRAIN TIME calculation if they will be isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation.
The purpose of the RPV Water Inventory Control Instrumentation is to support the requirements of LCO 3.5.2, "Reactor Pressure Vessel (RPV)
Water Inventory Control," and the definition of DRAIN TIME. There are functions that support automatic isolation of residual heat removal subsystem and Reactor Water Cleanup System penetration flow path(s) on low RPV water level.
General Electric BWR/6 STS              B 3.3.5.2-1                                        Rev. 5.0
 
RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES APPLICABLE          With the unit in MODE 4 or 5, RPV water inventory control is not required SAFETY              to mitigate any events or accidents evaluated in the safety analyses. RPV ANALYSES, LCO,      water inventory control is required in MODES 4 and 5 to protect and APPLICABILITY  Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur.
A double-ended guillotine break of the Reactor Coolant System (RCS) is not considered in MODES 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is considered in which an initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure. It is assumed, based on engineering judgment, that while in MODES 4 and 5, one ECCS injection/spray subsystem can be manually initiated to maintain adequate reactor vessel water level.
As discussed in References 1, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety.
Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).
Permissive and interlock setpoints are generally considered as nominal values without regard to measurement accuracy.
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
                    ------------------------------ REVIEWER'S NOTE --------------------------------------
Additional plant- or design- specific isolation instrumentation functions initiated by low RPV water level may be included in the required Functions and credited when calculating DRAIN TIME.
RHR System Isolation 1.a - Reactor Vessel Water Level - Low. Level 3 The definition of DRAIN TIME allows crediting the closing of penetration flow paths that are capable of being automatically isolated by RPV water level isolation instrumentation prior to the RPV water level being equal to the TAF. The Reactor Vessel Water Level - Low, Level 3 Function is only required to be OPERABLE when automatic isolation of the associated RHR penetration flow path is credited in calculating DRAIN TIME.
General Electric BWR/6 STS                B 3.3.5.2-2                                                      Rev. 5.0
 
RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Reactor Vessel Water Level - Low, Level 3 signals are initiated from four level transmitters (two per trip system) that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. While four channels (two channels per trip system) of the Reactor Vessel Water Level - Low, Level 3 Function are available, only two channels (all in the same trip system) are required to be OPERABLE.
The Reactor Vessel Water Level - Low, Level 3 Allowable Value was chosen to be the same as the RPS Reactor Vessel Water Level - Low, Level 3 Allowable Value (LCO 3.3.1.1), since the capability to cool the fuel may be threatened.
The Reactor Vessel Water Level - Low, Level 3 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME.
This Function isolates the Group 3 valves.
Reactor Water Cleanup (RWCU) System Isolation 2.a - Reactor Vessel Water level - Low Low, Level 2 The definition of DRAIN TIME allows crediting the closing of penetration flow paths that are capable of being automatically isolated by RPV water level isolation instrumentation prior to the RPV water level being equal to the TAF. The Reactor Vessel Water Level - Low Low, Level 2 Function associated with RWCU System isolation may be credited for automatic isolation of penetration flow paths associated with the RWCU System.
Reactor Vessel Water Level - Low Low, Level 2 is initiated from two channels per trip system that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. While four channels (two channels per trip system) of the Reactor Vessel Water Level - Low, Level 2 Function are available, only two channels (all in the same trip system) are required to be OPERABLE.
The Reactor Vessel Water Level - Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Reactor Vessel Water Level - Low Low, Level 2 Allowable Value (LCO 3.3.5.1), since the capability to cool the fuel may be threatened.
General Electric BWR/6 STS            B 3.3.5.2-3                                      Rev. 5.0
 
RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Reactor Vessel Water Level - Low Low, Level 2 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME.
This Function isolates the Group 8 valves.
ACTIONS            A Note has been provided to modify the ACTIONS related to RPV Water Inventory Control instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable RPV Water Inventory Control instrumentation channels provide appropriate compensatory measures for separate inoperable Condition entry for each inoperable RPV Water Inventory Control instrumentation channel.
A.1, A.2.1 and A.2.2 RHR System Isolation, Reactor Vessel Water Level - Low Level 3, and Reactor Water Cleanup System, Reactor Vessel Water Level - Low Low, Level 2 functions are applicable when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME. If the instrumentation is inoperable, Required Action A.1 directs immediate action to place the channel in trip. With the inoperable channel in the tripped condition, the remaining channel will isolate the penetration flow path on low water level. If both channels are inoperable and placed in trip, the penetration flow path will be isolated. Alternatively, Required Action A.2.1 requires that the associated penetration flow path(s) to be immediately declared incapable of automatic isolation. Required Action A.2.2 directs initiating action to calculate DRAIN TIME. The calculation cannot credit automatic isolation of the affected penetration flow paths.
SURVEILLANCE        The following SRs apply to each RPV Water Inventory Control Instrument REQUIREMENTS        Function in Table 3.3.5.2-1.
SR 3.3.5.2.1 Performance of the CHANNEL CHECK 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 General Electric BWR/6 STS            B 3.3.5.2-4                                        Rev. 5.0
 
RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued) 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 something even more serious. A CHANNEL CHECK guarantees that undetected outright channel failure is limited; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL FUNCTIONAL TEST.
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 instrument has drifted outside its limit.
[ The Frequency of 12 hours is based upon operating experience that demonstrates channel failure is rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
SR 3.3.5.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the 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.
General Electric BWR/6 STS                B 3.3.5.2-5                                                      Rev. 5.0
 
RPV Water Inventory Control Instrumentation B 3.3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)
Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.
[ The Frequency of 92 days is based upon operating experience that demonstrates channel failure is rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. Information Notice 84-81 "Inadvertent Reduction in Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup,"
November 1984.
: 2. Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.
: 3. Generic Letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(F), " August 1992.
: 4. NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," May 1993.
: 5. Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994.
General Electric BWR/6 STS                B 3.3.5.2-6                                                      Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 B 3.3 INSTRUMENTATION B 3.3.5.3 Reactor Core Isolation Cooling (RCIC) System Instrumentation BASES BACKGROUND          The purpose of the RCIC System instrumentation is to initiate actions to ensure adequate core cooling when the reactor vessel is isolated from its primary heat sink (the main condenser) and normal coolant makeup flow from the Reactor Feedwater System is unavailable, such that initiation of the low pressure Emergency Core Cooling Systems (ECCS) pumps does not occur. A more complete discussion of RCIC System operation is provided in the Bases of LCO 3.5.3, "RCIC System." This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the RCIC instrumentation, as well as LCOs on other reactor system parameters and equipment performance.
Technical Specifications are required by 10 CFR 50.36 to include LSSSs for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical 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 Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur.
                    ---------------------------------REVIEWER'S NOTE-----------------------------------
The term "Limiting Trip Setpoint" [LTSP] is generic terminology for the calculated trip setting (setpoint) value calculated by means of the plant specific setpoint methodology documented in a document controlled under 10 CFR 50.59. The term [LTSP] indicates that no additional margin has been added between the Analytical Limit and the calculated trip setting.
                    "Nominal Trip Setpoint [NTSP]" is the suggested terminology for the actual setpoint implemented in the plant surveillance procedures where margin has been added to the calculated [LTSP]. The as-found and as-left tolerances will apply to the [NTSP] implemented in the Surveillance procedures to confirm channel performance.
General Electric BWR/6 STS                B 3.3.5.3-1                                        Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES BACKGROUND (continued)
Licensees are to insert the name of the document(s) controlled under 10 CFR 50.59 that contain the methodology for calculating the as-left and as-found tolerances in Note b of Table 3.3.5.3-1, for the phrase "[insert the name of a document controlled under 10 CFR 50.59 such as the Technical Requirements Manual or any document incorporated into the facility FSAR]" throughout the Bases.
If the [LTSP] is not included in Table 3.3.5.3-1, the plant specific location for the [LTSP] or [NTSP] must be cited in Note b of Table 3.3.5.3-1. The brackets indicate plant specific terms may apply, as reviewed and approved by the NRC.
The [Limiting Trip Setpoint (LTSP)] specified in Table 3.3.5.3-1 is a predetermined setting for a protection channel chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the SL would not be exceeded. Therefore, the [LTSP] accounts for uncertainties in setting the channel (e.g.,
calibration), uncertainties in how the channel might actually perform (e.g.,
repeatability), changes in the point of action of the channel 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 [LTSP] ensures that SLs are not exceeded. As such, the
[LTSP] meets the definition of an LSSS (Ref. 1)
The Allowable Value specified in Table 3.3.5.3-1, 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 surveillance interval.
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)." Relying solely on the [LTSP] to define OPERABILITY in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as found" value of a protection channel 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 protection channel with a setting that General Electric BWR/6 STS                B 3.3.5.3-2                                                      Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES BACKGROUND (continued) has been found to be different from the [LTSP] due to some drift of the setting may still be OPERABLE because drift is to be expected. This expected drift would have been specifically accounted for in the setpoint methodology for calculating the [LTSP] and thus the automatic protective action would still have ensured that the SL would not be exceeded with the "as found" setting of the protection channel. Therefore, the channel would still be OPERABLE because it would have performed its safety function and the only corrective action required would be to reset the channel within the established as-left tolerance around [LTSP] to account for further drift during the next surveillance interval. Note that, although the channel is OPERABLE under these circumstances, the trip setpoint must be left adjusted to a value within the as-left tolerance, 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 (as-found criteria).
However, there is also some point beyond which the channel may not be able to perform its function due to, for example, greater than expected drift. This value needs to be specified in the Technical Specifications in order to define OPERABILITY of the channels and is designated as the Allowable Value.
If the actual setting (as-found setpoint) of the channel is found to be conservative with respect to the Allowable Value but is beyond the as-found tolerance band, the channel is OPERABLE, but degraded. The degraded condition will be further evaluated during performance of the SR. This evaluation will consist of resetting the channel setpoint to the
[Nominal Trip Setpoint (NTSP)] (within the allowed tolerance), and evaluating the channel response. If the channel is functioning as required and is expected to pass the next surveillance, then the channel is OPERABLE and can be restored to service at the completion of the surveillance. After the surveillance is completed, the channel as-found condition will be entered into the Corrective Action Program for further evaluation.
The RCIC System may be initiated by either automatic or manual means.
Automatic initiation occurs for conditions of reactor vessel Low Low water level. The variable is monitored by four transmitters that are connected to four trip units. The outputs of the trip units are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic arrangement.
Once initiated, the RCIC logic seals in and can be reset by the operator only when the reactor vessel water level signals have cleared.
General Electric BWR/6 STS            B 3.3.5.3-3                                        Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES BACKGROUND (continued)
The RCIC test line isolation valve (which is also a primary containment isolation valve) is closed on a RCIC initiation signal to allow full system flow and maintain containment isolated in the event RCIC is not operating.
The RCIC System also monitors the water levels in the condensate storage tank (CST) and the suppression pool, since these are the two sources of water for RCIC operation. Reactor grade water in the CST is the normal source. Upon receipt of a RCIC initiation signal, the CST suction valve is automatically signaled to open (it is normally in the open position) unless the pump suction from the suppression pool valve is open. If the water level in the CST falls below a preselected level, first the suppression pool suction valve automatically opens and then the CST suction valve automatically closes. Two level transmitters are used to detect low water level in the CST. Either switch can cause the suppression pool suction valve to open and the CST suction valve to close. The suppression pool suction valve also automatically opens and the CST suction valve closes if high water level is detected in the suppression pool (one-out-of-two logic similar to the CST water level logic). To prevent losing suction to the pump, the suction valves are interlocked so that one suction path must be open before the other automatically closes.
The RCIC System provides makeup water to the reactor until the reactor vessel water level reaches the high water level (Level 8) trip (two-out-of-two logic), at which time the RCIC steam supply, steam supply bypass, and cooling water supply valves close (the injection valve also closes due to the closure of the steam supply valves). The RCIC System restarts if vessel level again drops to the low level initiation point (Level 2).
APPLICABLE          The function of the RCIC System, to provide makeup coolant to the SAFETY              reactor, is to respond to transient events. The RCIC System is not an ANALYSES, LCO,      Engineered Safety Feature System and no credit is taken in the safety and APPLICABILITY  analysis for RCIC System operation. The RCIC System instrumentation satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii). Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.
Permissive and interlock setpoints allow the blocking of trips during plant startups, and restoration of trips when the permissive conditions are not satisfied, but they are not explicitly modeled in the Safety Analyses.
These permissives and interlocks ensure that the starting conditions are consistent with the safety analysis, before preventive or mitigating actions General Electric BWR/6 STS            B 3.3.5.3-4                                        Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) occur. Because these permissives or interlocks are only one of multiple conservative starting assumptions for the accident analysis, they are generally considered as nominal values without regard to measurement accuracy.
The OPERABILITY of the RCIC System instrumentation is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.5.3-1. Each Function must have a required number of OPERABLE channels with their setpoints set within the setting tolerance of the [LTSPs], where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
Each channel must also respond within its assumed response time.
Allowable Values are specified for each RCIC System instrumentation Function specified in Table 3.3.5.3-1. [LTSPs] and the methodologies for calculation of the as-left and as-found tolerances are described in [insert the name of a document controlled under 10 CFR 50.59 such as the Technical Requirements Manual or any document incorporated into the facility FSAR]. The [LTSPs] are selected to ensure that the setpoints remain conservative to the as-left tolerance band between CHANNEL CALIBRATIONS. After each calibration the trip setpoint shall be left within the as-left band around the [LTSP]. [LTSPs] are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytical limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytical limits, corrected for calibration, process, and some of the instrument errors. The [LTSPs] are then determined, accounting for the remaining instrument errors (e.g., drift).
The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
Note that, although the channel is OPERABLE under these circumstances, the trip setpoint must be left adjusted to a value within the as-left tolerance, 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 (as-found criteria).
General Electric BWR/6 STS            B 3.3.5.3-5                                      Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The individual Functions are required to be OPERABLE in MODE 1, and in MODES 2 and 3 with reactor steam dome pressure > 150 psig, since this is when RCIC is required to be OPERABLE. (Refer to LCO 3.5.3 for Applicability Bases for the RCIC System.)
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
: 1. Reactor Vessel Water Level - Low Low, Level 2 Low reactor pressure vessel (RPV) water level indicates that normal feedwater flow is insufficient to maintain reactor vessel water level and that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, the RCIC System is initiated at Level 2 to assist in maintaining water level above the top of the active fuel.
Reactor Vessel Water Level - Low Low, Level 2 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.
The Reactor Vessel Water Level - Low Low, Level 2 Allowable Value is set high enough such that for complete loss of feedwater flow, the RCIC System flow with high pressure core spray assumed to fail will be sufficient to avoid initiation of low pressure ECCS at Level 1.
Four channels of Reactor Vessel Water Level - Low Low, Level 2 Function are available and are required to be OPERABLE when RCIC is required to be OPERABLE to ensure that no single instrument failure can preclude RCIC initiation. Refer to LCO 3.5.3 for RCIC Applicability Bases.
: 2. Reactor Vessel Water Level - High, Level 8 High RPV water level indicates that sufficient cooling water inventory exists in the reactor vessel such that there is no danger to the fuel.
Therefore, the Level 8 signal is used to close the RCIC steam supply, steam supply bypass, and cooling water supply valves to prevent overflow into the main steam lines (MSLs). (The injection valve also closes due to the closure of the steam supply valve.)
General Electric BWR/6 STS            B 3.3.5.3-6                                        Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Reactor Vessel Water Level - High, Level 8 signals for RCIC are initiated from two level transmitters from the narrow range water level measurement instrumentation, which sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel.
The Reactor Vessel Water Level - High, Level 8 Allowable Value is high enough to preclude isolating the injection valve of the RCIC during normal operation, yet low enough to trip the RCIC System prior to water overflowing into the MSLs.
Two channels of Reactor Vessel Water Level - High, Level 8 Function are available and are required to be OPERABLE when RCIC is required to be OPERABLE to ensure that no single instrument failure can preclude RCIC initiation. Refer to LCO 3.5.3 for RCIC Applicability Bases.
: 3. Condensate Storage Tank Level - Low Low level in the CST indicates the unavailability of an adequate supply of makeup water from this normal source. Normally the suction valve between the RCIC pump and the CST is open and, upon receiving a RCIC initiation signal, water for RCIC injection would be taken from the CST. However, if the water level in the CST falls below a preselected level, first the suppression pool suction valve automatically opens and then the CST suction valve automatically closes. This ensures that an adequate supply of makeup water is available to the RCIC pump. To prevent losing suction to the pump, the suction valves are interlocked so that the suppression pool suction valve must be open before the CST suction valve automatically closes.
Two level transmitters are used to detect low water level in the CST. The Condensate Storage Tank Level - Low Function Allowable Value is set high enough to ensure adequate pump suction head while water is being taken from the CST.
Two channels of Condensate Storage Tank Level - Low Function are available and are required to be OPERABLE when RCIC is required to be OPERABLE to ensure that no single instrument failure can preclude RCIC swap to suppression pool source. Refer to LCO 3.5.3 for RCIC Applicability Bases.
General Electric BWR/6 STS            B 3.3.5.3-7                                      Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
: 4. Suppression Pool Water Level - High Excessively high suppression pool water level could result in the loads on the suppression pool exceeding design values should there be a blowdown of the reactor vessel pressure through the safety/relief valves.
Therefore, signals indicating high suppression pool water level are used to transfer the suction source of RCIC from the CST to the suppression pool to eliminate the possibility of RCIC continuing to provide additional water from a source outside primary containment. This Function satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). To prevent losing suction to the pump, the suction valves are interlocked so that the suppression pool suction valve must be open before the CST suction valve automatically closes.
Suppression pool water level signals are initiated from two level transmitters. The Allowable Value for the Suppression Pool Water Level -
High Function is set low enough to ensure that RCIC will be aligned to take suction from the suppression pool before the water level reaches the point at which suppression design loads would be exceeded.
Two channels of Suppression Pool Water Level - High Function are available and are required to be OPERABLE when RCIC is required to be OPERABLE to ensure that no single instrument failure can preclude RCIC swap to suppression pool source. Refer to LCO 3.5.3 for RCIC Applicability Bases.
: 5. Manual Initiation The Manual Initiation push button switch introduces a signal into the RCIC System initiation logic that is redundant to the automatic protective instrumentation and provides manual initiation capability. There is one push button for the RCIC System.
The Manual Initiation Function is not assumed in any accident or transient analyses in the FSAR. However, the Function is retained for overall redundancy and diversity of the RCIC function as required by the NRC in the plant licensing basis.
There is no Allowable Value for this Function since the channel is mechanically actuated based solely on the position of the push button.
One channel of Manual Initiation is required to be OPERABLE when RCIC is required to be OPERABLE.
General Electric BWR/6 STS            B 3.3.5.3-8                                      Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES ACTIONS            -----------------------------------REVIEWERS NOTE-----------------------------------
Certain LCO Completion Times are based on approved topical reports. In order for a licensee to use the times, the licensee must justify the Completion Times as required by the NRC staff Safety Evaluation Report (SER) for the topical report.
A Note has been provided to modify the ACTIONS related to RCIC System instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable RCIC System instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable RCIC System instrumentation channel.
A.1 Required Action A.1 directs entry into the appropriate Condition referenced in Table 3.3.5.3-1 in the accompanying LCO. The applicable Condition referenced in the Table is Function dependent. Each time a channel is discovered to be inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition.
B.1 and B.2 Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in a complete loss of automatic initiation capability for the RCIC System. In this case, automatic initiation capability is lost if two Function 1 channels in the same trip system are inoperable and untripped. In this situation (loss of automatic initiation capability), the 24 hour allowance of Required Action B.2 is not appropriate, and the RCIC System must be declared inoperable within 1 hour after discovery of loss of RCIC initiation capability.
General Electric BWR/6 STS                B 3.3.5.3-9                                                      Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES ACTIONS (continued)
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action B.1, the Completion Time only begins upon discovery that the RCIC System cannot be automatically initiated due to two inoperable, untripped Reactor Vessel Water Level - Low Low, Level 2 channels in the same trip system. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
Because of the redundancy of sensors available to provide initiation signals and the fact that the RCIC System is not assumed in any accident or transient analysis, an allowable out of service time of 24 hours has been shown to be acceptable (Ref. 2) to permit restoration of any inoperable channel to OPERABLE status. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action B.2. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition E must be entered and its Required Action taken.
C.1 A risk based analysis was performed and determined that an allowable out of service time of 24 hours (Ref. 2) is acceptable to permit restoration of any inoperable channel to OPERABLE status (Required Action C.1). A Required Action (similar to Required Action B.1), limiting the allowable out of service time if a loss of automatic RCIC initiation capability exists, is not required. This Condition applies to the Reactor Vessel Water Level -
High, Level 8 Function, whose logic is arranged such that any inoperable channel will result in a loss of automatic RCIC initiation capability. As stated above, this loss of automatic RCIC initiation capability was analyzed and determined to be acceptable. This Condition also applies to the Manual Initiation Function. Since this Function is not assumed in any accident or transient analysis, a total loss of manual initiation capability (Required Action C.1) for 24 hours is allowed. The Required Action does not allow placing a channel in trip since this action would not necessarily result in the safe state for the channel in all events.
General Electric BWR/6 STS            B 3.3.5.3-10                                        Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES ACTIONS (continued)
D.1, D.2.1, and D.2.2 Required Action D.1 is intended to ensure that appropriate actions are taken if multiple inoperable, untripped channels within the same Function result in automatic component initiation capability being lost for the feature(s). For Required Action D.1, the RCIC System is the only associated feature. In this case, automatic component initiation capability is lost if two Function 3 channels or two Function 4 channels are inoperable and untripped. In this situation (loss of automatic suction swap), the 24 hour allowance of Required Actions D.2.1 and D.2.2 is not appropriate, and the RCIC System must be declared inoperable within 1 hour from discovery of loss of RCIC initiation capability. As noted, Required Action D.1 is only applicable if the RCIC pump suction is not aligned to the suppression pool since, if aligned, the Function is already performed.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action D.1, the Completion Time only begins upon discovery that the RCIC System cannot be automatically aligned to the suppression pool due to two inoperable, untripped channels in the same Function. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
Because of the redundancy of sensors available to provide initiation signals and the fact that the RCIC System is not assumed in any accident or transient analysis, an allowable out of service time of 24 hours has been shown to be acceptable (Ref. 2) to permit restoration of any inoperable channel to OPERABLE status. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action D.2.1, which performs the intended function of the channel (shifting the suction source to the suppression pool). Alternatively, Required Action D.2.2 allows the manual alignment of the RCIC suction to the suppression pool within 24 hours, which also performs the intended function. If Required Action D.2.1 or D.2.2 is performed, measures should be taken to ensure that the RCIC System piping remains filled with water. If it is not desired to perform Required Actions D.2.1 and D.2.2 (e.g., as in the case where shifting the suction source could drain down the RCIC suction piping),
Condition E must be entered and its Required Action taken.
General Electric BWR/6 STS            B 3.3.5.3-11                                      Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES ACTIONS (continued)
E.1 With any Required Action and associated Completion Time not met, the RCIC System may be incapable of performing the intended function, and the RCIC System must be declared inoperable immediately.
SURVEILLANCE        -----------------------------------REVIEWERS NOTE-----------------------------------
REQUIREMENTS        Certain Frequencies are based on approved topical reports. In order for a licensee to use these Frequencies, the licensee must justify the Frequencies as required by the staff SER for the topical report.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Notes a and b are applied to the setpoint verification Surveillances for all RCIC System Instrumentation Functions in Table 3.3.5.3-1 unless one or more of the following exclusions apply:
: 1. Manual actuation circuits, automatic actuation logic circuits or instrument functions that derive input from contacts which have no associated sensor or adjustable device, e.g., limit switches, breaker position switches, manual actuation switches, float switches, proximity detectors, etc. are excluded. In addition, those permissives and interlocks that derive input from a sensor or adjustable device that is tested as part of another TS function are excluded.
: 2. Settings associated with safety relief valves are excluded. The performance of these components is already controlled (i.e., trended with as-left and as-found limits) under the ASME Code for Operation and Maintenance of Nuclear Power Plants testing program.
: 3. Functions and Surveillance Requirements which test only digital components are normally excluded. There is no expected change in result between SR performances for these components. Where separate as-left and as-found tolerance is established for digital component SRs, the requirements would apply.
A generic evaluation of RCIC System Instrumentation Functions resulted in Notes a and b being applied to the Functions shown in TS 3.3.5.3.
Each licensee adopting this change must review the list of potential Functions to identify whether any of the identified functions meet any of the exclusion criteria based on the plant specific design and safety analysis (AOOs). The footnotes applied to Function 3.3.5.3-1.[2], Reactor Vessel Water Level - High, Level 8 are optional.
General Electric BWR/6 STS              B 3.3.5.3-12                                                      Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES SURVEILLANCE REQUIREMENTS (continued)
As noted in the beginning of the SRs, the SRs for each RCIC System instrument Function are found in the SRs column of Table 3.3.5.3-1.
The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed as follows: (a) for up to 6 hours for Functions 2 and 5; and (b) for up to 6 hours for Functions 1, 3, and 4 provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 2) assumption of the average time required to perform channel Surveillance.
That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the RCIC will initiate when necessary.
SR 3.3.5.3.1 Performance of the CHANNEL CHECK 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 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 instrument has drifted outside its limit.
[ The Frequency of 12 hours is based upon operating experience that demonstrates channel failure is rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS            B 3.3.5.3-13                                        Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with the channels required by the LCO.
SR 3.3.5.3.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the 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 methodology.
[ The Frequency of 92 days is based on the reliability analysis of Reference 2.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.3.5.3-14                                                      Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.5.3.3 The calibration of trip units provides a check of the actual trip setpoints.
The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.5.3-1. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be re-adjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.
[ The Frequency of 92 days is based on the reliability analysis of Reference 2.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.5.3.3 is modified by two Notes as identified in Table 3.3.5.3-1.
The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value.
Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition.
The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the [LTSP] is used in the plant surveillance procedures [NTSP], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to General Electric BWR/6 STS                B 3.3.5.3-15                                                      Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES SURVEILLANCE REQUIREMENTS (continued) the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP], then the channel shall be declared inoperable. The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
SR 3.3.5.3.4 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter with the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
[ The Frequency is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.5.3.4 is modified by two Notes as identified in Table 3.3.5.3-1.
The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value.
Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The General Electric BWR/6 STS                B 3.3.5.3-16                                                      Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES SURVEILLANCE REQUIREMENTS (continued) purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition.
The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the [LTSP] is used in the plant surveillance procedures [NTSP], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP], then the channel shall be declared inoperable. The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
SR 3.3.5.3.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.5.3 overlaps this Surveillance to provide complete testing of the safety function.
[ The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.3.5.3-17                                                      Rev. 5.0
 
RCIC System Instrumentation B 3.3.5.3 BASES REFERENCES          1. Regulatory Guide 1.105, "Setpoints for Safety-Related Instrumentation," Revision 3.
: 2. NEDE-770-06-2, "Addendum to Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
General Electric BWR/6 STS          B 3.3.5.3-18                                    Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 B 3.3 INSTRUMENTATION B 3.3.6.1 Primary Containment Isolation Instrumentation BASES BACKGROUND          The primary containment isolation instrumentation automatically initiates closure of appropriate primary containment isolation valves (PCIVs). The function of the PCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs). Primary containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a DBA.
The isolation instrumentation includes the sensors, relays, and switches that are necessary to cause initiation of primary containment and reactor coolant pressure boundary (RCPB) isolation. Most channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a primary containment isolation signal to the isolation logic. Functional diversity is provided by monitoring a wide range of independent parameters. The input parameters to the isolation logic are (a) reactor vessel water level, (b) ambient and differential temperatures, (c) main steam line (MSL) flow measurement, (d) Standby Liquid Control (SLC) System initiation, (e) condenser vacuum loss, (f) main steam line pressure, (g) reactor core isolation cooling (RCIC) and RCIC/residual heat removal (RHR) steam line flow, (h) ventilation exhaust radiation, (i) RCIC steam line pressure, (j) RCIC turbine exhaust diaphragm pressure, (k) reactor water cleanup (RWCU) differential flow, (l) reactor steam dome pressure, and (m) drywell pressure. Redundant sensor input signals are provided from each such isolation initiation parameter. The only exception is SLC System initiation. In addition, manual isolation of the logics is provided.
The primary containment isolation instrumentation has inputs to the trip logic from the isolation Functions listed below.
: 1. Main Steam Line Isolation Most Main Steam Line Isolation Functions receive inputs from four channels. The outputs from these channels are combined in one-out-of-two taken twice logic to initiate isolation of all main steam isolation valves (MSIVs). The outputs from the same channels are arranged into two two-out-of-two logic trip systems to isolate all MSL drain valves. Each MSL drain line has two isolation valves with one two-out-of-two logic system associated with each valve.
General Electric BWR/6 STS            B 3.3.6.1-1                                          Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES BACKGROUND (continued)
The exception to this arrangement is the Main Steam Line Flow - High Function. This Function uses 16 flow channels, four for each steam line.
One channel from each steam line inputs to one of four trip strings. Two trip strings make up each trip system, and both trip systems must trip to cause an MSL isolation. Each trip string has four inputs (one per MSL),
any one of which will trip the trip string. The trip strings within a trip system are arranged in a one-out-of-two taken twice logic. Therefore, this is effectively a one-out-of-eight taken twice logic arrangement to initiate isolation of the MSIVs. Similarly, the 16 flow channels are connected into two two-out-of-two logic trip systems (effectively, two one-out-of-four twice logic), with each trip system isolating one of the two MSL drain valves.
: 2. Primary Containment Isolation Each Primary Containment Isolation Function receives inputs from four channels. The outputs from these channels are arranged into two two-out-of-two logic trip systems. One trip system initiates isolation of all inboard PCIVs, while the other trip system initiates isolation of all outboard PCIVs. Each trip system logic closes one of the two valves on each penetration so that operation of either trip system isolates the penetration.
: 3. Reactor Core Isolation Cooling System Isolation Most Functions receive input from two channels, with each channel in one trip system using one-out-of-one logic. Functions 3.j and 3.k (RHR Equipment Room Temperature) have one channel in each trip system in each room for a total of four channels per Function; but the logic is the same (one-out-of-one). Each of the two trip systems is connected to one of the two valves on each RCIC penetration so that operation of either trip system isolates the penetration. The exception to this arrangement is the RCIC Turbine Exhaust Diaphragm Pressure - High Function. This Function receives input from four turbine exhaust diaphragm pressure channels. The outputs from the turbine exhaust diaphragm pressure channels are connected into two two-out-of-two trip systems, each trip system isolating one of the two RCIC valves.
: 4. Reactor Water Cleanup System Isolation Most Functions receive input from two channels with each channel in one trip system using one-out-of-one logic. Functions 4.e and 4.f (RWCU Pump Room Temperature) have one channel in each trip system in each room for a total of four channels per Function, but the logic is the same (one-out-of-one). Each of the two trip systems is connected to one of the two valves on each RWCU penetration so that operation of either trip General Electric BWR/6 STS            B 3.3.6.1-2                                          Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES BACKGROUND (continued) system isolates the penetration. The exception to this arrangement is the Reactor Vessel Water Level - Low Low, Level 2 Function. This Function receives input from four reactor vessel water level channels. The outputs from the reactor vessel water level channels are connected into two two-out-of-two trip systems, each trip system isolating one of the two RWCU valves.
: 5. Shutdown Cooling System Isolation The Shutdown Cooling Isolation Function receives input signals from instrumentation for the Reactor Vessel Water Level - Low, Level 3; Drywell Pressure - High; Reactor Steam Dome Pressure - High; and RHR Equipment Room Ambient and Differential Temperature - High Functions.
The Reactor Vessel Water Level - Low, Reactor Steam Dome Pressure -
High, and Drywell Pressure - High Functions each have four channels.
The outputs from the reactor vessel water level and drywell pressure channels are connected into two two-out-of-two trip systems. The reactor steam dome pressure is arranged into two one-out-of-two trip systems.
The RHR Equipment Room Ambient and Differential Temperature Functions receive input from four channels with each channel in one trip system in one room using one-out-of-one logic. Each of the two trip systems is connected to one of the two valves on each shutdown cooling penetration so that operation of either trip system isolates the penetration.
APPLICABLE          The isolation signals generated by the primary containment isolation SAFETY              instrumentation are implicitly assumed in the safety analyses of ANALYSES, LCO,      References 1 and 2 to initiate closure of valves to limit offsite doses and APPLICABILITY  Refer to LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs),"
Applicable Safety Analyses Bases, for more detail.
Primary containment isolation instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.
The OPERABILITY of the primary containment instrumentation is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.6.1-1. Each Function must have a required number of OPERABLE channels, with their setpoints within the specified Allowable Values, where appropriate. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Each channel must also respond within its assumed response time, where appropriate.
General Electric BWR/6 STS            B 3.3.6.1-3                                        Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Allowable Values are specified for each Primary Containment Isolation Function specified in the Table. Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.
Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
Certain Emergency Core Cooling Systems (ECCS) and RCIC valves (e.g., minimum flow) also serve the dual function of automatic PCIVs.
The signals that isolate these valves are also associated with the automatic initiation of the ECCS and RCIC. The instrumentation and ACTIONS associated with these signals are addressed in LCO 3.3.5.1, "ECCS Instrumentation," and LCO 3.3.5.2, "RCIC Instrumentation," and are not included in this LCO.
In general, the individual Functions are required to be OPERABLE in MODES 1, 2, and 3 consistent with the Applicability for LCO 3.6.1.1, "Primary Containment." Functions that have different Applicabilities are discussed below in the individual Functions discussion.
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
: 1. Main Steam Line Isolation 1.a. Reactor Vessel Water Level - Low Low Low, Level 1 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of the MSIVs and other interfaces with the reactor vessel occurs to prevent offsite dose limits from being exceeded. The Reactor Vessel Water Level General Electric BWR/6 STS            B 3.3.6.1-4                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
                    - Low Low Low, Level 1 Function is one of the many Functions assumed to be OPERABLE and capable of providing isolation signals. The Reactor Vessel Water Level - Low Low Low, Level 1 Function associated with isolation is assumed in the analysis of the recirculation line break (Ref. 1). The isolation of the MSL on Level 1 supports actions to ensure that offsite dose limits are not exceeded for a DBA.
Reactor vessel water level signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level
                    - Low Low Low, Level 1 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Reactor Vessel Water Level - Low Low Low, Level 1 Allowable Value is chosen to be the same as the ECCS Level 1 Allowable Value (LCO 3.3.5.1) to ensure that the MSLs isolate on a potential loss of coolant accident (LOCA) to prevent offsite doses from exceeding 10 CFR 100 limits.
This Function isolates the Group 1 and 5 valves.
1.b. Main Steam Line Pressure - Low Low MSL pressure indicates that there may be a problem with the turbine pressure regulation, which could result in a low reactor vessel water level condition and the RPV cooling down more than 100&deg;F/hour if the pressure loss is allowed to continue. The Main Steam Line Pressure - Low Function is directly assumed in the analysis of the pressure regulator failure (Ref. 2). For this event, the closure of the MSIVs ensures that the RPV temperature change limit (100&deg;F/hour) is not reached. In addition, this Function supports actions to ensure that Safety Limit 2.1.1.1 is not exceeded. (This Function closes the MSIVs prior to pressure decreasing below 785 psig, which results in a scram due to MSIV closure, thus reducing reactor power to < 25% RTP.)
The MSL low pressure signals are initiated from four transmitters that are connected to the MSL header. The transmitters are arranged such that, even though physically separated from each other, each transmitter is able to detect low MSL pressure. Four channels of Main Steam Line Pressure - Low Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
General Electric BWR/6 STS            B 3.3.6.1-5                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Allowable Value was selected to be high enough to prevent excessive RPV depressurization.
The Main Steam Line Pressure - Low Function is only required to be OPERABLE in MODE 1 since this is when the assumed transient can occur (Ref. 2).
This Function isolates the Group 1 valves.
1.c. Main Steam Line Flow - High Main Steam Line Flow - High is provided to detect a break of the MSL and to initiate closure of the MSIVs. If the steam were allowed to continue flowing out of the break, the reactor would depressurize and the core could uncover. If the RPV water level decreases too far, fuel damage could occur. Therefore, the isolation is initiated on high flow to prevent or minimize core damage. The Main Steam Line Flow - High Function is directly assumed in the analysis of the main stream line break (MSLB) accident (Ref. 1). The isolation action, along with the scram function of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46 and offsite doses do not exceed the 10 CFR 100 limits.
The MSL flow signals are initiated from 16 transmitters that are connected to the four MSLs. The transmitters are arranged such that, even though physically separated from each other, all four connected to one steam line would be able to detect the high flow. Four channels of Main Steam Line Flow - High Function for each unisolated MSL (two channels per trip system) are available and are required to be OPERABLE so that no single instrument failure will preclude detecting a break in any individual MSL.
The Allowable Value is chosen to ensure that offsite dose limits are not exceeded due to the break.
This Function isolates the Group 1 valves.
1.d. Condenser Vacuum - Low The Condenser Vacuum - Low Function is provided to prevent overpressurization of the main condenser in the event of a loss of the main condenser vacuum. Since the integrity of the condenser is an assumption in offsite dose calculations, the Condenser Vacuum - Low Function is assumed to be OPERABLE and capable of initiating closure of the MSIVs. The closure of the MSIVs is initiated to prevent the addition of steam that would lead to additional condenser pressurization and General Electric BWR/6 STS            B 3.3.6.1-6                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) possible rupture of the diaphragm installed to protect the turbine exhaust hood, thereby preventing a potential radiation leakage path following an accident.
Condenser vacuum pressure signals are derived from four pressure transmitters that sense the pressure in the condenser. Four channels of Condenser Vacuum - Low Function are available and are required to be OPERABLE to ensure no single instrument failure can preclude the isolation function.
The Allowable Value is chosen to prevent damage to the condenser due to pressurization, thereby ensuring its integrity for offsite dose analysis.
As noted (footnote (a) to Table 3.3.6.1-1), the channels are not required to be OPERABLE in MODES 2 and 3, when all turbine stop valves (TSVs) are closed, since the potential for condenser overpressurization is minimized. Switches are provided to manually bypass the channels when all TSVs are closed.
This Function isolates the Group 1 valves.
1.e, 1.f. Main Steam Tunnel Ambient and Differential Temperature - High Ambient and Differential Temperature - High is provided to detect a leak in the RCPB, and provides diversity to the high flow instrumentation. The isolation occurs when a very small leak has occurred. If the small leak is allowed to continue without isolation, offsite dose limits may be reached.
However, credit for these instruments is not taken in any transient or accident analysis in the FSAR, since bounding analyses are performed for large breaks such as MSLBs.
Ambient temperature signals are initiated from thermocouples located in the area being monitored. Four channels of Main Steam Tunnel Temperature - High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. Each Function has one temperature element.
Eight thermocouples provide input to the Main Steam Tunnel Differential Temperature - High Function. The output of these thermocouples is used to determine the differential temperature. Each channel consists of a differential temperature instrument that receives inputs from thermocouples that are located in the inlet and outlet of the area cooling system for a total of four available channels.
The ambient and differential temperature monitoring Allowable Value is chosen to detect a leak equivalent to 25 gpm.
General Electric BWR/6 STS            B 3.3.6.1-7                                        Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
These Functions isolate the Group 1 valves.
1.g. Manual Initiation The Manual Initiation push button channels introduce signals into the MSL isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability. There is no specific FSAR safety analysis that takes credit for this Function. It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.
There are four push buttons for the logic, two manual initiation push buttons per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.
Four channels of Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3, since these are the MODES in which the MSL Isolation automatic Functions are required to be OPERABLE.
: 2. Primary Containment Isolation 2.a, 2.e. Reactor Vessel Water Level - Low Low, Level 2 Low RPV water level indicates the capability to cool the fuel may be threatened. The valves whose penetrations communicate with the primary containment are isolated to limit the release of fission products.
The isolation of the primary containment on Level 2 supports actions to ensure that offsite dose limits of 10 CFR 100 are not exceeded. The Reactor Vessel Water Level - Low Low, Level 2 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.
Reactor Vessel Water Level - Low Low, Level 2 signals are initiated from level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level - Low Low, Level 2 Function are available and are required to be OPERABLE to ensure no single instrument failure can preclude the isolation function.
The Reactor Vessel Water Level - Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Reactor Vessel Water Level - Low Low, Level 2 Allowable Value (LCO 3.3.5.1), since isolation of these valves is not critical to orderly plant shutdown.
General Electric BWR/6 STS            B 3.3.6.1-8                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
This Function isolates the Group 6A, 6B, and 7 valves.
2.b, 2.d, 2.f. Drywell Pressure - High High drywell pressure can indicate a break in the RCPB. The isolation of some of the PCIVs on high drywell pressure supports actions to ensure that offsite dose limits of 10 CFR 100 are not exceeded. The Drywell Pressure - High Function associated with isolation of the primary containment is implicitly assumed in the FSAR accident analysis as these leakage paths are assumed to be isolated post LOCA.
High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell. Four channels of Drywell Pressure -
High per Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Value was selected to be the same as the ECCS Drywell Pressure - High Allowable Value (LCO 3.3.5.1), since this may be indicative of a LOCA inside primary containment.
These Functions isolate the Group 6A and 7 valves (Function 2.b), E61 isolation valves (Function 2.d), and Group 6B valves (Function 2.f).
2.c. Reactor Vessel Water Level - Low Low Low, Level 1 Low RPV water level indicates the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of the primary containment occurs to prevent offsite dose limits from being exceeded. The Reactor Vessel Water Level
                    - Low Low Low, Level 1 Function is one of the many Functions assumed to be OPERABLE and capable of providing isolation signals. The Reactor Vessel Water Level - Low Low Low, Level 1 Function associated with isolation is implicitly assumed in the FSAR analysis as these leakage paths are assumed to be isolated post LOCA.
Reactor vessel water level signals are initiated from level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level
                    - Low Low Low, Level 1 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
General Electric BWR/6 STS            B 3.3.6.1-9                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Reactor Vessel Water Level - Low Low Low, Level 1 Allowable Value is chosen to be the same as the ECCS Reactor Vessel Water Level - Low Low Low, Level 1 Allowable Value (LCO 3.3.5.1) to ensure the valves are isolated to prevent offsite doses from exceeding 10 CFR 100 limits.
This Function isolates the E61 isolation valves.
2.g. Containment and Drywell Ventilation Exhaust Radiation - High High ventilation exhaust radiation is an indication of possible gross failure of the fuel cladding. The release may have originated from the primary containment due to a break in the RCPB. When Exhaust Radiation - High is detected, valves whose penetrations communicate with the primary containment atmosphere are isolated to limit the release of fission products. Additionally, the Ventilation Exhaust Radiation - High is assumed to initiate isolation of the primary containment during a fuel handling accident [involving handling recently irradiated fuel] (Ref. 2).
The Exhaust Radiation - High signals are initiated from radiation detectors that are located on the ventilation exhaust piping coming from the drywell and containment. The signal from each detector is input to an individual monitor whose trip outputs are assigned to an isolation channel. Four channels of Containment and Drywell Ventilation Exhaust - High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Values are chosen to promptly detect gross failure of the fuel cladding and to ensure offsite doses remain below 10 CFR 20 and 10 CFR 100 limits.
The Function is required to be OPERABLE during movement of [recently]
irradiated fuel assemblies in the primary or secondary containment because the capability of detecting radiation releases due to fuel failures (due to dropped [recently] irradiated fuel assemblies) must be provided to ensure offsite dose limits are not exceeded. [Due to radioactive decay, this Function is only required to isolate primary containment during 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)].
These Functions isolate the Group 7 valves.
General Electric BWR/6 STS          B 3.3.6.1-10                                        Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 2.h. Manual Initiation The Manual Initiation push button channels introduce signals into the primary containment isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability. There is no specific FSAR safety analysis that takes credit for this Function. It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.
There are four push buttons for the logic, two manual initiation push buttons per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.
Four channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3, since these are the MODES in which the Primary Containment Isolation automatic Functions are required to be OPERABLE.
: 3. Reactor Core Isolation Cooling System Isolation 3.a. RCIC Steam Line Flow - High RCIC Steam Line Flow - High Function is provided to detect a break of the RCIC steam lines and initiates closure of the steam line isolation valves. If the steam is allowed to continue flowing out of the break, the reactor will depressurize and core uncovery can occur. Therefore, the isolation is initiated on high flow to prevent or minimize core damage.
The isolation action, along with the scram function of the Reactor Protection System (RPS), ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Specific credit for this Function is not assumed in any FSAR accident analyses since the bounding analysis is performed for large breaks such as recirculation and MSL breaks. However, these instruments prevent the RCIC steam line break from becoming bounding.
The RCIC Steam Line Flow - High signals are initiated from two transmitters that are connected to the system steam lines. Two channels of RCIC Steam Line Flow - High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Value is chosen to be low enough to ensure that the trip occurs to prevent fuel damage and maintains the MSLB event as the bounding event.
General Electric BWR/6 STS            B 3.3.6.1-11                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
This Function isolates the Group 4 valves.
3.b. RCIC Steam Line Flow Time Delay The RCIC Steam Line Flow Time Delay is provided to prevent false isolations on RCIC Steam Line Flow - High during system startup transients and therefore improves system reliability. This Function is not assumed in any FSAR transient or accident analyses.
The Allowable Value was chosen to be long enough to prevent false isolations due to system starts but not so long as to impact offsite dose calculations.
Two channels for RCIC Steam Line Flow Time Delay Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
3.c. RCIC Steam Supply Line Pressure - Low Low MSL pressure indicates that the pressure of the steam in the RCIC turbine may be too low to continue operation of the associated system's turbine. This isolation is for equipment protection and is not assumed in any transient or accident analysis in the FSAR. However, it also provides a diverse signal to indicate a possible system break. These instruments are included in the Technical Specifications (TS) because of the potential for risk due to possible failure of the instruments preventing RCIC initiations.
The RCIC Steam Supply Line Pressure - Low signals are initiated from two transmitters that are connected to the system steam line. Two channels of RCIC Steam Supply Line Pressure - Low Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Value is selected to be high enough to prevent damage to the system's turbines.
This Function isolates the Group 4 valves.
3.d. RCIC Turbine Exhaust Diaphragm Pressure - High High turbine exhaust diaphragm pressure indicates that the pressure may be too high to continue operation of the associated system's turbine. That is, one of two exhaust diaphragms has ruptured and pressure is reaching turbine casing pressure limits. This isolation is for equipment protection and is not assumed in any transient or accident analysis in the FSAR.
General Electric BWR/6 STS          B 3.3.6.1-12                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
These instruments are included in the TS because of the potential for risk due to possible failure of the instruments preventing RCIC initiations (Ref. 3).
The RCIC Turbine Exhaust Diaphragm Pressure - High signals are initiated from four transmitters that are connected to the area between the rupture diaphragms on each system's turbine exhaust line. Four channels of RCIC Turbine Exhaust Diaphragm Pressure - High Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Values are high enough to prevent damage to the system's turbines.
This Function isolates the Group 4 valves.
3.e, 3.f, 3.j, 3.k. Ambient and Differential Temperature - High Ambient and Differential Temperatures are provided to detect a leak from the associated system steam piping. The isolation occurs when a very small leak has occurred and is diverse to the high flow instrumentation. If the small leak is allowed to continue without isolation, offsite dose limits may be reached. These Functions are not assumed in any FSAR transient or accident analysis, since bounding analyses are performed for large breaks such as recirculation or MSL breaks.
Ambient and Differential Temperature - High signals are initiated from thermocouples that are appropriately located to protect the system that is being monitored. Two instruments monitor each area. Six channels for RHR and RCIC Ambient Temperature - High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. There are two for the RCIC room and four for the RHR area.
There are 12 thermocouples (four for the RCIC room and eight for the RHR area) that provide input to the Area Ventilation Differential Temperature - High Function. The output of these thermocouples is used to determine the differential temperature. Each channel consists of a differential temperature instrument that receives inputs from thermocouples that are located in the inlet and outlet of the area cooling system for a total of six (two for the RCIC room and four for the RHR area) available channels.
The Allowable Values are set low enough to detect a leak equivalent to 25 gpm.
General Electric BWR/6 STS            B 3.3.6.1-13                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
This Function isolates the Group 4 valves.
3.g, 3.h. Main Steam Line Tunnel Ambient and Differential Temperature -
High Ambient and Differential Temperature - High is provided to detect a leak in the RCPB and provides diversity to the high flow instrumentation. The isolation occurs when a very small leak has occurred. If the small leak is allowed to continue without isolation, offsite limits may be reached.
However, credit for these instruments is not taken in any transient or accident analysis in the FSAR, since bounding analyses are performed for large breaks such as MSLBs.
Ambient temperature signals are initiated from thermocouples located in the area being monitored. Two channels of Main Steam Tunnel Temperature - High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. Each Function has one temperature element.
Four thermocouples provide input to the Main Steam Tunnel Differential Temperature - High Function. The output of these thermocouples is used to determine the differential temperature. Each channel consists of a differential temperature instrument that receives inputs from thermocouples that are located in the inlet and outlet of the area cooling system for a total of two available channels.
The Allowable Values are chosen to detect a leak equivalent to 25 gpm.
This Function isolates the Group 4 valves.
3.i. Main Steam Line Tunnel Temperature Timer The Main Steam Line Tunnel Temperature Timer is provided to allow all the other systems that may be leaking in the main steam tunnel (as indicated by the high temperature) to be isolated before RCIC is automatically isolated. This ensures maximum RCIC System operation by preventing isolations due to leaks in other systems. This Function is not assumed in any FSAR transient or accident analysis; however, maximizing RCIC availability is an important function.
Two channels for RCIC Main Steam Line Tunnel Timer Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
General Electric BWR/6 STS          B 3.3.6.1-14                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Allowable Values are based on maximizing the availability of the RCIC System; that is, providing sufficient time to isolate all other potential leakage sources in the main steam tunnel before RCIC is isolated.
This Function isolates the Group 4 valves.
3.l. RCIC/RHR High Steam Line Flow - High RCIC/RHR high steam line flow is provided to detect a break of the common steam line of RCIC and RHR (steam condensing mode) and initiates closure of the isolation valves for both systems. If the steam were allowed to continue flowing out of the break, the reactor would depressurize and the core could uncover. Therefore, the isolation is initiated at high flow to prevent or minimize core damage. Specific credit for this Function is not assumed in any FSAR accident or transient analysis since the bounding analysis is performed for large breaks such as recirculation and MSL breaks. However, these instruments prevent the RCIC/RHR steam line break from becoming bounding.
The RCIC/RHR steam line flow signals are initiated from two transmitters that are connected to the steam line. Two channels with one channel in each trip system are available and required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. The Allowable Value is selected to ensure that the trip occurs to prevent fuel damage and maintains the MSLB as the boundary event.
This Function actuates the Group 4 valves.
3.m. Drywell Pressure - High High drywell pressure can indicate a break in the RCPB. The RCIC isolation of the turbine exhaust is provided to prevent communication with the drywell when high drywell pressure exists. A potential leakage path exists via the turbine exhaust. The isolation is delayed until the system becomes unavailable for injection (i.e., low steam line pressure). The isolation of the RCIC turbine exhaust by Drywell Pressure - High is indirectly assumed in the FSAR accident analysis because the turbine exhaust leakage path is not assumed to contribute to offsite doses.
High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell. Two channels of RCIC Drywell Pressure - High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
General Electric BWR/6 STS            B 3.3.6.1-15                                        Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Allowable Value was selected to be the same as the ECCS Drywell Pressure - High Allowable Value (LCO 3.3.5.1), since this is indicative of a LOCA inside primary containment.
This Function isolates the Group 9 valves.
3.n. Manual Initiation The Manual Initiation push button channels introduce signals into the RCIC System isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability. There is no specific FSAR safety analysis that takes credit for this Function. It is retained for overall redundancy and diversity of the isolation function as required by the NRC in the plant licensing basis.
There are four push buttons for RCIC, two manual initiation push buttons per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.
Four channels of RCIC Manual Initiation are available and are required to be OPERABLE.
: 4. Reactor Water Cleanup System Isolation 4.a. Differential Flow - High The high differential flow signal is provided to detect a break in the RWCU System. This will detect leaks in the RWCU System when area or differential temperature would not provide detection (i.e., a cold leg break). Should the reactor coolant continue to flow out of the break, offsite dose limits may be exceeded. Therefore, isolation of the RWCU System is initiated when high differential flow is sensed to prevent exceeding offsite doses. A time delay is provided to prevent spurious trips during most RWCU operational transients. This Function is not assumed in any FSAR transient or accident analysis, since bounding analyses are performed for large breaks such as MSLBs.
The high differential flow signals are initiated from two transmitters that are connected to the inlet (from the reactor vessel) and four transmitters from the outlets (to condenser and feedwater) of the RWCU System. The outputs of the transmitters are compared (in two different summers) and the outputs are sent to two high flow trip units. If the difference between the inlet and outlet flow is too large, each trip unit generates an isolation General Electric BWR/6 STS            B 3.3.6.1-16                                        Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) signal. Two channels of Differential Flow - High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Reactor Water Cleanup Differential Flow - High Allowable Value ensures that the break of the RWCU piping is detected.
This Function isolates the Group 8 valves.
4.b. Differential Flow - Timer The Differential Flow - Timer is provided to avoid RWCU System isolations due to operational transients (such as pump starts and mode changes). During these transients the inlet and return flows become unbalanced for short time periods and Differential Flow - High will be sensed without an RWCU System break being present. Credit for this Function is not assumed in the FSAR accident or transient analysis, since bounding analyses are performed for large breaks such as MSLBs.
The Differential Flow Timer Allowable Value is selected to ensure that the MSLB outside containment remains the limiting break for FSAR analysis for offsite dose calculations.
Two channels for Differential Flow - Timer Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
4.c, 4.d, 4.e, 4.f, 4.g, 4.h. Ambient and Differential Temperature - High Ambient and Differential Temperature - High is provided to detect a leak from the RWCU System. The isolation occurs even when very small leaks have occurred and is diverse to the high differential flow instrumentation for the hot portions of the RWCU System. If the small leak continues without isolation, offsite dose limits may be reached.
Credit for these instruments is not taken in any transient or accident analysis in the FSAR, since bounding analyses are performed for large breaks such as MSLBs.
Ambient and differential temperature signals are initiated from temperature elements that are located in the room that is being monitored. There are eight thermocouples that provide input to the Area Temperature - High Function (two per area). Eight channels are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
General Electric BWR/6 STS            B 3.3.6.1-17                                    Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
There are 16 thermocouples that provide input to the Differential Temperature - High Function. The output of these thermocouples is used to determine the differential temperature. Each channel consists of a differential temperature instrument that receives inputs from thermocouples that are located in the inlet and outlet of the area cooling system for a total of eight available channels (two per area). Eight channels are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Ambient and Differential Temperature - High Allowable Values are set low enough to detect a leak equivalent to 25 gpm.
These Functions isolate the Group 8 valves.
4.i, 4.j. Main Steam Line Tunnel Ambient and Differential Temperature -
High Ambient and Differential Temperature - High is provided to detect a leak in the RCPB and provides diversity to the high flow instrumentation. The isolation occurs when a very small leak has occurred. If the small leak is allowed to continue without isolation, offsite dose limits may be reached.
However, credit for these instruments is not taken in any transient or accident analysis, since bounding analyses are performed for large breaks such as MSLBs.
Ambient temperature signals are initiated from thermocouples located in the area being monitored. Two channels of Main Steam Tunnel Temperature - High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. Each Function has one temperature element.
There are four thermocouples that provide input to the Differential Temperature - High Function. The output of these thermocouples is used to determine the differential temperature. Each channel consists of a differential temperature instrument that receives inputs from thermocouples that are located in the inlet and outlet of the area cooling system for a total of two available channels.
The Allowable Values are chosen to detect a leak equivalent to 25 gpm.
This Function isolates the Group 8 valves.
General Electric BWR/6 STS          B 3.3.6.1-18                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 4.k. Reactor Vessel Water Level - Low Low, Level 2 Low RPV water level indicates the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of some reactor vessel interfaces occurs to isolate the potential sources of a break. The isolation of the RWCU System on Level 2 supports actions to ensure that fuel peak cladding temperature remains below the limits of 10 CFR 50.46. The Reactor Vessel Water Level - Low Low, Level 2 Function associated with RWCU isolation is not directly assumed in any transient or accident analysis, since bounding analyses are performed for large breaks such as MSLBs.
Reactor Vessel Water Level - Low Low, Level 2 signals are initiated from level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level - Low Low, Level 2 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Reactor Vessel Water Level - Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Reactor Vessel Water Level - Low Low, Level 2 Allowable Value (LCO 3.3.5.1), since the capability to cool the fuel may be threatened.
This Function isolates the Group 8 valves.
4.l. SLC System Initiation The isolation of the RWCU System is required when the SLC System has been initiated to prevent dilution and removal of the boron solution by the RWCU System (Ref. 4). SLC System initiation signals are initiated from the two SLC pump start signals.
There is no Allowable Value associated with this Function since the channels are mechanically actuated based solely on the position of the SLC System initiation switch.
Two channels (one from each pump) of SLC System Initiation Function are available and are required to be OPERABLE only in MODES 1 and 2, since these are the only MODES where the reactor can be critical, and these MODES are consistent with the Applicability for the SLC System (LCO 3.1.7).
General Electric BWR/6 STS            B 3.3.6.1-19                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 4.m. Manual Initiation The Manual Initiation push button channels introduce signals into the RWCU System isolation logic that are redundant to the automatic protective instrumentation and provide manual isolation capability. There is no specific FSAR safety analysis that takes credit for this Function. It is retained for overall redundancy and diversity of the isolation function as required by the NRC in plant licensing basis.
There are four push buttons for the logic, two manual initiation push buttons per trip system. There is no Allowable Value for this Function, since the channels are mechanically actuated based solely on the position of the push buttons.
Four channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3 since these are the MODES in which the RWCU System Isolation automatic Functions are required to be OPERABLE.
: 5. Shutdown Cooling System Isolation 5.a, 5.b. Ambient and Differential Temperature - High Ambient and Differential Temperature - High is provided to detect a leak from the associated system steam piping. The isolation occurs when a very small leak has occurred and is diverse to the high flow instrumentation. If the small leak is allowed to continue without isolation, offsite dose limits may be reached. These Functions are not assumed in any FSAR transient or accident analysis, since bounding analyses are performed for large breaks such as MSLBs.
Ambient and Differential Temperature - High signals are initiated from thermocouples that are appropriately located to protect the system that is being monitored. Two instruments monitor each area. Four channels for RHR Ambient and Differential Temperature - High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
Eight thermocouples provide input to the Area Ventilation Differential Temperature - High Function. The output of these thermocouples is used to determine the differential temperature. Each channel consists of a differential temperature instrument that receives inputs from thermocouples that are located in the inlet and outlet of the area cooling system for a total of four available channels.
General Electric BWR/6 STS            B 3.3.6.1-20                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Allowable Values are set low enough to detect a leak equivalent to 25 gpm.
This Function isolates the Group 3 valves.
5.c. Reactor Vessel Water Level - Low, Level 3 Low RPV water level indicates the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, isolation of some reactor vessel interfaces occurs to begin isolating the potential sources of a break. The Reactor Vessel Water Level - Low, Level 3 Function associated with RHR Shutdown Cooling System isolation is not directly assumed in any transient or accident analysis, since bounding analyses are performed for large breaks such as MSLBs. The RHR Shutdown Cooling System isolation on Level 3 supports actions to ensure that the RPV water level does not drop below the top of the active fuel during a vessel draindown event caused by a leak (e.g., pipe break or inadvertent valve opening) in the RHR Shutdown Cooling System.
Reactor Vessel Water Level - Low, Level 3 signals are initiated from level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels (two channels per trip system) of the Reactor Vessel Water Level - Low, Level 3 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Reactor Vessel Water Level - Low, Level 3 Allowable Value was chosen to be the same as the RPS Reactor Vessel Water Level - Low, Level 3 Allowable Value (LCO 3.3.1.1) since the capability to cool the fuel may be threatened.
The Reactor Vessel Water Level - Low, Level 3 Function is only required to be OPERABLE in MODE 3 to prevent this potential flow path from lowering reactor vessel level to the top of the fuel. In MODES 1 and 2, other isolations (e.g., Reactor Steam Dome Pressure - High) and administrative controls ensure that this flow path remains isolated to prevent unexpected loss of inventory via this flow path.
General Electric BWR/6 STS          B 3.3.6.1-21                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
This Function isolates the Group 3 valves.
5.d. Reactor Steam Dome Pressure - High The Shutdown Cooling System Reactor Steam Dome Pressure - High Function is provided to isolate the shutdown cooling portion of the RHR System. This interlock is provided only for equipment protection to prevent an intersystem LOCA scenario and credit for the interlock is not assumed in the accident or transient analysis in the FSAR.
The Reactor Steam Dome - High pressure signals are initiated from four transmitters. Four channels of Reactor Steam Dome Pressure - High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. The Allowable Value was chosen to be low enough to protect the system equipment from overpressurization.
This Function isolates the Group 3 valves.
5.e. Drywell Pressure - High High drywell pressure can indicate a break in the RCPB. The isolation of some of the PCIVs on high drywell pressure supports actions to ensure that offsite dose limits of 10 CFR 100 are not exceeded. The Drywell Pressure - High Function associated with isolation of the RHR Shutdown Cooling System is not modeled in any FSAR accident or transient analysis because other leakage paths (e.g., MSIVs) are more limiting.
High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell. Four channels of Drywell Pressure -
High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Value was selected to be the same as the ECCS Drywell Pressure - High Allowable Value (LCO 3.3.5.1), since this may be indicative of a LOCA inside primary containment.
This Function isolates the Group 3 valves.
ACTIONS            -----------------------------------REVIEWERS NOTE-----------------------------------
Certain LCO Completion Times are based on approved topical reports. In order for a licensee to use the times, the licensee must justify the Completion Times as required by the staff Safety Evaluation Report (SER) for the topical report.
General Electric BWR/6 STS              B 3.3.6.1-22                                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS (continued)
The ACTIONS are modified by two NOTES. Note 1 allows penetration flow path(s) to be unisolated intermittently under administrative controls.
These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room.
In this way, the penetration can be rapidly isolated when a need for primary containment isolation is indicated. Note 2 has been provided to modify the ACTIONS related to primary containment isolation instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable primary containment isolation instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable primary containment isolation instrumentation channel. When the Required Channels in Table 3.3.6.1-1 are specified (e.g., on a per steam line, per loop, etc.,
basis) then the Condition may be entered separately for each steam line, loop, as appropriate.
A.1 Because of the diversity of sensors available to provide isolation signals and the redundancy of the isolation design, an allowable out of service time of 12 hours or 24 hours, depending on the Function, has been shown to be acceptable (Refs. 5 and 6) to permit restoration of any inoperable channel to OPERABLE status. This out of service time is only acceptable provided the associated Function is still maintaining isolation capability (refer to Required Action B.1 Bases). [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action A.1.
Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue with no further restrictions. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an isolation),
Condition C must be entered and its Required Action taken.
General Electric BWR/6 STS            B 3.3.6.1-23                                        Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS (continued)
B.1 Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant automatic isolation capability being lost for the associated penetration flow path(s). The MSL isolation Functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip such that both trip systems will generate a trip signal from the given Function on a valid signal. The other isolation Functions are considered to be maintaining isolation capability when sufficient channels are OPERABLE or in trip such that one trip system will generate a trip signal from the given Function on a valid signal. This ensures that one of the two PCIVs in the associated penetration flow path can receive an isolation signal from the given Function. For Functions 1.a, 1.b, 1.d, 1.e, and 1.f, this would require both trip systems to have one channel OPERABLE or in trip. For Function 1.c, this would require both trip systems to have one channel, associated with each MSL, OPERABLE or in trip. For Functions 2.a, 2.b, 2.c, 2.d, 2.e, 2.f, 2.g, 3.d, 4.k, 5.c, 5.d, and 5.e, this would require one trip system to have two channels, each OPERABLE or in trip. For Functions 3.a, 3.b, 3.c, 3.e, 3.f, 3.g, 3.h, 3.i, 3.l, 3.m, 4.a, 4.b, 4.c, 4.d, 4.g, 4.h, 4.i, 4.j, and 4.l, this would require one trip system to have one channel OPERABLE or in trip. For Functions 3.j, 3.k, 4.e, 4.f, 5.a, and 5.b, each Function consists of channels that monitor several different locations. Therefore, this would require one channel per location to be OPERABLE or in trip (the channels are not required to be in the same trip system). The Condition does not include the Manual Initiation Functions (Functions 1.g, 2.h, 3.n, and 4.m),
since they are not assumed in any accident or transient analysis. Thus, a total loss of manual initiation capability for 24 hours (as allowed by Required Action A.1) is allowed.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
C.1 Required Action C.1 directs entry into the appropriate Condition referenced in Table 3.3.6.1-1. The applicable Condition specified in Table 3.3.6.1-1 is Function and MODE or other specified condition dependent and may change as the Required Action of a previous Condition is completed. Each time an inoperable channel has not met General Electric BWR/6 STS              B 3.3.6.1-24                                            Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS (continued) any Required Action of Condition A or B and the associated Completion Time has expired, Condition C will be entered for that channel and provides for transfer to the appropriate subsequent Condition.
D.1, D.2.1, and D.2.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by placing the plant in at least MODE 3 within 12 hours and in MODE 4 within 36 hours (Required Actions D.2.1 and D.2.2). Alternately, the associated MSLs may be isolated (Required Action D.1), and if allowed (i.e., plant safety analysis allows operation with an MSL isolated), plant operation with the MSL isolated may continue. Isolating the affected MSL accomplishes the safety function of the inoperable channel. 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.
E.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by placing the plant in at least MODE 2 within 6 hours.
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.
F.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, plant operation may continue if the affected penetration flow path(s) is isolated. Isolating the affected penetration flow path(s) accomplishes the safety function of the inoperable channels.
For some of the Ambient and Differential Temperature Functions, the affected penetration flow path(s) may be considered isolated by isolating only that portion of the system in the associated room monitored by the inoperable channel. That is, if the RWCU pump room A ambient channel is inoperable, the A pump room area can be isolated while allowing continued RWCU operation utilizing the B RWCU pump.
General Electric BWR/6 STS            B 3.3.6.1-25                                    Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS (continued)
Alternatively, if it is not desired to isolate the affected penetration flow path(s) (e.g., as in the case where isolating the penetration flow path(s) could result in a reactor scram), Condition H must be entered and its Required Actions taken.
The Completion Time is acceptable because it minimizes risk while allowing sufficient time for plant operations personnel to isolate the affected penetration flow path(s).
G.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, plant operations may continue if the affected penetration flow path(s) is isolated. Isolating the affected penetration flow path(s) accomplishes the safety function of the inoperable channels. The 24 hour Completion Time is acceptable due to the fact that these Functions (Manual Initiation) are not assumed in any accident or transient analysis in the FSAR. Alternately, if it is not desired to isolate the affected penetration flow path(s) (e.g., as in the case where isolating the penetration flow path(s) could result in a reactor scram),
Condition H must be entered and its Required Actions taken.
H.1 and H.2 If the channel is not restored to OPERABLE status or placed in trip, or any Required Action of Condition F or G is not met and the associated Completion Time has expired, the plant must be placed in a MODE or other specified condition in which the LCO does not apply. This is done by placing the plant in at least MODE 3 within 12 hours and in MODE 4 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.
I.1 and I.2 If the channel is not restored to OPERABLE status within the allowed Completion Time, the associated SLC subsystem(s) is declared inoperable or the RWCU System is isolated. Since this Function is required to ensure that the SLC System performs its intended function, sufficient remedial measures are provided by declaring the associated SLC subsystem inoperable or isolating the RWCU System.
General Electric BWR/6 STS            B 3.3.6.1-26                                        Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES ACTIONS (continued)
The Completion Time of 1 hour is acceptable because it minimizes risk while allowing sufficient time for personnel to isolate the RWCU System.
J.1 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated penetration flow path should be closed. However, if the shutdown cooling function is needed to provide core cooling, these Required Actions allow the penetration flow path to remain unisolated provided action is immediately initiated to restore the channel to OPERABLE status. ACTIONS must continue until the channel is restored to OPERABLE status.
K.1 and K.2 If the channel is not restored to OPERABLE status or placed in trip within the allowed Completion Time, the associated penetration flow path(s) should be isolated (Required Action K.1). Isolating the affected penetration flow path(s) accomplishes the safety function of the inoperable instrumentation. Alternately, the plant must be placed in a condition in which the LCO does not apply. If applicable, movement of
[recently] irradiated fuel assemblies must be immediately suspended.
Suspension of these activities shall not preclude completion of movement of a component to a safe condition.
SURVEILLANCE        -----------------------------------REVIEWERS NOTE-----------------------------------
REQUIREMENTS        Certain Frequencies are based on approved topical reports. In order for a licensee to use these Frequencies, the licensee must justify the Frequencies as required by the staff SER for the topical report.
As noted at the beginning of the SRs, the SRs for each Primary Containment Isolation Instrumentation Function are found in the SRs column of Table 3.3.6.1-1.
The Surveillances are also modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required General Electric BWR/6 STS              B 3.3.6.1-27                                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE REQUIREMENTS (continued)
Actions may be delayed for up to 6 hours provided the associated Function maintains trip capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 5 and 6) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the PCIVs will isolate the penetration flow path(s) when necessary.
SR 3.3.6.1.1 Performance of the CHANNEL CHECK 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 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 instrument has drifted outside its limit.
[ The Frequency of 12 hours is based on operating experience that demonstrates channel failure is rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.3.6.1-28                                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
SR 3.3.6.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the 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 methodology.
[ The Frequency is based on reliability analysis described in References 5 and 6.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.1.3 The calibration of trip units consists of a test to provide a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.6.1-1. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the General Electric BWR/6 STS                B 3.3.6.1-29                                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE REQUIREMENTS (continued) setpoint methodology. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.
[ The Frequency of 92 days is based on the reliability analysis of References 5 and 6.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.1.4 and SR 3.3.6.1.5 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
[ The Frequency of SR 3.3.6.1.4 is based on the assumption of a 92 day calibration interval in the determination of equipment drift in the setpoint analysis. The Frequency of SR 3.3.6.1.5 is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.3.6.1-30                                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.1.6 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing performed on PCIVs in LCO 3.6.1.3 overlaps this Surveillance to provide complete testing of the assumed safety function. [ The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.1.7 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis.
Testing is performed only on channels where the assumed response time does not correspond to the diesel generator (DG) start time. For channels assumed to respond within the DG start time, sufficient margin exists in the [10] second start time when compared to the typical channel response time (milliseconds) so as to assure adequate response without a specific measurement test. The instrument response times must be General Electric BWR/6 STS              B 3.3.6.1-31                                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE REQUIREMENTS (continued) added to the PCIV closure times to obtain the ISOLATION SYSTEM RESPONSE TIME. ISOLATION SYSTEM RESPONSE TIME acceptance criteria are included in Reference 7.
ISOLATION SYSTEM RESPONSE TIME may be verified by actual response time measurements in any series of sequential, overlapping, or total channel measurements.
[-----------------------------------REVIEWERS NOTE----------------------------------
The following Bases are applicable for plants adopting NEDO-32291-A and/or Supplement 1.
However, the sensors for Functions 1.a, 1.b, and 1.c are allowed to be excluded from specific ISOLATION SYSTEM RESPONSE TIME measurement if the conditions of Reference 8 are satisfied. If these conditions are satisfied, sensor response time may be allocated based on either assumed design sensor response time or the manufacturer's stated design response time. When the requirements of Reference 8 are not satisfied, sensor response time must be measured. Furthermore, measurement of the instrument loops response time for Functions 1.a, 1.b, and 1.c is not required if the conditions of Reference 9 are satisfied.
For all other Functions, the measurement of instrument loop response times may be excluded if the conditions of Reference 8 are satisfied.]
A Note to the Surveillance states that the radiation detectors may be excluded from ISOLATION SYSTEM RESPONSE TIME testing. This Note is necessary because of the difficulty of generating an appropriate detector input signal and because the principles of detector operation virtually ensure an instantaneous response time. Response time for radiation detection channels shall be measured from detector output or the input of the first electronic component in the channel.
[ ISOLATION SYSTEM RESPONSE TIME tests are conducted on an 18 month STAGGERED TEST BASIS. The 18 month test Frequency is consistent with the typical industry refueling cycle and is based upon plant operating experience that shows that random failures of instrumentation components causing serious response time degradation, but not channel failure, are infrequent.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.3.6.1-32                                                      Rev. 5.0
 
Primary Containment Isolation Instrumentation B 3.3.6.1 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [6.3].
: 2. FSAR, Chapter [15].
: 3. NEDO-31466, "Technical Specification Screening Criteria Application and Risk Assessment," November 1987.
: 4. FSAR, Section [9.3.5].
: 5. NEDC-31677-P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," June 1989.
: 6. NEDC-30851-P-A, Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.
: 7. FSAR, Section [7.3].
[8. NEDO-32291-A, "System Analyses for the Elimination of Selected Response Time Testing Requirements," October 1995.
: 9. NEDO-32291-A, Supplement 1, "System Analyses for the Elimination of Selected Response Time Testing Requirements," October 1999.]
General Electric BWR/6 STS              B 3.3.6.1-33                                                      Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 B 3.3 INSTRUMENTATION B 3.3.6.2 Secondary Containment Isolation Instrumentation BASES BACKGROUND          The secondary containment isolation instrumentation automatically initiates closure of appropriate secondary containment isolation valves (SCIVs) and starts the Standby Gas Treatment (SGT) System. The function of these systems, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) (Ref. 1), such that offsite radiation exposures are maintained within the requirements of 10 CFR 100 that are part of the NRC staff approved licensing basis. Secondary containment isolation and establishment of vacuum with the SGT System within the assumed time limits ensures that fission products that leak from primary containment following a DBA, or are released outside primary containment or during certain operations when primary containment is not required to be OPERABLE are maintained within applicable limits.
The isolation instrumentation includes the sensors, relays, and switches that are necessary to cause initiation of secondary containment isolation.
Most channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a secondary containment isolation signal to the isolation logic.
Functional diversity is provided by monitoring a wide range of independent parameters. The input parameters to the isolation logic are (a) reactor vessel water level, (b) drywell pressure, (c) fuel handling area ventilation exhaust, and (d) fuel handling area pool sweep exhaust radiation. Redundant sensor input signals from each parameter are provided for initiation of isolation parameters. In addition, manual initiation of the logic is provided.
For all Secondary Containment Isolation instrumentation Functions, both channels in a trip system are required to trip the associated trip system.
In addition to the isolation function, the SGT subsystems are initiated.
There are two SGT subsystems with one subsystem being initiated by each trip system. Typically, automatically isolated secondary containment penetrations are isolated by two isolation valves. One trip system initiates isolation of each valve so that operation of either trip system isolates the penetrations.
APPLICABLE          The isolation signals generated by the secondary containment isolation SAFETY              instrumentation are implicitly assumed in the safety analyses of ANALYSES, LCO,      References 1 and 2 to initiate closure of valves and start the SGT and APPLICABILITY  System to limit offsite doses.
General Electric BWR/6 STS              B 3.3.6.2-1                                      Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Refer to LCO 3.6.4.2, "Secondary Containment Isolation Valves (SCIVs),"
and LCO 3.6.4.3, "Standby Gas Treatment (SGT) System," Applicable Safety Analyses Bases for more detail of the safety analyses.
The secondary containment isolation instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.
The OPERABILITY of the secondary containment isolation instrumentation is dependent upon the OPERABILITY of the individual instrumentation channel Functions. Each Function must have the required number of OPERABLE channels with their setpoints set within the specified Allowable Values, as shown in Table 3.3.6.2-1. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. Each channel must also respond within its assumed response time, where appropriate.
Allowable Values are specified for each Function specified in the Table.
Nominal trip setpoints are specified in setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Values between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.
Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
In general, the individual Functions are required to be OPERABLE in the MODES or other specified conditions when SCIVs and the SGT System are required.
General Electric BWR/6 STS            B 3.3.6.2-2                                      Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
: 1. Reactor Vessel Water Level - Low Low, Level 2 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. An isolation of the secondary containment and actuation of the SGT System are initiated in order to minimize the potential of an offsite dose release. The Reactor Vessel Water Level - Low Low, Level 2 Function is one of the Functions assumed to be OPERABLE and capable of providing isolation and initiation signals. The isolation and initiation of systems on Reactor Vessel Water Level - Low Low, Level 2 support actions to ensure that any offsite releases are within the limits calculated in the safety analysis.
Reactor Vessel Water Level - Low Low, Level 2 signals are initiated from level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level - Low Low, Level 2 Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Reactor Vessel Water Level - Low Low, Level 2 Allowable Value was chosen to be the same as the High Pressure Core Spray (HPCS)/Reactor Core Isolation Cooling (RCIC) Reactor Vessel Water Level - Low Low, Level 2 Allowable Value (LCO 3.3.5.1, "Emergency Core Cooling System (ECCS) Instrumentation," and LCO 3.3.5.3, "Reactor Core Isolation Cooling (RCIC) System Actuation"), since this could indicate the capability to cool the fuel is being threatened.
The Reactor Vessel Water Level - Low Low, Level 2 Function is required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists in the Reactor Coolant System (RCS); thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas.
In MODES 4 and 5, the probability and consequences of these events are low due to the RCS pressure and temperature limitations of these MODES; thus, this Function is not required.
General Electric BWR/6 STS            B 3.3.6.2-3                                        Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
: 2. Drywell Pressure - High High drywell pressure can indicate a break in the reactor coolant pressure boundary (RCPB). An isolation of the secondary containment and actuation of the SGT System are initiated in order to minimize the potential of an offsite dose release. The isolation of high drywell pressure supports actions to ensure that any offsite releases are within the limits calculated in the safety analysis. However, the Drywell Pressure - High Function associated with isolation is not assumed in any FSAR accident or transient analysis. It is retained for the overall redundancy and diversity of the secondary containment isolation instrumentation as required by the NRC approved licensing basis.
High drywell pressure signals are initiated from pressure transmitters that sense the pressure in the drywell. Four channels of Drywell - High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Value was chosen to be the same as the ECCS Drywell Pressure - High Function Allowable Value (LCO 3.3.5.1) since this is indicative of a loss of coolant accident.
The Drywell Pressure - High Function is required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists in the RCS; thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas. This Function is not required in MODES 4 and 5 because the probability and consequences of these events are low due to the RCS pressure and temperature limitations of these MODES.
3, 4. Fuel Handling Area Ventilation and Pool Sweep Exhaust Radiation -
High High High secondary containment exhaust radiation is an indication of possible gross failure of the fuel cladding. The release may have originated from the primary containment due to a break in the RCPB or the refueling floor due to a fuel handling accident. When Exhaust Radiation - High High is detected, secondary containment isolation and actuation of the SGT System are initiated to limit the release of fission products as assumed in the FSAR safety analyses (Ref. 1).
The Exhaust Radiation - High High signals are initiated from radiation detectors that are located on the ventilation exhaust piping coming from the fuel handling area and the fuel handling area pool sweep, respectively. The signal from each detector is input to an individual monitor whose trip outputs are assigned to an isolation channel. Four General Electric BWR/6 STS            B 3.3.6.2-4                                        Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) channels of Fuel Handling Area Ventilation Exhaust Radiation - High High Function and four channels of Fuel Handling Area Pool Sweep Exhaust Radiation - High High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.
The Allowable Values are chosen to promptly detect gross failure of the fuel cladding.
The Exhaust Radiation - High High Functions are required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists; thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas. In MODES 4 and 5, the probability and consequences of these events are low due to the RCS pressure and temperature limitations of these MODES; thus, these Functions are not required. In addition, the Functions are required to be OPERABLE during movement of [recently] irradiated fuel assemblies in the primary or secondary containment because the capability of detecting radiation releases due to fuel failures (due to dropped fuel assemblies) must be provided to ensure that offsite dose limits are not exceeded. [Due to radioactive decay, this Function is only required to isolate secondary containment during 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).]
: 5. Manual Initiation The Manual Initiation push button channels introduce signals into the secondary containment isolation logic that are redundant to the automatic protective instrumentation channels, and provide manual isolation capability. There is no specific FSAR safety analysis that takes credit for this Function. It is retained for the overall redundancy and diversity of the secondary containment isolation instrumentation as required by the NRC approved licensing basis.
There are four push buttons for the logic, two manual initiation push buttons per trip system. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.
Four channels of the Manual Initiation Function are available and are required to be OPERABLE in MODES 1, 2, and 3 and during movement of [recently] irradiated fuel assemblies in the secondary containment, since these are the MODES and other specified conditions in which the Secondary Containment Isolation automatic Functions are required to be OPERABLE.
General Electric BWR/6 STS            B 3.3.6.2-5                                          Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES ACTIONS            -----------------------------------REVIEWERS NOTE-----------------------------------
Certain LCO Completion Times are based on approved topical reports. In order for a licensee to use the times, the licensee must justify the Completion Times as required by the staff Safety Evaluation Report (SER) for the topical report.
A Note has been provided to modify the ACTIONS related to secondary containment isolation instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition.
However, the Required Actions for inoperable secondary containment isolation instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable secondary containment isolation instrumentation channel. When the Required Channels in Table 3.3.6.3-1 are specified (e.g., on a per steam line, per loop, etc., basis) then the Condition may be entered separately for each steam line, loop, as appropriate.
A.1 Because of the diversity of sensors available to provide isolation signals and the redundancy of the isolation design, an allowable out of service time of 12 hours or 24 hours, depending on the Function, has been shown to be acceptable (Refs. 3 and 4) to permit restoration of any inoperable channel to OPERABLE status. This out of service time is only acceptable provided the associated Function is still maintaining isolation capability (refer to Required Action B.1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action A.1. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.
Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an isolation), Condition C must be entered and its Required Actions taken.
B.1 Required Action B.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function General Electric BWR/6 STS                B 3.3.6.2-6                                                      Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES ACTIONS (continued) result in a complete loss of automatic isolation capability for the associated penetration flow path(s) or a complete loss of automatic initiation capability for the SGT System. A Function is considered to be maintaining secondary containment isolation capability when sufficient channels are OPERABLE or in trip, such that one trip system will generate a trip signal from the given Function on a valid signal. This ensures that one of the two SCIVs in the associated penetration flow path and one SGT subsystem can be initiated on an isolation signal from the given Function. For the Functions with two two-out-of-two logic trip systems (Functions 1, 2, 3, and 4), this would require one trip system to have two channels, each OPERABLE or in trip. The Condition does not include the Manual Initiation Function (Function 5), since it is not assumed in any accident or transient analysis. Thus, a total loss of manual initiation capability for 24 hours (as allowed by Required Action A.1) is allowed.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
C.1.1, C.1.2, C.2.1, and C.2.2 If any Required Action and associated Completion Time of Condition A or B are not met, the ability to isolate the secondary containment and start the SGT System cannot be ensured. Therefore, further actions must be performed to ensure the ability to maintain the secondary containment function. Isolating the associated valves and starting the associated SGT subsystem (Required Actions C.1.1 and C.2.1) performs the intended function of the instrumentation and allows operations to continue.
Alternatively, declaring the associated SCIVs or SGT subsystem inoperable (Required Actions C.1.2 and C.2.2) is also acceptable since the Required Actions of the respective LCOs (LCO 3.6.4.2 and LCO 3.6.4.3) provide appropriate actions for the inoperable components.
One hour is sufficient for plant operations personnel to establish required plant conditions or to declare the associated components inoperable without challenging plant systems.
SURVEILLANCE        -----------------------------------REVIEWERS NOTE-----------------------------------
REQUIREMENTS        Certain Frequencies are based on approved topical reports. In order for a licensee to use these Frequencies, the licensee must justify the Frequencies as required by the staff SER for the topical report.
General Electric BWR/6 STS                B 3.3.6.2-7                                                      Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE REQUIREMENTS (continued)
As noted at the beginning of the SRs, the SRs for each Secondary Containment Isolation instrumentation Function are located in the SRs column of Table 3.3.6.2-1.
The Surveillances are also modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains secondary containment isolation capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Action(s) taken.
This Note is based on the reliability analysis (Refs. 3 and 4) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the SCIVs will isolate the associated penetration flow paths and the SGT System will initiate when necessary.
SR 3.3.6.2.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the indicated parameter for one instrument 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 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 instrument has drifted outside its limit.
[ The Frequency of 12 hours is based on operating experience that demonstrates channel failure is rare.
OR General Electric BWR/6 STS            B 3.3.6.2-8                                        Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
SR 3.3.6.2.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the 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 methodology.
[ The Frequency of 92 days is based upon the reliability analysis of References 3 and 4.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.3.6.2-9                                                      Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.6.2.3 Calibration of trip units provides a check of the actual trip setpoints. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.6.2-1.
There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, performance is still within the requirements of the plant safety analysis.
Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.
[ The Frequency of 92 days is based on the reliability analysis of References 3 and 4.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.2.4 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
[ 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.
General Electric BWR/6 STS                B 3.3.6.2-10                                                      Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.2.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required isolation logic for a specific channel. The system functional testing, performed on SCIVs and the SGT System in LCO 3.6.4.2 and LCO 3.6.4.3, respectively, overlaps this Surveillance to provide complete testing of the assumed safety function.
[ The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.3.6.2-11                                                      Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.6.2.6 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis.
Testing is performed only on channels where the assumed response time does not correspond to the diesel generator (DG) start time. For channels assumed to respond within the DG start time, sufficient margin exists in the [10] second start time when compared to the typical channel response time (milliseconds) so as to assure adequate response without a specific measurement test. The instrument response times must be added to the SCIV closure times to obtain the ISOLATION SYSTEM RESPONSE TIME. ISOLATION SYSTEM RESPONSE TIME acceptance criteria are included in Reference 5.
ISOLATION SYSTEM RESPONSE TIME may be verified by actual response time measurements in any series of sequential, overlapping, or total channel measurements.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
[The following Bases are applicable for plants adopting NEDO-32291-A.
However, the measurement of instrument loop response times may be excluded if the conditions of Reference 6 are satisfied.]
A Note to the Surveillance states that the radiation detectors may be excluded from ISOLATION SYSTEM RESPONSE TIME testing. This Note is necessary because of the difficulty of generating an appropriate detector input signal and because the principles of detector operation virtually ensure an instantaneous response time. Response time for radiation detector channels shall be measured from detector output or the input of the first electronic component in the channel.
[ ISOLATION SYSTEM RESPONSE TIME tests are conducted on an 18 month STAGGERED TEST BASIS. 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.3.6.2-12                                                      Rev. 5.0
 
Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [6.3].
: 2. FSAR, Chapter [15].
: 3. NEDC-31677-P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," July 1990.
: 4. NEDC-30851-P-A Supplement 2, "Technical Specifications Improvement Analysis for BWR Isolation Instrumentations Common to RPS and ECCS Instrumentation," March 1989.
: 5. FSAR, Section [7.3].
[6. NEDO-32291-A, "System Analyses for the Elimination of Selected Response Time Testing Requirements," October 1995.]
General Electric BWR/6 STS              B 3.3.6.2-13                                                      Rev. 5.0
 
RHR Containment Spray System Instrumentation B 3.3.6.3 B 3.3 INSTRUMENTATION B 3.3.6.3  Residual Heat Removal (RHR) Containment Spray System Instrumentation BASES BACKGROUND          The RHR Containment Spray System is an operating mode of the RHR System that is initiated to condense steam in the containment atmosphere. This ensures that containment pressure is maintained within its limits following a loss of coolant accident (LOCA). The RHR Containment Spray System can be initiated either automatically or manually.
The RHR Containment Spray System is automatically initiated by Reactor Vessel Water Level - Low Low Low, Level 1, Drywell Pressure - High, and Containment Pressure - High signals. Most channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a signal to the trip logic. The channels provide inputs to two trip systems; one trip system initiates one containment spray subsystem while the second trip system initiates the other containment spray subsystem (Ref. 1). For a trip system to initiate the associated subsystem, it must receive one signal from each of the following inputs: Drywell Pressure - High, Containment Pressure - High, and a System Timer. The Drywell Pressure - High and Containment Pressure - High Functions each have two channels, which are arranged in a one-out-of-two logic to provide the necessary signal. The System Timer is initiated by a one-out-of-two taken twice logic consisting of two channels each of the Reactor Vessel Water Level - Low Low Low, Level 1 and Drywell Pressure - High Functions. When the System Timer has timed out, the trip system receives the System Timer signal.
Manual initiation of the system is accomplished with the use of manual initiation push buttons. The system can be manually initiated using the manual initiation push buttons only if a Drywell Pressure - High signal is present. There is no time delay when using the manual initiation push buttons.
APPLICABLE          Operation of the RHR Containment Spray System is required to maintain SAFETY              containment pressure within design limits after a LCO, and LOCA.
ANALYSES, LCO,      Safety analyses in Reference 2 implicitly assume that sufficient and APPLICABILITY    instrumentation and controls, described below, are available to initiate the RHR Containment Spray System.
The RHR Containment Spray System instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.
General Electric BWR/6 STS              B 3.3.6.3-1                                      Rev. 5.0
 
RHR Containment Spray System Instrumentation B 3.3.6.3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The OPERABILITY of the RHR Containment Spray System instrumentation is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.6.3-1. Each Function must have the required number of OPERABLE channels with their setpoints within the specified Allowable Values. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value, where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
Allowable Values are specified for each Function in the Table. Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.
Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments, as defined by 10 CFR 50.49) are accounted for. These uncertainties are described in the setpoint methodology.
The RHR Containment Spray System instrumentation is required to be OPERABLE in MODES 1, 2, and 3, when considerable energy exists in the Reactor Coolant System and a Design Basis Accident (DBA) could cause pressurization of the primary containment. In MODES 4 and 5, the reactor is shut down, and any LOCA would not cause pressurization of the drywell or containment.
The specific Applicable Safety Analyses and LCO discussions are listed below on a Function by Function basis.
General Electric BWR/6 STS            B 3.3.6.3-2                                          Rev. 5.0
 
RHR Containment Spray System Instrumentation B 3.3.6.3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
: 1. Drywell Pressure - High High pressure in the drywell could indicate a break in the reactor coolant pressure boundary (RCPB). The RHR Containment Spray System mitigates the consequences of steam leaking from the drywell directly into containment airspace, bypassing the suppression pool.
Four Drywell Pressure - High transmitters (two per trip system) are available and are required to be OPERABLE and capable of automatically initiating the RHR Containment Spray System. This ensures that no single instrument failure can preclude the RHR containment spray function. The Drywell Pressure - High Allowable Value is chosen to be the same as the Emergency Core Cooling Systems (ECCS) Drywell Pressure - High Allowable Value (LCO 3.3.5.1, "Emergency Core Cooling Systems (ECCS) Instrumentation") since this could be indicative of a LOCA.
: 2. Containment Pressure - High High pressure in the containment could indicate a break in the RCPB.
The RHR Containment Spray System mitigates the consequences of steam leaking from the drywell directly into the containment airspace, bypassing the suppression pool.
Four Containment Pressure - High transmitters are available, but only two Containment Pressure - High transmitters (one per trip system) are required to be OPERABLE and capable of automatically initiating the RHR Containment Spray System. This ensures that no single instrument failure can preclude the RHR containment spray function.
The Containment Pressure - High Allowable Value is chosen to ensure the primary containment design pressure is not exceeded.
: 3. Reactor Vessel Water Level - Low Low Low, Level 1 Low reactor pressure vessel (RPV) water level indicates that a break of the RCPB may have occurred and the capability to maintain the primary containment pressure within design limits may be threatened. The RHR Containment Spray System mitigates the consequences of the steam leaking from the drywell directly into the containment airspace, bypassing the suppression pool.
General Electric BWR/6 STS            B 3.3.6.3-3                                      Rev. 5.0
 
RHR Containment Spray System Instrumentation B 3.3.6.3 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Reactor vessel water level signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level
                    - Low Low Low, Level 1 (two per trip system) are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the RHR containment spray function.
The Reactor Vessel Water Level - Low Low Low, Level 1 Allowable Value is chosen to be the same as the ECCS Reactor Vessel Water Level - Low Low Low, Level 1 Allowable Value (LCO 3.3.5.1) since this could be indicative of a LOCA.
: 4. System A and System B Timers The purpose of these timers is to delay automatic initiation of the RHR Containment Spray System for approximately 10 minutes after low pressure coolant injection (LPCI) initiation to give the LPCI System time to fulfill its ECCS function in response to a LOCA. The time delay is needed since the RHR Containment Spray System utilizes the same pumps as the LPCI subsystem (RHR pumps).
There are two timers, one for each subsystem, designated System A Timer and System B Timer. Since each subsystem of the RHR Containment Spray System has a timer, a single failure of a timer will cause the failure of only one RHR containment spray subsystem. The other subsystem will still be available to perform the RHR containment spray cooling function. The Allowable Value for the time delay is chosen to be long enough to allow the LPCI System to fulfill its function, but short enough to prevent containment pressure from exceeding the design limit.
: 5. Manual Initiation The Manual Initiation Function introduces signals into the RHR containment spray logic and is redundant to all automatic protective instrumentation except Drywell Pressure - High. There is no specific FSAR analysis that takes credit for this Function. It is retained for overall redundancy and diversity of the initiation Function as required by the NRC approved licensing basis. Each trip system has a manual push button, for a total of two push buttons, both of which are required to be OPERABLE.
There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.
General Electric BWR/6 STS            B 3.3.6.3-4                                      Rev. 5.0
 
RHR Containment Spray System Instrumentation B 3.3.6.3 BASES ACTIONS            -----------------------------------REVIEWERS NOTE-----------------------------------
Certain LCO Completion Times are based on approved topical reports. In order for a licensee to use the times, the licensee must justify the Completion Times as required by the staff Safety Evaluation Report (SER) for the topical report.
A Note has been provided to modify the ACTIONS related to RHR Containment Spray System instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition.
However, the Required Actions for inoperable RHR Containment Spray System instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable RHR Containment Spray System instrumentation channel.
A.1 Required Action A.1 directs entry into the appropriate Condition referenced in Table 3.3.6.3-1. The applicable Condition specified in the Table is Function dependent. Each time a channel is discovered inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition.
B.1 and B.2 Required Action B.1 is intended to ensure appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in a complete loss of automatic initiation capability for the RHR Containment Spray System. Automatic initiation capability is lost if one Function 1 channel in both trip systems is inoperable and untripped, or one Function 3 channel in both trip systems is inoperable and untripped.
In this situation (loss of automatic initiation capability), the 24 hour allowance of Required Action B.2 is not appropriate and the RHR Containment Spray System, made inoperable by RHR Containment Spray System instrumentation, must be declared inoperable within 1 hour after discovery of loss of RHR Containment Spray System initiation capability for both trip systems.
General Electric BWR/6 STS                B 3.3.6.3-5                                                      Rev. 5.0
 
RHR Containment Spray System Instrumentation B 3.3.6.3 BASES ACTIONS (continued)
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action B.1, the Completion Time only begins upon discovery that the RHR Containment Spray System cannot be automatically initiated due to inoperable, untripped channels within the same Function, as described in the paragraph above.
The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
Because of the redundancy of sensors available to provide initiation signals, an allowable out of service time of 24 hours has been shown to be acceptable (Ref. 3) to permit restoration of any inoperable channel to OPERABLE status. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition, per Required Action B.2. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore the capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g.,
as in the case where placing the inoperable channel in trip would result in an initiation), Condition D must be entered and its Required Action taken.
C.1 and C.2 Required Action C.1 is intended to ensure appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in automatic initiation capability being lost for the RHR Containment Spray System. Automatic initiation capability is lost if two Function 2 channels or two Function 4 channels are inoperable. In this situation (loss of automatic initiation capability), the 24 hour allowance of Required Action C.2 is not appropriate and the associated RHR Containment Spray System must be declared inoperable within 1 hour after discovery of loss of RHR Containment Spray System initiation capability for both trip systems. As noted, Required Action C.1 is only applicable for Functions 2 and 4. The Required Action is not applicable to Function 5 (which also requires entry into this Condition if a channel in this Function is inoperable) since it is the Manual Initiation Function and is not assumed in any FSAR accident or transient analysis. Thus, a total loss of manual initiation capability for 24 hours (as allowed by Required Action C.2) is allowed.
General Electric BWR/6 STS            B 3.3.6.3-6                                        Rev. 5.0
 
RHR Containment Spray System Instrumentation B 3.3.6.3 BASES ACTIONS (continued)
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action C.1, the Completion Time only begins upon discovery that the RHR Containment Spray System cannot be automatically initiated due to two inoperable channels within the same Function. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels.
Because of the redundancy of sensors available to provide initiation signals, an allowable out of service time of 24 hours has been shown to be acceptable (Ref. 3) to permit restoration of any inoperable channel to OPERABLE status. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition D must be entered and its Required Action taken. The Required Actions do not allow placing the channel in trip since this action could either cause the initiation or it would not necessarily result in a safe state for the channel in all events.
D.1 With any Required Action and associated Completion Time not met, the associated RHR containment spray subsystem may be incapable of performing the intended function and the RHR containment spray subsystem associated with inoperable untripped channels must be declared inoperable immediately.
SURVEILLANCE        -----------------------------------REVIEWERS NOTE-----------------------------------
REQUIREMENTS        Certain Frequencies are based on approved topical reports. In order for a licensee to use these Frequencies, the licensee must justify the Frequencies as required by the staff SER for the topical report.
As noted at the beginning of the SRs, the SRs for each RHR Containment Spray System Function are located in the SRs column of Table 3.3.6.3-1.
The Surveillances are also modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains RHR containment spray initiation capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the General Electric BWR/6 STS                B 3.3.6.3-7                                                      Rev. 5.0
 
RHR Containment Spray System Instrumentation B 3.3.6.3 BASES SURVEILLANCE REQUIREMENTS (continued) channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 3) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the RHR containment spray will initiate when necessary.
SR 3.3.6.3.1 Performance of the CHANNEL CHECK 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 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 instrument has drifted outside its limit.
[ The Frequency of 12 hours is based upon operating experience that demonstrates channel failure is rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the channels required by the LCO.
General Electric BWR/6 STS                B 3.3.6.3-8                                                      Rev. 5.0
 
RHR Containment Spray System Instrumentation B 3.3.6.3 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.6.3.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure the entire channel will perform the 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 methodology.
[ The Frequency of 92 days is based upon the reliability analysis of Reference 3.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.3.3 The calibration of trip units provides a check of the actual trip setpoints.
The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.6.3-1. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.
General Electric BWR/6 STS                B 3.3.6.3-9                                                      Rev. 5.0
 
RHR Containment Spray System Instrumentation B 3.3.6.3 BASES SURVEILLANCE REQUIREMENTS (continued)
[ The Frequency of 92 days is based upon the reliability analysis of Reference 3.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.3.4 and SR 3.3.6.3.5 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology.
CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
[ The Frequency of SR 3.3.6.3.4 is based on the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
The Frequency of SR 3.3.6.3.5 is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.3.6.3-10                                                      Rev. 5.0
 
RHR Containment Spray System Instrumentation B 3.3.6.3 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.3.6 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.6.1.7, "Residual Heat Removal (RHR) Containment Spray," overlaps this Surveillance to provide complete testing of the assumed safety function.
[ The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [ ], Figure [ ].
: 2. FSAR, Section [6.2.1.1.5].
: 3. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
General Electric BWR/6 STS                B 3.3.6.3-11                                                      Rev. 5.0
 
SPMU System Instrumentation B 3.3.6.4 B 3.3 INSTRUMENTATION B 3.3.6.4 Suppression Pool Makeup (SPMU) System Instrumentation BASES BACKGROUND          The SPMU System provides water from the upper containment pool to the suppression pool, by gravity flow, after a loss of coolant accident (LOCA) to ensure that primary containment temperature and pressure design limits are met. The SPMU System is automatically initiated by signals generated by Reactor Vessel Water Level - Low Low, Level 2; Reactor Vessel Water Level - Low Low Low, Level 1; Drywell Pressure -
High; and Suppression Pool Water Level - Low Low channels. The channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a signal to the trip logic. The channels provide inputs to two trip systems; one trip system initiates one SPMU subsystem while the second trip system initiates the other SPMU subsystem (Ref. 1). Two separate initiation logics are provided for each trip system.
One initiation logic for a trip system will initiate the associated subsystem if a LOCA signal coincident with a Suppression Pool Water Level - Low Low signal is received. The LOCA signal is received from the associated division of low pressure Emergency Core Cooling Systems (ECCS) initiation signal (i.e., two channels of Reactor Vessel Water Level - Low Low Low, Level 1 and two channels of Drywell Pressure - High are arranged in a one-out-of-two taken twice logic). Two channels of Suppression Pool Water Level - Low Low are arranged in a one-out-of-two logic, which generates the Suppression Pool Water Level - Low Low signal. The associated low pressure ECCS division's Manual Initiation push button (one per division) also supplies a signal, which manually performs the same function as the automatic LOCA signal (i.e., ECCS Manual Initiation coincident with a Suppression Pool Water Level - Low Low will initiate the trip system). Two SPMU Manual Initiation push buttons are also provided (arranged in a one-out-of-two logic), which manually perform the same function as the automatic Suppression Pool Water Level - Low Low signal.
The second initiation logic for a trip system will initiate after a time delay of approximately 30 minutes when Drywell Pressure - High (a different Function from the Drywell Pressure - High Function described above) and Reactor Vessel Water Level - Low Low, Level 2 signals are received.
Two channels of each of these two variables are arranged in a one-out-of-two taken twice logic. Once actuated, this logic starts the timer, and once the timer times out, the trip system initiates the associated SPMU subsystem. Two manual initiation push buttons (the same push buttons as the primary and secondary containment isolation manual initiation General Electric BWR/6 STS              B 3.3.6.4-1                                        Rev. 5.0
 
SPMU System Instrumentation B 3.3.6.4 BASES BACKGROUND (continued) push buttons), arranged in a two-out-of-two logic, are also provided, which perform the same function as the two variables (i.e., the manual initiation push buttons will start the timer to initiate an associated SPMU subsystem).
APPLICABLE          The SPMU System is relied upon to dump upper containment pool water SAFETY              to the suppression pool to maintain drywell horizontal vent coverage and ANALYSES, LCO,      an adequate suppression poolheat sink volume to ensure that the and APPLICABILITY  primary containment internal pressure and temperature stay within design limits (Ref. 2).
The SPMU System instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii). Certain instrumentation Functions are retained for other reasons and are described in the individual Functions discussion.
The OPERABILITY of the SPMU System instrumentation is dependent on the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.6.4-1. Each Function must have the required number of OPERABLE channels with their setpoints within the specified Allowable Value, where appropriate. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
Allowable Values are specified for each Function in the Table. Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure the setpoints do not exceed the Allowable Values between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal setpoint, but within the Allowable Value, is acceptable.
Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
General Electric BWR/6 STS            B 3.3.6.4-2                                        Rev. 5.0
 
SPMU System Instrumentation B 3.3.6.4 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The SPMU System instrumentation is required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists in the Reactor Coolant System and a DBA could cause pressurization and heatup of the primary containment. In MODES 4 and 5, the reactor is shut down; therefore, any LOCA would not cause pressurization of the drywell, and the SPMU System would not be needed to maintain suppression pool water level. Furthermore, in MODES 4 and 5, the SPMU System is not required since there is insufficient energy to heat up the suppression pool in the event of a LOCA.
The specific Applicable Safety Analyses and LCO discussions are listed below on a Function by Function basis.
: 1. Drywell Pressure - High High pressure in the drywell could indicate a break in the reactor coolant pressure boundary (RCPB). The Drywell Pressure - High is one of the Functions required to be OPERABLE and capable of initiating the SPMU System during the postulated accident. This protection is required to ensure primary containment temperature and pressure design limits are not exceeded during a LOCA. Accident analysis assumes that the suppression pool vents remain covered during a LOCA. Therefore, this signal is used to dump water from the upper containment pool into the suppression pool as assumed in the large break LOCA analysis.
High drywell pressure signals are initiated from pressure transmitters that sense the pressure at four different locations in the drywell. Four channels of Drywell Pressure - High Function (two channels per trip system) are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the SPMU System function.
The Allowable Value is chosen to be the same as the ECCS Drywell Pressure - High Allowable Value (LCO 3.3.5.1, "Emergency Core Cooling Systems (ECCS) Instrumentation"), since this could be indicative of a LOCA.
: 2. Reactor Vessel Water Level - Low Low Low, Level 1 Low reactor pressure vessel (RPV) water level indicates that a LOCA may have occurred and the capability to maintain the primary containment temperature and pressure and suppression pool level design limits may be threatened. Accident analysis assumes that the suppression pool vents remain covered during a LOCA. Therefore, this signal is used to dump water from the upper containment pool into the suppression pool as assumed in the large break LOCA analysis.
General Electric BWR/6 STS            B 3.3.6.4-3                                      Rev. 5.0
 
SPMU System Instrumentation B 3.3.6.4 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Reactor vessel water level signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of reactor vessel water level (two channels per trip system) are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the SPMU System function. The Reactor Vessel Water Level - Low Low Low, Level 1 Allowable Value is chosen to be the same as the ECCS Reactor Vessel Water Level - Low Low Low, Level 1 Allowable Value (LCO 3.3.5.1), since this could be indicative of a LOCA.
: 3. Suppression Pool Water Level - Low Low The Suppression Pool Water Level - Low Low signal provides assurance that the water level in the suppression pool will not drop below that required to keep the suppression pool vents covered for all LOCA break sizes. Accident analyses assume that the suppression pool vents remain covered during a LOCA. Therefore, the signal indicating low suppression pool water level is used to dump water from the upper containment pool into the suppression pool as assumed in the large break LOCA analysis.
Suppression pool water level signals are from four transmitters that sense pool level at four different locations (two per trip system). However, only two of the four Suppression Pool Water Level - Low Low channels (one per trip system) are required to be OPERABLE to ensure that no single instrument failure can preclude the SPMU System function due to the redundancy of the Function.
The Allowable Value is set high enough to ensure coverage of the suppression pool vents.
: 4. Drywell Pressure - High High pressure in the drywell could indicate a break in the RCPB. The Drywell Pressure - High is one of the Functions required to be OPERABLE and capable of initiating the SPMU System during the postulated accident. This protection is required to ensure primary containment temperature and pressure design limits are not exceeded during a small break LOCA.
High drywell pressure signals are initiated from pressure transmitters that sense the pressure at four different locations in the drywell. Four channels of Drywell Pressure - High Function (two channels per trip system) are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the SPMU System function.
General Electric BWR/6 STS            B 3.3.6.4-4                                      Rev. 5.0
 
SPMU System Instrumentation B 3.3.6.4 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Allowable Value is chosen to be the same as the RPS Drywell Pressure - High Allowable Value (LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation"), since this could be indicative of a LOCA.
: 5. Reactor Vessel Water Level - Low Low, Level 2 Low RPV water level indicates that a LOCA may have occurred and that the capability to maintain the primary containment temperature and pressure and suppression pool design limits during a small break LOCA may be threatened.
Reactor vessel water level signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level
                    - Low Low, Level 2 (two per trip system) are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the SPMU System function. The Allowable Value is chosen to be the same as the HPCS Reactor Vessel Water Level - Low Low, Level 2 Allowable Value (LCO 3.3.5.1), since this could be indicative of a LOCA.
: 6. Timer The SPMU System valves open on a Drywell Pressure - High and/or Reactor Vessel Water Level - Low Low, Level 2 signal after about a 30 minute timer delay, where the timer itself is started by these signals.
The minimum suppression pool volume, without an upper pool dump, is adequate to meet all heat sink requirements for 30 minutes during a small break LOCA.
There are two SPMU System timers (one per trip system). Two timers are available and are required to be OPERABLE to ensure that no single timer failure can preclude the SPMU System function. The Allowable Value is chosen to be short enough to ensure that the suppression pool will serve as an adequate heat sink during a small break LOCA.
: 7. Manual Initiation The SPMU System Manual Initiation push button channels produce signals to provide manual initiation capabilities that are redundant to the automatic protective instrumentation. The Manual Initiation Function is not assumed in any transient or accident analysis in the FSAR. However, the Function is retained for overall redundancy and diversity of the SPMU System as required by the NRC in the approved licensing basis.
General Electric BWR/6 STS            B 3.3.6.4-5                                      Rev. 5.0
 
SPMU System Instrumentation B 3.3.6.4 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Four manual initiation push buttons (two per trip system) are available and required to be OPERABLE to ensure that no single instrument failure can preclude the SPMU System function. There is no Allowable Value for this Function since the channels are mechanically actuated based solely on the position of the push buttons.
ACTIONS            -----------------------------------REVIEWERS NOTE-----------------------------------
Certain LCO Completion Times are based on approved topical reports. In order for a licensee to use the times, the licensee must justify the Completion Times as required by the staff Safety Evaluation Report (SER) for the topical report.
A Note has been provided to modify the ACTIONS related to SPMU System instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable SPMU System instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable SPMU System instrumentation channel.
A.1 Required Action A.1 directs entry into the appropriate Condition referenced in Table 3.3.6.4-1. The applicable Condition specified in the Table is Function dependent. Each time a channel is discovered inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition.
B.1 and B.2 Required Action B.1 is intended to ensure appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in a complete loss of automatic initiation capability for the SPMU System.
In this case, automatic initiation capability is lost if (a) one Function 1 channel in both trip systems is inoperable and untripped, (b) one Function 2 channel in both trip systems is inoperable and untripped, General Electric BWR/6 STS                B 3.3.6.4-6                                                      Rev. 5.0
 
SPMU System Instrumentation B 3.3.6.4 BASES ACTIONS (continued)
(c) one Function 4 channel in both trip systems is inoperable and untripped, or (d) one Function 5 channel in both trip systems is inoperable and untripped. In this situation (loss of automatic initiation capability), the 24 hour allowance of Required Action B.2 is not appropriate and the SPMU System must be declared inoperable within 1 hour after discovery of loss of SPMU initiation capability for both trip systems.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action B.1, the Completion Time only begins upon discovery that the SPMU System cannot be automatically initiated due to inoperable, untripped channels within the same Function as described in the paragraph above. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
Because of the redundancy of sensors available to provide initiation signals, an allowable out of service time of 24 hours has been shown to be acceptable (Ref. 3) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action B.2. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition D must be entered and its Required Action taken.
C.1 and C.2 Required Action C.1 is intended to ensure appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in a complete loss of automatic initiation capability for the SPMU System.
In this case, automatic initiation capability is lost if two Function 3 channels or two Function 6 channels are inoperable. In this situation (loss of automatic initiation capability), the 24 hour allowance of Required Action C.2 is not appropriate and the SPMU System must be declared inoperable within 1 hour after discovery of loss of SPMU initiation capability for both trip systems. As noted, Required Action C.1 is only applicable for Functions 3 and 6. Required Action C.1 is not applicable to Function 7 (which also requires entry into this Condition if a channel in General Electric BWR/6 STS              B 3.3.6.4-7                                        Rev. 5.0
 
SPMU System Instrumentation B 3.3.6.4 BASES ACTIONS (continued) this Function is inoperable), since it is the Manual Initiation Function and is not assumed in any FSAR accident or transient analysis. Thus, a total loss of manual initiation capability for 24 hours (as allowed by Required Action C.2) is allowed.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action C.1, the Completion Time only begins upon discovery that the SPMU System cannot be automatically initiated due to two inoperable channels within the same Function. The 1 hour Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels.
Because of the redundancy of sensors available to provide initiation signals, an allowable out of service time of 24 hours has been shown to be acceptable (Ref. 3) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition D must be entered and its Required Action taken. The Required Actions do not allow placing the channel in trip since this action could either cause the initiation or it would not necessarily result in a safe state for the channel in all events.
D.1 With any Required Action and associated Completion Time not met, the associated SPMU subsystem may be incapable of performing the intended function and the SPMU subsystem associated with inoperable, untripped channels must be declared inoperable immediately.
SURVEILLANCE        -----------------------------------REVIEWERS NOTE-----------------------------------
REQUIREMENTS        Certain Frequencies are based on approved topical reports. In order for a licensee to use these Frequencies, the licensee must justify the Frequencies as required by the staff SER for the topical report.
As noted at the beginning of the SRs, the SRs for each SPMU System Function are located in the SRs column of Table 3.3.6.4-1.
The Surveillances are also modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated General Electric BWR/6 STS                B 3.3.6.4-8                                                      Rev. 5.0
 
SPMU System Instrumentation B 3.3.6.4 BASES SURVEILLANCE REQUIREMENTS (continued)
Function maintains suppression pool makeup capability. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 3) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the SPMU will initiate when necessary.
SR 3.3.6.4.1 Performance of the CHANNEL CHECK 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 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 instrument has drifted outside its limit.
[ The Frequency of 12 hours is based upon operating experience that demonstrates channel failure is rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.3.6.4-9                                                      Rev. 5.0
 
SPMU System Instrumentation B 3.3.6.4 BASES SURVEILLANCE REQUIREMENTS (continued)
The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the required channels of the LCO.
SR 3.3.6.4.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure the entire channel will perform the 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 methodology.
[ The Frequency of 92 days is based on the reliability analysis of Reference 3.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.4.3 The calibration of trip units provides a check of the actual trip setpoints.
The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in Table 3.3.6.4-1. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint General Electric BWR/6 STS                B 3.3.6.4-10                                                      Rev. 5.0
 
SPMU System Instrumentation B 3.3.6.4 BASES SURVEILLANCE REQUIREMENTS (continued) methodology. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.
[ The Frequency of 92 days is based on the reliability analysis of Reference 3.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.4.4 and SR 3.3.6.4.5 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology.
CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
[ The Frequency of SR 3.3.6.4.4 is based on the assumption of a 92 day calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
The Frequency of SR 3.3.6.4.5 is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
OR General Electric BWR/6 STS                B 3.3.6.4-11                                                      Rev. 5.0
 
SPMU System Instrumentation B 3.3.6.4 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.4.6 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.6.2.4, "Suppression Pool Makeup (SPMU) System," overlaps this Surveillance to provide complete testing of the assumed safety function.
[ The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Figure [ ].
: 2. FSAR, Section [6.2.7.3].
: 3. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
General Electric BWR/6 STS                B 3.3.6.4-12                                                      Rev. 5.0
 
Relief and LLS Instrumentation B 3.3.6.5 B 3.3 INSTRUMENTATION B 3.3.6.5 Relief and Low-Low Set (LLS) Instrumentation BASES BACKGROUND            The safety/relief valves (S/RVs) prevent overpressurization of the nuclear steam system. Instrumentation is provided to support two modes of S/RV operation - the relief function (all valves) and the LLS function (selected valves). Refer to LCO 3.4.4, "Safety/Relief Valves (S/RVs)," and LCO 3.6.1.6, "Low-Low Set (LLS) Safety/Relief Valves (S/RVs)," for Applicability Bases for additional information of these modes of S/RV operation. This is achieved by specifying limiting safety system settings (LSSS) in terms of parameters directly monitored by the Safety/Relief valve instrumentation, as well as LCOs on other reactor system parameters, and equipment performance.
Technical Specifications are required by 10 CFR 50.36 to include LSSS for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the process variable at which a safety action is initiated, as established by the safety analysis, to ensure that an SL is not exceeded. Any automatic protection action that occurs on reaching the Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur.
                      ---------------------------------REVIEWER'S NOTE-----------------------------------
The term "Limiting Trip Setpoint" [LTSP] is generic terminology for the calculated trip setting (setpoint) value calculated by means of the plant specific setpoint methodology documented in a document controlled under 10 CFR 50.59. The term [LTSP] indicates that no additional margin has been added between the Analytical Limit and the calculated trip setting.
                      "Nominal Trip Setpoint [NTSP]" is the suggested terminology for the actual setpoint implemented in the plant surveillance procedures where margin has been added to the calculated [LTSP]. The as-found and as-left tolerances will apply to the [NTSP] implemented in the Surveillance procedures to confirm channel performance.
General Electric BWR/6 STS                  B 3.3.6.5-1                                        Rev. 5.0
 
Relief and LLS Instrumentation B 3.3.6.5 BASES BACKGROUND (continued)
Licensees are to insert the name of the document(s) controlled under 10 CFR 50.59 that contain the methodology for calculating the as-left and as-found tolerances in Note 2 of SR 3.3.6.5.2 and SR 3.3.6.5.3, for the phrase "[insert the name of a document controlled under 10 CFR 50.59 such as the Technical Requirements Manual or any document incorporated into the facility FSAR]" throughout these Bases.
Where the [LTSP] is not documented in SR 3.3.6.5.2 and 3.3.6.5.3, the plant specific location for the [LTSP] or [NTSP] must be cited in Note 2 of SR 3.3.6.5.2 and 3.3.6.5.3. The brackets indicate plant specific terms may apply, as reviewed and approved by the NRC.
The [Limiting Trip Setpoint (LTSP)] specified in SR 3.3.6.5.2 and SR 3.3.6.5.3 is a predetermined setting for a protection channel chosen to ensure automatic actuation prior to the process variable reaching the Analytical Limit and thus ensuring that the SL would not be exceeded. As such, the [LTSP] accounts for uncertainties in setting the channel (e.g., calibration), uncertainties in how the channel might actually perform (e.g., repeatability), changes in the point of action of the channel 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 [LTSP] ensures that SLs are not exceeded. Therefore the [LTSP] meets the definition of an LSSS (Ref. 1).
The Allowable Value specified in SR 3.3.6.5.2 and 3.3.6.5.3 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 surveillance interval.
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)." Relying solely on the [LTSP] to define OPERABILITY in Technical Specifications would be an overly restrictive requirement if it were applied as an OPERABILITY limit for the "as found" value of a protection channel 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 protection channel with a setting that General Electric BWR/6 STS                B 3.3.6.5-2                                                      Rev. 5.0
 
Relief and LLS Instrumentation B 3.3.6.5 BASES BACKGROUND (continued) has been found to be different from the [LTSP] due to some drift of the setting may still be OPERABLE because drift is to be expected. This expected drift would have been specifically accounted for in the setpoint methodology for calculating the [LTSP] and thus the automatic protective action would still have ensured that the SL would not be exceeded with the "as found" setting of the protection channel. Therefore, the channel would still be OPERABLE because it would have performed its safety function and the only corrective action required would be to reset the channel within the established as-left tolerance around the [LTSP] to account for further drift during the next surveillance interval. Note that, although the channel is OPERABLE under these circumstances, the trip setpoint must be left adjusted to a value within the as-left tolerance, 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 (as-found criteria).
However, there is also some point beyond which the channel may not be able to perform its function due to, for example, greater than expected drift. This value needs to be specified in the Technical Specifications in order to define OPERABILITY of the channels and is designated as the Allowable Value.
If the actual setting (as-found setpoint) of the channel is found to be conservative with respect to the Allowable Value but is beyond the as-found tolerance band, the channel is OPERABLE, but degraded. The degraded condition will be further evaluated during performance of the SR. This evaluation will consist of resetting the channel setpoint to the
[Nominal Trip Setpoint (NTSP)] (within the allowed tolerance), and evaluating the channel response. If the channel is functioning as required and is expected to pass the next surveillance, then the channel is OPERABLE and can be restored to service at the completion of the surveillance. After the surveillance is completed, the channel as-found condition will be entered into the Corrective Action Program for further evaluation.
The relief function of the S/RVs prevents overpressurization of the nuclear steam system. The LLS function of the S/RVs is designed to mitigate the effects of postulated thrust loads on the S/RV discharge lines by preventing subsequent actuations with an elevated water leg in the S/RV discharge line. It also mitigates the effects of postulated pressure loads on the containment by preventing multiple actuations in rapid succession of the S/RVs subsequent to their initial actuation.
General Electric BWR/6 STS            B 3.3.6.5-3                                      Rev. 5.0
 
Relief and LLS Instrumentation B 3.3.6.5 BASES BACKGROUND (continued)
Upon any S/RV actuation, the LLS logic assigns preset opening and reclosing setpoints to six preselected S/RVs. These setpoints are selected to override the normal relief setpoints such that the LLS S/RVs will stay open longer, thus releasing more steam (energy) to the suppression pool; hence more energy (and time) is required for repressurization and subsequent S/RV openings. The LLS logic increases the time between (or prevents) subsequent actuations to allow the high water leg created from the initial S/RV opening to return to (or fall below) its normal water level, thus reducing thrust loads from subsequent actuations to within their design limits. In addition, the LLS is designed to limit S/RV subsequent actuations to one valve, so that containment loads will also be reduced.
The relief instrumentation consists of two trip systems, with each trip system actuating one solenoid for each S/RV. There are two solenoids per S/RV, and each solenoid can open its respective S/RV. The relief mode (S/RVs and associated trip systems) is divided into three setpoint groups (the low with one S/RV, the medium with 10 S/RVs, and the high with nine S/RVs). The S/RV relief function is actuated by transmitters that monitor reactor steam dome pressure. The reactor steam dome pressure transmitters send signals to trip units whose outputs are arranged in a two-out-of-two logic for each trip system in each of three separate setpoint groups (e.g., the medium group of 10 S/RVs opens when at least one of the associated trip systems trips at its assigned setpoint). Once an S/RV has been opened, it will reclose when reactor steam dome pressure decreases below the opening pressure setpoint. This logic arrangement ensures that no single instrument failure can preclude the S/RV relief function.
The LLS logic consists of two trip systems similar to the S/RV relief function. Either trip system can actuate the LLS S/RVs by energizing the associated solenoids on the S/RV pilot valves. Each LLS trip system is enabled and sealed in upon initial S/RV actuation from the existing reactor steam dome pressure sensors of any of the normal relief setpoint groups. The reactor steam dome pressure channels used to arm LLS are arranged in a one-out-of-three taken twice logic. The reactor steam dome pressure channels that control the opening and closing of the LLS S/RVs are arranged in either a one-out-of-one or a two-out-of-two logic depending on which LLS S/RV group is being controlled. This logic arrangement ensures that no single instrument failure can preclude the LLS S/RV function. The channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a LLS or relief initiation signal, as applicable, to the initiation logic.
General Electric BWR/6 STS              B 3.3.6.5-4                                      Rev. 5.0
 
Relief and LLS Instrumentation B 3.3.6.5 BASES APPLICABLE          The relief and LLS instrumentation are designed to prevent SAFETY              overpressurization of the nuclear steam system and to ensure that the ANALYSES            containment loads remain within the primary containment design basis (Ref. 2).
Relief and LLS instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
Permissive and interlock setpoints allow the blocking of trips during plant startups, and restoration of trips when the permissive conditions are not satisfied, but they are not explicitly modeled in the Safety Analyses.
These permissives and interlocks ensure that the starting conditions are consistent with the safety analysis, before preventive or mitigating actions occur. Because these permissives or interlocks are only one of multiple conservative starting assumptions for the accident analysis, they are generally considered as nominal values without regard to measurement accuracy.
LCO                The LCO requires OPERABILITY of sufficient relief and LLS instrumentation channels to provide adequate assurance of successfully accomplishing the relief and LLS function, assuming any single instrumentation channel failure within the LLS logic. Therefore, two trip systems are required to be OPERABLE. The OPERABILITY of each trip system is dependent upon the OPERABILITY of the reactor steam dome pressure channels associated with required relief and LLS S/RVs. Each required channel shall have its setpoint conservative with respect to the specified Allowable Value.
The Allowable Values are specified in SR 3.3.6.5.2 and SR 3.3.6.5.3.
[LTSPs] and the methodologies for calculation of the as-left and as-found tolerances are described in [insert the name of a document controlled under 10 CFR 50.59 such as the Technical Requirements Manual or any document incorporated into the facility FSAR]. The [LTSPs] are selected to ensure that the setpoints remain conservative to the as-left tolerance band between CHANNEL CALIBRATIONS. After each calibration the trip setpoint shall be left within the as-left band around the [LTSP].
[LTSPs] are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytical limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytical limits, corrected for calibration, process, and some of the instrument errors. The [LTSPs] are then determined, accounting for the remaining General Electric BWR/6 STS            B 3.3.6.5-5                                        Rev. 5.0
 
Relief and LLS Instrumentation B 3.3.6.5 BASES LCO (continued) instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
Note that, although the channel is OPERABLE under these circumstances, the trip setpoint must be left adjusted to a value within the as-left tolerance, 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 (as-found criteria).
For relief, the actuating Allowable Values are based on the transient event of main steam isolation valve (MSIV) closure with an indirect scram (i.e., neutron flux). This analysis is described in Reference 3. For LLS, the actuating and reclosing Allowable Values are based on the transient event of MSIV closure with a direct scram (i.e., MSIV position switches).
This analysis is described in Reference 2.
APPLICABILITY      The relief and LLS instrumentation is required to be OPERABLE in MODES 1, 2, and 3, since considerable energy exists in the nuclear steam system and the S/RVs may be needed to provide pressure relief.
If the S/RVs are needed, then the relief and LLS functions are required to ensure that the primary containment design basis is maintained. In MODES 4 and 5, the reactor pressure is low enough that the overpressure limit cannot be approached by assumed operational transients or accidents. Thus, pressure relief, associated relief, and LLS instrumentation are not required.
ACTIONS            -----------------------------------REVIEWERS NOTE-----------------------------------
Certain LCO Completion Times are based on approved topical reports. In order for a licensee to use the times, the licensee must justify the Completion Times as required by the staff Safety Evaluation Report (SER) for the topical report.
A.1 Because the failure of any reactor steam dome pressure instrument channels [providing relief S/RV opening and LLS opening and closing pressure setpoints] in one trip system will not prevent the associated S/RV from performing its relief and LLS function, 7 days is allowed to restore a trip system to OPERABLE status. [Alternatively, a Completion General Electric BWR/6 STS                B 3.3.6.5-6                                                      Rev. 5.0
 
Relief and LLS Instrumentation B 3.3.6.5 BASES ACTIONS (continued)
Time can be determined in accordance with the Risk Informed Completion Time Program.] In this condition, the remaining OPERABLE trip system is adequate to perform the relief and LLS initiation function.
However, the overall reliability is reduced because a single failure in the OPERABLE trip system could result in a loss of relief or LLS function.
The 7 day Completion Time is considered appropriate for the relief and LLS function because of the redundancy of sensors available to provide initiation signals and the redundancy of the relief and LLS design. In addition, the probability of multiple relief or LLS instrumentation channel failures, which renders the remaining trip system inoperable, occurring together with an event requiring the relief or LLS function during the 7 day Completion Time is very low.
B.1 and B.2 If the inoperable trip system is not restored to OPERABLE status within 7 days, per Condition A, or if two trip systems are inoperable, 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 12 hours and to MODE 4 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        -----------------------------------REVIEWERS NOTE-----------------------------------
REQUIREMENTS        Certain Frequencies are based on approved topical reports. In order for a licensee to use these Frequencies, the licensee must justify the Frequencies as required by the staff SER for the topical report.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Notes 1 and 2 are applied to the setpoint verification Surveillances for all Relief and LLS Instrumentation Functions unless one or more of the following exclusions apply:
: 1. Manual actuation circuits, automatic actuation logic circuits or instrument functions that derive input from contacts which have no associated sensor or adjustable device, e.g., limit switches, breaker position switches, manual actuation switches, float switches, proximity detectors, etc. are excluded. In addition, those permissives and interlocks that derive input from a sensor or adjustable device that is tested as part of another TS function are excluded.
General Electric BWR/6 STS                B 3.3.6.5-7                                                      Rev. 5.0
 
Relief and LLS Instrumentation B 3.3.6.5 BASES SURVEILLANCE REQUIREMENTS (continued)
: 2. Settings associated with safety relief valves are excluded. The performance of these components is already controlled (i.e., trended with as-left and as-found limits) under the ASME Code for Operation and Maintenance of Nuclear Power Plants testing program.
: 3. Functions and Surveillance Requirements which test only digital components are normally excluded. There is no expected change in result between SR performances for these components. Where separate as-left and as-found tolerance is established for digital component SRs, the requirements would apply.
The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains relief or LLS initiation capability, as applicable. Upon completion of the Surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 4) assumption of the average time required to perform channel surveillance. That analysis demonstrated the 6 hour testing allowance does not significantly reduce the probability that the relief and LLS valves will initiate when necessary.
SR 3.3.6.5.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the 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 methodology.
[ The Frequency of 92 days is based on the reliability analysis of Reference 4.
OR General Electric BWR/6 STS                B 3.3.6.5-8                                                      Rev. 5.0
 
Relief and LLS Instrumentation B 3.3.6.5 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.5.2 The calibration of trip units provides a check of the actual trip setpoints.
The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value specified in SR 3.3.6.5.3. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.
[ The Frequency of 92 days is based on the reliability analysis of Reference 4.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.6.5.2 is modified by two Notes. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure General Electric BWR/6 STS                B 3.3.6.5-9                                                      Rev. 5.0
 
Relief and LLS Instrumentation B 3.3.6.5 BASES SURVEILLANCE REQUIREMENTS (continued) confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the [LTSP] is used in the plant surveillance procedures [NTSP], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP], then the channel shall be declared inoperable.
The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
SR 3.3.6.5.3 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
[ 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.3.6.5-10                                                      Rev. 5.0
 
Relief and LLS Instrumentation B 3.3.6.5 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.6.5.3 is modified by two Notes. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value. Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition. The second Note requires that the as-left setting for the channel be within the as-left tolerance of the [LTSP]. Where a setpoint more conservative than the [LTSP] is used in the plant surveillance procedures [NTSP], the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the [LTSP], then the channel shall be declared inoperable.
The second Note also requires that [LTSP] and the methodologies for calculating the as-left and the as-found tolerances be in [insert the facility FSAR reference or the name of any document incorporated into the facility FSAR by reference].
SR 3.3.6.5.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specific channel. The system functional testing performed for S/RVs in LCO 3.4.4 and LCO 3.6.1.6 overlaps this Surveillance to provide complete testing of the assumed safety function. [ The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS            B 3.3.6.5-11                                      Rev. 5.0
 
Relief and LLS Instrumentation B 3.3.6.5 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. Regulatory Guide 1.105, "Setpoints for Safety-Related Instrumentation," Revision 3.
: 2. FSAR, Section [5.2.2].
: 3. FSAR, Appendix 5A.
: 4. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
General Electric BWR/6 STS              B 3.3.6.5-12                                                      Rev. 5.0
 
[CRFA] System Instrumentation B 3.3.7.1 B 3.3 INSTRUMENTATION B 3.3.7.1  [Control Room Fresh Air (CRFA)] System Instrumentation BASES BACKGROUND          The [CRFA] System is designed to provide a radiologically controlled environment to ensure the habitability of the control room for the safety of control room operators under all plant conditions. Two independent
[CRFA] subsystems are each capable of fulfilling the stated safety function. The instrumentation and controls for the [CRFA] System automatically initiate action to isolate or pressurize the main control room (MCR) to minimize the consequences of radioactive material in the control room environment.
In the event of a loss of coolant accident (LOCA) signal (Reactor Vessel Water Level - Low Low, Level 2 or Drywell Pressure - High) or Control Room Ventilation Radiation Monitor signal, the [CRFA] System is automatically started in the isolation mode. The MCR air is then recirculated through the charcoal filter, and sufficient outside air is drawn in through the normal intake to keep the MCR slightly pressurized with respect to the turbine building.
The [CRFA] System instrumentation has two trip systems: one trip system initiates one [CRFA] subsystem, while the second trip system initiates the other [CRFA] subsystem (Ref. 1). Each trip system receives input from the Functions listed above. The Functions are arranged as follows for each trip system. The Reactor Vessel Water Level - Low Low, Level 2 and Drywell Pressure - High are arranged together in a one-out-of-two taken twice logic. The Control Room Ventilation Radiation Monitors are arranged in a two-out-of-two logic. The channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a [CRFA] System initiation signal to the initiation logic.
APPLICABLE          The ability of the [CRFA] System to maintain the habitability of the MCR is SAFETY              explicitly assumed for certain accidents as discussed in the FSAR safety ANALYSES, LCO,      analyses (Refs. 2 and 3). [CRFA] System operation ensures that the and APPLICABILITY    radiation exposure of control room personnel, through the duration of any one of the postulated accidents, does not exceed the limits set by GDC 19 of 10 CFR 50, Appendix A.
[CRFA] System instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS              B 3.3.7.1-1                                        Rev. 5.0
 
[CRFA] System Instrumentation B 3.3.7.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The OPERABILITY of the [CRFA] System instrumentation is dependent upon the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.7.1-1. Each Function must have a required number of OPERABLE channels, with their setpoints within the specified Allowable Values, where appropriate. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
Allowable Values are specified for each [CRFA] System Function specified in the Table. Nominal trip setpoints are specified in the setpoint calculations. These nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between successive CHANNEL CALIBRATIONS. Operation with a trip setpoint that is less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.
Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined, accounting for the remaining instrument errors (e.g., drift). The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
: 1. Reactor Vessel Water Level - Low Low, Level 2 Low reactor pressure vessel (RPV) water level indicates that the capability to cool the fuel may be threatened. A low reactor vessel water level could indicate a LOCA, and will automatically initiate the [CRFA]
System, since this could be a precursor to a potential radiation release and subsequent radiation exposure to control room personnel.
General Electric BWR/6 STS            B 3.3.7.1-2                                        Rev. 5.0
 
[CRFA] System Instrumentation B 3.3.7.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
Reactor Vessel Water Level - Low Low, Level 2 signals are initiated from four level transmitters that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level - Low Low, Level 2 Function are available (two channels per trip system) and are required to be OPERABLE to ensure that no single instrument failure can preclude [CRFA] System initiation.
The Allowable Value for the Reactor Vessel Water Level - Low Low, Level 2 is chosen to be the same as the Secondary Containment Isolation Reactor Vessel Water Level - Low Low, Level 2 Allowable Value (LCO 3.3.6.2).
The Reactor Vessel Water Level - Low Low, Level 2 Function is required to be OPERABLE in MODES 1, 2, and 3 to ensure that the control room personnel are protected. In MODES 4 and 5, the Control Room Ventilation Radiation Monitor Function provides adequate protection.
: 2. Drywell Pressure - High High pressure in the drywell could indicate a break in the reactor coolant pressure boundary (RCPB). A high drywell pressure signal could indicate a LOCA and will automatically initiate the [CRFA] System, since this could be a precursor to a potential radiation release and subsequent radiation exposure to control room personnel.
Drywell Pressure - High signals are initiated from four pressure transmitters that sense drywell pressure. Four channels of Drywell Pressure - High Function are available (two channels per trip system) and are required to be OPERABLE to ensure that no single instrument failure can preclude [CRFA] System initiation.
The Drywell Pressure - High Allowable Value was chosen to be the same as the Secondary Containment Isolation Drywell Pressure - High Allowable Value (LCO 3.3.6.2).
The Drywell Pressure - High Function is required to be OPERABLE in MODES 1, 2, and 3 to ensure that control room personnel are protected during a LOCA. In MODES 4 and 5, the Drywell Pressure - High Function is not required since there is insufficient energy in the reactor to pressurize the drywell to the Drywell Pressure - High setpoint.
General Electric BWR/6 STS            B 3.3.7.1-3                                        Rev. 5.0
 
[CRFA] System Instrumentation B 3.3.7.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
: 3. Control Room Ventilation Radiation Monitors The Control Room Ventilation Radiation Monitors measure radiation levels exterior to the inlet ducting of the MCR. A high radiation level may pose a threat to MCR personnel; thus, a detector indicating this condition automatically signals initiation of the [CRFA] System.
The Control Room Ventilation Radiation Monitors Function consists of four independent monitors. Four channels of Control Room Ventilation Radiation Monitors are available and are required to be OPERABLE to ensure that no single instrument failure can preclude [CRFA] System initiation. The Allowable Value was selected to ensure protection of the control room personnel.
The Control Room Ventilation Radiation Monitors Function is required to be OPERABLE in MODES 1, 2, and 3, and during movement of [recently]
irradiated fuel in the secondary containment to ensure that control room personnel are protected during a LOCA or a fuel handling event [involving handling recently irradiated fuel]. During MODES 4 and 5, when these specified conditions are not in progress, the probability of a LOCA is low; thus, the Function is not required. [Also due to radioactive decay, this Function is only required to initiate the [CRFA] System during 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).]
ACTIONS            -----------------------------------REVIEWERS NOTE-----------------------------------
Certain LCO Completion Times are based on approved topical reports. In order for a licensee to use these times, the licensee must justify the Completion Times as required by the staff Safety Evaluation Report (SER) for the topical report.
A Note has been provided to modify the ACTIONS related to [CRFA]
System instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable [CRFA] System instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable [CRFA] System instrumentation channel.
General Electric BWR/6 STS                B 3.3.7.1-4                                                      Rev. 5.0
 
[CRFA] System Instrumentation B 3.3.7.1 BASES ACTIONS (continued)
A.1 Required Action A.1 directs entry into the appropriate Condition referenced in Table 3.3.7.1-1. The applicable Condition specified in the Table is Function dependent. Each time an inoperable channel is discovered, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition.
B.1 and B.2 Because of the diversity of sensors available to provide initiation signals and the redundancy of the [CRFA] System design, an allowable out of service time of 24 hours has 25-been shown to be acceptable (Refs. 4 and 5) to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the associated Function is still maintaining [CRFA] System initiation capability. A Function is considered to be maintaining [CRFA] System initiation capability when sufficient channels are OPERABLE or in trip, such that one trip system will generate an initiation signal from the given Function on a valid signal. This would require one trip system to have two channels, each OPERABLE or in trip. In this situation (loss of [CRFA]
System initiation capability), the 24 hour allowance of Required Action B.2 is not appropriate. If the Function is not maintaining [CRFA] System initiation capability, the [CRFA] System must be declared inoperable within 1 hour of discovery of loss of [CRFA] System initiation capability in both trip systems. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action B.2. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition E must be entered and its Required Actions taken.
C.1 and C.2 Because of the diversity of sensors available to provide initiation signals and the redundancy of the [CRFA] System design, an allowable out of service time of 12 hours has been shown to be acceptable (Refs. 4 and 6) to permit restoration of any inoperable channel to OPERABLE status.
However, this out of service time is only acceptable provided the associated Function is still maintaining [CRFA] System initiation General Electric BWR/6 STS              B 3.3.7.1-5                                        Rev. 5.0
 
[CRFA] System Instrumentation B 3.3.7.1 BASES ACTIONS (continued) capability. A Function is considered to be maintaining [CRFA] System initiation capability when sufficient channels are OPERABLE or in trip, such that one trip system will generate an initiation signal from the given Function on a valid signal. This would require one trip system to have two channels, each OPERABLE or in trip. In this situation (loss of [CRFA]
System initiation capability), the 12 hour allowance of Required Action C.2 is not appropriate. If the Function is not maintaining [CRFA]
System initiation capability, the [CRFA] System must be declared inoperable within 1 hour of discovery of loss of [CRFA] System initiation capability in both trip systems. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition, per Required Action C.2.
Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue. Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition E must be entered and its Required Actions taken.
D.1 and D.2 Because of the diversity of sensors available to provide initiation signals and the redundancy of the [CRFA] System design, an allowable out of service time of 6 hours is provided to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the associated Function is still maintaining [CRFA]
System initiation capability. A Function is considered to be maintaining
[CRFA] System initiation capability when sufficient channels are OPERABLE or in trip, such that one trip system will generate an initiation signal from the given Function on a valid signal. This would require one trip system to have two channels, each OPERABLE or in trip. In this situation (loss of [CRFA] System initiation capability), the 6 hour allowance of Required Action D.2 is not appropriate. If the Function is not maintaining [CRFA] System initiation capability, the [CRFA] System must be declared inoperable within 1 hour of discovery of loss of [CRFA]
System initiation capability in both trip systems. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition, per Required Action D.2. Placing the inoperable channel in trip performs the intended function of the channel (starts the associated [CRFA] subsystem in the isolation mode). Alternately, if it is not desired to place the channel in trip (e.g., as in the case where it is not desired to start the subsystem),
Condition E must be entered and its Required Actions taken.
General Electric BWR/6 STS              B 3.3.7.1-6                                        Rev. 5.0
 
[CRFA] System Instrumentation B 3.3.7.1 BASES ACTIONS (continued)
The 6 hour Completion Time is based on the consideration that this Function provides the primary signal to start the [CRFA] System, thus ensuring that the design basis of the [CRFA] System is met.
E.1 and E.2 With any Required Action and associated Completion Time not met, the associated [CRFA] subsystem must be placed in the isolation mode of operation (Required Action D.1) to ensure that control room personnel will be protected in the event of a Design Basis Accident. The method used to place the [CRFA] subsystem in operation must provide for automatically reinitiating the subsystem upon restoration of power following a loss of power to the [CRFA] subsystem(s). As noted, if the toxic gas protection instrumentation is concurrently inoperable, then the
[CRFA] subsystem shall be placed in the toxic gas mode instead of the isolation mode. This provides proper protection of the control room personnel if both toxic gas instrumentation (not required by Technical Specifications) and radiation instrumentation are concurrently inoperable.
Alternately, if it is not desired to start the subsystem, the [CRFA]
subsystem associated with inoperable, untripped channels must be declared inoperable within 1 hour.
The 1 hour Completion Time is intended to allow the operator time to place the [CRFA] subsystem in operation. The 1 hour Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels, or for placing the associated [CRFA] subsystem in operation.
SURVEILLANCE        -----------------------------------REVIEWERS NOTE-----------------------------------
REQUIREMENTS        Certain Frequencies are based on approved topical reports. In order for a licensee to use these Frequencies, the licensee must justify the Frequencies as required by the staff SER for the topical report.
As noted at the beginning of the SRs, the SRs for each [CRFA] System Instrumentation Function are located in the SRs column of Table 3.3.7.1-1.
The Surveillances are also modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours, provided the associated Function maintains [CRFA] System initiation capability. Upon completion of the surveillance, or expiration of the 6 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition General Electric BWR/6 STS                B 3.3.7.1-7                                                      Rev. 5.0
 
[CRFA] System Instrumentation B 3.3.7.1 BASES SURVEILLANCE REQUIREMENTS (continued) entered and Required Actions taken. This Note is based on the reliability analysis (Refs. 4, 5, and 6) assumption of the average time required to perform channel surveillance. That analysis demonstrated that the 6 hour testing allowance does not significantly reduce the probability that the
[CRFA] System will initiate when necessary.
SR 3.3.7.1.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the indicated parameter for one instrument 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 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 instrument has drifted outside its limit.
[ The Frequency of 12 hours is based upon operating experience that demonstrates channel failure is rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
The CHANNEL CHECK supplements less formal, but more frequent, checks of channel status during normal operational use of the displays associated with channels required by the LCO.
General Electric BWR/6 STS                B 3.3.7.1-8                                                      Rev. 5.0
 
[CRFA] System Instrumentation B 3.3.7.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.7.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the 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 methodology.
[ The Frequency of 92 days is based on the reliability analyses of References 4, 5, and 6.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.7.1.3 The calibration of trip units provides a check of the actual trip setpoints.
Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology. The channel must be declared inoperable if the trip setting is discovered to be less conservative than the Allowable Value. If the trip setting is discovered to be less conservative than accounted for in the appropriate setpoint methodology, but is not beyond the Allowable Value, the channel performance is still within the requirements of the plant safety analysis. Under these conditions, the setpoint must be readjusted to be equal to or more conservative than accounted for in the appropriate setpoint methodology.
General Electric BWR/6 STS                B 3.3.7.1-9                                                      Rev. 5.0
 
[CRFA] System Instrumentation B 3.3.7.1 BASES SURVEILLANCE REQUIREMENTS (continued)
[ The Frequency of 92 days is based on the reliability analyses of References 4, 5, and 6.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.7.1.4 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with those established by the setpoint methodology. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
[ The Frequency is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.3.7.1-10                                                      Rev. 5.0
 
[CRFA] System Instrumentation B 3.3.7.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.3.7.1.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic for a specific channel. The system functional testing performed in LCO 3.7.3, "Control Room Fresh Air ([CRFA]) System," overlaps this Surveillance to provide complete testing of the assumed safety function.
[ The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Figure [ ].
: 2. FSAR, Section [6.4].
: 3. FSAR, Chapter [15].
: 4. GENE-770-06-1, "Bases for Changes to Surveillance Test Intervals and Allowed Out-of-Service Times for Selected Instrumentation Technical Specifications," February 1991.
: 5. NEDC-31677P-A, "Technical Specification Improvement Analysis for BWR Isolation Actuation Instrumentation," July 1990.
: 6. NEDC-30851P-A, Supplement 2, "Technical Specification Improvement Analysis for BWR Isolation Instrumentation Common to RPS and ECCS Instrumentation," March 1989.
General Electric BWR/6 STS                B 3.3.7.1-11                                                      Rev. 5.0
 
LOP Instrumentation B 3.3.8.1 B 3.3 INSTRUMENTATION B 3.3.8.1 Loss of Power (LOP) Instrumentation BASES BACKGROUND          Successful operation of the required safety functions of the Emergency Core Cooling Systems (ECCS) is dependent upon the availability of adequate power sources for energizing the various components such as pump motors, motor operated valves, and the associated control components. The LOP instrumentation monitors the 4.16 kV emergency buses. Offsite power is the preferred source of power for the 4.16 kV emergency buses. If the monitors determine that insufficient power is available, the buses are disconnected from the offsite power sources and connected to the onsite diesel generator (DG) power sources.
Each 4.16 kV emergency bus has its own independent LOP instrumentation and associated trip logic. The voltage for the Division 1, 2, and 3 buses is monitored at two levels, which can be considered as two different undervoltage functions: loss of voltage and degraded voltage.
The LOP instrumentation comprises three Functions for Divisions 1 and 2, and two Functions for Division 3, which represent different voltage levels that cause various bus transfers and disconnects. Each Function is monitored by four undervoltage relays for each emergency bus whose outputs are arranged in a one-out-of-two taken twice logic configuration (Ref. 1). The channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a LOP trip signal to the trip logic.
APPLICABLE          The LOP instrumentation is required for the Engineered Safety Features SAFETY              to function in any accident with a loss of offsite power. The required ANALYSES, LCO,      channels of LOP instrumentation ensure that the ECCS and other and APPLICABILITY    assumed systems powered from the DGs provide plant protection in the event of any of the analyzed accidents in References 2, 3, and 4 in which a loss of offsite power is assumed. The initiation of the DGs on loss of offsite power, and subsequent initiation of the ECCS, ensure that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.
Accident analyses credit the loading of the DG based on the loss of offsite power during a loss of coolant accident (LOCA). The diesel starting and loading times have been included in the delay time associated with each safety system component requiring DG supplied power following a loss of offsite power.
The LOP instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS              B 3.3.8.1-1                                      Rev. 5.0
 
LOP Instrumentation B 3.3.8.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The OPERABILITY of the LOP instrumentation is dependent upon the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.8.1-1. Each Function must have a required number of OPERABLE channels per 4.16 kV emergency bus, with their setpoints within the specified Allowable Values. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
The Allowable Values are specified for each Function in the Table.
Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoint does not exceed the Allowable Value between CHANNEL CALIBRATIONS.
Operation with a trip setpoint less conservative than the nominal trip setpoint, but within the Allowable Value, is acceptable. Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g.,
degraded voltage), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined accounting for the remaining instrument errors (e.g., drift).
The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.
4.16 kV Emergency Bus Undervoltage 1.a, 1.b, 2.a, 2.b. 4.16 kV Emergency Bus Undervoltage (Loss of Voltage)
Loss of voltage on a 4.16 kV emergency bus indicates that offsite power may be completely lost to the respective emergency bus and is unable to supply sufficient power for proper operation of the applicable equipment.
Therefore, the power supply to the bus is transferred from offsite power to DG power when the voltage on the bus drops below the Loss of Voltage Function Allowable Values (loss of voltage with a short time delay). This ensures that adequate power will be available to the required equipment.
General Electric BWR/6 STS            B 3.3.8.1-2                                      Rev. 5.0
 
LOP Instrumentation B 3.3.8.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
The Bus Undervoltage Allowable Values are low enough to prevent inadvertent power supply transfer, but high enough to ensure power is available to the required equipment. The Time Delay Allowable Values are long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that power is available to the required equipment.
Four channels of 4.16 kV Emergency Bus Undervoltage (Loss of Voltage)
Function per associated emergency bus are only required to be OPERABLE when the associated DG is required to be OPERABLE to ensure that no single instrument failure can preclude the DG function.
(Four channels input to each of the three DGs.) Refer to LCO 3.8.1, "AC Sources - Operating" for Applicability Bases for the DGs.
1.c, 1.d, 2.c, 2.d, 2.e. 4.16 kV Emergency Bus Undervoltage (Degraded Voltage)
A reduced voltage condition on a 4.16 kV emergency bus indicates that while offsite power may not be completely lost to the respective emergency bus, power may be insufficient for starting large motors without risking damage to the motors that could disable the ECCS function. Therefore, power supply to the bus is transferred from offsite power to onsite DG power when the voltage on the bus drops below the Degraded Voltage Function Allowable Values (degraded voltage with a time delay). This ensures that adequate power will be available to the required equipment.
The Bus Undervoltage Allowable Values are low enough to prevent inadvertent power supply transfer, but high enough to ensure that sufficient power is available to the required equipment. The Time Delay Allowable Values are long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that sufficient power is available to the required equipment.
Four channels of 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) Function per associated emergency bus are only required to be OPERABLE when the associated DG is required to be OPERABLE to ensure that no single instrument failure can preclude the DG function.
(Four channels input to each of the three DGs.) Refer to LCO 3.8.1 for Applicability Bases for the DGs.
General Electric BWR/6 STS            B 3.3.8.1-3                                    Rev. 5.0
 
LOP Instrumentation B 3.3.8.1 BASES ACTIONS            A Note has been provided to modify the ACTIONS related to LOP instrumentation channels. Section 1.3, Completion Times, specifies that once a Condition has been entered, subsequent divisions, subsystems, components, or variables expressed in the Condition discovered to be inoperable or not within limits will not result in separate entry into the Condition. Section 1.3 also specifies that Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable LOP instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable LOP instrumentation channel.
A.1 With one or more channels of a Function inoperable, the Function may not be capable of performing the intended function. Therefore, only 1 hour is allowed to restore the inoperable channel to OPERABLE status.
[Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action A.1. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.
Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the channel in trip would result in a DG initiation),
Condition B must be entered and its Required Action taken.
The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.
B.1 If any Required Action and associated Completion Time is not met, the associated Function may not be capable of performing the intended function. Therefore, the associated DG(s) are declared inoperable immediately. This requires entry into applicable Conditions and Required Actions of LCO 3.8.1 which provide appropriate actions for the inoperable DG(s).
General Electric BWR/6 STS              B 3.3.8.1-4                                        Rev. 5.0
 
LOP Instrumentation B 3.3.8.1 BASES SURVEILLANCE        As noted at the beginning of the SRs, the SRs for each LOP REQUIREMENTS        Instrumentation Function are located in the SRs column of Table 3.3.8.1-1.
The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 2 hours provided the associated Function maintains DG initiation capability. Upon completion of the Surveillance, or expiration of the 2 hour allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.
SR 3.3.8.1.1 Performance of the CHANNEL CHECK 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 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 instrument has drifted outside its limit.
[ The Frequency of 12 hours is based on operating experience that demonstrates channel failure is rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.3.8.1-5                                                      Rev. 5.0
 
LOP Instrumentation B 3.3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The CHANNEL CHECK supplements less formal, but more frequent, checks of channels during normal operational use of the displays associated with the required channels of the LCO.
SR 3.3.8.1.2 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the 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 methodology.
[ The Frequency of 31 days is based on plant operating experience with regard to channel OPERABILITY and drift that demonstrates that failure of more than one channel of a given Function in any 31 day interval is rare.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.8.1.3 A CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies the channel responds to the measured parameter within the necessary range and accuracy. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with General Electric BWR/6 STS                B 3.3.8.1-6                                                      Rev. 5.0
 
LOP Instrumentation B 3.3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) those established by the setpoint methodology. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.
[ The Frequency is based on the assumption of an 18 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.8.1.4 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specific channel. The system functional testing performed in LCO 3.8.1 overlaps this Surveillance to provide complete testing of the assumed safety functions.
[ 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 18 month Frequency.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.3.8.1-7                                                      Rev. 5.0
 
LOP Instrumentation B 3.3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Figure [ ].
: 2. FSAR, Section [5.2].
: 3. FSAR, Section [6.3].
: 4. FSAR, Chapter [15].
General Electric BWR/6 STS                B 3.3.8.1-8                                                      Rev. 5.0
 
RPS Electric Power Monitoring B 3.3.8.2 B 3.3 INSTRUMENTATION B 3.3.8.2  Reactor Protection System (RPS) Electric Power Monitoring BASES BACKGROUND          The RPS Electric Power Monitoring System is provided to isolate the RPS bus from the motor generator (MG) set or an alternate power supply in the event of overvoltage, undervoltage, or underfrequency. This system protects the loads connected to the RPS bus against unacceptable voltage and frequency conditions (Ref. 1) and forms an important part of the primary success path for the essential safety circuits. Some of the essential equipment powered from the RPS buses includes the RPS logic, scram solenoids, and various valve isolation logic.
The RPS Electric Power Monitoring assembly will detect any abnormal high or low voltage or low frequency condition in the outputs of the two MG sets or the alternate power supply and will de-energize its respective RPS bus, thereby causing all safety functions normally powered by this bus to de-energize.
In the event of failure of an RPS Electric Power Monitoring System (e.g.,
both inseries electric power monitoring assemblies), the RPS loads may experience significant effects from the unregulated power supply.
Deviation from the nominal conditions can potentially cause damage to the scram solenoids and other Class 1E devices.
In the event of a low voltage condition, for an extended period of time, the scram solenoids can chatter and potentially lose their pneumatic control capability, resulting in a loss of primary scram action.
In the event of an overvoltage condition, the RPS logic relays and scram solenoids, as well as the main steam isolation valve solenoids, may experience a voltage higher than their design voltage. If the overvoltage condition persists for an extended time period, it may cause equipment degradation and the loss of plant safety function.
Two redundant Class 1E circuit breakers are connected in series between each RPS bus and its MG set, and between each RPS bus and its alternate power supply. Each of these circuit breakers has an associated independent set of Class 1E overvoltage, undervoltage, and underfrequency sensing logic. Together, a circuit breaker and its sensing logic constitute an electric power monitoring assembly. If the output of the MG set exceeds the predetermined limits of overvoltage, undervoltage, or underfrequency, a trip coil driven by this logic circuitry opens the circuit breaker, which removes the associated power supply from service.
General Electric BWR/6 STS              B 3.3.8.2-1                                      Rev. 5.0
 
RPS Electric Power Monitoring B 3.3.8.2 BASES APPLICABLE          RPS electric power monitoring is necessary to meet the assumptions of SAFETY              the safety analyses by ensuring that the equipment powered from the ANALYSES            RPS buses can perform its intended function. RPS electric power monitoring provides protection to the RPS and other systems that receive power from the RPS buses, by disconnecting the RPS from the power supply under specified conditions that could damage the RPS bus powered equipment.
RPS electric power monitoring satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                The OPERABILITY of each RPS electric power monitoring assembly is dependent upon the OPERABILITY of the overvoltage, undervoltage, and underfrequency logic, as well as the OPERABILITY of the associated circuit breaker. Two electric power monitoring assemblies are required to be OPERABLE for each inservice power supply. This provides redundant protection against any abnormal voltage or frequency conditions to ensure that no single RPS electric power monitoring assembly failure can preclude the function of RPS bus powered components. Each inservice electric power monitoring assembly's trip logic setpoints are required to be within the specific Allowable Value. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions.
Allowable Values are specified for each RPS electric power monitoring assembly trip logic (refer to SR 3.3.8.2.2). Nominal trip setpoints are specified in the setpoint calculations. The nominal setpoints are selected to ensure that the setpoints do not exceed the Allowable Value between CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable. A channel is inoperable if its actual trip setpoint is not within its required Allowable Value. Trip setpoints are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g.,
overvoltage), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analytic limits are derived from the limiting values of the process parameters obtained from the safety analysis. The Allowable Values are derived from the analytic limits, corrected for calibration, process, and some of the instrument errors. The trip setpoints are then determined, accounting for the remaining instrument errors (e.g., drift).
The trip setpoints derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.
General Electric BWR/6 STS            B 3.3.8.2-2                                        Rev. 5.0
 
RPS Electric Power Monitoring B 3.3.8.2 BASES LCO (continued)
The Allowable Values for the instrument settings are based on the RPS providing  57 Hz, 120 V +/- 10% (to all equipment), and 115 V +/- 10 V (to scram and MSIV solenoids). The most limiting voltage requirement and associated line losses determine the settings of the electric power monitoring instrument channels. The settings are calculated based on the loads on the buses and RPS MG set or alternate power supply being 120 VAC and 60 Hz.
APPLICABILITY      The operation of the RPS electric power monitoring assemblies is essential to disconnect the RPS bus powered components from the MG set or alternate power supply during abnormal voltage or frequency conditions. Since the degradation of a nonclass 1E source supplying power to the RPS bus can occur as a result of any random single failure, the OPERABILITY of the RPS electric power monitoring assemblies is required when the RPS bus powered components are required to be OPERABLE. This results in the RPS Electric Power Monitoring System OPERABILITY being required in MODES 1, 2, and 3, and MODES 4 and 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies or with both residual heat removal (RHR) shutdown cooling isolation valves open.
ACTIONS            A.1 If one RPS electric power monitoring assembly for an inservice power supply (MG set or alternate) is inoperable, or one RPS electric power monitoring assembly on each inservice power supply is inoperable, the OPERABLE assembly will still provide protection to the RPS bus powered components under degraded voltage or frequency conditions. However, the reliability and redundancy of the RPS Electric Power Monitoring System are reduced and only a limited time (72 hours) is allowed to restore the inoperable assembly(s) to OPERABLE status. If the inoperable assembly(s) cannot be restored to OPERABLE status, the associated power supply must be removed from service (Required Action A.1). This places the RPS bus in a safe condition. An alternate power supply with OPERABLE power monitoring assemblies may then be used to power the RPS bus.
The 72 hour Completion Time takes into account the remaining OPERABLE electric power monitoring assembly and the low probability of an event requiring RPS Electric Power Monitoring protection occurring during this period. It allows time for plant operations personnel to take corrective actions or to place the plant in the required condition in an orderly manner and without challenging plant systems.
General Electric BWR/6 STS            B 3.3.8.2-3                                      Rev. 5.0
 
RPS Electric Power Monitoring B 3.3.8.2 BASES ACTIONS (continued)
Alternatively, if it is not desired to remove the power supply(s) from service (e.g., as in the case where removing the power supply(s) from service would result in a scram or isolation), Condition C or D, as applicable, must be entered and its Required Actions taken.
B.1 If both power monitoring assemblies for an inservice power supply (MG set or alternate) are inoperable, or both power monitoring assemblies in each inservice power supply are inoperable, the system protective function is lost. In this condition, 1 hour is allowed to restore one assembly to OPERABLE status for each inservice power supply. If one inoperable assembly for each inservice power supply cannot be restored to OPERABLE status, the associated power supplies must be removed from service within 1 hour (Required Action B.1). An alternate power supply with OPERABLE assemblies may then be used to power one RPS bus. The 1 hour Completion Time is sufficient for the plant operations personnel to take corrective actions and is acceptable because it minimizes risk while allowing time for restoration or removal from service of the electric power monitoring assemblies.
Alternately, if it is not desired to remove the power supply(s) from service (e.g., as in the case where removing the power supply(s) from service would result in a scram or isolation), Condition C or D, as applicable, must be entered and its Required Actions taken.
C.1 and C.2
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [Licensee] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [Licensee] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
If any Required Action and associated Completion Time of Condition A or B are not met in MODE 1, 2, or 3, the plant must be brought to a General Electric BWR/6 STS                B 3.3.8.2-4                                                      Rev. 5.0
 
RPS Electric Power Monitoring B 3.3.8.2 BASES ACTIONS (continued)
MODE in which overall plant risk is minimized. The plant shutdown is accomplished by placing the plant in MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action C.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is 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, D.2.1, and D.2.2 If any Required Action and associated Completion Time of Condition A or B are not met in MODE 4 or 5, with any control rod withdrawn from a core cell containing one or more fuel assemblies or with both RHR shutdown cooling valves open, the operator must immediately initiate action to fully insert all insertable control rods in core cells containing one or more fuel assemblies (Required Action D.1). This Required Action results in the least reactive condition for the reactor core and ensures that the safety function of the RPS (e.g., scram of control rods) is not required.
In addition, action must be immediately initiated to either restore one electric power monitoring assembly to OPERABLE status for the inservice power source supplying the required instrumentation powered from the RPS bus (Required Action D.2.1) or to isolate the RHR Shutdown Cooling System (Required Action D.2.2). Required Action D.2.1 is provided because the RHR Shutdown Cooling System may be needed to provide core cooling. All actions must continue until the applicable Required Actions are completed.
General Electric BWR/6 STS            B 3.3.8.2-5                                        Rev. 5.0
 
RPS Electric Power Monitoring B 3.3.8.2 BASES SURVEILLANCE        SR 3.3.8.2.1 REQUIREMENTS A CHANNEL FUNCTIONAL TEST is performed on each overvoltage, undervoltage, and underfrequency channel to ensure that the entire channel will perform the 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 methodology.
As noted in the Surveillance, the CHANNEL FUNCTIONAL TEST is only required to be performed while the plant is in a condition in which the loss of the RPS bus will not jeopardize steady state power operation (the design of the system is such that the power source must be removed from service to conduct the Surveillance). The 24 hours is intended to indicate an outage of sufficient duration to allow for scheduling and proper performance of the Surveillance. The Note in the Surveillance is based on guidance provided in Generic Letter 91-09 (Ref. 3).
[ The 184 day Frequency is based on Reference 3.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.8.2.2 CHANNEL CALIBRATION is a complete check of the instrument loop and the sensor. This test verifies that the channel responds to the measured parameter within the necessary range and accuracy. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found setting are consistent with General Electric BWR/6 STS                B 3.3.8.2-6                                                      Rev. 5.0
 
RPS Electric Power Monitoring B 3.3.8.2 BASES SURVEILLANCE REQUIREMENTS (continued) those established by the setpoint methodology. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.
[ 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.3.8.2.3 Performance of a system functional test demonstrates a required system actuation (simulated or actual) signal. The logic of the system will automatically trip open the associated power monitoring assembly circuit breaker. Only one signal per power monitoring assembly is required to be tested. This Surveillance overlaps with the CHANNEL CALIBRATION to provide complete testing of the safety function. The system functional test of the Class 1E circuit breakers is included as part of this test to provide complete testing of the safety function. If the breakers are incapable of operating, the associated electric power monitoring assembly would be inoperable.
[ 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.3.8.2-7                                                      Rev. 5.0
 
RPS Electric Power Monitoring B 3.3.8.2 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [8.3.1.1.5].
: 2. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
: 3. NRC Generic Letter 91-09, "Modification of Surveillance Interval for the Electric Protective Assemblies in Power Supplies for the Reactor Protection System."
General Electric BWR/6 STS                B 3.3.8.2-8                                                      Rev. 5.0
 
Recirculation Loops Operating B 3.4.1 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.1 Recirculation Loops Operating BASES BACKGROUND            The Reactor Coolant Recirculation System is designed to provide a forced coolant flow through the core to remove heat from the fuel. The forced coolant flow removes more heat from the fuel than would be possible with just natural circulation. The forced flow, therefore, allows operation at significantly higher power than would otherwise be possible.
The recirculation system also controls reactivity over a wide span of reactor power by varying the recirculation flow rate to control the void content of the moderator. The Reactor Coolant Recirculation System consists of two recirculation pump loops external to the reactor vessel.
These loops provide the piping path for the driving flow of water to the reactor vessel jet pumps. Each external loop contains a two speed motor driven recirculation pump, a flow control valve, associated piping, jet pumps, valves, and instrumentation. The recirculation loops are part of the reactor coolant pressure boundary and are located inside the drywell structure. The jet pumps are reactor vessel internals.
The recirculated coolant consists of saturated water from the steam separators and dryers that has been subcooled by incoming feedwater.
This water passes down the annulus between the reactor vessel wall and the core shroud. A portion of the coolant flows from the vessel, through the two external recirculation loops, and becomes the driving flow for the jet pumps. Each of the two external recirculation loops discharges high pressure flow into an external manifold, from which individual recirculation inlet lines are routed to the jet pump risers within the reactor vessel. The remaining portion of the coolant mixture in the annulus becomes the suction flow for the jet pumps. This flow enters the jet pump at suction inlets and is accelerated by the driving flow. The drive flow and suction flow are mixed in the jet pump throat section. The total flow then passes through the jet pump diffuser section into the area below the core (lower plenum), gaining sufficient head in the process to drive the required flow upward through the core.
The subcooled water enters the bottom of the fuel channels and contacts the fuel cladding, where heat is transferred to the coolant. As it rises, the coolant begins to boil, creating steam voids within the fuel channel that continue until the coolant exits the core. Because of reduced moderation, the steam voiding introduces negative reactivity that must be compensated for to maintain or to increase reactor power. The recirculation flow control allows operators to increase recirculation flow and sweep some of the voids from the fuel channel, overcoming the negative reactivity void effect. Thus, the reason for having variable General Electric BWR/6 STS                B 3.4.1-1                                        Rev. 5.0
 
Recirculation Loops Operating B 3.4.1 BASES BACKGROUND (continued) recirculation flow is to compensate for reactivity effects of boiling over a wide range of power generation (i.e., 55 to 100% RTP) without having to move control rods and disturb desirable flux patterns.
Each recirculation loop is manually started from the control room. The recirculation flow control valves provide regulation of individual recirculation loop drive flows. The flow in each loop can be manually or automatically controlled.
APPLICABLE          The operation of the Reactor Coolant Recirculation System is an initial SAFETY              condition assumed in the design basis loss of coolant accident (LOCA)
ANALYSES            (Ref. 1). During a LOCA caused by a recirculation loop pipe break, the intact loop is assumed to provide coolant flow during the first few seconds of the accident. The initial core flow decrease is rapid because the recirculation pump in the broken loop ceases to pump reactor coolant to the vessel almost immediately. The pump in the intact loop coasts down relatively slowly. This pump coastdown governs the core flow response for the next several seconds until the jet pump suction is uncovered (Ref. 1). The analyses assume that both loops are operating at the same flow prior to the accident. However, the LOCA analysis was reviewed for the case with a flow mismatch between the two loops, with the pipe break assumed to be in the loop with the higher flow. While the flow coastdown and core response are potentially more severe in this assumed case (since the intact loop starts at a lower flow rate and the core response is the same as if both loops were operating at a lower flow rate), a small mismatch has been determined to be acceptable based on engineering judgement.
The recirculation system is also assumed to have sufficient flow coastdown characteristics to maintain fuel thermal margins during abnormal operational transients (Ref. 2), which are analyzed in Chapter 15 of the FSAR.
A plant specific LOCA analysis has been performed assuming only one operating recirculation loop. This analysis has demonstrated that, in the event of a LOCA caused by a pipe break in the operating recirculation loop, the Emergency Core Cooling System response will provide adequate core cooling, provided the APLHGR requirements are modified accordingly (Ref. 3).
The transient analyses of Chapter 15 of the FSAR have also been performed for single recirculation loop operation (Ref. 3) and demonstrate sufficient flow coastdown characteristics to maintain fuel thermal margins during the abnormal operational transients analyzed provided the MCPR requirements are modified. During single recirculation loop operation, modification to the Reactor Protection System average power range General Electric BWR/6 STS              B 3.4.1-2                                        Rev. 5.0
 
Recirculation Loops Operating B 3.4.1 BASES APPLICABLE SAFETY ANALYSES (continued) monitor (APRM) instrument setpoints is also required to account for the different relationships between recirculation drive flow and reactor core flow. The APLHGR and MCPR setpoints for single loop operation are specified in the COLR. The APRM flow biased simulated thermal power setpoint is specified in in LCO 3.3.1.1, "Reactor Protection System (RPS)
Instrumentation."
Recirculation loops operating satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO                Two recirculation loops are required to be in operation with their flows matched within the limits specified in SR 3.4.1.1 to ensure that during a LOCA caused by a break of the piping of one recirculation loop the assumptions of the LOCA analysis are satisfied. With the limits specified in SR 3.4.1.1 not met, the recirculation loop with the lower flow must be considered not in operation. With only one recirculation loop in operation, modifications to the required APLHGR limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), and APRM Flow Biased Simulated Thermal Power - High setpoint (LCO 3.3.1.1) may be applied to allow continued operation consistent with the assumptions of Reference 3.
APPLICABILITY      In MODES 1 and 2, requirements for operation of the Reactor Coolant Recirculation System are necessary since there is considerable energy in the reactor core and the limiting design basis transients and accidents are assumed to occur.
In MODES 3, 4, and 5, the consequences of an accident are reduced and the coastdown characteristics of the recirculation loops are not important.
ACTIONS            A.1 With the requirements of the LCO not met, the recirculation loops must be restored to operation with matched flows within 24 hours. A recirculation loop is considered not in operation when the pump in that loop is idle or when the mismatch between total jet pump flows of the two loops is greater than required limits. The loop with the lower flow must be considered not in operation. Should a LOCA occur with one recirculation loop not in operation, the core flow coastdown and resultant core response may not be bounded by the LOCA analyses. Therefore, only a limited time is allowed to restore the inoperable loop to operating status.
General Electric BWR/6 STS              B 3.4.1-3                                        Rev. 5.0
 
Recirculation Loops Operating B 3.4.1 BASES ACTIONS (continued)
Alternatively, if the single loop requirements of the LCO are applied to the operating limits and RPS setpoints, operation with only one recirculation loop would satisfy the requirements of the LCO and the initial conditions of the accident sequence.
The 24 hour Completion Time is based on the low probability of an accident occurring during this time period, on a reasonable time to complete the Required Action, and on frequent core monitoring by operators allowing abrupt changes in core flow conditions to be quickly detected.
This Required Action does not require tripping the recirculation pump in the lowest flow loop when the mismatch between total jet pump flows of the two loops is greater than the required limits. However, in cases where large flow mismatches occur, low flow or reverse flow can occur in the low flow loop jet pumps, causing vibration of the jet pumps. If zero or reverse flow is detected, the condition should be alleviated by changing flow control valve position to re-establish forward flow or by tripping the pump.
B.1 With no recirculation loops in operation, or the Required Action and associated Completion Time of Condition A not met, the unit is required to 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 12 hours. In this condition, the recirculation loops are not required to be operating because of the reduced severity of DBAs and minimal dependence on the recirculation loop coastdown characteristics. The allowed Completion Time of 12 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 3.4.1.1 REQUIREMENTS This SR ensures the recirculation loop flows are within the allowable limits for mismatch. At low core flow (i.e., < [70]% of rated core flow), the MCPR requirements provide larger margins to the fuel cladding integrity Safety Limit such that the potential adverse effect of early boiling transition during a LOCA is reduced. A larger flow mismatch can therefore be allowed when core flow is < [70]% of rated core flow. The recirculation loop jet pump flow, as used in this Surveillance, is the summation of the flows from all of the jet pumps associated with a single recirculation loop.
General Electric BWR/6 STS              B 3.4.1-4                                        Rev. 5.0
 
Recirculation Loops Operating B 3.4.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The mismatch is measured in terms of percent of rated core flow. If the flow mismatch exceeds the specified limits, the loop with the lower flow is considered inoperable. This SR is not required when both loops are not in operation since the mismatch limits are meaningless during single loop or natural circulation operation. The Surveillance must be performed within 24 hours after both loops are in operation. [ The 24 hour Frequency is consistent with the Frequency for jet pump OPERABILITY verification and has been shown by operating experience to be adequate to detect off normal jet pump loop flows in a timely manner.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [6.3.3.4].
: 2. FSAR, Section [5.5.1.4].
[3. Plant specific analysis for single loop operation. ]
General Electric BWR/6 STS                B 3.4.1-5                                                      Rev. 5.0
 
FCVs B 3.4.2 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.2 Flow Control Valves (FCVs)
BASES BACKGROUND          The Reactor Coolant Recirculation System is described in the Background section of the Bases for LCO 3.4.1, "Recirculation Loops Operating," which discusses the operating characteristics of the system and how this affects the design basis transient and accident analyses.
The jet pumps and the FCVs are part of the Reactor Coolant Recirculation System. The jet pumps are described in the Bases for LCO 3.4.3, "Jet Pumps."
The Recirculation Flow Control System consists of the electronic and hydraulic components necessary for the positioning of the two hydraulically actuated FCVs. The recirculation loop flow rate can be rapidly changed within the expected flow range, in response to rapid changes in system demand. Limits on the system response are required to minimize the impact on core flow response during certain accidents and transients. Solid state control logic will generate an FCV "motion inhibit" signal in response to any one of several hydraulic power unit or analog control circuit failure signals. The "motion inhibit" signal causes hydraulic power unit shutdown and hydraulic isolation such that the FCVs fail "as is."
APPLICABLE          The FCV stroke rate is limited to  11% per second in the opening and SAFETY              closing directions on a control signal failure of maximum demand. This ANALYSES            stroke rate is an assumption of the analysis of the recirculation flow control failures on decreasing and increasing flow (Refs. 1 and 2). The closure of a recirculation FCV concurrent with a loss of coolant accident (LOCA) has been analyzed and found to be acceptable for a maximum closure rate of 11% of strokes per second (Ref. 3).
Flow control valves satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO                  An FCV in each operating recirculation loop must be OPERABLE to ensure that the assumptions of the design basis transient and accident analyses are satisfied.
APPLICABILITY        In MODES 1 and 2, the FCVs are required to be OPERABLE, since during these conditions there is considerable energy in the reactor core, and the limiting design basis transients and accidents are assumed to occur. In MODES 3, 4, and 5, the consequences of a transient or accident are reduced and OPERABILITY of the flow control valves is not important.
General Electric BWR/6 STS              B 3.4.2-1                                        Rev. 5.0
 
FCVs B 3.4.2 BASES ACTIONS            A Note has been provided to modify the ACTIONS related to FCVs.
Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable FCVs provide appropriate compensatory measures for separate inoperable FCVs. As such, a Note has been provided that allows separate Condition entry for each inoperable FCV.
A.1 With one or two required FCVs inoperable, the assumptions of the design basis transient and accident analyses may not be met and the inoperable FCV must be returned to OPERABLE status or hydraulically locked within 4 hours.
Opening an FCV faster than the limit could result in a more severe flow runout transient, resulting in violation of the Safety Limit MCPR. Closing an FCV faster than the limit assumed in the LOCA analysis (Refs. 1 and 2) could affect the recirculation flow coastdown, resulting in higher peak clad temperatures. Therefore, if an FCV is inoperable due to stroke times faster than the limits, deactivating the valve will essentially lock the valve in position, which will prohibit the FCV from adversely affecting the DBA and transient analyses. Continued operation is allowed in this Condition.
The 4 hour Completion Time is a reasonable time period to complete the Required Action, while limiting the time of operation with an inoperable FCV.
B.1 If the FCVs are not deactivated ("locked up") within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 12 hours. This brings the unit to a condition where the flow coastdown characteristics of the recirculation loop are not important. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging unit systems.
General Electric BWR/6 STS              B 3.4.2-2                                          Rev. 5.0
 
FCVs B 3.4.2 BASES SURVEILLANCE        SR 3.4.2.1 REQUIREMENTS Hydraulic power unit pilot operated isolation valves located between the servo valves and the common "open" and "close" lines are required to close in the event of a loss of hydraulic pressure. When closed, these valves inhibit FCV motion by blocking hydraulic pressure from the servo valve to the common open and close lines as well as to the alternate subloop. This Surveillance verifies FCV lockup on a loss of hydraulic pressure.
[ 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 SR when performed at the [18] month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.4.2.2 This SR ensures the overall average rate of FCV movement at all positions is maintained within the analyzed limits.
[ 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 SR when performed at the [18] month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR General Electric BWR/6 STS                  B 3.4.2-3                                                      Rev. 5.0
 
FCVs B 3.4.2 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [15.3.2].
: 2. FSAR, Section [15.4.5].
[ 3. Plant specific Safety Evaluation Report. ]
General Electric BWR/6 STS                B 3.4.2-4                                                      Rev. 5.0
 
Jet Pumps B 3.4.3 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.3 Jet Pumps BASES BACKGROUND          The Reactor Coolant Recirculation System is described in the Background section of the Bases for LCO 3.4.1, "Recirculation Loops Operating," which discusses the operating characteristics of the system and how these characteristics affect the Design Basis Accident (DBA) analyses.
The jet pumps are part of the Reactor Coolant Recirculation System and are designed to provide forced circulation through the core to remove heat from the fuel. The jet pumps are located in the annular region between the core shroud and the vessel inner wall. Because the jet pump suction elevation is at two thirds core height, the vessel can be reflooded and coolant level maintained at two thirds core height even with the complete break of the recirculation loop pipe that is located below the jet pump suction elevation.
Each reactor coolant recirculation loop contains 12 jet pumps.
Recirculated coolant passes down the annulus between the reactor vessel wall and the core shroud. A portion of the coolant flows from the vessel, through the two external recirculation loops, and becomes the driving flow for the jet pumps. Each of the two external recirculation loops discharges high pressure flow into an external manifold from which individual recirculation inlet lines are routed to the jet pump risers within the reactor vessel. The remaining portion of the coolant mixture in the annulus becomes the suction flow for the jet pumps. This flow enters the jet pump at suction inlets and is accelerated by the drive flow. The drive flow and suction flow are mixed in the jet pump throat section. The total flow then passes through the jet pump diffuser section into the area below the core (lower plenum), gaining sufficient head in the process to drive the required flow upward through the core.
APPLICABLE          Jet pump OPERABILITY is an explicit assumption in the design basis loss SAFETY              of coolant accident (LOCA) analysis evaluated in Reference 1.
ANALYSES The capability of reflooding the core to two-thirds core height is dependent upon the structural integrity of the jet pumps. If the structural system, including the beam holding a jet pump in place, fails, jet pump displacement and performance degradation could occur, resulting in an increased flow area through the jet pump and a lower core flooding elevation. This could adversely affect the water level in the core during the reflood phase of a LOCA as well as the assumed blowdown flow during a LOCA.
Jet pumps satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS            B 3.4.3-1                                          Rev. 5.0
 
Jet Pumps B 3.4.3 BASES LCO                The structural failure of any of the jet pumps could cause significant degradation in the ability of the jet pumps to allow reflooding to two thirds core height during a LOCA. OPERABILITY of all jet pumps is required to ensure that operation of the Reactor Coolant Recirculation System will be consistent with the assumptions used in the licensing basis analysis (Ref. 1).
APPLICABILITY      In MODES 1 and 2, the jet pumps are required to be OPERABLE since there is a large amount of energy in the reactor core and since the limiting DBAs are assumed to occur in these MODES. This is consistent with the requirements for operation of the Reactor Coolant Recirculation System (LCO 3.4.1).
In MODES 3, 4, and 5, the Reactor Coolant Recirculation System is not required to be in operation, and when not in operation sufficient flow is not available to evaluate jet pump OPERABILITY.
ACTIONS            A.1 An inoperable jet pump can increase the blowdown area and reduce the capability of reflooding during a design basis LOCA. If one or more of the jet pumps are inoperable, 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 12 hours. The allowed Completion Time of 12 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 3.4.3.1 REQUIREMENTS This SR is designed to detect significant degradation in jet pump performance that precedes jet pump failure (Ref. 2). This SR is required to be performed only when the loop has forced recirculation flow since surveillance checks and measurements can only be performed during jet pump operation. The jet pump failure of concern is a complete mixer displacement due to jet pump beam failure. Jet pump plugging is also of concern since it adds flow resistance to the recirculation loop. Significant degradation is indicated if the specified criteria confirm unacceptable deviations from established patterns or relationships. The allowable deviations from the established patterns have been developed based on the variations experienced at plants during normal operation and with jet pump assembly failures (Refs. 2 and 3). Since refueling activities (fuel assembly replacement or shuffle, as well as any modifications to fuel support orifice size or core plate bypass flow) can affect the relationship between core flow, jet pump flow, and recirculation loop flow, these General Electric BWR/6 STS              B 3.4.3-2                                        Rev. 5.0
 
Jet Pumps B 3.4.3 BASES SURVEILLANCE REQUIREMENTS (continued) relationships may need to be re-established each cycle. Similarly, initial entry into extended single loop operation may also require establishment of these relationships. During the initial weeks of operation under such conditions, while baselining new "established patterns", engineering judgement of the daily surveillance results is used to detect significant abnormalities which could indicate a jet pump failure.
The recirculation flow control valve (FCV) operating characteristics (loop flow versus FCV position) are determined by the flow resistance from the loop suction through the jet pump nozzles. A change in the relationship indicates a flow restriction, loss in pump hydraulic performance, leak, or new flow path between the recirculation pump discharge and jet pump nozzle. For this criterion, the loop flow versus FCV position relationship must be verified.
Total core flow can be determined from measurements of the recirculation loop drive flows. Once this relationship has been established, increased or reduced total core flow for the same recirculation loop drive flow may be an indication of failures in one or several jet pumps.
Individual jet pumps in a recirculation loop typically do not have the same flow. The unequal flow is due to the drive flow manifold, which does not distribute flow equally to all risers. The flow (or jet pump diffuser to lower plenum differential pressure) pattern or relationship of one jet pump to the loop average is repeatable. An appreciable change in this relationship is an indication that increased (or reduced) resistance has occurred in one of the jet pumps. This may be indicated by an increase in the relative flow for a jet pump that has experienced beam cracks.
The deviations from normal are considered indicative of a potential problem in the recirculation drive flow or jet pump system (Ref. 2).
Normal flow ranges and established jet pump flow and differential pressure patterns are established by plotting historical data as discussed in Reference 2.
[ The 24 hour Frequency has been shown by operating experience to be adequate to verify jet pump OPERABILITY and is consistent with the Frequency for recirculation loop OPERABILITY verification.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS              B 3.4.3-3                                          Rev. 5.0
 
Jet Pumps B 3.4.3 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
This SR is modified by two Notes. Note 1 allows this Surveillance not to be performed until 4 hours after the associated recirculation loop is in operation, since these checks can only be performed during jet pump operation. The 4 hours is an acceptable time to establish conditions appropriate for data collection and evaluation.
Note 2 allows this SR not to be performed when THERMAL POWER is 25% RTP. During low flow conditions, jet pump noise approaches the threshold response of the associated flow instrumentation and precludes the collection of repeatable and meaningful data.
REFERENCES          1. FSAR, Section [6.3].
: 2. GE Service Information Letter No. 330, June 9, 1990.
: 3. NUREG/CR-3052, November 1984.
General Electric BWR/6 STS                B 3.4.3-4                                                      Rev. 5.0
 
S/RVs B 3.4.4 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.4 Safety/Relief Valves (S/RVs)
BASES BACKGROUND            The American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (Ref. 1) requires the Reactor Pressure Vessel be protected from overpressure during upset conditions by self actuated safety valves. As part of the nuclear pressure relief system, the size and number of safety/relief valves (S/RVs) are selected such that peak pressure in the nuclear system will not exceed the ASME Code limits for the reactor coolant pressure boundary (RCPB).
The S/RVs are located on the main steam lines between the reactor vessel and the first isolation valve within the drywell. Each S/RV discharges steam through a discharge line to a point below the minimum water level in the suppression pool.
The S/RVs can actuate by either of two modes: the safety mode or the relief mode. In the safety mode (or spring mode of operation), the direct action of the steam pressure in the main steam lines will act against a spring loaded disk that will pop open when the valve inlet pressure exceeds the spring force. In the relief mode (or power actuated mode of operation), a pneumatic piston or cylinder and mechanical linkage assembly are used to open the valve by overcoming the spring force, even with the valve inlet pressure equal to 0 psig. The pneumatic operator is arranged so that its malfunction will not prevent the valve disk from lifting if steam inlet pressure reaches the spring lift set pressures. In the relief mode, valves may be opened manually or automatically at the selected preset pressure. Six of the S/RVs providing the relief function also provide the low-low set relief function specified in LCO 3.6.1.6, "Low-Low Set (LLS) Valves." Eight of the S/RVs that provide the relief function are part of the Automatic Depressurization System specified in LCO 3.5.1, "ECCS - Operating." The instrumentation associated with the relief valve function and low-low set relief function is discussed in the Bases for LCO 3.3.6.5, "Relief and Low-Low Set (LLS) Instrumentation,"
and instrumentation for the ADS function is discussed in LCO 3.3.5.1, "Emergency Core Cooling Systems (ECCS) Instrumentation."
APPLICABLE            The overpressure protection system must accommodate the most severe SAFETY                pressure transient. Evaluations have determined that the most severe ANALYSES              transient is the closure of all main steam isolation valves (MSIVs) followed by reactor scram on high neutron flux (i.e., failure of the direct scram associated with MSIV position) (Ref. 2). For the purpose of the analyses, [six] of the S/RVs are assumed to operate in the relief mode, and seven in the safety mode. The analysis results demonstrate that the design S/RV capacity is capable of maintaining reactor pressure below General Electric BWR/6 STS                B 3.4.4-1                                        Rev. 5.0
 
S/RVs B 3.4.4 BASES APPLICABLE SAFETY ANALYSES (continued) the ASME Code limit of 110% of vessel design pressure (110% x 1250 psig = 1375 psig). This LCO helps to ensure that the acceptance limit of 1375 psig is met during the design basis event.
From an overpressure standpoint, the design basis events are bounded by the MSIV closure with flux scram event described above. Reference 3 discusses additional events that are expected to actuate the S/RVs.
S/RVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                The safety function of seven S/RVs is required to be OPERABLE in the safety mode, and an additional seven S/RVs (other than the seven S/RVs that satisfy the safety function) must be OPERABLE in the relief mode.
The requirements of this LCO are applicable only to the capability of the S/RVs to mechanically open to relieve excess pressure. In Reference 2, an evaluation was performed to establish the parametric relationship between the peak vessel pressure and the number of OPERABLE S/RVs.
The results show that with a minimum of seven S/RVs in the safety mode and six S/RVs in the relief mode OPERABLE, the ASME Code limit of 1375 psig is not exceeded.
The S/RV setpoints are established to ensure the ASME Code limit on peak reactor pressure is satisfied. The ASME Code specifications require the lowest safety valve be set at or below vessel design pressure (1250 psig) and the highest safety valve be set so the total accumulated pressure does not exceed 110% of the design pressure for conditions.
The transient evaluations in Reference 3 are based on these setpoints, but also include the additional uncertainties of +/- 1% of the nominal setpoint to account for potential setpoint drift to provide an added degree of conservatism.
Operation with fewer valves OPERABLE than specified, or with setpoints outside the ASME limits, could result in a more severe reactor response to a transient than predicted, possibly resulting in the ASME Code limit on reactor pressure being exceeded.
APPLICABILITY      In MODES 1, 2, and 3, the specified number of S/RVs must be OPERABLE since there may be considerable energy in the reactor core and the limiting design basis transients are assumed to occur. The S/RVs may be required to provide pressure relief to discharge energy from the core until such time that the Residual Heat Removal (RHR)
System is capable of dissipating the heat.
General Electric BWR/6 STS            B 3.4.4-2                                        Rev. 5.0
 
S/RVs B 3.4.4 BASES APPLICABILITY (continued)
In MODE 4, decay heat is low enough for the RHR System to provide adequate cooling, and reactor pressure is low enough that the overpressure limit is unlikely to be approached by assumed operational transients or accidents. In MODE 5, the reactor vessel head is unbolted or removed and the reactor is at atmospheric pressure. The S/RV function is not needed during these conditions.
ACTIONS            A.1 With the safety function of one [required] S/RV inoperable, the remaining OPERABLE S/RVs are capable of providing the necessary overpressure protection. Because of additional design margin, the ASME Code limits for the RCPB can also be satisfied with two S/RVs inoperable. However, the overall reliability of the pressure relief system is reduced because additional failures in the remaining OPERABLE S/RVs could result in failure to adequately relieve pressure during a limiting event. For this reason, continued operation is permitted for a limited time only.
The 14 day Completion Time to restore the inoperable required S/RVs to OPERABLE status is based on the relief capability of the remaining S/RVs, the low probability of an event requiring S/RV actuation, and a reasonable time to complete the Required Action. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.]
B.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
If the inoperable required S/RV cannot be restored to OPERABLE status within the associated Completion Time of Required Action A.1, the plant must be brought to a MODE in which overall plant risk is minimized. To General Electric BWR/6 STS                B 3.4.4-3                                                      Rev. 5.0
 
S/RVs B 3.4.4 BASES ACTIONS (continued) achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action B.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is 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 If [two] or more [required] S/RVs are inoperable, a transient may result in the violation of the ASME Code limit on reactor pressure. 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 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE        SR 3.4.4.1 REQUIREMENTS This Surveillance demonstrates that the [required] S/RVs will open at the pressures assumed in the safety analysis of Reference 2. The demonstration of the S/RV safety function lift settings must be performed during shutdown, since this is a bench test[, and in accordance with the INSERVICE TESTING PROGRAM]. The lift setting pressure shall General Electric BWR/6 STS            B 3.4.4-4                                          Rev. 5.0
 
S/RVs B 3.4.4 BASES SURVEILLANCE REQUIREMENTS (continued) correspond to ambient conditions of the valves at nominal operating temperatures and pressures. The S/RV setpoint is +/- [3]% for OPERABILITY; however, the valves are reset to +/- 1% during the Surveillance to allow for drift. [A Note is provided to allow up to [two] of the required [11] S/RVs to be physically replaced with S/RVs with lower setpoints. This provides operational flexibility which maintains the assumptions in the over-pressure analysis.]
                    -----------------------------------REVIEWERS NOTE-----------------------------------
If the testing is within the scope of the licensee's INSERVICE TESTING PROGRAM, the Frequency "In accordance with the INSERVICE TESTING PROGRAM" should be used. Otherwise, the periodic Frequency of 18 months or the reference to the Surveillance Frequency Control Program should be used.
[ The [18 month] Frequency was selected because this Surveillance must be performed during shutdown conditions and is based on the time between refuelings.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.4.4.2 The [required] relief function S/RVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test is performed to verify the mechanical portions of the automatic relief function operate as designed when initiated either by an actual or simulated initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.5.4 overlaps this SR to provide complete testing of the safety function.
General Electric BWR/6 STS                  B 3.4.4-5                                                      Rev. 5.0
 
S/RVs B 3.4.4 BASES SURVEILLANCE REQUIREMENTS (continued)
[ 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 SR when performed at the [18 month]
Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
This SR is modified by a Note that excludes valve actuation. This prevents an RPV pressure blowdown.
SR 3.4.4.3 A manual actuation of each [required] S/RV is performed to verify that, mechanically, the valve is functioning properly and no blockage exists in the valve discharge line. This can be demonstrated by the response of the turbine control valves or bypass valves, by a change in the measured steam flow, or any other method suitable to verify steam flow. Adequate reactor steam dome pressure must be available to perform this test to avoid damaging the valve. Also, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the S/RVs divert steam flow upon opening.
Sufficient time is therefore allowed after the required pressure and flow are achieved to perform this test. Adequate pressure at which this test is to be performed is 950 psig (the pressure recommended by the valve manufacturer). Adequate steam flow is represented by [at least 1.25 turbine bypass valves open, or total steam flow  106 lb/hr]. Plant startup is allowed prior to performing this test because valve OPERABILITY and the setpoints for overpressure protection are verified, per ASME requirements, prior to valve installation. Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test. The 12 hours allowed for manual actuation after the required General Electric BWR/6 STS                  B 3.4.4-6                                                      Rev. 5.0
 
S/RVs B 3.4.4 BASES SURVEILLANCE REQUIREMENTS (continued) pressure is reached is sufficient to achieve stable conditions for testing and provides a reasonable time to complete the SR. If the valve fails to actuate due only to the failure of the solenoid but is capable of opening on overpressure, the safety function of the S/RV is considered OPERABLE.
[ The [18] month on a STAGGERED TEST BASIS Frequency ensures that each solenoid for each S/RV is alternately tested. The 18 month Frequency was developed based on the S/RV tests required by the ASME (Ref. 1). 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. ASME Code for Operation and Maintenance of Nuclear Power Plants.
: 2. FSAR, Section [5.2.5.5.3].
: 3. FSAR, Section [15].
: 4. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
General Electric BWR/6 STS                  B 3.4.4-7                                                      Rev. 5.0
 
RCS Operational LEAKAGE B 3.4.5 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.5 RCS Operational LEAKAGE BASES BACKGROUND          The RCS includes systems and components that contain or transport the coolant to or from the reactor core. The pressure containing components of the RCS and the portions of connecting systems out to and including the isolation valves define the reactor coolant pressure boundary (RCPB).
The joints of the RCPB components are welded or bolted.
During plant life, the joint and valve interfaces can produce varying amounts of reactor coolant LEAKAGE, through either normal operational wear or mechanical deterioration. Limits on RCS operational LEAKAGE are required to ensure appropriate action is taken before the integrity of the RCPB is impaired. This LCO specifies the types and limits of LEAKAGE.
This protects the RCS pressure boundary described in 10 CFR 50.2, 10 CFR 50.55a(c), and GDC 55 of 10 CFR 50, Appendix A (Refs. 1, 2, and 3).
The safety significance of leaks from the RCPB varies widely depending on the source, rate, and duration. Therefore, detection of LEAKAGE in the drywell is necessary. Methods for quickly separating the identified LEAKAGE from the unidentified LEAKAGE are necessary to provide the operators quantitative information to permit them to take corrective action should a leak occur detrimental to the safety of the facility or the public.
A limited amount of leakage inside the drywell is expected from auxiliary systems that cannot be made 100% leaktight. Leakage from these systems should be detected and isolated from the drywell atmosphere, if possible, so as not to mask RCS operational LEAKAGE detection.
This LCO deals with protection of the RCPB from degradation and the core from inadequate cooling, in addition to preventing the accident analyses radiation release assumptions from being exceeded. The consequences of violating this LCO include the possibility of a loss of coolant accident.
APPLICABLE          The allowable RCS operational LEAKAGE limits are based on the SAFETY              predicted and experimentally observed behavior of pipe cracks. The ANALYSES            normally expected background LEAKAGE due to equipment design and the detection capability of the instrumentation for determining system LEAKAGE were also considered. The evidence from experiments suggests, for LEAKAGE even greater than the specified unidentified LEAKAGE limits, the probability is small that the imperfection or crack associated with such LEAKAGE would grow rapidly.
General Electric BWR/6 STS              B 3.4.5-1                                        Rev. 5.0
 
RCS Operational LEAKAGE B 3.4.5 BASES APPLIICABLE SAFETY ANALYSES (continued)
The unidentified LEAKAGE flow limit allows time for corrective action before the RCPB could be significantly compromised. The 5 gpm limit is a small fraction of the calculated flow from a critical crack in the primary system piping. Crack behavior from experimental programs (Refs. 4 and 5) shows leak rates of hundreds of gallons per minute will precede crack instability (Ref. 6).
The low limit on increase in unidentified LEAKAGE assumes a failure mechanism of intergranular stress corrosion cracking (IGSCC) that produces tight cracks. This flow increase limit is capable of providing an early warning of such deterioration.
No applicable safety analysis assumes the total LEAKAGE limit. The total LEAKAGE limit considers RCS inventory makeup capability and drywell floor sump capacity.
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 Pressure boundary LEAKAGE is prohibited as the leak itself could cause further RCPB deterioration, resulting in higher LEAKAGE.
: b. Unidentified LEAKAGE Five gpm of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the drywell air monitoring, drywell sump level monitoring, and drywell air cooler condensate flow rate monitoring equipment can detect within a reasonable time period.
Separating the sources of leakage (i.e., leakage from an identified source versus leakage from an unidentified source) is necessary for prompt identification of potentially adverse conditions, assessment of the safety significance, and corrective action..
: c. Total LEAKAGE The total LEAKAGE limit is based on a reasonable minimum detectable amount. The limit also accounts for LEAKAGE from known sources (identified LEAKAGE). Violation of this LCO indicates an unexpected amount of LEAKAGE and, therefore, could indicate new or additional degradation in an RCPB component or system.
General Electric BWR/6 STS              B 3.4.5-2                                          Rev. 5.0
 
RCS Operational LEAKAGE B 3.4.5 BASES LCO (continued)
: d. Unidentified LEAKAGE Increase An unidentified LEAKAGE increase of > 2 gpm within the previous 4 hour period indicates a potential flaw in the RCPB and must be quickly evaluated to determine the source and extent of the LEAKAGE. The increase is measured relative to the steady state value; temporary changes in LEAKAGE rate as a result of transient conditions (e.g., startup) are not considered. As such, the 2 gpm increase limit is only applicable in MODE 1 when operating pressures and temperatures are established.
APPLICABILITY      In MODES 1, 2, and 3, the RCS operational LEAKAGE LCO applies because the potential for RCPB LEAKAGE is greatest when the reactor is pressurized.
In MODES 4 and 5, RCS operational LEAKAGE limits are not required since the reactor is not pressurized and stresses in the RCPB materials and potential for LEAKAGE are reduced.
ACTIONS            A.1 If pressure boundary LEAKAGE exists, the affected component, pipe, or vessel must be isolated from the RCS by a closed manual valve, closed and de-activated automatic valve, blind flange, or check valve within 4 hours. While in this condition, structural integrity of the system should be considered because the structural integrity of the part of the system within the isolation boundary must be maintained under all licensing basis conditions, including consideration of the potential for further degradation of the isolated location. Normal LEAKAGE past the isolation device is acceptable as it will limit RCS LEAKAGE and is included in identified or unidentified LEAKAGE. This action is necessary to prevent further deterioration of the RCPB.
B.1 With RCS unidentified or total LEAKAGE greater than the limits, actions must be taken to reduce the leak. Because the LEAKAGE limits are conservatively below the LEAKAGE that would constitute a critical crack size, 4 hours is allowed to reduce the LEAKAGE rates before the reactor must be shut down. If an unidentified LEAKAGE has been identified and quantified, it may be reclassified and considered as identified LEAKAGE.
However, the total LEAKAGE limit would remain unchanged.
General Electric BWR/6 STS            B 3.4.5-3                                        Rev. 5.0
 
RCS Operational LEAKAGE B 3.4.5 BASES ACTIONS (continued)
C.1 and C.2 An unidentified LEAKAGE increase of > 2 gpm within a 4 hour period is an indication of a potential flaw in the RCPB and must be quickly evaluated. Although the increase does not necessarily violate the absolute unidentified LEAKAGE limit, certain susceptible components must be determined not to be the source of the LEAKAGE increase within the required Completion Time. For an unidentified LEAKAGE increase greater than required limits, an alternative to reducing LEAKAGE increase to within limits (i.e., reducing the leakage rate such that the current rate is less than the "2 gpm increase in the previous [4] hours" limit; either by isolating the source or other possible methods) is to evaluate RCS type 304 and type 316 austenitic stainless steel piping that is subject to high stress or that contains relatively stagnant or intermittent flow fluids and determine it is not the source of the increased LEAKAGE. This type of piping is very susceptible to IGSCC.
The 4 hour Completion Time is needed to properly reduce the LEAKAGE increase or verify the source before the reactor must be shut down.
D.1 and D.2 If any Required Action and associated Completion is 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 MODE 3 within 12 hours and to MODE 4 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 3.4.5.1 REQUIREMENTS The RCS LEAKAGE is monitored by a variety of instruments designed to provide alarms when LEAKAGE is indicated and to quantify the various types of LEAKAGE. Leakage detection instrumentation is discussed in more detail in the Bases for LCO 3.4.7, "RCS Leakage Detection Instrumentation." Sump level and flow rate are typically monitored to determine actual LEAKAGE rates. However, any method may be used to quantify LEAKAGE within the guidelines of Reference 7. [ In conjunction with alarms and other administrative controls, an 8 hour Frequency for this Surveillance is appropriate for identifying changes in LEAKAGE and for tracking required trends (Ref. 8).
OR General Electric BWR/6 STS              B 3.4.5-4                                        Rev. 5.0
 
RCS Operational LEAKAGE B 3.4.5 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. 10 CFR 50.2.
: 2. 10 CFR 50.55a(c).
: 3. 10 CFR 50, Appendix A, GDC 55.
: 4. GEAP-5620, April 1968.
: 5. NUREG-76/067, October 1975.
: 6. FSAR, Section [5.2.5.5.3].
: 7. Regulatory Guide 1.45.
: 8. Generic Letter 88-01, Supplement 1.
General Electric BWR/6 STS                B 3.4.5-5                                                      Rev. 5.0
 
RCS PIV Leakage B 3.4.6 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.6 RCS Pressure Isolation Valve (PIV) Leakage BASES BACKGROUND          RCS PIVs are defined as any two normally closed valves in series within the reactor coolant pressure boundary (RCPB). The function of RCS PIVs is to separate the high pressure RCS from an attached low pressure system. This protects the RCS pressure boundary described in 10 CFR 50.2, 10 CFR 50.55a(c), and GDC 55 of 10 CFR 50, Appendix A (Refs. 1, 2, and 3). PIVs are designed to meet the requirements of Reference 4. 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 these valves is not included in any allowable LEAKAGE specified in LCO 3.4.5, "RCS Operational LEAKAGE."
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 accident which could degrade the ability for low pressure injection.
A study (Ref. 5) evaluated various PIV configurations to determine the probability of intersystem LOCAs. This study concluded that periodic leakage testing of the PIVs can substantially reduce intersystem LOCA probability.
PIVs are provided to isolate the RCS from the following typically connected systems:
: a. Residual Heat Removal (RHR) System,
: b. Low Pressure Core Spray System,
: c. High Pressure Core Spray System, and
: d. Reactor Core Isolation Cooling System.
The PIVs are listed in Reference 6.
General Electric BWR/6 STS              B 3.4.6-1                                      Rev. 5.0
 
RCS PIV Leakage B 3.4.6 BASES APPLICABLE          Reference 5 evaluated various PIV configurations, leakage testing of the SAFETY              valves, and operational changes to determine the effect on the ANALYSES            probability of intersystem LOCAs. This study concluded that periodic leakage testing of the PIVs can substantially reduce the probability of an intersystem LOCA.
PIV leakage is not considered in any Design Basis Accident analyses.
This Specification provides for monitoring the condition of the RCPB to detect PIV degradation that has the potential to cause a LOCA outside of containment. RCS PIV leakage satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO                RCS PIV leakage is 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. 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.
The LCO PIV leakage limit is 0.5 gpm per nominal inch of valve size with a maximum limit of 5 gpm (Ref. 4).
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). 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, and 3, this LCO applies because the PIV leakage potential is greatest when the RCS is pressurized. In MODE 3, valves in the RHR flowpath are not required to meet the requirements of this LCO when in, or during transition to or from, the RHR shutdown cooling mode of operation.
In MODES 4 and 5, 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. Accordingly, the potential for the consequences of reactor coolant leakage is far lower during these MODES.
ACTIONS            The ACTIONS are modified by two Notes. Note 1 has been provided to modify the ACTIONS related to RCS PIV flow paths. Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the Condition, discovered to be inoperable or not within limits, will not General Electric BWR/6 STS              B 3.4.6-2                                        Rev. 5.0
 
RCS PIV Leakage B 3.4.6 BASES ACTIONS (continued) result in separate entry into the Condition. Section 1.3 also specifies Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition.
However, the Required Actions for the Condition of RCS PIV leakage limits exceeded provide appropriate compensatory measures for separate affected RCS PIV flow paths. As such, a Note has been provided that allows separate Condition entry for each affected RCS PIV 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. As a result, the applicable Conditions and Required Actions for systems made inoperable by PIVs must be entered. This ensures appropriate remedial actions are taken, if necessary, for the affected systems.
A.1 and A.2 If leakage from one or more RCS PIVs is not within limit, the flow path must be isolated by at least one closed manual, deactivated, automatic, or check valve within 4 hours. Required Action A.1 and Required Action 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 on the RCPB [or the high pressure portion of the system.]
Four hours provides time to reduce leakage in excess of the allowable limit and to isolate the flow path if leakage cannot be reduced while corrective actions to reseat the leaking PIVs are taken. The 4 hours allows time for these actions and restricts the time of operation with leaking valves.
Required Action A.2 specifies that the double isolation barrier of two valves be restored by closing another 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 Required Action, the low probability of a second valve failing during this time period, and the low probability of a pressure boundary rupture of the low pressure ECCS piping when overpressurized to reactor pressure (Ref. 7).
B.1 and B.2 If leakage cannot be reduced or the system isolated, 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 12 hours and to MODE 4 within 36 hours. This action may reduce the leakage and also General Electric BWR/6 STS              B 3.4.6-3                                        Rev. 5.0
 
RCS PIV Leakage B 3.4.6 BASES ACTIONS (continued) reduces the potential for a LOCA outside the containment. The Completion Times are reasonable, based on operating experience, to achieve the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
SURVEILLANCE        SR 3.4.6.1 REQUIREMENTS Performance of leakage testing on each RCS PIV 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.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
If the testing is within the scope of the licensee's INSERVICE TESTING PROGRAM, the Frequency "In accordance with the INSERVICE TESTING PROGRAM" should be used. Otherwise, the periodic Frequency of 18 months or the reference to the Surveillance Frequency Control Program should be used.
[ The 18 month Frequency required by the INSERVICE TESTING PROGRAM is within the ASME Code Frequency requirement and is based on the need to perform this Surveillance under the conditions that apply during an outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                  B 3.4.6-4                                                      Rev. 5.0
 
RCS PIV Leakage B 3.4.6 BASES SURVEILLANCE REQUIREMENTS (continued)
Therefore, this SR is modified by a Note that states the leakage Surveillance is not required to be performed in MODE 3. Entry into MODE 3 is permitted for leakage testing at high differential pressures with stable conditions not possible in the lower MODES.
REFERENCES          1. 10 CFR 50.2.
: 2. 10 CFR 50.55a(c).
: 3. 10 CFR 50, Appendix A, GDC 55.
: 4. ASME Code for Operation and Maintenance of Nuclear Power Plants.
: 5. NUREG-0677, May 1980.
: 6. FSAR, Section [ ].
: 7. NEDC-31339, November 1986.
General Electric BWR/6 STS            B 3.4.6-5                                        Rev. 5.0
 
RCS Leakage Detection Instrumentation B 3.4.7 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.7 RCS Leakage Detection Instrumentation BASES BACKGROUND          GDC 30 of 10 CFR 50, Appendix A (Ref. 1), requires means for detecting and, to the extent practical, identifying the location of the source of RCS LEAKAGE. Regulatory Guide 1.45, Revision 0, (Ref. 2) describes acceptable methods for selecting leakage detection systems.
Limits on LEAKAGE from the reactor coolant pressure boundary (RCPB) are required so that appropriate action can be taken before the integrity of the RCPB is impaired (Ref. 2). Leakage detection systems for the RCS are provided to alert the operators when leakage rates above normal background levels are detected and also to supply quantitative measurement of rates. [In addition to meeting the OPERABILITY requirements, the monitors are typically set to provide the most sensitive response without causing an excessive number of spurious alarms.] The Bases for LCO 3.4.5, "RCS Operational LEAKAGE," discuss the limits on RCS LEAKAGE rates.
Systems for separating the LEAKAGE of an identified source from an unidentified source are necessary to provide prompt and quantitative information to the operators to permit them to take immediate corrective action.
LEAKAGE from the RCPB inside the drywell is detected by at least one of two or three independently monitored variables, such as sump level changes and drywell gaseous and particulate radioactivity levels. The primary means of quantifying LEAKAGE in the drywell is the drywell floor drain sump monitoring system.
The drywell floor drain sump monitoring system monitors the LEAKAGE collected in the floor drain sump. This unidentified LEAKAGE consists of LEAKAGE from control rod drives, valve flanges or packings, floor drains, the Closed Cooling Water System, and drywell air cooling unit condensate drains, and any LEAKAGE not collected in the drywell equipment drain sump. The drywell floor drain sump has transmitters that supply level indications in the main control room.
The floor drain sump level indicators have switches that start and stop the sump pumps when required. A timer starts each time the sump is pumped down to the low level setpoint. If the sump fills to the high level setpoint before the timer ends, an alarm sounds in the control room, indicating a LEAKAGE rate into the sump in excess of a preset limit. A second timer starts when the sump pumps start on high level. Should this timer run out before the sump level reaches the low level setpoint, an General Electric BWR/6 STS              B 3.4.7-1                                        Rev. 5.0
 
RCS Leakage Detection Instrumentation B 3.4.7 BASES BACKGROUND (continued) alarm is sounded in the control room indicating a LEAKAGE rate into the sump in excess of a preset limit. A flow indicator in the discharge line of the drywell floor drain sump pumps provides flow indication in the control room.
The drywell air monitoring systems continuously monitor the drywell atmosphere for airborne particulate and gaseous radioactivity. A sudden increase of radioactivity, which may be attributed to RCPB steam or reactor water LEAKAGE, is annunciated in the control room.
[ Condensate from four of the six drywell coolers is routed to the drywell floor drain sump and is monitored by a flow transmitter that provides indication and alarms in the control room. This drywell air cooler condensate flow rate monitoring system serves as an added indicator, but not quantifier, of RCS unidentified LEAKAGE. ]
APPLICABLE          A threat of significant compromise to the RCPB exists if the barrier SAFETY              contains a crack that is large enough to propagate rapidly. LEAKAGE ANALYSES            rate limits are set low enough to detect the LEAKAGE emitted from a single crack in the RCPB (Refs. 3 and 4).
A control room alarm allows the operators to evaluate the significance of the indicated LEAKAGE and, if necessary, shut down the reactor for further investigation and corrective action. The allowed LEAKAGE rates are well below the rates predicted for critical crack sizes (Ref. 5).
Therefore, these actions provide adequate response before a significant break in the RCPB can occur.
RCS leakage detection instrumentation satisfies Criterion 1 of 10 CFR 50.36(c)(2)(ii).
LCO                  This LCO requires instruments of diverse monitoring principles to be OPERABLE to provide confidence that small amounts of unidentified LEAKAGE are detected in time to allow actions to place the plant in a safe condition, when RCS LEAKAGE indicates possible RCPB degradation.
The LCO requires [three] instruments to be OPERABLE.
The drywell floor drain sump monitoring system is required to quantify the unidentified LEAKAGE rate from the RCS. Thus, for the system to be considered OPERABLE, either the flow monitoring or the sump level monitoring portion of the system must be OPERABLE and capable of determining the leakage rate. The identification of an increase in unidentified LEAKAGE will be delayed by the time required for the unidentified LEAKAGE to travel to the drywell floor drain sump and it may General Electric BWR/6 STS              B 3.4.7-2                                        Rev. 5.0
 
RCS Leakage Detection Instrumentation B 3.4.7 BASES LCO (continued) take longer than one hour to detect a 1 gpm increase in unidentified LEAKAGE, depending on the origin and magnitude of the LEAKAGE.
This sensitivity is acceptable for containment sump monitor OPERABILITY.
The reactor coolant contains radioactivity that, when released to the drywell, can be detected by the gaseous or particulate drywell atmospheric radioactivity monitor. Only one of the two detectors is required to be OPERABLE. Radioactivity detection systems are included for monitoring both particulate and gaseous activities because of their sensitivities and rapid responses to RCS LEAKAGE, but have recognized limitations. 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. If there are few fuel element cladding defects and low levels of activation products, it may not be possible for the gaseous or particulate drywell atmospheric radioactivity monitors to detect a 1 gpm increase within 1 hour during normal operation. However, the gaseous or particulate drywell atmospheric radioactivity monitor is OPERABLE when it is capable of detecting a 1 gpm increase in unidentified LEAKAGE within 1 hour given an RCS activity equivalent to that assumed in the design calculations for the monitors (Reference 6).
[An increase in humidity of the drywell atmosphere could indicate the release of water vapor to the drywell. Drywell air cooler condensate flow rate is instrumented to detect when there is an increase above the normal value by 1 gpm. The time required to detect a 1 gpm increase above the normal value varies based on environmental and system conditions and may take longer than 1 hour. This sensitivity is acceptable for containment air cooler condensate flow rate monitor OPERABILITY.]
The LCO is satisfied when monitors of diverse measurement means are available. Thus, the drywell floor drain sump monitoring system, in combination with a gaseous or particulate drywell atmospheric radioactivity monitor [and a drywell air cooler condensate flow rate monitoring system], provides an acceptable minimum.
APPLICABILITY      In MODES 1, 2, and 3, leakage detection systems are required to be OPERABLE to support LCO 3.4.5. This Applicability is consistent with that for LCO 3.4.5.
General Electric BWR/6 STS              B 3.4.7-3                                        Rev. 5.0
 
RCS Leakage Detection Instrumentation B 3.4.7 BASES ACTIONS              A.1 With the drywell floor drain sump monitoring system inoperable, no other form of sampling can provide the equivalent information to quantify leakage. However, the drywell atmospheric activity monitor [and the drywell air cooler condensate flow rate monitor] will provide indications of changes in leakage.
With the drywell floor drain sump monitoring system inoperable, but with RCS unidentified and total LEAKAGE being determined every 8 hours (SR 3.4.5.1), operation may continue for 30 days. The 30 day Completion Time of Required Action A.1 is acceptable, based on operating experience, considering the multiple forms of leakage detection that are still available.
B.1 and B.2 With both gaseous and particulate drywell atmospheric monitoring channels inoperable, grab samples of the drywell atmosphere shall be taken and analyzed to provide periodic leakage information. [Provided a sample is obtained and analyzed every 12 hours, the plant may be operated for up to 30 days to allow restoration of at least one of the required monitors.] [Provided a sample is obtained and analyzed every 12 hours, the plant may continue operation since at least one other form of drywell leakage detection (i.e., air cooler condensate flow rate monitor) is available.]
The 12 hour interval provides periodic information that is adequate to detect LEAKAGE. The 30 day Completion Time for restoration recognizes that at least one other form of leakage detection is available.
[ C.1 With the required drywell air cooler condensate flow rate monitoring system inoperable, SR 3.4.7.1 is performed every 8 hours to provide periodic information of activity in the drywell at a more frequent interval than the routine Frequency of SR 3.4.7.1. The 8 hour interval provides periodic information that is adequate to detect LEAKAGE and recognizes that other forms of leakage detection are available. However, this Required Action is modified by a Note that allows this action to be not applicable if the required drywell atmospheric monitoring system is inoperable. Consistent with SR 3.0.1, Surveillances are not required to be performed on inoperable equipment. ]
General Electric BWR/6 STS                B 3.4.7-4                                        Rev. 5.0
 
RCS Leakage Detection Instrumentation B 3.4.7 BASES ACTIONS (continued)
D.1, D.2, D.3.1, and D.3.2 With the drywell floor drain sump monitoring system [and the drywell air cooler condensate flow rate monitoring system] inoperable, the only means of detecting LEAKAGE is the drywell atmospheric gaseous radiation monitor. A Note clarifies this applicability of the Condition. The drywell atmospheric gaseous radiation monitor typically cannot detect a 1 gpm leak within one hour when RCS activity is low. In addition, this configuration does not provide the required diverse means of leakage detection. Indirect methods of monitoring RCS leakage must be implemented. Grab samples of the drywell atmosphere must be taken and analyzed and monitoring of RCS leakage by administrative means must be performed every 12 hours to provide alternate periodic information.
Administrative means of monitoring RCS leakage include monitoring and trending parameters that may indicate an increase in RCS leakage.
There are diverse alternative mechanisms from which appropriate indicators may be selected based on plant conditions. It is not necessary to utilize all of these methods, but a method or methods should be selected considering the current plant conditions and historical or expected sources of unidentified leakage. The administrative methods are [primary containment and drywell pressure, temperature, and humidity, Component Cooling Water System outlet temperatures and makeup, Reactor Recirculation System pump seal pressure and temperature and motor cooler temperature indications, Drywell cooling fan outlet temperatures, Reactor Building Chiller amperage, Control Rod Drive System flange temperatures, and Safety Relief Valves tailpipe temperature, flow, or pressure.] These indications, coupled with the atmospheric grab samples, are sufficient to alert the operating staff to an unexpected increase in unidentified LEAKAGE.
The 12 hour interval is sufficient to detect increasing RCS leakage. The Required Action provides 7 days to restore another RCS leakage monitor to OPERABLE status to regain the intended leakage detection diversity.
The 7 day Completion Time ensures that the plant will not be operated in a degraded configuration for a lengthy time period.
[ E.1 and E.2 With both the gaseous and particulate drywell atmospheric monitor channels and the drywell air cooler condensate flow rate monitor inoperable, the only means of detecting LEAKAGE is the drywell floor drain sump monitor. This Condition does not provide the required diverse General Electric BWR/6 STS                B 3.4.7-5                                        Rev. 5.0
 
RCS Leakage Detection Instrumentation B 3.4.7 BASES ACTIONS (continued) 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 Time ensures that the plant will not be operated in a degraded configuration for a lengthy time period.]
F.1 and F.2 If any Required Action of Condition A, B, [C, D or E] cannot be 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 3 within 12 hours and to MODE 4 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions in an orderly manner and without challenging plant systems.
G.1 With all required monitors inoperable, no required automatic means of monitoring LEAKAGE are available, and immediate plant shutdown in accordance with LCO 3.0.3 is required.
General Electric BWR/6 STS            B 3.4.7-6                                        Rev. 5.0
 
RCS Leakage Detection Instrumentation B 3.4.7 BASES SURVEILLANCE        SR 3.4.7.1 REQUIREMENTS This SR requires the performance of a CHANNEL CHECK of the required drywell atmospheric monitoring system. The check gives reasonable confidence that the channel is operating properly. [ The Frequency of 12 hours is based on instrument reliability and is reasonable for detecting off normal conditions.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.4.7.2 This SR requires the performance of a CHANNEL FUNCTIONAL TEST of the required RCS leakage detection instrumentation. The test ensures that the monitors can perform their function in the desired manner. The test also 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 31 days considers instrument reliability, and operating experience has shown it proper for detecting degradation.
General Electric BWR/6 STS                B 3.4.7-7                                                      Rev. 5.0
 
RCS Leakage Detection Instrumentation B 3.4.7 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.4.7.3 This SR requires the performance of a CHANNEL CALIBRATION of the required RCS leakage detection instrumentation channels. The calibration verifies the accuracy of the instrument string, including the instruments located inside the drywell. [ The Frequency of [18] months is a typical refueling cycle and considers channel reliability.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
Operating experience has proven this Frequency is acceptable.
REFERENCES          1. 10 CFR 50, Appendix A, GDC 30.
: 2. Regulatory Guide 1.45, Revision 0, "Reactor Coolant Pressure Boundary Leakage Detection Systems," May 1973.
: 3. GEAP-5620, April 1968.
: 4. NUREG-75/067, October 1975.
: 5. FSAR, Section [5.2.5.5.3].
General Electric BWR/6 STS                B 3.4.7-8                                                      Rev. 5.0
 
RCS Leakage Detection Instrumentation B 3.4.7 BASES REFERENCES (continued)
: 6. FSAR, Section [5.2.5.2].
General Electric BWR/6 STS          B 3.4.7-9                                Rev. 5.0
 
RCS Specific Activity B 3.4.8 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.8 RCS Specific Activity BASES BACKGROUND          During circulation, the reactor coolant acquires radioactive materials due to release of fission products from fuel leaks into the coolant and activation of corrosion products in the reactor coolant. These radioactive materials in the coolant can plate out in the RCS, and, at times, an accumulation will break away to spike the normal level of radioactivity.
The release of coolant during a Design Basis Accident (DBA) could send radioactive materials into the environment.
Limits on the maximum allowable level of radioactivity in the reactor coolant are established to ensure, in the event of a release of any radioactive material to the environment during a DBA, radiation doses are maintained within the limits of 10 CFR 100 (Ref. 1).
This LCO contains iodine specific activity limits. The iodine isotopic activities per gram of reactor coolant are expressed in terms of a DOSE EQUIVALENT I-131. The allowable levels are intended to limit the 2 hour radiation dose to an individual at the site boundary to a small fraction of the 10 CFR 100 limit.
APPLICABLE          Analytical methods and assumptions involving radioactive material in the SAFETY              primary coolant are presented in the FSAR (Ref. 2). The specific activity ANALYSES            in the reactor coolant (the source term) is an initial condition for evaluation of the consequences of an accident due to a main steam line break (MSLB) outside containment. No fuel damage is postulated in the MSLB accident, and the release of radioactive material to the environment is assumed to end when the main steam isolation valves (MSIVs) close completely.
This MSLB release forms the basis for determining offsite doses (Ref. 2).
The limits on the specific activity of the primary coolant ensure that the 2 hour thyroid and whole body doses at the site boundary, resulting from an MSLB outside containment during steady state operation, will not exceed 10% of the dose guidelines of 10 CFR 100.
The limits on specific activity are values from a parametric evaluation of typical site locations. These limits are conservative because the evaluation considered more restrictive parameters than for a specific site, such as the location of the site boundary and the meteorological conditions of the site.
RCS specific activity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS              B 3.4.8-1                                        Rev. 5.0
 
RCS Specific Activity B 3.4.8 BASES LCO                The specific iodine activity is limited to  [0.2] &#xb5;Ci/gm DOSE EQUIVALENT I-131. This limit ensures the source term assumed in the safety analysis for the MSLB is not exceeded, so any release of radioactivity to the environment during an MSLB is less than a small fraction of the 10 CFR 100 limits.
APPLICABILITY      In MODE 1, and MODES 2 and 3 with any main steam line not isolated, limits on the primary coolant radioactivity are applicable since there is an escape path for release of radioactive material from the primary coolant to the environment in the event of an MSLB outside of primary containment.
In MODES 2 and 3 with the main steam lines isolated, such limits do not apply since an escape path does not exist. In MODES 4 and 5, no limits are required since the reactor is not pressurized and the potential for leakage is reduced.
ACTIONS            A.1 and A.2 When the reactor coolant specific activity exceeds the LCO DOSE EQUIVALENT I-131 limit, but is  4.0 &#xb5;Ci/gm, samples must be analyzed for DOSE EQUIVALENT I-131 at least once every 4 hours. In addition, the specific activity must be restored to the LCO limit within 48 hours.
The Completion Time of once every 4 hours is based on the time needed to take and analyze a sample. The 48 hour Completion Time to restore the activity level provides a reasonable time for temporary coolant activity increases (iodine spikes or crud bursts) to be cleaned up with the normal processing systems.
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, B.2.1, B.2.2.1, and B.2.2.2 If the DOSE EQUIVALENT I-131 cannot be restored to  [0.2] &#xb5;Ci/gm within 48 hours, or if at any time it is > [4.0] &#xb5;Ci/gm, it must be determined at least every 4 hours and all the main steam lines must be isolated within 12 hours. Isolating the main steam lines precludes the possibility of releasing radioactive material to the environment in an amount that is more than a small fraction of the requirements of 10 CFR 100 during a postulated MSLB accident.
General Electric BWR/6 STS              B 3.4.8-2                                          Rev. 5.0
 
RCS Specific Activity B 3.4.8 BASES ACTIONS (continued)
Alternately, the plant can be brought to MODE 3 within 12 hours and to MODE 4 within 36 hours. This option is provided for those instances when isolation of main steam lines is not desired (e.g., due to the decay heat loads). In MODE 4, the requirements of the LCO are no longer applicable.
The Completion Time of once every 4 hours is the time needed to take and analyze a sample. The 12 hour Completion Time is reasonable, based on operating experience, to isolate the main steam lines in an orderly manner and without challenging plant systems. Also, the allowed Completion Times for Required Actions B.2.2.1 and B.2.2.2 for bringing the plant to MODES 3 and 4 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 3.4.8.1 REQUIREMENTS This Surveillance is performed to ensure iodine remains within limit during normal operation. [ The 7 day Frequency is adequate to trend changes in the iodine activity level.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
This SR is modified by a Note that requires this Surveillance to be performed only in MODE 1 because the level of fission products generated in other MODES is much less.
REFERENCES          1. 10 CFR 100.11, 1973.
: 2. FSAR, Section [15.1.40].
General Electric BWR/6 STS                B 3.4.8-3                                                      Rev. 5.0
 
RHR Shutdown Cooling System - Hot Shutdown B 3.4.9 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.9 Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown BASES BACKGROUND          Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat must be removed to reduce the temperature of the reactor coolant to  200&deg;F. This decay heat removal is in preparation for performing refueling or maintenance operations, or for keeping the reactor in the Hot Shutdown condition.
The two redundant, manually controlled shutdown cooling subsystems of the RHR System provide decay heat removal. Each loop consists of a motor driven pump, two heat exchangers in series, and associated piping and valves. Both loops have a common suction from the same recirculation loop. Each pump discharges the reactor coolant, after circulation through the respective heat exchanger, to the reactor via separate feedwater lines or to the reactor via the LPCI injection path. The RHR heat exchangers transfer heat to the Standby Service Water System (LCO 3.7.1, "[Standby Service Water (SSW)] System and [Ultimate Heat Sink (UHS)]").
APPLICABLE          Decay heat removal by the RHR System in the shutdown cooling mode is SAFETY              not required for mitigation of any event or accident evaluated in the ANALYSES            safety analyses. Decay heat removal is, however, an important safety function that must be accomplished or core damage could result. The RHR Shutdown Cooling System satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).
LCO                Two RHR shutdown cooling subsystems are required to be OPERABLE, and, when no recirculation pump is in operation, one shutdown cooling subsystem must be in operation. An OPERABLE RHR shutdown cooling subsystem consists of one OPERABLE RHR pump, two heat exchangers in series, and the associated piping and valves. Each shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or local) in the shutdown cooling mode for removal of decay heat.
In MODE 3, one RHR shutdown cooling subsystem can provide the required cooling, but two subsystems are required to be OPERABLE to provide redundancy. Operation of one subsystem can maintain or reduce the reactor coolant temperature as required. However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required.
Management of gas voids is important to RHR Shutdown Cooling System OPERABILITY.
General Electric BWR/6 STS              B 3.4.9-1                                      Rev. 5.0
 
RHR Shutdown Cooling System - Hot Shutdown B 3.4.9 BASES LCO (continued)
Note 1 permits both RHR shutdown cooling subsystems and recirculation pumps to be removed from operation for a period of 2 hours in an 8 hour period. Note 2 allows one RHR shutdown cooling subsystem to be inoperable for up to 2 hours for performance of surveillance tests. These tests may be on the affected RHR System or on some other plant system or component that necessitates placing the RHR System in an inoperable status during the performance. This is permitted because the core heat generation can be low enough and the heatup rate slow enough to allow some changes to the RHR subsystems or other operations requiring RHR flow interruption and loss of redundancy.
APPLICABILITY      In MODE 3 with reactor steam dome pressure below the RHR cut in permissive pressure (i.e., the actual pressure at which the interlock resets) the RHR Shutdown Cooling System may be operated in the shutdown cooling mode to remove decay heat to reduce or maintain coolant temperature. Otherwise, a recirculation pump is required to be in operation.
In MODES 1 and 2, and in MODE 3 with reactor steam dome pressure greater than or equal to the RHR cut in permissive pressure, this LCO is not applicable. Operation of the RHR System in the shutdown cooling mode is not allowed above this pressure because the RCS pressure may exceed the design pressure of the shutdown cooling piping. Decay heat removal at reactor pressures greater than or equal to the RHR cut in permissive pressure is typically accomplished by condensing the steam in the main condenser. Additionally, in MODE 2 below this pressure, the OPERABILITY requirements for the Emergency Core Cooling Systems (ECCS) (LCO 3.5.1, "ECCS - Operating") do not allow placing the RHR shutdown cooling subsystem into operation.
The requirements for decay heat removal in MODES 4 and 5 are discussed in LCO 3.4.10, "Residual Heat Removal (RHR) Shutdown Cooling System - Cold Shutdown," LCO 3.9.8, "Residual Heat Removal (RHR) - High Water Level," and LCO 3.9.9, "Residual Heat Removal (RHR) - Low Water Level."
ACTIONS            A Note has been provided to modify the ACTIONS related to RHR shutdown cooling subsystems. Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for General Electric BWR/6 STS              B 3.4.9-2                                        Rev. 5.0
 
RHR Shutdown Cooling System - Hot Shutdown B 3.4.9 BASES ACTIONS (continued) inoperable shutdown cooling subsystems provide appropriate compensatory measures for separate inoperable shutdown cooling subsystems. As such, a Note has been provided that allows separate Condition entry for each inoperable RHR shutdown cooling subsystem.
A.1 With one required RHR shutdown cooling subsystem inoperable for decay heat removal, except as permitted by LCO Note 2, the overall reliability is reduced, however, because a single failure in the OPERABLE subsystem could result in reduced RHR shutdown cooling capability.
Therefore an alternate method of decay heat removal must be provided.
The required cooling capacity of the alternate method should be sufficient to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability. Alternate methods that can be used include (but are not limited to) the Reactor Water Cleanup System, or an inoperable but functional RHR shutdown cooling subsystem.
B.1 If the required alternate method of decay heat removal cannot be verified within one hour, immediate action must be taken to restore the inoperable RHR shutdown cooling subsystem to OPERABLE status. The Required Action will restore redundant decay heat removal paths. The immediate Completion Time reflects the importance of maintaining the availability of two paths for heat removal.
C.1 With both [required] RHR shutdown cooling subsystems inoperable, an alternate method of decay heat removal must be provided in addition to that provided for the initial RHR shutdown cooling subsystem inoperability. This re-establishes backup decay heat removal capabilities, similar to the requirements of the LCO. The 1 hour Completion Time is based on the decay heat removal function and the probability of a loss of the available decay heat removal capabilities. Furthermore, verification of the functional availability of these alternate method(s) must be reconfirmed every 24 hours thereafter. This will provide assurance of continued heat removal capability.
General Electric BWR/6 STS              B 3.4.9-3                                      Rev. 5.0
 
RHR Shutdown Cooling System - Hot Shutdown B 3.4.9 BASES ACTIONS (continued)
The required cooling capacity of the alternate method should be sufficient to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability. Alternate methods that can be used include (but are not limited to) the Reactor Water Cleanup System, or an inoperable but functional RHR shutdown cooling subsystem.
D.1 If the required alternate methods of decay heat removal cannot be verified within one hour, immediate action must be taken to restore at least one RHR shutdown cooling subsystem to OPERABLE status. The immediate Completion Time reflects the importance of restoring a method of heat removal.
Required Action D.1 is modified by a Note indicating that all required MODE changes to MODE 4 may be suspended until one RHR shutdown cooling subsystem is restored to OPERABLE status. In this case, LCO 3.0.3 and other Required Actions directing entry into MODE 4 could force the unit into a less safe condition in which there may be no adequate means to remove decay heat. It is more appropriate to allow the restoration of one of the RHR shutdown cooling subsystems before requiring entry into a condition in which that subsystem would be needed and exiting a condition where other sources of cooling are available.
When at least one RHR subsystem is restored to OPERABLE status, the Completion Times of LCO 3.0.3 or other Required Actions resume at the point at which they were suspended.
E.1, E.2, and E.3 With no RHR shutdown cooling subsystem and no recirculation pump in operation, except as is permitted by LCO Note 1, reactor coolant circulation by the RHR shutdown cooling subsystem or one recirculation pump must be restored without delay.
Until RHR or recirculation pump operation is re-established, an alternate method of reactor coolant circulation must be placed into service. This will provide the necessary circulation for monitoring coolant temperature.
The 1 hour Completion Time is based on the coolant circulation function and is modified such that the 1 hour is applicable separately for each occurrence involving a loss of coolant circulation. Furthermore, verification of the functioning of the alternate method must be reconfirmed every 12 hours thereafter. This will provide assurance of continued temperature monitoring capability.
General Electric BWR/6 STS              B 3.4.9-4                                      Rev. 5.0
 
RHR Shutdown Cooling System - Hot Shutdown B 3.4.9 BASES ACTIONS (continued)
During the period when the reactor coolant is being circulated by an alternate method (other than by the required RHR shutdown cooling subsystem or recirculation pump), the reactor coolant temperature and pressure must be periodically monitored to ensure proper function of the alternate method. The once per hour Completion Time is deemed appropriate.
SURVEILLANCE        SR 3.4.9.1 REQUIREMENTS This Surveillance verifies that one RHR shutdown cooling subsystem or recirculation pump is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. [ The Frequency of 12 hours is sufficient in view of other visual and audible indications available to the operator for monitoring the RHR subsystem in the control room.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
This Surveillance is modified by a Note allowing sufficient time to align the RHR System for shutdown cooling operation after clearing the pressure interlock that isolates the system, or for placing a recirculation pump in operation. The Note takes exception to the requirements of the Surveillance being met (i.e., forced coolant circulation is not required for this initial 2 hour period), which also allows entry into the Applicability of this Specification in accordance with SR 3.0.4 since the Surveillance will not be "not met" at the time of entry into the Applicability.
SR 3.4.9.2 RHR Shutdown Cooling System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR shutdown cooling subsystems and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.
General Electric BWR/6 STS                B 3.4.9-5                                                      Rev. 5.0
 
RHR Shutdown Cooling System - Hot Shutdown B 3.4.9 BASES SURVEILLANCE REQUIREMENTS (continued)
Selection of RHR Shutdown Cooling System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration.
Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.
The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the Surveillance is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RHR Shutdown Cooling System is not rendered inoperable by the accumulated gas (i.e., the system is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits.
RHR Shutdown Cooling System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.
General Electric BWR/6 STS              B 3.4.9-6                                        Rev. 5.0
 
RHR Shutdown Cooling System - Hot Shutdown B 3.4.9 BASES SURVEILLANCE REQUIREMENTS (continued)
This SR is modified by a Note that states the SR is not required to be performed until 12 hours after reactor steam dome pressure is < [the RHR cut in permissive pressure]. In a rapid shutdown, there may be insufficient time to verify all susceptible locations prior to entering the Applicability.
[ The 31 day Frequency takes into consideration the gradual nature of gas accumulation in the RHR Shutdown Cooling System piping and the procedural controls governing system operation.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          None.
General Electric BWR/6 STS                B 3.4.9-7                                                      Rev. 5.0
 
RHR Shutdown Cooling System - Cold Shutdown B 3.4.10 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.10 Residual Heat Removal (RHR) Shutdown Cooling System - Cold Shutdown BASES BACKGROUND          Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat must be removed to maintain the temperature of the reactor coolant at  200&deg;F. This decay heat removal is in preparation for performing refueling or maintenance operations, or for keeping the reactor in the Cold Shutdown condition.
The two redundant, manually controlled shutdown cooling subsystems of the RHR System provide decay heat removal. Each loop consists of a motor driven pump, two heat exchangers in series, and associated piping and valves. Both loops have a common suction from the same recirculation loop. Each pump discharges the reactor coolant, after circulation through the respective heat exchanger, to the reactor via separate feedwater lines or to the reactor via the LPCI injection path. The RHR heat exchangers transfer heat to the Standby Service Water System.
APPLICABLE          Decay heat removal by the RHR System in the shutdown cooling mode is SAFETY              not required for mitigation of any event or accident evaluated in the ANALYSES            safety analyses. Decay heat removal is, however, an important safety function that must be accomplished or core damage could result. The RHR Shutdown Cooling System satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).
LCO                Two RHR shutdown cooling subsystems are required to be OPERABLE, and, when no recirculation pump is in operation, one RHR shutdown cooling subsystem must be in operation. An OPERABLE RHR shutdown cooling subsystem consists of one OPERABLE RHR pump, two heat exchangers in series, and the associated piping and valves. Each shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or local) in the shutdown cooling mode for removal of decay heat. In MODE 4, one RHR shutdown cooling subsystem can provide the required cooling, but two subsystems are required to be OPERABLE to provide redundancy. Operation of one subsystem can maintain and reduce the reactor coolant temperature as required. However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required. Management of gas voids is important to RHR Shutdown Cooling System OPERABILITY.
General Electric BWR/6 STS            B 3.4.10-1                                      Rev. 5.0
 
RHR Shutdown Cooling System - Cold Shutdown B 3.4.10 BASES LCO (continued)
Note 1 permits both RHR shutdown cooling subsystems and recirculation pumps to be removed from operation for a period of 2 hours in an 8 hour period. Note 2 allows one RHR shutdown cooling subsystem to be inoperable for up to 2 hours for performance of surveillance tests. These tests may be on the affected RHR System or on some other plant system or component that necessitates placing the RHR System in an inoperable status during the performance. This is permitted because the core heat generation can be low enough and the heatup rate slow enough to allow some changes to the RHR subsystems or other operations requiring RHR flow interruption and loss of redundancy.
APPLICABILITY      In MODE 4, the RHR System may be operated in the shutdown cooling mode to remove decay heat to maintain coolant temperature below 200&deg;F. Otherwise, a recirculation pump is required to be in operation.
In MODES 1 and 2, and in MODE 3 with reactor steam dome pressure greater than or equal to the RHR cut in permissive pressure, this LCO is not applicable. Operation of the RHR System in the shutdown cooling mode is not allowed above this pressure because the RCS pressure may exceed the design pressure of the shutdown cooling piping. Decay heat removal at reactor pressures greater than or equal to the RHR cut in permissive pressure is typically accomplished by condensing the steam in the main condenser. Additionally, in MODE 2 below this pressure, the OPERABILITY requirements for the Emergency Core Cooling Systems (ECCS) (LCO 3.5.1, "ECCS - Operating") do not allow placing the RHR shutdown cooling subsystem into operation.
The requirements for decay heat removal in MODE 3 below the cut in permissive pressure and in MODE 5 are discussed in LCO 3.4.9, "Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown," LCO 3.9.8, "Residual Heat Removal (RHR) - High Water Level," and LCO 3.9.9, "Residual Heat Removal (RHR) - Low Water Level."
ACTIONS            A Note has been provided to modify the ACTIONS related to RHR shutdown cooling subsystems. Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable shutdown cooling subsystems provided appropriate compensatory measures for separate inoperable shutdown cooling subsystems. As such, a Note has been provided that allows separate Condition entry for each inoperable RHR shutdown cooling subsystem.
General Electric BWR/6 STS              B 3.4.10-2                                        Rev. 5.0
 
RHR Shutdown Cooling System - Cold Shutdown B 3.4.10 BASES ACTIONS (continued)
A.1 With one of the two required RHR shutdown cooling subsystems inoperable except as permitted by LCO Note 2, the remaining subsystem is capable of providing the required decay heat removal. However, the overall reliability is reduced. Therefore, an alternate method of decay heat removal must be provided. With both RHR shutdown cooling subsystems inoperable, an alternate method of decay heat removal must be provided in addition to that provided for the initial RHR shutdown cooling subsystem inoperability. This re-establishes backup decay heat removal capabilities, similar to the requirements of the LCO. The 1 hour Completion Time is based on the decay heat removal function and the probability of a loss of the available decay heat removal capabilities.
Furthermore, verification of the functional availability of these alternate method(s) must be reconfirmed every 24 hours thereafter. This will provide assurance of continued heat removal capability.
The required cooling capacity of the alternate method should be sufficient to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to the alternate method capability. Alternate methods that can be used include (but are not limited to) the Spent Fuel Pool Cooling System, the Reactor Water Cleanup System, or an inoperable but functional RHR shutdown cooling subsystem.
B.1 If the required alternate method(s) of decay heat removal cannot be verified within one hour, immediate action must be taken to restore the inoperable RHR shutdown cooling subsystem(s) to OPERABLE status.
The Required Action will restore redundant decay heat removal paths.
The immediate Completion Time reflects the importance of maintaining the availability of two paths for heat removal.
C.1 and C.2 With no RHR shutdown cooling subsystem and no recirculation pump in operation, except as is permitted by LCO Note 1, and until RHR or recirculation pump operation is re-established, an alternate method of reactor coolant circulation must be placed into service. This will provide the necessary circulation for monitoring coolant temperature. The 1 hour General Electric BWR/6 STS              B 3.4.10-3                                        Rev. 5.0
 
RHR Shutdown Cooling System - Cold Shutdown B 3.4.10 BASES ACTIONS (continued)
Completion Time is based on the coolant circulation function and is modified such that the 1 hour is applicable separately for each occurrence involving a loss of coolant circulation. Furthermore, verification of the functioning of the alternate method must be reconfirmed every 12 hours thereafter. This will provide assurance of continued temperature monitoring capability.
During the period when the reactor coolant is being circulated by an alternate method (other than by the required RHR shutdown cooling system or recirculation pump), the reactor coolant temperature and pressure must be periodically monitored to ensure proper function of the alternate method. The once per hour Completion Time is deemed appropriate.
SURVEILLANCE        SR 3.4.10.1 REQUIREMENTS This Surveillance verifies that one RHR shutdown cooling subsystem or recirculation pump is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. [ The Frequency of 12 hours is sufficient in view of other visual and audible indications available to the operator for monitoring the RHR subsystem in the control room.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.4.10.2 RHR Shutdown Cooling System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR shutdown cooling subsystems and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.
General Electric BWR/6 STS                B 3.4.10-4                                                      Rev. 5.0
 
RHR Shutdown Cooling System - Cold Shutdown B 3.4.10 BASES SURVEILLANCE REQUIREMENTS (continued)
Selection of RHR Shutdown Cooling System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration.
Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.
The RHR Shutdown Cooling System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the Surveillance is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RHR Shutdown Cooling System is not rendered inoperable by the accumulated gas (i.e., the system is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits.
RHR Shutdown Cooling System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.
[ The 31 day Frequency takes into consideration the gradual nature of gas accumulation in the RHR Shutdown Cooling System piping and the procedural controls governing system operation.
General Electric BWR/6 STS            B 3.4.10-5                                        Rev. 5.0
 
RHR Shutdown Cooling System - Cold Shutdown B 3.4.10 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          None.
General Electric BWR/6 STS                B 3.4.10-6                                                      Rev. 5.0
 
RCS P/T Limits B 3.4.11 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.11 RCS Pressure and Temperature (P/T) Limits BASES BACKGROUND          All components of the RCS are designed to withstand effects of cyclic loads due to system pressure and temperature changes. These loads are introduced by startup (heatup) and shutdown (cooldown) operations, power transients, and reactor trips. This LCO limits the pressure and temperature changes during RCS heatup and cooldown, within the design assumptions and the stress limits for cyclic operation.
The PTLR contains P/T limit curves for heatup, cooldown, and inservice leak and hydrostatic testing, and data for the maximum rate of change of reactor coolant temperature. The heatup curve provides limits for both heatup and criticality.
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. Therefore, the LCO limits apply mainly to the vessel.
10 CFR 50, Appendix G (Ref. 1), requires the establishment of P/T limits for material fracture toughness requirements of the RCPB materials.
Reference 1 requires an adequate margin to brittle failure during normal operation, anticipated operational occurrences, and system hydrostatic tests. It mandates the use of the American Society of Mechanical Engineers (ASME) Code, Section III, Appendix G (Ref. 2).
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. 3) and 10 CFR 50, Appendix H (Ref. 4). The operating P/T limit curves will be adjusted, as necessary, based on the evaluation findings and the recommendations of Reference 5.
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 General Electric BWR/6 STS            B 3.4.11-1                                        Rev. 5.0
 
RCS P/T Limits B 3.4.11 BASES BACKGROUND (continued)
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 limits include the Reference 1 requirement that they be at least 40&deg;F above the heatup curve or the cooldown curve and not lower than the minimum permissible temperature for the inservice leak and hydrostatic testing.
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, a condition that is unanalyzed.
Reference 7 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.
RCS P/T limits satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO                The elements of this LCO are:
: a. RCS pressure, temperature, and heatup or cooldown rate are within the limits specified in the PTLR, during RCS heatup, cooldown, and inservice leak and hydrostatic testing,
: b. The temperature difference between the reactor vessel bottom head coolant and the reactor pressure vessel (RPV) coolant is within the limit of the PTLR during recirculation pump startup, and during increases in THERMAL POWER or loop flow while operating at low THERMAL POWER or loop flow, General Electric BWR/6 STS              B 3.4.11-2                                        Rev. 5.0
 
RCS P/T Limits B 3.4.11 BASES LCO (continued)
: c. The temperature difference between the reactor coolant in the respective recirculation loop and in the reactor vessel meets the limit of the PTLR during recirculation pump startup, and during increases in THERMAL POWER or loop flow while operating at low THERMAL POWER or loop flow,
: d. RCS pressure and temperature are within the criticality limits specified in the PTLR, prior to achieving criticality, and
: e. The reactor vessel flange and the head flange temperatures are within the limits of the PTLR when tensioning the reactor vessel head bolting studs.
These limits define allowable operating regions and permit a large number of operating cycles while also providing a wide margin to nonductile failure.
The rate of change of temperature limits control the thermal gradient through the vessel wall and are used as inputs for calculating the heatup, cooldown, and inservice leak and hydrostatic 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.
Violation of the limits places the reactor vessel outside of the bounds of the stress analyses and can increase stresses in other RCS components.
The consequences depend on several factors, as follows:
: a. The severity of the departure from the allowable operating pressure temperature 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 potential for violating a P/T limit exists at all times. For example, P/T limit violations could result from ambient temperature conditions that result in the reactor vessel metal temperature being less than the minimum allowed temperature for boltup. Therefore, this LCO is applicable even when fuel is not loaded in the core.
General Electric BWR/6 STS              B 3.4.11-3                                        Rev. 5.0
 
RCS P/T Limits B 3.4.11 BASES ACTIONS            A.1 and A.2 Operation outside the P/T limits while in MODE 1, 2, or 3 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 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 if continued operation is desired. 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 of a mild violation. More severe violations may require special, event specific stress analyses or inspections. A favorable evaluation must be completed if continued operation is desired.
Condition A is modified by a Note requiring Required Action A.2 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.
B.1 and B.2 If a Required Action and associated Completion Time of Condition A are not met, the plant must be brought to a lower MODE because either the RCS remained in an unacceptable P/T region for an extended period of increased stress, or 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 the reduced pressure and temperature conditions, the possibility of propagation of undetected flaws is decreased.
General Electric BWR/6 STS            B 3.4.11-4                                      Rev. 5.0
 
RCS P/T Limits B 3.4.11 BASES ACTIONS (continued)
Pressure and temperature are reduced by bringing the plant to at least MODE 3 within 12 hours and to MODE 4 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.
C.1 and C.2 Operation outside the P/T limits in other than MODES 1, 2, and 3 (including defueled conditions) must be corrected so that the RCPB is returned to a condition that has been verified by stress analyses. The Required Action must be initiated without delay and continued until the limits are restored.
Besides restoring the P/T limit parameters to within limits, an evaluation is required to determine if RCS operation is allowed. This evaluation must verify that the RCPB integrity is acceptable and must be completed before approaching criticality or heating up to > 200&deg;F. Several methods may be used, including comparison with pre-analyzed transients, new analyses, or inspection of the components. ASME Section XI, Appendix E (Ref. 6), may be used to support the evaluation; however, its use is restricted to evaluation of the beltline.
SURVEILLANCE        SR 3.4.11.1 REQUIREMENTS Verification that operation is within PTLR limits is required 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 of minor deviations.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.4.11-5                                                      Rev. 5.0
 
RCS P/T Limits B 3.4.11 BASES SURVEILLANCE REQUIREMENTS (continued)
Surveillance for heatup, cooldown, or inservice leakage and hydrostatic testing may be discontinued when the criteria given in the relevant plant procedure for ending the activity are satisfied.
This SR has been modified by a Note that requires this Surveillance to be performed only during system heatup and cooldown operations and inservice leakage and hydrostatic testing.
SR 3.4.11.2 A separate limit is used when the reactor is approaching criticality.
Consequently, the RCS pressure and temperature must be verified within the appropriate limits before withdrawing control rods that will make the reactor critical.
Performing the Surveillance within 15 minutes before control rod withdrawal for the purpose of achieving criticality provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the control rod withdrawal.
SR 3.4.11.3, SR 3.4.11.4, [SR 3.4.11.5, and SR 3.4.11.6]
Differential temperatures within the applicable PTLR limits ensure that thermal stresses resulting from the startup of an idle recirculation pump will not exceed design allowances. [In addition, compliance with these limits ensures that the assumptions of the analysis for the startup of an idle recirculation loop (Ref. 8) are satisfied.]
[ Performing the Surveillance within 15 minutes before starting the idle recirculation pump provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the idle pump start. ]
[ Limiting differential temperatures within the applicable limits during a THERMAL POWER increase or recirculation flow increase in single loop operation, while THERMAL POWER  30% RTP or operating loop flow 50% of rated loop flow, ensure that resulting thermal stresses will not exceed design allowances.
General Electric BWR/6 STS              B 3.4.11-6                                        Rev. 5.0
 
RCS P/T Limits B 3.4.11 BASES SURVEILLANCE REQUIREMENTS (continued)
Performing the Surveillance within 15 minutes before starting the idle recirculation pump, THERMAL POWER increase during single loop operation, or recirculation flow increase during single loop operation, provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the idle pump start, power increase, or flow increase. ]
An acceptable means of demonstrating compliance with the temperature differential requirement in SR 3.4.11.4 [and SR 3.4.11.6] is to compare the temperatures of the operating recirculation loop and the idle loop.
[SR 3.4.11.3 has] These SRs have been modified by [a Note] [Notes]
that require[s] the Surveillance to be met only in [MODES 1, 2, 3, and 4 with reactor steam dome pressure  25 psig]. In MODE 5, the overall stress on limiting components is lower; therefore, T limits are not required [for SRs 3.4.11.3 and 3.4.11.4 in MODE 5. In MODES 3, 4, and 5, THERMAL POWER increases are not possible, and recirculation flow increases will not result in additional stresses. Therefore, T limits are only required for SRs 3.4.11.5 and 3.4.11.6 in MODES 1 and 2]. The
[Note][Notes] also state that the SR is only required to be met during the event of concern (e.g., pump startup, power increase or flow increase) since this is when the stresses occur.
SR 3.4.11.7, SR 3.4.11.8, and SR 3.4.11.9 Limits on the reactor vessel flange and head flange temperatures are generally bounded by the other P/T limits during system heatup and cooldown. However, operations approaching MODE 4 from MODE 5 and in MODE 4 with RCS temperature less than or equal to certain specified values require assurance that these temperatures meet the LCO limits.
The flange temperatures must be verified to be above the limits before and while tensioning the vessel head bolting studs to ensure that once the head is tensioned the limits are satisfied. When in MODE 4 with RCS temperature  80&deg;F, checks of the flange temperatures are required because of the reduced margin to the limits. When in MODE 4 with RCS temperature  100&deg;F, monitoring of the flange temperature is required to ensure the temperatures are within the limits specified in the PTLR.
General Electric BWR/6 STS            B 3.4.11-7                                        Rev. 5.0
 
RCS P/T Limits B 3.4.11 BASES SURVEILLANCE REQUIREMENTS (continued)
[ The 30 minute Frequency reflects the urgency of maintaining the temperatures within limits, and also limits the time that the temperature limits could be exceeded. The 12 hour Frequency is reasonable based on the rate of temperature change possible at these temperatures.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. 10 CFR 50, Appendix G.
: 2. ASME, Boiler and Pressure Vessel Code, Section III, Appendix G.
: 3. ASTM E 185-82, July 1982.
: 4. 10 CFR 50, Appendix H.
: 5. Regulatory Guide 1.99, Revision 2, May 1988.
: 6. ASME, Boiler and Pressure Vessel Code, Section XI, Appendix E.
: 7. NEDO-21778-A, December 1978.
[ 8. FSAR, Section [15.1.26]. ]
General Electric BWR/6 STS                  B 3.4.11-8                                                      Rev. 5.0
 
Reactor Steam Dome Pressure B 3.4.12 B 3.4 REACTOR COOLANT SYSTEM (RCS)
B 3.4.12 Reactor Steam Dome Pressure BASES BACKGROUND          The reactor steam dome pressure is an assumed initial condition of Design Basis Accidents (DBAs) and transients and is also an assumed value in the determination of compliance with reactor pressure vessel overpressure protection criteria.
APPLICABLE          The reactor steam dome pressure of  [1045] psig is an initial condition of SAFETY              the vessel overpressure protection analysis of Reference 1. This ANALYSES            analysis assumes an initial maximum reactor steam dome pressure and evaluates the response of the pressure relief system, primarily the safety/relief valves, during the limiting pressurization transient. The determination of compliance with the overpressure criteria is dependent on the initial reactor steam dome pressure; therefore, the limit on this pressure ensures that the assumptions of the overpressure protection analysis are conserved. Reference 2 also assumes an initial reactor steam dome pressure for the analysis of DBAs and transients used to determine the limits for fuel cladding integrity MCPR (see Bases for LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)") and 1%
cladding plastic strain (see Bases for LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)").
Reactor steam dome pressure satisfies the requirements of Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO                The specified reactor steam dome pressure limit of  [1045] psig ensures the plant is operated within the assumptions of the transient analyses.
Operation above the limit may result in a transient response more severe than analyzed.
APPLICABILITY      In MODES 1 and 2, the reactor steam dome pressure is required to be less than or equal to the limit. In these MODES, the reactor may be generating significant steam, and the DBAs and transients are bounding.
In MODES 3, 4, and 5, the limit is not applicable because the reactor is shut down. In these MODES, the reactor pressure is well below the required limit, and no anticipated events will challenge the overpressure limits.
General Electric BWR/6 STS            B 3.4.12-1                                        Rev. 5.0
 
Reactor Steam Dome Pressure B 3.4.12 BASES ACTIONS            A.1 With the reactor steam dome pressure greater than the limit, prompt action should be taken to reduce pressure to below the limit and return the reactor to operation within the bounds of the analyses. The 15 minute Completion Time is reasonable considering the importance of maintaining the pressure within limits. This Completion Time also ensures that the probability of an accident while pressure is greater than the limit is minimal. If the operator is unable to restore the reactor steam dome pressure to below the limit, then the reactor should be brought to MODE 3 to be within the assumptions of the transient analyses.
B.1 If the reactor steam dome pressure cannot be restored to within the limit within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours. The allowed Completion Time of 12 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 3.4.12.1 REQUIREMENTS Verification that reactor steam dome pressure is  [1045] psig ensures that the initial conditions of the DBAs and transients are met. [ Operating experience has shown the 12 hour Frequency to be sufficient for identifying trends and verifying operation within safety analyses assumptions.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [5.2.2.2.4].
: 2. FSAR, Section [15].
General Electric BWR/6 STS                B 3.4.12-2                                                      Rev. 5.0
 
ECCS - Operating B 3.5.1 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.1 ECCS - Operating BASES BACKGROUND          The ECCS is designed, in conjunction with the primary and secondary containment, to limit the release of radioactive materials to the environment following a loss of coolant accident (LOCA). The ECCS uses two independent methods (flooding and spraying) to cool the core during a LOCA. The ECCS network is composed of the High Pressure Core Spray (HPCS) System, the Low Pressure Core Spray (LPCS)
System, and the low pressure coolant injection (LPCI) mode of the Residual Heat Removal (RHR) System. The ECCS also consists of the Automatic Depressurization System (ADS). The suppression pool provides the required source of water for the ECCS. Although no credit is taken in the safety analyses for the condensate storage tank (CST), it is capable of providing a source of water for the HPCS System.
On receipt of an initiation signal, ECCS pumps automatically start; simultaneously the system aligns, and the pumps inject water, taken either from the CST or suppression pool, into the Reactor Coolant System (RCS) as RCS pressure is overcome by the discharge pressure of the ECCS pumps. Although the system is initiated, ADS action is delayed, allowing the operator to interrupt the timed sequence if the system is not needed. The HPCS pump discharge pressure almost immediately exceeds that of the RCS, and the pump injects coolant into the spray sparger above the core. If the break is small, HPCS will maintain coolant inventory, as well as vessel level, while the RCS is still pressurized. If HPCS fails, it is backed up by ADS in combination with LPCI and LPCS.
In this event, the ADS timed sequence would be allowed to time out and open the selected safety/relief valves (S/RVs), depressurizing the RCS and allowing the LPCI and LPCS to overcome RCS pressure and inject coolant into the vessel. If the break is large, RCS pressure initially drops rapidly, and the LPCI and LPCS systems cool the core.
Water from the break returns to the suppression pool where it is used again and again. Water in the suppression pool is circulated through a heat exchanger cooled by the Standby Service Water (SWS) System.
Depending on the location and size of the break, portions of the ECCS may be ineffective; however, the overall design is effective in cooling the core regardless of the size or location of the piping break. Although no credit is taken in the safety analysis for the RCIC System, it performs a similar function as HPCS but has reduced makeup capability.
Nevertheless, it will maintain inventory and cool the core, while the RCS is still pressurized, following a reactor pressure vessel (RPV) isolation.
General Electric BWR/6 STS              B 3.5.1-1                                        Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES BACKGROUND (continued)
All ECCS subsystems are designed to ensure that no single active component failure will prevent automatic initiation and successful operation of the minimum required ECCS subsystems.
The LPCS System (Ref. 1) consists of a motor driven pump, a spray sparger above the core, piping, and valves to transfer water from the suppression pool to the sparger. The LPCS System is designed to provide cooling to the reactor core when the reactor pressure is low.
Upon receipt of an initiation signal, the LPCS pump is automatically started when AC power is available. When the RPV pressure drops sufficiently, LPCS flow to the RPV begins. A full flow test line is provided to route water from and to the suppression pool to allow testing of the LPCS System without spraying water into the RPV.
LPCI is an independent operating mode of the RHR System. There are three LPCI subsystems. Each LPCI subsystem (Ref. 2) consists of a motor driven pump, piping, and valves to transfer water from the suppression pool to the core. Each LPCI subsystem has its own suction and discharge piping and separate vessel nozzle that connects with the core shroud through internal piping. The LPCI subsystems are designed to provide core cooling at low RPV pressure. Upon receipt of an initiation signal, each LPCI pump is automatically started (C pump immediately, when AC power is available, and A and B pumps approximately 5.25 seconds after AC power is available). When the RPV pressure drops sufficiently, LPCI flow to the RPV begins. RHR System valves in the LPCI flow path are automatically positioned to ensure the proper flow path for water from the suppression pool to inject into the core. A discharge test line is provided to route water from and to the suppression pool to allow testing of each LPCI pump without injecting water into the RPV.
The HPCS System (Ref. 3) consists of a single motor driven pump, a spray sparger above the core, and piping and valves to transfer water from the suction source to the sparger. Suction piping is provided from the CST and the suppression pool. Pump suction is normally aligned to the CST source to minimize injection of suppression pool water into the RPV. However, if the CST water supply is low or the suppression pool level is high, an automatic transfer to the suppression pool water source ensures a water supply for continuous operation of the HPCS System.
The HPCS System is designed to provide core cooling over a wide range of RPV pressures (0 psid to 1177 psid, vessel to suction source). Upon receipt of an initiation signal, the HPCS pump automatically starts (when AC power is available) and valves in the flow path begin to open. Since the HPCS System is designed to operate over the full range of expected RPV pressures, HPCS flow begins as soon as the necessary valves are General Electric BWR/6 STS              B 3.5.1-2                                        Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES BACKGROUND (continued) open. A full flow test line is provided to route water from and to the CST to allow testing of the HPCS System during normal operation without spraying water into the RPV.
The ECCS pumps are provided with minimum flow bypass lines, which discharge to the suppression pool. The valves in these lines automatically open to prevent pump damage due to overheating when other discharge line valves are closed or RPV pressure is greater than the LPCS or LPCI pump discharge pressures following system initiation.
To ensure rapid delivery of water to the RPV and to minimize water hammer effects, the ECCS discharge line "keep fill" systems are designed to maintain all pump discharge lines filled with water.
The ADS (Ref. 4) consists of 8 of the 20 S/RVs. It is designed to provide depressurization of the primary system during a small break LOCA if HPCS fails or is unable to maintain required water level in the RPV. ADS operation reduces the RPV pressure to within the operating pressure range of the low pressure ECCS subsystems (LPCS and LPCI), so that these subsystems can provide core cooling. Each ADS valve is supplied with pneumatic power from an air storage system, which consists of air accumulators and air receivers located in the drywell.
APPLICABLE          The ECCS performance is evaluated for the entire spectrum of break SAFETY              sizes for a postulated LOCA. The accidents for which ECCS operation is ANALYSES            required are presented in References 5, 6, and 7. The required analyses and assumptions are defined in 10 CFR 50 (Ref. 8), and the results of these analyses are described in Reference 9.
This LCO helps to ensure that the following acceptance criteria for the ECCS, established by 10 CFR 50.46 (Ref. 10), will be met following a LOCA assuming the worst case single active component failure in the ECCS:
: a. Maximum fuel element cladding temperature is  2200&deg;F,
: b. Maximum cladding oxidation is  0.17 times the total cladding thickness before oxidation,
: c. Maximum hydrogen generation from zirconium water reaction is 0.01 times the hypothetical amount that would be generated if all of the metal in the cladding surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react,
: d. The core is maintained in a coolable geometry, and
: e. Adequate long term cooling capability is maintained.
General Electric BWR/6 STS            B 3.5.1-3                                        Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES APPLICABLE SAFETY ANALYSES (continued)
The limiting single failures are discussed in Reference 11. For a large break LOCA, failure of ECCS subsystems in Division 1 (LPCS and LPCI-A) or Division 2 (LPCI-B and LPCI-C) due to failure of its associated diesel generator is, in general, the most severe failure. For a small break LOCA, HPCS System failure is the most severe failure. One ADS valve failure is analyzed as a limiting single failure for events requiring ADS operation. The remaining OPERABLE ECCS subsystems provide the capability to adequately cool the core and prevent excessive fuel damage.
The ECCS satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                Each ECCS injection/spray subsystem and eight ADS valves are required to be OPERABLE. The ECCS injection/spray subsystems are defined as the three LPCI subsystems, the LPCS System, and the HPCS System.
The low pressure ECCS injection/spray subsystems are defined as the LPCS System and the three LPCI subsystems. Management of gas voids is important to ECCS injection/spray subsystem OPERABILITY.
With less than the required number of ECCS subsystems OPERABLE during a limiting design basis LOCA concurrent with the worst case single failure, the limits specified in 10 CFR 50.46 (Ref. 10) could potentially be exceeded. All ECCS subsystems must therefore be OPERABLE to satisfy the single failure criterion required by 10 CFR 50.46 (Ref. 10).
[ As noted, LPCI subsystems may be considered OPERABLE during alignment and operation for decay heat removal when below the actual RHR cut in permissive pressure in MODE 3, if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable. Alignment and operation for decay heat removal includes when the required RHR pump is not operating or when the system is realigned from or to the RHR shutdown cooling mode. This allowance is necessary since the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. At these low pressures and decay heat levels, a reduced complement of ECCS subsystems should provide the required core cooling, thereby allowing operation of RHR shutdown cooling when necessary. ]
APPLICABILITY      All ECCS subsystems are required to be OPERABLE during MODES 1, 2, and 3 when there is considerable energy in the reactor core and core cooling would be required to prevent fuel damage in the event of a break in the primary system piping. In MODES 2 and 3, the ADS function is not General Electric BWR/6 STS              B 3.5.1-4                                        Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES APPLICABILITY (continued) required when pressure is  150 psig because the low pressure ECCS subsystems (LPCS and LPCI) are capable of providing flow into the RPV below this pressure. Requirements for MODES 4 and 5 are specified in LCO 3.5.2, "RPV Water Inventory Control."
ACTIONS            A Note prohibits the application of LCO 3.0.4.b to an inoperable HPCS subsystem. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable HPCS subsystem and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
A.1 If any one low pressure ECCS injection/spray subsystem is inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days [or in accordance with the Risk Informed Completion Time Program]. In this Condition, the remaining OPERABLE subsystems provide adequate core cooling during a LOCA. However, overall ECCS reliability is reduced because a single failure in one of the remaining OPERABLE subsystems concurrent with a LOCA may result in the ECCS not being able to perform its intended safety function. The 7 day Completion Time is based on a reliability study (Ref. 12) that evaluated the impact on ECCS availability by assuming that various components and subsystems were taken out of service. The results were used to calculate the average availability of ECCS equipment needed to mitigate the consequences of a LOCA as a function of allowed outage times (i.e.,
Completion Times).
B.1 and B.2 If the HPCS System is inoperable, and the RCIC System is verified to be OPERABLE (when RCIC is required to be OPERABLE), the HPCS System must be restored to OPERABLE status within 14 days [or in accordance with the Risk Informed Completion Time Program]. In this Condition, adequate core cooling is ensured by the OPERABILITY of the redundant and diverse low pressure ECCS injection/spray subsystems in conjunction with the ADS. Also, the RCIC System will automatically provide makeup water at most reactor operating pressures. Verification of RCIC OPERABILITY immediately is therefore required when HPCS is inoperable. This may be performed by an administrative check, by examining logs or other information to determine if RCIC is out of service General Electric BWR/6 STS              B 3.5.1-5                                        Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES ACTIONS (continued) for maintenance or other reasons. It is not necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the RCIC System. However, if the OPERABILITY of the RCIC System cannot be verified and RCIC is required to be OPERABLE, Condition D must be immediately entered. If a single active component fails concurrent with a design basis LOCA, there is a potential, depending on the specific failure, that the minimum required ECCS equipment will not be available. A 14 day Completion Time is based on the results of a reliability study (Ref. 12) and has been found to be acceptable through operating experience.
C.1 With two ECCS injection subsystems inoperable or one ECCS injection and one ECCS spray subsystem inoperable, at least one ECCS injection/spray subsystem must be restored to OPERABLE status within 72 hours [or in accordance with the Risk Informed Completion Time Program]. In this Condition, the remaining OPERABLE subsystems provide adequate core cooling during a LOCA. However, overall ECCS reliability is reduced in this Condition because a single failure in one of the remaining OPERABLE subsystems concurrent with a design basis LOCA may result in the ECCS not being able to perform its intended safety function. Since the ECCS availability is reduced relative to Condition A, a more restrictive Completion Time is imposed. The 72 hour Completion Time is based on a reliability study, as provided in Reference 12.
D.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
General Electric BWR/6 STS                B 3.5.1-6                                                      Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES ACTIONS (continued)
If any Required Action and associated Completion Time of Condition A, B, or C are not met, the plant must be brought to a MODE in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 13) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action D.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is 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 The LCO requires eight ADS valves to be OPERABLE to provide the ADS function. Reference 14 contains the results of an analysis that evaluated the effect of one ADS valve being out of service. Per this analysis, operation of only seven ADS valves will provide the required depressurization. However, overall reliability of the ADS is reduced because a single failure in the OPERABLE ADS valves could result in a reduction in depressurization capability. Therefore, operation is only allowed for a limited time. The 14 day Completion Time is based on a reliability study (Ref. 12) and has been found to be acceptable through operating experience. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.]
General Electric BWR/6 STS              B 3.5.1-7                                        Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES ACTIONS (continued)
F.1 and F.2 If any one low pressure ECCS injection/spray subsystem is inoperable in addition to one inoperable ADS valve, adequate core cooling is ensured by the OPERABILITY of HPCS and the remaining low pressure ECCS injection/spray subsystems. However, the overall ECCS reliability is reduced because a single active component failure concurrent with a design basis LOCA could result in the minimum required ECCS equipment not being available. Since both a high pressure (ADS) and low pressure subsystem are inoperable, a more restrictive Completion Time of 72 hours is required to restore either the low pressure ECCS injection/spray subsystem or the ADS valve to OPERABLE status. This Completion Time is based on a reliability study (Ref. 12) and has been found to be acceptable through operating experience. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.]
G.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
If any Required Action and associated Completion Time of Condition E or F are not met or if two or more ADS valves are inoperable, the plant must be brought to a MODE in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
General Electric BWR/6 STS                B 3.5.1-8                                                      Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES ACTIONS (continued)
Required Action G.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
H.1 When multiple ECCS subsystems are inoperable, as stated in Condition H, the plant is in a condition outside of the accident analyses.
Therefore, LCO 3.0.3 must be entered immediately.
SURVEILLANCE        SR 3.5.1.1 REQUIREMENTS The ECCS injection/spray subsystem flow path piping and components have the potential to develop voids and pockets of entrained gases.
Preventing and managing gas intrusion and accumulation is necessary for proper operation of the ECCS injection/spray subsystems and may also prevent a water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.
Selection of ECCS injection/spray subsystem locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration.
Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.
General Electric BWR/6 STS              B 3.5.1-9                                        Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The ECCS injection/spray subsystem is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the Surveillance is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the ECCS injection/spray subsystems are not rendered inoperable by the accumulated gas (i.e., the system is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits.
ECCS injection/spray subsystem locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.
[ The 31 day Frequency is based on operating experience, on the procedural controls governing system operation, and on the gradual nature of void buildup in the ECCS piping.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation.
General Electric BWR/6 STS            B 3.5.1-10                                        Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.5.1.2 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since these valves were verified to be in the correct position prior to locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves potentially capable of being mispositioned are in the correct position.
This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.
[ The 31 day Frequency of this SR was derived from the INSERVICE TESTING PROGRAM requirements for performing valve testing at least once every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control and because improper valve alignment would only affect a single subsystem. This Frequency has been shown to be acceptable through operating experience.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                  B 3.5.1-11                                                      Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance is modified by a Note which exempts system vent flow paths opened under administrative control. The administrative control should be proceduralized and include stationing a dedicated individual at the system vent flow path who is in continuous communication with the operators in the control room. This individual will have a method to rapidly close the system vent flow path if directed.
SR 3.5.1.3 Verification that ADS air receiver pressure is  [150] psig assures adequate air pressure for reliable ADS operation. The accumulator on each ADS valve provides pneumatic pressure for valve actuation. The designed pneumatic supply pressure requirements for the accumulator are such that, following a failure of the pneumatic supply to the accumulator, at least two valve actuations can occur with the drywell at 70% of design pressure (Ref. 15). The ECCS safety analysis assumes only one actuation to achieve the depressurization required for operation of the low pressure ECCS. This minimum required pressure of [150] psig is provided by the ADS Instrument Air Supply System. [ The 31 day Frequency takes into consideration administrative control over operation of the Instrument Air Supply System and alarms for low air pressure.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.5.1.4 The performance requirements of the ECCS pumps are determined through application of the 10 CFR 50, Appendix K, criteria (Ref. 8). This periodic Surveillance is performed (in accordance with the ASME Code requirements for the ECCS pumps) to verify that the ECCS pumps will develop the flow rates required by the respective analyses. The ECCS pump flow rates ensure that adequate core cooling is provided to satisfy the acceptance criteria of 10 CFR 50.46 (Ref. 10).
General Electric BWR/6 STS                B 3.5.1-12                                                      Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The pump flow rates are verified against a system head that is equivalent to the RPV pressure expected during a LOCA. The total system pump outlet pressure is adequate to overcome the elevation head pressure between the pump suction and the vessel discharge, the piping friction losses, and RPV pressure present during LOCAs. These values may be established during pre-operational testing.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
If the testing is within the scope of the licensee's INSERVICE TESTING PROGRAM, the Frequency "In accordance with the INSERVICE TESTING PROGRAM" should be used. Otherwise, the periodic Frequency of 92 days or the reference to the Surveillance Frequency Control Program should be used.
[ A 92 day Frequency for this Surveillance is in accordance with the INSERVICE TESTING PROGRAM requirements.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.5.1.5 The ECCS subsystems are required to actuate automatically to perform their design functions. This Surveillance test verifies that, with a required system initiation signal (actual or simulated), the automatic initiation logic of HPCS, LPCS, and LPCI will cause the systems or subsystems to operate as designed, including actuation of the system throughout its emergency operating sequence, automatic pump startup, and actuation of all automatic valves to their required positions. This Surveillance also ensures that the HPCS System will automatically restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level (Level 8) trip and that the suction is automatically transferred from General Electric BWR/6 STS                B 3.5.1-13                                                      Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued) the CST to the suppression pool. The SR excludes automatic valves that are locked, sealed, or otherwise secured in the actuated position. The SR does not apply to valves that are locked, sealed, or otherwise secured in the actuated position since the affected valves were verified to be in the actuated position prior to being locked, sealed, or otherwise secured.
Placing an automatic valve in a locked, sealed, or otherwise secured position requires an assessment of the OPERABILITY of the system or any supported systems, including whether it is necessary for the valve to be repositioned to the non-actuated position to support the accident analysis. Restoration of an automatic valve to the non-actuated position requires verification that the SR has been met within its required Frequency. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlaps this Surveillance to provide complete testing of the assumed safety function.
[ The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
This SR is modified by a Note that excludes vessel injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.
General Electric BWR/6 STS                  B 3.5.1-14                                                      Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.5.1.6 The ADS designated S/RVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test is performed to demonstrate that the mechanical portions of the ADS function (i.e.,
solenoids) operate as designed when initiated either by an actual or simulated initiation signal, causing proper actuation of all the required components. SR 3.5.1.7 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function.
[ The 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 SR when performed at the 18 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
This SR is modified by a Note that excludes valve actuation. This prevents an RPV pressure blowdown.
SR 3.5.1.7 A manual actuation of each ADS valve is performed to verify that the valve and solenoids are functioning properly and that no blockage exists in the S/RV discharge lines. This is demonstrated by the response of the turbine control or bypass valve, by a change in the measured steam flow, or by any other method suitable to verify steam flow. Adequate reactor steam dome pressure must be available to perform this test to avoid damaging the valve. Also, adequate steam flow must be passing through General Electric BWR/6 STS                  B 3.5.1-15                                                      Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES SURVEILLANCE REQUIREMENTS (continued) the main turbine or turbine bypass valves to continue to control reactor pressure when the ADS valves divert steam flow upon opening.
Sufficient time is therefore allowed, after the required pressure and flow are achieved, to perform this test. Adequate pressure at which this test is to be performed is [950] psig (the pressure recommended by the valve manufacturer). Adequate steam flow is represented by [at least 1.25 turbine bypass valves open, or total steam flow  106 lb/hr]. Reactor startup is allowed prior to performing this test because valve OPERABILITY and the setpoints for overpressure protection are verified, per ASME requirements, prior to valve installation. Therefore, this SR is modified by a Note that states the Surveillance is not required to be performed until 12 hours after reactor steam pressure and flow are adequate to perform the test. SR 3.5.1.6 and the LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.1 overlap this Surveillance to provide complete testing of the assumed safety function.
[ The Frequency of 18 months on a STAGGERED TEST BASIS ensures that both solenoids for each ADS valve are alternately tested. The Frequency is based on the need to perform this Surveillance under the conditions that apply just prior to or during a startup from a plant outage.
Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES        1.      FSAR, Section [6.3.2.2.3].
: 2.      FSAR, Section [6.3.2.2.4].
: 3.      FSAR, Section [6.3.2.2.1].
: 4.      FSAR, Section [6.3.2.2.2].
General Electric BWR/6 STS                  B 3.5.1-16                                                      Rev. 5.0
 
ECCS - Operating B 3.5.1 BASES REFERENCES (continued)
: 5. FSAR, Section [15.2.8].
: 6. FSAR, Section [15.6.4].
: 7. FSAR, Section [15.6.5].
: 8. 10 CFR 50, Appendix K.
: 9. FSAR, Section [6.3.3].
: 10. 10 CFR 50.46.
: 11. FSAR, Section [6.3.3.3].
: 12. Memorandum from R.L. Baer (NRC) to V. Stello, Jr. (NRC),
                        "Recommended Interim Revisions to LCO's for ECCS Components,"
December 1, 1975.
: 13. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
: 14. FSAR, Section [6.3.3.7.8].
: 15. FSAR, Section [7.3.1.1.1.4.2].
General Electric BWR/6 STS          B 3.5.1-17                                    Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.2 Reactor Pressure Vessel (RPV) Water Inventory Control BASES BACKGROUND          The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF.
If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.
APPLICABLE          With the unit in MODE 4 or 5, RPV water inventory control is not SAFETY              required to mitigate any events or accidents evaluated in the safety ANALYSES            analyses. RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material to the environment should an unexpected draining event occur.
A double-ended guillotine break of the Reactor Coolant System (RCS) is not considered in MODES 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is considered in which an initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure (an event that creates a drain path through multiple vessel penetrations located below top of active fuel, such as loss of normal power, or a single human error). It is assumed, based on engineering judgment, that while in MODES 4 and 5, one low pressure ECCS injection/spray subsystem can maintain adequate reactor vessel water level.
As discussed in References 1, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety.
Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).
LCO                  The RPV water level must be controlled in MODES 4 and 5 to ensure that if an unexpected draining event should occur, the reactor coolant water level remains above the top of the active irradiated fuel as required by Safety Limit 2.1.1.3.
The Limiting Condition for Operation (LCO) requires the DRAIN TIME of RPV water inventory to the TAF to be  36 hours. A DRAIN TIME of 36 hours is considered reasonable to identify and initiate action to mitigate unexpected draining of reactor coolant. An event that could General Electric BWR/6 STS              B 3.5.2-1                                          Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 BASES LCO (continued) cause loss of RPV water inventory and result in the RPV water level reaching the TAF in greater than 36 hours does not represent a significant challenge to Safety Limit 2.1.1.3 and can be managed as part of normal plant operation.
One ECCS injection/spray subsystem is required to be OPERABLE and capable of being manually aligned and started from the control room to provide defense-in-depth should an unexpected draining event occur.
OPERABILITY of the ECCS injection/spray subsystem includes any necessary valves, instrumentation, or controls needed to manually align and start the subsystem from the control room. A ECCS injection/spray subsystem is defined as either one of the three low pressure coolant injection (LPCI) subsystems, one Low Pressure Core Spray (LPCS)
System or, one High Pressure Core Spray (HPCS) System. The LPCI subsystems and the LPCS System consist of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV.
The HPCS System consists of one motor driven pump, piping, and valves to transfer water from the suppression pool or condensate storage tank (CST) to the RPV. Management of gas voids is important to ECCS injection/spray subsystem OPERABILITY.
APPLICABILITY      RPV water inventory control is required in MODES 4 and 5.
Requirements on water inventory control in other MODES are contained in LCOs in Section 3.3, "Instrumentation," and other LCOs in Section 3.5, "ECCS, RPV Water Inventory Control, and RCIC System." RPV water inventory control is required to protect Safety Limit 2.1.1.3 which is applicable whenever irradiated fuel is in the reactor vessel.
ACTIONS            A.1 and B.1 If the required ECCS injection/spray subsystem is inoperable, it must be restored to OPERABLE status within 4 hours. In this Condition, the LCO controls on DRAIN TIME minimize the possibility that an unexpected draining event could necessitate the use of the ECCS injection/spray subsystem, however the defense-in-depth provided by the ECCS injection/spray subsystem is lost. The 4 hour Completion Time for restoring the required ECCS injection/spray subsystem to OPERABLE status is based on engineering judgment that considers the LCO controls on DRAIN TIME and the low probability of an unexpected draining event that would result in loss of RPV water inventory.
General Electric BWR/6 STS            B 3.5.2-2                                        Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 BASES ACTIONS (continued)
If the inoperable ECCS injection/spray subsystem is not restored to OPERABLE status within the required Completion Time, action must be initiated immediately to establish a method of water injection capable of operating without offsite electrical power. The method of water injection includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur. The method of water injection may be manually initiated and may consist of one or more systems or subsystems, and must be able to access water inventory capable of maintaining the RPV water level above the TAF for  36 hours.
If recirculation of injected water would occur, it may be credited in determining the necessary water volume.
C.1, C.2, and C.3 With the DRAIN TIME less than 36 hours but greater than or equal to 8 hours, compensatory measures should be taken to ensure the ability to implement mitigating actions should an unexpected draining event occur.
Should a draining event lower the reactor coolant level to below the TAF, there is potential for damage to the reactor fuel cladding and release of radioactive material. Additional actions are taken to ensure that radioactive material will be contained, diluted [, and processed] prior to being released to the environment.
The [secondary containment] provides a controlled volume in which fission products can be contained, diluted [, and processed] prior to release to the environment. Required Action C.1 requires verification of the capability to establish the [secondary containment] boundary in less than the DRAIN TIME. The required verification confirms actions to establish the [secondary containment] boundary are preplanned and necessary materials are available. [The [secondary containment]
boundary is considered established when one standby gas treatment (SGT) subsystem is capable of maintaining a negative pressure in the
[secondary containment] with respect to the environment.]
Verification that the [secondary containment] boundary can be established must be performed within 4 hours. The required verification is an administrative activity and does not require manipulation or testing of equipment.
General Electric BWR/6 STS              B 3.5.2-3                                        Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 BASES ACTIONS (continued)
[Secondary containment] penetration flow paths form a part of the
[secondary containment] boundary. Required Action C.2 requires verification of the capability to isolate each [secondary containment]
penetration flow path in less than the DRAIN TIME. The required verification confirms actions to isolate the [secondary containment]
penetration flow paths are preplanned and necessary materials are available. Power operated valves are not required to receive automatic isolation signals if they can be closed manually within the required time.
Verification that the [secondary containment] penetration flow paths can be isolated must be performed within 4 hours. The required verification is an administrative activity and does not require manipulation or testing of equipment.
[One SGT subsystem is capable of maintaining the [secondary containment] at a negative pressure with respect to the environment and filter gaseous releases. Required Action C.3 requires verification of the capability to place one SGT subsystem in operation in less than the DRAIN TIME. The required verification confirms actions to place a SGT subsystem in operation are preplanned and necessary materials are available. Verification that a SGT subsystem can be placed in operation must be performed within 4 hours. The required verification is an administrative activity and does not require manipulation or testing of equipment.]
                    ---------------------------------- REVIEWER'S NOTE ----------------------------------
The bracketed information applies to multiple unit sites with a shared secondary containment and recognizes that an OPERABLE secondary containment, secondary containment penetrations, and SGT subsystems satisfy Required Actions C.1, C.2, and C.3.
[Required Actions C.1, C.2, and C.3 are considered to be met when
[secondary containment], [secondary containment] penetrations, and the SGT System are OPERABLE in accordance with LCO 3.6.4.1, LCO 3.6.4.2, and LCO 3.6.4.3.]
General Electric BWR/6 STS                B 3.5.2-4                                                      Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 BASES ACTIONS (continued)
D.1, D.2, D.3, and D.4
                    ---------------------------------- REVIEWER'S NOTE ----------------------------------
The bracketed information applies to multiple unit sites with a shared secondary containment and recognizes that an OPERABLE secondary containment, secondary containment penetrations, and SGT subsystems satisfy Required Actions D.2, D.3, and D.4.
With the DRAIN TIME less than 8 hours, mitigating actions are implemented in case an unexpected draining event should occur. Note that if the DRAIN TIME is less than 1 hour, Required Action E.1 is also applicable.
Required Action D.1 requires immediate action to establish an additional method of water injection augmenting the ECCS injection/spray subsystem required by the LCO. The additional method of water injection includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur. The Note to Required Action D.1 states that either the ECCS injection/spray subsystem or the additional method of water injection must be capable of operating without offsite electrical power. The additional method of water injection may be manually initiated and may consist of one or more systems or subsystems. The additional method of water injection must be able to access water inventory capable of being injected to maintain the RPV water level above the TAF for  36 hours. The additional method of water injection and the ECCS injection/spray subsystem may share all or part of the same water sources. If recirculation of injected water would occur, it may be credited in determining the required water volume.
Should a draining event lower the reactor coolant level to below the TAF, there is potential for damage to the reactor fuel cladding and release of radioactive material. Additional actions are taken to ensure that radioactive material will be contained, diluted, and processed prior to being released to the environment.
The [secondary containment] provides a control volume in which fission products can be contained, diluted [, and processed] prior to release to the environment. Required Action D.2 requires that actions be immediately initiated to establish the [secondary containment] boundary.
[With the [secondary containment] boundary established, one SGT subsystem is capable of maintaining a negative pressure in the
[secondary containment] with respect to the environment].
General Electric BWR/6 STS                B 3.5.2-5                                                      Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 BASES ACTIONS (continued)
The [secondary containment] penetrations form a part of the [secondary containment] boundary. Required Action D.3 requires that actions be immediately initiated to verify that each [secondary containment]
penetration flow path is isolated or to verify that it can be [automatically or] manually isolated from the control room.
[One SGT subsystem is capable of maintaining the [secondary containment] at a negative pressure with respect to the environment and filter gaseous releases. Required Action D.4 requires that actions be immediately initiated to verify that at least one SGT subsystem is capable of being placed in operation. The required verification is an administrative activity and does not require manipulation or testing of equipment.]
[Required Actions D.2, D.3, and D.4 are considered to be met when
[secondary containment], [secondary containment] penetrations, and the SGT System are OPERABLE in accordance with LCO 3.6.4.1, LCO 3.6.4.2, and LCO 3.6.4.3.]
E.1 If the Required Actions and associated Completion Times of Conditions C or D are not met or if the DRAIN TIME is less than 1 hour, actions must be initiated immediately to restore the DRAIN TIME to  36 hours. In this condition, there may be insufficient time to respond to an unexpected draining event to prevent the RPV water inventory from reaching the TAF.
Note that Required Actions D.1, D.2, D.3, and D.4 are also applicable when DRAIN TIME is less than 1 hour.
SURVEILLANCE        SR 3.5.2.1 REQUIREMENTS This Surveillance verifies that the DRAIN TIME of RPV water inventory to the TAF is  36 hours. The period of 36 hours is considered reasonable to identify and initiate action to mitigate draining of reactor coolant. Loss of RPV water inventory that would result in the RPV water level reaching the TAF in greater than 36 hours does not represent a significant challenge to Safety Limit 2.1.1.3 and can be managed as part of normal plant operation.
The definition of DRAIN TIME states that realistic cross-sectional areas and drain rates are used in the calculation. A realistic drain rate may be determined using a single, step-wise, or integrated calculation considering the changing RPV water level during a draining event. For a Control Rod RPV penetration flow path with the control rod drive General Electric BWR/6 STS              B 3.5.2-6                                          Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued) mechanism removed and not replaced with a blank flange, the realistic cross-sectional area is based on the control rod blade seated in the control rod guide tube. If the control rod blade will be raised from the penetration to adjust or verify seating of the blade, the exposed cross-sectional area of the RPV penetration flow path is used.
The definition of DRAIN TIME excludes from the calculation those penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are closed and administratively controlled, blank flanges, or other devices that prevent flow of reactor coolant through the penetration flow paths. A blank flange or other bolted device must be connected with a sufficient number of bolts to prevent draining. Normal or expected leakage from closed systems or past isolation devices is permitted. Determination that a system is intact and closed or isolated must consider the status of branch lines.
The Residual Heat Removal (RHR) Shutdown Cooling System is only considered an intact closed system when misalignment issues (Reference 6) have been precluded by functional valve interlocks or by isolation devices, such that redirection of RPV water out of an RHR subsystem is precluded. Further, RHR Shutdown Cooling System is only considered an intact closed system if its controls have not been transferred to remote shutdown, which disables the interlocks and isolation signals.
The exclusion of a single penetration flow path, or multiple penetration flow paths susceptible to a common mode failure, from the determination of DRAIN TIME should consider the effects of temporary alterations in support of maintenance (rigging, scaffolding, temporary shielding, piping plugs, freeze seals, etc.). If reasonable controls are implemented to prevent such temporary alterations from causing a draining event from a closed system, or between the RPV and the isolation device, the effect of the temporary alterations on DRAIN TIME need not be considered.
Reasonable controls include, but are not limited to, controls consistent with the guidance in NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Revision
[4F], NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management," or commitments to NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants."
General Electric BWR/6 STS            B 3.5.2-7                                        Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)
Surveillance Requirement 3.0.1 requires SRs to be met between performances. Therefore, any changes in plant conditions that would change the DRAIN TIME requires that a new DRAIN TIME be determined.
[ The Frequency of 12 hours is sufficient in view of indications of RPV water level available to the operator .
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.5.2.2 and SR 3.5.2.3 The minimum water level of [12.67 ft] required for the suppression pool is periodically verified to ensure that the suppression pool will provide adequate net positive suction head (NPSH) for the ECCS pump, recirculation volume, and vortex prevention. With the suppression pool water level less than the required limit, the required ECCS injection/spray subsystem is inoperable unless aligned to an OPERABLE CST.
When the suppression pool level is < [12.67 ft], the HPCS System is considered OPERABLE only if it can take suction from the CST and the CST water level is sufficient to provide the required NPSH for the HPCS pump. Therefore, a verification that either the suppression pool water level is  [12.67 ft] or the HPCS System is aligned to take suction from the CST and the CST contains  [170,000] gallons of water, equivalent to
[18] ft, ensures that the HPCS System can supply makeup water to the RPV.
[ The 12 hour Frequency of these SRs was developed considering operating experience related to suppression pool and CST water level variations. 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 suppression pool or CST water level condition.
General Electric BWR/6 STS                  B 3.5.2-8                                                      Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.5.2.4 The ECCS injection/spray subsystem flow path piping and components have the potential to develop voids and pockets of entrained gases.
Preventing and managing gas intrusion and accumulation is necessary for proper operation of the ECCS injection/spray subsystems and may also prevent a water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.
Selection of ECCS injection/spray subsystem locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration.
Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.
The ECCS injection/spray subsystem is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the Surveillance is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the ECCS injection/spray subsystems are not rendered inoperable by the accumulated gas (i.e., the General Electric BWR/6 STS                B 3.5.2-9                                                      Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued) system is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits.
ECCS injection/spray subsystem locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.
[ The 31 day Frequency is based on operating experience, on the procedural controls governing system operation, and on the gradual nature of void buildup in the ECCS piping.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.5.2-10                                                      Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.5.2.5 Verifying that the required ECCS injection/spray subsystem can be manually aligned, and the pump started and operated for at least 10 minutes demonstrates that the subsystem is available to mitigate a draining event. This SR is modified by two Notes. Note 1 states that testing the ECCS injection/spray subsystem may be done through the test return line to avoid overfilling the refueling cavity. Note 2 states that credit for meeting the SR may be taken for normal system operation that satisfies the SR, such as using the RHR mode of LPCI for  10 minutes.
The minimum operating time of 10 minutes was based on engineering judgement. [The performance frequency of 92 days is consistent with similar at-power testing required by SR 3.5.1.4.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.5.2.6 Verifying that each valve credited for automatically isolating a penetration flow path actuates to the isolation position on an actual or simulated RPV water level isolation signal is required to prevent RPV water inventory from dropping below the TAF should an unexpected draining event occur.
[ 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
[18] month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR General Electric BWR/6 STS                B 3.5.2-11                                                      Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.5.2.7 This Surveillance verifies that a required LCPI subsystem, LPCS System, or HPCS System can be manually aligned and started from the control room, including any necessary valve alignment, instrumentation, or controls, to transfer water from the suppression pool or CST to the RPV.
[ The [18] month Frequency is based on the need to perform the Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.
Operating experience has shown that these components usually pass the SR when performed at the [18] month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
This SR is modified by a Note that excludes vessel injection/spray during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.
General Electric BWR/6 STS                B 3.5.2-12                                                      Rev. 5.0
 
RPV Water Inventory Control B 3.5.2 BASES REFERENCES          1. Information Notice 84-81 "Inadvertent Reduction in Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup,"
November 1984.
: 2. Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.
: 3. Generic Letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(F)," August 1992.
: 4. NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," May 1993.
: 5. Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994.
: 6. General Electric Service Information Letter No. 388, "RHR Valve Misalignment During Shutdown Cooling Operation for BWR 3/4/5/6,"
February 1983.
General Electric BWR/6 STS          B 3.5.2-13                                      Rev. 5.0
 
RCIC System B 3.5.3 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.3 RCIC System BASES BACKGROUND          The RCIC System is not part of the ECCS; however, the RCIC System is included with the ECCS section because of their similar functions.
The RCIC System is designed to operate either automatically or manually following reactor pressure vessel (RPV) isolation accompanied by a loss of coolant flow from the feedwater system to provide adequate core cooling and control of RPV water level. Under these conditions, the High Pressure Core Spray (HPCS) and RCIC systems perform similar functions. The RCIC System design requirements ensure that the criteria of Reference 1 are satisfied.
The RCIC System (Ref. 2) consists of a steam driven turbine pump unit, piping, and valves to provide steam to the turbine, as well as piping and valves to transfer water from the suction source to the core via the feedwater system line. Suction piping is provided from the condensate storage tank (CST) and the suppression pool. Pump suction is normally aligned to the CST to minimize injection of suppression pool water into the RPV. However, if the CST water supply is low, or the suppression pool level is high, an automatic transfer to the suppression pool water source ensures a water supply for continuous operation of the RCIC System. The steam supply to the turbine is piped from main steam line A, upstream of the inboard main steam line isolation valve.
The RCIC System is designed to provide core cooling for a wide range of reactor pressures, [165] psig to [1155] psig. Upon receipt of an initiation signal, the RCIC turbine accelerates to a specified speed. As the RCIC flow increases, the turbine control valve is automatically adjusted to maintain design flow. Exhaust steam from the RCIC turbine is discharged to the suppression pool. A full flow test line is provided to route water from and to the CST to allow testing of the RCIC System during normal operation without injecting water into the RPV.
The RCIC pump is provided with a minimum flow bypass line, which discharges to the suppression pool. The valve in this line automatically opens to prevent pump damage due to overheating when other discharge line valves are closed. To ensure rapid delivery of water to the RPV and to minimize water hammer effects, the RCIC System discharge line "keep fill" system is designed to maintain the pump discharge line filled with water.
General Electric BWR/6 STS              B 3.5.3-1                                        Rev. 5.0
 
RCIC System B 3.5.3 BASES APPLICABLE          The function of the RCIC System is to respond to transient events by SAFETY              providing makeup coolant to the reactor. The RCIC System is not an ANALYSES            Engineered Safety Feature System and no credit is taken in the safety analyses for RCIC System operation. The RCIC System satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).
LCO                The OPERABILITY of the RCIC System provides adequate core cooling such that actuation of any of the ECCS subsystems is not required in the event of RPV isolation accompanied by a loss of feedwater flow. The RCIC System has sufficient capacity to maintain RPV inventory during an isolation event. Management of gas voids is important to RCIC System OERABILITY.
APPLICABILITY      The RCIC System is required to be OPERABLE in MODE 1, and MODES 2 and 3 with reactor steam dome pressure > 150 psig since RCIC is the primary non-ECCS water source for core cooling when the reactor is isolated and pressurized. In MODES 2 and 3 with reactor steam dome pressure  150 psig, the ECCS injection/spray subsystems can provide sufficient flow to the vessel. In MODES 4 and 5, RCIC is not required to be OPERABLE since RPV water inventory control is required by LCO 3.5.2, "RPV Water Level Inventory Control."
ACTIONS            A Note prohibits the application of LCO 3.0.4.b to an inoperable RCIC System. There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable RCIC System 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 A.2 If the RCIC System is inoperable during MODE 1, or MODES 2 or 3 with reactor steam dome pressure > 150 psig, and the HPCS System is verified to be OPERABLE, the RCIC System must be restored to OPERABLE status within 14 days [or in accordance with the Risk Informed Completion Time Program]. In this Condition, loss of the RCIC System will not affect the overall plant capability to provide makeup inventory at high RPV pressure since the HPCS System is the only high pressure system assumed to function during a loss of coolant accident (LOCA). OPERABILITY of the HPCS is therefore verified immediately when the RCIC System is inoperable. This may be performed as an administrative check, by examining logs or other information, to determine if the HPCS is out of service for maintenance or other reasons.
Verification does not require performing the Surveillances needed to demonstrate the OPERABILITY of the HPCS System. If the OPERABILITY of the HPCS System cannot be verified, however, General Electric BWR/6 STS            B 3.5.3-2                                        Rev. 5.0
 
RCIC System B 3.5.3 BASES ACTIONS (continued)
Condition B must be immediately entered. For transients and certain abnormal events with no LOCA, RCIC (as opposed to HPCS) is the preferred source of makeup coolant because of its relatively small capacity, which allows easier control of RPV water level. Therefore, a limited time is allowed to restore the inoperable RCIC to OPERABLE status.
The 14 day Completion Time is based on a reliability study (Ref. 3) that evaluated the impact on ECCS availability, assuming that various components and subsystems were taken out of service. The results were used to calculate the average availability of ECCS equipment needed to mitigate the consequences of a LOCA as a function of allowed outage times (AOTs). Because of the similar functions of the HPCS and RCIC, the AOTs (i.e., Completion Times) determined for the HPCS are also applied to RCIC.
B.1 and B.2 If the RCIC System cannot be restored to OPERABLE status within the associated Completion Time, or if the HPCS System is simultaneously inoperable, the plant must be brought to a condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and reactor steam dome pressure reduced to  150 psig 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 3.5.3.1 REQUIREMENTS The RCIC System flow path piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RCIC System and may also prevent a water hammer, pump cavitation, and pumping of noncondensible gas.
Selection of RCIC System locations susceptible to gas accumulation is based on a self-assessment of the piping configuration to identify where gases may accumulate and remain even after the system is filled and vented, and to identify vulnerable potential degassing flow paths. The review is supplemented by verification that installed high-point vents are actually at the system high points, including field verification to ensure General Electric BWR/6 STS              B 3.5.3-3                                        Rev. 5.0
 
RCIC System B 3.5.3 BASES SURVEILLANCE REQUIREMENTS (continued) pipe shapes and construction tolerances have not inadvertently created additional high points. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.
The RCIC System is OPERABLE when it is sufficiently filled with water.
Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump),
the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the Surveillance is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RCIC System is not rendered inoperable by the accumulated gas (i.e., the system is sufficiently filled with water),
the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits.
RCIC System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations.
Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.
[ The 31 day Frequency is based on the gradual nature of void buildup in the RCIC piping, the procedural controls governing system operation, and operating experience.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation.
General Electric BWR/6 STS              B 3.5.3-4                                        Rev. 5.0
 
RCIC System B 3.5.3 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.5.3.2 Verifying the correct alignment for manual, power operated, and automatic valves in the RCIC flow path provides assurance that the proper flow path will exist for RCIC 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 locking, sealing, or securing. A valve that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves. For the RCIC System, this SR also includes the steam flow path for the turbine and the flow controller position.
[ The 31 day Frequency of this SR was derived from the INSERVICE TESTING PROGRAM requirements for performing valve testing at least every 92 days. The Frequency of 31 days is further justified because the valves are operated under procedural control and because improper valve position would affect only the RCIC System. This Frequency has been shown to be acceptable through operating experience.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                  B 3.5.3-5                                                      Rev. 5.0
 
RCIC System B 3.5.3 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance is modified by a Note which exempts system vent flow paths opened under administrative control. The administrative control should be proceduralized and include stationing a dedicated individual at the system vent flow path who is in continuous communication with the operators in the control room. This individual will have a method to rapidly close the system vent flow path if directed.
SR 3.5.3.3 and SR 3.5.3.4 The RCIC pump flow rates ensure that the system can maintain reactor coolant inventory during pressurized conditions with the RPV isolated.
The flow tests for the RCIC System are performed at two different pressure ranges such that system capability to provide rated flow is tested both at the higher and lower operating ranges of the system.
Additionally, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the RCIC System diverts steam flow. Reactor steam pressure must be  [920] psig to perform SR 3.5.3.3 and  [150] psig to perform SR 3.5.3.4. Adequate steam flow is represented by [at least 1.25 turbine bypass valves open, or total steam flow  106 lb/hr. Therefore, sufficient time is allowed after adequate pressure and flow are achieved to perform these SRs. Reactor startup is allowed prior to performing the low pressure Surveillance because the reactor pressure is low and the time to satisfactorily perform the Surveillance is short. The reactor pressure is allowed to be increased to normal operating pressure since it is assumed that the low pressure test has been satisfactorily completed and there is no indication or reason to believe that RCIC is inoperable. Therefore, these SRs are modified by Notes that state the Surveillances are not required to be performed until 12 hours after the reactor steam pressure and flow are adequate to perform the test.
[ A 92 day Frequency for SR 3.5.3.3 is consistent with the INSERVICE TESTING PROGRAM requirements. The 18 month Frequency for SR 3.5.3.4 is based on the need to perform this Surveillance under the conditions that apply just prior to or during startup from a plant outage.
Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS              B 3.5.3-6                                        Rev. 5.0
 
RCIC System B 3.5.3 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.5.3.5 The RCIC System is required to actuate automatically to perform its design function. This Surveillance verifies that with a required system initiation signal (actual or simulated) the automatic initiation logic of RCIC will cause the system to operate as designed, including actuation of the system throughout its emergency operating sequence, automatic pump startup and actuation of all automatic valves to their required positions.
This Surveillance test also ensures that the RCIC System will automatically restart on an RPV low water level (Level 2) signal received subsequent to an RPV high water level (Level 8) trip and that the suction is automatically transferred from the CST to the suppression pool. The SR excludes automatic valves that are locked, sealed, or otherwise secured in the actuated position. The SR does not apply to valves that are locked, sealed, or otherwise secured in the actuated position since the affected valves were verified to be in the actuated position prior to being locked, sealed, or otherwise secured. Placing an automatic valve in a locked, sealed, or otherwise secured position requires an assessment of the OPERABILITY of the system or any supported systems, including whether it is necessary for the valve to be repositioned to the non-actuated position to support the accident analysis. Restoration of an automatic valve to the non-actuated position requires verification that the SR has been met within its required Frequency. The LOGIC SYSTEM FUNCTIONAL TEST performed in LCO 3.3.5.3 overlaps this Surveillance to provide complete testing of the assumed safety function.
[ The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR General Electric BWR/6 STS                  B 3.5.3-7                                                      Rev. 5.0
 
RCIC System B 3.5.3 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
This SR is modified by a Note that excludes vessel injection during the Surveillance. Since all active components are testable and full flow can be demonstrated by recirculation through the test line, coolant injection into the RPV is not required during the Surveillance.
REFERENCES          1. 10 CFR 50, Appendix A, GDC 33.
: 2. FSAR, Section [5.4.6.2].
: 3. Memorandum from R.L. Baer (NRC) to V. Stello, Jr. (NRC),
                          "Recommended Interim Revisions to LCO's for ECCS Components,"
December 1, 1975.
General Electric BWR/6 STS                B 3.5.3-8                                                      Rev. 5.0
 
Primary Containment B 3.6.1.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.1 Primary Containment BASES BACKGROUND          The function of the primary containment is to isolate and contain fission products released from the Reactor Primary System following a design basis loss of coolant accident (LOCA) and to confine the postulated release of radioactive material to within limits. The primary containment consists of a steel lined, reinforced concrete vessel, which surrounds the Reactor Primary System and provides an essentially leak tight barrier against an uncontrolled release of radioactive material to the environment. Additionally, this structure provides shielding from the fission products that may be present in the primary containment atmosphere following accident conditions.
The isolation devices for the penetrations in the primary containment boundary are a part of the primary 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 3.6.1.3, "Primary Containment Isolation Valves (PCIVs),"
: b. Primary containment air locks are OPERABLE, except as provided in LCO 3.6.1.2, "Primary Containment Air Locks,"
: c. All equipment hatches are closed, and
[ d. The pressurized sealing mechanism associated with a penetration is OPERABLE, except as provided in LCO 3.6.1.[ ]. ]
This Specification ensures that the performance of the primary containment, in the event of a Design Basis Accident (DBA), meets the assumptions used in the safety analyses of References 1 and 2.
SR 3.6.1.1.1 leakage rate requirements are in conformance with 10 CFR 50, Appendix J, Option [A][B] (Ref. 3), as modified by approved exemptions.
General Electric BWR/6 STS            B 3.6.1.1-1                                      Rev. 5.0
 
Primary Containment B 3.6.1.1 BASES APPLICABLE          The safety design basis for the primary containment is that it must SAFETY              withstand the pressures and temperatures of the limiting DBA without ANALYSES            exceeding the design leakage rate.
The DBA that postulates the maximum release of radioactive material within primary containment is a LOCA. In the analysis of this accident, it is assumed that primary containment is OPERABLE such that release of fission products to the environment is controlled by the rate of primary containment leakage.
Analytical methods and assumptions involving the primary containment are presented in References 1 and 2. The safety analyses assume a nonmechanistic fission product release following a DBA, which forms the basis for determination of offsite doses. The fission product release is, in turn, based on an assumed leakage rate from the primary containment.
OPERABILITY of the primary containment ensures that the leakage rate assumed in the safety analyses is not exceeded.
The maximum allowable leakage rate for the primary containment (La) is
[0.437]% by weight of the containment and drywell air per 24 hours at the design basis LOCA maximum peak containment pressure (Pa) of
([11.5] psig) (Ref. 4).
Primary containment satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                Primary containment OPERABILITY is maintained by limiting leakage to 1.0 La, except prior to the first startup after performing a required Primary Containment Leakage Rate Testing Program leakage test. At this time the applicable leakage limits must be met.
Compliance with this LCO will ensure a primary containment configuration, including equipment hatches, that is structurally sound and that will limit leakage to those leakage rates assumed in the safety analysis. Individual leakage rates specified for the primary containment air locks are addressed in LCO 3.6.1.2.
APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, primary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.
General Electric BWR/6 STS              B 3.6.1.1-2                                      Rev. 5.0
 
Primary Containment B 3.6.1.1 BASES ACTIONS            A.1 In the event that primary containment is inoperable, primary containment must be restored to OPERABLE status within 1 hour. The 1 hour Completion Time provides a period of time to correct the problem that is commensurate with the importance of maintaining primary containment OPERABILITY during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring primary containment OPERABILITY) occurring during periods where primary containment is inoperable is minimal.
B.1 and B.2 If primary containment cannot be restored to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 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 3.6.1.1.1 REQUIREMENTS Maintaining the primary containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. The primary containment concrete visual examinations may be performed during either power operation, e.g., performed concurrently with other primary containment inspection-related activities such as tendon testing, or during a maintenance or refueling outage. The visual examinations of the steel liner plate inside primary containment are performed during maintenance or refueling outages since this is the only time the liner plate is fully accessible.
Failure to meet air lock leakage testing (SR 3.6.1.2.1 and SR 3.6.1.2.4),
[secondary containment bypass leakage (SR 3.6.1.3.9),] resilient seal primary containment purge valve leakage testing (SR 3.6.1.3.6), or main steam isolation valve leakage (SR 3.6.1.3.10) does not necessarily result in a failure of this SR. The impact of the failure to meet these SRs must be evaluated against the Type A, B, and C acceptance criteria of the Primary Containment Leakage Rate Testing Program. As left leakage prior to the first startup after performing a required Primary 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 General Electric BWR/6 STS              B 3.6.1.1-3                                        Rev. 5.0
 
Primary Containment B 3.6.1.1 BASES SURVEILLANCE REQUIREMENTS (continued) 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.
The Frequency is required by the Primary Containment Leakage Rate Testing Program.
SR Frequencies are as required by the Primay 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.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Regulatory Guide 1.163 and NEI 94-01 include acceptance criteria for as-left and as-found Type A leakage rates and combined Type B and C leakage rates, which may be reflected in the Bases.
[ SR 3.6.1.1.2 The structural integrity of the primary containment is ensured by the successful completion of the Primary Containment Tendon Surveillance Program and by associated visual inspections of the steel liner and penetrations for evidence of deterioration or breach of integrity. This ensures that the structural integrity of the primary containment will be maintained in accordance with the provisions of the Primary Containment Tendon Surveillance Program. Testing and Frequency are in accordance with the ASME Code, Section XI, Subsection IWL (Ref. 5), and applicable addenda as required by 10 CFR 50.55a. ]
REFERENCES          1. FSAR, Section [6.2].
: 2. FSAR, Section [15.6.5].
: 3. 10 CFR 50, Appendix J, Option [A][B].
: 4. FSAR, Section [ ].
: 5. ASME Code, Section XI, Subsection IWL.
General Electric BWR/6 STS                B 3.6.1.1-4                                                      Rev. 5.0
 
Primary Containment Air Locks B 3.6.1.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.2 Primary Containment Air Locks BASES BACKGROUND          Two double door primary containment air locks have been built into the primary containment to provide personnel access to the primary containment and to provide primary containment isolation during the process of personnel entry and exit. The air locks are designed to withstand the same loads, temperatures, and peak design internal and external pressures as the primary containment (Ref. 1). As part of the primary containment, the air lock limits the release of radioactive material to the environment during normal unit operation and through a range of 853transients and accidents up to and including postulated Design Basis Accidents (DBAs).
Each air lock door has been designed and tested to certify its ability to withstand pressure in excess of the maximum expected pressure following a DBA in primary containment. Each of the doors has inflatable seals that are maintained > [60] psig by the seal air flask and pneumatic system, which is maintained at a pressure  [90] psig. Each door has two seals to ensure they are single failure proof in maintaining the leak tight boundary of primary containment.
Each air lock is nominally a right circular cylinder, 10 ft 2 inches in diameter, with doors at each end that are interlocked to prevent simultaneous opening. The air locks are provided with limit switches on both doors in each air lock that provide control room indication of door position. [Additionally, control room indication is provided to alert the operator whenever an air lock interlock mechanism is defeated.] During periods when primary containment is not required to be OPERABLE, the air lock interlock mechanism may be disabled, allowing both doors of an air lock to remain open for extended periods when frequent primary containment entry is necessary. Under some conditions, as allowed by this LCO, the primary containment may be accessed through the air lock when the door interlock mechanism has failed, by manually performing the interlock function.
The primary containment air locks form part of the primary containment pressure boundary. As such, air lock integrity and leak tightness are essential for maintaining primary containment leakage rate to within limits 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.
General Electric BWR/6 STS            B 3.6.1.2-1                                        Rev. 5.0
 
Primary Containment Air Locks B 3.6.1.2 BASES APPLICABLE          The DBA that postulates the maximum release of radioactive material SAFETY              within primary containment is a LOCA. In the analysis of this accident, it ANALYSES            is assumed that primary containment is OPERABLE, such that release of fission products to the environment is controlled by the rate of primary containment leakage. The primary containment is designed with a maximum allowable leakage rate (La) of [0.437]% by weight of the containment and drywell air per 24 hours at the calculated maximum peak containment pressure (Pa) of [11.5] psig. This allowable leakage rate forms the basis for the acceptance criteria imposed on the SRs associated with the air locks.
Primary containment air lock OPERABILITY is also required to minimize the amount of fission product gases that may escape primary containment through the air lock and contaminate and pressurize the secondary containment.
Primary containment air locks satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                As part of the primary containment pressure boundary, the air lock's safety function is related to control of containment leakage rates following a DBA. Thus, the air lock's structural integrity and leak tightness are essential to the successful mitigation of such an event.
The primary containment air locks are required to be OPERABLE. For each 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 to be open at a time. This provision ensures that a gross breach of primary containment does not exist when primary 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 primary containment.
APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the primary containment air lock is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.
General Electric BWR/6 STS            B 3.6.1.2-2                                        Rev. 5.0
 
Primary Containment Air Locks B 3.6.1.2 BASES ACTIONS            The ACTIONS are modified by Note 1, which allows entry and exit to perform repairs of 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 primary containment boundary is not intact (during access through the OPERABLE door). The ability to open the OPERABLE door, even if it means the primary containment boundary is temporarily not intact, is acceptable due to the low probability of an event that could pressurize the primary 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.
Note 2 has been included 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.
The ACTIONS are modified by a third Note, which ensures appropriate remedial actions are taken when necessary. Pursuant to LCO 3.0.6, ACTIONS are not required even if primary containment is exceeding its leakage limit. Therefore, the Note is added to require ACTIONS for LCO 3.6.1.1, "Primary Containment," to be taken in this event.
A.1, A.2, and A.3 With one primary containment air lock door inoperable in one or more primary containment air locks, the OPERABLE door must be verified closed (Required Action A.1) in each affected air lock. This ensures that a leak tight primary containment barrier is maintained by the use of an OPERABLE air lock door. This action must be completed within 1 hour.
The 1 hour Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, which requires that primary containment be restored to OPERABLE status within 1 hour.
General Electric BWR/6 STS            B 3.6.1.2-3                                        Rev. 5.0
 
Primary Containment Air Locks B 3.6.1.2 BASES ACTIONS (continued)
In addition, the affected air lock penetration must be isolated by locking closed the 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 ensures that the affected air lock with an inoperable door has been isolated by the use of a locked closed OPERABLE air lock door. This ensures that an acceptable primary 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 controls. Allowing verification by administrative controls 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 air lock are inoperable. With both doors in the 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.
Primary containment entry may be required to perform Technical Specifications (TS) Surveillances and Required Actions, as well as other activities on equipment inside primary 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-related activities) if the primary 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 primary containment during the short time that the OPERABLE door is expected to be open.
General Electric BWR/6 STS            B 3.6.1.2-4                                        Rev. 5.0
 
Primary Containment Air Locks B 3.6.1.2 BASES ACTIONS (continued)
B.1, B.2, and B.3 With an air lock interlock mechanism inoperable in one or both primary containment 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 one air lock are inoperable. With both doors in the 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 the primary 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 controls. Allowing verification by administrative controls 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 immediately initiated to evaluate containment overall leakage rates using current air lock leakage test results. An evaluation is acceptable since it is overly conservative to immediately declare the primary 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) primary containment remains OPERABLE, yet only 1 hour (according to LCO 3.6.1.1) 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 primary containment air locks must be verified closed. This Required Action must be completed within the 1 hour Completion Time. This specified time period is consistent with the ACTIONS of LCO 3.6.1.1, which require that primary containment be restored to OPERABLE status within 1 hour.
General Electric BWR/6 STS            B 3.6.1.2-5                                        Rev. 5.0
 
Primary Containment Air Locks B 3.6.1.2 BASES ACTIONS (continued)
Additionally, the air lock must be restored to OPERABLE status within 24 hours [or in accordance with the Risk Informed Completion Time Program]. The 24 hour Completion Time is reasonable for restoring an inoperable air lock to OPERABLE status considering that at least one door is maintained closed in each affected air lock.
D.1 and D.2 If the inoperable primary containment air lock cannot be restored to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 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 3.6.1.2.1 REQUIREMENTS Maintaining primary containment air locks OPERABLE requires compliance with the leakage rate test requirements of the Primary Containment Leakage Rate Testing Program. This SR reflects the leakage rate testing requirements with regard to air lock leakage (Type B leakage tests). The acceptance criteria were established [during initial air lock and primary containment OPERABILITY testing]. The periodic testing requirements verify that the air lock leakage does not exceed the allowed fraction of the overall primary containment leakage rate. The Frequency is required by the Primary 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 3.6.1.1.1. This ensures that air lock leakage is properly accounted for in determining the combined Type B and C primary containment leakage rate.
General Electric BWR/6 STS            B 3.6.1.2-6                                      Rev. 5.0
 
Primary Containment Air Locks B 3.6.1.2 BASES SURVEILLANCE REQUIREMENTS (continued)
[ SR 3.6.1.2.2 The seal air flask pressure is verified to be at  [90] psig every 7 days to ensure that the seal system remains viable. It must be checked because it could bleed down during or following access through the air lock, which occurs regularly. [ The 7 day Frequency has been shown to be acceptable through operating experience and is considered adequate in view of the other indications available to operations personnel that the seal air flask pressure is low.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
SR 3.6.1.2.3 The air lock interlock mechanism is designed to prevent simultaneous opening of both doors in the air lock. Since both the inner and outer doors of an air lock are designed to withstand the maximum expected post accident primary containment pressure (Ref. 3), closure of either door will support primary containment OPERABILITY. Thus, the interlock feature supports primary containment OPERABILITY while the air lock is being used for personnel transit in and out of the containment. Periodic testing of this interlock demonstrates that the interlock will function as designed and that simultaneous inner and outer door opening 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 primary containment air lock door is used for entry and exit (procedures require strict adherence to single door opening), this test is only required to be performed every 24 months. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage, and the potential for loss of primary 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.
General Electric BWR/6 STS                B 3.6.1.2-7                                                      Rev. 5.0
 
Primary Containment Air Locks B 3.6.1.2 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
[ SR 3.6.1.2.4 A seal pneumatic system test to ensure that pressure does not decay at a rate equivalent to > [2] psig for a period of [48] hours from an initial pressure of [90] psig is an effective leakage rate test to verify system performance. [ 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 [18] month Frequency, which is based on the refueling cycle.
Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
REFERENCES          1. FSAR, Section [3.8].
: 2. 10 CFR 50, Appendix J, Option [A][B].
: 3. FSAR, Table [6.2-13].
General Electric BWR/6 STS                B 3.6.1.2-8                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.3 Primary Containment Isolation Valves (PCIVs)
BASES BACKGROUND          The function of the PCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) to within limits. Primary containment isolation within the time limits specified for those PCIVs designed to close automatically ensures that the release of radioactive material to the environment will be consistent with the assumptions used in the analyses for a DBA.
The OPERABILITY requirements for PCIVs help ensure that an adequate primary containment boundary is maintained during and after an accident by minimizing potential paths to the environment. Therefore, the OPERABILITY requirements provide assurance that the primary containment function assumed in the safety analysis will be maintained.
These isolation devices consist of either passive devices or active (automatic) devices. 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.
The [6] and [20] inch primary containment purge valves are PCIVs that are qualified for use during all operational conditions. The [6] and
[20] inch primary containment purge valves are normally maintained closed in MODES 1, 2, and 3 to ensure leak tightness. The purge valves must be closed when not being used for pressure control, ALARA, or air quality considerations to ensure that the primary containment boundary assumed in the safety analysis will be maintained.
APPLICABLE          The PCIV LCO was derived from the assumptions related to minimizing SAFETY              the loss of reactor coolant inventory, and establishing the primary ANALYSES            containment boundary during major accidents. As part of the primary containment boundary, PCIV OPERABILITY supports leak tightness of primary containment. Therefore, the safety analysis of any event requiring isolation of primary containment is applicable to this LCO.
General Electric BWR/6 STS            B 3.6.1.3-1                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES APPLICABLE SAFETY ANALYSES (continued)
The DBAs that result in a release of radioactive material for which the consequences are mitigated by PCIVs are a loss of coolant accident (LOCA), a main steam line break (MSLB), and 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)] inside primary containment (Refs. 1 and 2). In the analysis for each of these accidents, it is assumed that PCIVs are either closed or function to close within the required isolation time following event initiation. This ensures that potential paths to the environment through PCIVs (including primary containment purge valves) are minimized. Of the events analyzed in Reference 1, the MSLB is the most limiting event due to radiological consequences. The closure time of the main steam isolation valves (MSIVs) is a significant variable from a radiological standpoint. The MSIVs are required to close within 3 to 5 seconds since the 5 second closure time is assumed in the analysis. The safety analyses assume that the purge valves are closed at event initiation. Likewise, it is assumed that the primary containment is isolated such that release of fission products to the environment is controlled.
The DBA analysis assumes that within 60 seconds after the accident, isolation of the primary containment is complete and leakage terminated, except for the maximum allowable leakage, La. The primary containment isolation total response time of 60 seconds includes signal delay, diesel generator startup (for loss of offsite power), and PCIV stroke times.
[ The single failure criterion required to be imposed in the conduct of unit safety analyses was considered in the original design of the primary 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 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, and 3. In this case, the single failure criterion remains applicable to the primary containment purge valve due to failure in the control circuit associated with each valve. Again, the primary containment purge valve design precludes a single failure from compromising the primary containment boundary as long as the system is operated in accordance with this LCO. ]
PCIVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS              B 3.6.1.3-2                                        Rev. 5.0
 
PCIVs B 3.6.1.3 BASES LCO                PCIVs form a part of the primary containment boundary. The PCIV safety function is related to minimizing the loss of reactor coolant inventory and establishing the primary containment boundary during a DBA.
The power operated, automatic isolation valves are required to have isolation times within limits and actuate on an automatic isolation signal.
Primary containment purge valves that are not qualified to close under accident conditions must be sealed closed [or blocked to prevent full opening] to be OPERABLE. The valves covered by this LCO are listed with their associated stroke times in the FSAR (Ref. 3).
The normally closed PCIVs are considered OPERABLE when manual valves are closed or open in accordance with appropriate administrative controls, 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 and devices are those listed in Reference 3.
Purge valves with resilient seals, secondary bypass valves, MSIVs, and hydrostatically tested valves must meet additional leakage rate requirements. Other PCIV leakage rates are addressed by LCO 3.6.1.1, "Primary Containment," as Type B or C testing.
This LCO provides assurance that the PCIVs will perform their designed safety functions to minimize the loss of reactor coolant inventory and establish the primary containment boundary during accidents.
APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, PCIVs are not required to be OPERABLE and the primary containment purge valves are not required to be sealed closed in MODES 4 and 5. Certain valves are required to be OPERABLE when the associated instrumentation is required to be OPERABLE according to LCO 3.3.6.1, "Primary Containment Isolation Instrumentation." (This does not include the valves that isolate the associated instrumentation.)
ACTIONS            The ACTIONS are modified by a Note allowing penetration flow path(s)
[except for the [ ] inch primary containment purge valve flow path(s)] to be unisolated intermittently under administrative controls. [The primary containment purge valve exception applies to primary containment purge valves that are not qualified to close under accident conditions.] These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for primary General Electric BWR/6 STS            B 3.6.1.3-3                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES ACTIONS (continued) containment isolation is indicated. Due to the size of the containment purge line penetration and the fact that those penetrations exhaust directly from the primary containment atmosphere to the environment, the penetration flow path containing these valves may not be opened under administrative controls. A single purge valve in a penetration flow path may be opened to effect repairs to an inoperable valve, as allowed by the exception to SR 3.6.1.3.1 and Note 2 to SR 3.6.1.3.2.
A second Note has been added to provide clarification that, for the purpose of 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 PCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable PCIVs are governed by subsequent Condition entry and application of associated Required Actions.
The ACTIONS are modified by Notes 3 and 4. Note 3 ensures appropriate remedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable PCIV (e.g., an Emergency Core Cooling System subsystem is inoperable due to a failed open test return valve). Note 4 ensures appropriate remedial actions are taken when the primary containment leakage limits are exceeded.
Pursuant to LCO 3.0.6, these ACTIONS are not required even when the associated LCO is not met. Therefore, Notes 3 and 4 are added to require the proper actions are taken.
A.1 and A.2
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Adoption of a Completion Time greater than 4 hours requires implementation of the following commitment: "Each licensee requesting extended Completion Times for PCIVs must commit to enhancing its configuration risk management program (CRMP), including those implemented under 10 CFR 50.65(a)(4), the Maintenance Rule, to include a Large Early Release Fraction (LERF) methodology and assessment.
This commitment and the CRMP enhancements must be documented in the licensees plant-specific application."
With one or more penetration flow paths with one PCIV inoperable,
[except for secondary containment bypass leakage rate, MSIV leakage rate, purge valve leakage rate, or hydrostatically tested line leakage rate not within limits], the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier General Electric BWR/6 STS                B 3.6.1.3-4                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES ACTIONS (continued) that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured. For penetrations isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available one to the primary containment. The Required Action must be completed within the specified Completion Time (4 hours for [feedwater isolation valves (FWIVs), residual heat removal (RHR) shutdown cooling suction line PCIVs, and Low Pressure Core Spray (LPCS) System PCIVs]; 8 hours for MISIVs; [and 7 days for other PCIVs in primary containment penetration flow paths with two [or more] PCIVs])
[or in accordance with the Risk Informed Completion Time Program]. For
[FWIVs, RHR shutdown cooling suction line PCIVs, and the LPCS System PCIVs], a 4 hour Completion Time is allowed. The Completion Time of 4 hours is reasonable considering the time required to isolate the affected penetration and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. For MSIVs, an 8 hour Completion Time is allowed. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.] The Completion Time of 8 hours allows a period of time to restore the MSIVs to OPERABLE status given the fact that MSIV closure will result in isolation of the main steam line(s) and a potential for plant shutdown.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
The 7 day Completion Time is only allowed for those plants which adopt NEDC-33046-A, "Technical Justification to Support Risk-Informed Primary Containment Isolation Valve AOT Extensions for BWR Plants,"
dated January 2005, including the conditions described in the incorporated safety evaluation.
Otherwise, a 4 hour Completion Time must be maintained for PCIVs other than MSIVs.
[For other PCIVs in primary containment penetration flow paths with two
[or more] PCIVs, a 7 day Completion Time is allowed. The Completion Time of 7 days provides the capability for on-line maintenance, repair, and testing of a PCIV and is reasonable considering the relative importance of supporting primary containment OPERABILITY in MODES 1, 2, and 3 (Ref. 4).]
For affected penetrations that have been isolated in accordance with Required Action A.1, the affected penetration flow path must be verified to be isolated on a periodic basis. This is necessary to ensure that primary containment penetrations required to be isolated following an accident, General Electric BWR/6 STS                B 3.6.1.3-5                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES ACTIONS (continued) 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 devices outside the primary containment, drywell, and steam tunnel and capable of being mispositioned are in the correct position.
The Completion Time for this verification of "once per 31 days [following isolation] for isolation devices outside primary containment, drywell, and steam tunnel," is appropriate because the devices are operated under administrative controls and the probability of their misalignment is low.
For devices inside the primary containment, drywell, or steam tunnel, the specified time period of "prior to entering MODE 2 or 3 from MODE 4, if not performed within the previous 92 days," is based on engineering judgment and is considered reasonable in view of the inaccessibility of the devices and the existence of other administrative controls ensuring that device misalignment is an unlikely possibility.
Condition A is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with two [or more] PCIVs. For penetration flow paths with one PCIV, Condition C provides appropriate Required Actions.
Required Action A.2 is modified by two Notes. Note 1 applies to isolation devices located in high radiation areas and allows them to be verified 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 low.
B.1 With one or more penetration flow paths with two [or more] PCIVs inoperable, [except for secondary containment bypass leakage rate, MSIV leakage rate, purge valve leakage rate, or hydrostatically tested line leakage rate not within limit], either the inoperable PCIVs must be restored to OPERABLE status or 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.
General Electric BWR/6 STS            B 3.6.1.3-6                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES ACTIONS (continued)
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 3.6.1.1.
Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two [or more] PCIVs. For penetration flow paths with one PCIV, Condition C provides the appropriate Required Actions.
C.1 and C.2 When one or more penetration flow paths with one PCIV inoperable,
[except for secondary containment bypass leakage rate, MSIV leakage rate, purge valve leakage rate, or hydrostatically tested line leakage rate not within limit], 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.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
The 7 day Completion Time is only allowed for those plants which adopt NEDC-33046-A, including the conditions described in the incorporated Safety Evaluation. Otherwise, a 4 hour Completion Time is provided for most penetrations and a 72 hour Completion Time is provided for closed system penetrations (for cases other than closed system penetrations, if a plant specific evaluation is provided for NRC review and accepted for a Completion Time of 72 hours, the Completion Time may be simplified to state 72 hours).
The Completion Time of [4] hours is reasonable considering the time required to isolate the penetration and the relative importance of supporting primary containment OPERABILITY during MODES 1, 2, and 3. [ The 72 hour Completion Time 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 primary containment OPERABILITY during MODES 1, 2, and 3. The closed system must meet the requirements of Ref. 5.] [The Completion Time of 7 days, for penetrations with a closed system, provides the capability for on-line maintenance, repair, and testing of a PCIV and is reasonable considering the relative importance of supporting primary General Electric BWR/6 STS                B 3.6.1.3-7                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES ACTIONS (continued) containment OPERABILITY in MODES 1, 2, and 3 (Ref. 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 ensure that primary containment penetrations required to be isolated following an accident are isolated. The Completion Time of once per 31 days [following isolation]
for verifying that each affected penetration is isolated is appropriate because the valves are operated under administrative controls and the probability of their misalignment is low.
Condition C is modified by a Note indicating this Condition is applicable only to those penetration flow paths with only one PCIV. For penetration flow paths with two PCIVs, Conditions A and B provide the appropriate Required Actions. This Note is necessary since this Condition is written specifically to address those penetrations with a single PCIV.
Required Action C.2 is modified by two Notes. Note 1 applies to valves and blind flanges located in high radiation areas and allows them to be verified 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 valves, once they have been verified to be in the proper position, is low.
[ D.1 With the [secondary containment bypass leakage rate (SR 3.6.1.3.9),]
MSIV leakage rate (SR 3.6.1.3.10), [purge valve leakage rate (SR 3.6.1.3.6),] [or] [hydrostatically tested line leakage rate (SR 3.6.1.3.11)], 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 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 isolation 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 hydrostatically tested line leakage [not on a closed system] and for secondary containment bypass leakage is reasonable General Electric BWR/6 STS              B 3.6.1.3-8                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES ACTIONS (continued) considering the time required to restore the leakage by isolating the penetration and the relative importance of secondary containment bypass leakage to the overall containment function. For MSIV leakage, an 8 hour Completion Time is allowed. The Completion Time of 8 hours for MSIV leakage allows a period of time to restore the MSIVs to OPERABLE status given the fact that MSIV closure will result in isolation of the main steam line(s) and potential for plant shutdown. [The 24 hour Completion Time for purge valve leakage is acceptable considering the purge valves remain closed so that a gross breach of the containment does not exist.]
[The 72 hour Completion Time for hydrostatically tested line leakage [on a closed system] is acceptable based on the available water seal expected to remain as a gaseous fission product boundary during the accident
[, and, in many cases, an associated closed system].
                    -----------------------------------REVIEWERS NOTE-----------------------------------
The bracketed options provided in ACTION D reflect options in plant design and options in adopting the associated leakage rate Surveillances.
The options (both in 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.
Adopting Completion Times for secondary containment bypass and/or hydrostatically tested lines is based on whether the associated SRs are adopted.
The additional bracketed options for whether the hydrostatically tested line is with or without a closed system is predicated on plant-specific design. If the design is such that there are not both types of hydrostatically tested lines (some with and some without closed systems),
the specific 'closed system' wording can be removed and the appropriate 4 or 72 hour Completion Time retained. In the event there are both types, the clarifying wording remains and the brackets are removed. ]
[ E.1, E.2, and E.3 In the event one or more containment purge valves 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 General Electric BWR/6 STS                B 3.6.1.3-9                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES ACTIONS (continued) adversely affected by a single active failure. Isolation barriers that meet this criterion are a [closed and de-activated automatic valve, closed manual valve, and blind flange]. If a purge valve with resilient seals is utilized to satisfy Required Action E.1 it must have been demonstrated to meet the leakage requirements of SR 3.6.1.3.6. The specified Completion Time is reasonable, considering that one containment purge valve remains closed so that a gross breach of containment does not exist. [Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.]
In accordance with Required Action E.2, this penetration flow path
[following isolation] 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 and potentially capable of being mispositioned are in the correct position. For the isolation devices inside containment, the time period specified as "prior to entering MODE 2 or 3 from MODE 4 if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of 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 3.6.1.3.6 must be performed at least once every [ ] days [following isolation]. This provides assurance 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 3.6.1.3.6 is 184 days. 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 [ ] days was chosen and has been shown acceptable based on operating experience.
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 General Electric BWR/6 STS            B 3.6.1.3-10                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES ACTIONS (continued) 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 any Required Action and associated Completion Time cannot be met in MODE 1, 2, or 3, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 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 and H.1 If any Required Action and associated Completion Time cannot be met, the plant must be placed in a condition in which the LCO does not apply.
If applicable, movement of [recently] irradiated fuel assemblies must be immediately suspended. Suspension of these activities shall not preclude completion of movement of a component to a safe condition. Also, if applicable, action must be immediately initiated to restore the valves to OPERABLE status. This allows RHR to remain in service while actions are being taken to restore the valve. ]
SURVEILLANCE        [ SR 3.6.1.3.1 REQUIREMENTS Each [ ] inch primary containment purge valve is required to be verified sealed closed. This SR is intended to apply to primary containment purge valves that are not fully qualified to open under accident conditions. This SR is designed to ensure that a gross breach of primary containment is not caused by an inadvertent or spurious opening of a primary 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. Primary containment purge valves that are sealed closed must have motive power to the valve operator removed. This can be accomplished by de-energizing the source of electric power or removing the air supply to the valve operator. In this application, the term "sealed" has no connotation of leak tightness. [ The 31 day Frequency is a result of an NRC initiative, Generic Issue B-24, (Ref. 6) related to primary containment purge valve use during unit operations.
OR General Electric BWR/6 STS            B 3.6.1.3-11                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
This SR allows a valve that is open under administrative controls to not meet the SR during the time the valve is open. Opening a purge valve under administrative controls is restricted to one valve in a penetration flow path at a given time (refer to discussion for Note 1 of the ACTIONS) in order to effect repairs to that valve. This allows one purge valve to be opened without resulting in a failure of the Surveillance and resultant entry into the ACTIONS for this purge valve, provided the stated restrictions are met. Condition E must be entered during this allowance, and the valve opened only as necessary for effecting repairs. Each purge valve in the penetration flow path may be alternately opened, provided one remains sealed closed, if necessary, to complete repairs on the penetration.
[ The SR is modified by a Note stating that primary containment purge valves are only required to be sealed closed in MODES 1, 2, and 3. If a LOCA inside primary containment occurs in these MODES, the purge valves may not be capable of closing before the pressure pulse affects systems downstream of the purge valves or the release of radioactive material will exceed limits prior to the closing of the purge valves. At other times when the purge valves are required to be capable of closing (e.g., during movement of [recently] irradiated fuel assemblies),
pressurization concerns are not present and the purge valves are allowed to be open. ] ]
[ SR 3.6.1.3.2 This SR verifies that the [20] inch primary containment purge 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.
General Electric BWR/6 STS                B 3.6.1.3-12                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES SURVEILLANCE REQUIREMENTS (continued)
The SR is also modified by a Note (Note 1) stating that primary containment purge valves are only required to be closed in MODES 1, 2, and 3. If a LOCA inside primary containment occurs in these MODES, the purge valves may not be capable of closing before the pressure pulse affects systems downstream of the purge valves, or the release of radioactive material will exceed limits prior to the purge valves closing. At other times when the purge valves are required to be capable of closing (e.g., during movement of irradiated fuel assemblies) pressurization concerns are not present and the purge valves are allowed to be open.
The SR is modified by a Note (Note 2) stating that the SR is not required to be met when the purge valves are open for the stated reasons. The Note states that these valves may be opened for pressure control, ALARA, or air quality considerations for personnel entry, or for Surveillances that require the valves to be open, provided the drywell
[purge supply and exhaust] lines are isolated. These primary containment purge valves are capable of closing in the environment following a LOCA. Therefore, these valves are allowed to be open for limited periods of time. [ The 31 day Frequency is consistent with other primary containment purge valve requirements discussed in SR 3.6.1.3.1.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
SR 3.6.1.3.3 This SR verifies that each primary containment isolation manual valve and blind flange that is located outside primary containment, drywell, and steam tunnel, and not locked, sealed, or otherwise secured and is required to be closed during accident conditions, is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside of the primary containment boundary is within design limits. This SR General Electric BWR/6 STS              B 3.6.1.3-13                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES SURVEILLANCE REQUIREMENTS (continued) does not require any testing or valve manipulation. Rather, it involves verification that those PCIVs outside primary containment, and capable of being mispositioned, are in the correct position. [ Since verification of valve position for PCIVs outside primary containment is relatively easy, the 31 day Frequency was chosen to provide added assurance that the PCIVs are in the correct positions. 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
Two Notes are added to this SR. The first Note applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in the proper position, is low. A second Note is included to clarify that PCIVs open under administrative controls are not required to meet the SR during the time the PCIVs are open.
SR 3.6.1.3.4 This SR verifies that each primary containment manual isolation valve and blind flange located inside primary containment, drywell, or steam tunnel, 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 primary containment boundary is within design limits. For PCIVs inside primary containment, drywell, or steam tunnel the Frequency of "prior to entering MODE 2 or 3 from MODE 4, if not performed within the previous 92 days," is appropriate since these PCIVs are operated under General Electric BWR/6 STS              B 3.6.1.3-14                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES SURVEILLANCE REQUIREMENTS (continued) administrative controls and the probability of their misalignment is low.
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.
Two Notes are added to this SR. The first Note allows valves and blind flanges located in high radiation areas to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable since access to these areas is typically restricted during MODES 1, 2, and 3. Therefore, the probability of misalignment of these PCIVs, once they have been verified to be in their proper position, is low. A second Note is included to clarify that PCIVs that are open under administrative controls are not required to meet the SR during the time that the PCIVs are open.
SR 3.6.1.3.5 Verifying the isolation time of each power operated, automatic PCIV is within limits is required to demonstrate OPERABILITY. MSIVs may be excluded from this SR since MSIV full closure isolation time is demonstrated by SR 3.6.1.3.6. The isolation time test ensures that the valve will isolate in a time period less than or equal to that assumed in the safety analysis. The isolation time is in accordance with the Inservice Testing Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
If the testing is within the scope of the licensee's INSERVICE TESTING PROGRAM, the Frequency "In accordance with the INSERVICE TESTING PROGRAM" should be used. Otherwise, the periodic Frequency of 92 days or the reference to the Surveillance Frequency Control Program should be used.
[ The Frequency of this SR is [in accordance with the INSERVICE TESTING PROGRAM] [92 days.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.]
General Electric BWR/6 STS              B 3.6.1.3-15                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
[ SR 3.6.1.3.6 For primary containment purge valves with resilient seals, additional leakage rate testing beyond the test requirements of 10 CFR 50, Appendix J, Option [A][B] (Ref. 7), 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 primary containment and the environment), a Frequency of 184 days was established.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
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 which occurs to a valve that has not been opened). Thus, decreasing the interval is a prudent measure after a valve has been opened.
The SR is modified by a Note stating that the primary containment purge valves are only required to meet leakage rate testing requirements in MODES 1, 2, and 3. If a LOCA inside primary containment occurs in these MODES, purge valve leakage must be minimized to ensure offsite radiological release is within limits. At other times when the purge valves are required to be capable of closing (e.g., during handling of [recently]
irradiated fuel), pressurization concerns are not present and the purge valves are not required to meet any specific leakage criteria. ]
General Electric BWR/6 STS                B 3.6.1.3-16                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.6.1.3.7 Verifying that the full closure isolation time of each MSIV is within the specified limits is required to demonstrate OPERABILITY. The full closure isolation time test ensures that the MSIV will isolate in a time period that does not exceed the times assumed in the DBA analyses.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
If the testing is within the scope of the licensee's INSERVICE TESTING PROGRAM, the Frequency "In accordance with the INSERVICE TESTING PROGRAM" should be used. Otherwise, the periodic Frequency of 92 days or the reference to the Surveillance Frequency Control Program should be used.
[ The Frequency of this SR is [in accordance with the INSERVICE TESTING PROGRAM] [18 months.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
SR 3.6.1.3.8 Automatic PCIVs close on a primary containment isolation signal to prevent leakage of radioactive material from primary containment following a DBA. This SR ensures that each automatic PCIV will actuate to its isolation position on a primary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.1.6 overlaps this SR to provide complete testing of the safety function. [ The [18] month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass this Surveillance when performed at the [18] month Frequency.
Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
General Electric BWR/6 STS              B 3.6.1.3-17                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
[ SR 3.6.1.3.9 This SR ensures that the leakage rate of secondary containment bypass leakage paths is less than the specified leakage rate. This provides assurance that the assumptions in the radiological evaluations of Reference 2 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 Primary Containment Leakage Rate Testing Program. This SR simply imposes additional acceptance criteria.
[ This SR is modified by a Note that states that these valves are only required to meet this leakage limit in MODES 1, 2, and 3. In the other conditions, the Reactor Coolant System is not pressurized and specific primary containment leakage limits are not required. ]
[ Bypass leakage is considered part of La.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Unless specifically exempted.] ]
SR 3.6.1.3.10 The analyses in References 1 and 2 are based on leakage that is less than the specified leakage rate. Leakage through all four MSIVs must be
[100] scfh when tested at Pt ([11.5] psig). A Note is added to this SR General Electric BWR/6 STS                B 3.6.1.3-18                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES SURVEILLANCE REQUIREMENTS (continued) which states that these valves are only required to meet this leakage limit in MODES 1, 2, and 3. In the other conditions, the Reactor Coolant System is not pressurized and specific primary containment leakage limits are not required. This ensures that MSIV leakage is properly accounted for in determining the overall primary containment leakage rate. The Frequency is required by the Primary Containment Leakage Rate Testing Program.
SR 3.6.1.3.11 Surveillance of hydrostatically tested lines provides assurance that the calculation assumptions of References 1 and 2 are met. The acceptance criteria for the combined leakage of all hydrostatically tested lines is [1.0 gpm times the total number of hydrostatically tested PCIVs] when tested at 1.1 Pa ([63.25] psig). The combined leakage rates must be demonstrated to be in accordance with the leakage test frequency required by the Primary Containment Leakage Rate Testing Program.
[ This SR is modified by a Note that states that these valves are only required to meet the combined leakage rate in MODES 1, 2, and 3 since this is when the Reactor Coolant System is pressurized and primary containment is required. In some instances, the valves are required to be capable of automatically closing during MODES other than MODES 1, 2, and 3. However, specific leakage limits are not applicable in these other MODES or conditions. ]
[ SR 3.6.1.3.12
                    -----------------------------------REVIEWERS NOTE-----------------------------------
This SR is only required for those plants with purge valves with resilient seals allowed to be open during [MODE 1, 2, or 3] and having blocking devices on the valves that are not permanently installed.
Verifying that each [ ] inch primary containment purge valve is blocked to restrict opening to  [50%] is required to ensure that the valves can close under DBA conditions within the time limits assumed in the analyses of References 1 and 2.
[ The SR is modified by a Note stating that this SR is only required to be met in MODES 1, 2, and 3. If a LOCA inside primary containment occurs in these MODES, the purge valves must close to maintain containment leakage within the values assumed in the accident analysis. At other General Electric BWR/6 STS                B 3.6.1.3-19                                                      Rev. 5.0
 
PCIVs B 3.6.1.3 BASES SURVEILLANCE REQUIREMENTS (continued) 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    --------------------------------------------------------------------------------------------- ] ] ]
REFERENCES          1. FSAR, Chapter [15].
: 2. FSAR, Section [6.2].
: 3. FSAR, [Table 6.2-44].
: 4. NEDC-33046-A, Revision 2, "Technical Justification to Support Risk-Informed Primary Containment Isolation Valve AOT Extensions for BWR Plants," January 2005.
: 5. FSAR, Section 6.2.[ ].
: 6. Generic Issue B-24.
: 7. 10 CFR 50, Appendix J, Option [A][B].
General Electric BWR/6 STS              B 3.6.1.3-20                                                      Rev. 5.0
 
Primary Containment Pressure B 3.6.1.4 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.4 Primary Containment Pressure BASES BACKGROUND          The primary containment pressure is limited during normal operation to preserve the initial conditions assumed in the accident analyses for a Design Basis Accident (DBA) or loss of coolant accident (LOCA).
The limits on primary containment [to secondary containment differential]
pressure have been developed based on operating experience. The auxiliary building, which is part of the secondary containment, completely surrounds the lower portion of the primary containment. Therefore, the primary containment design external differential pressure, and consequently the Specification limit, are established relative to the auxiliary building pressure. The auxiliary building pressure is kept slightly negative relative to the atmospheric pressure to prevent leakage to the atmosphere.
Transient events, which include inadvertent containment spray initiation, can reduce the primary containment pressure (Ref. 1). Without an appropriate limit on the negative containment pressure, the design limit for negative internal pressure of [-3.0] psid could be exceeded.
Therefore, the Specification pressure limits of [-0.1 and 1.0 psid] were established (Ref. 2).
The limitation on the primary [to secondary containment differential]
pressure provides added assurance that the peak LOCA primary containment pressure does not exceed the design value of 15 psig (Ref. 1).
APPLICABLE          Primary containment performance for the DBA is evaluated for the entire SAFETY              spectrum of break sizes for postulated LOCAs inside containment ANALYSES            (Ref. 3). Among the inputs to the design basis analysis is the initial primary containment internal pressure. The primary containment [to secondary containment differential] pressure can affect the initial containment internal pressure. The initial pressure limitation requirements ensure that peak primary containment pressure for a DBA LOCA does not exceed the design value of 15 psig and that peak negative pressure for an inadvertent containment spray event does not exceed the design value of [-3.0] psid.
Primary containment pressure satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS            B 3.6.1.4-1                                        Rev. 5.0
 
Primary Containment Pressure B 3.6.1.4 BASES LCO                A limitation on the primary [to secondary containment differential]
pressure of [ -0.1 and  1.0 psid] is required to ensure that primary containment initial conditions are consistent with the initial safety analyses assumptions so that containment pressures remain within design values during a LOCA and the design value of containment negative pressure is not exceeded during an inadvertent operation of containment sprays.
APPLICABILITY      In MODES 1, 2, and 3, a DBA could result in a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining primary containment pressure within limits is not required in MODE 4 or 5.
ACTIONS            A.1 When primary [to secondary containment differential] pressure is not within the limits of the LCO, differential pressure must be restored to within limits within 1 hour. The Required Action is necessary to return operation to within the bounds of the primary containment analysis. The 1 hour Completion Time is consistent with the ACTIONS of LCO 3.6.1.1, "Primary Containment," which requires that primary containment be restored to OPERABLE status within 1 hour.
B.1 and B.2 If primary [to secondary containment differential] 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 12 hours and to MODE 4 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 3.6.1.4.1 REQUIREMENTS Verifying that primary containment [to secondary containment differential]
pressure is within limits ensures that operation remains within the limits assumed in the primary containment analysis. [ The 12 hour Frequency of this SR was developed based on operating experience related to trending primary 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 primary containment pressure condition.
General Electric BWR/6 STS            B 3.6.1.4-2                                        Rev. 5.0
 
Primary Containment Pressure B 3.6.1.4 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [6.2.1].
: 2. FSAR, Section [6.2.1.1.4.2].
: 3. FSAR, Section [6.2].
General Electric BWR/6 STS                B 3.6.1.4-3                                                      Rev. 5.0
 
Primary Containment Air Temperature B 3.6.1.5 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.5 Primary Containment Air Temperature BASES BACKGROUND          Heat loads from the drywell, as well as piping and equipment in the primary containment, add energy to the primary containment airspace and raise airspace temperature. Coolers included in the unit design remove this energy and maintain an appropriate average temperature inside primary containment. The average airspace temperature affects the calculated response to postulated Design Basis Accidents (DBAs).
This primary containment air temperature limit is an initial condition input for the Reference 1 safety analyses.
APPLICABLE          Primary containment performance for the DBA is evaluated for a entire SAFETY              spectrum of break sizes for postulated loss of coolant accidents (LOCAs)
ANALYSES            inside containment (Ref. 1). Among the inputs to the design basis analysis is the initial primary containment average air temperature.
Analyses assume an initial average primary containment air (and suppression pool) temperature of [95]&deg;F. Maintaining the expected initial conditions ensures that safety analyses remain valid and ensures that the peak LOCA primary containment temperature does not exceed the maximum allowable temperature of 185&deg;F (Ref. 1). Exceeding this design temperature may result in the degradation of the primary containment structure under accident loads. Equipment inside primary containment, and needed to mitigate the effects of a DBA, is designed to operate and be capable of operating under environmental conditions expected for the accident.
Primary containment air temperature satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO                During a DBA, with an initial primary containment average air temperature less than or equal to the LCO temperature limit, the 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, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining primary containment average air temperature within the limit is not required in MODE 4 or 5.
General Electric BWR/6 STS            B 3.6.1.5-1                                        Rev. 5.0
 
Primary Containment Air Temperature B 3.6.1.5 BASES ACTIONS              A.1 When primary containment average air temperature is not within the limit of the LCO, it must be restored within 8 hours. This Required Action is necessary to return operation to within the bounds of the primary 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.
B.1 and B.2 If the primary containment average air temperature cannot be restored to within 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 12 hours and to MODE 4 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 3.6.1.5.1 REQUIREMENTS Verifying that the primary containment average air temperature is within the LCO limit ensures that operation remains within the limits assumed for the primary containment analyses. In order to determine the primary containment average air temperature, an arithmetic average is calculated, using measurements taken at locations within the primary containment selected to provide a representative sample of the overall primary containment atmosphere.
[ The 24 hour Frequency of this SR is considered acceptable based on observed slow rates of temperature increase within primary containment as a result of environmental heat sources (due to large volume of the primary 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 primary containment air temperature condition.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS              B 3.6.1.5-2                                        Rev. 5.0
 
Primary Containment Air Temperature B 3.6.1.5 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [6.2].
General Electric BWR/6 STS                B 3.6.1.5-3                                                      Rev. 5.0
 
LLS Valves B 3.6.1.6 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.6 Low-Low Set (LLS) Valves BASES BACKGROUND          The safety/relief valves (S/RVs) can actuate either in the relief mode, the safety mode, the Automatic Depressurization System mode, or the LLS mode. In the LLS mode (or power actuated mode of operation), a pneumatic diaphragm and stem assembly overcome the spring force and open the pilot valve. As in the safety mode, opening the pilot valve allows a differential pressure to develop across the main valve piston and thus opens the main valve. The main valve can stay open with valve inlet steam pressure as low as [0] psig. The pneumatic operator is arranged so that its malfunction will not prevent the valve disk from lifting if steam inlet pressure exceeds the safety mode pressure setpoints.
[Six] of the S/RVs are equipped to provide the LLS function. The LLS logic causes the LLS valves to be opened at a lower pressure than the relief or safety mode pressure setpoints and stay open longer, such that reopening of more than one S/RV is prevented on subsequent actuations.
Therefore, the LLS function prevents excessive short duration S/RV cycles with valve actuation at the relief setpoint.
Each S/RV discharges steam through a discharge line and quencher to a location near the bottom of the suppression pool, which causes a load on the suppression pool wall. Actuation at lower reactor pressure results in a lower load.
APPLICABLE          The LLS relief mode functions to ensure that the containment design SAFETY              basis of one S/RV operating on "subsequent actuations" is met (Ref. 1).
ANALYSES            In other words, multiple simultaneous openings of S/RVs (following the initial opening) and the corresponding higher loads, are avoided. The safety analysis demonstrates that the LLS functions to avoid the induced thrust loads on the S/RV discharge line resulting from "subsequent actuations" of the S/RV during Design Basis Accidents (DBAs).
Furthermore, the LLS function justifies the primary containment analysis assumption that multiple simultaneous S/RV openings occur only on the initial actuation for DBAs. Even though [six] LLS S/RVs are specified, all
[six] LLS S/RVs do not operate in any DBA analysis.
LLS valves satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                [Six LLS valves are required to be OPERABLE to satisfy the assumptions of the safety analysis (Ref. 2). The requirements of this LCO are applicable to the mechanical and electrical/pneumatic capability of the LLS valves to function for controlling the opening and closing of the S/RVs General Electric BWR/6 STS            B 3.6.1.6-1                                          Rev. 5.0
 
LLS Valves B 3.6.1.6 BASES APPLICABILITY      In MODES 1, 2, and 3, an event could cause pressurization of the reactor and opening of S/RVs. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the LLS valves OPERABLE is not required in MODE 4 or 5.
ACTIONS            A.1 With one LLS valve inoperable, the remaining OPERABLE LLS valves are adequate to perform the designed function. However, the overall reliability is reduced. The 14 day Completion Time takes into account the redundant capability afforded by the remaining LLS S/RVs and the low probability of an event in which the remaining LLS S/RV capability would be inadequate.
B.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
If the inoperable LLS valve cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 3) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action B.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, General Electric BWR/6 STS                B 3.6.1.6-2                                                      Rev. 5.0
 
LLS Valves B 3.6.1.6 BASES ACTIONS (continued) because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is 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 If two or more LLS valves are inoperable, there could be excessive short duration S/RV cycling during an overpressure event. The plant must be brought to a condition in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and MODE 4 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 3.6.1.6.1 REQUIREMENTS A manual actuation of each LLS valve is performed to verify that the valve and solenoids are functioning properly and that no blockage exists in the valve discharge line. This can be demonstrated by the response of the turbine control or bypass valve, by a change in the measured steam flow, or by any other method that is suitable to verify steam flow. Adequate reactor steam dome pressure must be available to perform this test to avoid damaging the valve. Adequate pressure at which this test is to be performed is  [950] psig (the pressure recommended by the valve manufacturer). Also, adequate steam flow must be passing through the main turbine or turbine bypass valves to continue to control reactor pressure when the ADS valves divert steam flow upon opening.
Adequate steam flow is represented by [at least 1.25 turbine bypass valves open, or total steam flow  106 lb/hr]. [ The [18] month Frequency was developed based on the S/RV tests required by the ASME Boiler and Pressure Vessel Code (Ref. 4). The Frequency of [18] months on a STAGGERED TEST BASIS ensures that each solenoid for each S/RV is alternately tested. Operating experience has shown these components usually pass the Surveillance when performed at the [18] month General Electric BWR/6 STS            B 3.6.1.6-3                                        Rev. 5.0
 
LLS Valves B 3.6.1.6 BASES SURVEILLANCE REQUIREMENTS (continued)
Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
Since steam pressure is required in order to perform the Surveillance, however, and steam may not be available during a unit outage, the Surveillance may be performed during the shutdown prior to or the startup following a unit outage. Unit startup is allowed prior to performing this test because valve OPERABILITY and the setpoints for overpressure protection are verified by Reference 4 prior to valve installation. After adequate reactor steam dome pressure and flow are reached, 12 hours are allowed to prepare for and perform the test.
SR 3.6.1.6.2 The LLS designed S/RVs are required to actuate automatically upon receipt of specific initiation signals. A system functional test is performed to verify that the mechanical portions (i.e., solenoids) of the automatic LLS function operate as designed when initiated either by an actual or simulated automatic initiation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.5.4 overlaps this SR to provide complete testing of the safety function.
[ The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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 was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.6.1.6-4                                                      Rev. 5.0
 
LLS Valves B 3.6.1.6 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
This SR is modified by a Note that excludes valve actuation. This prevents a reactor pressure vessel pressure blowdown.
REFERENCES          [ 1. GESSAR-II, Appendix 3BA.8. ]
: 2. FSAR, Section [5.5.17].
: 3. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
: 4. ASME Code for Operation and Maintenance of Nuclear Power Plants.
General Electric BWR/6 STS                B 3.6.1.6-5                                                      Rev. 5.0
 
RHR Containment Spray System B 3.6.1.7 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.7 Residual Heat Removal (RHR) Containment Spray System BASES BACKGROUND          The primary containment is designed with a suppression pool so that, in the event of a loss of coolant accident (LOCA), steam released from the primary system is channeled through the suppression pool water and condensed without producing significant pressurization of the primary containment. The primary containment is designed so that with the pool initially at the minimum water volume and the worst single failure of the primary containment heat removal systems, suppression pool energy absorption combined with subsequent operator controlled pool cooling will prevent the primary containment pressure from exceeding its design value. However, the primary containment must also withstand a postulated bypass leakage pathway that allows the passage of steam from the drywell directly into the primary containment airspace, bypassing the suppression pool. The primary containment also must withstand a low energy steam release into the primary containment airspace. The RHR Containment Spray System is designed to mitigate the effects of bypass leakage and low energy line breaks.
There are two redundant, 100% capacity RHR containment spray subsystems. Each subsystem consists of a suction line from the suppression pool, an RHR pump, a heat exchanger, and three spray spargers inside the primary containment (outside of the drywell) above the refueling floor. Dispersion of the spray water is accomplished by 350 nozzles in each subsystem.
The RHR containment spray mode will be automatically initiated, if required, following a LOCA, or it may be manually initiated according to emergency procedures.
APPLICABLE          Reference 1 contains the results of analyses that predict the primary SAFETY              containment pressure response for a LOCA with the maximum allowable ANALYSES            bypass leakage area.
The equivalent flow path area for bypass leakage has been specified to be [0.9] ft2. The analysis demonstrates that with containment spray operation the primary containment pressure remains within design limits.
The RHR Containment Spray System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS              B 3.6.1.7-1                                    Rev. 5.0
 
RHR Containment Spray System B 3.6.1.7 BASES LCO                In the event of a Design Basis Accident (DBA), a minimum of one RHR containment spray subsystem is required to mitigate potential bypass leakage paths and maintain the primary containment peak pressure below design limits. To ensure that these requirements are met, two RHR containment spray subsystems must be OPERABLE. Therefore, in the event of an accident, at least one subsystem is OPERABLE assuming the worst case single active failure. An RHR containment spray subsystem is OPERABLE when the pump, the heat exchanger, and associated piping, valves, instrumentation, and controls are OPERABLE.
Management of gas voids is important to RHR Containment Spray System OPERABILITY.
APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause pressurization of primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining RHR containment spray subsystems OPERABLE is not required in MODE 4 or 5.
ACTIONS            A.1 With one RHR containment spray subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days [or in accordance with the Risk Informed Completion Time Program]. In this Condition, the remaining OPERABLE RHR containment spray subsystem is adequate to perform the primary containment cooling function.
However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced primary containment cooling capability. The 7 day Completion Time was chosen in light of the redundant RHR containment capabilities afforded by the OPERABLE subsystem and the low probability of a DBA occurring during this period.
B.1 With two RHR containment spray subsystems inoperable, one subsystem must be restored to OPERABLE status within 8 hours. In this Condition, there is a substantial loss of the primary containment bypass leakage mitigation function. The 8 hour Completion Time is based on this loss of function and is considered acceptable due to the low probability of a DBA and because alternative methods to remove heat from primary containment are available.
General Electric BWR/6 STS            B 3.6.1.7-2                                      Rev. 5.0
 
RHR Containment Spray System B 3.6.1.7 BASES ACTIONS (continued)
C.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
If the inoperable RHR containment spray subsystem cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action C.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
General Electric BWR/6 STS                B 3.6.1.7-3                                                      Rev. 5.0
 
RHR Containment Spray System B 3.6.1.7 BASES SURVEILLANCE        SR 3.6.1.7.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in the RHR containment spray mode flow path provides assurance that the proper flow paths will exist for 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 locking, sealing, or securing. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.
[ The 31 day Frequency of this SR is justified because the valves are operated under procedural control and because improper valve position would affect only a single subsystem. This Frequency has been shown to be acceptable based on operating experience.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
Two Notes have been added to this SR. The first Note allows RHR containment spray subsystems to be considered OPERABLE during alignment to and operation in the RHR shutdown cooling mode when below [the RHR cut in permissive pressure in MODE 3], if capable of being manually realigned and not otherwise inoperable. At these low pressures and decay heat levels (the reactor is shut down in MODE 3), a reduced complement of subsystems can provide the required containment pressure mitigation function thereby allowing operation of an RHR shutdown cooling loop when necessary. The second Note exempts system vent flow paths opened under administrative control. The administrative control should be proceduralized and include stationing a dedicated individual at the system vent flow path who is in continuous communication with the operators in the control room. This individual will have a method to rapidly close the system vent flow path if directed.
General Electric BWR/6 STS                B 3.6.1.7-4                                                      Rev. 5.0
 
RHR Containment Spray System B 3.6.1.7 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.6.1.7.2 RHR Containment Spray System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR suppression pool spray subsystems and may also prevent water hammer and pump cavitation.
Selection of RHR Containment Spray System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration.
Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.
The RHR Containment Spray System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the Surveillance is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RHR Containment Spray System is not rendered inoperable by the accumulated gas (i.e., the system is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits.
RHR Containment Spray System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for General Electric BWR/6 STS            B 3.6.1.7-5                                      Rev. 5.0
 
RHR Containment Spray System B 3.6.1.7 BASES SURVEILLANCE REQUIREMENTS (continued) susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.
[ The 31 day Frequency takes into consideration the gradual nature of gas accumulation in the RHR Containment Spray System piping and the procedural controls governing system operation.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.1.7.3 Verifying each RHR pump develops a flow rate  [5650] gpm while operating in the suppression pool cooling mode with flow through the associated heat exchanger ensures that pump performance has not degraded during the cycle. It is tested in the pool cooling mode to demonstrate pump OPERABILITY without spraying down equipment in primary containment. Flow is a normal test of centrifugal pump performance required by the ASME Code (Ref. 3). 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.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
If the testing is within the scope of the licensee's INSERVICE TESTING PROGRAM, the Frequency "In accordance with the INSERVICE TESTING PROGRAM" should be used. Otherwise, the periodic Frequency of 92 days or the reference to the Surveillance Frequency Control Program should be used.
General Electric BWR/6 STS                B 3.6.1.7-6                                                      Rev. 5.0
 
RHR Containment Spray System B 3.6.1.7 BASES SURVEILLANCE REQUIREMENTS (continued)
[ The Frequency of this SR is [in accordance with the INSERVICE TESTING PROGRAM] [92 days.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
SR 3.6.1.7.4 This SR verifies that each RHR containment spray subsystem automatic valve actuates to its correct position upon receipt of an actual or simulated automatic actuation signal. Actual spray initiation is not required to meet this SR. The SR excludes automatic valves that are locked, sealed, or otherwise secured in the actuated position. The SR does not apply to valves that are locked, sealed, or otherwise secured in the actuated position since the affected valves were verified to be in the actuated position prior to being locked, sealed, or otherwise secured.
Placing an automatic valve in a locked, sealed, or otherwise secured position requires an assessment of the OPERABILITY of the system or any supported systems, including whether it is necessary for the valve to be repositioned to the non-actuated position to support the accident analysis. Restoration of an automatic valve to the non-actuated position requires verification that the SR has been met within its required Frequency. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.3.6 overlaps this SR to provide complete testing of the safety function. [ The
[18] month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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.
OR General Electric BWR/6 STS                B 3.6.1.7-7                                                      Rev. 5.0
 
RHR Containment Spray System B 3.6.1.7 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.1.7.5 This Surveillance is performed to verify that the spray nozzles are not obstructed and that flow will be provided when required. [ The 10 year Frequency is adequate to detect degradation in performance due to the passive nozzle design and its normally dry state and has been shown to be acceptable through operating experience.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [6.2.1.1.5].
: 2. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
: 3. ASME Code for Operation and Maintenance of Nuclear Power Plants.
General Electric BWR/6 STS                B 3.6.1.7-8                                                      Rev. 5.0
 
PVLCS B 3.6.1.8 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.8 Penetration Valve Leakage Control System (PVLCS)
BASES BACKGROUND            The PVLCS supplements the isolation function of primary containment isolation valves (PCIVs) in process lines that also penetrate the secondary containment. These penetrations are sealed by air from the PVLCS to prevent fission products leaking past the isolation valves and bypassing the secondary containment after a Design Basis Accident (DBA) loss of coolant accident (LOCA).
The PVLCS consists of [two] independent, manually initiated subsystems, either of which is capable of preventing fission product leakage from the containment post LOCA. Each subsystem is comprised of an air compressor, an accumulator, an injection valve, and three injection headers with separate isolation valves. This system has additional headers, which serve the Main Steam Isolation Valve Leakage Control System and safety/relief valve (S/RV) actuator air accumulators.
Each process line has two PCIVs and an additional manual isolation valve outside of the outboard PCIV. The two outboard valves are double disk gate valves. Each valve is provided sealing air from its electrically associated division of PVLCS to the area between the dual disk seats.
The PVLCS is started manually.
APPLICABLE            The analyses described in Reference 1 provide the evaluation of offsite SAFETY                dose consequences during accident conditions. During the first ANALYSES              25 minutes following an accident, the isolation valves on lines that penetrate primary containment and also penetrate secondary containment are assumed to leak fission products directly to the environment, without being processed by the Standby Gas Treatment System. The analyses take credit for manually initiating PVLCS after 25 minutes and do not assume any further secondary containment bypass leakage.
The PVLCS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                  [Two] PVLCS subsystems must be OPERABLE such that in the event of an accident, at least one subsystem is OPERABLE assuming the worst case single active failure. A PVLCS subsystem is OPERABLE when all necessary components are available to supply each associated dual seat isolation valve with sufficient air pressure to preclude containment leakage when the containment atmosphere is at the maximum peak containment pressure, Pa.
General Electric BWR/6 STS              B 3.6.1.8-1                                      Rev. 5.0
 
PVLCS B 3.6.1.8 BASES APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the PVLCS is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of radioactive material from primary containment.
ACTIONS            A.1 With one PVLCS subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE PVLCS subsystem is adequate to perform the leakage control function. The 30 day Completion Time is based on the low probability of the occurrence of a LOCA, the amount of time available after the event for operator action to prevent exceeding this limit, the low probability of failure of the OPERABLE PVLCS subsystem, and the availability of the PCIVs.
B.1 With [two] PVLCS subsystems inoperable, at least one subsystem must be restored to OPERABLE status within 7 days. The 7 day Completion Time is based on the low probability of the occurrence of a DBA LOCA, the availability of 25 minutes for operator action, and the availability of the PCIVs.
C.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
If the inoperable PVLCS subsystem cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
General Electric BWR/6 STS                B 3.6.1.8-2                                                      Rev. 5.0
 
PVLCS B 3.6.1.8 BASES ACTIONS (continued)
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action C.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is 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 3.6.1.8.1 REQUIREMENTS The minimum air supply necessary for PVLCS OPERABILITY varies with the system being supplied with compressed air from the PVLCS accumulators. Due to the support system function of PVLCS for S/RV actuator air, however, the specified minimum pressure of [101] psig is required, which provides sufficient air for [ ] S/RV actuations with the drywell pressure at 30 psig. This minimum air pressure alone is sufficient for PVLCS to support the OPERABILITY of these S/RV systems and is verified every 24 hours. [ The 24 hour Frequency is considered adequate in view of other indications available in the control room, such as alarms, to alert the operator to an abnormal PVLCS air pressure condition.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS            B 3.6.1.8-3                                        Rev. 5.0
 
PVLCS B 3.6.1.8 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.1.8.2 A simulated system operation is performed to ensure that the PVLCS will function throughout its operating sequence. This includes correct automatic positioning of valves once the system is initiated manually.
Proper functioning of the compressor and valves is verified by this Surveillance. [ The [18] month Frequency was developed considering it is prudent that many Surveillances be performed only during a plant outage.
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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [15.6.5].
: 2. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
General Electric BWR/6 STS                B 3.6.1.8-4                                                      Rev. 5.0
 
MSIV LCS B 3.6.1.9 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.9 Main Steam Isolation Valve (MSIV) Leakage Control System (LCS)
BASES BACKGROUND          The MSIV LCS supplements the isolation function of the MSIVs by processing the fission products that could leak through the closed MSIVs after a Design Basis Accident (DBA) loss of coolant accident (LOCA).
The MSIV LCS consists of two independent subsystems: an inboard subsystem, which is connected between the inboard and outboard MSIVs; and an outboard subsystem, which is connected immediately downstream of the outboard MSIVs. Each subsystem is capable of processing leakage from MSIVs following a DBA LOCA. Each subsystem consists of blowers (four blowers for the inboard subsystem and two blowers for the outboard subsystem), valves, piping, and heaters (for the inboard subsystem only). The four electric heaters in the inboard subsystem are provided to boil off any condensate prior to the gas mixture passing through the flow limiter.
Each subsystem operates in two process modes: depressurization and bleedoff. The depressurization process reduces the steam line pressure to within the operating capability of equipment used for the bleedoff mode. During bleedoff (long term leakage control), the blowers maintain a negative pressure in the main steam lines (Ref. 1). This ensures that leakage through the closed MSIVs is collected by the MSIV LCS. In both process modes, the effluent is discharged to the auxiliary building, which encloses a volume served by the Standby Gas Treatment (SGT) System.
The MSIV LCS is manually initiated approximately 20 minutes following a DBA LOCA (Ref. 2).
APPLICABLE          The MSIV LCS mitigates the consequences of a DBA LOCA by ensuring SAFETY              that fission products that may leak from the closed MSIVs are diverted to ANALYSES            the auxiliary building and ultimately filtered by the SGT System. The analyses in Reference 3 provide the evaluation of offsite dose consequences. The operation of the MSIV LCS prevents a release of untreated leakage for this type of event.
The MSIV LCS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                One MSIV LCS subsystem can provide the required processing of the MSIV leakage. To ensure that this capability is available, assuming worst case single failure, two MSIV LCS subsystems must be OPERABLE.
General Electric BWR/6 STS            B 3.6.1.9-1                                      Rev. 5.0
 
MSIV LCS B 3.6.1.9 BASES APPLICABILITY      In MODES 1, 2, and 3, a DBA could lead to a fission product release to primary containment. Therefore, MSIV LCS OPERABILITY is required during these MODES. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the MSIV LCS OPERABLE is not required in MODE 4 or 5 to ensure MSIV leakage is processed.
ACTIONS            A.1 With one MSIV LCS subsystem inoperable, the inoperable MSIV LCS subsystem must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE MSIV LCS subsystem is adequate to perform the required leakage control function. However, the overall reliability is reduced because a single failure in the remaining subsystem could result in a total loss of MSIV leakage control function. The 30 day Completion Time is based on the redundant capability afforded by the remaining OPERABLE MSIV LCS subsystem and the low probability of a DBA LOCA occurring during this period.
B.1 With two MSIV LCS subsystems inoperable, at least one subsystem must be restored to OPERABLE status within 7 days. The 7 day Completion Time is based on the low probability of the occurrence of a DBA LOCA.
C.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
If the MSIV LCS subsystem cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
General Electric BWR/6 STS                B 3.6.1.9-2                                                      Rev. 5.0
 
MSIV LCS B 3.6.1.9 BASES ACTIONS (continued)
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action C.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is 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 3.6.1.9.1 REQUIREMENTS Each MSIV LCS blower is operated for  [15] minutes to verify OPERABILITY. [ The 31 day Frequency was developed considering the known reliability of the LCS blower and controls, the two subsystem redundancy, and the low probability of a significant degradation of the MSIV LCS subsystem occurring between surveillances and has been shown to be acceptable through operating experience.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.6.1.9-3                                                      Rev. 5.0
 
MSIV LCS B 3.6.1.9 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.6.1.9.2 The electrical continuity of each inboard MSIV LCS subsystem heater is verified by a resistance check, by verifying the rate of temperature increase meets specifications, or by verifying the current or wattage draw meets specifications. [ The 31 day Frequency is based on operating experience that has shown that these components usually pass this Surveillance when performed at this Frequency.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.1.9.3 A system functional test is performed to ensure that the MSIV LCS will operate through its operating sequence. This includes verifying that the automatic positioning of the valves and the operation of each interlock and timer are correct, that the blowers start and develop the required flow rate and the necessary vacuum, and the upstream heaters meet current or wattage draw requirements (if not used to verify electrical continuity in SR 3.6.1.9.2). [ 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency General Electric BWR/6 STS                B 3.6.1.9-4                                                      Rev. 5.0
 
MSIV LCS B 3.6.1.9 BASES SURVEILLANCE REQUIREMENTS (continued) description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [6.7].
: 2. Regulatory Guide 1.96, Revision [1].
: 3. FSAR, Section [15.6.5].
: 4. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
General Electric BWR/6 STS                B 3.6.1.9-5                                                      Rev. 5.0
 
Suppression Pool Average Temperature B 3.6.2.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.1 Suppression Pool Average Temperature BASES BACKGROUND          The suppression pool is a concentric open container of water with a stainless steel liner that is located at the bottom of the primary containment. The suppression pool is designed to absorb the decay heat and sensible heat released during a reactor blowdown from safety/relief valve discharges or from a loss of coolant accident (LOCA). The suppression pool must also condense steam from the Reactor Core Isolation Cooling System turbine exhaust and provides the main emergency water supply source for the reactor vessel. The amount of energy that the pool can absorb as it condenses steam is dependent upon the initial average suppression pool temperature. The lower the initial pool temperature, the more heat it can absorb without heating up excessively. Since it is an open pool, its temperature will affect both primary containment pressure and average air temperature. Using conservative inputs and methods, the maximum calculated primary containment pressure during and following a Design Basis Accident (DBA) must remain below the primary containment design pressure of
[15] psig. In addition, the maximum primary containment average air temperature must remain < [185]&deg;F.
The technical concerns that lead to the development of suppression pool average temperature limits are as follows:
: a. Complete steam condensation - [the original limit for the end of a LOCA blowdown was 170&deg;F, based on the Bodega Bay and Humboldt Bay Tests],
: b. Primary containment peak pressure and temperature - [the design pressure is [15] psig and design temperature is [185]&deg;F],
: c. Condensation oscillation (CO) loads - [a maximum allowable initial temperature of [100]&deg;F ensures that CO loads do not exceed the Mark III CO load definition], and
: d. Chugging load - [a maximum allowable initial temperature of [100]&deg;F ensures that expected LOCA temperatures are within the range of Mark III tested conditions].
General Electric BWR/6 STS            B 3.6.2.1-1                                      Rev. 5.0
 
Suppression Pool Average Temperature B 3.6.2.1 BASES APPLICABLE          The postulated DBA against which the primary containment performance SAFETY              is evaluated is the entire spectrum of postulated pipe breaks within the ANALYSES            primary containment. Inputs to the safety analyses include initial suppression pool water volume and suppression pool temperature (Reference 1 for LOCAs and Reference 2 for the suppression pool temperature analyses required by Reference 3). An initial pool temperature of [95]&deg;F is assumed for the Reference 1 and 2 analyses.
Reactor shutdown at a pool temperature of [110]&deg;F and vessel depressurization at a pool temperature of [120]&deg;F are assumed for the Reference 2 analyses. The limit of [105]&deg;F, at which testing is terminated, is not used in the safety analyses because DBAs are assumed to not initiate during plant testing.
Suppression pool average temperature satisfies Criteria 2 and 3 of 10 CFR 50.36(c)(2)(ii).
LCO                A limitation on the suppression pool average temperature is required to assure that the primary containment conditions assumed for the safety analyses are met. This limitation subsequently ensures that peak primary containment pressures and temperatures do not exceed maximum allowable values during a postulated DBA or any transient resulting in heatup of the suppression pool. The LCO requirements are as follows:
: a. Average temperature  [95]&deg;F [when any OPERABLE intermediate range monitor (IRM) channel is > [25/40] divisions of full scale on Range 7] [with THERMAL POWER > 1% RATED THERMAL POWER (RTP)], and no testing that adds heat to the suppression pool is being performed. This requirement ensures that licensing bases initial conditions are met.
: b. Average temperature  [105]&deg;F [when any OPERABLE IRM channel is > [25/40] divisions of full scale on Range 7] [with THERMAL POWER > 1% RTP] and testing that adds heat to the suppression pool is being performed. This requirement ensures that the plant has testing flexibility, and was selected to provide margin below the
[110]&deg;F limit at which reactor shutdown is required. When testing ends, temperature must be restored to  [95]&deg;F within 24 hours according to Required Action A.2. Therefore, the time period that the temperature is > [95]&deg;F is short enough not to cause a significant increase in plant risk.
: c. Average temperature  [110]&deg;F [when all OPERABLE IRM channels are  [25/40] divisions of full scale on Range 7] [with THERMAL POWER  1% RTP]. This requirement ensures that the plant will be shut down at > [110]&deg;F. The pool is designed to absorb decay heat and sensible heat but could be heated beyond design limits by the steam generated if the reactor is not shut down.
General Electric BWR/6 STS              B 3.6.2.1-2                                      Rev. 5.0
 
Suppression Pool Average Temperature B 3.6.2.1 BASES LCO (continued)
[Note that [25/40] divisions of full scale on IRM Range 7 is a convenient measure of when the reactor is producing power essentially equivalent to 1% RTP]. At [this power level] [1% RTP], heat input is approximately equal to normal system heat losses.
APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause significant heatup of the suppression pool. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining suppression pool average temperature within limits is not required in MODE 4 or 5.
ACTIONS            A.1 and A.2 With the suppression pool average temperature above the specified limit when not performing testing that adds heat to the suppression pool and when above the specified power indication, the initial conditions exceed the conditions assumed for the Reference 1 and 3 analyses. However, primary containment cooling capability still exists, and the primary containment pressure suppression function will occur at temperatures well above that assumed for safety analyses. Therefore, continued operation is allowed for a limited time. The 24 hour Completion Time is adequate to allow the suppression pool temperature to be restored to below the limit. Additionally, when pool temperature is > [95]&deg;F, increased monitoring of the pool temperature is required to ensure it remains  [110]&deg;F. The once per hour Completion Time is adequate based on past experience, which has shown that suppression pool temperature increases relatively slowly except when testing that adds heat to the pool is being performed. Furthermore, the once per hour Completion Time is considered adequate in view of other indications in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.
B.1 If the suppression pool average temperature 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, THERMAL POWER must be reduced to [ [25/40] divisions of full scale on Range 7 for all OPERABLE IRM channels] [ 1% RTP] within 12 hours. The 12 hour Completion Time is reasonable, based on operating experience, to reduce reactor power from full power in an orderly manner and without challenging plant systems.
General Electric BWR/6 STS            B 3.6.2.1-3                                      Rev. 5.0
 
Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS (continued)
C.1 Suppression pool average temperature is allowed to be > [95]&deg;F [with any OPERABLE IRM channel > [25/40] divisions of full scale on Range 7]
[with THERMAL POWER > 1% RTP] when testing that adds heat to the suppression pool is being performed. However, if temperature is
                    > [105]&deg;F, the testing must be immediately suspended to preserve the pool's heat absorption capability. With the testing suspended, Condition A is entered and the Required Actions and associated Completion Times are applicable.
D.1, D.2, and D.3 Suppression pool average temperature > [110]&deg;F requires that the reactor be shut down immediately. This is accomplished by placing the reactor mode switch in the shutdown position. Further cooldown to MODE 4 is required at normal cooldown rates (provided pool temperature remains
[120]&deg;F). Additionally, when pool temperature is > [110]&deg;F, increased monitoring of pool temperature is required to ensure that it remains
[120]&deg;F. The once per 30 minute Completion Time is adequate, based on operating experience. Given the high pool temperature in this Condition, the monitoring Frequency is increased to twice that of Condition A. Furthermore, the 30 minute Completion Time is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.
E.1 and E.2 If suppression pool average temperature cannot be maintained  [120]&deg;F, the plant must be brought to a MODE in which the LCO does not apply.
To achieve this status, the reactor pressure must be reduced to
                    < [200] psig within 12 hours and the plant must be brought to MODE 4 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 without challenging plant systems.
Continued addition of heat to the suppression pool with pool temperature
                    > [120]&deg;F could result in exceeding the design basis maximum allowable values for primary containment temperature or pressure. Furthermore, if a blowdown were to occur when temperature was > [120]&deg;F, the maximum allowable bulk and local temperatures could be exceeded very quickly.
General Electric BWR/6 STS            B 3.6.2.1-4                                      Rev. 5.0
 
Suppression Pool Average Temperature B 3.6.2.1 BASES SURVEILLANCE        SR 3.6.2.1.1 REQUIREMENTS The suppression pool average temperature is regularly monitored to ensure that the required limits are satisfied. Average temperature is determined by taking an arithmetic average of the OPERABLE suppression pool water temperature channels. [ The 24 hour Frequency has been shown to be acceptable based on operating experience.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
When heat is being added to the suppression pool by testing, however, it is necessary to monitor suppression pool temperature more frequently.
The 5 minute Frequency during testing is justified by the rates at which testing will heat up the suppression pool, has been shown to be acceptable based on operating experience, and provides assurance that allowable pool temperatures are not exceeded. The Frequency is further justified in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.
REFERENCES          1. FSAR, Section [6.2].
: 2. FSAR, Section [15.2].
: 3. NUREG-0783.
General Electric BWR/6 STS                B 3.6.2.1-5                                                      Rev. 5.0
 
Suppression Pool Water Level B 3.6.2.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.2 Suppression Pool Water Level BASES BACKGROUND          The suppression pool is a concentric open container of water with a stainless steel liner, which is located at the bottom of the primary containment. The suppression pool is designed to absorb the decay heat and sensible heat released during a reactor blowdown from safety/relief valve (S/RV) discharges or from a loss of coolant accident (LOCA). The suppression pool must also condense steam from the Reactor Core Isolation Cooling (RCIC) System turbine exhaust and provides the main emergency water supply source for the reactor vessel. The suppression pool volume ranges between [135,291] ft3 at the low water level limit of
[18 ft 4.5 inches] and [138,701] ft3 at the high water level limit of [18 ft 9.75 inches].
If the suppression pool water level is too low, an insufficient amount of water would be available to adequately condense the steam from the S/RV quenchers, main vents, or RCIC turbine exhaust lines. Low suppression pool water level could also result in an inadequate emergency makeup water source to the Emergency Core Cooling System. The lower volume would also absorb less steam energy before heating up excessively. Therefore, a minimum suppression pool water level is specified.
If the suppression pool water level is too high, it could result in excessive clearing loads from S/RV discharges and excessive pool swell loads resulting from a Design Basis Accident (DBA) LOCA. An inadvertent upper pool dump could also overflow the weir wall into the drywell.
Therefore, a maximum pool water level is specified. This LCO specifies an acceptable range to prevent the suppression pool water level from being either too high or too low.
APPLICABLE          Initial suppression pool water level affects suppression pool temperature SAFETY              response calculations, calculated drywell pressure during vent clearing ANALYSES            for a DBA, calculated pool swell loads for a DBA LOCA, and calculated loads due to S/RV discharges. Suppression pool water level must be maintained within the limits specified so that the safety analysis of Reference 1 remains valid.
Suppression pool water level satisfies Criteria 2 and 3 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS            B 3.6.2.2-1                                          Rev. 5.0
 
Suppression Pool Water Level B 3.6.2.2 BASES LCO                A limit that suppression pool water level be  [18 ft 4.5 inches] and  [18 ft 9.75 inches] is required to ensure that the primary containment conditions assumed for the safety analysis are met. Either the high or low water level limits were used in the safety analysis, depending upon which is conservative for a particular calculation.
APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause significant loads on the primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced because of the pressure and temperature limitations in these MODES. The requirements for maintaining suppression pool water level within limits in MODE 4 or 5 is addressed in LCO 3.5.2, "RPV Water Inventory Control."
ACTIONS            A.1 With suppression pool water level outside the limits, the conditions assumed for the safety analysis are not met. If water level is below the minimum level, the pressure suppression function still exists as long as main vents are covered, RCIC turbine exhausts are covered, and S/RV quenchers are covered. If suppression pool water level is above the maximum level, protection against overpressurization still exists due to the margin in the peak containment pressure analysis or as long as the drywell sprays are OPERABLE. Prompt action to restore the suppression pool water level to within the normal range is prudent, however, to retain the margin to weir wall overflow from an inadvertent upper pool dump and reduce the risks of increased pool swell and dynamic loading. Therefore, continued operation for a limited time is allowed. The 2 hour Completion Time is sufficient to restore suppression pool water level to within specified limits. Also, it takes into account the low probability of an event impacting the suppression pool water level occurring during this interval.
B.1 and B.2 If suppression pool water level 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 12 hours and to MODE 4 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.
General Electric BWR/6 STS            B 3.6.2.2-2                                        Rev. 5.0
 
Suppression Pool Water Level B 3.6.2.2 BASES SURVEILLANCE        SR 3.6.2.2.1 REQUIREMENTS Verification of the suppression pool water level is to ensure that the required limits are satisfied. [ The 24 hour Frequency of this SR was developed considering operating experience related to trending variations in suppression pool water level and water level instrument drift during the applicable MODES and to assessing the proximity to the specified LCO level limits. 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 suppression pool water level condition.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [6.2].
General Electric BWR/6 STS                B 3.6.2.2-3                                                      Rev. 5.0
 
RHR Suppression Pool Cooling B 3.6.2.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling BASES BACKGROUND          Following a Design Basis Accident (DBA), the RHR Suppression Pool Cooling System removes heat from the suppression pool. The suppression pool is designed to absorb the sudden input of heat from the primary system. In the long term, the pool continues to absorb residual heat generated by fuel in the reactor core. Some means must be provided to remove heat from the suppression pool so that the temperature inside the primary containment remains within design limits.
This function is provided by two redundant RHR suppression pool cooling subsystems. The purpose of this LCO is to ensure that both subsystems are OPERABLE in applicable MODES.
Each RHR subsystem contains a pump and two heat exchangers in series and is manually initiated and independently controlled. The two RHR subsystems perform the suppression pool cooling function by circulating water from the suppression pool through the RHR heat exchangers and returning it to the suppression pool. RHR service water, circulating through the tube side of the heat exchangers, exchanges heat with the suppression pool water and discharges this heat to the external heat sink.
The heat removal capability of one RHR subsystem is sufficient to meet the overall DBA pool cooling requirement to limit peak temperature to
[185]&deg;F for loss of coolant accidents (LOCAs) and transient events such as a turbine trip or a stuck open safety/relief valve (S/RV). S/RV leakage and Reactor Core Isolation Cooling System testing increase suppression pool temperature more slowly. The RHR Suppression Pool Cooling System is also used to lower the suppression pool water bulk temperature following such events.
APPLICABLE          Reference 1 contains the results of analyses used to predict primary SAFETY              containment pressure and temperature following large and small break ANALYSES            LOCAs. The intent of the analyses is to demonstrate that the heat removal capacity of the RHR Suppression Pool Cooling System is adequate to maintain the primary containment conditions within design limits. The suppression pool temperature is calculated to remain below the design limit.
The RHR Suppression Pool Cooling System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS            B 3.6.2.3-1                                      Rev. 5.0
 
RHR Suppression Pool Cooling B 3.6.2.3 BASES LCO                During a DBA, a minimum of one RHR suppression pool cooling subsystem is required to maintain the primary containment peak pressure and temperature below the design limits (Ref. 1). To ensure that these requirements are met, two RHR suppression pool cooling subsystems must be OPERABLE with power from two safety related independent power supplies. Therefore, in the event of an accident, at least one subsystem is OPERABLE, assuming the worst case single active failure.
An RHR suppression pool cooling subsystem is OPERABLE when the pump, two heat exchangers, and associated piping, valves, instrumentation, and controls are OPERABLE. Management of gas voids is important to RHR Suppression Pool Cooling System OPERABILITY.
APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment and cause a heatup and pressurization of primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, the RHR Suppression Pool Cooling System is not required to be OPERABLE in MODE 4 or 5.
ACTIONS            A.1 With one RHR suppression pool cooling subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days [or in accordance with the Risk Informed Completion Time Program]. In this Condition, the remaining RHR suppression pool cooling subsystem is adequate to perform the primary containment cooling function. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced primary containment cooling capability. The 7 day Completion Time is acceptable in light of the redundant RHR suppression pool cooling capabilities afforded by the OPERABLE subsystem and the low probability of a DBA occurring during this period.
B.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
General Electric BWR/6 STS                B 3.6.2.3-2                                        Rev. 5.0
 
RHR Suppression Pool Cooling B 3.6.2.3 BASES ACTIONS (continued)
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
If one RHR suppression pool cooling subsystem is inoperable and is not restored to OPERABLE status within the required Completion Time, the plant must be brought to a condition in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action B.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is 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 With two RHR suppression pool cooling subsystems inoperable, one subsystem must be restored to OPERABLE status within 8 hours. In this condition, there is a substantial loss of the primary containment pressure and temperature mitigation function. The 8 hour Completion Time is based on this loss of function and is considered acceptable due to the low probability of a DBA and the potential avoidance of a plant shutdown transient that could result in the need for the RHR suppression pool cooling subsystems to operate.
General Electric BWR/6 STS                B 3.6.2.3-3                                                      Rev. 5.0
 
RHR Suppression Pool Cooling B 3.6.2.3 BASES ACTIONS (continued)
D.1 and D.2 If the Required Action and required Completion Time of Condition C 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 12 hours and to MODE 4 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 3.6.2.3.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves, in the RHR suppression pool cooling mode flow path provides assurance that the proper flow path exists for system 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 being locked, sealed, or secured. A valve is also allowed to be in the nonaccident position, provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable, since the RHR suppression pool cooling mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.
[ The Frequency of 31 days is justified because the valves are operated under procedural control, improper valve position would affect only a single subsystem, the probability of an event requiring initiation of the system is low, and the subsystem is a manually initiated system. This Frequency has been shown to be acceptable, based on operating experience.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.6.2.3-4                                                      Rev. 5.0
 
RHR Suppression Pool Cooling B 3.6.2.3 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.6.2.3.2 RHR Suppression Pool Cooling System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR suppression pool cooling subsystems and may also prevent water hammer and pump cavitation.
Selection of RHR Suppression Pool Cooling System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration.
Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.
The RHR Suppression Pool Cooling System is OPERABLE when it is sufficiently filled with water. Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump), the Surveillance is not met. If the accumulated gas is eliminated or brought within the acceptance criteria limits during performance of the Surveillance, the Surveillance is met and past system OPERABILITY is evaluated under the Corrective Action Program. If it is determined by subsequent evaluation that the RHR Suppression Pool Cooling System is not rendered inoperable by the accumulated gas (i.e.,
the system is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits.
RHR Suppression Pool Cooling System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations. Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for General Electric BWR/6 STS              B 3.6.2.3-5                                      Rev. 5.0
 
RHR Suppression Pool Cooling B 3.6.2.3 BASES SURVEILLANCE REQUIREMENTS (continued) susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.
[ The 31 day Frequency takes into consideration the gradual nature of gas accumulation in the RHR Suppression Pool Cooling System piping and the procedural controls governing system operation.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.2.3.3 Verifying each RHR pump develops a flow rate  [7450] gpm, while operating in the suppression pool cooling mode with flow through the associated heat exchanger ensures that pump performance has not degraded during the cycle. Flow is a normal test of centrifugal pump performance required by ASME (Ref. 3). This test confirms one point on the pump design curve, and the results are indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
If the testing is within the scope of the licensee's INSERVICE TESTING PROGRAM, the Frequency "In accordance with the INSERVICE TESTING PROGRAM" should be used. Otherwise, the periodic Frequency of 92 days or the reference to the Surveillance Frequency Control Program should be used.
General Electric BWR/6 STS                B 3.6.2.3-6                                                      Rev. 5.0
 
RHR Suppression Pool Cooling B 3.6.2.3 BASES SURVEILLANCE REQUIREMENTS (continued)
[ The Frequency of this SR is [in accordance with the INSERVICE TESTING PROGRAM] [92 days.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
REFERENCES          1. FSAR, Section [6.2].
: 2. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
: 3. ASME Code for Operation and Maintenance of Nuclear Power Plants.
General Electric BWR/6 STS                B 3.6.2.3-7                                                      Rev. 5.0
 
SPMU System B 3.6.2.4 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.4 Suppression Pool Makeup (SPMU) System BASES BACKGROUND          The function of the SPMU System is to transfer water from the upper containment pool to the suppression pool after a loss of coolant accident (LOCA). For a LOCA, with Emergency Core Cooling System injection from the suppression pool, a large volume of water can be held up in the drywell behind the weir wall. This holdup can significantly lower suppression pool water level. The water transfer from the SPMU System ensures a post LOCA suppression pool vent coverage of  2 ft above the top of the top row vents so that long term steam condensation is maintained. The additional makeup water is used as part of the long term suppression pool heat sink. The post LOCA delayed transfer of this water to the suppression pool provides an initially low vent submergence, which results in lower drywell pressure loading and lower pool dynamic loading during a Design Basis Accident (DBA) LOCA as compared to higher vent submergence. The sizing of the residual heat removal heat exchanger takes credit for the additional SPMU System water mass in the calculation of the post LOCA peak containment pressure and suppression pool temperature.
The required water dump volume from the upper containment pool is equal to the difference between the total post LOCA drawdown volume and the assumed volume loss from the suppression pool. The total drawdown volume is the volume of suppression pool water that can be entrapped outside of the suppression pool following a LOCA. The post LOCA entrapment volumes causing suppression pool level drawdown include:
: a. The free volume inside and below the top of the drywell weir wall,
: b. The added volume required to fill the reactor pressure vessel from a condition of normal power operation to a post accident complete fill of the vessel, including the top dome,
: c. The volume in the steam lines out to the inboard main steam isolation valve (MSIV) on three lines and out to the outboard MSIV on one line, and
: d. Allowances for primary containment spray holdup on equipment and structural surfaces.
The SPMU System consists of two redundant subsystems, each capable of dumping the makeup volume from the upper containment pool to the suppression pool by gravity flow. Each dump line includes two normally General Electric BWR/6 STS            B 3.6.2.4-1                                    Rev. 5.0
 
SPMU System B 3.6.2.4 BASES BACKGROUND (continued) closed valves in series. The upper pool is dumped automatically on a suppression pool water level Low-Low signal (with a LOCA signal permissive) or on the basis of a timer following a LOCA signal alone to ensure that the makeup volume is available as part of the long term energy sink for small breaks that might not cause dump on a suppression pool water level Low-Low signal. A 30 minute timer was chosen, since the initial suppression pool mass is adequate for any sequence of vessel blowdown energy and decay heat up to at least 30 minutes.
Although the minimum freeboard distance above the suppression pool high water level limit of LCO 3.6.2.2, "Suppression Pool Water Level," to the top of the weir wall is adequate to preclude flooding of the drywell, a LOCA permissive signal is used to prevent an erroneous suppression pool level signal from causing pool dump. In addition, the SPMU System mode switch may be keylocked in the "OFF" position to ensure that inadvertent dump will not occur. Inadvertent actuation of the SPMU System during MODE 4 or 5 could create a radiation hazard to plant personnel due to a loss of shield water from the upper pool if irradiated fuel were in an elevated position.
APPLICABLE          Analyses used to predict suppression pool temperature following large SAFETY              and small break LOCAs, which are the applicable DBAs for the SPMU ANALYSES            System, are contained in References 1 and 2. During these events, the SPMU System is relied upon to dump upper containment pool water to maintain drywell horizontal vent coverage and an adequate suppression pool heat sink volume to ensure that the primary containment internal pressure and temperature stay within design limits. The analysis assumes an SPMU System dump volume of [36,380] ft3 at a temperature of [125]NF.
The SPMU System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                During a DBA, a minimum of one SPMU subsystem is required to maintain peak suppression pool water temperature below the design limits (Ref. 1). To ensure that these requirements are met, two SPMU subsystems must be OPERABLE with power from two independent safety related power supplies. Therefore, in the event of an accident, at least one subsystem is OPERABLE, assuming the worst case single active failure. The SPMU System is OPERABLE when the upper containment pool water temperature is  [125]&deg;F, the water level is  [23 ft 3 inches],
gates are in the stored condition, the piping is intact, and the system valves are OPERABLE. The above temperature and water level conditions correspond to an SPMU System available dump volume of
[36,380] ft3.
General Electric BWR/6 STS            B 3.6.2.4-2                                        Rev. 5.0
 
SPMU System B 3.6.2.4 BASES APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause heatup and pressurization of the primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the SPMU System OPERABLE is not required in MODE 4 or 5.
ACTIONS            A.1 When upper containment pool water level is < [23 ft 3 inches], the volume is inadequate to ensure that the suppression pool heat sink capability matches the safety analysis assumptions. A sufficient quantity of water is necessary to ensure long term energy sink capabilities of the suppression pool and maintain water coverage over the uppermost drywell vents.
Loss of water volume has a relatively large impact on heat sink capability.
Therefore, the upper containment pool water level must be restored to within limit within 4 hours. The 4 hour Completion Time is sufficient to provide makeup water to the upper containment pool to restore level within specified limit. Also, it takes into account the low probability of an event occurring that would require the SPMU System.
B.1 When upper containment pool water temperature is > [125]&deg;F, the heat absorption capacity is inadequate to ensure that the suppression pool heat sink capability matches the safety analysis assumptions. Increased temperature has a relatively smaller impact on heat sink capability.
Therefore, the upper containment pool water temperature must be restored to within limit within 24 hours. The 24 hour Completion Time is sufficient to restore the upper containment pool to within the specified temperature limit. It also takes into account the low probability of an event occurring that would require the SPMU System.
C.1 With one SPMU subsystem inoperable for reasons other than Condition A or B, the inoperable subsystem must be restored to OPERABLE status within 7 days [or in accordance with the Risk Informed Completion Time Program]. The 7 day Completion Time is acceptable in light of the redundant SPMU System capabilities afforded by the OPERABLE subsystem and the low probability of a DBA occurring during this period.
General Electric BWR/6 STS            B 3.6.2.4-3                                        Rev. 5.0
 
SPMU System B 3.6.2.4 BASES ACTIONS (continued)
D.1 and D.2 If any Required Action and required Completion Time 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 12 hours and to MODE 4 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 3.6.2.4.1 REQUIREMENTS The upper containment pool water level is regularly monitored to ensure that the required limits are satisfied. [ The 24 hour Frequency of this SR was developed, considering operating experience related to upper containment pool water level variations and water level instrument drift during the applicable MODES and considering the low probability of a DBA occurring between surveillances. 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 upper containment pool water level condition.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.2.4.2 The upper containment pool water temperature is regularly monitored to ensure that the required limit is satisfied. [ The 24 hour Frequency was developed, based on operating experience related to upper containment pool temperature variations during the applicable MODES.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.6.2.4-4                                                      Rev. 5.0
 
SPMU System B 3.6.2.4 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.2.4.3 Verifying the correct alignment for manual, power operated, and automatic valves in the SPMU System flow path provides assurance that the proper flow paths will exist for system 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 being locked, sealed, or secured. This SR 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 does not apply to valves that cannot be inadvertently misaligned, such as check valves.
[ The Frequency of 31 days is justified because the valves are operated under procedural control and because improper valve position would affect only a single subsystem. This Frequency has been shown to be acceptable through operating experience.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
[ SR 3.6.2.4.4 The upper containment pool has two gates used to separate the pool into distinct sections to facilitate fuel transfer and maintenance during refueling operations and two additional gates in the separator pool weir wall extension, which, when installed, limit personnel exposure and ensure adequate water submergence of the separator when the separator General Electric BWR/6 STS                B 3.6.2.4-5                                                      Rev. 5.0
 
SPMU System B 3.6.2.4 BASES SURVEILLANCE REQUIREMENTS (continued) is stored in the pool. The SPMU System dump line penetrations are located in the steam separator storage section of the pool. To provide the required SPMU System dump volume to the suppression pool, the gates must be removed (or placed in their stored position) to allow communication between the various pool sections. [ The 31 day Frequency is appropriate because the gates are moved under procedural control and only the infrequent movement of these gates is required in MODES 1, 2, and 3.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
SR 3.6.2.4.5 This SR requires a verification that each SPMU subsystem automatic valve actuates to its correct position on receipt of an actual or simulated automatic initiation signal. This includes verification of the correct automatic positioning of the valves and of the operation of each interlock and timer. As noted, actual makeup to the suppression pool may be excluded. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.4.6 overlaps this SR to provide complete testing of the safety function. [ The
[18] month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                B 3.6.2.4-6                                                      Rev. 5.0
 
SPMU System B 3.6.2.4 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [6.2].
: 2. FSAR, Chapter [15].
General Electric BWR/6 STS                B 3.6.2.4-7                                                      Rev. 5.0
 
Primary Containment and Drywell Hydrogen Ignitors B 3.6.3.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.1 Primary Containment and Drywell Hydrogen Ignitors BASES BACKGROUND          The primary containment and drywell hydrogen ignitors are a part of the combustible gas control required by 10 CFR 50.44 (Ref. 1) and GDC 41, "Containment Atmosphere Cleanup" (Ref. 2), to reduce the hydrogen concentration in the primary containment following a degraded core accident. The hydrogen ignitors ensure the combustion of hydrogen in a manner such that containment overpressure failure is prevented as a result of a postulated degraded core accident.
10 CFR 50.44 (Ref. 1) requires boiling water reactor units with Mark III containments to install suitable hydrogen control systems. The hydrogen ignitors are installed to accommodate an amount of hydrogen equivalent to that generated from the reaction of 75% of the fuel cladding with water.
This requirement was placed on reactor units with Mark III containments because they were not designed for inerting and because of their low design pressure. Calculations indicate that if hydrogen equivalent to that generated from the reaction of 75% of the fuel cladding with water were to collect in primary containment, the resulting hydrogen concentration would be far above the lower flammability limit such that, without the hydrogen ignitors, if the hydrogen were ignited from a random ignition source, the resulting hydrogen burn would seriously challenge the primary containment.
The hydrogen ignitors are based on the concept of controlled ignition using thermal ignitors designed to be capable of functioning in a post accident environment, seismically supported and capable of actuation from the control room. Ignitors are distributed throughout the [32] regions of the drywell and primary containment in which hydrogen could be released or to which it could flow in significant quantities. The hydrogen ignitors are arranged in two independent divisions such that each containment region has two ignitors, one from each division, controlled and powered redundantly so that ignition would occur in each region even if one division failed to energize.
When the hydrogen ignitors are energized they heat up to a surface temperature  [1700]&deg;F. At this temperature, they ignite the hydrogen gas that is present in the airspace in the vicinity of the ignitor. The hydrogen ignitors depend on the dispersed location of the ignitors so that local pockets of hydrogen at increased concentrations would burn before reaching a hydrogen concentration significantly higher than the lower flammability limit. Hydrogen ignition in the vicinity of the ignitors is assumed to occur when the local hydrogen concentration reaches
[8.0] volume percent (v/o) and results in [85]% of the hydrogen present being consumed.
General Electric BWR/6 STS            B 3.6.3.1-1                                        Rev. 5.0
 
Primary Containment and Drywell Hydrogen Ignitors B 3.6.3.1 BASES APPLICABLE          The hydrogen ignitors cause hydrogen in containment to burn in a SAFETY              controlled manner as it accumulates following a degraded core accident ANALYSES            (Ref. 3). Burning occurs at the lower flammability concentration, where the resulting temperatures and pressures are relatively benign. Without the system, hydrogen could build up to higher concentrations that could result in a violent reaction if ignited by a random ignition source after such a buildup.
The hydrogen ignitors are not included for mitigation of a Design Basis Accident (DBA) because an amount of hydrogen equivalent to that generated from the reaction of 75% of the fuel cladding with water is far in excess of the hydrogen calculated for the limiting DBA loss of coolant accident (LOCA). The hydrogen concentration resulting from a DBA can be maintained less than the flammability limit using the hydrogen recombiners. However, the hydrogen ignitors have been shown by probabilistic risk analysis to be a significant contributor to limiting the severity of accident sequences that are commonly found to dominate risk for units with Mark III containment.
The hydrogen ignitors satisfy Criterion 4 of 10 CFR 50.36(c)(2)(ii).
LCO                Two divisions of primary containment and drywell hydrogen ignitors must be OPERABLE, each with more than 90% of the ignitors OPERABLE.
This ensures operation of at least one ignitor division, with adequate coverage of the primary containment and drywell, in the event of a worst case single active failure. This will ensure that the hydrogen concentration remains near 4.0 v/o.
APPLICABILITY      In MODES 1 and 2, the hydrogen ignitor is required to control hydrogen concentration to near the flammability limit of 4.0 v/o following a degraded core event that would generate hydrogen in amounts equivalent to a metal water reaction of 75% of the core cladding. The control of hydrogen concentration prevents overpressurization of the primary containment. The event that could generate hydrogen in quantities sufficiently high enough to exceed the flammability limit is limited to MODES 1 and 2.
In MODE 3, both the hydrogen production rate and the total hydrogen produced after a degraded core accident would be less than that calculated for the DBA LOCA. Also, because of the limited time in this MODE, the probability of an accident requiring the hydrogen ignitor is low.
Therefore, the hydrogen ignitor is not required in MODE 3.
In MODES 4 and 5, the probability and consequences of a degraded core accident are reduced due to the pressure and temperature limitations.
Therefore, the hydrogen ignitors are not required to be OPERABLE in MODES 4 and 5 to control hydrogen.
General Electric BWR/6 STS            B 3.6.3.1-2                                          Rev. 5.0
 
Primary Containment and Drywell Hydrogen Ignitors B 3.6.3.1 BASES ACTIONS            A.1 With one hydrogen ignitor division inoperable, the inoperable division must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE hydrogen ignitor division is adequate to perform the hydrogen burn function. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced hydrogen control capability. The 30 day Completion Time is based on the low probability of the occurrence of a degraded core event that would generate hydrogen in amounts equivalent to a metal water reaction of 75% of the core cladding, the amount of time available after the event for operator action to prevent hydrogen accumulation from exceeding the flammability limit, and the low probability of failure of the OPERABLE hydrogen ignitor division.
B.1 and B.2 With two primary containment and drywell ignitor divisions inoperable, the ability to perform the hydrogen control function via alternate capabilities must be verified by administrative means within 1 hour. The 1 hour Completion Time allows a reasonable period of time to verify that a loss of hydrogen control function does not exist. The verification may be performed as an administrative check by examining logs or other information to determine the availability of the alternate hydrogen control capabilities. It does not mean to perform the Surveillances needed to demonstrate OPERABILITY of the alternate hydrogen control capabilities.
If the ability to perform the hydrogen control function is maintained, continued operation is permitted with two ignitor divisions inoperable for up to 7 days. Seven days is a reasonable time to allow two ignitor divisions 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.
C.1 If any Required Action and required Completion Time 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 12 hours. The allowed Completion Time of 12 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.
General Electric BWR/6 STS              B 3.6.3.1-3                                      Rev. 5.0
 
Primary Containment and Drywell Hydrogen Ignitors B 3.6.3.1 BASES SURVEILLANCE        SR 3.6.3.1.1 and SR 3.6.3.1.2 REQUIREMENTS These SRs verify that there are no physical problems that could affect the ignitor operation. Since the ignitors are mechanically passive, they are not subject to mechanical failure. The only credible failures are loss of power or burnout. The verification that each required ignitor is energized is performed by circuit current versus voltage measurement.
[ The Frequency of 184 days has been shown to be acceptable through operating experience because of the low failure occurrence, and provides assurance that hydrogen burn capability exists between the more rigorous 18 month Surveillances. Operating experience has shown these components usually pass the Surveillance when performed at a 184 day Frequency. Additionally, these surveillances must be performed every 92 days if four or more ignitors in any division are inoperable. The 92 day Frequency was chosen, recognizing that the failure occurrence is higher than normal. Thus, decreasing the Frequency from 184 days to 92 days is a prudent measure, since only two more inoperable ignitors (for a total of six) will result in an inoperable ignitor division.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.3.1.2 is modified by a Note that indicates that the Surveillance is not required to be performed until 92 days after four or more ignitors in the division are discovered to be inoperable.
[ SR 3.6.3.1.3 and SR 3.6.3.1.4 These functional tests are performed to verify system OPERABILITY.
The current draw to develop a surface temperature of  1700&deg;F is verified for ignitors in inaccessible areas, e.g., in a high radiation area.
Additionally, the surface temperature of each accessible ignitor is measured to be  1700&deg;F to demonstrate that a temperature sufficient for ignition is achieved. [ 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 General Electric BWR/6 STS                B 3.6.3.1-4                                                      Rev. 4.0
 
Primary Containment and Drywell Hydrogen Ignitors B 3.6.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
REFERENCES          1. 10 CFR 50.44.
: 2. 10 CFR 50, Appendix A, GDC 41.
: 3. FSAR, Section [6.2.5].
General Electric BWR/6 STS                B 3.6.3.1-5                                                      Rev. 5.0
 
[Drywell Purge System]
B 3.6.3.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.2 [Drywell Purge System]
BASES BACKGROUND            The [Drywell Purge System] ensures a uniformly mixed post accident containment atmosphere, thereby minimizing the potential for local hydrogen burns due to a pocket of hydrogen above the flammable concentration.
The [Drywell Purge System] is an Engineered Safety Feature and is designed to operate in post accident environments without loss of function. The system has two independent subsystems, each consisting of a compressor and associated valves, controls, and piping. Each subsystem is sized to pump [500] scfm. Each subsystem is powered from a separate emergency power supply. Since each subsystem can provide 100% of the mixing requirements, the system will provide its design function with a worst case single active failure.
Following an accident, the drywell is immediately pressurized due to the release of steam into the drywell environment. This pressure is relieved by the lowering of the water level within the weir wall, clearing the drywell vents and allowing the mixture of steam and noncondensibles to flow into the primary containment through the suppression pool, removing much of the heat from the steam. The remaining steam in the drywell begins to condense as steam flow from the reactor pressure vessel ceases, the drywell pressure falls rapidly. Both drywell purge compressors start automatically 30 seconds after a signal is received from the Emergency Core Cooling System instrumentation, but only when drywell pressure has decreased to within approximately [0.087] psi above primary containment pressure. This ensures the blowdown from the drywell to the primary containment is complete. The drywell purge compressors force air from the primary containment into the drywell. Drywell pressure increases until the water level between the weir wall and the drywell is forced down to the first row of suppression pool vents forcing drywell atmosphere back into containment and mixing with containment atmosphere to dilute the hydrogen.
APPLICABLE            The [Drywell Purge System] ensures a mixed atmosphere for combustible SAFETY                gas control as required by 10 CFR 50.44 (b)(1). The [Drywell Purge ANALYSES              System] was originally designed to help mitigate the potential consequences of hydrogen generation following a Design Basis Accident (DBA) loss of coolant accident (LOCA). However, more recent studies have shown that the hydrogen release postulated from a DBA LOCA is not risk significant because it is not large enough to lead to early containment failure. The revised rule effective October 16, 2003, eliminated the design basis LOCA hydrogen release from 10 CFR 50.44, General Electric BWR/6 STS              B 3.6.3.2-1                                        Rev. 5.0
 
[Drywell Purge System]
B 3.6.3.2 BASES APPLICABLE SAFETY ANALYSES (continued) but retained the requirement for all containment types to have the capability for ensuring a mixed atmosphere in order to prevent local accumulation of detonable gases that could threaten containment integrity or equipment operating in a local compartment. The [Drywell Purge System] provides the capability for reducing the drywell hydrogen concentration to approximately the bulk average primary containment concentration following an accident.
Hydrogen may accumulate in primary containment following an accident as a result of:
: a. A metal steam reaction between the zirconium fuel rod cladding and the reactor coolant and
: b. Radiolytic decomposition of water in the Reactor Coolant System and drywell sump.
To evaluate the potential for hydrogen accumulation in primary containment following an accident, the hydrogen generation as a function of time following the initiation of the accident is calculated. Evaluation assumptions recommended by Reference 1 are used to determine the timing of the actions to mitigate the event.
The [Drywell Purge System] satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).
LCO                Two [drywell purge] subsystems must be OPERABLE to ensure operation of at least one primary containment [drywell purge] subsystem in the event of a worst case single active failure. Operation with at least one OPERABLE [drywell purge] subsystem provides the capability of controlling the hydrogen concentration in the drywell without exceeding the flammability limit.
APPLICABILITY      In MODES 1 and 2, the two [drywell purge] subsystems ensure the capability to prevent localized hydrogen concentrations above the flammability limit of 4.0 v/o in the drywell, assuming a worst case single active failure.
In MODE 3, both the hydrogen production rate and the total hydrogen produced after an accident would be less than that calculated for an accident in MODE 1 or 2. Also, because of the limited time in this MODE, the probability of an accident requiring the [Drywell Purge System] is low.
Therefore, the [Drywell Purge System] is not required in MODE 3.
General Electric BWR/6 STS            B 3.6.3.2-2                                        Rev. 5.0
 
[Drywell Purge System]
B 3.6.3.2 BASES APPLICABILITY (continued)
In MODES 4 and 5, the probability and consequences of an accident are reduced due to the pressure and temperature limitations in these MODES. Therefore, the [Drywell Purge System] is not required in these MODES.
ACTIONS            A.1 With one [drywell purge] subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE subsystem is adequate to perform the drywell purge function. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced drywell purge capability. The 30 day Completion Time is based on the availability of the second subsystem, the low probability of an accident that would generate hydrogen in amounts capable of exceeding the flammability limit, and the amount of time available after the event for operator action to prevent hydrogen accumulation from exceeding this limit.
B.1 and B.2
                    -----------------------------------REVIEWERS NOTE-----------------------------------
This Condition is only allowed for units with an alternate hydrogen control system acceptable to the technical staff.
With two [drywell purge] subsystems 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 [one division of the hydrogen ignitors]. The 1 hour Completion Time allows a reasonable period of time to verify that a loss of hydrogen control function does not exist.
                    -----------------------------------REVIEWERS 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 once per 12 hours thereafter to ensure its continued availability.
[Both] the [initial] verification may [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 General Electric BWR/6 STS                B 3.6.3.2-3                                                      Rev. 5.0
 
[Drywell Purge System]
B 3.6.3.2 BASES ACTIONS (continued) the ability to perform the hydrogen control function is maintained, continued operation is permitted with two [drywell purge] subsystems inoperable for up to 7 days. Seven days is a reasonable time to allow two
[drywell purge] subsystems to be inoperable because the hydrogen control function is maintained and because of the low probability of the occurrence of an accident that would generate hydrogen in amounts capable of exceeding the flammability limit.
C.1 If any Required Action and the required Completion Time 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 12 hours. The allowed Completion Time of 12 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 3.6.3.2.1 REQUIREMENTS Operating each [drywell purge] subsystem for  15 minutes ensures that each subsystem is OPERABLE and that all associated controls are functioning properly. It also ensures that blockage, compressor failure, or excessive vibration can be detected for corrective action. [ The 92 day Frequency is consistent with INSERVICE TESTING PROGRAM Frequencies, operating experience, the known reliability of the compressor and controls, and the two redundant subsystems available.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
[ SR 3.6.3.2.2 Verifying that each [drywell purge] subsystem flow rate is  [500] scfm ensures that each subsystem is capable of maintaining drywell hydrogen concentrations below the flammability limit. [ The 18 month Frequency is General Electric BWR/6 STS                B 3.6.3.2-4                                                      Rev. 5.0
 
[Drywell Purge System]
B 3.6.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
REFERENCES          1. Regulatory Guide 1.7, Revision [3].
General Electric BWR/6 STS                B 3.6.3.2-5                                                      Rev. 5.0
 
[Secondary Containment]
B 3.6.4.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.1 [Secondary Containment]
BASES BACKGROUND          The function of the [secondary containment] is to contain, dilute, and hold up fission products that may leak from primary containment following a Design Basis Accident (DBA). In conjunction with operation of the Standby Gas Treatment (SGT) System and closure of certain valves whose lines penetrate the [secondary containment], the [secondary containment] is designed to reduce the activity level of the fission products prior to release to the environment and to isolate and contain fission products that are released during certain operations that take place inside primary containment, when primary containment is not required to be OPERABLE, or that take place outside primary containment.
The [secondary containment] is a structure that completely encloses the primary containment and those components that may be postulated to contain primary system fluid. This structure forms a control volume that serves to hold up and dilute the fission products. It is possible for the pressure in the control volume to rise relative to the environmental pressure (e.g., due to pump/motor heat load additions). To prevent ground level exfiltration while allowing the [secondary containment] to be designed as a conventional structure, the [secondary containment]
requires support systems to maintain the control volume pressure at less than the external pressure. Requirements for these systems are specified separately in LCO 3.6.4.2, "Secondary Containment Isolation Valves (SCIVs)," and LCO 3.6.4.3, "Standby Gas Treatment (SGT)
System."
APPLICABLE          There are three principal accidents for which credit is taken for SAFETY              [secondary containment] OPERABILITY. These are a LOCA (Ref. 1), a ANALYSES            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)] inside primary containment (Ref. 2), and a fuel handling accident
[involving handling recently irradiated fuel] in the auxiliary building (Ref. 3). The [secondary containment] performs no active function in response to each of these limiting events; however, its leak tightness is required to ensure that the release of radioactive materials from the primary containment is restricted to those leakage paths and associated leakage rates assumed in the accident analysis, and that fission products entrapped within the [secondary containment] structure will be treated by the SGT System prior to discharge to the environment.
[Secondary containment] satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS            B 3.6.4.1-1                                          Rev. 5.0
 
[Secondary Containment]
B 3.6.4.1 BASES LCO                An OPERABLE [secondary containment] provides a control volume into which fission products that bypass or leak from primary containment, or are released from the reactor coolant pressure boundary components located in [secondary containment], can be diluted and processed prior to release to the environment. For the [secondary containment] to be considered OPERABLE, it must have adequate leak tightness to ensure that the required vacuum can be established and maintained.
APPLICABILITY      In MODES 1, 2, and 3, a LOCA could lead to a fission product release to primary containment that leaks to [secondary containment]. Therefore,
[secondary containment] OPERABILITY is required during the same operating conditions that require primary containment OPERABILITY.
In MODES 4 and 5, the probability and consequences of the LOCA are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining [secondary containment] OPERABLE is not required in MODE 4 or 5 to ensure a control volume, except for other situations for which significant releases of radioactive material can be postulated, such as during movement of [recently] irradiated fuel assemblies in the [primary or secondary containment].
[Due to radioactive decay, secondary containment is only required to be OPERABLE during fuel handling involving handling recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous [X] days).]
                    -----------------------------------REVIEWERS 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).
Additionally, licensees adding the term "recently" must make the following commitment which is consistent with NUMARC 93-01, Revision [4F],
Section 11.3.6.5, "Safety Assessment for Removal of Equipment from Service During Shutdown Conditions," subheading "Containment -
Secondary (BWR)."
                    "The following guidelines are included in the assessment of systems removed from service during movement of irradiated fuel:
General Electric BWR/6 STS                B 3.6.4.1-2                                        Rev. 5.0
 
[Secondary Containment]
B 3.6.4.1 BASES APPLICABILITY (continued)
                          - 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 If [secondary containment] is inoperable, it must be restored to OPERABLE status within 4 hours. The 4 hour Completion Time provides a period of time to correct the problem that is commensurate with the importance of maintaining [secondary containment] during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring [secondary containment] OPERABILITY) occurring during periods where [secondary containment] is inoperable is minimal.
B.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
General Electric BWR/6 STS                B 3.6.4.1-3                                                      Rev. 5.0
 
[Secondary Containment]
B 3.6.4.1 BASES ACTIONS (continued)
If the [secondary containment] cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4),
because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action B.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is 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 Movement of [recently] irradiated fuel assemblies in the [primary or secondary containment] can be postulated to cause significant fission product release to the [secondary containment]. In such cases, the
[secondary containment] is the only barrier to release of fission products to the environment. Therefore, movement of [recently] irradiated fuel assemblies must be immediately suspended if the [secondary containment] is inoperable.
Suspension of these activities shall not preclude completing an action that involves moving a component to a safe position.
General Electric BWR/6 STS            B 3.6.4.1-4                                        Rev. 5.0
 
[Secondary Containment]
B 3.6.4.1 BASES ACTIONS (continued)
Required Action C.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving [recently] irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving
[recently] irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of [recently] irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown. ]
SURVEILLANCE        [ SR 3.6.4.1.1 REQUIREMENTS This SR ensures that the [secondary containment] boundary is sufficiently leak tight to preclude exfiltration under expected wind conditions.
The SR is modified by a Note which states the SR is not required to be met for up to 4 hours if an analysis demonstrates that one SGT subsystem remains capable of establishing the required [secondary containment] vacuum. Use of the Note is expected to be infrequent but may be necessitated by situations in which [secondary containment]
vacuum may be less than the required containment vacuum, such as, but not limited to, wind gusts or failure or change of operating normal ventilation subsystems. These conditions do not indicate any change in the leak tightness of the [secondary containment] boundary. The analysis should consider the actual conditions (equipment configuration, temperature, atmospheric pressure, wind conditions, measured
[secondary containment] vacuum, etc.) to determine whether, if an accident requiring [secondary containment] to be OPERABLE were to occur, one train of SGT could establish the assumed [secondary containment] vacuum within the time assumed in the accident analysis. If so, the SR may be considered met for a period up to 4 hours. The 4 hour limit is based on the expected short duration of the situations when the Note would be applied.
[ The 24 hour Frequency of this SR was developed based on operating experience related to [secondary containment] vacuum variations during the applicable MODES and the low probability of a DBA occurring between surveillances.
Furthermore, the 24 hour Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal [secondary containment] vacuum condition.
OR General Electric BWR/6 STS            B 3.6.4.1-5                                      Rev. 5.0
 
[Secondary Containment]
B 3.6.4.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
SR 3.6.4.1.2 Verifying that [secondary containment] equipment hatches are closed ensures that the infiltration of outside air of such a magnitude as to prevent maintaining the desired negative pressure does not occur and provides adequate assurance that exfiltration from the [secondary containment] will not occur. In this application, the term "sealed" has no connotation of leak tightness.
[ The 31 day Frequency for this SR has been shown to be adequate based on operating experience, and is considered adequate in view of the other indications of hatch status that are available to the operator.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.6.4.1-6                                                      Rev. 5.0
 
[Secondary Containment]
B 3.6.4.1 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.6.4.1.3 Verifying that one [secondary containment] access door in each access opening is closed provides adequate assurance that exfiltration from the
[secondary containment] will not occur. An access opening contains at least one inner and one outer door. [In some cases, [secondary containment] access openings are shared such that there are multiple inner or outer doors.] The intent is to not breach the [secondary containment], which is achieved by maintaining the inner or outer portion of the barrier closed except when the access opening is being used for entry and exit.
[ The 31 day Frequency for this SR has been shown to be adequate, based on operating experience, and is considered adequate in view of the other indications of door status that are available to the operator.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
[SR 3.6.4.1.4 and] SR 3.6.4.1.5 The SGT System exhausts the [secondary] containment atmosphere to the environment through appropriate treatment equipment. Each SGT subsystem is designed to draw down pressure in the [secondary]
containment to  [0.25] inches of vacuum water gauge in  [120] seconds and maintain pressure in the [secondary] containment at  [0.266] inches of vacuum water gauge for 1 hour at a flow rate  [4000] cfm. To ensure that all fission products released to the [secondary] containment are treated, [SR 3.6.4.1.4 and] SR 3.6.4.1.5 verify that a pressure in the
[secondary] containment that is less than the lowest postulated pressure external to the [secondary] containment boundary can [rapidly] be
[established and] maintained. When the SGT System is operating as designed, the establishment and maintenance of [secondary] containment pressure cannot be accomplished if the [secondary] containment General Electric BWR/6 STS                B 3.6.4.1-7                                                      Rev. 5.0
 
[Secondary Containment]
B 3.6.4.1 BASES SURVEILLANCE REQUIREMENTS (continued) boundary is not intact. [Establishment of this pressure is confirmed by SR 3.6.4.1.4, which demonstrates that the [secondary] containment can be drawn down to  [0.25] inches of vacuum water gauge in
[120] seconds using one SGT subsystem.] SR 3.6.4.1.5 demonstrates that the pressure in the [secondary] containment can be maintained
[0.266] inches of vacuum water gauge for 1 hour using one SGT subsystem at a flow rate  [4000] cfm. The 1 hour test period allows
[secondary] containment to be in thermal equilibrium at steady state conditions. The primary purpose of these SR[s] is to ensure [secondary]
containment boundary integrity. The secondary purpose of these SR[s] is to ensure that the SGT subsystem being tested functions as designed.
There is a separate LCO with Surveillance Requirements which serves the primary purpose of ensuring OPERABILITY of the SGT System. The inoperability of the SGT System does not necessarily constitute a failure of these Surveillance[s] relative to the [secondary] containment OPERABILITY. [ These SR[s] need not be performed with each SGT subsystem. The SGT subsystem used for these Surveillance[s] is staggered to ensure that in addition to the requirements of LCO 3.6.4.3, either SGT subsystem will perform this test. Operating experience has shown the [secondary] containment boundary usually passes these Surveillance[s] when performed at the [18] month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [15.6.5].
: 2. FSAR, Section [15.7.6].
: 3. FSAR, Section [15.7.4].
: 4. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
General Electric BWR/6 STS                B 3.6.4.1-8                                                      Rev. 5.0
 
SCIVs B 3.6.4.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.2 Secondary Containment Isolation Valves (SCIVs)
BASES BACKGROUND          The function of the SCIVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) (Ref. 1). Secondary containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that fission products that leak from primary containment following a DBA, that are released during certain operations when primary containment is not required to be OPERABLE, or that take place outside primary containment, are maintained within the secondary containment boundary.
The OPERABILITY requirements for SCIVs help ensure that an adequate secondary containment boundary is maintained during and after an accident by minimizing potential paths to the environment. 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), and blind flanges are considered passive devices. Check valves or other automatic valves designed to close without operator action following an accident are considered active devices. Isolation barrier(s) for the penetration are discussed in Reference 2.
Automatic SCIVs close on a secondary containment isolation signal to establish a boundary for untreated radioactive material within secondary containment following a DBA or other accidents.
Other penetrations are isolated by the use of valves in the closed position or blind flanges.
APPLICABLE          The SCIVs must be OPERABLE to ensure the secondary containment SAFETY              barrier to fission product releases is established. The principal accidents ANALYSES            for which the secondary containment boundary is required are a loss of coolant accident (Ref. 1), 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)] inside primary containment (Ref. 3),
and a fuel handling accident [involving handling recently irradiated fuel] in the auxiliary building (Ref. 4). The secondary containment performs no active function in response to each of these limiting events, but the boundary established by SCIVs is required to ensure that leakage from the primary containment is processed by the Standby Gas Treatment (SGT) System before being released to the environment.
General Electric BWR/6 STS            B 3.6.4.2-1                                          Rev. 5.0
 
SCIVs B 3.6.4.2 BASES APPLICABLE SAFETY ANALYSES (continued)
Maintaining SCIVs OPERABLE with isolation times within limits ensures that fission products will remain trapped inside secondary containment so that they can be treated by the SGT System prior to discharge to the environment.
SCIVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                SCIVs form a part of the secondary containment boundary. The SCIV safety function is related to control of offsite radiation releases resulting from DBAs.
The power operated, automatic isolation valves are considered OPERABLE when their isolation times are within limits and the valves actuate on an automatic isolation signal. The valves covered by this LCO, along with their associated stroke times, are listed in Reference 5.
The normally closed isolation valves or blind flanges are considered OPERABLE when manual valves are closed or open in accordance with appropriate administrative controls, automatic SCIVs are de-activated and secured in their closed position, and blind flanges are in place. These passive isolation valves or devices are listed in Reference 5.
APPLICABILITY      In MODES 1, 2, and 3, a DBA could lead to a fission product release to the primary containment that leaks to the secondary containment.
Therefore, OPERABILITY of SCIVs is required.
In MODES 4 and 5, the probability and consequences of these events are reduced due to pressure and temperature limitations in these MODES.
Therefore, maintaining SCIVs OPERABLE is not required in MODE 4 or 5, except for other situations under which significant releases of radioactive material can be postulated, such as during movement of
[recently] irradiated fuel assemblies. Moving [recently] irradiated fuel assemblies in the [primary or secondary containment] may also occur in MODES 1, 2, and 3. [Due to radioactive decay, SCIVs are only required to be OPERABLE during fuel handling involving handling recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous [X] days).]
ACTIONS            The ACTIONS are modified by three Notes. The first Note allows penetration flow paths to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator, who is in continuous communication with the control room, at the controls of the isolation device. In this way, the penetration can be rapidly isolated when the need for [secondary containment] isolation is indicated.
General Electric BWR/6 STS            B 3.6.4.2-2                                          Rev. 5.0
 
SCIVs B 3.6.4.2 BASES ACTIONS (continued)
The second Note provides clarification that for the purpose of 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 SCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable SCIVs are governed by subsequent Condition entry and application of associated Required Actions.
The third Note ensures appropriate remedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable SCIV.
A.1 and A.2 In the event that there are one or more penetration flow paths with one SCIV inoperable, the affected penetration flow path(s) 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 criteria are a closed and de-activated automatic SCIV, a closed manual valve, and a blind flange. For penetrations isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available device to secondary containment. This Required Action must be completed within the 8 hour Completion Time. The specified time period is reasonable considering the time required to isolate the penetration and the low probability of a DBA, which requires the SCIVs to close, occurring during this short time.
For affected penetrations that have been isolated in accordance with Required Action A.1, the affected penetration must be verified to be isolated on a periodic basis. This is necessary to ensure that secondary containment penetrations required to be isolated following an accident, but 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 the affected penetration remains isolated.
Required Action A.2 is modified by two Notes. Note 1 applies to devices located in high radiation areas and allows them to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted.
Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and allows these devices to be verified General Electric BWR/6 STS            B 3.6.4.2-3                                        Rev. 5.0
 
SCIVs B 3.6.4.2 BASES ACTIONS (continued) 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, once they have been verified to be in the proper position, is low.
B.1 With two SCIVs in one or more penetration flow paths inoperable, the affected penetration flow path must be isolated within 4 hours. 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 4 hour Completion Time is reasonable, considering the time required to isolate the penetration and the low probability of a DBA, which requires the SCIVs to close, occurring during this short time.
The Condition has been modified by a Note stating that Condition B is only applicable to penetration flow paths with two isolation valves. This clarifies that only Condition A is entered if one SCIV is inoperable in each of two penetrations.
C.1 and C.2 If any Required Action and associated Completion Time 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 12 hours and to MODE 4 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.
D.1 and D.2 If any Required Action and associated Completion Time cannot be met, the plant must be placed in a condition in which the LCO does not apply.
If applicable, the movement of [recently] irradiated fuel assemblies in the
[primary and secondary containment] must be immediately suspended.
Suspension of these activities shall not preclude completion of movement of a component to a safe position.
General Electric BWR/6 STS            B 3.6.4.2-4                                      Rev. 5.0
 
SCIVs B 3.6.4.2 BASES ACTIONS (continued)
Required Action D.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving [recently] irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving
[recently] irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of [recently] irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.
SURVEILLANCE        SR 3.6.4.2.1 REQUIREMENTS This SR verifies each secondary containment isolation manual valve and blind flange that is not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside of the [secondary containment] boundary is within design limits. This SR does not require any testing or valve manipulation. Rather, it involves verification that those SCIVs in [secondary containment] that are capable of being mispositioned are in the correct position.
[ Since these SCIVs are readily accessible to personnel during normal unit operation and verification of their position is relatively easy, the 31 day Frequency was chosen to provide added assurance that the SCIVs are in the correct positions.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
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.
General Electric BWR/6 STS                B 3.6.4.2-5                                                      Rev. 5.0
 
SCIVs B 3.6.4.2 BASES SURVEILLANCE REQUIREMENTS (continued)
Two Notes have been added to this SR. The first Note applies to valves and blind flanges located in high radiation areas and allows them to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA reasons. Therefore, the probability of misalignment of these SCIVs, once they have been verified to be in the proper position, is low.
A second Note has been included to clarify that SCIVs that are open under administrative controls are not required to meet the SR during the time the SCIVs are open.
SR 3.6.4.2.2 Verifying the isolation time of each power operated, automatic SCIV is within limits is required to demonstrate OPERABILITY. The isolation time test ensures that the SCIV will isolate in a time period less than or equal to that assumed in the safety analyses. The isolation time is in accordance with the Inservice Testing Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
If the testing is within the scope of the licensee's INSERVICE TESTING PROGRAM, the Frequency "In accordance with the INSERVICE TESTING PROGRAM" should be used. Otherwise, the periodic Frequency of 92 days or the reference to the Surveillance Frequency Control Program should be used.
[ The Frequency of this SR is [in accordance with the INSERVICE TESTING PROGRAM] [92 days.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
General Electric BWR/6 STS                B 3.6.4.2-6                                                      Rev. 5.0
 
SCIVs B 3.6.4.2 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.6.4.2.3 Verifying that each automatic SCIV closes on a [secondary containment]
isolation signal is required to prevent leakage of radioactive material from
[secondary containment] following a DBA or other accidents. This SR ensures that each automatic SCIV will actuate to the isolation position on a [secondary containment] isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.2.5 overlaps this SR to provide complete testing of the safety function. [ The [18] month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the 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 was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [15.6.5].
: 2. FSAR, Section [6.2.3].
: 3. FSAR, Section [15.7.6].
: 4. FSAR, Section [15.7.4].
: 5. FSAR, Section [ ].
General Electric BWR/6 STS                B 3.6.4.2-7                                                      Rev. 5.0
 
SGT System B 3.6.4.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.3 Standby Gas Treatment (SGT) System BASES BACKGROUND          The SGT System is required by 10 CFR 50, Appendix A, GDC 41, "Containment Atmosphere Cleanup" (Ref. 1). The function of the SGT System is to ensure that radioactive materials that leak from the primary containment into the secondary containment following a Design Basis Accident (DBA) are filtered and adsorbed prior to exhausting to the environment.
The SGT System consists of two fully redundant subsystems, each with its own set of ductwork, dampers, charcoal filter train, and controls.
Each charcoal filter train consists of (components listed in order of the direction of the air flow):
: a. A moisture separator,
: b. An electric heater,
: c. A prefilter,
: d. A high efficiency particulate air (HEPA) filter,
: e. A charcoal adsorber,
: f. A second HEPA filter, and
: g. A centrifugal fan with inlet flow control vanes.
The sizing of the SGT System equipment and components is based on the results of an infiltration analysis, as well as an exfiltration analysis of the auxiliary and enclosure building structures. The internal pressure of the SGT System boundary region is maintained at a negative pressure of
[0.25] inch water gauge when the system is in operation, which represents the internal pressure required to ensure zero exfiltration of air from the building when exposed to a [10] mph wind blowing at an angle of
[45]&deg; to the building.
The moisture separator is provided to remove entrained water in the air, while the electric heater reduces the relative humidity of the airstream to less than [70]% (Ref. 2). The prefilter removes large particulate matter, while the HEPA filter is provided to remove fine particulate matter and protect the charcoal from fouling. The charcoal adsorber removes General Electric BWR/6 STS            B 3.6.4.3-1                                          Rev. 5.0
 
SGT System B 3.6.4.3 BASES BACKGROUND (continued) gaseous elemental iodine and organic iodides, and the final HEPA filter is provided to collect any carbon fines exhausted from the charcoal adsorber.
The SGT System automatically starts and operates in response to actuation signals indicative of conditions or an accident that could require operation of the system. Following initiation, both enclosure building recirculation fans and both charcoal filter train fans start. SGT System flows are controlled by modulating inlet vanes installed on the charcoal filter train exhaust fans and two position volume control dampers installed in branch ducts to individual regions of the secondary containment.
APPLICABLE          The design basis for the SGT System is to mitigate the consequences of SAFETY              a loss of coolant accident and fuel handling accidents. [Due to ANALYSES            radioactive decay, the SGT System is only required to be OPERABLE during fuel handling involving handling recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous [X]
days).] (Ref. 3). For all events analyzed, the SGT System is shown to be automatically initiated to reduce, via filtration and adsorption, the radioactive material released to the environment.
The SGT System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                Following a DBA, a minimum of one SGT subsystem is required to maintain the secondary containment at a negative pressure with respect to the environment and to process gaseous releases. Meeting the LCO requirements for two operable subsystems ensures operation of at least one SGT subsystem in the event of a single active failure.
APPLICABILITY      In MODES 1, 2, and 3, a DBA could lead to a fission product release to primary containment that leaks to secondary containment. Therefore, SGT System OPERABILITY is required during these MODES.
In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the SGT System OPERABLE is not required in MODE 4 or 5, except for other situations under which significant releases of radioactive material can be postulated, such as during movement of [recently] irradiated fuel assemblies in the [primary or secondary containment]. [Due to radioactive decay, the SGT System is only required to be OPERABLE during fuel handling involving handling recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous [X] days).]
General Electric BWR/6 STS            B 3.6.4.3-2                                          Rev. 5.0
 
SGT System B 3.6.4.3 BASES ACTIONS            A.1 With one SGT subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this Condition, the remaining OPERABLE SGT subsystem is adequate to perform the required radioactivity release control function. However, the overall system reliability is reduced because a single failure in the OPERABLE subsystem could result in the radioactivity release control function not being adequately performed. The 7 day Completion Time is based on consideration of such factors as the availability of the OPERABLE redundant SGT subsystem and the low probability of a DBA occurring during this period.
B.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
If the SGT subsystem cannot be restored to OPERABLE status within the required Completion Time in MODE 1, 2, or 3, the plant must be brought to a MODE in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action C.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the General Electric BWR/6 STS                B 3.6.4.3-3                                                      Rev. 5.0
 
SGT System B 3.6.4.3 BASES ACTIONS (continued) results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is 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 During movement of [recently] irradiated fuel assemblies in the [primary or secondary containment], when Required Action A.1 cannot be completed within the required Completion Time, the OPERABLE SGT subsystem should be immediately placed in operation. This Required Action ensures that the remaining subsystem is OPERABLE, that no failures that could prevent automatic actuation have occurred, and that any other failure would be readily detected.
An alternative to Required Action C.1 is to immediately suspend activities that represent a potential for releasing a significant amount of radioactive material to the secondary containment, thus placing the unit in a Condition that minimizes risk. If applicable, movement of [recently]
irradiated fuel assemblies must be immediately suspended. Suspension of these activities shall not preclude completion of movement of a component to a safe position.
The Required Actions of Condition C have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving [recently] irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving [recently] irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of [recently] irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.
General Electric BWR/6 STS            B 3.6.4.3-4                                        Rev. 5.0
 
SGT System B 3.6.4.3 BASES ACTIONS (continued)
D.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
If both SGT subsystems are inoperable in MODE 1, 2, or 3, the SGT system may not be capable of supporting the required radioactivity release control function. Therefore, the plant must be brought to a MODE in which the overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 4) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action D.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
General Electric BWR/6 STS                B 3.6.4.3-5                                                      Rev. 5.0
 
SGT System B 3.6.4.3 BASES ACTIONS (continued)
E.1 When two SGT subsystems are inoperable, if applicable, movement of
[recently] irradiated fuel assemblies in the [primary and secondary containment] must be immediately suspended. Suspension of these activities shall not preclude completion of movement of a component to a safe position.
Required Action E.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving [recently] irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving
[recently] irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of [recently] irradiated fuel assemblies would not be sufficient reason to require a reactor shutdown.
SURVEILLANCE        SR 3.6.4.3.1 REQUIREMENTS Operation [with the heaters on] for  15 continuous minutes demonstrates OPERABILITY of the system. Periodic operation ensures that [heater failure,] blockage, fan or motor failure, or excessive vibration can be detected for corrective action. [ The 31 day Frequency was developed in consideration of the known reliability of fan motors and controls and the redundancy available in the system.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.6.4.3-6                                                      Rev. 5.0
 
SGT System B 3.6.4.3 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.6.4.3.2 This SR verifies that the required SGT 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).
Specified test frequencies and additional information are discussed in detail in the VFTP.
SR 3.6.4.3.3 This SR requires verification that each SGT subsystem starts upon receipt of an actual or simulated initiation signal. The SR excludes automatic dampers that are locked, sealed, or otherwise secured in the actuated position. The SR does not apply to dampers that are locked, sealed, or otherwise secured in the actuated position since the affected dampers were verified to be in the actuated position prior to being locked, sealed, or otherwise secured. Placing an automatic damper in a locked, sealed, or otherwise secured position requires an assessment of the OPERABILITY of the system or any supported systems, including whether it is necessary for the damper to be repositioned to the non-actuated position to support the accident analysis. Restoration of an automatic damper to the non-actuated position requires verification that the SR has been met within its required Frequency. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.2.5 overlaps this SR to provide complete testing of the safety function. [ While this Surveillance can be performed with the reactor at power, operating experience has shown these components usually pass the Surveillance when performed at the [18] month Frequency, which is based on the refueling cycle.
Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.6.4.3-7                                                      Rev. 5.0
 
SGT System B 3.6.4.3 BASES SURVEILLANCE REQUIREMENTS (continued)
[ SR 3.6.4.3.4 This SR requires verification that the SGT filter cooler bypass damper can be opened and the fan started. This ensures that the ventilation mode of SGT System operation is available. The SR excludes automatic dampers that are locked, sealed, or otherwise secured in the open position. The SR does not apply to dampers that are locked, sealed, or otherwise secured in the open position since the affected dampers were verified to be in the open position prior to being locked, sealed, or otherwise secured. Placing an automatic damper in a locked, sealed, or otherwise secured position requires an assessment of the OPERABILITY of the system or any supported systems, including whether it is necessary for the damper to be closed to support the accident analysis. Restoration of an automatic damper to the closed position requires verification that the SR has been met within its required Frequency. [ While this Surveillance can be performed with the reactor at power, operating experience has shown these components usually pass the Surveillance when performed at the [18] month Frequency, which is based on the refueling cycle.
Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
REFERENCES          1. 10 CFR 50, Appendix A, GDC 41.
: 2. FSAR, Section [6.2.3].
: 3. FSAR, Section [15.6.5].
: 4. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
General Electric BWR/6 STS                B 3.6.4.3-8                                                      Rev. 5.0
 
Drywell B 3.6.5.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.5.1 Drywell BASES BACKGROUND          The drywell houses the reactor pressure vessel (RPV), the reactor coolant recirculating loops, and branch connections of the Reactor Coolant System (RCS), which have isolation valves at the primary containment boundary. The function of the drywell is to maintain a pressure boundary that channels steam from a loss of coolant accident (LOCA) to the suppression pool, where it is condensed. Air forced from the drywell is released into the primary containment. The pressure suppression capability assures that peak LOCA temperature and pressure in the primary containment are within design limits. The drywell also protects accessible areas of the containment from radiation originating in the reactor core and RCS.
To ensure the drywell pressure suppression capability, the drywell bypass leakage must be minimized to prevent overpressurization of the primary containment during the drywell pressurization phase of a LOCA. This requires periodic testing of the drywell bypass leakage, confirmation that the drywell air lock is leak tight, OPERABILITY of the drywell isolation valves (DIVs), and confirmation that the drywell vacuum relief valves are closed.
The isolation devices for the drywell penetrations are a part of the drywell barrier. To maintain this barrier:
: a. The drywell air lock is OPERABLE except as provided in LCO 3.6.5.2, "Drywell Air Lock,"
: b. The drywell penetrations required to be closed during accident conditions are either:
: 1. Capable of being closed by an OPERABLE automatic DIV or
: 2. Closed by manual valves, blind flanges, or de-activated automatic valves secured in closed positions except as provided in LCO 3.6.5.3, "Drywell Isolation Valves (DIVs)," and
: c. The Drywell Vacuum Relief System is OPERABLE except as provided in LCO 3.6.5.6, "Drywell Vacuum Relief System."
This Specification is intended to ensure that the performance of the drywell in the event of a DBA meets the assumptions used in the safety analyses (Ref. 1).
General Electric BWR/6 STS            B 3.6.5.1-1                                      Rev. 5.0
 
Drywell B 3.6.5.1 BASES APPLICABLE          Analytical methods and assumptions involving the drywell are presented SAFETY              in Reference 1. The safety analyses assume that for a high energy line ANALYSES            break inside the drywell, the steam is directed to the suppression pool through the horizontal vents where it is condensed. Maintaining the pressure suppression capability assures that safety analyses remain valid and that the peak LOCA temperature and pressure in the primary containment are within design limits.
The drywell satisfies Criteria 2 and 3 of 10 CFR 50.36(c)(2)(ii).
LCO                Maintaining the drywell OPERABLE is required to ensure that the pressure suppression design functions assumed in the safety analyses are met. The drywell is OPERABLE if the drywell structural integrity is intact and the bypass leakage is within limits, except prior to the first startup after performing a required drywell bypass leakage test. At this time, the drywell bypass leakage must be  [10%] of the drywell bypass leakage limit.
APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to the primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the drywell is not required to be OPERABLE in MODES 4 and 5.
ACTIONS            A.1 In the event the drywell 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 the drywell OPERABLE during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring drywell OPERABILITY) occurring during periods when the drywell is inoperable is minimal. Also, the Completion Time is the same as that applied to inoperability of the primary containment in LCO 3.6.1.1, "Primary Containment."
B.1 and B.2 If the drywell cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 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.
General Electric BWR/6 STS            B 3.6.5.1-2                                        Rev. 5.0
 
Drywell B 3.6.5.1 BASES SURVEILLANCE        SR 3.6.5.1.1 REQUIREMENTS The analyses in Reference 2 are based on a maximum drywell bypass leakage. This Surveillance ensures that the actual drywell bypass leakage is less than or equal to the acceptable A/k design value of
[1.0] ft2 assumed in the safety analysis. As left drywell bypass leakage, prior to the first startup after performing a required drywell bypass leakage test, is required to be  [10%] of the drywell bypass leakage limit.
At all other times between required drywell leakage rate tests, the acceptance criteria is based on design A/k. At the design A/k the containment temperature and pressurization response are bounded by the assumptions of the safety analysis. [ The leakage test is performed every [18] months, consistent with the difficulty of performing the test, risk of high radiation exposure, and the remote possibility that a component failure that is not identified by some other drywell or primary containment SR might occur. 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.5.1.2 The exposed accessible drywell interior and exterior surfaces are inspected to ensure there are no apparent physical defects that would prevent the drywell from performing its intended function. This SR ensures that drywell structural integrity is maintained. [ The [40] month Frequency was chosen so that the interior and exterior surfaces of the drywell can be inspected at every other refueling outage. Due to the passive nature of the drywell structure, the [40] month Frequency is sufficient to identify component degradation that may affect drywell structural integrity.
OR General Electric BWR/6 STS                B 3.6.5.1-3                                                      Rev. 5.0
 
Drywell B 3.6.5.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES                1. FSAR, Chapter [6] and Chapter [15].
General Electric BWR/6 STS                B 3.6.5.1-4                                                      Rev. 5.0
 
Drywell Air Lock B 3.6.5.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.5.2 Drywell Air Lock BASES BACKGROUND            The drywell air lock forms part of the drywell boundary and provides a means for personnel access during MODES 2 and 3 during low power phase of unit startup. For this purpose, one double door drywell air lock has been provided, which maintains drywell isolation during personnel entry and exit from the drywell. Under the normal unit operation, the drywell air lock is kept sealed. The air pressure in the seals is maintained
                      > [60] psig by the seal air flask and pneumatic system, which is maintained at a pressure > [90] psig.
The drywell air lock is designed to the same standards as the drywell boundary. Thus, the drywell air lock must withstand the pressure and temperature transients associated with the rupture of any primary system line inside the drywell and also the rapid reversal in pressure when the steam in the drywell is condensed by the Emergency Core Cooling System flow following loss of coolant accident flooding of the reactor pressure vessel (RPV). It is also designed to withstand the high temperature associated with the break of a small steam line in the drywell that does not result in rapid depressurization of the RPV.
The air lock is nominally a right circular cylinder, [10] ft in diameter, with doors at each end that are interlocked to prevent simultaneous opening.
During periods when the drywell is not required to be OPERABLE, the air lock interlock mechanism may be disabled, allowing both doors of the air lock to remain open for extended periods when frequent drywell entry is necessary. Each air lock door has been designed and tested to certify its ability to withstand a pressure in excess of the maximum expected pressure following a Design Basis Accident (DBA).
The 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 interlock mechanism is defeated.
The drywell air lock forms part of the drywell pressure boundary. Not maintaining air lock OPERABILITY may result in degradation of the pressure suppression capability, which is assumed to be functional in the unit safety analyses. The drywell air lock does not need to meet the requirements of 10 CFR 50, Appendix J (Ref. 1), since it is not part of the primary containment leakage boundary. However, it is prudent to specify a leakage rate requirement for the drywell air lock. A seal leakage rate limit of  200 scfh and an air lock overall leakage rate limit of  200 scfh, at pressure  Pa (11.5 psig), have been established to assure the integrity of the seals.
General Electric BWR/6 STS              B 3.6.5.2-1                                        Rev. 5.0
 
Drywell Air Lock B 3.6.5.2 BASES APPLICABLE          Analytical methods and assumptions involving the drywell are presented SAFETY              in Reference 2. The safety analyses assume that for a high energy line ANALYSES            break inside the drywell, the steam is directed to the suppression pool through the horizontal vents where it is condensed. Since the drywell air lock is part of the drywell pressure boundary, its design and maintenance are essential to support drywell OPERABILITY, which assures that the safety analyses are met.
The drywell air lock satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                The drywell air lock forms part of the drywell pressure boundary. The air lock safety function assures that steam resulting from a DBA is directed to the suppression pool. Thus, the air lock's structural integrity is essential to the successful mitigation of such an event.
The air lock is required to be OPERABLE. For the air lock to be considered OPERABLE, the air lock interlock mechanism must be OPERABLE, air lock leakage must be within limits, 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 the drywell does not exist when the drywell is required to be OPERABLE.
Closure of a single door in the air lock is necessary to support drywell OPERABILITY following postulated events. Nevertheless, both doors are kept closed when the air lock is not being used for entry into and exit from the drywell.
APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to the primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, the drywell air lock is not required to be OPERABLE in MODES 4 and 5.
ACTIONS            The ACTIONS are modified by Note 1 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 to repair. If the inner door is inoperable, however, then there is a short time during which the drywell boundary is not intact (during access through the outer door). The ability to open the OPERABLE door, even if it means the drywell boundary is temporarily not intact, is acceptable due to the low probability of an event that could pressurize the drywell during the short time in which the OPERABLE door is expected to be open. The OPERABLE door must be immediately closed after each entry and exit.
General Electric BWR/6 STS            B 3.6.5.2-2                                        Rev. 5.0
 
Drywell Air Lock B 3.6.5.2 BASES ACTIONS (continued)
The ACTIONS are modified by a second Note, which ensures appropriate remedial actions are taken when necessary. Pursuant to LCO 3.0.6, ACTIONS are not required even if the drywell is exceeding its bypass leakage limit. Therefore, the Note is added to require ACTIONS for LCO 3.6.5.1 to be taken in this event.
A.1, A.2, and A.3 With one drywell air lock door inoperable, the OPERABLE door must be verified closed (Required Action A.1). This ensures that a leak tight drywell barrier is maintained by the use of an OPERABLE air lock door.
This action must be completed within 1 hour. The 1 hour Completion Time is consistent with the ACTIONS of LCO 3.6.5.1, "Drywell," which requires that the drywell be restored to OPERABLE status within 1 hour.
In addition, the air lock penetration must be isolated by locking closed the OPERABLE air lock door within the 24 hour Completion Time. The Completion Time is considered reasonable for locking the OPERABLE air lock door, considering that the OPERABLE door is being maintained closed.
Required Action A.3 verifies that the air lock has been isolated by the use of a locked and closed OPERABLE air lock door. This ensures that an acceptable drywell 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 that ensure that the OPERABLE air lock door remains closed.
The Required Actions are modified by two Notes. Note 1 ensures only the Required Actions and associated Completion Times of Condition C are required if both doors in the air lock are inoperable. The exception of the Note does not affect tracking the Completion Times 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. Drywell entry may be required to perform Technical Specifications (TS) Surveillances and Required Actions, as well as other activities on equipment inside the drywell 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 drywell 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 drywell during the short time that the OPERABLE door is expected to be open.
General Electric BWR/6 STS            B 3.6.5.2-3                                        Rev. 5.0
 
Drywell Air Lock B 3.6.5.2 BASES ACTIONS (continued)
B.1, B.2, and B.3 With the drywell air lock interlock mechanism inoperable, the Required Actions and associated Completion Times consistent with Condition A are applicable.
The Required Actions are modified by two Notes. Note 1 ensures only the Required Actions and associated Completion Times of Condition C are required if both doors in the air lock are inoperable. Note 2 allows entry and exit into the drywell under the control of a dedicated individual stationed at the air lock to ensure that only one door is opened at a time (i.e., the individual performs the function of the interlock).
C.1, C.2, and C.3 With the air lock inoperable for reasons other than those described in Condition A or B, Required Action C.1 requires action to be immediately initiated to evaluate drywell bypass leakage using current air lock test results. An evaluation is acceptable, since it is overly conservative to immediately declare the drywell inoperable if both doors in an air lock have failed a seal test or the overall air lock leakage is not within limits. In many instances (e.g., only one seal per door has failed), drywell remains OPERABLE, yet only 1 hour (per LCO 3.6.5.1) 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 drywell leakage rate can still be within limits.
Required Action C.2 requires that one door in the drywell air lock must be verified to be closed. This Required Action must be completed within the 1 hour Completion Time. This specified time period is consistent with the ACTIONS of LCO 3.6.5.1, which requires that the drywell be restored to OPERABLE status within 1 hour.
Additionally, the air lock must be restored to OPERABLE status within 24 hours [or in accordance with the Risk Informed Completion Time Program]. The 24 hour Completion Time is reasonable for restoring an inoperable air lock to OPERABLE status, considering that at least one door is maintained closed in the air lock.
General Electric BWR/6 STS            B 3.6.5.2-4                                        Rev. 5.0
 
Drywell Air Lock B 3.6.5.2 BASES ACTIONS (continued)
D.1 and D.2 If the inoperable drywell 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 12 hours and to MODE 4 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 3.6.5.2.1 REQUIREMENTS This SR requires a test be performed to verify seal leakage of the drywell air lock doors at pressures  [11.5] psig. A seal leakage rate limit of
[200] scfh has been established to ensure the integrity of the seals.
The Surveillance is only required to be performed once after each closing.
[ The Frequency of 72 hours is based on operating experience and is considered adequate in view of the other indications available to plant operations personnel that the seal is intact.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.5.2.2 The drywell air lock seal air flask pressure is periodically verified to be
[90] psig to ensure that the seal system remains viable. It must be checked because it could bleed down during or following access through the air lock, which occurs regularly. [ The 7 day Frequency has been shown to be acceptable, based on operating experience, and is considered adequate in view of the other indications to the plant operations personnel that the seal air flask pressure is low.
OR General Electric BWR/6 STS                B 3.6.5.2-5                                                      Rev. 5.0
 
Drywell Air Lock B 3.6.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.5.2.3 The air lock door interlock is designed to prevent simultaneous opening of both doors in the air lock. Since both the inner and outer doors of the air lock are designed to withstand the maximum expected post accident drywell pressure, closure of either door will support drywell OPERABILITY. Thus, the door interlock feature supports drywell OPERABILITY while the air lock is being used for personnel transit in and out of the drywell. Periodic testing of this interlock demonstrates that the interlock will function as designed and that simultaneous inner and outer door opening will not inadvertently occur. [ Due to the purely mechanical nature of this interlock, and given that the interlock mechanism is only challenged when drywell is entered, this test is only required to be performed once every [18] months. 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 [18] month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.6.5.2-6                                                      Rev. 5.0
 
Drywell Air Lock B 3.6.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance is modified by a Note requiring the Surveillance to be performed only upon entry into the drywell.
SR 3.6.5.2.4 This SR requires a test to be performed to verify overall air lock leakage of the drywell air lock at pressures  [11.5] psig. [ 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 [18] month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
This SR has been modified by a Note indicating that an inoperable air lock door does not invalidate the previous successful performance of an overall air lock leakage test. This is considered reasonable, since either air lock door is capable of providing a fission product barrier in the event of a DBA.
SR 3.6.5.2.5 This SR ensures that the drywell air lock seal pneumatic system pressure does not decay at an unacceptable rate. The air lock seal will support drywell OPERABILITY down to a pneumatic pressure of [90] psig. Since the air lock seal air flask pressure is verified in SR 3.6.5.2.2 to be
[90] psig, a decay rate  [30] psig over [10] days is acceptable. The
[10] day interval is based on engineering judgment, considering that there is no postulated DBA where the drywell is still pressurized [10] days after the event.
General Electric BWR/6 STS                B 3.6.5.2-7                                                      Rev. 5.0
 
Drywell Air Lock B 3.6.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)
[ 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.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. 10 CFR 50, Appendix J.
: 2. FSAR, Chapters [6 and 15].
General Electric BWR/6 STS                B 3.6.5.2-8                                                      Rev. 5.0
 
Drywell Isolation Valves B 3.6.5.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.5.3 Drywell Isolation Valves BASES BACKGROUND            The drywell isolation valves, in combination with other accident mitigation systems, function to ensure that steam and water releases to the drywell are channeled to the suppression pool to maintain the pressure suppression function of the drywell.
The OPERABILITY requirements for drywell isolation valves help ensure that valves are closed, when required, and isolation occurs within the time limits specified for those isolation valves designed to close automatically.
Therefore, the OPERABILITY requirements support minimizing drywell bypass leakage assumed in the safety analysis (Ref. 1) for a DBA. 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 credible single failure or malfunction of an active component can result in a loss of isolation.
The Drywell Vacuum Relief System valves serve a dual function, one of which is drywell isolation. However, since the other safety function of vacuum relief would not be available if the normal drywell isolation valve actions were taken, the drywell isolation valve OPERABILITY requirements are not applicable to the Drywell Vacuum Relief System isolation valves. Similar surveillance requirements in the LCO for Drywell Vacuum Relief System provide assurance that the isolation capability is available without conflicting with the vacuum relief function.
The Drywell Vent and Purge System is a high capacity system with a
[20] inch line, which has isolation valves covered by this LCO. The system supplies filtered outside air directly to the drywell through two lines, each containing two primary containment isolation valves (PCIVs) and two drywell isolation valves called drywell purge isolation valves. The drywell air is exhausted through a line also containing two drywell purge isolation valves by means of two fan units, which are part of the Containment Cooling System charcoal filter trains located inside primary containment. After the air is conditioned and filtered, it is exhausted through two PCIVs. The system is used to remove trace radioactive airborne products prior to personnel entry. The Drywell Vent and Purge System is seldom used in MODE 1, 2, or 3; therefore, the drywell purge isolation valves are seldom open during power operation.
General Electric BWR/6 STS              B 3.6.5.3-1                                        Rev. 5.0
 
Drywell Isolation Valves B 3.6.5.3 BASES BACKGROUND (continued)
The drywell purge isolation valves fail closed on loss of instrument air or power. The drywell purge isolation valves are fast closing valves (approximately [4] seconds). These valves are qualified to close against the differential pressure induced by a loss of coolant accident (LOCA).
APPLICABLE          This LCO is intended to ensure that releases from the core do not bypass SAFETY              the suppression pool so that the pressure suppression capability of the ANALYSES            drywell is maintained. Therefore, as part of the drywell boundary, drywell isolation valve OPERABILITY minimizes drywell bypass leakage.
Therefore, the safety analysis of any event requiring isolation of the drywell is applicable to this LCO.
The DBA resulting in a release of steam, water, or radioactive material within the drywell is a LOCA. In the analysis for these accidents, it is assumed that drywell isolation valves either are closed or function to close within the required isolation time following event initiation. Analyses (Ref. 1) also assumed a 4 second drywell purge isolation valve closure time following a 1 second delay prior to closure.
The drywell isolation valves and drywell purge isolation valves satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                The drywell isolation valve safety function is to form a part of the drywell boundary.
The drywell isolation valves are required to have isolation times of automatic drywell isolation valves within limits, automatic drywell isolation valves actuate on an automatic isolation signal, drywell isolation manual valves closed, purge valves closed, and 20 inch purge valves blocked to restrict maximum valve opening. While the Drywell Vacuum Relief System valves isolate drywell penetrations, they are excluded from this Specification. Controls on their isolation function are adequately addressed in LCO 3.6.5.6, "Drywell Vacuum Relief System." The valves covered by this LCO are included (with their associated stroke time for automatic valves) in Reference 2.
The normally closed isolation valves or blind flanges are considered OPERABLE when manual valves are closed or open in accordance with appropriate administrative controls, automatic valves are de-activated and secured in their closed position (including check valves with flow through the valve secured), and blind flanges are in place. These passive isolation valves and devices are those listed in Reference 2.
General Electric BWR/6 STS            B 3.6.5.3-2                                        Rev. 5.0
 
Drywell Isolation Valves B 3.6.5.3 BASES APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to the primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, the drywell isolation valves are not required to be OPERABLE in MODES 4 and 5.
ACTIONS            The ACTIONS are modified by three Notes. The first Note allows penetration flow paths to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated operator, who is in continuous communication with the control room, at the controls of the valve. In this way, the penetration can be rapidly isolated when a need for drywell isolation is indicated.
The second Note provides clarification that for the purpose of this LCO separate Condition entry is allowed for each penetration flow path.
The third Note requires the OPERABILITY of affected systems to be evaluated when a drywell isolation valve is inoperable. This ensures appropriate remedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable drywell isolation valve.
The fourth Note ensures appropriate remedial actions are taken when the drywell bypass leakage limits are exceeded. Pursuant to LCO 3.0.6, these ACTIONS are not required even when the associated LCO is not met. Therefore, Note 4 is added to require the proper actions be taken.
A.1 and A.2 With one or more penetration flow paths with one drywell isolation valve inoperable, the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic drywell isolation valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured. In this Condition, the remaining OPERABLE drywell isolation valve is adequate to perform the isolation function. However, the overall reliability is reduced because a single failure in the OPERABLE drywell isolation valve could result in a loss of drywell isolation. The 8 hour Completion Time is acceptable, since the drywell design bypass leakage A/k of [1.0] ft2 would be maintained even with a single failure due to application of ACTIONS Note 4. In addition, the Completion Time is reasonable, considering the time required to isolate the penetration and the relative importance of supporting drywell OPERABILITY during MODES 1, 2, and 3.
[Alternatively, a Completion Time can be determined in accordance with the Risk Informed Completion Time Program.]
General Electric BWR/6 STS            B 3.6.5.3-3                                        Rev. 5.0
 
Drywell Isolation Valves B 3.6.5.3 BASES ACTIONS (continued)
For affected penetration flow paths that have been isolated in accordance with Required Action A.1, the affected penetrations must be verified to be isolated on a periodic basis. This is necessary to ensure that drywell penetrations that are required to be isolated following an accident, and 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 device manipulation; rather, it involves verification that those devices outside drywell and capable of potentially being mispositioned are in the correct position. Since these devices are inside primary containment, the time period specified as "prior to entering MODE 2 or 3 from MODE 4, if not performed within the previous 92 days," is based on engineering judgment and is considered reasonable in view of the inaccessibility of the devices and other administrative controls that will ensure that device misalignment is an unlikely possibility. Also, this Completion Time is consistent with the Completion Time specified for PCIVs in LCO 3.6.1.3, "Primary Containment Isolation Valves (PCIVs)."
Required Action A.2 is modified by two Notes. Note 1 applies to isolation devices located in high radiation areas and allows them to be verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted. 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 once they have been verified to be in the proper position, is low.
B.1 With one or more penetration flow paths with two drywell isolation valves inoperable, the affected penetration flow path must be isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, a blind flange, and a check valve with flow through the valve secured. The 4 hour Completion Time is acceptable, since the drywell design bypass leakage A/k of [1.0] ft2 is maintained due to application of ACTIONS Note 4. The Completion Time is reasonable, considering the time required to isolate the penetration, and the probability of a DBA, which requires the drywell isolation valves to close, occurring during this short time is very low.
General Electric BWR/6 STS            B 3.6.5.3-4                                        Rev. 5.0
 
Drywell Isolation Valves B 3.6.5.3 BASES ACTIONS (continued)
Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two isolation valves. For penetration flow paths with one drywell isolation valve, Condition A provides the appropriate Required Actions.
C.1 and C.2 If any Required Action and associated Completion Time cannot be met, the plant must be placed in a MODE in which the LCO does not apply.
To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 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 3.6.5.3.1 REQUIREMENTS Each [ ] inch drywell purge isolation valve is required to be periodically verified sealed closed. This Surveillance is intended to be used for drywell purge isolation valves that are not qualified to open under accident conditions. This SR is designed to ensure that a gross breach of drywell is not caused by an inadvertent or spurious drywell purge isolation valve opening. Detailed analysis of these [ ] inch drywell purge valves failed to conclusively demonstrate their ability to close during a LOCA in time to support drywell OPERABILITY. Therefore, these valves are required to be in sealed closed position during MODES 1, 2, and 3.
These [ ] inch drywell purge valves that are sealed closed must have motive power to the valve operator removed. This can be accomplished by de-energizing the source of electric power or removing the air supply to the valve operator. In this application, the term "sealed" has no connotation of leakage within limits. [ The Frequency is a result of the NRC resolution of Generic Issue B-24 (Ref. 3) related to purge valve use during unit operations.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
General Electric BWR/6 STS                B 3.6.5.3-5                                                      Rev. 5.0
 
Drywell Isolation Valves B 3.6.5.3 BASES SURVEILLANCE REQUIREMENTS (continued)
[ SR 3.6.5.3.2 This SR ensures that the [20] inch drywell purge isolation valves are closed as required or, if open, open for an allowable reason. This SR is intended to be used for drywell purge isolation valves that are fully qualified to close under accident conditions; therefore, these valves are allowed to be open for limited periods of time. This SR has been modified by a Note indicating the SR is not required to be met when the drywell purge supply or exhaust valves are open for pressure control, ALARA or air quality considerations for personnel entry, or surveillances that require the valve to be open [provided the [20] inch containment [purge system supply and exhaust] lines are isolated]. [ The 31 day Frequency is consistent with the valve requirements discussed under SR 3.6.5.3.1.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
SR 3.6.5.3.3 This SR requires verification that each drywell isolation manual valve and blind flange that is not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that drywell bypass leakage is maintained to a minimum. Since these valves are inside primary containment, the Frequency specified as "prior to entering MODE 2 or 3 from MODE 4, if not performed in the previous 92 days," is appropriate because of the inaccessibility of the drywell isolation valves and because these drywell isolation valves are operated under administrative controls and the probability of their misalignment is low. 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.
A Note has been included to clarify that valves that are open under administrative controls are not required to meet the SR during the time the valves are open.
General Electric BWR/6 STS                B 3.6.5.3-6                                                      Rev. 5.0
 
Drywell Isolation Valves B 3.6.5.3 BASES SURVEILLANCE REQUIREMENTS (continued)
SR 3.6.5.3.4 Verifying that the isolation time of each power operated, automatic drywell 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 is in accordance with the INSERVICE TESTING PROGRAM.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
If the testing is within the scope of the licensee's INSERVICE TESTING PROGRAM, the Frequency "In accordance with the INSERVICE TESTING PROGRAM" should be used. Otherwise, the periodic Frequency of 92 days or the reference to the Surveillance Frequency Control Program should be used.
[ The Frequency of this SR is [ in accordance with the INSERVICE TESTING PROGRAM] [92 days.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
SR 3.6.5.3.5 Verifying that each automatic drywell isolation valve closes on a drywell isolation signal is required to prevent bypass leakage from the drywell following a DBA. This SR ensures each automatic drywell isolation valve will actuate to its isolation position on a drywell isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.6.1.6 overlaps this SR to provide complete testing of the safety function. [ The [18] month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power, since isolation of penetrations would eliminate cooling water flow and disrupt the normal operation of many critical components. Operating General Electric BWR/6 STS                B 3.6.5.3-7                                                      Rev. 5.0
 
Drywell Isolation Valves B 3.6.5.3 BASES SURVEILLANCE REQUIREMENTS (continued) experience has shown these components usually pass this Surveillance when performed at the [18] month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.5.3.6 Verifying that each [ ] inch drywell purge valve is blocked to restrict opening to > [50]% is required to ensure that the valves can be closed under DBA conditions within the time limits assumed in the safety analyses.
[ The [18] month Frequency is appropriate because the blocking devices are typically removed only during a refueling outage.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [6.2.4].
: 2. FSAR, Table [6.2-44].
: 3. Generic Issue B-24.
General Electric BWR/6 STS                B 3.6.5.3-8                                                      Rev. 5.0
 
Drywell Pressure B 3.6.5.4 B 3.6 CONTAINMENT SYSTEMS B 3.6.5.4 Drywell Pressure BASES BACKGROUND          Drywell-to-primary containment differential pressure is an assumed initial condition in the analyses that determine the primary containment thermal hydraulic and dynamic loads during a postulated loss of coolant accident (LOCA).
If drywell pressure is less than the primary containment airspace pressure, the water level in the weir annulus will increase and, consequently, the liquid inertia above the top vent will increase. This will cause top vent clearing during a postulated LOCA to be delayed, and that would increase the peak drywell pressure. In addition, an inadvertent upper pool dump occurring with a negative drywell-to-primary containment differential pressure could result in overflow over the weir wall.
The limitation on negative drywell-to-primary containment differential pressure ensures that changes in calculated peak LOCA drywell pressures due to differences in water level of the suppression pool and the drywell weir annulus are negligible. It also ensures that the possibility of weir wall overflow after an inadvertent pool dump is minimized. The limitation on positive drywell-to-primary containment differential pressure helps ensure that the horizontal vents are not cleared with normal weir annulus water level.
APPLICABLE          Primary containment performance is evaluated for the entire spectrum of SAFETY              break sizes for postulated LOCAs. Among the inputs to the design basis ANALYSES            analysis is the initial drywell internal pressure (Ref. 1). The initial drywell internal pressure affects the drywell pressure response to a LOCA (Ref. 1) and the suppression pool swell load definition (Ref. 2).
Additional analyses (Refs. 3 and 4) have been performed to show that if initial drywell pressure does not exceed the negative pressure limit, the suppression pool swell and vent clearing loads will not be significantly increased and the probability of weir wall overflow is minimized after an inadvertent upper pool dump.
Drywell pressure satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO                  A limitation on the drywell-to-primary containment differential pressure of
[ -0.26 psid and  2.0 psid] is required to ensure that suppression pool water is not forced over the weir wall, vent clearing does not occur during normal operation, containment conditions are consistent with the safety analyses, and LOCA drywell pressures and pool swell loads are within design values.
General Electric BWR/6 STS              B 3.6.5.4-1                                          Rev. 5.0
 
Drywell Pressure B 3.6.5.4 BASES APPLICABILITY      In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to the primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining the drywell-to-primary containment differential pressure limitation is not required in MODE 4 or 5.
ACTIONS            A.1 With drywell-to-primary containment differential pressure not within the limits of the LCO, it must be restored within 1 hour. The Required Action is necessary to return operation to within the bounds of the safety analyses. The 1 hour Completion Time is consistent with the ACTIONS of LCO 3.6.5.1, "Drywell," which requires that the drywell be restored to OPERABLE status within 1 hour.
B.1 and B.2 If drywell-to-primary containment differential 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 12 hours and to MODE 4 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 3.6.5.4.1 REQUIREMENTS This SR provides assurance that the limitations on drywell-to-primary containment differential pressure stated in the LCO are met. [ The 12 hour Frequency of this SR was developed, based on operating experience related to trending of drywell pressure variations during the applicable MODES and to assessing proximity to the specified LCO pressure limits. 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 drywell pressure condition.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS            B 3.6.5.4-2                                      Rev. 5.0
 
Drywell Pressure B 3.6.5.4 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [6.2.1].
: 2. FSAR, Section [3.8].
: 3. FSAR, Section [6.2.1.1.6].
: 4. FSAR, Section [6.2.7].
General Electric BWR/6 STS                B 3.6.5.4-3                                                      Rev. 5.0
 
Drywell Air Temperature B 3.6.5.5 B 3.6 CONTAINMENT SYSTEMS B 3.6.5.5 Drywell Air Temperature BASES BACKGROUND            The drywell contains the reactor vessel and piping, which add heat to the airspace. Drywell coolers remove heat and maintain a suitable environment. The drywell average air temperature affects equipment OPERABILITY, personnel access, and the calculated response to postulated Design Basis Accidents (DBAs). The limitation on drywell average air temperature ensures that the peak drywell temperature during a design basis loss of coolant accident (LOCA) does not exceed the design temperature of [330]&deg;F. The limiting DBA for drywell atmosphere temperature is a small steam line break, assuming no heat transfer to the passive steel and concrete heat sinks in the drywell.
APPLICABLE            Primary containment performance for the DBA is evaluated for the entire SAFETY                spectrum of break sizes for postulated LOCAs inside containment ANALYSES              (Ref. 1). Among the inputs to the design basis analysis is the initial drywell average air temperature. Increasing the initial drywell average air temperature could change the calculated results of the design bases analysis. The safety analyses (Ref. 1) assume an initial average drywell air temperature of [135]&deg;F. This limitation ensures that the safety analyses remain valid by maintaining the expected initial conditions and ensures that the peak LOCA drywell temperature does not exceed the maximum allowable temperature of [330]&deg;F. The consequence of exceeding this design temperature may result in the degradation of the drywell structure under accident loads. Equipment inside the drywell that is required to mitigate the effects of a DBA is designed and qualified to operate under environmental conditions expected for the accident.
Drywell average air temperature satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).
LCO                  If the initial drywell average air temperature is less than or equal to the LCO temperature limit, the peak accident temperature can be maintained below the drywell design temperature during a DBA. This ensures the ability of the drywell to perform its design function.
APPLICABILITY        In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to the primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, maintaining drywell average air temperature within the limit is not required in MODE 4 or 5.
General Electric BWR/6 STS              B 3.6.5.5-1                                        Rev. 5.0
 
Drywell Air Temperature B 3.6.5.5 BASES ACTIONS              A.1 When the drywell average air temperature is not within the limit of the LCO, it must be restored within 8 hours. The Required Action is necessary to return operation to within the bounds of the safety analyses.
The 8 hour Completion Time is acceptable, considering the sensitivity of the analyses to variations in this parameter, and provides sufficient time to correct minor problems.
B.1 and B.2 If drywell average air temperature cannot be restored to within limit within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 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 3.6.5.5.1 REQUIREMENTS Verifying that the drywell average air temperature is within the LCO limit ensures that operation remains within the limits assumed for the drywell analysis. Drywell air temperature is monitored in all quadrants and at various elevations. Since the measurements are uniformly distributed, an arithmetic average is an accurate representation of actual drywell average temperature.
[ The 24 hour Frequency of the SR was developed based on operating experience related to variations in drywell average air temperature variations during the applicable MODES. 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 drywell air temperature condition.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                B 3.6.5.5-2                                                      Rev. 5.0
 
Drywell Air Temperature B 3.6.5.5 BASES REFERENCES          1. FSAR, Section [6.2].
General Electric BWR/6 STS        B 3.6.5.5-3                Rev. 5.0
 
Drywell Vacuum Relief System B 3.6.5.6 B 3.6 CONTAINMENT SYSTEMS B 3.6.5.6 Drywell Vacuum Relief System BASES BACKGROUND          The Mark III pressure suppression containment is designed to condense, in the suppression pool, the steam released into the drywell in the event of a loss of coolant accident (LOCA). The steam discharging to the pool carries the noncondensibles from the drywell. Therefore, the drywell atmosphere changes from low humidity air to nearly 100% steam (no air) as the event progresses. When the drywell subsequently cools and depressurizes, noncondensibles in the drywell must be replaced to avoid excessive weir wall overflow into the drywell. Rapid weir wall overflow must be controlled in a large break LOCA, so that essential equipment and systems located above the weir wall in the drywell are not subjected to excessive drag and impact loads. The drywell post-LOCA and the drywell purge vacuum relief subsystems are the means by which noncondensibles are transferred from the primary containment back to the drywell.
The vacuum relief systems are a potential source of bypass leakage (i.e.,
some of the steam released into the drywell from a LOCA bypasses the suppression pool and leaks directly to the primary containment airspace).
Since excessive bypass leakage could degrade the pressure suppression function, the Drywell Vacuum Relief System has been designed with at least two valves in series in each vacuum breaker line. This minimizes the potential for a stuck open valve to threaten drywell OPERABILITY.
The [two] drywell purge vacuum relief subsystems use separate [10] inch lines penetrating the drywell, and each subsystem consists of a series arrangement of a motor operated isolation valve and two check valves.
The [two] drywell post-LOCA vacuum relief subsystems use a common
[10] inch line penetrating the drywell, and each subsystem consists of a motor operated valve in series with a check valve. At least two [10] inch lines must be available to provide adequate relief to control rapid weir wall overflow.
APPLICABLE          The Drywell Vacuum Relief System must function in the event of a large SAFETY              break LOCA to control rapid weir wall overflow that could cause drag and ANALYSES            impact loadings on essential equipment and systems in the drywell above the weir wall. The Drywell Vacuum Relief System is not required to assist in hydrogen dilution or to protect the structural integrity of the drywell following a large break LOCA. Furthermore, their passive operation (remaining closed and not leaking during drywell pressurization) is implicit in all of the LOCA analyses (Ref. 1).
The Drywell Vacuum Relief System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
General Electric BWR/6 STS            B 3.6.5.6-1                                          Rev. 5.0
 
Drywell Vacuum Relief System B 3.6.5.6 BASES LCO                The LCO ensures that in the event of a LOCA, [two] drywell post-LOCA and [two] drywell purge vacuum relief subsystems are available to mitigate the potential subsequent drywell depressurization. Each vacuum relief subsystem is OPERABLE when capable of opening at the required setpoint but is maintained in the closed position during normal operation.
APPLICABILITY      In MODES 1, 2, and 3, a Design Basis Accident could cause pressurization of primary containment. Therefore, Drywell Vacuum Relief System OPERABILITY is required during these MODES. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the Drywell Vacuum Relief System OPERABLE is not required in MODE 4 or 5.
ACTIONS            The ACTIONS Note ensures appropriate remedial actions are taken when the drywell bypass leakage limits are exceeded. Pursuant to LCO 3.0.6, these ACTIONS are not required even when the associated LCO is not met. Therefore, the Note is added to require the proper actions be taken.
A.1 With one or more vacuum relief subsystems open, the subsystem must be closed within 4 hours. This assures that drywell leakage would not result if a postulated LOCA were to occur. The 4 hour Completion Time is acceptable, since the drywell design bypass leakage A/k) of [1.0] ft2 is maintained, and is considered a reasonable length of time needed to complete the Required Action.
A Note has been added to provide clarification that separate Condition entry is allowed for vacuum relief subsystems not closed.
B.1 and C.1 With one [or two] drywell post-LOCA vacuum relief subsystems inoperable or one drywell purge vacuum relief subsystem inoperable, for reasons other then being not closed, the inoperable subsystem(s) must be restored to OPERABLE status within 30 days. In these Conditions, the remaining OPERABLE vacuum relief subsystems are adequate to perform the depressurization mitigation function since two [10] inch lines remain available. The 30 day Completion Time takes into account the redundant capability afforded by the remaining subsystems, a reasonable time for repairs, and the low probability of an event requiring the vacuum relief subsystems to function occurring during this period.
General Electric BWR/6 STS            B 3.6.5.6-2                                      Rev. 5.0
 
Drywell Vacuum Relief System B 3.6.5.6 BASES ACTIONS (continued)
D.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
If one [or two] drywell post-LOCA vacuum relief subsystems are inoperable for reasons other than not being closed or one drywell purge vacuum relief subsystem is inoperable for reasons other than not being closed, and not restored within the provided Completion Time, the plant must be brought to a condition in which the overall plant risk is minimized.
To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 2) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action D.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
General Electric BWR/6 STS                B 3.6.5.6-3                                                      Rev. 5.0
 
Drywell Vacuum Relief System B 3.6.5.6 BASES ACTIONS (continued)
E.1 and F.1 With [two] drywell purge vacuum relief subsystems inoperable or with
[two] drywell post-LOCA and one drywell purge vacuum relief subsystems inoperable, for reasons other than being not closed, at least one inoperable subsystem must be restored to OPERABLE status within 72 hours. In these Conditions, only one [10] inch line remains available.
The 72 hour Completion Time takes into account at least one vacuum relief subsystem is still OPERABLE, a reasonable time for repairs, and the low probability of an event requiring the vacuum relief subsystems to function occurring during this period.
G.1, G.2, H.1, and H.2 If the inoperable drywell vacuum relief subsystem(s) cannot be closed or restored to OPERABLE status within the required Completion Time, or if two drywell purge vacuum relief subsystems are inoperable, for reasons other than being not closed, and two drywell post-LOCA vacuum relief subsystem(s) are inoperable, for reasons other than being not closed, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours and to MODE 4 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 3.6.5.6.1 REQUIREMENTS Each vacuum breaker and its associated isolation valve is verified to be closed to ensure that this potential large bypass leakage path is not present. This Surveillance is performed by observing the vacuum breaker or associated isolation valve position indication or by verifying that the vacuum breakers are closed when a differential pressure of [1.0] psid between the drywell and primary containment is maintained for 1 hour without makeup. [ The 7 day Frequency is based on engineering judgment, is considered adequate in view of other indications of vacuum breaker or isolation valve status available to the plant personnel, and has been shown to be acceptable through operating experience.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS            B 3.6.5.6-4                                        Rev. 5.0
 
Drywell Vacuum Relief System B 3.6.5.6 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
Two Notes are added to this SR. The first Note allows drywell vacuum breakers opened in conjunction with the performance of a Surveillance to not be considered as failing this SR. These periods of opening drywell vacuum breakers are controlled by plant procedures and do not represent inoperable drywell vacuum breakers. A second Note is included to clarify that vacuum breakers open due to an actual differential pressure are not considered as failing this SR.
SR 3.6.5.6.2 Each vacuum breaker and its associated isolation valve must be cycled to ensure that it opens adequately to perform its design function and returns to the fully closed position. This provides assurance that the safety analysis assumptions are valid. [ A 31 day Frequency was chosen to provide additional assurance that the vacuum breakers and their associated isolation valves are OPERABLE.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.6.5.6.3 Verification of the vacuum breaker opening setpoint is necessary to ensure that the safety analysis assumption that the vacuum breaker will open fully at a differential pressure of [1.0] psid is valid. [ 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 General Electric BWR/6 STS                B 3.6.5.6-5                                                      Rev. 5.0
 
Drywell Vacuum Relief System B 3.6.5.6 BASES SURVEILLANCE REQUIREMENTS (continued) power. Operating experience has shown these components usually pass the Surveillance when performed at the [18] month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [6.2].
: 2. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
General Electric BWR/6 STS                B 3.6.5.6-6                                                      Rev. 5.0
 
[SSW] System and [UHS]
B 3.7.1 B 3.7 PLANT SYSTEMS B 3.7.1 [Standby Service Water (SSW)] System and [Ultimate Heat Sink (UHS)]
BASES BACKGROUND          The [SSW] System is designed to provide cooling water for the removal of heat from unit auxiliaries, such as Residual Heat Removal (RHR) System heat exchangers, standby diesel generators (DGs), and room coolers for Emergency Core Cooling System equipment required for a safe reactor shutdown following a Design Basis Accident (DBA) or transient. The
[SSW] System also provides cooling to unit components, as required, during normal shutdown and reactor isolation modes. During a DBA, the equipment required for normal operation only is isolated from the [SSW]
System, and cooling is directed only to safety related equipment.
The [SSW] System consists of the [UHS], two independent cooling water headers (subsystems A and B), and their associated pumps, piping, valves, and instrumentation. The two [SSW] pumps, or one [SSW] pump and the high pressure core spray service water pump, are sized to provide sufficient cooling capacity to support the required safety related systems during safe shutdown of the unit following a loss of coolant accident (LOCA). Subsystems A and B are redundant and service equipment in [SSW] Divisions 1 and 2, respectively.
The [UHS] consists of two concrete makeup water basins, each containing one cooling tower with two fan cells per basin. The combined basin volume is sized such that sufficient water inventory is available for all [SSW] System post LOCA cooling requirements for a 30 day period with no external makeup water source available (Regulatory Guide 1.27, Ref. 1). Normal makeup for each basin is provided automatically by the Plant Service Water System.
Cooling water is pumped from the cooling tower basins by the two [SSW]
pumps to the essential components through the two main redundant supply headers (subsystems A and B). After removing heat from the components, the water is discharged to the cooling towers where the heat is rejected through direct contact with ambient air.
Subsystems A and B supply cooling water to redundant equipment required for a safe reactor shutdown. Additional information on the design and operation of the [SSW] System and [UHS] along with the specific equipment for which the [SSW] System supplies cooling water is provided in the FSAR, Section [9.2.1] and the FSAR, Table [9.2-3]
(Refs. 2 and 3, respectively). The [SSW] System is designed to withstand a single active or passive failure, coincident with a loss of offsite power, without losing the capability to supply adequate cooling water to equipment required for safe reactor shutdown.
General Electric BWR/6 STS              B 3.7.1-1                                          Rev. 5.0
 
[SSW] System and [UHS]
B 3.7.1 BASES BACKGROUND (continued)
Following a DBA or transient, the [SSW] System will operate automatically without operator action. Manual initiation of supported systems (e.g., suppression pool cooling) is, however, performed for long term cooling operations.
APPLICABLE          The volume of each water source incorporated in a [UHS] complex is SAFETY              sized so that sufficient water inventory is available for all [SSW] System ANALYSES            post LOCA cooling requirements for a 30 day period with no additional makeup water source available (Ref. 1). The ability of the [SSW] System to support long term cooling of the reactor or containment is assumed in evaluations of the equipment required for safe reactor shutdown presented in the FSAR, Sections [9.2.1], [6.2.1.1.3.3.1.6] and Chapter [15], (Refs. 2, 4, and 5, respectively). These analyses include the evaluation of the long term primary containment response after a design basis LOCA. The [SSW] System provides cooling water for the RHR suppression pool cooling mode to limit suppression pool temperature and primary containment pressure following a LOCA. This ensures that the primary containment can perform its intended function of limiting the release of radioactive materials to the environment following a LOCA. The [SSW] System also provides cooling to other components assumed to function during a LOCA (e.g., RHR and Low Pressure Core Spray systems). Also, the ability to provide onsite emergency AC power is dependent on the ability of the [SSW] System to cool the DGs.
The safety analyses for long term containment cooling were performed, as discussed in the FSAR, Sections [6.2.1.1.3.3.1.6] and [6.2.2.3] (Refs. 4 and 6, respectively), for a LOCA, concurrent with a loss of offsite power, and minimum available DG power. The worst case single failure affecting the performance of the [SSW] System is the failure of one of the two standby DGs, which would in turn affect one [SSW] subsystem. The
[SSW] flow assumed in the analyses is [7900] gpm per pump to the heat exchanger (FSAR, Table [6.2-2], Ref. 7). Reference 2 discusses [SSW]
System performance during these conditions.
The [SSW] System, together with the [UHS], satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                The OPERABILITY of subsystem A (Division 1) and subsystem B (Division 2) of the [SSW] System is required to ensure the effective operation of the RHR System in removing heat from the reactor, and the effective operation of other safety related equipment during a DBA or transient. Requiring both subsystems to be OPERABLE ensures that either subsystem A or B will be available to provide adequate capability to meet cooling requirements of the equipment required for safe shutdown in the event of a single failure.
General Electric BWR/6 STS            B 3.7.1-2                                        Rev. 5.0
 
[SSW] System and [UHS]
B 3.7.1 BASES LCO (continued)
A subsystem is considered OPERABLE when:
: a. The associated pump is OPERABLE,
: b. The associated [UHS] is OPERABLE, and
: c. The associated piping, valves, instrumentation, and controls required to perform the safety related function are OPERABLE.
OPERABILITY of the [UHS] is based on a maximum water temperature of
[95]&deg;F with OPERABILITY of each subsystem requiring a minimum basin water level at or above elevation [130 ft 3 inches] mean sea level (equivalent to an indicated level of  [7 ft 3 inches]) and four OPERABLE cooling tower fans.
The isolation of the [SSW] System to components or systems may render those components or systems inoperable, but does not affect the OPERABILITY of the [SSW] System.
OPERABILITY of the High Pressure Core Spray (HPCS) Service Water System (SWS) is addressed by LCO 3.7.2, "HPCS SWS."
APPLICABILITY      In MODES 1, 2, and 3, the [SSW] System and [UHS] are required to be OPERABLE to support OPERABILITY of the equipment serviced by the
[SSW] System and [UHS], and are required to be OPERABLE in these MODES.
Although the LCO for the [SSW] System and [UHS] is not applicable in MODES 4 and 5, the capability of the [SSW] System and [UHS] to perform their necessary related support functions may be required for OPERABILITY of supported systems.
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 restore the inoperable cooling tower fan(s) to OPERABLE status within 7 days [or in accordance with the Risk Informed Completion Time Program].
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 in one or more cooling towers, the number of available systems, and the time required to complete the Required Action. ]
General Electric BWR/6 STS            B 3.7.1-3                                        Rev. 5.0
 
[SSW] System and [UHS]
B 3.7.1 BASES ACTIONS (continued)
B.1 If one [SSW] subsystem is inoperable [for reasons other than Condition A], it must be restored to OPERABLE status within 72 hours [or in accordance with the Risk Informed Completion Time Program]. With the unit in this condition, the remaining OPERABLE [SSW] subsystem is adequate to perform the heat removal function. However, the overall reliability is reduced because a single failure in the OPERABLE [SSW]
subsystem could result in loss of [SSW] function. The 72 hour Completion Time was developed taking into account the redundant capabilities afforded by the OPERABLE subsystem and the low probability of a DBA occurring during this period.
The Required Action is modified by two Notes indicating that the applicable Conditions of LCO 3.8.1, "AC Sources - Operating," and LCO 3.4.9, "Residual Heat Removal (RHR) Shutdown Cooling System -
Hot Shutdown," be entered and the Required Actions taken if the inoperable [SSW] subsystem results in an inoperable DG or RHR shutdown cooling, respectively. This is in accordance with LCO 3.0.6 and ensures the proper actions are taken for these components.
C.1
                    -----------------------------------REVIEWERS NOTE ----------------------------------
Adoption of a MODE 3 end state requires the licensee to make the following commitments:
: 1.    [LICENSEE] will follow the guidance established in Section 11 of NUMARC 93-01, "Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Nuclear Management and Resource Council, Revision [4F].
: 2.    [LICENSEE] will follow the guidance established in TSTF-IG-05-02, Implementation Guidance for TSTF-423, Revision 2, "Technical Specifications End States, NEDC-32988-A," November 2009.
If one or more cooling towers with one cooling tower fan are inoperable or one SSW subsystem is inoperable for reasons other than Condition A and not restored within the provided Completion Time, the plant must be brought to a condition in which overall plant risk is minimized. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours.
General Electric BWR/6 STS                B 3.7.1-4                                                      Rev. 5.0
 
[SSW] System and [UHS]
B 3.7.1 BASES ACTIONS (continued)
Remaining in the Applicability of the LCO is acceptable because the plant risk in MODE 3 is similar to or lower than the risk in MODE 4 (Ref. 8) and because the time spent in MODE 3 to perform the necessary repairs to restore the system to OPERABLE status will be short. However, voluntary entry into MODE 4 may be made as it is also an acceptable low-risk state.
Required Action C.1 is modified by a Note that states that LCO 3.0.4.a is not applicable when entering MODE 3. This Note prohibits the use of LCO 3.0.4.a to enter MODE 3 during startup with the LCO not met.
However, there is no restriction on the use of LCO 3.0.4.b, if applicable, because LCO 3.0.4.b requires performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering MODE 3, and establishment of risk management actions, if appropriate. LCO 3.0.4 is not applicable to, and the Note does not preclude, changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS or that are part of a shutdown of the unit.
The allowed Completion Time is 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
                    -----------------------------------REVIEWERS NOTE-----------------------------------
The [ ]&deg;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]&deg;F, the design basis assumption associated with initial UHS temperature is bounded provided the temperature of the UHS averaged over the previous 24 hour period is
[90]&deg;F. With the water temperature of the UHS > [90]&deg;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]&deg;F, Required Action D.1 is provided to more frequently monitor the water temperature of the UHS and verify the temperature is  [90]&deg;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 General Electric BWR/6 STS                  B 3.7.1-5                                                      Rev. 5.0
 
[SSW] System and [UHS]
B 3.7.1 BASES ACTIONS (continued) the UHS exceeds [90]&deg;F when averaged over the previous 24 hour period or the water temperature of the UHS exceeds [ ]&deg;F, Condition E must be entered immediately.]
E.1 and E.2 If the UHS water temperature is not within the limit in Condition D, or both
[SSW] subsystems are inoperable [for reasons other than Condition A], or the ((UHS] is determined inoperable for reasons other than Condition A or D], 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 12 hours and in MODE 4 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 3.7.1.1 REQUIREMENTS This SR ensures adequate long term (30 days) cooling can be maintained. With the [UHS] water source below the minimum level, the affected [SSW] subsystem must be declared inoperable. [ The 24 hour Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
[ SR 3.7.1.2 This SR verifies the water level [in each [SSW] pump well of the intake structure] to be sufficient for the proper operation of the [SSW] pumps (net positive suction head and pump vortexing are considered in determining this limit). [ The 24 hour Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.
General Electric BWR/6 STS                  B 3.7.1-6                                                      Rev. 5.0
 
[SSW] System and [UHS]
B 3.7.1 BASES SURVEILLANCE REQUIREMENTS (continued)
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
[ SR 3.7.1.3 Verification of the [UHS] temperature ensures that the heat removal capability of the [SSW] System is within the assumptions of the DBA analysis. [ The 24 hour Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
[ SR 3.7.1.4 Operating each cooling tower fan for  15 minutes ensures 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 cooling tower fans occurring between Surveillances.
OR General Electric BWR/6 STS                  B 3.7.1-7                                                      Rev. 5.0
 
[SSW] System and [UHS]
B 3.7.1 BASES SURVEILLANCE REQUIREMENTS (continued)
The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ---------------------------------------------------------------------------------------------- ] ]
SR 3.7.1.5 Verifying the correct alignment for each manual, power operated, and automatic valve in each [SSW] subsystem flow path provides assurance that the proper flow paths will exist for [SSW] 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, sealing, or securing. A valve is also allowed to be in the nonaccident position and yet considered in the correct position, provided it can be automatically realigned to its accident position. This SR 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 does not apply to valves that cannot be inadvertently misaligned, such as check valves.
This SR is modified by a Note indicating that isolation of the [SSW]
System to components or systems may render those components or systems inoperable, but does not affect the OPERABILITY of the [SSW]
System. As such, when all [SSW] pumps, valves, and piping are OPERABLE, but a branch connection off the main header is isolated, the
[SSW] System is still OPERABLE.
[ The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
General Electric BWR/6 STS                  B 3.7.1-8                                                      Rev. 5.0
 
[SSW] System and [UHS]
B 3.7.1 BASES SURVEILLANCE REQUIREMENTS (continued)
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.7.1.6 This SR verifies that the automatic isolation valves of the [SSW] System will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety related equipment during an accident event. This is demonstrated by use of an actual or simulated initiation signal. This SR also verifies the automatic start capability of the
[SSW] pump and cooling tower fans in each subsystem. The SR excludes automatic valves that are locked, sealed, or otherwise secured in the actuated position. The SR does not apply to valves that are locked, sealed, or otherwise secured in the actuated position since the affected valves were verified to be in the actuated position prior to being locked, sealed, or otherwise secured. Placing an automatic valve in a locked, sealed, or otherwise secured position requires an assessment of the OPERABILITY of the system or any supported systems, including whether it is necessary for the valve to be repositioned to the non-actuated position to support the accident analysis. Restoration of an automatic valve to the non-actuated position requires verification that the SR has been met within its required Frequency. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.5.1.6 overlaps this SR to provide complete testing of the safety function.
[ Operating experience has shown that these components usually pass the SR when performed on the [18] month Frequency. Therefore, this Frequency is concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
General Electric BWR/6 STS                  B 3.7.1-9                                                      Rev. 5.0
 
[SSW] System and [UHS]
B 3.7.1 BASES REFERENCES          1. Regulatory Guide 1.27, Revision 2, January 1976.
: 2. FSAR, Section [9.2.1].
: 3. FSAR, Table [9.2-3].
: 4. FSAR, Section [6.2.1.1.3.3.1.6].
: 5. FSAR, Chapter [15].
: 6. FSAR, Section [6.2.2.3].
: 7. FSAR, Table [6.2-2].
: 8. NEDC-32988-A, Revision 2, Technical Justification to Support Risk-Informed Modification to Selected Required End States for BWR Plants, December 2002.
General Electric BWR/6 STS          B 3.7.1-10                                    Rev. 5.0
 
HPCS SWS B 3.7.2 B 3.7 PLANT SYSTEMS B 3.7.2 High Pressure Core Spray (HPCS) Service Water System (SWS)
BASES BACKGROUND          The HPCS SWS is designed to provide cooling water for the removal of heat from components of the Division 3 HPCS System.
The HPCS SWS consists of the Ultimate Heat Sink (UHS) Basin A, one cooling water header (subsystem C of the Standby Service Water (SSW)
System), and the associated pumps, piping, and valves. The UHS is also considered part of the SSW System (LCO 3.7.1, "[Standby Service Water (SSW)] System and [Ultimate Heat Sink (UHS)]").
Cooling water is pumped from a UHS water source by the HPCS service water pump to the essential components through the HPCS service water supply header. After removing heat from the components, the water is discharged to the cooling towers, where the heat is rejected through direct contact with ambient air.
The HPCS SWS specifically supplies cooling water to the Division 3 HPCS diesel generator jacket water coolers and HPCS pump room cooler. The HPCS SWS pump is sized such that it will provide adequate cooling water to the equipment required for safe shutdown. Following a Design Basis Accident or transient, the HPCS SWS will operate automatically and without operator action as described in the FSAR, Section [9.2.1] (Ref. 1).
APPLICABLE          The ability of the HPCS SWS to provide adequate cooling to the HPCS SAFETY              System is an implicit assumption for safety analyses evaluated in the ANALYSES            FSAR, Chapters [6] and [15] (Refs. 2 and 3, respectively).
The HPCS SWS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                  The HPCS SWS is required to be OPERABLE to ensure that the HPCS System will operate as required. An OPERABLE HPCS SWS consists of an OPERABLE UHS; an OPERABLE pump; and an OPERABLE UHS flow path, capable of taking suction from the associated SSW source and transferring the water to the appropriate unit equipment.
The OPERABILITY of the UHS is specified in LCO 3.7.1. However, the OPERABILITY of the basin cooling tower fans does not affect the OPERABILITY of the HPCS SWS, due to the limited heat removal during its operation.
General Electric BWR/6 STS              B 3.7.2-1                                      Rev. 5.0
 
HPCS SWS B 3.7.2 BASES APPLICABILITY      In MODES 1, 2, and 3, the HPCS SWS is required to be OPERABLE to support OPERABILITY of the HPCS System since it is required to be OPERABLE in these MODES.
Although the LCO for the HPCS SWS System is not applicable in MODES 4 and 5, the capability of the HPCS SWS System to perform its necessary related support functions may be required for OPERABILITY of supported systems.
ACTIONS            A.1 When the HPCS SWS is inoperable, the capability of the HPCS System to perform its intended function cannot be ensured. Therefore, if the HPCS SWS is inoperable, the HPCS System must be declared inoperable immediately and Condition C of LCO 3.5.1, "ECCS -
Operating," entered.
SURVEILLANCE        SR 3.7.2.1 REQUIREMENTS This SR ensures that adequate cooling can be maintained. With the UHS water source below the minimum level, the HPCS SWS must be declared inoperable. [ The 24 hour Frequency is based on operating experience related to trending of the parameter variations during the applicable MODES.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.7.2.2 Verifying the correct alignment for each manual, power operated, and automatic valve in the HPCS service water flow path provides assurance that the proper flow paths will exist for HPCS service water 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 correct position prior to locking, sealing, or securing.
General Electric BWR/6 STS                B 3.7.2-2                                                      Rev. 5.0
 
HPCS SWS B 3.7.2 BASES SURVEILLANCE REQUIREMENTS (continued)
A valve is also allowed to be in the nonaccident position and yet considered in the correct position, provided it can be automatically realigned to its accident position within the required time. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.
This SR is modified by a Note indicating that isolation of the [HPCS SWS]
System to components or systems may render those components or systems inoperable, but does not affect the OPERABILITY of the [HPCS SWS] System. As such, when all [HPCS SWS] pumps, valves, and piping are OPERABLE, but a branch connection off the main header is isolated, the [HPCS SWS] System is still OPERABLE.
[ The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
SR 3.7.2.3 This SR verifies that the automatic valves of the HPCS SWS will automatically switch to the safety or emergency position to provide cooling water exclusively to the safety related equipment during an accident event. This is demonstrated by use of an actual or simulated initiation signal. The SR excludes automatic valves that are locked, sealed, or otherwise secured in the actuated position. The SR does not apply to valves that are locked, sealed, or otherwise secured in the actuated position since the affected valves were verified to be in the General Electric BWR/6 STS                  B 3.7.2-3                                                      Rev. 5.0
 
HPCS SWS B 3.7.2 BASES SURVEILLANCE REQUIREMENTS (continued) actuated position prior to being locked, sealed, or otherwise secured.
Placing an automatic valve in a locked, sealed, or otherwise secured position requires an assessment of the OPERABILITY of the system or any supported systems, including whether it is necessary for the valve to be repositioned to the non-actuated position to support the accident analysis. Restoration of an automatic valve to the non-actuated position requires verification that the SR has been met within its required Frequency. The LOGIC SYSTEM FUNCTIONAL TEST in SR 3.3.5.1.5 overlaps this SR to provide complete testing of the safety function.
[ Operating experience has shown that these components usually pass the SR when performed at the [18] month Frequency. Therefore, this Frequency is concluded to be acceptable from a reliability standpoint.
OR The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.
                    -----------------------------------REVIEWERS NOTE-----------------------------------
Plants controlling Surveillance Frequencies under a Surveillance Frequency Control Program should utilize the appropriate Frequency description, given above, and the appropriate choice of Frequency in the Surveillance Requirement.
                    ------------------------------------------------------------------------------------------------ ]
REFERENCES          1. FSAR, Section [9.2.1].
: 2. FSAR, Chapter [6].
: 3. FSAR, Chapter [15].
General Electric BWR/6 STS                  B 3.7.2-4                                                      Rev. 5.0
 
[CRFA] System B 3.7.3 B 3.7 PLANT SYSTEMS B 3.7.3 [Control Room Fresh Air (CRFA)] System BASES BACKGROUND          The [CRFA] System provides a protected environment from which occupants can control the unit following an uncontrolled release of radioactivity hazardous chemicals, or smoke.
The safety related function of the [CRFA] System used to control radiation exposure consists of two independent and redundant high efficiency air filtration subsystems for treatment of recirculated air or outside supply air and a control room envelope (CRE) boundary that limits the inleakage of unfiltered air. Each [CRFA] subsystem consists of a demister, an electric heater, a prefilter, a high efficiency particulate air (HEPA) filter, an activated charcoal adsorber section, a second HEPA filter, a fan, and the associated ductwork, valves or dampers, doors, barriers, and instrumentation. Demisters remove water droplets from the airstream.
Prefilters and HEPA filters remove particulate matter, which may be radioactive. The charcoal adsorbers provide a holdup period for gaseous iodine, allowing time for decay.
The CRE is the area within the confines of the CRE boundary that contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions. This area encompasses the control room, and may encompass other non-critical areas to which frequent personnel access or continuous occupancy is not necessary in the event of an accident. The CRE is protected for normal operation, natural events, and accident conditions. The CRE boundary is the combination of walls, floor, roof, ducting, doors, penetrations and equipment that physically form the CRE. The OPERABILITY of the CRE boundary must be maintained to ensure that the inleakage of unfiltered air into the CRE will not exceed the inleakage assumed in the licensing basis analysis of design basis accident (DBA) consequences to CRE occupants. The CRE and its boundary are defined in the Control Room Envelope Habitability Program.
In addition to the safety related standby emergency filtration function, parts of the [CRFA] System are operated to maintain the CRE environment during normal operation. Upon receipt of the initiation signal(s) (indicative of conditions that could result in radiation exposure to CRE occupants), the [CRFA] System automatically switches to the isolation mode of operation to minimize infiltration of contaminated air into the CRE. A system of dampers isolates the CRE, and CRE air flow is recirculated and processed through either of the two filter subsystems.
General Electric BWR/6 STS              B 3.7.3-1                                          Rev. 5.0
 
[CRFA] System B 3.7.3 BASES BACKGROUND (continued)
The [CRFA] System is designed to maintain a habitable environment in the CRE for a 30 day continuous occupancy after a DBA, without exceeding [5 rem whole body dose or its equivalent to any part of the body] [5 rem total effective dose equivalent (TEDE)]. [CRFA] System operation in maintaining the CRE habitability is discussed in the FSAR, Sections [6.5.1] and [9.4.1] (Refs. 1 and 2, respectively).
APPLICABLE          The ability of the [CRFA] System to maintain the habitability of the CRE is SAFETY              an explicit assumption for the safety analyses presented in the FSAR, ANALYSES            Chapters [6] and [15] (Refs. 3 and 4, respectively). The isolation mode of the [CRFA] System is assumed to operate following a DBA. The radiological doses to CRE occupants as a result of the various DBAs are summarized in Reference 4. No single active or passive failure will cause the loss of outside or recirculated air from the CRE.
The [CRFA] System provides protection from smoke and hazardous chemicals to the CRE occupants. The analysis of hazardous chemical releases demonstrates that the toxicity limits are not exceeded in the CRE following a hazardous chemical release (Ref. 5). The evaluation of a smoke challenge demonstrates that it will not result in the inability of the CRE occupants to control the reactor either from the control room or from the remote shutdown panels (Ref. 6).
The [CRFA] System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).
LCO                Two redundant subsystems of the [CRFA] System are required to be OPERABLE to ensure that at least one is available, if a single active failure disables the other subsystem. Total [CRFA] System failure, such as from a loss of both ventilation subsystems or from an inoperable CRE boundary, could result in exceeding a dose of [5 rem whole body or its equivalent to any part of the body] [5 rem TEDE] to the CRE occupants in the event of a DBA.
Each [CRFA] subsystem is considered OPERABLE when the individual components necessary to limit CRE occupant exposure are OPERABLE.
A subsystem 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.
General Electric BWR/6 STS              B 3.7.3-2                                        Rev. 5.0
 
[CRFA] System B 3.7.3 BASES LCO (continued)
In order for the [CRFA] subsystems to be considered OPERABLE, the CRE boundary must be maintained such that the CRE occupant dose from a large radioactive release does not exceed the calculated dose in the licensing basis consequence analyses for DBAs, and that CRE occupants are protected from hazardous chemicals and smoke.
The LCO is modified by a Note allowing the CRE boundary to be opened intermittently under administrative controls. This Note only applies to openings in the CRE boundary that can be rapidly restored to the design condition, such as doors, hatches, floor plugs, and access panels. 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 should be proceduralized and consist of stationing a dedicated individual at the opening who is in continuous communication with the operators in the CRE. This individual will have a method to rapidly close the opening and to restore the CRE boundary to a condition equivalent to the design condition when a need for CRE isolation is indicated.
APPLICABILITY      In MODES 1, 2, and 3, the [CRFA] System must be OPERABLE to ensure that the CRE will remain habitable during and following a DBA, since the DBA could lead to a fission product release.
In MODES 4 and 5, the probability and consequences of a DBA are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the [CRFA] System OPERABLE is not required in MODE 4 or 5, except during movement of [recently] irradiated fuel assemblies in the [primary or secondary containment]. [Due to radioactive decay, the CRFA System is only required to be OPERABLE during fuel handling involving handling recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous [X]
days).]
ACTIONS            A.1 With one [CRFA] su}}

Latest revision as of 20:01, 19 November 2024

NUREG-1434, Vol. 2, Rev. 5, Standard Technical Specifications, General Electric BWR/6 Plants: Bases
ML21271A596
Person / Time
Issue date: 09/30/2021
From: Michelle Honcharik
Office of Nuclear Reactor Regulation
To:
Malone Tina
References
NUREG-1434 V02 R05
Download: ML21271A596 (906)
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