NL-15-169, Browns Ferry, Units 1, 2 and 3 - Proposed Technical Specification Bases Markups, Attachment 4

Browns Ferry, Units 1, 2 and 3 - Proposed Technical Specification Bases Markups, Attachment 4

ML15282A179
Person / Time
Site:	Browns Ferry
Issue date:	09/21/2015
From:	Tennessee Valley Authority
To:	Office of Nuclear Reactor Regulation
Shared Package
ML15282A154	List: CNL-15-169, Electric Power Research Institute Affidavit ML15282A152 ML15282A166 ML15282A167 ML15282A168 ML15282A169 ML15282A178 ML15282A179 ML15282A180 ML15282A181 ML15282A182 ML15282A184 ML15282A185 ML15282A187 ML15282A188 ML15282A189 ML15282A190 ML15282A191 ML15282A192 ML15282A193 ML15282A194 ML15282A221 ML15282A222 ML15282A223 ML15282A224 ML15282A225 ML15282A235 ML15282A236 ML15282A237 ML15282A238 ML15282A239 ML15282A240 ML15282A241 ML15282A258 ML15282A259 ML15282A260 ML15282A261 NL-15-169, ANP-2637, Revision 6, Boiling Water Reactor Licensing Methodology Compendium. NL-15-169, ANP-2860NP Revision 2, Supplement 2, Browns Ferry Unit 1 - Summary of Responses to Request for Additional Information, Extension for Use of Atrium 10XM Fuel for Extended Power Uprate. NL-15-169, ANP-3342NP, Revision 1, Browns Ferry EPU (120% OLTP) Equilibrium Fuel Cycle Design. NL-15-169, ANP-3343NP, Revision 0, Nuclear Fuel Design Report Browns Ferry EPU (120% OLTP) Equilibrium Cycle Atrium 10XM Fuel. NL-15-169, ANP-3372NP, Revision 1, Browns Ferry Unit 3 Cycle 19 EPU (120% OLTP) LAR Reference Fuel Cycle Design. NL-15-169, ANP-3377NP, Browns Ferry Units 1, 2 and 3 LOCA Break Spectrum Analysis Atrium 10XM Fuel (Epu). NL-15-169, ANP-3378NP, Browns Ferry Units 1, 2 and 3, LOCA-ECCS Analysis MAPLHGR Limits for Atrium 10XM Fuel (Epu). NL-15-169, ANP-3384NP, Revision 3, Browns Ferry Units 1, 2 and 3, LOCA-ECCS Analysis MAPLHGR Limits for ATRIUM-10 Fuel (Epu). NL-15-169, ANP-3385NP, Revision 1, Mechanical Design Report for Browns Ferry Units 1, 2, and 3 Extended Power Uprate (EPU) ATRIUM-10 Fuel Assemblies, Licensing Report. NL-15-169, ANP-3386NP, Revision 1, Mechanical Design Report for Browns Ferry Units 1, 2 and 3 Extended Power Uprate (EPU) Atrium 10XM Fuel Assemblies, Licensing Report. NL-15-169, ANP-3388NP, Revision 0, Fuel Rod Thermal-Mechanical Evaluation for Browns Ferry Extended Power Uprate, Licensing Report. NL-15-169, ANP-3403NP, Revision 2, Fuel Uprate Safety Analysis Report for Browns Ferry Units 1, 2, and 3, Attachment 9 NL-15-169, ANP-3404NP, Revision 2, Browns Ferry Unit 3 Cycle 19 Representative Reload Analysis at Extended Power Uprate ... further results
References
CNL-15-169
Download: ML15282A179 (158)

Text

Reactor Core SLs B 2.1.1 (continued)

BFN-UNIT 1 B 2.0-3 Revision 0 , 68 October 18, 2012 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity SAFETY ANALYSES (continued) The SPCB critical power correlation is used for both AREVA and coresident fuel and is valid at pressure >

700 psia, and bundle mass fluxes >

0.1 x 10 6 lbm/hr-ft 2 (>12,000 lb m/hr, i.e., >

10% core flow, on a per bundle basis) for ATRIUM-10 and GE14 fuel types. The thermal margin monitoring at 25% power and higher, the hot channel flow rate will be >28,000 lb m/hr (core flow not less than natural circulat ion, i.e., ~25%-30% core flow for 25% power); therefore the f uel cladding integrity SL is conservative relative to the app licable range of the SPCB critical power correlation. For operation at low pressures or low flows, another basis is used, as follows:

The static head across the fuel bundles due only to elevation effects from liquid only in the channel, core bypass region, and

annulus at zero power, zero flow is approximately 4.5 psi. At all

operating conditions, this pressure differential is maintained by

the bypass region of the core and the annulus region of the

vessel. The elevation head provided by the annulus produces

natural circulation flow conditions which have balancing

pressure head and loss terms inside the core shroud. This

natural circulation principle maintains a core plenum to plenum

pressure drop of about 4.5 to 5 psid along the natural circulation

flow line of the P/F operating map.

In the range of power levels

of interest, approaching 25% of rated power below which

thermal margin monitoring is not required, the pressure drop

and density head terms tradeoff for power changes such that

natural circulation flow is nearly independent of reactor power.

This characteristic is represented by the nearly vertical portion of the natural circulation line on the P/F operating map.

Analysis has shown that the hot channel flow rate is >28,000

lb m/hr (>0.23 x 10 6 lb m/hr-ft 2) in the region of operation with power ~25% and core pressure drop of about 4.5 to 5 psid. Full

scale ATLAS test data taken at pressures from 14.7 psia to 800 psia indicate that the fuel assembly critical power at 28,000

lb m/hr is approximately 3 MW

t. With the design peaking factors, this corresponds to a core thermal power of more than 50%.

Reactor Core SLs B 2.1.1 (continued)

BFN-UNIT 1 B 2.0-4 Revision 0 , 68 October 18, 2012 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity (continued)

SAFETY ANALYSES Thus operation up to 25% of rated power with normal

natural circulation available is conservatively acceptable

even if reactor pressure is equal to or below 800 psia. If reactor power is significantly less than 25% of rated (e.g.,

below 10% of rated), the core flow and the channel flow

supported by the available driving head may be less than

28,000 lb m/hr (along the lower portion of the natural circulation flow characteristic on the P/F map). However, the critical power that can be supported by the core and hot

channel flow with normal natural circulation paths available

remains well above the actual power conditions. The

inherent characteristics of BW R natural circulation make power and core flow follow the natural circulation line as

long as normal water level is maintained.

Thus, operation with core thermal power below 25% of rated

without thermal margin surveillance is conservatively acceptable

even for reactor operations at natural circulation. Adequate fuel

thermal margins are also maintained without further surveillance

for the low power conditions that would be present if core

natural circulation is below 10% of rated flow.

SLC System B 3.1.7 (continued)

BFN-UNIT 1 B 3.1-53 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCE SR 3.1.7.4 and SR 3.1.7.6 REQUIREMENTS (continued) SR 3.1.7.4 requires an ex amination of the sodium pentaborate solution by using chemical analysis to ensure that the proper

concentration of boron exists in the storage tank. The

concentration is dependent upon the volume of water and

quantity of boron in the storage tank. SR 3.1.7.6 requires verification that the SLC system conditions satisfy the following

equation: ( C )( Q )( E ) ( 13 WT % )( 86 GPM )( 19.8 ATOM % ) > = 1.0 C = sodium pentaborate solution weight percent

concentration

Q = SLC system pump flow rate in gpm

E = Boron-10 atom percent enrichment in the sodium pentaborate solution To meet 10 CFR 50.62, the SLC System must have a minimum flow capacity and boron content equivalent in control capacity to

86 gpm of 13 weight percent natural sodium pentaborate

solution. The atom percentage of natural B-10 is 19.8%. This equivalency requirement is met when the equation given above

is satisfied. The equation can be satisfied by adjusting the

solution concentration, pump flow rate or Boron-10 enrichment.

If the results of the equation are < 1, the SLC System is no

longer capable of shutting down the reactor with the margin

described in Reference 2. Ho wever, the quantity of stored boron includes an additional margin (25%) beyond the amount

needed to shut down the reactor to allow for possible imperfect

mixing of the chemical solution in the reactor water, leakage, and the volume in other piping connected to the reactor system.

The sodium pentaborate solution (SPB) concentration is allowed to be > 9.2 weight percent pr ovided the concentration and temperature of the sodium pentaborate solution are verified SLC System B 3.1.7 BFN-UNIT 1 B 3.1-57 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCE SR 3.1.7.11 REQUIREMENTS (continued) SR 3.1.7.11 verifies that 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 Flowpath provides assurance 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 also

does not apply to valves that ar e locked, sealed, or otherwise secured in position since they are verified to be in the correct

position prior to locking, sealing or securing. This verification of valve alignment 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 is

based on engineering judgment and is consistent with the procedural controls governing valve operation that ensures

correct valve positions. REFERENCES 1.10 CFR 50.62.2.FSAR, Section 3.8.4.3.NRC No.93-102, "Final Policy Statement on Technical Specification Improvem ents," July 23, 1993.4.FSAR, Section 14.6.

APLHGR B 3.2.1 (continued)

BFN-UNIT 1 B 3.2-3a Revision 40 , 68 Amendment No. 236 October 18, 2012 BASES LCO The APLHGR limits specified in the COLR are the result of the fuel design, DBA, and transient analyses. With only one recirculation loop in operati on, in conformance with the requirements of LCO 3.4.1, "Rec irculation Loops Operating," the limit is determined by multiply ing the exposure dependent limit by an APLHGR correction factor (Ref. 5 and Ref. 10). Cycle

specific APLHGR correction factors for single recirculation loop

operation are documented in t he COLR. APLHGR limits are selected such that no power or flow dependent corrections are required. Additional APLHGR oper ating limit adjustments may be provided in the COLR supporting other analyzed equipment out-of-service conditions. APPLICABILITY The APLHGR limits are pr imarily 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 scram function provi des prompt scram 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 is APLHGR B 3.2.1 (continued)

BFN-UNIT 1 B 3.2-4 Revision 0, 40 October 26, 2006 BASES APPLICABILITY operating with s ubstantial margin to the APLHGR limits; thus, (continued) 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 should be taken to

restore the APLHGR(s) to within t he required limits such that the plant operates within analyzed conditions and within design

limits of the fuel rods. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is sufficient

to restore the APLHGR(s) to wit hin 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 sp ecified condition in which the LCO does not apply. To achieve this status, THERMAL

POWER must be reduced to < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The

allowed Completion Time is reasonable, based on operating

experience, to reduce THERMAL POWER to < 25% RTP in an

orderly manner and without c hallenging plant systems.

SURVEILLANCE SR 3.2.1.1 REQUIREMENTS APLHGRs are required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. They are co mpared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal APLHGR B 3.2.1 (continued)

BFN-UNIT 1 B 3.2-5 Revision 0, 40, 68 October 18, 2012 BASES SURVEILLANCE SR 3.2.1.1 (continued)

REQUIREMENTS operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

REFERENCES 1. NEDE-24011-P-A, Rev.

16, "General Electric Standard Application for Reactor Fuel," October 2007.

2. FSAR, Chapter 3.

3. FSAR, Chapter 14.

4. FSAR, Appendix N.

5. NEDC-32484P, "Browns Ferry Nuclear Plant Units 1, 2, and 3, SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis," Revision 2, December 1997.

6. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

7. NEDC-32433P, "Maximum Extended Load Line Limit and ARTS Improvement Program Analyses for Browns Ferry

Nuclear Plant Units 1, 2, and 3," April 1995.

8. NEDO-30130-A, "Steady State Nuclear Methods,"

May 1985.

9. NEDO-24154, "Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors," October 1978. 10. NEDO-24236, "Browns Ferry Nuclear Plant Units 1, 2, and 3, Single-Loop Operation," May 1981.

MCPR B 3.2.2 (continued)

BFN-UNIT 1 B 3.2-7 Revision 40 , 68 Amendment No. 236 October 18, 2012 BASES (continued)

APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the abnormal operational tr ansients to establish the operating limit MCPR are presented in Referenc es 2, 3, 4, 5, 8, 10, 11, 12, 13, 14, and 15. To ensure that the MCPR 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 added to the MCPR SL, the required operating limit MCPR is obtained.

The MCPR operating limits deriv ed from the transient analysis are dependent on the operating core flow and power to ensure adherence to fuel design limits dur ing the worst transient that

occurs with moderate frequency (Reference 8). Flow

dependent MCPR (MCPR f) limits are determined by steady state thermal hydraulic methods using the three dimensional BWR simulator code (Ref. 12) and the multichannel thermal hydraulics code (Ref. 13). The operating limit is dependent on the maximum core flow limiter se tting in the Recirculation Flow Control System.

Power dependent MCPR limits (MCPR p) are determined by the three-dimensional BWR simulator code (Ref. 12) and the one-dimensional transient codes (Refs. 14 and 15). Due to the sensitivity of the transient response to initial core flow levels at power levels below those at which the turbine control valve fast

closure scrams are bypassed, high and low flow MCPR p operating limits are provi ded for operating between 25

% RTP and the previously mentioned bypass power level.

The MCPR satisfies Criterion 2 of the NRC Policy Statement (Ref. 7).

MCPR B 3.2.2 (continued)

BFN-UNIT 1 B 3.2-8 Revision 0 , 40 , 68 October 18, 2012 BASES (continued)

LCO The MCPR operating limits specif ied in the COLR are the result of the Design Basis Accident (DBA) and transient analysis.

Additionally MCPR operating limits supporting analyzed equipment out-of-service conditions are provided in the COLR.

The operating limit MCPR is det ermined by the larger of the MCPR f and MCPR p limits. 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 minimum recirculation

pump speed and the moderator void ra tio is small. Surveillance

of thermal limits below 25% RTP is unnecessary due to the

large inherent margin that ensur es that the MCPR SL is not exceeded even if a limiting transient occurs. Statistical analyses indicate that the nominal value of the initial MCPR expected at 25% RTP is > 3.5. Studies of t he variation of limiting transient behavior have been performed over the range of power and flow

conditions. These studies 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 provides rapid scram initiation for any significant power increase transient, which effectively

eliminates any MCPR complianc e 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 MCPR B 3.2.2 (continued)

BFN-UNIT 1 B 3.2-9 Revision 0 , 40 , 68 October 18, 2012 BASES ACTIONS A.1 (continued) 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 operati ng within analyzed conditions.

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 D BA occurring simultaneously with the MCPR out of specification.

B.1 If the MCPR cannot be restored to within its required limits within the associated Completion Time, the plant must be

brought to a MODE or other sp ecified condition in which the LCO does not apply. To achieve this status, THERMAL

POWER must be reduced to < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The

allowed Completion Time is reasonable, based on operating

experience, to reduce THERMAL POWER to < 25% RTP in an

orderly manner and without c hallenging plant systems.

SURVEILLANCE SR 3.2.2.1 REQUIREMENTS The MCPR is required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. It is compared to the specified limits in the COLR to ensure that the r eactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal

operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

LHGR B 3.2.3 (continued)

BFN-UNIT 1 B 3.2-12a Revision 0 , 68 July 3, 2012 BASES (continued)

LCO Additional LHGR operating lim its adjustments may be provided (continued) the COLR to support analyzed equipment out-of-service operation.

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, t herefore, the Specification is only required when the reactor is operating at 25% RTP.

LHGR B 3.2.3 BFN-UNIT 1 B 3.2-13 Revision 0 BASES (continued)

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 s hould be taken to restore the LHGR(s) to within its required limits such that the plant is

operating within analyzed conditions. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion

Time is normally sufficient to re store 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 is reduced to

< 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. It is compared to the specified limits in the COLR to ensure that the r eactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of the slow changes in power distribution during normal operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels.

RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-5 Revision 0 BASES APPLICABLEThe trip setpoints are then determined accounting for the SAFETY ANALYSES,remaining instrument errors (e.g., drift). The trip setpoints

LCO, and derived in this manner provide adequate protection becauseAPPLICABILITYinstrumentation uncertainties, process effects, calibration (continued)tolerances, instrument drift, and severe environmental effects (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 or other specified conditions in the Table, which 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 are required in each

MODE to provide primary and diverse initiation signals.

The only MODES specified in Table 3.3.1.1-1 are MODES 1 (which encompasses 30% RTP) and 2, and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies. No RPS Function is required in MODES 3 and

4 since 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.

In MODE 5, 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, no RPS function

is 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.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-11 Revision 0, 40, 45 February 27, 2007 BASES APPLICABLEAverage Power Range Monitor SAFETY ANALYSES, LCO, and 2.a. Average Power Range Monitor Neutron Flux - High,APPLICABILITY(Setdown)

(continued)

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 AveragePower 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 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 since the potential for criticality exists. In MODE 1, the Average Power Range Monitor NeutronFlux - High Function provides protection against reactivity

transients and the RWM and rod block monitor protect against

control rod withdrawal error events.

RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-16a Revision 45 February 27, 2007 BASES APPLICABLE2.f. Oscillation Power Range Monitor (OPRM) Upscale SAFETY ANALYSES, LCO, and The OPRM Upscale Function provides compliance with GDC 10APPLICABILITYand GDC 12, thereby providing protection from exceeding the (continued)fuel MCPR safety limit (SL) due to anticipated thermal hydraulic power oscillations.

References 13, 14, and 15 describe three algorithms for detecting thermal hydraulic instability related neutron flux oscillations: the period based detection algorithm, the amplitude based algorithm, and the growth rate algorithm. All three are implemented in the OPRM Upscale Function, but the safety analysis takes credit only for the period based detection algorithm. The remaining algorithms provide defense in depth and additional protection against unanticipated oscillations.

OPRM Upscale Function OPERABILITY for Technical Specification purposes is based only on the period based detection algorithm.

The OPRM Upscale Function receives input signals from the local power range monitors (LPRMs) within the reactor core, which are combined into "cells" for evaluation of the OPRM algorithms.

The OPRM Upscale Function is required to be OPERABLE when the plant is in a region of power flow operation where anticipated events could lead to thermal hydraulic instability and related neutron flux oscillations. Within this region, the automatic trip is enabled when THERMAL POWER, as indicated by the APRM Simulated Thermal Power, is 25%RTP and reactor core flow, as indicated by recirculation drive flow is < 60% of rated flow, the operating region where actual thermal hydraulic oscillations may occur. Requiring the OPRM Upscale Function to be OPERABLE in MODE 1 provides consistency with operability requirements for other APRM functions and assures that the OPRM Upscale Function is OPERABLE whenever reactor power could increase into the region of concern without operator action.

RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-24 Revision 0 BASES APPLICABLE8. Turbine Stop Valve - Closure (continued)

SAFETY ANALYSES, LCO, andTurbine Stop Valve - Closure signals are initiated from positionAPPLICABILITYswitches located on each of the four TSVs. Two independent position switches are associated with each stop valve. One of

the two switches provides input to RPS trip system A; the other, to RPS trip system B. Thus, each RPS trip system receives an input from four Turbine Stop Valve - Closure channels, each

consisting of one position switch. The logic for the Turbine Stop Valve - Closure Function is such that three or more TSVs

must be closed to produce a scram. This Function must be enabled at THERMAL POWER 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine

bypass valves may affect this function.The Turbine Stop Valve - Closure 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 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 if any three TSVs should

close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is 30% RTP.This Function is not required when THERMAL POWER is< 30% 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.

RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-25 Revision 0 BASES APPLICABLE9. Turbine Control Valve Fast Closure, Trip Oil Pressure - LowSAFETY ANALYSES,(PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and APPLICABILITYFast closure of the TCVs results in the loss of a heat sink that (continued)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 7. 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 electrohydraulic control (EHC) fluid

pressure at each control valve. One pressure switch is

associated with each control valve, and the signal from each

switch is assigned to a separate RPS logic channel. This Function must be enabled at THERMAL POWER 30% RTP.This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this function.The Turbine Control Valve Fast Closure, Trip Oil Pressure -

Low Allowable Value is selected high enough to detect

imminent TCV fast closure.

RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-26 Revision 0, 41 November 09, 2006 BASES APPLICABLE9. Turbine Control Valve Fast Closure, Trip Oil Pressure - LowSAFETY ANALYSES,(PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and (continued)

APPLICABILITY 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 30% RTP. This Function is not required when THERMAL POWER is < 30% RTP, since theReactor Vessel Steam Dome Pressure - High and the Average Power Range Monitor Fixed Neutron Flux - High Functions are

adequate to maintain the necessary safety margins.

For this instrument function, the nominal trip setpoint including the as-left tolerances is defined as the LSSS. The acceptable as-found band is based on a statistical combination of possible measurable uncertainties (i.e., setting tolerance, drift,temperature effects, and measurement and test equipment).

During instrument calibrations, if the as-found setpoint is found to be conservative with respect to the Allowable Value, but outside its acceptable as-found band (tolerance range), as defined by its associated Surveillance Requirement procedure, then there shall be an initial determination to ensure confidence that the channel can perform as required before returning the channel to service in accordance with the Surveillance. The technician performing the Surveillance will evaluate the instrument's ability to maintain a stable setpoint within the as-left tolerance. The technician's evaluation will be reviewed by on shift personnel during the approval of the Surveillance data prior to returning the channel back to service at the completion of the Surveillance. This shall constitute the initial determination of operability. If a channel is found to exceed the channel's Allowable Value or cannot be reset within the RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-36 Revision 0, 40 October 26, 2006 BASES SURVEILLANCESR 3.3.1.1.2 REQUIREMENTS (continued)To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor

power calculated from a heat balance. 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 3.3.1.1.7.

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 within the last 7 days, in accordance with SR 3.0.2. A Note is provided which

allows an increase in THERMAL POWER above 25% if the

7 day Frequency is not met per SR 3.0.2. In this event, the SR

must be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 1B 3.3-43 Revision 0, 43 January 17, 2007 BASES SURVEILLANCESR 3.3.1.1.15 REQUIREMENTS (continued)This SR ensures that scrams initiated from the Turbine StopValve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions will not be inadvertently bypassed when THERMAL POWER is 30% RTP. Thisinvolves calibration of the bypass channels (PIS-1-81A,PIS-1-81B, PIS-1-91A, and PIS-1-91B). Adequate margins for

the instrument setpoint methodologies are incorporated into the

actual setpoint.

If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at 30% RTP, either due to open main turbine bypass valve(s) or other reasons), then the affectedTurbine Stop Valve - Closure 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 (Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low

Functions are enabled), this SR is met and the channel is

considered OPERABLE.The Frequency of 24 months is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 1B 3.3-43a Revision 45 February 27, 2007 BASES SURVEILLANCESR 3.3.1.1.17 REQUIREMENTS (continued)This SR ensures that scrams initiated from OPRM Upscale Function (Function 2.f) will not be inadvertently bypassed when THERMAL POWER, as indicated by the APRM Simulated Thermal Power, is 25% RTP and core flow, as indicated by recirculation drive flow, is < 60% rated core flow. This normally involves confirming the bypass setpoints. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint. The actual surveillance ensures that the OPRM Upscale Function is enabled (not bypassed) for the correct values of APRM Simulated Thermal Power and recirculation drive flow. Other surveillances ensure that the APRM Simulated Thermal Power and recirculation flow properly correlate with THERMAL POWER and core flow, respectively.

If any bypass setpoint is nonconservative (i.e., the OPRM Upscale Function is bypassed when APRM Simulated Thermal Power 25% RTP and recirculation drive flow < 60% rated), then the affected channel is considered inoperable for the OPRM Upscale Function. Alternatively, the bypass setpoint may be adjusted toplace the channel in a conservative condition (unbypass). If placed in the unbypassed condition, this SR is met and the channel is considered OPERABLE.

The frequency of 24 months is based on engineering judgment and reliability of the components.

Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 (cont inued)BFN-UNIT 1B 3.3-73 Revision 0 BASES (continued) APPLICABLEThe feedwater and main turbine high water level trip SAFETY ANALYSESinstrumentation is assumed to be capable of providing a turbine trip in the design basis transient analysis for a feedwater

controller failure, maximum demand event (Ref. 1). The reactor

vessel high water level trip indirectly initiates a reactor scram

from the main turbine trip (above 30% RTP) and trips the

feedwater pumps, thereby terminating the event. The reactor

scram mitigates the reduction in MCPR.

Feedwater and main turbine high water level trip instrumentation satisfies Criterion 3 of the NRC Policy

Statement (Ref. 3).

LCO The LCO requires two channels of the Reactor Vessel WaterLevel - High instrumentation per trip system to be OPERABLE

to ensure that no single instrument failure will prevent the

feedwater pump turbines and main turbine trip on a valid Reactor Vessel Water Level - High signal. Both channels in

either trip system are needed to provide trip signals in order for

the feedwater and main turbine trips to occur. Each channel

must have its setpoint set within the specified Allowable Value

of SR 3.3.2.2.3. The Allowable Value is set to ensure that the

thermal limits are not exceeded during the event. The actual

setpoint is calibrated to be consistent with the applicable

setpoint methodology assumptions. 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 successive CHANNEL

CALIBRATIONS. Operation with a trip setpoint less

conservative than the nominal trip setpoint, but within its

Allowable Value, is acceptable.

Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 1B 3.3-74 Revision 0 BASES LCO Trip setpoints are those predetermined values of output at (continued)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. A channel is inoperable if its actual trip

setpoint is not within its required Allowable Value. 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 environmental effects (for channels that must

function in harsh environments as defined by 10 CFR 50.49)

are accounted for. APPLICABILITYThe feedwater and main turbine high water level trip instrumentation is required to be OPERABLE at 25% RTP to ensure that the fuel cladding integrity Safety Limit and the

cladding 1% plastic strain limit are not violated during the

feedwater controller failure, maximum demand event. As

discussed in the Bases for LCO 3.2.1, "Average Planar Linear

Heat Generation Rate (APLHGR)," and LCO 3.2.2, "MINIMUM

CRITICAL POWER RATIO (MCPR)," sufficient margin to these

limits exists below 25% RTP; therefore, these requirements are

only necessary when operating at or above this power level.

Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 (cont inued)BFN-UNIT 1B 3.3-77 Revision 0 BASES ACTIONS B.1 (continued)

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is sufficient for the operator to

take corrective action, and takes into account the likelihood of

an event requiring actuation of feedwater and main turbine high

water level trip instrumentation occurring during this period. It

is also consistent with the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in

LCO 3.2.2 for Required Action A.1, since this instrumentation's

purpose is to preclude a MCPR violation.

C.1 With the required channels not restored to OPERABLE status or placed in trip, THERMAL POWER must be reduced to

< 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. As discussed in the Applicability

section of the Bases, operation below 25% RTP results in

sufficient margin to the required limits, and the feedwater and

main turbine high water level trip instrumentation is not required

to protect fuel integrity during the feedwater controller failure, maximum demand event. The allowed Completion Time of

4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is based on operating experience to reduce THERMAL

POWER to < 25% RTP from full power conditions in an orderly

manner and without challenging plant systems. SURVEILLANCEThe Surveillances are modified by a Note to indicate that REQUIREMENTSwhen a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated

Conditions and Required Actions may be delayed for up to

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains feedwater

and main turbine high water level trip capability. Upon

completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />

allowance, the channel must be returned to OPERABLE status EOC-RPT Instrumentation B 3.3.4.1 (cont inued)BFN-UNIT 1B 3.3-106 Revision 0 , 68 October 18, 2012 BASES BACKGROUNDEach EOC-RPT trip system is a two-out-of-two logic for each (continued)Function; thus, either two TSV - Closure or two TCV FastClosure, 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. APPLICABLEThe TSV - Closure and the TCV Fast Closure, Trip Oil SAFETY ANALYSES,Pressure - Low Functions are designed to trip the recirculation

LCO, and pumps in the event of a turbine trip or generator load rejectionAPPLICABILITYto mitigate the increase in neutron flux, heat flux, and reactor pressure, and to increase the margin to the MCPR SL, and LHGR limits. The analytical methods and assumptions used in evaluating the turbine trip and generator load rejection are

summarized in References 2, 3, and 4.

To mitigate pressurization transient effects, the EOC-RPT must trip the recirculation pumps after initiation of 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 a

scram alone, resulting in an increased margin to the MCPR SL, and LHGR limits. Alternatively, MCPR limits for an inoperableEOC-RPT, as specified in the COLR, are sufficient to prevent

violation of the MCPR Safety Limit, and fuel mechanical limits.The EOC-RPT function is automatically disabled when turbine

first stage pressure is < 30% RTP.EOC-RPT instrumentation satisfies Criterion 3 of the NRC Policy Statement (Ref. 6).

EOC-RPT Instrumentation B 3.3.4.1 (cont inued)BFN-UNIT 1B 3.3-109 Revision 0 , 68 October 18, 2012 BASES APPLICABLETurbine Stop Valve - Closure (continued)

SAFETY ANALYSES, LCO, and Closure of the TSVs is determined by measuring the position ofAPPLICABILITYeach valve. There are two separate position signals associated with each stop valve, the signal from each switch being assigned to a separate trip channel. The logic for the TSV -

Closure Function is such that two or more TSVs must be closed

to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine

bypass valves may affect this function. To consider this

function OPERABLE, bypass of the function must not occur when bypass valves are open. 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 Allowable Value is

selected to detect imminent TSV closure.

This protection is required, consistent with the safety analysis assumptions, whenever THERMAL POWER is 30% RTP.Below 30% RTP, 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 margin

to the MCPR SL, and LHGR limits.

EOC-RPT Instrumentation B 3.3.4.1 (cont inued)BFN-UNIT 1B 3.3-110 Revision 0 , 68 October 18, 2012 BASES APPLICABLETurbine Control Valve Fast Closure, Trip Oil Pressure - LowSAFETY ANALYSES,(PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and APPLICABILITYFast closure of the TCVs during a generator load rejection (continued)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, and LHGR limits are not exceeded during the worst case transient.

Fast closure of the TCVs is determined by measuring the electrohydraulic control fluid pressure at each control valve.

There is one pressure switch associated with each control

valve, and the signal from each switch 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 switch trips) to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 30% RTP.This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this function. To

consider this function OPERABLE, bypass of the function must

not occur when bypass valves are open. 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.

EOC-RPT Instrumentation B 3.3.4.1 (cont inued)BFN-UNIT 1B 3.3-111 Revision 0 BASES APPLICABLETurbine Control Valve Fast Closure, Trip Oil Pressure - LowSAFETY ANALYSES,(PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and (continued)

APPLICABILITY This protection is required consistent with the safety analysis whenever THERMAL POWER is 30% RTP. Below 30% RTP,the Reactor Vessel Steam Dome Pressure - High and theAPRM Fixed Neutron Flux - High Functions of the RPS are

adequate to maintain the necessary safety margins.

ACTIONS A Note has been provided to modify the ACTIONS related toEOC-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.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 1B 3.3-113 Revision 0 , 68 October 18, 2012 BASES ACTIONS B.1 and B.2 (continued)

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.

Alternately, Required Action B.2 requires the MCPR and LHGR limits for inoperable EOC-RPT, as specified in the COLR, to be applied. This also restores the margin to MCPR and LHGR limits assumed in the safety analysis.

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is sufficient time 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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />

Completion Time provided in LCO 3.2.2 for Required

Action A.1, since this instrumentation's purpose is to preclude a

MCPR or LHGR violation.

C.1 With any Required Action and associated Completion Time not

met, THERMAL POWER must be reduced to < 30% RTP within

4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is

reasonable, based on operating experience, to reduce

THERMAL POWER to < 30% RTP from full power conditions in

an orderly manner and without challenging plant systems.

EOC-RPT Instrumentation B 3.3.4.1 (cont inued)BFN-UNIT 1B 3.3-115 Revision 0, 43 January 17, 2007 BASES SURVEILLANCESR 3.3.4.1.2 REQUIREMENTS (continued)This SR ensures that an EOC-RPT initiated from the TSV - Closure and TCV Fast Closure, Trip Oil Pressure - Low

Functions will not be inadvertently bypassed when THERMAL POWER is 30% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint. If any

bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at 30% RTP, either due to open mainturbine bypass valves or other reasons), the affected TSV - Closure 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 with the channel considered OPERABLE.The Frequency of 24 months is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.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 a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint

analysis.

Jet Pumps B 3.4.2 BFN-UNIT 1 B 3.4-16 Revision 0 BASES SURVEILLANCE SR 3.4.2.1 (continued)

REQUIREMENTS

Note 2 allows this SR not to be performed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after THERMAL POWER exceeds 25% of 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. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is an acceptable time to establish conditions appropriate to perform this SR.

REFERENCES 1. FSAR, Section 14.6.3.

2. GE Service Information Letter No. 330, "Jet Pump Beam Cracks," June 9, 1980.

3. NUREG/CR-3052, "Closeout of IE Bulletin 80-07: BWR Jet Pump Assembly Failure," November 1984.

4. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

Primary Containment B 3.6.1.1 (continued)

BFN-UNIT 1 B 3.6-3 Revision 0, 49 April 30, 2007 BASES APPLICABLE The maximum allowable leakage rate for the primary SAFETY ANALYSES containment (L a) is 2.0% by weight of the containment air per (continued) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the design bas is LOCA maximum peak containment pressure (P a) of 48.5 psig (Ref. 1).

Primary containment satisfies Criterion 3 of the NRC Policy Statement (Ref. 6).

LCO Primary containment OPERABILITY is maintained by limiting leakage to 1.0 L a , except prior to the first startup after performing a required Primary Containment Leakage Rate Testing Program leakage test. At this time, applicable leakage limits must be met. Compliance with this LCO will ensure a

primary containment configur ation, including equipment hatches, that is structurally s ound and that will lim it leakage to those leakage rates assumed in the safety analyses.

Individual leakage rates specif ied for the prim ary containment air lock 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 primar y 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, prim ary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of

radioactive material from primary containment.

Primary Containment B 3.6.1.1 BFN-UNIT 1 B 3.6-6 Revision 0, 43 January 17, 2007 BASES SURVEILLANCE SR 3.6.1.1.2 (continued)

REQUIREMENTS

Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber and veri fying that the pressure in either the suppression chamber or the drywell does not change by more than 0.25 inch of wate r per minute over a 10 minute period. The leakage test is per formed every 24 months. The 24 month Frequency was developed considering it is prudent that this Surveillance be performed during a unit outage and

also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs.

REFERENCES 1. FSAR, Section 5.2.

2. FSAR, Section 14.6.

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

4. NEI 94-01, Revision O, "Industr y Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J." 5. ANSI/ANS-56.8-1994, "Ame rican National Standard for Containment System Leakage Testing Requirement."

6. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

Primary Containment Air Lock B 3.6.1.2 (continued)

BFN-UNIT 1 B 3.6-8 Revision 0, 49 April 30, 2007 BASES BACKGROUND the air lock to remain open for extended periods when frequent (continued) primary containment entry is necessary. Unde r some conditions allowed by this LCO, the prim ary containment may be accessed through the air lock, when the interlock mechanism has failed, by manually performing the interlock function.

The primary containment air lock forms 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 t hat assumed in the unit safety analysis.

APPLICABLE The DBA that postulates the maximum release of radioactive SAFETY ANALYSES material within primary containment is a LOCA. In the analysis of this accident, it is assum ed that primary containment is OPERABLE, such that releas e of fission products to the environment is controlled by the rate of primary containment leakage. The primar y containment is designed with a maximum allowable leakage rate (L a) of 2.0% by weight of the containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the calculat ed maximum peak containment pressure (P a) of 48.5 psig (Ref. 3). This allowable leakage rate forms the basis for the acceptanc e criteria imposed on the SRs associated with the air lock.

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.

The primary containment air lo ck satisfies Criterion 3 of the NRC Policy Statement (Ref. 4).

CAD System B 3.6.3.1 (continued)

BFN-UNIT 1 B 3.6-90 Revision 0 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.1 Containment Atmosphere Dilution (CAD) System BASES BACKGROUND The CAD Syst em functions to maintain combustible gas concentrations within the primary containment at or below the flammability limits following a postulated loss of coolant accident (LOCA) by diluting hydrogen and oxygen with nitrogen. To ensure that a combustible gas mixture does not occur, oxygen

concentration is kept < 5.0 volume percent (v/o), or hydrogen

concentration is kept < 4.0 v/o.

The CAD System is manually in itiated and consists of two independent, 100% capacity sub systems, each of which is capable of supplying nitrogen through separate piping systems to the drywell and suppression chamber of each unit. Each

subsystem includes a liquid nitrogen supply tank, ambient vaporizer, electric heater, and a manifold with branches to each primary containment (for Unit s 1, 2, and 3).

The nitrogen storage tanks each contain 2500 gal, which is adequate for 7 days of CAD subsystem operation.

The CAD System operates in conjunction with emergency

operating procedures that ar e used to reduce primary containment pressure peri odically during CAD System operation. This combination results in a feed and bleed approach to maintaining hydroge n and oxygen concentrations below combustible levels.

CAD System B 3.6.3.1 (continued)

BFN-UNIT 1 B 3.6-94 Revision 0, 34 September 07, 2005 BASES ACTIONS B.1and B.2 (continued)

The Completion Time of 7 days is a reasonable time to allow continued reactor operation with two CAD subsystems inoperable because the hydrogen control function is maintained (via the Primary Containment Inerting System) and because of the low probability of the occurr ence of a LOCA that would generate hydrogen in amounts c apable of exceeding the flammability limit.

C.1 If any Required Action cannot be met within the associated

Completion Time, the plant mu st be brought to a MODE in which the LCO does not apply. To achieve this status, the plant

must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience, to reac h MODE 3 from full power

conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.3.1.1 REQUIREMENTS Verifying that there is 2500 gal of liquid nitrogen supply in each nitrogen storage tank will ensure at least 7 days of post-LOCA CAD operation. This minimum volume of liquid

nitrogen allows sufficient time a fter an accident to replenish the nitrogen supply for long term inerti ng. This is verified every 31 days to ensure that the system is capable of performing its intended function when required. The 31 day Frequency is based on operating experience, which has shown 31 days to be an acceptable period to verify the liquid nitrogen supply and on

the availability of other hydrogen mitigating systems.

CAD System B 3.6.3.1 BFN-UNIT 1 B 3.6-96 Revision 0 BASES (continued)

REFERENCES 1. AEC Safety Guide 7, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident, March 10, 1971.

2. FSAR, Section 5.2.6.

3. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

RHRSW System B 3.7.1 (continued)

BFN-UNIT 1 B 3.7-3 Revision 0 , 44 , 73 January 3, 2013 BASES APPLICABLE With two and three units f ueled, a worse case single failure SAFETY ANALYSES could also include the loss of two RHRSW pumps caused by (continued) losing a 4 kV shutdown board since there are certain alignment configurations that allow two RHRSW pumps to be powered from the same 4 kV shutdown bo ard. As discussed in the FSAR, Section 14.6.3.3.2 (Ref.

4) for these analyses, manual initiation of the OPERABLE RHRSW subsystems and the associated RHR System is assumed to occur 10 minutes after a

DBA. The analyses assume that there are two RHRSW subsystems operating in each unit, with one RHRSW pump in each subsystem capable of producing 4000 gpm of flow. In this case, the maximum suppression chamber water temperature and pressure are 187.3°F (as re ported in Reference 6) and 48.5 psig, respectively, well below the design temperature of

281°F and maximum allowable pressure of 62 psig.

The RHRSW System satisfies Criterion 3 of the NRC Policy Statement (Ref 5).

LCO Four RHRSW subsystems are required to be OPERABLE to provide the required redundancy to ensure that the system

functions to remove post a ccident heat loads, assuming the worst case single active failure o ccurs coincident with the loss of offsite power. Additionally, since the RHRSW pumps are

shared between the three BFN unit s, the number of OPERABLE pumps required is also dependent on the number of units

fueled.

An RHRSW subsystem is considered OPERABLE when:

a. At least one RHRSW pump (i.e., one required RHRSW pump) is OPERABLE; and b. An OPERABLE flow path is capable of taking suction from the intake structure and tr ansferring the water to the associated RHR heat exchanger at the assumed flow rate.

RHRSW System B 3.7.1 BFN-UNIT 1 B 3.7-10 Revision 0 BASES (continued)

REFERENCES 1. FSAR, Section 10.9.

2. FSAR, Chapter 5.

3. FSAR, Chapter 14.

4. FSAR, Section 14.6.3.3.2.

5. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

6. GE-NE-B13-01755-2, Revision 1, February 1996.

Main Turbine Bypass System B 3.7.5 (continued)

BFN-UNIT 1 B 3.7-32 Revision 0 B 3.7 PLANT SYSTEMS B 3.7.5 Main Turbine Bypass System BASES BACKGROUND The Main Turbine Bypass S ystem is designed to control steam pressure when reactor steam generation exceeds turbine

requirements during unit start up, sudden load reduction, and cooldown. It allows excess steam flow from the reactor to the

condenser without going through t he turbine. The bypass capacity of the system is 25%

of the Nuclear Steam Supply System rated steam flow. Sudd en load reductions within the capacity of the steam bypa ss can be accommodated without reactor scram. The Main Turbi ne Bypass System consists of nine valves connected to the ma in steam lines between the main steam isolation valves and the turbine stop valve bypass valve chest. Each of these nine valves is operated by hydraulic cylinders. The bypass valves are controlled by the pressure regulation function of the Pressure Regulator and Turbine Generator Control System, as discussed in the FSAR, Section 7.11.3.3 (Ref. 1).

The bypass valves are normally

closed, and the pressure regulator controls the turbine control valves that direct all steam flow to the turbine. If the speed governor or the load limiter restricts steam flow to the turbine, the pressure regulator controls the system pressure by opening the bypass valves. When the bypass valves open, the steam flows from the bypass chest, th rough connecting piping, to the pressure breakdown assemblies, w here a series of orifices are used to further reduce the steam pressure before the steam enters the condenser.

Main Turbine Bypass System B 3.7.5 (continued)

BFN-UNIT 1 B 3.7-34 Revision 0 , 68 October 18, 2012 BASES (continued)

APPLICABILITY The Main Turbine Bypass System is required to be OPERABLE at 25% RTP to ensure that the f uel cladding integrity Safety Limit is not violated during abnorma l operational transients. As

discussed in the Bases for LCO 3.2.1 and LCO 3.2.2, sufficient

margin to these limits exists at < 25% RTP. T herefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A.1

If the Main Turbine Bypass Syst em is inoperable (one or more bypass valves inoperable), or the APLHGR, MCPR, and LHGR limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are not ap plied, the assumptions of the design basis transient analysis may not be met. Under such circumstances, prompt action should be taken to restore the

Main Turbine Bypass System to OPERABLE status or adjust the APLHGR, MCPR, and LHGR limits accordingly. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is reasonable, bas ed on the time to complete the Required Action and the low probability of an event occurring during this period requiring the Main Turbine Bypass

System.

B.1 If the Main Turbine Bypass S ystem cannot be restored to OPERABLE status or the APLHG R, MCPR, and LHGR limits for an inoperable Main Turbine Bypass System are not applied, THERMAL POWER must be reduced to < 25% RTP. As

discussed in the Applicability section, operation at < 25% RTP

results in sufficient margin to the required limits, and the Main

Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity SAFETY ANALYSES (continued)

Critical power correlations are valid over a wide range of conditions per References 2 and 5, extending to expected conditions below 25% THERMAL POWER. For core thermal power levels at, or above 25% rated, the hot channel flow rate is expected to be >28,000 lbm/hr, (core flow not less than natural circulation i.e., ~25%

-30 % core flow for 25% power); therefore, the fuel cladding integrity SL is conservative relative to the applicable range of the critical power correlations. For operation at low pressure/flow conditions, consistent with the low power region of the Power/Flow operating map, another basis is used as follows:

The static head across the fuel bundles is due to elevation effects from water solid channel, core bypass, and annulus regions, is approximately 4.5 psid. The pressure differential is maintained by the water solid bypass region of the core, along with the annulus region of the vessel. Elevation head provided by the bypass and annulus regions produces natural circulation flow conditions balancing pressure head with loss terms inside the core shroud.

Natural circulation principles maintain a core plenum to plenum pressure drop of approximately 4.5 to 5 psid along the natural circulation flow line of the Power/Flow operating map. When power levels approach 25% rated, pressure drop and density head terms are closely balanced as power changes, such that natural circulation flow is nearly independent of reactor power.

The flow characteristic is represented by the nearly vertical portion of the natural circulation line on the Power/Flow operating map. For a core pressure drop of approximately 4.5 to 5 psid, the hot channel flow rate is expected to be >28,000 lbm/hr in the region of operation when core power is < 25% with a corresponding core pressure drop of about 4.5 to 5 psid.

(continued)

BFN-UNIT 2 B 2.0-3 Revision 0 , 31 , 61 Amendment 313 February 26, 2015

Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity (continued)

SAFETY ANALYSES For example, Reference 5 test data, taken at low pressures and flow rates, indicate assembly critical power in excess of 4 MWt, for flow rates indicative of natural circulation conditions. At 25% rated power, assembly average power is < 1.2 MWt. When considering design peaking factors, hot channel power could be expected to be on the order of 2 MWt. Consequently, operation up to 25% rated core power, with normal natural circulation available, is conservative even if reactor pressure is less than the lower pressure limit of the critical power correlation.

When reactor power is significantly less than 25% of rated (e.g., below 10% of rated), hot channel flow supported by the available driving head may fall below 28,000 lbm/hr (along the lower portion of the natural circulation flow characteristic on the Power/Flow map). However, the critical power supported by the flow, remains above actual hot channel power conditions. The inherent characteristics of BWR natural circulation make core power/flow follow the natural circulation line as long as normal annulus water level is maintained.

Operation below 25% rated core thermal power is conservatively acceptable, even for reactor operations at natural circulation. Adequate fuel thermal margins are maintained for low power conditions present during core natural circulation, even though the flow may be less than the critical power correlation applicability range.

(continued)

BFN-UNIT 2 B 2.0-4 Revision 0 , 31 , 61 Amendment 313 February 26, 2015

SLC System B 3.1.7 (cont inued)BFN-UNIT 2B 3.1-48 Revision 0 , 29 January 25, 2005 BASES BACKGROUNDThe worst case sodium pentaborate solution concentration (continued)required to shutdown the reactor with sufficient margin to account for 0.05 k/k and Xenon poisoning effects is 9.2 weight percent. This corresponds to a 40 F saturation temperature.

The worst case SLCS equipment area temperature is not predicted to fall below 50 F. This provides a 10 F thermal margin to unwanted precipitation of the sodium pentaborate.

Tank heating components provide backup assurance that the

sodium pentaborate solution temperature will never fall below 50 F but are not required for TS operability considerations. APPLICABLEThe SLC System is manually initiated from the main controlSAFETY ANALYSESroom, as directed by the emergency operating instructions, if the operator believes the reactor cannot be shut down, or kept

shut down, with the control rods. The SLC System is used in

the event that enough control rods cannot be inserted to

accomplish shutdown and cooldown in the normal manner. The

SLC System injects borated water into the reactor core to add

negative reactivity to compensate for all of the various reactivity

effects that could occur during plant operations. To meet this

objective, it is necessary to inject a quantity of boron, which

produces a concentration of 660 ppm of natural boron, in the reactor coolant at 70 F. To allow for imperfect mixing, leakage and the volume in other piping connected to the reactor system, an amount of boron equal to 25% of the amount cited above is

added (Ref. 2). This volume versus concentration limit and 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 entire 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.

SLC System B 3.1.7 (cont inued)BFN-UNIT 2B 3.1-52 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCESR 3.1.7.1 (continued)

REQUIREMENTS pentaborate solution concentration requirements ( 9.2% by weight) and the required quantity of Boron-10 ( 186 lbs)establish the tank volume requirement. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency

is based on operating experience that has shown there are

relatively slow variations in the solution volume.SR 3.1.7.2SR 3.1.7.2 verifies the continuity of the explosive charges in the injection valves to ensure that proper operation will occur if

required. An automatic continuity monitor may be used to

continuously satisfy this requirement. 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 and has demonstrated the reliability of the

explosive charge continuity.SR 3.1.7.3 SR 3.1.7.3 requires an examination of sodium pentaborate solution by using chemical analysis to ensure that the proper concentration of boron exists in the storage tank for post-LOCAsuppression pool pH control. This parameter is used as inputto determine the volume requirements for SR 3.1.7.1. The concentration is dependent upon the volume of water and quantity of boron in the storage tank.

SR 3.1.7.3 must be performed every 31 days or within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of when boron or water is added to the storage tank solution to determine that the boron solution concentration is within the specified limits. The 31 day Frequency of this Surveillance is appropriate because of the relatively slow variation of boron concentration between surveillances.

SLC System B 3.1.7 (cont inued)BFN-UNIT 2B 3.1-53 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCESR 3.1.7.4 and SR 3.1.7.6 REQUIREMENTS (continued)SR 3.1.7.4 requires an examination of the sodium pentaborate solution by using chemical analysis to ensure that the proper

concentration of boron exists in the storage tank. The

concentration is dependent upon the volume of water and

quantity of boron in the storage tank. SR 3.1.7.6 requires verification that the SLC system conditions satisfy the following

equation:( C )( Q )( E ) ( 13 WT % )( 86 GPM )( 19.8 ATOM % ) > = 1.0 C = sodium pentaborate solution weight percent

concentration

Q = SLC system pump flow rate in gpm

E = Boron-10 atom percent enrichment in the sodium

pentaborate solutionTo meet 10 CFR 50.62, the SLC System must have a minimum flow capacity and boron content equivalent in control capacity

to 86 gpm of 13 weight percent natural sodium pentaborate

solution. The atom percentage of natural B-10 is 19.8%. This

equivalency requirement is met when the equation given above

is satisfied. The equation can be satisfied by adjusting the

solution concentration, pump flow rate or Boron-10 enrichment.

If the results of the equation are < 1, the SLC System is no

longer capable of shutting down the reactor with the margin

described in Reference 2. However, the quantity of stored

boron includes an additional margin (25%) beyond the amount

needed to shut down the reactor to allow for possible imperfect

mixing of the chemical solution in the reactor water, leakage, and the volume in other piping connected to the reactor system.

The sodium pentaborate solution (SPB) concentration is allowed to be > 9.2 weight percent provided the concentration

and temperature of the sodium pentaborate solution are verified SLC System B 3.1.7 BFN-UNIT 2B 3.1-57 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCESR 3.1.7.11 REQUIREMENTS (continued)SR 3.1.7.11 verifies that 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 Flowpath

provides assurance 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 also

does not apply to valves that are locked, sealed, or otherwise

secured in position since they are verified to be in the correct

position prior to locking, sealing or securing. This verification of

valve alignment 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 is

based on engineering judgment and is consistent with the

procedural controls governing valve operation that ensures

correct valve positions. REFERENCES1.10 CFR 50.62.2.FSAR, Section 3.8.4.3. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.4. FSAR, Section 14.6.

APLHGR B 3.2.1 (continued)

BFN-UNIT 2B 3.2-3b Revision 31 , 61 December 7, 2010 BASES (continued) APPLICABILITYAPLHGR limits are primarily derived from fuel design evaluations and LOCA and transient analyses assumed to occur at high power levels. Design calculations 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 scram function provides prompt scram 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 is operating with substantial margin to the APLHGR limits; thus, this LCO is not required.

APLHGR B 3.2.1 (continued)

BFN-UNIT 2B 3.2-4 Revision 0 BASES (continued)

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 should be taken to

restore the APLHGR(s) to within the required limits such that

the plant operates within analyzed conditions and within design

limits of the fuel rods. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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. SURVEILLANCESR 3.2.1.1 REQUIREMENTS APLHGRs are required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is

based on both engineering judgment and recognition of the

slowness of changes in power distribution during normal

operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

MCPR B 3.2.2 (continued)

BFN-UNIT 2B 3.2-7 Revision 31 , 61 Amendment No. 256 December 7, 2010 BASES APPLICABLEevaluated are loss of flow, increase in pressure and power, SAFETY ANALYSESpositive reactivity insertion, and coolant temperature decrease. (continued)The limiting transient yields the largest change in CPR (CPR).When the largest CPR is added to the MCPR SL, the required operating limit MCPR is obtained.

The MCPR operating limits derived from the transient analysis are dependent on the operating core flow and power to ensure adherence to fuel design limits during the worst transient that

occurs with moderate frequency. Flow dependent MCPR (MCPR f) limits are determined by steady-state thermal hydraulic methods using the three-dimensional BWR simulator code (Reference 12) and the multichannel thermal hydraulic code (Reference 13). The operating limit is dependent on the

maximum core flow limiter setting in the Recirculation Flow

Control System.

Power-dependent MCPR limits (MCPR p) are determined by the three-dimensional BWR simulator code (Ref. 12) and the one-dimensional transient codes (Refs. 14 and 15). 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 scrams are

bypassed, high and low flow MCPR p operating limits are provided for operating between 25% RTP and the previously

mentioned bypass power level.

The MCPR satisfies Criterion 2 of the NRC Policy Statement(Ref. 7).

MCPR B 3.2.2 (continued)

BFN-UNIT 2B 3.2-8 Revision 0, 31 April 6, 2005 BASES (continued)

LCO The MCPR operating limits specified in the COLR are the result of the Design Basis Accident (DBA) and transient analysis.

Additional MCPR operating limits may be provided in the COLR to support analyzed equipment out-of-service operation. The operating limit MCPR is determined by the larger of the MCPR f and MCPR p limits. APPLICABILITYThe 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 minimum

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 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 range

of power and flow conditions. These studies 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 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.

MCPR B 3.2.2 (continued)

BFN-UNIT 2B 3.2-9 Revision 0 BASES (continued)

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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 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 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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.

MCPR B 3.2.2 (continued)

BFN-UNIT 2B 3.2-10 Revision 0, 31 April 6, 2005 BASES (continued) SURVEILLANCESR 3.2.2.1 REQUIREMENTS The MCPR is required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is

based on both engineering judgment and recognition of the

slowness of changes in power distribution during normal

operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.SR 3.2.2.2 Because the transient analysis takes credit for conservatism in the scram speed performance, it must be demonstrated that the

specific scram speed distribution is consistent with that used in the transient analysis. SR 3.2.2.2 determines the actual scram speed distribution and compares it with the assumed distribution. The MCPR operating limit is determined based either on the applicable limit associated with scram times of LCO 3.1.4, "Control Rod Scram Times," or the nominal scram times. The scram speed-dependent MCPR limits are contained in the COLR. This determination must be performed within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after each set of control rod scram time tests required bySR 3.1.4.1 and SR 3.1.4.2 because the effective scram speed distribution may change during the cycle. The 72-hour Completion Time is acceptable due to the relatively minor changes in the actual control rod scram speed distribution expected during the fuel cycle.

LHGR B 3.2.3 (continued)

BFN-UNIT 2B 3.2-13a Revision 31 , 61 December 7, 2010 BASES (continued)

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. Additional LHGR

operating limits adjustments may be provided in the COLR to

support analyzed equipment out-of-service operation.

Additional LHGR operating limits adjustments may be provided in the COLR to support analyzed equipment out-of-service operation. APPLICABILITYThe 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.

LHGR B 3.2.3 (continued)

BFN-UNIT 2B 3.2-14 Revision 0 BASES (continued)

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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 is reduced to < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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.

LHGR B 3.2.3 BFN-UNIT 2B 3.2-15 Revision 0 BASES (continued) SURVEILLANCESR 3.2.3.1 REQUIREMENTS The LHGR is required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is

based on both engineering judgment and recognition of the

slow changes in power distribution during normal operation.

The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels. REFERENCES1.FSAR, Chapter 14.2.FSAR, Chapter 3.3.NUREG-0800, Standard Review Plan 4.2,Section II.A.2(g), Revision 2, July 1981.4.NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-5 Revision 0 BASES APPLICABLE The trip setpoints are then determined accounting for the SAFETY ANALYSES, remaining in strument errors (e.g., drift). The trip setpoints LCO, and derived in this manner pr ovide adequate protection because APPLICABILITY instrumentation uncertain ties, process effects, calibration (continued) tolerances, instrument dr ift, and severe environmental effects (for channels that must func tion 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 or other specified conditions in the Table, which may require an RPS trip to mitigat e the consequences of a design basis accident or transient. To ensure a reliable scram function, a combination of Functions are required in each MODE to

provide primary and diverse initiation signals.

The only MODES specified in Table 3.3.1.1-1 are MODES 1 (which encompasses 30% RTP) and 2, and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies. No RPS Function is required in MODES 3 and 4 since all control rods are fu lly inserted and the Reactor Mode Switch Shutdown Position control rod withdrawal block (LCO 3.3.2.1) does not allow an y control rod to be withdrawn.

In MODE 5, control rods withdraw n from a core cell containing no fuel assemblies do not affect t he reactivity of the core and, therefore, are not required to have the capability to scram.

Provided all other control rods remain inserted, no RPS function

is 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.

The specific Applicable Safety Analyses, LCO, and Applicability

discussions are listed below on a Function by Function basis.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-10 Revision 0 BASES APPLICABLE 2.a. Average Power Range Monitor Neutron Flux - High, SAFETY ANALYSES, (Setdown)

LCO, and APPLICABILITY For operation at low power (i.e., MODE 2), the Average Power (continued) Range Monitor Neutron Flux - High, (Setdown) Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operatin g 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 Rang e 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 r un position, reactor power does not exceed 25% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow. Theref ore, it indirectly prevents fuel damage during significant reacti vity increases with THERMAL POWER < 25% RTP.

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 sinc e the potential for criticality exists. In MODE 1, the Average Power Range Monitor Neutron Flux - High Function provides protection against reactivity

transients and the RWM and rod block monitor protect against

control rod withdrawal error events.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-15a Amendment No. 258 March 05, 1999 BASES APPLICABLE 2.f. Oscillation Power Range Monitor (OPRM) Upscale SAFETY ANALYSES, LCO, and The OPRM Upscale Function provides compliance with GDC 10 APPLICABILITY and GDC 12, thereby providing protection from exceeding the (continued) fuel MCPR safety limit (S L) due to anticipated thermal hydraulic power oscillations.

References 13, 14, and 15 describe three algorithms for detecting thermal hydraulic inst ability related neutron flux oscillations: the period based de tection algorith m, the amplitude based algorithm, and the growth ra te algorithm. All three are implemented in the OPRM Upscal e Function, but the safety analysis takes credit only for the period based detection algorithm. The remaining algori thms provide defense in depth and additional protection against unanticipated oscillations.

OPRM Upscale Function OPERABILITY for Technical Specification purposes is based only on the period based detection algorithm.

The OPRM Upscale Function receives input signals from the local power range monitors (LPRMs) within the reactor core, which are combined into "cells" for evaluation of the OPRM algorithms.

The OPRM Upscale Function is required to be OPERABLE when the plant is in a region of power flow operation where anticipated events could lead to thermal hydraulic instability and related neutron flux oscillations. Within this region, the automatic trip is enabled when THERMAL POWER, as indicated by the APRM Simulated Thermal Power, is 25% RTP and reactor core flow, as i ndicated by recirculation drive flow is < 60% of rated flow, the operating region where actual thermal hydraulic oscillations ma y occur. Requiring the OPRM Upscale Function to be OPERABLE in MODE 1 provides consistency with operability requirements for other APRM functions and assures that the OPRM Upscale Function is OPERABLE whenever reactor power could increase into the region of concern wit hout operator action.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-23 Revision 0 41 November 09, 2006 BASES APPLICABLE 8. Turbine Stop Valve - Closure (continued) SAFETY ANALYSES, LCO, and Turbine Stop Valve - Closure signals are initiated from position APPLICABILITY switches located on each of the four TSVs. Two independent position switches are associated with each stop valve. One of the two switches provides input to RPS trip system A; the other, to RPS trip system B. Thus, each RPS trip system receives an

input from four Turbine Stop Valve - Closure channels, each consisting of one position switch.

The logic for the Turbine Stop Valve - Closure Function is such that three or more TSVs must

be closed to produce a scram. This Function must be enabled at THERMAL POWER 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this function.

The Turbine Stop Valve - Closure 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 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 Func tion if any three TSVs should close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is 30% RTP.

This Function is not required when THERMAL POWER is < 30% 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.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-24 Revision 0 41 November 09, 2006 BASES APPLICABLE 9. Turbine Control Valve Fa st Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and APPLICABILITY Fast closure of the TCVs re sults in the loss of a heat sink that (continued) 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 clos ure 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 7. For this event, the reactor scram

reduces the amount of energy re quired 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 electrohydraulic control (EHC) fluid pressure at each control valve. One pressure switch is

associated with each control valve, and the signal from each switch is assigned to a separat e RPS logic channel. This Function must be enabled at THERMAL POWER 30% RTP.

This is normally accomplished automatically by pressure

transmitters sensing turbine fi rst stage pressure; therefore, opening the turbine bypass valves may affect this function.

The Turbine Control Valve Fast Closure, Trip Oil Pressure -

Low Allowable Value is selected high enough to detect imminent TCV fast closure.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-25 Revision 0, 41 November 09, 2006 BASES APPLICABLE 9. Turbine Control Valve Fa st Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and (continued)

APPLICABILITY

Four channels of Turbine Contro l 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, consist ent with the analysis assumptions, whenever THERMAL POWER is 30% RTP. This Function is not required when THERMAL POWE R is < 30% 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.

For this instrument function, the nominal trip setpoint including the as-left tolerances is defi ned as the LSSS. The acceptable as-found band is based on a statistical combination of possible measurable uncertainties (i.e., setting tolerance, drift, temperature effects, and meas urement and test equipment). During instrument calibrations, if the as-found setpoint is found to be conservative with respect to the Allowable Value, but outside its acceptable as-f ound band (tolerance range), as defined by its associated Survei llance Requirement procedure, then there shall be an initial determination to ensure confidence that the channel can perform as required before returning the channel to service in accordance with the Surveillance. The technician performing the Su rveillance will evaluate the instrument's ability to maintain a stable setpoint within the as-left tolerance. The technician's ev aluation will be reviewed by on shift personnel during the approval of the Surveillance data prior to returning the channel back to se rvice at the completion of the Surveillance. This shall consti tute the initial determination of operability. If a channel is found to exceed the channel's Allowable Value or c annot be reset within the RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-37 Revision 0 BASES SURVEILLANCE SR 3.3.1.1.2 REQUIREMENTS (continued) To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor power calculated from a heat balance. The Frequency of once

per 7 days is based on minor c hanges in LPRM sensitivity, which could affect the APRM reading, between performances of

SR 3.3.1.1.7.

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 mainta in 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 satisfactor ily performed within the last 7 days, in accordance with SR 3.0.

2. A Note is provided which allows an increase in THERMAL POWER above 25% if the 7 day Frequency is not met per SR 3.

0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-45 Amendment No. 255 November 30, 1998 BASES SURVEILLANCE SR 3.3.1.1.15 REQUIREMENTS (continued) This SR ensures that scrams initiated from the Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions wi ll not be inadvertently bypassed when THERMAL POWER is 30% RTP. This involves calibration of the bypass channels (PIS-1-81A, PIS-1-81B, PIS-1-91A, and PIS-1-91B). Adequate margins for the

instrument setpoint methodolog ies are incorporated into the actual setpoint.

If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at 30% RTP, either due to open main turbine bypass valve(s) or other reasons), then the affected Turbine Stop Valve - Closure 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 (nonb ypass). If placed in the nonbypass condition (Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low

Functions are enabled), this SR is met and the channel is considered OPERABLE.

The Frequency of 24 months is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-45a Amendment No. 258 March 05, 1999 BASES SURVEILLANCE SR 3.3.1.1.17 REQUIREMENTS (continued) This SR ensures that scrams initiated from OPRM Upscale Function (Function 2.f) will not be inadvertently bypassed when THERMAL POWER, as indica ted by the APRM Simulated Thermal Power, is 25% RTP and core flow, as indicated by recirculation drive flow, is < 60% rated core flow. This normally involves confirming the bypass setpoints. Adequate margins for the instrument setpoint methodol ogies are incorporated into the actual setpoint. The actual surveillance ensures that the OPRM Upscale Function is enabled (not bypassed) for the correct values of APRM Simulated Thermal Power and recirculation drive flow. Other surveillances ensure that the APRM Simulated Thermal Power and recirculation flow properly correlate with THERMAL POWER and core flow, respectively.

If any bypass setpoint is nonconservative (i.e., the OPRM Upscale Function is bypassed when APRM Simulated Thermal Power 25% RTP and recirculation drive flow < 60% rated), then the affected channel is co nsidered inoperable for the OPRM Upscale Function. Alter natively, the bypass setpoint may be adjusted to place the channel in a conservative condition (unbypass). If placed in the unbypassed condition, this SR is met and the channel is considered OPERABLE.

The frequency of 24 months is based on engineering judgment and reliability of the components.

Feedwater and Main Turbine High Wa ter Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 2 B 3.3-76 Revision 0 BASES (continued)

APPLICABLE The feedwater and main turbine high water level trip SAFETY ANALYSES instrumentation is assum ed to be capable of providing a turbine trip in the design basis transient analysis for a feedwater controller failure, maximum demand event (Ref. 1). The reactor vessel high water level trip indirectly initiates a reactor scram

from the main turbine trip (above 30% RTP) and trips the

feedwater pumps, thereby terminating the event. The reactor scram mitigates the reduction in MCPR.

Feedwater and main turbine high water level trip instrumentation satisfies Criterion 3 of the NRC Policy Statement (Ref. 3).

LCO The LCO requires two channels of the Reactor Vessel Water Level - High instrumentation per trip system to be OPERABLE to ensure that no single instru ment failure will prevent the feedwater pump turbines and ma in turbine trip on a valid Reactor Vessel Water Level - High signal. Both channels in

either trip system are needed to pr ovide trip signals in order for the feedwater and main turbine trips to occur. Each channel

must have its setpoint set withi n the specified Allowable Value of SR 3.3.2.2.3. The Allowable Value is se t to ensure that the thermal limits are not exceeded during the event. The actual setpoint is calibrated to be consistent with the applicable setpoint methodology assumptions.

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 successive CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.

Feedwater and Main Turbine High Wa ter Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 2 B 3.3-77 Revision 0, 31 April 6, 2005 BASES LCO Trip setpoints are those pr edetermined values of output at (continued) 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 out put value of the process parameter exceeds the se tpoint, the associated device (e.g., trip unit) changes state. The analyt ic limits are derived from the limiting values of the process parameter s obtained from the safety analysis. The Allowabl e Values are derived from the analytic limits, corrected for calib ration, process, and some of the instrument errors. A channel is inoperable if its actual trip setpoint is not within its requir ed Allowable Value. The trip setpoints are then determined a ccounting 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 environmental effects (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.

APPLICABILITY The feedwater and main turbine high water level trip instrumentation is required to be OPERABLE at 25% RTP to ensure that the fuel cladding in tegrity Safety Limit and the cladding 1% plastic strain lim it are not violated during the feedwater controller failure, maximum demand event. As discussed in the Bases for LCO 3.2.1, "Average Planar Linear Heat Generation Rate (APLHGR)," LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)

," and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)," sufficient margin to these limits exists below 25% RTP; t herefore, these requirements are only necessary when operating at or above this power level.

Feedwater and Main Turbine High Wa ter Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 2 B 3.3-80 Revision 0 BASES ACTIONS B.1 (continued)

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is suff icient for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of f eedwater and main turbine high water level trip instrumentation occurring during this period. It is also consistent with the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in

LCO 3.2.2 for Required Action A.1, since this instrumentation's purpose is to preclude a MCPR violation.

C.1 With the required channels not re stored to OPERABLE status or placed in trip, THERMAL POWER must be reduced to

< 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. As discussed in the Applicability

section of the Bases, operation below 25% RTP results in sufficient margin to the required limits, and the feedwater and main turbine high water level trip instrumentation is not required to protect fuel integrity during the feedwater controller failure, maximum demand event. The allowed Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is based on operating ex perience to reduce THERMAL POWER to < 25% RTP from full pow er conditions in an orderly manner and without chall enging plant systems.

SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for performance of required Surveill ances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains feedwater

and main turbine high water level trip capability. Upon

completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channe l must be returned to OPERABLE status

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 2 B 3.3-109 Revision 0 , 31 , 61 December 7, 2010 BASES BACKGROUND Each EOC-RPT trip system is a two-out-of-two logic for each (continued) Function; thus, either two TSV - Closure 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 syst em 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 and the TCV Fast Closure, Trip Oil SAFETY ANALYSES, Pressure - Low Functions are designed to trip the recirculation LCO, and pumps in the event of a turb ine trip or generator load rejection APPLICABILITY to mitigate the increase in neutron flux, heat flux, and reactor pressure, and to increase the margin to the MCPR SL and LHGR limits. The analytical methods and assumptions used in

evaluating the turbine trip and generator load rejection are summarized in References 2, 3, and 4.

To mitigate pressurization transi ent effects, the EOC-RPT must trip the recirculation pumps afte r initiation of cl osure movement of either the TSVs or the TCVs. The combined effects of this trip and a scram reduce fuel bundle power more rapidly than a

scram alone, resulting in an increased margin to the MCPR SL

and LHGR limits. Alternatively, MCPR limits for an inoperable EOC-RPT, as specified in the CO LR, are sufficient to prevent

violation of the MCPR Safety Li mit and fuel mechanical limits.

The EOC-RPT function is automatically disabled when turbine first stage pressure is < 30% RTP.

EOC-RPT instrumentation sati sfies Criterion 3 of the NRC Policy Statement (Ref. 6).

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 2 B 3.3-112 Revision 0 , 31 , 61 December 7, 2010 BASES APPLICABLE Turbine Stop Valve - Closure (continued) SAFETY ANALYSES, LCO, and Closure of the TSVs is dete rmined by measuring the position of APPLICABILITY each valve. There are two separate position signals associated with each stop valve, the signal from each switch being assigned to a separate trip channel. The logic for the TSV -

Closure Function is such that two or more TSVs must be closed to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves

may affect this function. To consider this function OPERABLE, bypass of the function must not occur when bypass valves are open. Four channels of TSV - Closure, with two channels in each trip system, are availabl e 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 Allowable Value is selected to detect imminent TSV

closure.

This protection is required, c onsistent with the safety analysis assumptions, whenever THERMAL POWER is 30% RTP. Below 30% RTP, the Reactor Vessel Steam Dome Pressure -

High and the Average Power Ra nge Monitor (APRM) Fixed Neutron Flux - High Functions of the Reactor Protection System (RPS) are adequate to maintain the necessary margin to the MCPR SL and LHGR limits.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 2 B 3.3-113 Revision 0, 31 April 6, 2005 BASES APPLICABLE Turbine Control Valve Fast Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and APPLICABILITY Fast closure of the TCVs during a generator load rejection (continued) results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transie nts 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 va lves. The EOC-RPT decreases reactor power and aids the reactor scram in ensuring that the MCPR SL and LHGR limits are not exceeded during the worst case transient.

Fast closure of the TCVs is determined by measuring the

electrohydraulic control fluid pre ssure at each control valve.

There is one pressure switch associated with each control valve, and the signal from each switch is assigned to a separate trip channel. The logic for t he TCV Fast Closure, Trip Oil Pressure - Low Function is such that two or more TCVs must be closed (pressure switch trips) to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 30% RTP.

This is normally accomplished automatically by pressure transmitters sensing turbine fi rst stage pressure; therefore, opening the turbine bypass valves may affect this function. To consider this function OPERABLE, bypass of the function must not occur when bypass valves are open. Four channels of TCV Fast Closure, Trip Oil Pressure - Low, with two channels in each trip system, are availabl e 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 immi nent TCV fast closure.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 2 B 3.3-114 Revision 0 BASES APPLICABLE Turbine Control Valve Fast Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and (continued)

APPLICABILITY

This protection is required c onsistent with the safety analysis whenever THERMAL POWER is 30% RTP. Below 30% RTP, the Reactor Vessel Steam Dome Pressure - High and the APRM Fixed Neutron Flux - Hi gh Functions of the RPS are adequate to maintain the necessary safety margins.

ACTIONS A Note has been provided to modify the ACTIONS related to EOC-RPT instrumentation channel

s. 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 sepa rate 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 inst rumentation channel.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 2 B 3.3-116 Revision 0 , 31 , 61 December 7, 2010 BASES ACTIONS B.1 and B.2 (continued)

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 capabilit

y. 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.

Alternately, Required Action B.2 requires the MCPR and LHGR limits for inoperable EOC-RPT, as specified in the COLR, to be

applied. This also restores the margin to MCPR and LHGR limits assumed in the safety analysis.

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is suff icient time 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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in LCO 3.2.2 for Required Action A.1, since this instrumentation's purpose is to preclude a MCPR or LHGR violation.

C.1 With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to < 30% RTP within

4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Comp letion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is reasonable, based on operating experience, to reduce THERMAL POWER to < 30% RTP fr om full power conditions in an orderly manner and without challenging plant systems.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 2 B 3.3-118 Amendment No. 255 November 30, 1998 BASES SURVEILLANCE SR 3.3.4.1.2 REQUIREMENTS (continued) This SR ensures that an EOC-RPT initiated from the TSV - Closure and TCV Fast Closure, Trip Oil Pressure - Low

Functions will not be inadvertently bypassed when THERMAL POWER is 30% RTP. This involves calibration of the bypass channels. Adequate margins fo r the instrument setpoint methodologies are incorporated into the actual setpoint. If any bypass channel's setpoint is nonc onservative (i.e., the Functions are bypassed at 30% RTP, either due to open main turbine bypass valves or other reasons), the affected TSV - Closure and TCV Fast Closure, Trip Oil Pressure - Low Functions are considered inoperable. Alter natively, the bypass channel can be placed in the conservative condition (nonbypass). If placed

in the nonbypass condition, th is SR is met with the channel considered OPERABLE.

The Frequency of 24 months is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

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 param eter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account fo r instrument drifts between successive calibrations consist ent with the plant specific setpoint methodology. The Frequency is based upon the assumption of an 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

Jet Pumps B 3.4.2 BFN-UNIT 2 B 3.4-16 Revision 0 BASES SURVEILLANCE SR 3.4.2.1 (continued)

REQUIREMENTS

Note 2 allows this SR not to be performed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after THERMAL POWER exceeds 25% of RTP. During low flow

conditions, jet pump noise approaches the threshold response

of the associated flow instru mentation and precludes the collection of repeatable and meaningful data. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is an acceptable time to establish conditions appropriate to perform this SR.

REFERENCES 1. FSAR, Section 14.6.3.

2. GE Service Information Letter No. 330, "Jet Pump Beam Cracks," June 9, 1980.

3. NUREG/CR-3052, "Closeout of IE Bulletin 80-07: BWR Jet Pump Assembly Failure," November 1984.

4. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

Primary Containment B 3.6.1.1

(continued)

BFN-UNIT 2 B 3.6-3 Amendment No. 254 September 08, 1998 BASES APPLICABLE The maximum allowable leakage rate for the primary SAFETY ANALYSES containment (L a) is 2.0% by weight of the containment air per (continued) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the design bas is LOCA maximum peak containment pressure (P a) of 50.6 psig (Ref. 1).

Primary containment satisfies Criterion 3 of the NRC Policy Statement (Ref. 6).

LCO Primary containment OPERABILITY is maintained by limiting leakage to 1.0 L a , except prior to the first startup after performing a required Primary Containment Leakage Rate Testing Program leakage test. At this time, applicable leakage limits must be met. Compliance with this LCO will ensure a

primary containment configuration, including equipment hatches, that is structurally s ound and that will limit leakage to those leakage rates assumed in the safety analyses.

Individual leakage rates specif ied for the prim ary containment air lock 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 primar y 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, prim ary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of

radioactive material from primary containment.

Primary Containment B 3.6.1.1 BFN-UNIT 2 B 3.6-6 Amendment No. 255 November 30, 1998 BASES SURVEILLANCE SR 3.6.1.1.2 (continued)

REQUIREMENTS

Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber and veri fying that the pressure in either the suppression chambe r or the drywell does not change by more than 0.25 inch of wate r per minute over a 10 minute period. The leakage test is per formed every 24 months. The 24 month Frequency was developed considering it is prudent that this Surveillance be performed during a unit outage and

also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs.

REFERENCES 1. FSAR, Section 5.2.

2. FSAR, Section 14.6.

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

4. NEI 94-01, Revision O, "Industr y Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J." 5. ANSI/ANS-56.8-1994, "Ame rican National Standard for Containment System Leakage Testing Requirement."

6. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

Primary Containment Air Lock B 3.6.1.2

(continued)

BFN-UNIT 2 B 3.6-8 Amendment No. 254 September 08, 1998 BASES BACKGROUND the air lock to remain open for extended periods when frequent (continued) primary containment entry is necessary. Under some conditions allowed by this LCO, the prim ary containment may be accessed through the air lock, when the interlock mechanism has failed, by manually performing the interlock function.

The primary containment air lock forms 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 t hat assumed in the unit safety analysis.

APPLICABLE The DBA that postulates the maximum release of radioactive SAFETY ANALYSES material within primary containment is a LOCA. In the analysis of this accident, it is assum ed that primary containment is OPERABLE, such that releas e of fission products to the environment is controlled by the rate of primary containment leakage. The primar y containment is designed with a maximum allowable leakage rate (L a) of 2.0% by weight of the containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the calculat ed maximum peak containment pressure (P a) of 50.6 psig (Ref. 3). This allowable leakage rate forms the basis for the acceptance criteria imposed on the SRs associated with the air lock.

Primary containment air lock OPERABILITY is also required to

minimize the amount of fission product gases that may escape

primary containment through t he air lock and contaminate and pressurize the secondary containment.

The primary containment air lo ck satisfies Criterion 3 of the NRC Policy Statement (Ref. 4).

CAD System B 3.6.3.1

(continued)

BFN-UNIT 2 B 3.6-90 Revision 0 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.1 Containment Atmosphere Dilution (CAD) System BASES BACKGROUND The CAD Syst em functions to maintain combustible gas concentrations within the primary containment at or below the flammability limits following a postulated loss of coolant accident (LOCA) by diluting hydrogen and oxygen with nitrogen. To ensure that a combustible gas mixture does not occur, oxygen

concentration is kept < 5.0 volume percent (v/o), or hydrogen

concentration is kept < 4.0 v/o.

The CAD System is manually initiated and consists of two

independent, 100% capacity sub systems, each of which is capable of supplying nitrogen through separate piping systems to the drywell and suppression chamber of each unit. Each

subsystem includes a liquid nitrogen supply tank, ambient vaporizer, electric heater, and a m anifold with branches to each primary containment (for Unit s 1, 2, and 3).

The nitrogen storage tanks each contain 2500 gal, which is adequate for 7 days of CAD subsystem operation.

The CAD System operates in conjunction with emergency

operating procedures that ar e used to reduce primary containment pressure peri odically during CAD System operation. This combination results in a feed and bleed approach to maintaining hydrogen and oxygen concentrations below combustible levels.

CAD System B 3.6.3.1 (continued)

BFN-UNIT 2 B 3.6-95 Amendment No. 265 Revision 0 May 24, 2000 BASES (continued)

SURVEILLANCE SR 3.6.3.1.1 REQUIREMENTS Verifying that there is 2500 gal of liquid nitrogen supply in each nitrogen storage tank will ensure at least 7 days of post-LOCA CAD operation. This minimum volume of liquid

nitrogen allows sufficient time a fter an accident to replenish the nitrogen supply for long term inerti ng. This is verified every 31 days to ensure that the system is capable of performing its intended function when required. The 31 day Frequency is based on operating experience, which has shown 31 days to be an acceptable period to verify the liquid nitrogen supply and on

the availability of other hydrogen mitigating systems.

SR 3.6.3.1.2

Verifying the correct alignment for manual, power operated, and

automatic valves in each of the CAD subsystem flow paths provides assurance that the prop er flow paths exist for system operation. This SR does not appl y to valves that are locked, sealed, or otherwise secured in position, since these valves

were verified to be in the co rrect position prior to locking, sealing, or securing.

A valve is also allowed to be in the nonaccident position provided it can be aligned to t he accident position within the time assumed in the accident analysis. This is acceptable because the CAD System is manually initiated. This SR 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 mis positioned are in the correct position.

CAD System B 3.6.3.1 BFN-UNIT 2 B 3.6-96 Amendment No. 265 Revision 0 May 24, 2000 BASES SURVEILLANCE SR 3.6.3.1.2 (continued)

REQUIREMENTS

The 31 day Frequency is appropriate because the valves are

operated under procedural control, improper valve position would only affect a single subsystem, the probability of an event requiring initiation of the system is low, and the system is a manually initiated system.

REFERENCES 1. AEC Safety Guide 7, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident, March 10, 1971.

2. FSAR, Section 5.2.6.

3. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-1 Revision 73 Amendment No. 254 January 3, 2013 B 3.7 PLANT SYSTEMS B 3.7.1 Residual Heat Removal Service Water (RHRSW) System and Ultimate Heat Sink (UHS)

BASES BACKGROUND The RHRSW System is designed to provide cooling water for the Residual Heat Removal (RHR) System heat exchangers, required for a safe reactor shut down following a Design Basis Accident (DBA) or transient.

The RHRSW System is operated whenever the RHR heat exchanger s are required to operate in the shutdown cooling mode or in the suppression pool cooling or spray mode of the RHR System.

The RHRSW System is common to the three BFN units and consists of the UHS and four independent and redundant subsystems, each of which f eeds one RHR heat exchanger in each unit. Each subsystem is made up of a header, two 4500 gpm pumps, a suction source, valves, piping, and associated

instrumentation. Two subsyst ems, with one pump operating in each subsystem, are capable of pr oviding 100% of the required cooling capacity to maintain safe shutdown conditions for one unit. The RHRSW System is designed with sufficient redundancy so that no single active component failure can prevent it from achieving its design function. The RHRSW System is described in the FSAR, Section 10.9 (Ref. 1).

Cooling water is pumped by the RHRSW pumps from the Wheeler Reservoir through the tube side of the RHR heat exchangers, and discharged back to the Wheeler Reservoir.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-2 Revision 73 Ame ndment No. 254 January 3, 2013 BASES BACKGROUND The system is initiated manually from each of the three units (continued) control r ooms. If operating during a loss of coolant accident (LOCA), the system is automatic ally tripped on degraded bus voltage to allow the diesel gener ators to automatically power only that equipment necessary to reflood the core. The system can be manually started any time the degraded bus voltage signal clears, and is assumed to be manually started within 10 minutes after the LOCA.

APPLICABLE The RHRSW S ystem removes heat fr om the suppression pool SAFETY ANALYSES to limit the suppr ession pool temperature and primary containment pressure following a LOCA. This ensures that the primary containment can perform its function of limiting the release of radioactive materials to the environment following a

LOCA. The ability of the RHR SW System to support long term cooling of the reactor or primar y containment is discussed in the FSAR, Chapters 5 and 14 (Refs. 2 and 3, respectively). These analyses explicitly assume that the RHRSW System will provide adequate cooling support to the equipment required for safe

shutdown. These analyses include the evaluation of the long term primary containment response after a design basis LOCA.

The safety analyses for long term cooling were performed for various combinations of RHR System failures and considers the

number of units fueled. With one unit fueled, the worst case single failure that would affect the performance of the RHRSW System is any failure that would disable two subsystems of the RHRSW System.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-3 Revision 73 Ame ndment No. 254 January 3, 2013 BASES APPLICABLE With two and three units fueled, a worst case single failure SAFETY ANALYSES could also include the loss of two RHRSW pumps caused by (continued) losing a 4 kV shutdown board since there are certain alignment configurations that allow two RHRSW pumps to be powered from the same 4 kV shutdown bo ard. As discussed in the FSAR, Section 14.6.3.3.2 (Ref.

4) for these analyses, manual initiation of the OPERABLE RHRSW subsystems and the associated RHR System is assumed to occur 10 minutes after a

DBA. The analyses assume that there are two RHRSW subsystems operating in each unit, with one RHRSW pump in each subsystem capable of producing 4000 gpm of flow. In this case, the maximum suppression chamber water temperature and pressure are 177°F (as reported in Reference 3) and 50.6 psig, respectively, well below the design temperature of

281°F and maximum allowable pressure of 62 psig.

The RHRSW System together with the UHS satisfies Criterion 3

of the NRC Policy Statement (Ref 5).

LCO Four RHRSW subsystems are required to be OPERABLE to provide the required redundancy to ensure that the system

functions to remove post a ccident heat loads, assuming the worst case single active failure o ccurs coincident with the loss of offsite power. Additionally, since the RHRSW pumps are

shared between the three BFN unit s, the number of OPERABLE pumps required is also dependent on the number of units

fueled.

An RHRSW subsystem is considered OPERABLE when:

a. At least one RHRSW pump (i.e., one required RHRSW pump) is OPERABLE; and

b. An OPERABLE flow path is capable of taking suction from the intake structure and tr ansferring the water to the associated RHR heat exchanger at the assumed flow rate.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-4 Revision 44 , 73 Amendment No. 254 January 3, 2013 BASES LCO In addition to the required number of OPERABLE subsystems, (continued) there must be an adeq uate number of pumps OPERABLE to provide cooling for the fueled non-accident units.

The total number of required RHRSW pumps must take into consideration the required numbe r of pumps required for the specific unit along with the number of pumps required for other units that are fueled. Hence, when one unit contains fuel, four RHRSW pumps are required to be OPERABLE. When two units contain fuel, six RHRSW pumps are required to be OPERABLE. When three units contain fuel, eight RHRSW pumps are required to be OPERABLE. The minimum specified number of pumps gives consider ation to all units capable of producing heat in aggregate and a ccounts for a single active failure. The above pre-accident configuration ensures that during a design basis accident with a postulated single active failure, the resulting configuration for the accident unit has at least two RHRSW subsystems OPERABLE to supply 100 percent of the long term RHR cooling water. The resulting configuration for the non-accident units has at least two RHRSW subsystems per unit OPERABLE to supply 100 perc ent of the required cooling capacity to maintain safe shutdown conditions.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-4a Revision 44 , 73 January 3, 2013 BASES LCO The number of required OPERABLE RHRSW pumps (continued) is modified by a Note which specifies that the number of required RHRSW pumps may be reduced by one for each

fueled unit that has been in MODE 4 or 5 for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

This Note acknowledges the fa ct that decay heat removal requirements are substantially reduced for fueled units in

MODE 4 or 5 for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The OPERABILITY of the UHS for RHRSW is based on having

a maximum water temperature wit hin the limits specified in Figure 3.7.1-1.

APPLICABILITY In MODES 1, 2, and 3, the RHRSW System and UHS are required to be OPERABLE to s upport the OPERABILITY of the RHR System for primary containment cooling (LCO 3.6.2.3, "Residual Heat Removal (RHR) Suppression Pool Cooling," and LCO 3.6.2.4, "Residual Heat Removal (RHR) Suppression Pool

Spray") and decay heat removal (L CO 3.4.7, "Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown"). The Applicability is therefore c onsistent with the requirements of these systems.

In MODES 4 and 5, the OPER ABILITY requirements of the RHRSW System and UHS are dete rmined by the systems they support.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-5 Revision 73 Amendment No. 254 January 3, 2013 BASES (continued)

ACTIONS Since the RHRSW System is common to all three units, the following requirements must be followed when multiple units contain fuel:

a. With one or more requir ed RHRSW pumps inoperable, all applicable ACTIONS must be entered for each unit.

b. With one or more RHRSW subsystems inoperable, all applicable ACTIONS for inoperable subsystems must be entered on the unit(s) that hav e the inoperable subsystem.

The Required Actions and associated Completion Times of Conditions A, B, C, and D are based on a reduction in redundancy of the RHRSW System, not a loss of RHRSW safety function. The Required Actions and associated Completion Times of Conditions E, F, and G consider that the RHRSW safety function is lost.

RHRSW safety function is maintained when at least two RHRSW subsystems, with two separate RHRSW pumps (i.e. one per subsystem), on a per fuel ed unit basis, are OPERABLE. Additionally, the total number of RHRSW pumps must be such that the RHRSW pumps credited for maintaining the RHRSW safety function for a specific unit are not credited for maintaining the RHRSW safety function for a different fueled unit.

When there are three fueled units, the RHRSW safety function is maintained when:

• Two RHRSW subsystems per fu eled unit are OPERABLE;

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-5a Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS

• Six RHRSW pumps are OPERABLE (two RHRSW pumps (continued) per fueled unit);

• Each OPERABLE RHRSW subsystem has one required RHRSW pump OPERABLE; and

• The required RHRSW pump that is OPERABLE in an RHRSW subsystem is not cr edited for maintaining the RHRSW safety function for another fueled unit (i.e., it is not one of the two RHRSW pumps that is required to be OPERABLE for another fueled unit).

When there are two fueled units, the RHRSW safety function is maintained when:

• Two RHRSW subsystems per fueled unit are OPERABLE;

• Four RHRSW pumps are O PERABLE (two RHRSW pumps per fueled unit);

• Each OPERABLE RHRSW subsystem has one required RHRSW pump OPERABLE; and

• The required RHRSW pump that is OPERABLE in an RHRSW subsystem is not cr edited for maintaining the RHRSW safety function for another fueled unit (i.e., it is not one of the two RHRSW pumps that is required to be OPERABLE for another fueled unit).

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-5b Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS When there is one fueled unit, the RHRSW safety function is (continued) maintained when:

• Two RHRSW subsystems are OPERABLE and

• Two RHRSW pumps are OPERABLE (i.e., one per OPERABLE RHRSW subsystem).

When any combination of pump(s) and other subsystem components, e.g., heat exchanger(s), are inoperable such that three or more components of the RHRSW System (on any or all fueled units) are inoperable, the capability to meet the safety function must be evaluated by all fueled units. When an RHRSW pump is credited by one f ueled unit for maintaining the RHRSW safety function, then the other fueled units cannot also credit this same RHRSW pump with maintaining their RHRSW afety function since the capacity of a single RHRSW pump is not sufficient to support the r equired heat removal function of more than one RHR heat exchanger. Therefore, in this condition, the RHRSW pump credited with maintaining RHRSW safety function on a fueled unit must be considered inoperable for the other fueled units for purpose of determining if RHRSW safety function is maintained. The other fueled units must then include the additional inoperable RHRSW pump(s) with the total number of inoperable components when determining if RHRSW safety function is maintained. If RHRSW safety function is determined to be lost, then Conditi on E or F is required to be entered. The examples, with respect to RHRSW pumps, used in the following descriptions of the ACTIONS assume that three units are fueled.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-6 Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS A.1 and A.2 (continued)

With one required RHRSW pum p inoperable, the inoperable RHRSW pump must be restored to OPERABLE status within 30 days. With the unit in this condition, the remaining OPERABLE RHRSW pumps are adequate to perform the RHRSW heat

removal function. However, t he overall reliability is reduced because a single failure could result in reduced primary containment cooling capability. The 30 day Completion Time is based on the availability of equipment in excess of normal redundancy requirements and the low probability of an event occurring requiring RHRSW during this period.

Alternatively, five RHRSW pum ps may be verified to be OPERABLE with power being su pplied from separate 4 kV shutdown boards.

Required Action A1 is modified by two Notes. Note 1 indicates that the Required Action is applicable only when two units are fueled. In the two unit fueled condit ion, a single failure (loss of a 4 kV shutdown board) could result in inadequate RHRSW pumps if two pumps are powered fr om the same power supply.

If five RHRSW pumps are pow ered from separate 4 kV shutdown boards, then no postulated single active failure could occur to prevent the RHRSW system from performing its design function. Operation can continue indefinitely if Required Action A.1 is met.

Note 2 requires only four RHRSW pumps powered from separate 4 kV shutdown boards to be OPERABLE if the other fueled unit has been in Mode 4 or 5 greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This acknowledges the fact that decay heat removal requirements are substantially reduced for fueled units in Mode 4 or 5 for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

These two Notes clarify the situations under Required Action A.1 would be the appropria te Required Action.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-6a Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS B.1 (continued)

With one RHRSW subsystem inoperable (e.g., one RHR heat exchanger inoperable or an RHRSW header isolated) for reasons other than inoperable RHRSW pumps, which are covered by separate Conditions, the inoperable RHRSW subsystem must be restored to OPERABLE status within 30 days. With the unit in th is condition, the remaining OPERABLE RHRSW subsystems are adequate to perform the

RHRSW heat removal function. However, the overall reliability is reduced because a single failure could result in reduced

primary containment cooling cap ability. The 30 day Completion

Time is based on the availability of equipment in excess of

normal redundancy requirements and the low probability of an event occurring requiring RHRSW during this period.

The Required Action is modified by a Note indicating that the

applicable Conditions of LCO 3.4.7 be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-7 Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS C.1 (continued)

With two required RHRSW pumps inoperable (i.e., one required RHRSW pump inoperable in each of two separate RHRSW subsystems or two RHRSW pumps inoperable in the same RHRSW subsystem), the remaining RHRSW pumps are adequate to perform the RHRSW heat removal function.

However, the overall reliability is reduced because a single failure of the OPERABLE RHRSW pumps could result in a loss of RHRSW function. The seven day Completion Time is based

on the redundant RHRSW capabilities afforded by the

OPERABLE RHRSW pumps and the low probability of an event occurring during this period.

D.1 With two RHRSW subsystems inoperable (e.g., two RHR heat exchangers inoperable) for reas ons other than inoperable RHRSW pumps, which are covered by separate Conditions, the remaining OPERABLE RHRSW subsystems are adequate to perform the RHRSW heat removal function. However, the overall reliability is reduced becau se a single failure could result

in reduced primary containment cooling capability. The seven day Completion Time is based on the availability of equipment in excess of normal redundancy requirements and

the low probability of an event occurring requiring RHRSW during this period.

The Required Action is modified by a Note indicating that the

applicable Conditions of LCO 3.4.7 be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-8 Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS E.1 (continued)

With three or more requir ed RHRSW pumps inoperable, the RHRSW System is not capable of performing its intended function. The requisite number of pumps must be restored to OPERABLE status within ei ght hours. The eight hour Completion Time is based on the Completion Times provided for the RHR suppression pool c ooling and spray functions.

F.1 With three or more required RHRSW subsystems inoperable (e.g., one RHR heat exchanger inoperable in each of three or four separate RHRSW subsystems) for reasons other than inoperable RHRSW pumps, which are covered by separate Conditions, the RHRSW System is not capable of performing its intended function. The requisite number of subsystems must be restored to OPERABLE status within eight hours. The eight hour Completion Time is based on the Completion Times provided for the RHR suppression pool cooling and spray functions.

The Required Action is modified by a Note indicating that the

applicable Conditions of LCO 3.4.7 be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-9 Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS G.1 and G.2 (continued)

If the RHRSW subsystem(s) or the RHRSW pump(s) cannot be restored to OPERABLE status wit hin the associated Completion Times or the UHS is determi ned inoperable, 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating

experience, to reach the require d unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.1.1 REQUIREMENTS

Verifying the correct alignment for each manual and power operated valve in each RHRSW sub system flow path provides assurance that the proper flow paths will exist for RHRSW

operation. This SR does not appl y to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct positi on prior to locking, sealing, or securing. A valve is also al lowed to be in the nonaccident position, and yet considered in t he correct position, provided it can be realigned to its accident po sition. This is acceptable because the RHRSW System is a manually initiated system.

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 is based on engineering judgment, is

consistent with the procedural controls governing valve operation, and ensures correct valve positions.

RHRSW System and UHS B 3.7.1 BFN-UNIT 2 B 3.7-10 Revision 69 Amendment No. 254 October 5, 2012 BASES SURVEILLANCE SR 3.7.1.2 REQUIREMENTS (continued) Verification of the UHS te mperature is within t he limits of Figure 3.7.1-1 ensures the heat removal capability of the RHRSW System is within the assumptions of the DBA analysis (Ref. 6).

The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Frequencies are based on operating

experience relating to trends of the parameter variations during the applicable MODES.

REFERENCES 1. FSAR, Section 10.9.

2. FSAR, Chapter 5.

3. FSAR, Chapter 14.

4. FSAR, Section 14.6.3.3.2.

5. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

6. FSAR, Section 14.6.3.3.2.3.

EECW System and UHS B 3.7.2 (continued)

BFN-UNIT 2 B 3.7-13 Amendment No. 254 September 08, 1998 BASES LCO The EECW System is consi dered OPERABLE when it has an (continued) OPERABLE UHS, three OPERABLE pumps, and two OPERABLE flow paths capable of taking suction from the intake structure and transferring t he water to the appropriate equipment.

The OPERABILITY of the UHS for EECW is based on having a maximum water temperature of 95°F. Additional requirements for UHS temperature are pr ovided in SR 3.7.1.2

The isolation of the EECW S ystem to components or systems may render those components or systems inoperable, but does

not affect the OPERABIL ITY of the EECW System.

APPLICABILITY In MODES 1, 2, and 3, the EECW System and UHS are required to be OPERABLE to support OPERABILITY of the

equipment serviced by the EECW System. Therefore, the EECW System and UHS are required to be OPERABLE in these MODES.

In MODES 4 and 5, the OPER ABILITY requirements of the EECW System and UHS are determined by the systems they support.

ACTIONS A.1

With one required EECW pump inoperable, the required EECW pump must be restored to OPERABLE status within 7 days.

With the system in this condition, the remaining OPERABLE

EECW pumps are adequate to perform the heat removal function. However, the overall reliability is reduced because a single failure in the EECW System could result in loss of EECW

function.

EECW System and UHS B 3.7.2 (continued)

BFN-UNIT 2 B 3.7-14 Revision 0 , 69 October 5, 2012 BASES ACTIONS A.1 (continued)

The 7 day Completion Time is based on the redundant EECW System capabilities afforded by the remaining OPERABLE

pumps, the low probability of an accident occurring during this time period and is consistent wit h the allowed Completion Time for restoring an inoperable DG.

B.1 and B.2

If the required EECW pump cannot be restored to OPERABLE status within the associated Comp letion Time, or two or more EECW pumps are inoperable or the UHS is determined inoperable, 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4

within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allo wed Completion Times are reasonable, based on operating experience, to reach the

required unit conditions from full power conditions in an orderly manner and without chall enging unit systems.

SURVEILLANCE SR 3.7.2.1 REQUIREMENTS

Verification of the UHS tem perature ensures that the heat removal capability of the EEC W System is within the

assumptions of the DBA analysis.

Additional requirements for UHS temperature to ensure RHRSW System heat removal capability is maintained within the assumptions of the DBA analysis are provided in SR 3.

7.1.2. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on operating experience related to trending of the

parameter variations during the applicable MODES.

Main Turbine Bypass System B 3.7.5 (continued)

BFN-UNIT 2 B 3.7-32 Revision 0 B 3.7 PLANT SYSTEMS B 3.7.5 Main Turbine Bypass System BASES BACKGROUND The Main Turbine Bypass S ystem is designed to control steam pressure when reactor steam generation exceeds turbine requirements during unit start up, sudden load reduction, and cooldown. It allows excess steam flow from the reactor to the

condenser without going through t he turbine. The bypass capacity of the system is 25%

of the Nuclear Steam Supply System rated steam flow. Sudde n load reductions within the capacity of the steam bypa ss can be accommodated without reactor scram. The Main Turbi ne Bypass System consists of nine valves connected to the ma in steam lines between the main steam isolation valves and the turbine stop valve bypass valve chest. Each of these nine valves is operated by hydraulic cylinders. The bypass valves are controlled by the pressure regulation function of the Pressure Regulator and Turbine Generator Control System, as discussed in the FSAR, Section 7.11.3.3 (Ref. 1).

The bypass valves are normally

closed, and the pressure regulator controls the turbine control valves that direct all steam flow to the turbine. If the speed governor or the load limiter restricts steam flow to the turbine, the pressure regulator controls the system pressure by opening the bypass valves. When the bypass valves open, the steam

flows from the bypass chest, th rough connecting piping, to the pressure breakdown assemblies, w here a series of orifices are used to further reduce the steam pressure before the steam enters the condenser.

Main Turbine Bypass System B 3.7.5 (continued)

BFN-UNIT 2 B 3.7-34 Revision 0, 31 April 6, 2005 BASES (continued)

APPLICABILITY The Main Turbine Bypass System is required to be OPERABLE at 25% RTP to ensure that the f uel cladding integrity Safety Limit is not violated during abnorma l operational transients. As

discussed in the Bases for LCO 3.2.1 and LCO 3.2.2, sufficient

margin to these limits exists at < 25% RTP. T herefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A.1

If the Main Turbine Bypass Syst em is inoperable (one or more bypass valves inoperable), or the APLHGR, MCPR, and LHGR limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are not ap plied, the assumptions of the design basis transient analysis may not be met. Under such circumstances, prompt action should be taken to restore the

Main Turbine Bypass System to OPERABLE status or adjust the APLHGR, MCPR, and LHGR limits accordingly. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is reasonable, based on the time to complete the Required Action and the low probability of an event occurring during this period requiring the Main Turbine Bypass

System.

B.1 If the Main Turbine Bypass S ystem cannot be restored to OPERABLE status or the APLHG R, MCPR, and LHGR limits for an inoperable Main Turbine Bypass System are not applied, THERMAL POWER must be reduced to < 25% RTP. As

discussed in the Applicability section, operation at < 25% RTP

results in sufficient margin to the required limits, and the Main

Reactor Core SLs B 2.1.1 (cont inued)BFN-UNIT 3B 2.0-3 Revision 0 , 25 , 61 December 7, 2010 BASES APPLICABLE2.1.1.1 Fuel Cladding Integrity SAFETY ANALYSES (continued)The SPCB critical power correlation is used for AREVA fuel and is valid at pressures 700 psia and bundle mass fluxes 0.1 x 10 6 lb m/hr-ft 2 (>12,000 lb m/hr, i.e., >

10% core flow, on a per bundle basis). For thermal margin monitoring at 25% power andhigher, the hot channel flow rate will be >28,000 lb m/hr (core flow not less than natural circulation, i.e., 25%-30% core flow for 25% power); therefore, the fuel cladding integrity SL is conservative relative to the applicable range of the SPCB critical power correlation. For operation at low pressures or low flows, another basis is used, as follows:

The static head across the fuel bundles due only to

elevation effects from liquid only in the channel, core

bypass region, and annulus at zero power, zero flow is

approximately 4.5 psi. At all operating conditions, this

pressure differential is maintained by the bypass region of

the core and the annulus region of the vessel. The

elevation head provided by the annulus produces natural

circulation flow conditions which have balancing pressure

head and loss terms inside the core shroud. This natural

circulation principle maintains a core plenum to plenum

pressure drop of about 4.5 to 5 psid along the natural

circulation flow line of the P/F operating map. In the range

of power levels of interest, approaching 25% of rated

power below which thermal margin monitoring is not

required, the pressure drop and density head terms

tradeoff for power changes such that natural circulation

flow is nearly independent of reactor power. This

characteristic is represented by the nearly vertical portion

of the natural circulation line on the P/F operating map.

Analysis has shown that the hot channel flow rate is

>28,000 lb m/hr (>0.23 x 10 6 lb m/hr-ft 2) in the region of operation with power ~25% and core pressure drop of

about 4.5 to 5 psid. Full scale ATLAS test data taken at

pressures from 14.7 psia to 800 psia indicate that the fuel

assembly critical power at 28,000 lb m/hr is approximately 3 Reactor Core SLs B 2.1.1 (cont inued)BFN-UNIT 3B 2.0-4 Revision 0 , 25 , 61 December 7, 2010 BASES APPLICABLE2.1.1.1 Fuel Cladding Integrity (continued)

SAFETY ANALYSES MW t. With the design peaking factors, this corresponds to a core thermal power of more than 50%.

Thus operation up to 25% of rated power with normal

natural circulation available is conservatively acceptable

even if reactor pressure is equal to or below the lower

pressure limit of the SPCB correlation. If reactor power is

significantly less than 25% of rated (e.g., below 10% of

rated), the core flow and the channel flow supported by the

available driving head may be less than 28,000 lb m/hr (along the lower portion of the natural circulation flow

characteristic on the P/F map). However, the critical power

that can be supported by the core and hot channel flow

with normal natural circulation paths available remains well

above the actual power conditions. The inherent

characteristics of BWR natural circulation make power and

core flow follow the natural circulation line as long as

normal water level is maintained.

Thus, operation with core thermal power below 25% of rated

without thermal margin surveillance is conservatively

acceptable even for reactor operations at natural circulation.

Adequate fuel thermal margins are also maintained without

further surveillance for the low power conditions that would be

present if core natural circulation is below the lower flow limit of

the SPCB correlation.

SLC System B 3.1.7 (cont inued)BFN-UNIT 3B 3.1-48 Revision 0 , 29 January 25, 2005 BASES BACKGROUNDThe worst case sodium pentaborate solution concentration (continued)required to shutdown the reactor with sufficient margin to account for 0.05 k/k and Xenon poisoning effects is 9.2 weight percent. This corresponds to a 40 F saturation temperature.

The worst case SLCS equipment area temperature is not predicted to fall below 50 F. This provides a 10 F thermal margin to unwanted precipitation of the sodium pentaborate.

Tank heating components provide backup assurance that the

sodium pentaborate solution temperature will never fall below 50 F but are not required for TS operability considerations. APPLICABLEThe SLC System is manually initiated from the main controlSAFETY ANALYSESroom, as directed by the emergency operating instructions, if the operator believes the reactor cannot be shut down, or kept

shut down, with the control rods. The SLC System is used in

the event that enough control rods cannot be inserted to

accomplish shutdown and cooldown in the normal manner. The

SLC System injects borated water into the reactor core to add

negative reactivity to compensate for all of the various reactivity

effects that could occur during plant operations. To meet this

objective, it is necessary to inject a quantity of boron, which

produces a concentration of 660 ppm of natural boron, in the reactor coolant at 70 F. To allow for imperfect mixing, leakage and the volume in other piping connected to the reactor system, an amount of boron equal to 25% of the amount cited above is

added (Ref. 2). This volume versus concentration limit and 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 entire 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.

SLC System B 3.1.7 (cont inued)BFN-UNIT 3B 3.1-52 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCESR 3.1.7.1 (continued)

REQUIREMENTS pentaborate solution concentration requirements ( 9.2% by weight) and the required quantity of Boron-10 ( 186 lbs)establish the tank volume requirement. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency

is based on operating experience that has shown there are

relatively slow variations in the solution volume.SR 3.1.7.2SR 3.1.7.2 verifies the continuity of the explosive charges in the injection valves to ensure that proper operation will occur if

required. An automatic continuity monitor may be used to

continuously satisfy this requirement. 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 and has demonstrated the reliability of the

explosive charge continuity.SR 3.1.7.3SR 3.1.7.3 requires an examination of sodium pentaborate solution by using chemical analysis to ensure that the proper concentration of boron exists in the storage tank for post-LOCA suppression pool pH control. This parameter is used as inputto determine the volume requirements for SR 3.1.7.1. The concentration is dependent upon the volume of water and quantity of boron in the storage tank.

SR 3.1.7.3 must be performed every 31 days or within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of when boron or water is added to the storage tank solution to determine that the boron solution concentration is within the specified limits. The 31 day Frequency of this Surveillance is appropriate because of the relatively slow variation of boron concentration between surveillances.

SLC System B 3.1.7 (cont inued)BFN-UNIT 3B 3.1-53 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCESR 3.1.7.4 and SR 3.1.7.6 REQUIREMENTS (continued)SR 3.1.7.4 requires an examination of the sodium pentaborate solution by using chemical analysis to ensure that the proper

concentration of boron exists in the storage tank. The

concentration is dependent upon the volume of water and

quantity of boron in the storage tank. SR 3.1.7.6 requires verification that the SLC system conditions satisfy the following

equation:( C )( Q )( E ) ( 13 WT % )( 86 GPM )( 19.8 ATOM % ) > = 1.0 C = sodium pentaborate solution weight percent

concentration

Q = SLC system pump flow rate in gpm

E = Boron-10 atom percent enrichment in the sodium

pentaborate solutionTo meet 10 CFR 50.62, the SLC System must have a minimum flow capacity and boron content equivalent in control capacity

to 86 gpm of 13 weight percent natural sodium pentaborate

solution. The atom percentage of natural B-10 is 19.8%. This

equivalency requirement is met when the equation given above

is satisfied. The equation can be satisfied by adjusting the

solution concentration, pump flow rate or Boron-10 enrichment.

If the results of the equation are < 1, the SLC System is no

longer capable of shutting down the reactor with the margin

described in Reference 2. However, the quantity of stored

boron includes an additional margin (25%) beyond the amount

needed to shut down the reactor to allow for possible imperfect

mixing of the chemical solution in the reactor water, leakage, and the volume in other piping connected to the reactor system.

The sodium pentaborate solution (SPB) concentration is allowed to be > 9.2 weight percent provided the concentration

and temperature of the sodium pentaborate solution are verified SLC System B 3.1.7 BFN-UNIT 3B 3.1-57 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCESR 3.1.7.11 REQUIREMENTS (continued)SR 3.1.7.11 verifies that 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 Flowpath

provides assurance 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 also

does not apply to valves that are locked, sealed, or otherwise

secured in position since they are verified to be in the correct

position prior to locking, sealing or securing. This verification of

valve alignment 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 is

based on engineering judgment and is consistent with the

procedural controls governing valve operation that ensures

correct valve positions. REFERENCES1.10 CFR 50.62.2.FSAR, Section 3.8.4.3. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.4. FSAR, Section 14.6.

APLHGR B 3.2.1 (continued)

BFN-UNIT 3B 3.2-3b Revision 25 , 61 December 7, 2010 BASES (continued) APPLICABILITYAPLHGR limits are primarily derived from fuel design evaluations and LOCA and transient analyses assumed to occur at high power levels. Design calculations 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 scram function provides prompt scram 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 is operating with substantial margin to the APLHGR limits; thus, this LCO is not required.

APLHGR B 3.2.1 (continued)

BFN-UNIT 3B 3.2-4 Amendment No. 213 September 03, 1998 BASES (continued)

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 should be taken to

restore the APLHGR(s) to within the required limits such that

the plant operates within analyzed conditions and within design limits of the fuel rods. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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. SURVEILLANCESR 3.2.1.1 REQUIREMENTS APLHGRs are required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is

based on both engineering judgment and recognition of the

slowness of changes in power distribution during normal

operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

MCPR B 3.2.2 (continued)

BFN-UNIT 3B 3.2-7 Revision 25 , 61 Amendment No. 216 December 7, 2010 BASES APPLICABLEevaluated are loss of flow, increase in pressure and power, SAFETY ANALYSESpositive reactivity insertion, and coolant temperature decrease. (continued)The limiting transient yields the largest change in CPR (CPR).When the largest CPR is added to the MCPR SL, the required operating limit MCPR is obtained.

The MCPR operating limits derived from the transient analysis are dependent on the operating core flow and power to ensure adherence to fuel design limits during the worst transient that

occurs with moderate frequency. Flow dependent MCPR (MCPR f) limits are determined by steady-state thermal hydraulic methods using the three-dimensional BWR simulator code (Reference 12) and the multichannel thermal hydraulic code (Reference 13). The operating limit is dependent on the

maximum core flow limiter setting in the Recirculation Flow

Control System.

Power-dependent MCPR limits (MCPR p) are determined by the three-dimensional BWR simulator code (Ref. 12) and the one-dimensional transient codes (Refs. 14 and 15). 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 scrams are

bypassed, high and low flow MCPR p operating limits are provided for operating between 25% RTP and the previously

mentioned bypass power level.

The MCPR satisfies Criterion 2 of the NRC Policy Statement(Ref. 7).

MCPR B 3.2.2 (continued)

BFN-UNIT 3B 3.2-8 Revision 25 Amendment No. 213 March 12, 2004 BASES (continued)

LCO The MCPR operating limits specified in the COLR are the result of the Design Basis Accident (DBA) and transient analysis.

Additional MCPR operating limits may be provided in the COLR to support analyzed equipment out-of-service operation. The operating limit MCPR is determined by the larger of the MCPR f and MCPR p limits. APPLICABILITYThe 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 minimum

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 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 range

of power and flow conditions. These studies 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 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.

MCPR B 3.2.2 (continued)

BFN-UNIT 3B 3.2-9 Amendment No. 213 September 03, 1998 BASES (continued)

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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 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 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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.

MCPR B 3.2.2 (continued)

BFN-UNIT 3B 3.2-10 Revision 25 Amendment No. 213 March 12, 2004 BASES (continued) SURVEILLANCESR 3.2.2.1 REQUIREMENTS The MCPR is required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is

based on both engineering judgment and recognition of the

slowness of changes in power distribution during normal

operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.SR 3.2.2.2 Because the transient analysis takes credit for conservatism in the scram speed performance, it must be demonstrated that the

specific scram speed distribution is consistent with that used in the transient analysis. SR 3.2.2.2 determines the actual scram speed distribution and compares it with the assumed distribution. The MCPR operating limit is determined basedeither on the applicable limit associated with scram times of LCO 3.1.4, "Control Rod Scram Times," or the nominal scramtimes. The scram speed-dependent MCPR limits are contained in the COLR. This determination must be performed within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after each set of control rod scram time tests required bySR 3.1.4.1 and SR 3.1.4.2 because the effective scram speed distribution may change during the cycle. The 72-hour Completion Time is acceptable due to the relatively minor changes in the actual control rod scram speed distribution expected during the fuel cycle.

LHGR B 3.2.3 (continued)

BFN-UNIT 3B 3.2-13a Revision 25 , 61 December 7, 2010 BASES (continued)

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. Additional LHGR

operating limits adjustments may be provided in the COLR to

support analyzed equipment out-of-service operation.

Additional LHGR operating limits adjustments may be provided in the COLR to support analyzed equipment out-of-service operation. APPLICABILITYThe 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.

LHGR B 3.2.3 (continued)

BFN-UNIT 3B 3.2-14 Amendment No. 213 September 03, 1998 BASES (continued)

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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 is reduced to < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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.

LHGR B 3.2.3 BFN-UNIT 3B 3.2-15 Amendment No. 213 September 03, 1998 BASES (continued) SURVEILLANCESR 3.2.3.1 REQUIREMENTS The LHGR is required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is

based on both engineering judgment and recognition of the

slow changes in power distribution during normal operation.

The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels. REFERENCES1.FSAR, Chapter 14.2.FSAR, Chapter 3.3.NUREG-0800, Standard Review Plan 4.2,Section II.A.2(g), Revision 2, July 1981.4.NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-5 Revision 0 BASES APPLICABLE The trip setpoints are then determined accounting for the SAFETY ANALYSES, remaining in strument errors (e.g., drift). The trip setpoints LCO, and derived in this manner pr ovide adequate protection because APPLICABILITY instrumentation uncertain ties, process effects, calibration (continued) tolerances, instrument dr ift, and severe environmental effects (for channels that must func tion 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 or other specified conditions in the Table, which may require an RPS trip to mitigat e the consequences of a design basis accident or transient. To ensure a reliable scram function, a combination of Functions are required in each MODE to

provide primary and diverse initiation signals.

The only MODES specified in Table 3.3.1.1-1 are MODES 1 (which encompasses 30% RTP) and 2, and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies. No RPS Function is required in MODES 3 and 4 since all control rods are fu lly inserted and the Reactor Mode Switch Shutdown Position control rod withdrawal block (LCO 3.3.2.1) does not allow an y control rod to be withdrawn.

In MODE 5, control rods withdraw n from a core cell containing no fuel assemblies do not affect t he reactivity of the core and, therefore, are not required to have the capability to scram.

Provided all other control rods remain inserted, no RPS function

is 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.

The specific Applicable Safety Analyses, LCO, and Applicability

discussions are listed below on a Function by Function basis.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-10 Amendment No. 213 September 03, 1998 BASES APPLICABLE 2.a. Average Power Range Monitor Neutron Flux - High, SAFETY ANALYSES, (Setdown)

LCO, and APPLICABILITY For operation at low power (i.e., MODE 2), the Average Power (continued) Range Monitor Neutron Flux - High, (Setdown) Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operatin g 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 r un position, reactor power does not exceed 25% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow. Theref ore, it indirectly prevents fuel damage during significant reacti vity increases with THERMAL POWER < 25% RTP.

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 sinc e the potential for criticality exists. In MODE 1, the Average Power Range Monitor Neutron Flux - High Function provides protection against reactivity

transients and the RWM and rod block monitor protect against

control rod withdrawal error events.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-15a Amendment No. 221 September 27, 1999 BASES APPLICABLE 2.f. Oscillation Power Range Monitor (OPRM) Upscale SAFETY ANALYSES, LCO, and The OPRM Upscale Function provides compliance with GDC 10 APPLICABILITY and GDC 12, thereby providing protection from exceeding the (continued) fuel MCPR safety limit (S L) due to anticipated thermal hydraulic power oscillations.

References 13, 14, and 15 describe three algorithms for detecting thermal hydraulic inst ability related neutron flux oscillations: the period based de tection algorith m, the amplitude based algorithm, and the growth ra te algorithm. All three are implemented in the OPRM Upscal e Function, but the safety analysis takes credit only for the period based detection algorithm. The remaining algori thms provide defense in depth and additional protection against unanticipated oscillations.

OPRM Upscale Function OPERABILITY for Technical Specification purposes is based only on the period based detection algorithm.

The OPRM Upscale Function receives input signals from the local power range monitors (LPRMs) within the reactor core, which are combined into "cells

" for evaluation of the OPRM algorithms.

The OPRM Upscale Function is required to be OPERABLE when the plant is in a region of power flow operation where anticipated events could lead to thermal hydraulic instability and related neutron flux oscillations. Within this region, the automatic trip is enabled when THERMAL POWER, as indicated by the APRM Simulated Thermal Power, is 25% RTP and reactor core flow, as i ndicated by recirculation drive flow is 60% of rated flow, the oper ating region where actual thermal hydraulic oscillations ma y occur. Requiring the OPRM Upscale Function to be OPERABLE in MODE 1 provides consistency with operability requirements for other APRM functions and assures that the OPRM Upscale Function is OPERABLE whenever reactor power could increase into the region of concern with out operator action.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-23 Amendment No. 213 September 03, 1998 BASES APPLICABLE 8. Turbine Stop Valve - Closure (continued) SAFETY ANALYSES, LCO, and Turbine Stop Valve - Closure signals are initiated from position APPLICABILITY switches located on each of the four TSVs. Two independent position switches are associated with each stop valve. One of the two switches provides input to RPS trip system A; the other, to RPS trip system B. Thus, each RPS trip system receives an

input from four Turbine Stop Valve - Closure channels, each consisting of one position switch.

The logic for the Turbine Stop Valve - Closure Function is such that three or more TSVs must

be closed to produce a scram. This Function must be enabled at THERMAL POWER 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this function.

The Turbine Stop Valve - Closure 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 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 Func tion if any three TSVs should close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is 30% RTP.

This Function is not required when THERMAL POWER is < 30% 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.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-24 Amendment No. 213 September 03, 1998 BASES APPLICABLE 9. Turbine Control Valve Fa st Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and APPLICABILITY Fast closure of the TCVs re sults in the loss of a heat sink that (continued) 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 clos ure 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 7. For this event, the reactor scram

reduces the amount of energy re quired 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 electrohydraulic control (EHC) fluid pressure at each control valve. One pressure switch is

associated with each control valve, and the signal from each switch is assigned to a separat e RPS logic channel. This Function must be enabled at THERMAL POWER 30% RTP.

This is normally accomplished automatically by pressure

transmitters sensing turbine fi rst stage pressure; therefore, opening the turbine bypass valves may affect this function.

The Turbine Control Valve Fast Closure, Trip Oil Pressure -

Low Allowable Value is selected high enough to detect imminent TCV fast closure.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-25 Amendm ent No. 213, Revision 41 November 09, 2006 BASES APPLICABLE 9. Turbine Control Valve Fa st Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and (continued)

APPLICABILITY

Four channels of Turbine Contro l 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, consist ent with the analysis assumptions, whenever THERMAL POWER is 30% RTP. This Function is not required when THERMAL POWE R is < 30% 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.

For this instrument function, the nominal trip setpoint including the as-left tolerances is defi ned as the LSSS. The acceptable as-found band is based on a statistical combination of possible measurable uncertainties (i.e., setting tolerance, drift, temperature effects, and meas urement and test equipment). During instrument calibrations, if the as-found setpoint is found to be conservative with respect to the Allowable Value, but outside its acceptable as-f ound band (tolerance range), as defined by its associated Survei llance Requirement procedure, then there shall be an initial determination to ensure confidence that the channel can perform as required before returning the channel to service in accordance with the Surveillance. The technician performing the Surveillance will evaluate the instrument's ability to maintain a stable setpoint within the as-left tolerance. The technician's ev aluation will be reviewed by on shift personnel during the approval of the Surveillance data prior to returning the channel back to se rvice at the completion of the Surveillance. This shall consti tute the initial determination of operability. If a channel is found to exceed the channel's Allowable Value or c annot be reset within the RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-37 Amendment No. 213 September 03, 1998 BASES SURVEILLANCE SR 3.3.1.1.2 REQUIREMENTS (continued) To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor power calculated from a heat balance. The Frequency of once per 7 days is based on minor c hanges in LPRM sensitivity, which could affect the APRM reading, between performances of

SR 3.3.1.1.7.

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 mainta in 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 satisfactor ily performed within the last 7 days, in accordance with SR 3.0.

2. A Note is provided which allows an increase in THERMAL POWER above 25% if the 7 day Frequency is not met per SR 3.

0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-45 Amendment No. 215 November 30, 1998 BASES SURVEILLANCE SR 3.3.1.1.15 REQUIREMENTS (continued) This SR ensures that scrams initiated from the Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions wi ll not be inadvertently bypassed when THERMAL POWER is 30% RTP. This involves calibration of the bypass channels (PIS-1-81A, PIS-1-81B, PIS-1-91A, and PIS-1-91B). Adequate margins for the

instrument setpoint methodolog ies are incorporated into the actual setpoint.

If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at 30% RTP, either due to open main turbine bypass valve(s) or other reasons), then the affected Turbine Stop Valve - Closure 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 (nonb ypass). If placed in the nonbypass condition (Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low

Functions are enabled), this SR is met and the channel is considered OPERABLE.

The Frequency of 24 months is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-45a Amendment No. 221 September 27, 1999 BASES SURVEILLANCE SR 3.3.1.1.17 REQUIREMENTS (continued) This SR ensures that scrams initiated from OPRM Upscale Function (Function 2.f) will not be inadvertently bypassed when THERMAL POWER, as indica ted by the APRM Simulated Thermal Power, is 25% RTP and core flow, as indicated by recirculation drive flow, is

< 60% rated core flow. This normally involves confirming the bypass setpoints. Adequate margins for the instrument setpoint methodol ogies are incorporated into the actual setpoint. The actual surveillance ensures that the OPRM Upscale Function is enabled (not bypassed) for the correct values of APRM Simulated Thermal Power and recirculation drive flow. Other surveillances ensure that the APRM Simulated Thermal Power and recirculation flow properly correlate with THERMAL POWER and core flow, respectively.

If any bypass setpoint is nonconservative (i.e., the OPRM Upscale Function is bypassed when APRM Simulated Thermal Power 25% RTP and recirculation drive flow

< 60% rated), then the affected channel is co nsidered inoperable for the OPRM Upscale Function. Alternatively, the bypass setpont may be adjusted to place the channel in a conservative condition (unbypass). If placed in the unbypassed condition, this SR is met and the channel is considered OPERABLE.

The frequency of 24 months is based on engineering judgment and reliability of the components.

Feedwater and Main Turbine High Wa ter Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 3 B 3.3-76 Amendment No. 213 September 03, 1998 BASES (continued)

APPLICABLE The feedwater and main turbine high water level trip SAFETY ANALYSES instrumentation is assum ed to be capable of providing a turbine trip in the design basis transient analysis for a feedwater controller failure, maximum demand event (Ref. 1). The reactor vessel high water level trip indirectly initiates a reactor scram

from the main turbine trip (above 30% RTP) and trips the

feedwater pumps, thereby terminating the event. The reactor scram mitigates the reduction in MCPR.

Feedwater and main turbine high water level trip instrumentation satisfies Criterion 3 of the NRC Policy Statement (Ref. 3).

LCO The LCO requires two channels of the Reactor Vessel Water Level - High instrumentation per trip system to be OPERABLE to ensure that no single instru ment failure will prevent the feedwater pump turbines and ma in turbine trip on a valid Reactor Vessel Water Level - High signal. Both channels in

either trip system are needed to pr ovide trip signals in order for the feedwater and main turbine trips to occur. Each channel

must have its setpoint set withi n the specified Allowable Value of SR 3.3.2.2.3. The Allowable Value is se t to ensure that the thermal limits are not exceeded during the event. The actual setpoint is calibrated to be consistent with the applicable setpoint methodology assumptions.

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 successive CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.

Feedwater and Main Turbine High Wa ter Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 3 B 3.3-77 Revision 25 Amendment No. 213 March 12, 2004 BASES LCO Trip setpoints are those pr edetermined values of output at (continued) 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 out put value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analyt ic limits are derived from the limiting values of the process parameter s obtained from the safety analysis. The Allowabl e Values are derived from the analytic limits, corrected for calib ration, process, and some of the instrument errors. A channel is inoperable if its actual trip setpoint is not within its requir ed Allowable Value. The trip setpoints are then determined a ccounting 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 environmental effects (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.

APPLICABILITY The feedwater and main turbine high water level trip instrumentation is required to be OPERABLE at 25% RTP to ensure that the fuel cladding in tegrity Safety Limit and the cladding 1% plastic strain lim it are not violated during the feedwater controller failure, maximum demand event. As

discussed in the Bases for LCO 3.2.1, "Average Planar Linear

Heat Generation Rate (APLHGR)," LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)

," and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)," sufficient margin to these limits exists below 25% RTP; t herefore, these requirements are only necessary when operating at or above this power level.

Feedwater and Main Turbine High Wa ter Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 3 B 3.3-80 Amendment No. 213 September 03, 1998 BASES ACTIONS B.1 (continued)

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is suff icient for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of f eedwater and main turbine high water level trip instrumentation occurring during this period. It is also consistent with the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in

LCO 3.2.2 for Required Action A.1, since this instrumentation's purpose is to preclude a MCPR violation.

C.1 With the required channels not re stored to OPERABLE status or placed in trip, THERMAL POWER must be reduced to

< 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. As discussed in the Applicability

section of the Bases, operation below 25% RTP results in sufficient margin to the required limits, and the feedwater and main turbine high water level trip instrumentation is not required to protect fuel integrity during the feedwater controller failure, maximum demand event. The allowed Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is based on operating ex perience to reduce THERMAL POWER to < 25% RTP from full pow er conditions in an orderly manner and without chall enging plant systems.

SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for performance of required Surveill ances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains feedwater

and main turbine high water level trip capability. Upon

completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channe l must be returned to OPERABLE status

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 3 B 3.3-109 Revision 25 , 61 Amendment No. 213 December 7, 2010 BASES BACKGROUND Each EOC-RPT trip system is a two-out-of-two logic for each (continued) Function; thus, either two TSV - Closure 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 syst em 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 and the TCV Fast Closure, Trip Oil SAFETY ANALYSES, Pressure - Low Functions are designed to trip the recirculation LCO, and pumps in the event of a turb ine trip or generator load rejection APPLICABILITY to mitigate the increase in neutron flux, heat flux, and reactor pressure, and to increase the margin to the MCPR SL and LHGR limits. The analytical methods and assumptions used in

evaluating the turbine trip and generator load rejection are summarized in References 2, 3, and 4.

To mitigate pressurization transi ent effects, the EOC-RPT must trip the recirculation pumps afte r initiation of cl osure movement of either the TSVs or the TCVs. The combined effects of this trip and a scram reduce fuel bundle power more rapidly than a

scram alone, resulting in an increased margin to the MCPR SL

and LHGR limits. Alternatively, MCPR limits for an inoperable EOC-RPT, as specified in the CO LR, are sufficient to prevent

violation of the MCPR Safety Li mit and fuel mechanical limits.

The EOC-RPT function is automatically disabled when turbine first stage pressure is < 30% RTP.

EOC-RPT instrumentation sati sfies Criterion 3 of the NRC Policy Statement (Ref. 6).

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 3 B 3.3-112 Revision 25 , 61 Amendment No. 213 December 7, 2010 BASES APPLICABLE Turbine Stop Valve - Closure (continued) SAFETY ANALYSES, LCO, and Closure of the TSVs is dete rmined by measuring the position of APPLICABILITY each valve. There are two separate position signals associated with each stop valve, the signal from each switch being assigned to a separate trip channel. The logic for the TSV -

Closure Function is such that two or more TSVs must be closed to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves

may affect this function. To consider this function OPERABLE, bypass of the function must not occur when bypass valves are open. Four channels of TSV - Closure, with two channels in each trip system, are availabl e 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 Allowable Value is selected to detect imminent TSV

closure.

This protection is required, c onsistent with the safety analysis assumptions, whenever THERMAL POWER is 30% RTP. Below 30% RTP, the Reactor Vessel Steam Dome Pressure -

High and the Average Power Ra nge Monitor (APRM) Fixed Neutron Flux - High Functions of the Reactor Protection System (RPS) are adequate to maintain the necessary margin to the MCPR SL and LHGR limits.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 3 B 3.3-113 Revision 25 Amendment No. 213 March 12, 2004 BASES APPLICABLE Turbine Control Valve Fast Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and APPLICABILITY Fast closure of the TCVs during a generator load rejection (continued) results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transie nts 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 va lves. The EOC-RPT decreases reactor power and aids the reactor scram in ensuring that the MCPR SL and LHGR limits are not exceeded during the worst case transient.

Fast closure of the TCVs is determined by measuring the

electrohydraulic control fluid pre ssure at each control valve.

There is one pressure switch associated with each control valve, and the signal from each switch is assigned to a separate trip channel. The logic for t he TCV Fast Closure, Trip Oil Pressure - Low Function is such that two or more TCVs must be closed (pressure switch trips) to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 30% RTP.

This is normally accomplished automatically by pressure transmitters sensing turbine fi rst stage pressure; therefore, opening the turbine bypass valves may affect this function. To

consider this function OPERABLE , bypass of the function must not occur when bypass valves are open. Four channels of TCV Fast Closure, Trip Oil Pressure - Low, with two channels in each trip system, are availabl e 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 immi nent TCV fast closure.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 3 B 3.3-114 Amendment No. 213 September 03, 1998 BASES APPLICABLE Turbine Control Valve Fast Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and (continued)

APPLICABILITY

This protection is required c onsistent with the safety analysis whenever THERMAL POWER is 30% RTP. Below 30% RTP, the Reactor Vessel Steam Dome Pressure - High and the APRM Fixed Neutron Flux - Hi gh Functions of the RPS are adequate to maintain the necessary safety margins.

ACTIONS A Note has been provided to modify the ACTIONS related to EOC-RPT instrumentation channel

s. 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 sepa rate 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 inst rumentation channel.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 3 B 3.3-116 Revision 25 , 61 Amendment No. 213 December 7, 2010 BASES ACTIONS B.1 and B.2 (continued)

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 capabilit

y. 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.

Alternately, Required Action B.2 requires the MCPR and LHGR limits for inoperable EOC-RPT, as specified in the COLR, to be

applied. This also restores the margin to MCPR and LHGR limits assumed in the safety analysis.

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is suff icient time 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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in LCO 3.2.2 for Required Action A.1, since this instrumentation's purpose is to preclude a MCPR or LHGR violation.

C.1 With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to < 30% RTP within

4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Comp letion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is reasonable, based on operating experience, to reduce THERMAL POWER to < 30% RTP fr om full power conditions in an orderly manner and without challenging plant systems.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 3 B 3.3-118 Amendment No. 215 November 30, 1998 BASES SURVEILLANCE SR 3.3.4.1.2 REQUIREMENTS (continued) This SR ensures that an EOC-RPT initiated from the TSV - Closure and TCV Fast Closure, Trip Oil Pressure - Low

Functions will not be inadvertently bypassed when THERMAL POWER is 30% RTP. This involves calibration of the bypass channels. Adequate margins fo r the instrument setpoint methodologies are incorporated into the actual setpoint. If any bypass channel's setpoint is noncons ervative (i.e., the Functions are bypassed at 30% RTP, either due to open main turbine bypass valves or other reasons), the affected TSV - Closure and TCV Fast Closure, Trip Oil Pressure - Low Functions are considered inoperable. Alter natively, the bypass channel can be placed in the conservative condition (nonbypass). If placed

in the nonbypass condition, th is SR is met with the channel considered OPERABLE.

The Frequency of 24 months is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

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 param eter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account fo r instrument drifts between successive calibrations consist ent with the plant specific setpoint methodology. The Frequency is based upon the assumption of an 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

Jet Pumps B 3.4.2 BFN-UNIT 3 B 3.4-16 Revision 0 BASES SURVEILLANCE SR 3.4.2.1 (continued)

REQUIREMENTS

Note 2 allows this SR not to be performed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after THERMAL POWER exceeds 25% of 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. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is an acceptable time to establish conditions appropriate to perform this SR.

REFERENCES 1. FSAR, Section 14.6.3.

2. GE Service Information Letter No. 330, "Jet Pump Beam Cracks," June 9, 1980.

3. NUREG/CR-3052, "Closeout of IE Bulletin 80-07: BWR Jet Pump Assembly Failure," November 1984.

4. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

Primary Containment B 3.6.1.1

(continued)

BFN-UNIT 3 B 3.6-3 Amendment No. 214 September 08, 1998 BASES APPLICABLE The maximum allowable leakage rate for the primary SAFETY ANALYSES containment (L a) is 2.0% by weight of the containment air per (continued) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the design bas is LOCA maximum peak containment pressure (P a) of 50.6 psig (Ref. 1).

Primary containment satisfies Criterion 3 of the NRC Policy Statement (Ref. 6).

LCO Primary containment OPERABILITY is maintained by limiting leakage to 1.0 L a , except prior to the first startup after performing a required Primary Containment Leakage Rate Testing Program leakage test. At this time, applicable leakage limits must be met. Compliance with this LCO will ensure a

primary containment configur ation, including equipment hatches, that is structurally s ound and that will lim it leakage to those leakage rates assumed in the safety analyses.

Individual leakage rates specif ied for the prim ary containment air lock 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 primar y 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, prim ary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of

radioactive material from primary containment.

Primary Containment B 3.6.1.1 BFN-UNIT 3 B 3.6-6 Amendment No. 215 November 30, 1998 BASES SURVEILLANCE SR 3.6.1.1.2 (continued)

REQUIREMENTS

Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber and veri fying that the pressure in either the suppression chamber or the drywell does not change by more than 0.25 inch of wate r per minute over a 10 minute period. The leakage test is per formed every 24 months. The 24 month Frequency was developed considering it is prudent that this Surveillance be performed during a unit outage and

also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs.

REFERENCES 1. FSAR, Section 5.2.

2. FSAR, Section 14.6.

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

4. NEI 94-01, Revision O, "Industr y Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J." 5. ANSI/ANS-56.8-1994, "Ame rican National Standard for Containment System Leakage Testing Requirement."

6. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

Primary Containment Air Lock B 3.6.1.2

(continued)

BFN-UNIT 3 B 3.6-8 Amendment No. 214 September 08, 1998 BASES BACKGROUND the air lock to remain open for extended periods when frequent (continued) primary containment entry is necessary. Unde r some conditions allowed by this LCO, the prim ary containment may be accessed through the air lock, when the interlock mechanism has failed, by manually performing the interlock function.

The primary containment air lock forms 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 t hat assumed in the unit safety analysis.

APPLICABLE The DBA that postulates the maximum release of radioactive SAFETY ANALYSES material within primary containment is a LOCA. In the analysis of this accident, it is assum ed that primary containment is OPERABLE, such that releas e of fission products to the environment is controlled by the rate of primary containment leakage. The primar y containment is designed with a maximum allowable leakage rate (L a) of 2.0% by weight of the containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the calculat ed maximum peak containment pressure (P a) of 50.6 psig (Ref. 3). This allowable leakage rate forms the basis for the acceptance criteria imposed on the SRs associated with the air lock.

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.

The primary containment air lo ck satisfies Criterion 3 of the NRC Policy Statement (Ref. 4).

CAD System B 3.6.3.1

(continued)

BFN-UNIT 3 B 3.6-90 Revision 0 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.1 Containment Atmosphere Dilution (CAD) System BASES BACKGROUND The CAD Syst em functions to maintain combustible gas concentrations within the primary containment at or below the flammability limits following a postulated loss of coolant accident (LOCA) by diluting hydrogen and oxygen with nitrogen. To ensure that a combustible gas mixture does not occur, oxygen

concentration is kept < 5.0 volume percent (v/o), or hydrogen

concentration is kept < 4.0 v/o.

The CAD System is manually in itiated and consists of two independent, 100% capacity sub systems, each of which is capable of supplying nitrogen through separate piping systems to the drywell and suppression chamber of each unit. Each

subsystem includes a liquid nitrogen supply tank, ambient vaporizer, electric heater, and a m anifold with branches to each primary containment (for Unit s 1, 2, and 3).

The nitrogen storage tanks each contain 2500 gal, which is adequate for 7 days of CAD subsystem operation.

The CAD System operates in conjunction with emergency

operating procedures that ar e used to reduce primary containment pressure peri odically during CAD System operation. This combination results in a feed and bleed approach to maintaining hydrogen and oxygen concentrations below combustible levels.

CAD System B 3.6.3.1 (continued)

BFN-UNIT 3 B 3.6-95 Amendment No. 225 Revision 0 May 24, 2000 BASES (continued)

SURVEILLANCE SR 3.6.3.1.1 REQUIREMENTS Verifying that there is 2500 gal of liquid nitrogen supply in each nitrogen storage tank will ensure at least 7 days of post-LOCA CAD operation. This minimum volume of liquid

nitrogen allows sufficient time a fter an accident to replenish the nitrogen supply for long term inerti ng. This is verified every 31 days to ensure that the system is capable of performing its intended function when required. The 31 day Frequency is based on operating experience, which has shown 31 days to be an acceptable period to verify the liquid nitrogen supply and on

the availability of other hydrogen mitigating systems.

SR 3.6.3.1.2

Verifying the correct alignment for manual, power operated, and

automatic valves in each of the CAD subsystem flow paths provides assurance that the prop er flow paths exist for system operation. This SR does not appl y to valves that are locked, sealed, or otherwise secured in position, since these valves

were verified to be in the co rrect position prior to locking, sealing, or securing.

A valve is also allowed to be in the nonaccident position

provided it can be aligned to t he accident position within the time assumed in the accident analysis. This is acceptable because the CAD System is manually initiated. This SR 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 mis positioned are in the correct position.

CAD System B 3.6.3.1 BFN-UNIT 3 B 3.6-96 Amendment No. 225 Revision 0 May 24, 2000 BASES SURVEILLANCE SR 3.6.3.1.2 (continued)

REQUIREMENTS

The 31 day Frequency is appropriate because the valves are

operated under procedural control, improper valve position would only affect a single subsystem, the probability of an event requiring initiation of the system is low, and the system is a manually initiated system.

REFERENCES 1. AEC Safety Guide 7, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident, March 10, 1971.

2. FSAR, Section 5.2.6.

3. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-1 Revision 73 Amendment No. 214 January 3, 2013 B 3.7 PLANT SYSTEMS B 3.7.1 Residual Heat Removal Service Water (RHRSW) System and Ultimate Heat Sink (UHS)

BASES BACKGROUND The RHRSW System is designed to provide cooling water for the Residual Heat Removal (RHR) System heat exchangers, required for a safe reactor shut down following a Design Basis Accident (DBA) or transient.

The RHRSW System is operated whenever the RHR heat exchanger s are required to operate in the shutdown cooling mode or in the suppression pool cooling or spray mode of the RHR System.

The RHRSW System is common to the three BFN units and consists of the UHS and four independent and redundant subsystems, each of which f eeds one RHR heat exchanger in each unit. Each subsystem is made up of a header, two 4500 gpm pumps, a suction source, valves, piping, and associated

instrumentation. Two subsyst ems, with one pump operating in each subsystem, are capable of pr oviding 100% of the required cooling capacity to maintain safe shutdown conditions for one unit. The RHRSW System is designed with sufficient redundancy so that no single active component failure can prevent it from achieving its design function. The RHRSW System is described in the FSAR, Section 10.9 (Ref. 1).

Cooling water is pumped by the RHRSW pumps from the Wheeler Reservoir through the tube side of the RHR heat exchangers, and discharged back to the Wheeler Reservoir.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-2 Revision 73 Amendment No. 214 January 3, 2013 BASES BACKGROUND The system is initiated manually from each of the three units (continued) control r ooms. If operating during a loss of coolant accident (LOCA), the system is automatic ally tripped on degraded bus voltage to allow the diesel gener ators to automatically power only that equipment necessary to reflood the core. The system can be manually started any time the degraded bus voltage signal clears, and is assumed to be manually started within 10 minutes after the LOCA.

APPLICABLE The RHRSW Syst em removes heat from the suppression pool SAFETY ANALYSES to limit the suppre ssion pool temperature and primary containment pressure following a LOCA. This ensures that the primary containment can perform its function of limiting the release of radioactive materials to the environment following a

LOCA. The ability of the RHR SW System to support long term cooling of the reactor or primar y containment is discussed in the FSAR, Chapters 5 and 14 (Refs. 2 and 3, respectively). These analyses explicitly assume that the RHRSW System will provide adequate cooling support to the equipment required for safe

shutdown. These analyses includ e the evaluation of the long term primary containment response after a design basis LOCA.

The safety analyses for long term cooling were performed for various combinations of RHR System failures and considers the

number of units fueled. With one unit fueled, the worst case single failure that would affect the performance of the RHRSW System is any failure that would disable two subsystems of the RHRSW System.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-3 Revision 73 Amendment No. 214 January 3, 2013 BASES APPLICABLE With two and three units fueled, a worst case single failure SAFETY ANALYSES could also include the loss of two RHRSW pumps caused by (continued) losing a 4 kV shutdown board since there are certain alignment configurations that allow two RHRSW pumps to be powered from the same 4 kV shutdown bo ard. As discussed in the FSAR, Section 14.6.3.3.2 (Ref.

4) for these analyses, manual initiation of the OPERABLE RHRSW subsystems and the associated RHR System is assumed to occur 10 minutes after a

DBA. The analyses assume that there are two RHRSW subsystems operating in each unit, with one RHRSW pump in each subsystem capable of producing 4000 gpm of flow. In this case, the maximum suppression chamber water temperature and pressure are 177°F (as reported in Reference 3) and 50.6 psig, respectively, well below the design temperature of

281°F and maximum allowable pressure of 62 psig.

The RHRSW System together with the UHS satisfies Criterion 3

of the NRC Policy Statement (Ref 5).

LCO Four RHRSW subsystems are required to be OPERABLE to provide the required redundancy to ensure that the system

functions to remove post a ccident heat loads, assuming the worst case single active failure o ccurs coincident with the loss of offsite power. Additionally, since the RHRSW pumps are

shared between the three BFN unit s, the number of OPERABLE pumps required is also dependent on the number of units

fueled.

An RHRSW subsystem is considered OPERABLE when:

a. At least one RHRSW pump (i.e., one required RHRSW pump) is OPERABLE, and

b. An OPERABLE flow path is capable of taking suction from the intake structure and tr ansferring the water to the associated RHR heat exchanger at the assumed flow rate.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-4 Revision 44 , 73 Amendment No. 214 January 3, 2013 BASES LCO In addition to the required number of OPERABLE subsystems, (continued) there must be an adeq uate number of pumps OPERABLE to provide cooling for the fueled non-accident units.

The total number of required RHRSW pumps must take into consideration the required numbe r of pumps required for the specific unit along with the number of pumps required for other units that are fueled. Hence, when one unit contains fuel, four RHRSW pumps are required to be OPERABLE. When two units contain fuel, six RHRSW pumps are required to be OPERABLE. When three units contain fuel, eight RHRSW pumps are required to be OPERABLE. The minimum specified number of pumps gives consider ation to all units capable of producing heat in aggregate and a ccounts for a single active failure. The above pre-accident configuration ensures that during a design bases accident with a postulated single active failure, the resulting configuration for the accident unit has at least two RHRSW subsystems OPERABLE to supply 100 percent of the long term RHR cooling water. The resulting configuration for the non-accident units has at least two RHRSW subsystems per unit OPERABLE to supply 100 perc ent of the required cooling capacity to maintain safe shutdown conditions.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-4a Revision 44 , 73 January 3, 2013 BASES LCO The number of required OPERABLE RHRSW pumps (continued) is modified by a Note which specifies that the number of required RHRSW pumps may be reduced by one for each

fueled unit that has been in MODE 4 or 5 for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

This Note acknowledges the fa ct that decay heat removal requirements are substantially reduced for fueled units in

MODE 4 or 5 for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The OPERABILITY of the UHS for RHRSW is based on having

a maximum water temperature wit hin the limits specified in Figure 3.7.1-1.

APPLICABILITY In MODES 1, 2, and 3, the RHRSW System and UHS are required to be OPERABLE to s upport the OPERABILITY of the RHR System for primary containment cooling (LCO 3.6.2.3, "Residual Heat Removal (RHR) Suppression Pool Cooling," and LCO 3.6.2.4, "Residual Heat Removal (RHR) Suppression Pool

Spray") and decay heat removal (L CO 3.4.7, "Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown"). The Applicability is therefore c onsistent with the requirements of these systems.

In MODES 4 and 5, the OPER ABILITY requirements of the RHRSW System and UHS are dete rmined by the systems they support.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-5 Revision 73 Amendment No. 214 January 3, 2013 BASES (continued)

ACTIONS Since the RHRSW System is common to all three units, the following requirements must be followed when multiple units contain fuel:

a. With one or more requir ed RHRSW pumps inoperable, all applicable ACTIONS must be entered for each unit.

b. With one or more RHRSW subsystem inoperable, all applicable ACTIONS for inoperable subsystems must be entered on the unit(s) that hav e the inoperable subsystem.

The Required Actions and associated Completion Times of Conditions A, B, C, and D are based on a reduction in redundancy of the RHRSW Syst em, not a loss of RHRSW safety function. The Required Actions and associated Completion Times of Conditions E, F, and G consider that the RHRSW safety function is lost.

RHRSW safety function is maintained when at least two RHRSW subsystems, with two separate RHRSW pumps (i.e., one per subsystem), on a per fuel ed unit basis, are OPERABLE. Additionally, the total number of RHRSW pumps must be such that the RHRSW pumps credited for maintaining the RHRSW safety function for a specific unit are not credited for maintaining the RHRSW safety function for a different fueled unit.

When there are three fueled units, the RHRSW safety function is maintained when:

• Two RHRSW subsystems per fueled unit are OPERABLE;

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-5a Revision 73 Amendment No. 214 January 3, 2013 BASES (continued)

ACTIONS

• Six RHRSW pumps are OPERABLE (two RHRSW pumps (continued) per fueled unit);

• Each OPERABLE RHRSW subsystem has one required RHRSW pump OPERABLE; and

• The required RHRSW pump that is OPERABLE in an RHRSW subsystem is not cr edited for maintaining the RHRSW safety function for another fueled unit (i.e., it is not one of the two RHRSW pumps that is required to be OPERABLE for another fueled unit).

When there are two fueled units, the RHRSW safety function is maintained when:

• Two RHRSW subsystems per fueled unit are OPERABLE;

• Four RHRSW pumps are O PERABLE (two RHRSW pumps per fueled unit);

• Each OPERABLE RHRSW subsystem has one required RHRSW pump OPERABLE; and

• The required RHRSW pump that is OPERABLE in an RHRSW subsystem is not cr edited for maintaining the RHRSW safety function for another fueled unit (i.e., it is not one of the two RHRSW pumps that is required to be OPERABLE for another fueled unit).

When there is one fueled unit, the RHRSW safety function is maintained when:

• Two RHRSW subsystems are OPERABLE and

• Two RHRSW pumps are OPERABLE (i.e., one per OPERABLE RHRSW subsystem).

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-5b Revision 73 Amendment No. 214 January 3, 2013 BASES (continued)

ACTIONS When any combination of pump(s) and other subsystem (continued) components, e.g., heat exc hanger(s), are inoper able such that three or more components of t he RHRSW System (on any or all fueled units) are inoperable, the capability to meet the safety function must be evaluated by all fueled units. When an RHRSW pump is credited by one f ueled unit for maintaining the RHRSW safety function, then the other two fueled units cannot also credit this same RHRSW pump with maintaining their RHRSW safety function since t he capacity of a single RHRSW pump is not sufficient to support the required heat removal function of more than one RHR heat exchanger. Therefore, in this condition, the RHRSW pum p credited with maintaining RHRSW safety function on a f ueled unit must be considered inoperable for the other fueled units for purpose of determining if RHRSW safety function is mainta ined. The other fueled units must then include the additio nal inoperable RHRSW pump(s) with the total number of inoperable components when determining if RHRSW safety function is maintained. If RHRSW safety function is deter mined to be lost, then Condition E or F is required to be entered.

The examples, with respect to RHRSW pumps, used in the following descriptions of the AC TIONS assume that all three units are fueled.

A.1 and A.2 With one required RHRSW pum p inoperable, the inoperable RHRSW pump must be restored to OPERABLE status within 30 days. With the unit in th is condition, the remaining OPERABLE RHRSW pumps are adequate to perform.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-6 Revision 73 Amendment No. 214 January 3, 2013 BASES ACTIONS A.1 and A.2 (continued)

the RHRSW heat removal function. However, the overall reliability is reduced because a single failure could result in

reduced primary containment cool ing capability. The 30 day Completion Time is based on the availability of equipment in

excess of normal redundancy requirements and the low

probability of an event occurring requiring RHRSW during this period. Alternatively, five RHRSW pum ps may be verified to be OPERABLE with power being su pplied from separate 4 kV shutdown boards.

Required Action A1 is modified by two Notes. Note 1 indicates that the Required Action is applicable only when two units are fueled. In the two unit fueled condit ion, a single failure (loss of a 4 kV shutdown board) could result in inadequate RHRSW pumps if two pumps are powered from the same power supply.

If five RHRSW pumps are pow ered from separate 4 kV shutdown boards, then no postulated single active failure could occur to prevent the RHRSW system from performing its design function. Operation can continue indefinitely if Required Action A.1 is met.

Note 2 requires only four RHRSW pumps powered from separate 4 kV shutdown boards to be OPERABLE if the other fueled unit has been in MODE 4 or 5 greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This acknowledges the fact that decay heat removal requirements are substantially reduced for fueled units in MODE 4 or 5 for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

These two Notes clarify the situations under which Required Action A.1 would be the appr opriate Required Action.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-6a Revision 73 Amendment No. 214 January 3, 2013 BASES ACTIONS B.1 (continued)

With one RHRSW subsystem inoperable (e.g., one RHR heat exchanger inoperable or an RHRSW header isolated) for reasons other than inoperable RHRSW pumps, which are covered by separate Conditions, the inoperable RHRSW subsystem must be restored to OPERABLE status within 30 days. With the unit in th is condition, the remaining OPERABLE RHRSW subsystems are adequate to perform the

RHRSW heat removal function. However, the overall reliability is reduced because a single failure could result in reduced

primary containment cooling cap ability. The 30 day Completion

Time is based on the availability of equipment in excess of

normal redundancy requirements and the low probability of an event occurring requiring RHRSW during this period.

The Required Action is modified by a Note indicating that the

applicable Conditions of LCO 3.4.7 be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-7 Revision 73 Amendment No. 214 January 3, 2013 BASES ACTIONS C.1 (continued)

With two required RHRSW pumps inoperable (i.e., one required RHRSW pump inoperable in each of the two separate RHRSW subsystems or two RHRSW pumps inoperable in the same RHRSW subsystem), the remaining RHRSW pumps are adequate to perform the RHRSW heat removal function.

However, the overall reliability is reduced because a single failure of the OPERABLE RHRSW pumps could result in a loss of RHRSW function. The seven day Completion Time is based

on the redundant RHRSW capabilities afforded by the

OPERABLE RHRSW pumps and t he low probability of an event occurring during this period.

D.1 With two RHRSW subsystems inoperable (e.g., two RHR heat exchangers inoperable) for reas ons other than inoperable RHRSW pumps, which are covered by separate Conditions, the remaining OPERABLE RHRSW subsystems are adequate to perform the RHRSW heat removal function. However, the

overall reliability is reduced becau se a single failure could result

in reduced primary containment cooling capability. The seven day Completion Time is based on the availability of equipment in excess of normal redundancy requirements and

the low probability of an event occurring requiring RHRSW during this period.

The Required Action is modified by a Note indicating that the

applicable Conditions of LCO 3.4.7 be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-8 Revision 73 Amendment No. 214 January 3, 2013 BASES ACTIONS E.1 (continued)

With three or more requir ed RHRSW pumps inoperable, the RHRSW System is not capabl e of performing its intended function. The requisite number of pumps must be restored to

OPERABLE status within ei ght hours. The eight hour Completion Time is based on the Completion Times provided for the RHR suppression pool cooling and spray functions.

F.1 With three or more required RHRSW subsystems inoperable (e.g., one RHR heat exchanger inoperable in each of three of four separate RHRSW subsystems) for reasons other than inoperable RHRSW pumps, which are covered by separate Conditions, the RHRSW System is not capable of performing its intended function. The requisite number of subsystems must be restored to OPERABLE status within eight hours. The eight hour Completion Time is based on the Completion Times provided for the RHR suppression pool cooling and spray functions.

The Required Action is modified by a Note indicating that the

applicable Conditions of LCO 3.4.7 be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-9 Revision 73 Amendment No. 214 January 3, 2013 BASES ACTIONS G.1 and G.2 (continued)

If the RHRSW subsystem(s) or the RHRSW pump(s) cannot be restored to OPERABLE status within the associated Completion Times or the UHS is determi ned inoperable, 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating

experience, to reach the require d unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.1.1 REQUIREMENTS

Verifying the correct alignment for each manual and power operated valve in each RHRSW sub system flow path provides assurance that the proper flow paths will exist for RHRSW

operation. This SR does not appl y to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct positi on prior to locking, sealing, or securing. A valve is also al lowed to be in the nonaccident position, and yet considered in t he correct position, provided it can be realigned to its accident po sition. This is acceptable because the RHRSW System is a manually initiated system.

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 is based on engineering judgment, is

consistent with the procedural controls governing valve operation, and ensures correct valve positions.

RHRSW System and UHS B 3.7.1 BFN-UNIT 3 B 3.7-10 Revision 69 Amendment No. 214 October 5, 2012 BASES SURVEILLANCE SR 3.7.1.2 REQUIREMENTS (continued) Verification of the UHS te mperature is within t he limits of Figure 3.7.1-1 ensures that the heat removal capability of the RHRSW System is within the assumptions of the DBA analysis (Ref. 6).

The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Frequencies are based on operating

experience relating to trending of the parameter variations during the applicable MODES.

REFERENCES 1. FSAR, Section 10.9.

2. FSAR, Chapter 5.

3. FSAR, Chapter 14.

4. FSAR, Section 14.6.3.3.2.

5. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

6. FSAR, Section 14.6.3.3.2.3..

EECW System and UHS B 3.7.2 (continued)

BFN-UNIT 3 B 3.7-13 Amendment No. 214 September 08, 1998 BASES LCO The EECW System is consi dered OPERABLE when it has an (continued) OPERABLE UHS, three OPERABLE pumps, and two OPERABLE flow paths capable of taking suction from the intake structure and transferring t he water to the appropriate equipment.

The OPERABILITY of the UHS for EECW is based on having a maximum water temperature of 95°F. Additional requirements for UHS temperature are pr ovided in SR 3.7.1.2.

The isolation of the EECW S ystem to components or systems may render those components or systems inoperable, but does

not affect the OPERABIL ITY of the EECW System.

APPLICABILITY In MODES 1, 2, and 3, the EECW System and UHS are required to be OPERABLE to support OPERABILITY of the

equipment serviced by the EECW System. Therefore, the EECW System and UHS are required to be OPERABLE in these MODES.

In MODES 4 and 5, the OPER ABILITY requirements of the EECW System and UHS are determined by the systems they support.

ACTIONS A.1

With one required EECW pump inoperable, the required EECW pump must be restored to OPERABLE status within 7 days.

With the system in this condition, the remaining OPERABLE

EECW pumps are adequate to perform the heat removal function. However, the overall reliability is reduced because a single failure in the EECW System could result in loss of EECW

function.

EECW System and UHS B 3.7.2 (continued)

BFN-UNIT 3 B 3.7-14 Revision 0 , 69 October 5, 2012 BASES ACTIONS A.1 (continued)

The 7 day Completion Time is based on the redundant EECW System capabilities afforded by the remaining OPERABLE

pumps, the low probability of an accident occurring during this time period and is consistent wit h the allowed Completion Time for restoring an inoperable DG.

B.1 and B.2

If the required EECW pump cannot be restored to OPERABLE status within the associated Comp letion Time, or two or more EECW pumps are inoperable or the UHS is determined inoperable, 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4

within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allo wed Completion Times are reasonable, based on operating experience, to reach the

required unit conditions from full power conditions in an orderly manner and without chall enging unit systems.

SURVEILLANCE SR 3.7.2.1 REQUIREMENTS

Verification of the UHS tem perature ensures that the heat removal capability of the EEC W System is within the

assumptions of the DBA analysis.

Additional requirements for UHS temperature to ensure RHRSW System heat removal capability is maintained within the assumptions of the DBA analysis are provided in SR 3.

7.1.2. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on operating experience related to trending of the

parameter variations during the applicable MODES.

Main Turbine Bypass System B 3.7.5 (continued)

BFN-UNIT 3 B 3.7-32 Revision 0 B 3.7 PLANT SYSTEMS B 3.7.5 Main Turbine Bypass System BASES BACKGROUND The Main Turbine Bypass S ystem is designed to control steam pressure when reactor steam generation exceeds turbine requirements during unit start up, sudden load reduction, and cooldown. It allows excess steam flow from the reactor to the

condenser without going through t he turbine. The bypass capacity of the system is 25%

of the Nuclear Steam Supply System rated steam flow. Sudd en load reductions within the capacity of the steam bypa ss can be accommodated without reactor scram. The Main Turbi ne Bypass System consists of nine valves connected to the ma in steam lines between the main steam isolation valves and the turbine stop valve bypass valve chest. Each of these nine valves is operated by hydraulic cylinders. The bypass valves are controlled by the pressure regulation function of the Pressure Regulator and Turbine Generator Control System, as discussed in the FSAR, Section 7.11.3.3 (Ref. 1).

The bypass valves are normally

closed, and the pressure regulator controls the turbine control valves that direct all steam flow to the turbine. If the speed governor or the load limiter restricts steam flow to the turbine, the pressure regulator controls the system pressure by opening the bypass valves. When the bypass valves open, the steam

flows from the bypass chest, th rough connecting piping, to the pressure breakdown assemblies, w here a series of orifices are used to further reduce the steam pressure before the steam enters the condenser.

Main Turbine Bypass System B 3.7.5 (continued)

BFN-UNIT 3 B 3.7-34 Revision 0, 25 March 12, 2004 BASES (continued)

APPLICABILITY The Main Turbine Bypass System is required to be OPERABLE at 25% RTP to ensure that the f uel cladding integrity Safety Limit is not violated during abnorma l operational transients. As

discussed in the Bases for LCO 3.2.1 and LCO 3.2.2, sufficient

margin to these limits exists at < 25% RTP. T herefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A.1

If the Main Turbine Bypass Syst em is inoperable (one or more bypass valves inoperable), or the APLHGR, MCPR, and LHGR limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are not ap plied, the assumptions of the design basis transient analysis may not be met. Under such circumstances, prompt action should be taken to restore the

Main Turbine Bypass System to OPERABLE status or adjust the APLHGR, MCPR, and LHGR limits accordingly. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is reasonable, based on the time to complete the Required Action and the low probability of an event occurring during this period requiring the Main Turbine Bypass

System.

B.1 If the Main Turbine Bypass S ystem cannot be restored to OPERABLE status or the APLHG R, MCPR, and LHGR limits for an inoperable Main Turbine Bypass System are not applied, THERMAL POWER must be reduced to < 25% RTP. As

discussed in the Applicability section, operation at < 25% RTP

results in sufficient margin to the required limits, and the Main

Reactor Core SLs B 2.1.1 (continued)

BFN-UNIT 1 B 2.0-3 Revision 0 , 68 October 18, 2012 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity SAFETY ANALYSES (continued) The SPCB critical power correlation is used for both AREVA and coresident fuel and is valid at pressure >

700 psia, and bundle mass fluxes >

0.1 x 10 6 lbm/hr-ft 2 (>12,000 lb m/hr, i.e., >

10% core flow, on a per bundle basis) for ATRIUM-10 and GE14 fuel types. The thermal margin monitoring at 25% power and higher, the hot channel flow rate will be >28,000 lb m/hr (core flow not less than natural circulat ion, i.e., ~25%-30% core flow for 25% power); therefore the f uel cladding integrity SL is conservative relative to the app licable range of the SPCB critical power correlation. For operation at low pressures or low flows, another basis is used, as follows:

The static head across the fuel bundles due only to elevation effects from liquid only in the channel, core bypass region, and

annulus at zero power, zero flow is approximately 4.5 psi. At all

operating conditions, this pressure differential is maintained by

the bypass region of the core and the annulus region of the

vessel. The elevation head provided by the annulus produces

natural circulation flow conditions which have balancing

pressure head and loss terms inside the core shroud. This

natural circulation principle maintains a core plenum to plenum

pressure drop of about 4.5 to 5 psid along the natural circulation

flow line of the P/F operating map.

In the range of power levels

of interest, approaching 25% of rated power below which

thermal margin monitoring is not required, the pressure drop

and density head terms tradeoff for power changes such that

natural circulation flow is nearly independent of reactor power.

This characteristic is represented by the nearly vertical portion of the natural circulation line on the P/F operating map.

Analysis has shown that the hot channel flow rate is >28,000

lb m/hr (>0.23 x 10 6 lb m/hr-ft 2) in the region of operation with power ~25% and core pressure drop of about 4.5 to 5 psid. Full

scale ATLAS test data taken at pressures from 14.7 psia to 800 psia indicate that the fuel assembly critical power at 28,000

lb m/hr is approximately 3 MW

t. With the design peaking factors, this corresponds to a core thermal power of more than 50%.

Reactor Core SLs B 2.1.1 (continued)

BFN-UNIT 1 B 2.0-4 Revision 0 , 68 October 18, 2012 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity (continued)

SAFETY ANALYSES Thus operation up to 25% of rated power with normal

natural circulation available is conservatively acceptable

even if reactor pressure is equal to or below 800 psia. If reactor power is significantly less than 25% of rated (e.g.,

below 10% of rated), the core flow and the channel flow

supported by the available driving head may be less than

28,000 lb m/hr (along the lower portion of the natural circulation flow characteristic on the P/F map). However, the critical power that can be supported by the core and hot

channel flow with normal natural circulation paths available

remains well above the actual power conditions. The

inherent characteristics of BW R natural circulation make power and core flow follow the natural circulation line as

long as normal water level is maintained.

Thus, operation with core thermal power below 25% of rated

without thermal margin surveillance is conservatively acceptable

even for reactor operations at natural circulation. Adequate fuel

thermal margins are also maintained without further surveillance

for the low power conditions that would be present if core

natural circulation is below 10% of rated flow.

SLC System B 3.1.7 (continued)

BFN-UNIT 1 B 3.1-53 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCE SR 3.1.7.4 and SR 3.1.7.6 REQUIREMENTS (continued) SR 3.1.7.4 requires an ex amination of the sodium pentaborate solution by using chemical analysis to ensure that the proper

concentration of boron exists in the storage tank. The

concentration is dependent upon the volume of water and

quantity of boron in the storage tank. SR 3.1.7.6 requires verification that the SLC system conditions satisfy the following

equation: ( C )( Q )( E ) ( 13 WT % )( 86 GPM )( 19.8 ATOM % ) > = 1.0 C = sodium pentaborate solution weight percent

concentration

Q = SLC system pump flow rate in gpm

E = Boron-10 atom percent enrichment in the sodium pentaborate solution To meet 10 CFR 50.62, the SLC System must have a minimum flow capacity and boron content equivalent in control capacity to

86 gpm of 13 weight percent natural sodium pentaborate

solution. The atom percentage of natural B-10 is 19.8%. This equivalency requirement is met when the equation given above

is satisfied. The equation can be satisfied by adjusting the

solution concentration, pump flow rate or Boron-10 enrichment.

If the results of the equation are < 1, the SLC System is no

longer capable of shutting down the reactor with the margin

described in Reference 2. Ho wever, the quantity of stored boron includes an additional margin (25%) beyond the amount

needed to shut down the reactor to allow for possible imperfect

mixing of the chemical solution in the reactor water, leakage, and the volume in other piping connected to the reactor system.

The sodium pentaborate solution (SPB) concentration is allowed to be > 9.2 weight percent pr ovided the concentration and temperature of the sodium pentaborate solution are verified SLC System B 3.1.7 BFN-UNIT 1 B 3.1-57 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCE SR 3.1.7.11 REQUIREMENTS (continued) SR 3.1.7.11 verifies that 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 Flowpath provides assurance 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 also

does not apply to valves that ar e locked, sealed, or otherwise secured in position since they are verified to be in the correct

position prior to locking, sealing or securing. This verification of valve alignment 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 is

based on engineering judgment and is consistent with the procedural controls governing valve operation that ensures

correct valve positions. REFERENCES 1.10 CFR 50.62.2.FSAR, Section 3.8.4.3.NRC No.93-102, "Final Policy Statement on Technical Specification Improvem ents," July 23, 1993.4.FSAR, Section 14.6.

APLHGR B 3.2.1 (continued)

BFN-UNIT 1 B 3.2-3a Revision 40 , 68 Amendment No. 236 October 18, 2012 BASES LCO The APLHGR limits specified in the COLR are the result of the fuel design, DBA, and transient analyses. With only one recirculation loop in operati on, in conformance with the requirements of LCO 3.4.1, "Rec irculation Loops Operating," the limit is determined by multiply ing the exposure dependent limit by an APLHGR correction factor (Ref. 5 and Ref. 10). Cycle

specific APLHGR correction factors for single recirculation loop

operation are documented in t he COLR. APLHGR limits are selected such that no power or flow dependent corrections are required. Additional APLHGR oper ating limit adjustments may be provided in the COLR supporting other analyzed equipment out-of-service conditions. APPLICABILITY The APLHGR limits are pr imarily 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 scram function provi des prompt scram 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 is APLHGR B 3.2.1 (continued)

BFN-UNIT 1 B 3.2-4 Revision 0, 40 October 26, 2006 BASES APPLICABILITY operating with s ubstantial margin to the APLHGR limits; thus, (continued) 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 should be taken to

restore the APLHGR(s) to within t he required limits such that the plant operates within analyzed conditions and within design

limits of the fuel rods. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is sufficient

to restore the APLHGR(s) to wit hin 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 sp ecified condition in which the LCO does not apply. To achieve this status, THERMAL

POWER must be reduced to < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The

allowed Completion Time is reasonable, based on operating

experience, to reduce THERMAL POWER to < 25% RTP in an

orderly manner and without c hallenging plant systems.

SURVEILLANCE SR 3.2.1.1 REQUIREMENTS APLHGRs are required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. They are co mpared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal APLHGR B 3.2.1 (continued)

BFN-UNIT 1 B 3.2-5 Revision 0, 40, 68 October 18, 2012 BASES SURVEILLANCE SR 3.2.1.1 (continued)

REQUIREMENTS operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

REFERENCES 1. NEDE-24011-P-A, Rev.

16, "General Electric Standard Application for Reactor Fuel," October 2007.

2. FSAR, Chapter 3.

3. FSAR, Chapter 14.

4. FSAR, Appendix N.

5. NEDC-32484P, "Browns Ferry Nuclear Plant Units 1, 2, and 3, SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis," Revision 2, December 1997.

6. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

7. NEDC-32433P, "Maximum Extended Load Line Limit and ARTS Improvement Program Analyses for Browns Ferry

Nuclear Plant Units 1, 2, and 3," April 1995.

8. NEDO-30130-A, "Steady State Nuclear Methods,"

May 1985.

9. NEDO-24154, "Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors," October 1978. 10. NEDO-24236, "Browns Ferry Nuclear Plant Units 1, 2, and 3, Single-Loop Operation," May 1981.

MCPR B 3.2.2 (continued)

BFN-UNIT 1 B 3.2-7 Revision 40 , 68 Amendment No. 236 October 18, 2012 BASES (continued)

APPLICABLE The analytical methods and assumptions used in evaluating SAFETY ANALYSES the abnormal operational tr ansients to establish the operating limit MCPR are presented in Referenc es 2, 3, 4, 5, 8, 10, 11, 12, 13, 14, and 15. To ensure that the MCPR 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 added to the MCPR SL, the required operating limit MCPR is obtained.

The MCPR operating limits deriv ed from the transient analysis are dependent on the operating core flow and power to ensure adherence to fuel design limits dur ing the worst transient that

occurs with moderate frequency (Reference 8). Flow

dependent MCPR (MCPR f) limits are determined by steady state thermal hydraulic methods using the three dimensional BWR simulator code (Ref. 12) and the multichannel thermal hydraulics code (Ref. 13). The operating limit is dependent on the maximum core flow limiter se tting in the Recirculation Flow Control System.

Power dependent MCPR limits (MCPR p) are determined by the three-dimensional BWR simulator code (Ref. 12) and the one-dimensional transient codes (Refs. 14 and 15). Due to the sensitivity of the transient response to initial core flow levels at power levels below those at which the turbine control valve fast

closure scrams are bypassed, high and low flow MCPR p operating limits are provi ded for operating between 25

% RTP and the previously mentioned bypass power level.

The MCPR satisfies Criterion 2 of the NRC Policy Statement (Ref. 7).

MCPR B 3.2.2 (continued)

BFN-UNIT 1 B 3.2-8 Revision 0 , 40 , 68 October 18, 2012 BASES (continued)

LCO The MCPR operating limits specif ied in the COLR are the result of the Design Basis Accident (DBA) and transient analysis.

Additionally MCPR operating limits supporting analyzed equipment out-of-service conditions are provided in the COLR.

The operating limit MCPR is det ermined by the larger of the MCPR f and MCPR p limits. 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 minimum recirculation

pump speed and the moderator void ra tio is small. Surveillance

of thermal limits below 25% RTP is unnecessary due to the

large inherent margin that ensur es that the MCPR SL is not exceeded even if a limiting transient occurs. Statistical analyses indicate that the nominal value of the initial MCPR expected at 25% RTP is > 3.5. Studies of t he variation of limiting transient behavior have been performed over the range of power and flow

conditions. These studies 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 provides rapid scram initiation for any significant power increase transient, which effectively

eliminates any MCPR complianc e 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 MCPR B 3.2.2 (continued)

BFN-UNIT 1 B 3.2-9 Revision 0 , 40 , 68 October 18, 2012 BASES ACTIONS A.1 (continued) 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 operati ng within analyzed conditions.

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 D BA occurring simultaneously with the MCPR out of specification.

B.1 If the MCPR cannot be restored to within its required limits within the associated Completion Time, the plant must be

brought to a MODE or other sp ecified condition in which the LCO does not apply. To achieve this status, THERMAL

POWER must be reduced to < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The

allowed Completion Time is reasonable, based on operating

experience, to reduce THERMAL POWER to < 25% RTP in an

orderly manner and without c hallenging plant systems.

SURVEILLANCE SR 3.2.2.1 REQUIREMENTS The MCPR is required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. It is compared to the specified limits in the COLR to ensure that the r eactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal

operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

LHGR B 3.2.3 (continued)

BFN-UNIT 1 B 3.2-12a Revision 0 , 68 July 3, 2012 BASES (continued)

LCO Additional LHGR operating lim its adjustments may be provided (continued) the COLR to support analyzed equipment out-of-service operation.

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, t herefore, the Specification is only required when the reactor is operating at 25% RTP.

LHGR B 3.2.3 BFN-UNIT 1 B 3.2-13 Revision 0 BASES (continued)

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 s hould be taken to restore the LHGR(s) to within its required limits such that the plant is

operating within analyzed conditions. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion

Time is normally sufficient to re store 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 is reduced to

< 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> thereafter. It is compared to the specified limits in the COLR to ensure that the r eactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on both engineering judgment and recognition of the slow changes in power distribution during normal operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels.

RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-5 Revision 0 BASES APPLICABLEThe trip setpoints are then determined accounting for the SAFETY ANALYSES,remaining instrument errors (e.g., drift). The trip setpoints

LCO, and derived in this manner provide adequate protection becauseAPPLICABILITYinstrumentation uncertainties, process effects, calibration (continued)tolerances, instrument drift, and severe environmental effects (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 or other specified conditions in the Table, which 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 are required in each

MODE to provide primary and diverse initiation signals.

The only MODES specified in Table 3.3.1.1-1 are MODES 1 (which encompasses 30% RTP) and 2, and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies. No RPS Function is required in MODES 3 and

4 since 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.

In MODE 5, 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, no RPS function

is 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.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-11 Revision 0, 40, 45 February 27, 2007 BASES APPLICABLEAverage Power Range Monitor SAFETY ANALYSES, LCO, and 2.a. Average Power Range Monitor Neutron Flux - High,APPLICABILITY(Setdown)

(continued)

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 AveragePower 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 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 since the potential for criticality exists. In MODE 1, the Average Power Range Monitor NeutronFlux - High Function provides protection against reactivity

transients and the RWM and rod block monitor protect against

control rod withdrawal error events.

RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-16a Revision 45 February 27, 2007 BASES APPLICABLE2.f. Oscillation Power Range Monitor (OPRM) Upscale SAFETY ANALYSES, LCO, and The OPRM Upscale Function provides compliance with GDC 10APPLICABILITYand GDC 12, thereby providing protection from exceeding the (continued)fuel MCPR safety limit (SL) due to anticipated thermal hydraulic power oscillations.

References 13, 14, and 15 describe three algorithms for detecting thermal hydraulic instability related neutron flux oscillations: the period based detection algorithm, the amplitude based algorithm, and the growth rate algorithm. All three are implemented in the OPRM Upscale Function, but the safety analysis takes credit only for the period based detection algorithm. The remaining algorithms provide defense in depth and additional protection against unanticipated oscillations.

OPRM Upscale Function OPERABILITY for Technical Specification purposes is based only on the period based detection algorithm.

The OPRM Upscale Function receives input signals from the local power range monitors (LPRMs) within the reactor core, which are combined into "cells" for evaluation of the OPRM algorithms.

The OPRM Upscale Function is required to be OPERABLE when the plant is in a region of power flow operation where anticipated events could lead to thermal hydraulic instability and related neutron flux oscillations. Within this region, the automatic trip is enabled when THERMAL POWER, as indicated by the APRM Simulated Thermal Power, is 25%RTP and reactor core flow, as indicated by recirculation drive flow is < 60% of rated flow, the operating region where actual thermal hydraulic oscillations may occur. Requiring the OPRM Upscale Function to be OPERABLE in MODE 1 provides consistency with operability requirements for other APRM functions and assures that the OPRM Upscale Function is OPERABLE whenever reactor power could increase into the region of concern without operator action.

RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-24 Revision 0 BASES APPLICABLE8. Turbine Stop Valve - Closure (continued)

SAFETY ANALYSES, LCO, andTurbine Stop Valve - Closure signals are initiated from positionAPPLICABILITYswitches located on each of the four TSVs. Two independent position switches are associated with each stop valve. One of

the two switches provides input to RPS trip system A; the other, to RPS trip system B. Thus, each RPS trip system receives an input from four Turbine Stop Valve - Closure channels, each

consisting of one position switch. The logic for the Turbine Stop Valve - Closure Function is such that three or more TSVs

must be closed to produce a scram. This Function must be enabled at THERMAL POWER 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine

bypass valves may affect this function.The Turbine Stop Valve - Closure 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 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 if any three TSVs should

close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is 30% RTP.This Function is not required when THERMAL POWER is< 30% 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.

RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-25 Revision 0 BASES APPLICABLE9. Turbine Control Valve Fast Closure, Trip Oil Pressure - LowSAFETY ANALYSES,(PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and APPLICABILITYFast closure of the TCVs results in the loss of a heat sink that (continued)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 7. 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 electrohydraulic control (EHC) fluid

pressure at each control valve. One pressure switch is

associated with each control valve, and the signal from each

switch is assigned to a separate RPS logic channel. This Function must be enabled at THERMAL POWER 30% RTP.This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this function.The Turbine Control Valve Fast Closure, Trip Oil Pressure -

Low Allowable Value is selected high enough to detect

imminent TCV fast closure.

RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-26 Revision 0, 41 November 09, 2006 BASES APPLICABLE9. Turbine Control Valve Fast Closure, Trip Oil Pressure - LowSAFETY ANALYSES,(PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and (continued)

APPLICABILITY 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 30% RTP. This Function is not required when THERMAL POWER is < 30% RTP, since theReactor Vessel Steam Dome Pressure - High and the Average Power Range Monitor Fixed Neutron Flux - High Functions are

adequate to maintain the necessary safety margins.

For this instrument function, the nominal trip setpoint including the as-left tolerances is defined as the LSSS. The acceptable as-found band is based on a statistical combination of possible measurable uncertainties (i.e., setting tolerance, drift,temperature effects, and measurement and test equipment).

During instrument calibrations, if the as-found setpoint is found to be conservative with respect to the Allowable Value, but outside its acceptable as-found band (tolerance range), as defined by its associated Surveillance Requirement procedure, then there shall be an initial determination to ensure confidence that the channel can perform as required before returning the channel to service in accordance with the Surveillance. The technician performing the Surveillance will evaluate the instrument's ability to maintain a stable setpoint within the as-left tolerance. The technician's evaluation will be reviewed by on shift personnel during the approval of the Surveillance data prior to returning the channel back to service at the completion of the Surveillance. This shall constitute the initial determination of operability. If a channel is found to exceed the channel's Allowable Value or cannot be reset within the RPS Instrumentation B 3.3.1.1 (cont inued)BFN-UNIT 1B 3.3-36 Revision 0, 40 October 26, 2006 BASES SURVEILLANCESR 3.3.1.1.2 REQUIREMENTS (continued)To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor

power calculated from a heat balance. 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 3.3.1.1.7.

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 within the last 7 days, in accordance with SR 3.0.2. A Note is provided which

allows an increase in THERMAL POWER above 25% if the

7 day Frequency is not met per SR 3.0.2. In this event, the SR

must be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 1B 3.3-43 Revision 0, 43 January 17, 2007 BASES SURVEILLANCESR 3.3.1.1.15 REQUIREMENTS (continued)This SR ensures that scrams initiated from the Turbine StopValve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions will not be inadvertently bypassed when THERMAL POWER is 30% RTP. Thisinvolves calibration of the bypass channels (PIS-1-81A,PIS-1-81B, PIS-1-91A, and PIS-1-91B). Adequate margins for

the instrument setpoint methodologies are incorporated into the

actual setpoint.

If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at 30% RTP, either due to open main turbine bypass valve(s) or other reasons), then the affectedTurbine Stop Valve - Closure 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 (Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low

Functions are enabled), this SR is met and the channel is

considered OPERABLE.The Frequency of 24 months is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 1B 3.3-43a Revision 45 February 27, 2007 BASES SURVEILLANCESR 3.3.1.1.17 REQUIREMENTS (continued)This SR ensures that scrams initiated from OPRM Upscale Function (Function 2.f) will not be inadvertently bypassed when THERMAL POWER, as indicated by the APRM Simulated Thermal Power, is 25% RTP and core flow, as indicated by recirculation drive flow, is < 60% rated core flow. This normally involves confirming the bypass setpoints. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint. The actual surveillance ensures that the OPRM Upscale Function is enabled (not bypassed) for the correct values of APRM Simulated Thermal Power and recirculation drive flow. Other surveillances ensure that the APRM Simulated Thermal Power and recirculation flow properly correlate with THERMAL POWER and core flow, respectively.

If any bypass setpoint is nonconservative (i.e., the OPRM Upscale Function is bypassed when APRM Simulated Thermal Power 25% RTP and recirculation drive flow < 60% rated), then the affected channel is considered inoperable for the OPRM Upscale Function. Alternatively, the bypass setpoint may be adjusted toplace the channel in a conservative condition (unbypass). If placed in the unbypassed condition, this SR is met and the channel is considered OPERABLE.

The frequency of 24 months is based on engineering judgment and reliability of the components.

Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 (cont inued)BFN-UNIT 1B 3.3-73 Revision 0 BASES (continued) APPLICABLEThe feedwater and main turbine high water level trip SAFETY ANALYSESinstrumentation is assumed to be capable of providing a turbine trip in the design basis transient analysis for a feedwater

controller failure, maximum demand event (Ref. 1). The reactor

vessel high water level trip indirectly initiates a reactor scram

from the main turbine trip (above 30% RTP) and trips the

feedwater pumps, thereby terminating the event. The reactor

scram mitigates the reduction in MCPR.

Feedwater and main turbine high water level trip instrumentation satisfies Criterion 3 of the NRC Policy

Statement (Ref. 3).

LCO The LCO requires two channels of the Reactor Vessel WaterLevel - High instrumentation per trip system to be OPERABLE

to ensure that no single instrument failure will prevent the

feedwater pump turbines and main turbine trip on a valid Reactor Vessel Water Level - High signal. Both channels in

either trip system are needed to provide trip signals in order for

the feedwater and main turbine trips to occur. Each channel

must have its setpoint set within the specified Allowable Value

of SR 3.3.2.2.3. The Allowable Value is set to ensure that the

thermal limits are not exceeded during the event. The actual

setpoint is calibrated to be consistent with the applicable

setpoint methodology assumptions. 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 successive CHANNEL

CALIBRATIONS. Operation with a trip setpoint less

conservative than the nominal trip setpoint, but within its

Allowable Value, is acceptable.

Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 1B 3.3-74 Revision 0 BASES LCO Trip setpoints are those predetermined values of output at (continued)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. A channel is inoperable if its actual trip

setpoint is not within its required Allowable Value. 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 environmental effects (for channels that must

function in harsh environments as defined by 10 CFR 50.49)

are accounted for. APPLICABILITYThe feedwater and main turbine high water level trip instrumentation is required to be OPERABLE at 25% RTP to ensure that the fuel cladding integrity Safety Limit and the

cladding 1% plastic strain limit are not violated during the

feedwater controller failure, maximum demand event. As

discussed in the Bases for LCO 3.2.1, "Average Planar Linear

Heat Generation Rate (APLHGR)," and LCO 3.2.2, "MINIMUM

CRITICAL POWER RATIO (MCPR)," sufficient margin to these

limits exists below 25% RTP; therefore, these requirements are

only necessary when operating at or above this power level.

Feedwater and Main Turbine High Water Level Trip Instrumentation B 3.3.2.2 (cont inued)BFN-UNIT 1B 3.3-77 Revision 0 BASES ACTIONS B.1 (continued)

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is sufficient for the operator to

take corrective action, and takes into account the likelihood of

an event requiring actuation of feedwater and main turbine high

water level trip instrumentation occurring during this period. It

is also consistent with the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in

LCO 3.2.2 for Required Action A.1, since this instrumentation's

purpose is to preclude a MCPR violation.

C.1 With the required channels not restored to OPERABLE status or placed in trip, THERMAL POWER must be reduced to

< 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. As discussed in the Applicability

section of the Bases, operation below 25% RTP results in

sufficient margin to the required limits, and the feedwater and

main turbine high water level trip instrumentation is not required

to protect fuel integrity during the feedwater controller failure, maximum demand event. The allowed Completion Time of

4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is based on operating experience to reduce THERMAL

POWER to < 25% RTP from full power conditions in an orderly

manner and without challenging plant systems. SURVEILLANCEThe Surveillances are modified by a Note to indicate that REQUIREMENTSwhen a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated

Conditions and Required Actions may be delayed for up to

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains feedwater

and main turbine high water level trip capability. Upon

completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />

allowance, the channel must be returned to OPERABLE status EOC-RPT Instrumentation B 3.3.4.1 (cont inued)BFN-UNIT 1B 3.3-106 Revision 0 , 68 October 18, 2012 BASES BACKGROUNDEach EOC-RPT trip system is a two-out-of-two logic for each (continued)Function; thus, either two TSV - Closure or two TCV FastClosure, 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. APPLICABLEThe TSV - Closure and the TCV Fast Closure, Trip Oil SAFETY ANALYSES,Pressure - Low Functions are designed to trip the recirculation

LCO, and pumps in the event of a turbine trip or generator load rejectionAPPLICABILITYto mitigate the increase in neutron flux, heat flux, and reactor pressure, and to increase the margin to the MCPR SL, and LHGR limits. The analytical methods and assumptions used in evaluating the turbine trip and generator load rejection are

summarized in References 2, 3, and 4.

To mitigate pressurization transient effects, the EOC-RPT must trip the recirculation pumps after initiation of 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 a

scram alone, resulting in an increased margin to the MCPR SL, and LHGR limits. Alternatively, MCPR limits for an inoperableEOC-RPT, as specified in the COLR, are sufficient to prevent

violation of the MCPR Safety Limit, and fuel mechanical limits.The EOC-RPT function is automatically disabled when turbine

first stage pressure is < 30% RTP.EOC-RPT instrumentation satisfies Criterion 3 of the NRC Policy Statement (Ref. 6).

EOC-RPT Instrumentation B 3.3.4.1 (cont inued)BFN-UNIT 1B 3.3-109 Revision 0 , 68 October 18, 2012 BASES APPLICABLETurbine Stop Valve - Closure (continued)

SAFETY ANALYSES, LCO, and Closure of the TSVs is determined by measuring the position ofAPPLICABILITYeach valve. There are two separate position signals associated with each stop valve, the signal from each switch being assigned to a separate trip channel. The logic for the TSV -

Closure Function is such that two or more TSVs must be closed

to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine

bypass valves may affect this function. To consider this

function OPERABLE, bypass of the function must not occur when bypass valves are open. 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 Allowable Value is

selected to detect imminent TSV closure.

This protection is required, consistent with the safety analysis assumptions, whenever THERMAL POWER is 30% RTP.Below 30% RTP, 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 margin

to the MCPR SL, and LHGR limits.

EOC-RPT Instrumentation B 3.3.4.1 (cont inued)BFN-UNIT 1B 3.3-110 Revision 0 , 68 October 18, 2012 BASES APPLICABLETurbine Control Valve Fast Closure, Trip Oil Pressure - LowSAFETY ANALYSES,(PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and APPLICABILITYFast closure of the TCVs during a generator load rejection (continued)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, and LHGR limits are not exceeded during the worst case transient.

Fast closure of the TCVs is determined by measuring the electrohydraulic control fluid pressure at each control valve.

There is one pressure switch associated with each control

valve, and the signal from each switch 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 switch trips) to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 30% RTP.This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this function. To

consider this function OPERABLE, bypass of the function must

not occur when bypass valves are open. 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.

EOC-RPT Instrumentation B 3.3.4.1 (cont inued)BFN-UNIT 1B 3.3-111 Revision 0 BASES APPLICABLETurbine Control Valve Fast Closure, Trip Oil Pressure - LowSAFETY ANALYSES,(PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and (continued)

APPLICABILITY This protection is required consistent with the safety analysis whenever THERMAL POWER is 30% RTP. Below 30% RTP,the Reactor Vessel Steam Dome Pressure - High and theAPRM Fixed Neutron Flux - High Functions of the RPS are

adequate to maintain the necessary safety margins.

ACTIONS A Note has been provided to modify the ACTIONS related toEOC-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.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 1B 3.3-113 Revision 0 , 68 October 18, 2012 BASES ACTIONS B.1 and B.2 (continued)

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.

Alternately, Required Action B.2 requires the MCPR and LHGR limits for inoperable EOC-RPT, as specified in the COLR, to be applied. This also restores the margin to MCPR and LHGR limits assumed in the safety analysis.

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is sufficient time 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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />

Completion Time provided in LCO 3.2.2 for Required

Action A.1, since this instrumentation's purpose is to preclude a

MCPR or LHGR violation.

C.1 With any Required Action and associated Completion Time not

met, THERMAL POWER must be reduced to < 30% RTP within

4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is

reasonable, based on operating experience, to reduce

THERMAL POWER to < 30% RTP from full power conditions in

an orderly manner and without challenging plant systems.

EOC-RPT Instrumentation B 3.3.4.1 (cont inued)BFN-UNIT 1B 3.3-115 Revision 0, 43 January 17, 2007 BASES SURVEILLANCESR 3.3.4.1.2 REQUIREMENTS (continued)This SR ensures that an EOC-RPT initiated from the TSV - Closure and TCV Fast Closure, Trip Oil Pressure - Low

Functions will not be inadvertently bypassed when THERMAL POWER is 30% RTP. This involves calibration of the bypass channels. Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint. If any

bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at 30% RTP, either due to open mainturbine bypass valves or other reasons), the affected TSV - Closure 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 with the channel considered OPERABLE.The Frequency of 24 months is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.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 a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint

analysis.

Jet Pumps B 3.4.2 BFN-UNIT 1 B 3.4-16 Revision 0 BASES SURVEILLANCE SR 3.4.2.1 (continued)

REQUIREMENTS

Note 2 allows this SR not to be performed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after THERMAL POWER exceeds 25% of 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. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is an acceptable time to establish conditions appropriate to perform this SR.

REFERENCES 1. FSAR, Section 14.6.3.

2. GE Service Information Letter No. 330, "Jet Pump Beam Cracks," June 9, 1980.

3. NUREG/CR-3052, "Closeout of IE Bulletin 80-07: BWR Jet Pump Assembly Failure," November 1984.

4. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

Primary Containment B 3.6.1.1 (continued)

BFN-UNIT 1 B 3.6-3 Revision 0, 49 April 30, 2007 BASES APPLICABLE The maximum allowable leakage rate for the primary SAFETY ANALYSES containment (L a) is 2.0% by weight of the containment air per (continued) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the design bas is LOCA maximum peak containment pressure (P a) of 48.5 psig (Ref. 1).

Primary containment satisfies Criterion 3 of the NRC Policy Statement (Ref. 6).

LCO Primary containment OPERABILITY is maintained by limiting leakage to 1.0 L a , except prior to the first startup after performing a required Primary Containment Leakage Rate Testing Program leakage test. At this time, applicable leakage limits must be met. Compliance with this LCO will ensure a

primary containment configur ation, including equipment hatches, that is structurally s ound and that will lim it leakage to those leakage rates assumed in the safety analyses.

Individual leakage rates specif ied for the prim ary containment air lock 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 primar y 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, prim ary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of

radioactive material from primary containment.

Primary Containment B 3.6.1.1 BFN-UNIT 1 B 3.6-6 Revision 0, 43 January 17, 2007 BASES SURVEILLANCE SR 3.6.1.1.2 (continued)

REQUIREMENTS

Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber and veri fying that the pressure in either the suppression chamber or the drywell does not change by more than 0.25 inch of wate r per minute over a 10 minute period. The leakage test is per formed every 24 months. The 24 month Frequency was developed considering it is prudent that this Surveillance be performed during a unit outage and

also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs.

REFERENCES 1. FSAR, Section 5.2.

2. FSAR, Section 14.6.

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

4. NEI 94-01, Revision O, "Industr y Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J." 5. ANSI/ANS-56.8-1994, "Ame rican National Standard for Containment System Leakage Testing Requirement."

6. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

Primary Containment Air Lock B 3.6.1.2 (continued)

BFN-UNIT 1 B 3.6-8 Revision 0, 49 April 30, 2007 BASES BACKGROUND the air lock to remain open for extended periods when frequent (continued) primary containment entry is necessary. Unde r some conditions allowed by this LCO, the prim ary containment may be accessed through the air lock, when the interlock mechanism has failed, by manually performing the interlock function.

The primary containment air lock forms 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 t hat assumed in the unit safety analysis.

APPLICABLE The DBA that postulates the maximum release of radioactive SAFETY ANALYSES material within primary containment is a LOCA. In the analysis of this accident, it is assum ed that primary containment is OPERABLE, such that releas e of fission products to the environment is controlled by the rate of primary containment leakage. The primar y containment is designed with a maximum allowable leakage rate (L a) of 2.0% by weight of the containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the calculat ed maximum peak containment pressure (P a) of 48.5 psig (Ref. 3). This allowable leakage rate forms the basis for the acceptanc e criteria imposed on the SRs associated with the air lock.

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.

The primary containment air lo ck satisfies Criterion 3 of the NRC Policy Statement (Ref. 4).

CAD System B 3.6.3.1 (continued)

BFN-UNIT 1 B 3.6-90 Revision 0 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.1 Containment Atmosphere Dilution (CAD) System BASES BACKGROUND The CAD Syst em functions to maintain combustible gas concentrations within the primary containment at or below the flammability limits following a postulated loss of coolant accident (LOCA) by diluting hydrogen and oxygen with nitrogen. To ensure that a combustible gas mixture does not occur, oxygen

concentration is kept < 5.0 volume percent (v/o), or hydrogen

concentration is kept < 4.0 v/o.

The CAD System is manually in itiated and consists of two independent, 100% capacity sub systems, each of which is capable of supplying nitrogen through separate piping systems to the drywell and suppression chamber of each unit. Each

subsystem includes a liquid nitrogen supply tank, ambient vaporizer, electric heater, and a manifold with branches to each primary containment (for Unit s 1, 2, and 3).

The nitrogen storage tanks each contain 2500 gal, which is adequate for 7 days of CAD subsystem operation.

The CAD System operates in conjunction with emergency

operating procedures that ar e used to reduce primary containment pressure peri odically during CAD System operation. This combination results in a feed and bleed approach to maintaining hydroge n and oxygen concentrations below combustible levels.

CAD System B 3.6.3.1 (continued)

BFN-UNIT 1 B 3.6-94 Revision 0, 34 September 07, 2005 BASES ACTIONS B.1and B.2 (continued)

The Completion Time of 7 days is a reasonable time to allow continued reactor operation with two CAD subsystems inoperable because the hydrogen control function is maintained (via the Primary Containment Inerting System) and because of the low probability of the occurr ence of a LOCA that would generate hydrogen in amounts c apable of exceeding the flammability limit.

C.1 If any Required Action cannot be met within the associated

Completion Time, the plant mu st be brought to a MODE in which the LCO does not apply. To achieve this status, the plant

must be brought to at least MODE 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The allowed Completion Time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is reasonable, based on operating experience, to reac h MODE 3 from full power

conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.3.1.1 REQUIREMENTS Verifying that there is 2500 gal of liquid nitrogen supply in each nitrogen storage tank will ensure at least 7 days of post-LOCA CAD operation. This minimum volume of liquid

nitrogen allows sufficient time a fter an accident to replenish the nitrogen supply for long term inerti ng. This is verified every 31 days to ensure that the system is capable of performing its intended function when required. The 31 day Frequency is based on operating experience, which has shown 31 days to be an acceptable period to verify the liquid nitrogen supply and on

the availability of other hydrogen mitigating systems.

CAD System B 3.6.3.1 BFN-UNIT 1 B 3.6-96 Revision 0 BASES (continued)

REFERENCES 1. AEC Safety Guide 7, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident, March 10, 1971.

2. FSAR, Section 5.2.6.

3. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

RHRSW System B 3.7.1 (continued)

BFN-UNIT 1 B 3.7-3 Revision 0 , 44 , 73 January 3, 2013 BASES APPLICABLE With two and three units f ueled, a worse case single failure SAFETY ANALYSES could also include the loss of two RHRSW pumps caused by (continued) losing a 4 kV shutdown board since there are certain alignment configurations that allow two RHRSW pumps to be powered from the same 4 kV shutdown bo ard. As discussed in the FSAR, Section 14.6.3.3.2 (Ref.

4) for these analyses, manual initiation of the OPERABLE RHRSW subsystems and the associated RHR System is assumed to occur 10 minutes after a

DBA. The analyses assume that there are two RHRSW subsystems operating in each unit, with one RHRSW pump in each subsystem capable of producing 4000 gpm of flow. In this case, the maximum suppression chamber water temperature and pressure are 187.3°F (as re ported in Reference 6) and 48.5 psig, respectively, well below the design temperature of

281°F and maximum allowable pressure of 62 psig.

The RHRSW System satisfies Criterion 3 of the NRC Policy Statement (Ref 5).

LCO Four RHRSW subsystems are required to be OPERABLE to provide the required redundancy to ensure that the system

functions to remove post a ccident heat loads, assuming the worst case single active failure o ccurs coincident with the loss of offsite power. Additionally, since the RHRSW pumps are

shared between the three BFN unit s, the number of OPERABLE pumps required is also dependent on the number of units

fueled.

An RHRSW subsystem is considered OPERABLE when:

a. At least one RHRSW pump (i.e., one required RHRSW pump) is OPERABLE; and b. An OPERABLE flow path is capable of taking suction from the intake structure and tr ansferring the water to the associated RHR heat exchanger at the assumed flow rate.

RHRSW System B 3.7.1 BFN-UNIT 1 B 3.7-10 Revision 0 BASES (continued)

REFERENCES 1. FSAR, Section 10.9.

2. FSAR, Chapter 5.

3. FSAR, Chapter 14.

4. FSAR, Section 14.6.3.3.2.

5. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

6. GE-NE-B13-01755-2, Revision 1, February 1996.

Main Turbine Bypass System B 3.7.5 (continued)

BFN-UNIT 1 B 3.7-32 Revision 0 B 3.7 PLANT SYSTEMS B 3.7.5 Main Turbine Bypass System BASES BACKGROUND The Main Turbine Bypass S ystem is designed to control steam pressure when reactor steam generation exceeds turbine

requirements during unit start up, sudden load reduction, and cooldown. It allows excess steam flow from the reactor to the

condenser without going through t he turbine. The bypass capacity of the system is 25%

of the Nuclear Steam Supply System rated steam flow. Sudd en load reductions within the capacity of the steam bypa ss can be accommodated without reactor scram. The Main Turbi ne Bypass System consists of nine valves connected to the ma in steam lines between the main steam isolation valves and the turbine stop valve bypass valve chest. Each of these nine valves is operated by hydraulic cylinders. The bypass valves are controlled by the pressure regulation function of the Pressure Regulator and Turbine Generator Control System, as discussed in the FSAR, Section 7.11.3.3 (Ref. 1).

The bypass valves are normally

closed, and the pressure regulator controls the turbine control valves that direct all steam flow to the turbine. If the speed governor or the load limiter restricts steam flow to the turbine, the pressure regulator controls the system pressure by opening the bypass valves. When the bypass valves open, the steam flows from the bypass chest, th rough connecting piping, to the pressure breakdown assemblies, w here a series of orifices are used to further reduce the steam pressure before the steam enters the condenser.

Main Turbine Bypass System B 3.7.5 (continued)

BFN-UNIT 1 B 3.7-34 Revision 0 , 68 October 18, 2012 BASES (continued)

APPLICABILITY The Main Turbine Bypass System is required to be OPERABLE at 25% RTP to ensure that the f uel cladding integrity Safety Limit is not violated during abnorma l operational transients. As

discussed in the Bases for LCO 3.2.1 and LCO 3.2.2, sufficient

margin to these limits exists at < 25% RTP. T herefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A.1

If the Main Turbine Bypass Syst em is inoperable (one or more bypass valves inoperable), or the APLHGR, MCPR, and LHGR limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are not ap plied, the assumptions of the design basis transient analysis may not be met. Under such circumstances, prompt action should be taken to restore the

Main Turbine Bypass System to OPERABLE status or adjust the APLHGR, MCPR, and LHGR limits accordingly. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is reasonable, bas ed on the time to complete the Required Action and the low probability of an event occurring during this period requiring the Main Turbine Bypass

System.

B.1 If the Main Turbine Bypass S ystem cannot be restored to OPERABLE status or the APLHG R, MCPR, and LHGR limits for an inoperable Main Turbine Bypass System are not applied, THERMAL POWER must be reduced to < 25% RTP. As

discussed in the Applicability section, operation at < 25% RTP

results in sufficient margin to the required limits, and the Main

Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity SAFETY ANALYSES (continued)

Critical power correlations are valid over a wide range of conditions per References 2 and 5, extending to expected conditions below 25% THERMAL POWER. For core thermal power levels at, or above 25% rated, the hot channel flow rate is expected to be >28,000 lbm/hr, (core flow not less than natural circulation i.e., ~25%

-30 % core flow for 25% power); therefore, the fuel cladding integrity SL is conservative relative to the applicable range of the critical power correlations. For operation at low pressure/flow conditions, consistent with the low power region of the Power/Flow operating map, another basis is used as follows:

The static head across the fuel bundles is due to elevation effects from water solid channel, core bypass, and annulus regions, is approximately 4.5 psid. The pressure differential is maintained by the water solid bypass region of the core, along with the annulus region of the vessel. Elevation head provided by the bypass and annulus regions produces natural circulation flow conditions balancing pressure head with loss terms inside the core shroud.

Natural circulation principles maintain a core plenum to plenum pressure drop of approximately 4.5 to 5 psid along the natural circulation flow line of the Power/Flow operating map. When power levels approach 25% rated, pressure drop and density head terms are closely balanced as power changes, such that natural circulation flow is nearly independent of reactor power.

The flow characteristic is represented by the nearly vertical portion of the natural circulation line on the Power/Flow operating map. For a core pressure drop of approximately 4.5 to 5 psid, the hot channel flow rate is expected to be >28,000 lbm/hr in the region of operation when core power is < 25% with a corresponding core pressure drop of about 4.5 to 5 psid.

(continued)

BFN-UNIT 2 B 2.0-3 Revision 0 , 31 , 61 Amendment 313 February 26, 2015

Reactor Core SLs B 2.1.1 BASES APPLICABLE 2.1.1.1 Fuel Cladding Integrity (continued)

SAFETY ANALYSES For example, Reference 5 test data, taken at low pressures and flow rates, indicate assembly critical power in excess of 4 MWt, for flow rates indicative of natural circulation conditions. At 25% rated power, assembly average power is < 1.2 MWt. When considering design peaking factors, hot channel power could be expected to be on the order of 2 MWt. Consequently, operation up to 25% rated core power, with normal natural circulation available, is conservative even if reactor pressure is less than the lower pressure limit of the critical power correlation.

When reactor power is significantly less than 25% of rated (e.g., below 10% of rated), hot channel flow supported by the available driving head may fall below 28,000 lbm/hr (along the lower portion of the natural circulation flow characteristic on the Power/Flow map). However, the critical power supported by the flow, remains above actual hot channel power conditions. The inherent characteristics of BWR natural circulation make core power/flow follow the natural circulation line as long as normal annulus water level is maintained.

Operation below 25% rated core thermal power is conservatively acceptable, even for reactor operations at natural circulation. Adequate fuel thermal margins are maintained for low power conditions present during core natural circulation, even though the flow may be less than the critical power correlation applicability range.

(continued)

BFN-UNIT 2 B 2.0-4 Revision 0 , 31 , 61 Amendment 313 February 26, 2015

SLC System B 3.1.7 (cont inued)BFN-UNIT 2B 3.1-48 Revision 0 , 29 January 25, 2005 BASES BACKGROUNDThe worst case sodium pentaborate solution concentration (continued)required to shutdown the reactor with sufficient margin to account for 0.05 k/k and Xenon poisoning effects is 9.2 weight percent. This corresponds to a 40 F saturation temperature.

The worst case SLCS equipment area temperature is not predicted to fall below 50 F. This provides a 10 F thermal margin to unwanted precipitation of the sodium pentaborate.

Tank heating components provide backup assurance that the

sodium pentaborate solution temperature will never fall below 50 F but are not required for TS operability considerations. APPLICABLEThe SLC System is manually initiated from the main controlSAFETY ANALYSESroom, as directed by the emergency operating instructions, if the operator believes the reactor cannot be shut down, or kept

shut down, with the control rods. The SLC System is used in

the event that enough control rods cannot be inserted to

accomplish shutdown and cooldown in the normal manner. The

SLC System injects borated water into the reactor core to add

negative reactivity to compensate for all of the various reactivity

effects that could occur during plant operations. To meet this

objective, it is necessary to inject a quantity of boron, which

produces a concentration of 660 ppm of natural boron, in the reactor coolant at 70 F. To allow for imperfect mixing, leakage and the volume in other piping connected to the reactor system, an amount of boron equal to 25% of the amount cited above is

added (Ref. 2). This volume versus concentration limit and 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 entire 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.

SLC System B 3.1.7 (cont inued)BFN-UNIT 2B 3.1-52 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCESR 3.1.7.1 (continued)

REQUIREMENTS pentaborate solution concentration requirements ( 9.2% by weight) and the required quantity of Boron-10 ( 186 lbs)establish the tank volume requirement. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency

is based on operating experience that has shown there are

relatively slow variations in the solution volume.SR 3.1.7.2SR 3.1.7.2 verifies the continuity of the explosive charges in the injection valves to ensure that proper operation will occur if

required. An automatic continuity monitor may be used to

continuously satisfy this requirement. 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 and has demonstrated the reliability of the

explosive charge continuity.SR 3.1.7.3 SR 3.1.7.3 requires an examination of sodium pentaborate solution by using chemical analysis to ensure that the proper concentration of boron exists in the storage tank for post-LOCAsuppression pool pH control. This parameter is used as inputto determine the volume requirements for SR 3.1.7.1. The concentration is dependent upon the volume of water and quantity of boron in the storage tank.

SR 3.1.7.3 must be performed every 31 days or within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of when boron or water is added to the storage tank solution to determine that the boron solution concentration is within the specified limits. The 31 day Frequency of this Surveillance is appropriate because of the relatively slow variation of boron concentration between surveillances.

SLC System B 3.1.7 (cont inued)BFN-UNIT 2B 3.1-53 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCESR 3.1.7.4 and SR 3.1.7.6 REQUIREMENTS (continued)SR 3.1.7.4 requires an examination of the sodium pentaborate solution by using chemical analysis to ensure that the proper

concentration of boron exists in the storage tank. The

concentration is dependent upon the volume of water and

quantity of boron in the storage tank. SR 3.1.7.6 requires verification that the SLC system conditions satisfy the following

equation:( C )( Q )( E ) ( 13 WT % )( 86 GPM )( 19.8 ATOM % ) > = 1.0 C = sodium pentaborate solution weight percent

concentration

Q = SLC system pump flow rate in gpm

E = Boron-10 atom percent enrichment in the sodium

pentaborate solutionTo meet 10 CFR 50.62, the SLC System must have a minimum flow capacity and boron content equivalent in control capacity

to 86 gpm of 13 weight percent natural sodium pentaborate

solution. The atom percentage of natural B-10 is 19.8%. This

equivalency requirement is met when the equation given above

is satisfied. The equation can be satisfied by adjusting the

solution concentration, pump flow rate or Boron-10 enrichment.

If the results of the equation are < 1, the SLC System is no

longer capable of shutting down the reactor with the margin

described in Reference 2. However, the quantity of stored

boron includes an additional margin (25%) beyond the amount

needed to shut down the reactor to allow for possible imperfect

mixing of the chemical solution in the reactor water, leakage, and the volume in other piping connected to the reactor system.

The sodium pentaborate solution (SPB) concentration is allowed to be > 9.2 weight percent provided the concentration

and temperature of the sodium pentaborate solution are verified SLC System B 3.1.7 BFN-UNIT 2B 3.1-57 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCESR 3.1.7.11 REQUIREMENTS (continued)SR 3.1.7.11 verifies that 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 Flowpath

provides assurance 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 also

does not apply to valves that are locked, sealed, or otherwise

secured in position since they are verified to be in the correct

position prior to locking, sealing or securing. This verification of

valve alignment 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 is

based on engineering judgment and is consistent with the

procedural controls governing valve operation that ensures

correct valve positions. REFERENCES1.10 CFR 50.62.2.FSAR, Section 3.8.4.3. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.4. FSAR, Section 14.6.

APLHGR B 3.2.1 (continued)

BFN-UNIT 2B 3.2-3b Revision 31 , 61 December 7, 2010 BASES (continued) APPLICABILITYAPLHGR limits are primarily derived from fuel design evaluations and LOCA and transient analyses assumed to occur at high power levels. Design calculations 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 scram function provides prompt scram 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 is operating with substantial margin to the APLHGR limits; thus, this LCO is not required.

APLHGR B 3.2.1 (continued)

BFN-UNIT 2B 3.2-4 Revision 0 BASES (continued)

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 should be taken to

restore the APLHGR(s) to within the required limits such that

the plant operates within analyzed conditions and within design

limits of the fuel rods. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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. SURVEILLANCESR 3.2.1.1 REQUIREMENTS APLHGRs are required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is

based on both engineering judgment and recognition of the

slowness of changes in power distribution during normal

operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

MCPR B 3.2.2 (continued)

BFN-UNIT 2B 3.2-7 Revision 31 , 61 Amendment No. 256 December 7, 2010 BASES APPLICABLEevaluated are loss of flow, increase in pressure and power, SAFETY ANALYSESpositive reactivity insertion, and coolant temperature decrease. (continued)The limiting transient yields the largest change in CPR (CPR).When the largest CPR is added to the MCPR SL, the required operating limit MCPR is obtained.

The MCPR operating limits derived from the transient analysis are dependent on the operating core flow and power to ensure adherence to fuel design limits during the worst transient that

occurs with moderate frequency. Flow dependent MCPR (MCPR f) limits are determined by steady-state thermal hydraulic methods using the three-dimensional BWR simulator code (Reference 12) and the multichannel thermal hydraulic code (Reference 13). The operating limit is dependent on the

maximum core flow limiter setting in the Recirculation Flow

Control System.

Power-dependent MCPR limits (MCPR p) are determined by the three-dimensional BWR simulator code (Ref. 12) and the one-dimensional transient codes (Refs. 14 and 15). 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 scrams are

bypassed, high and low flow MCPR p operating limits are provided for operating between 25% RTP and the previously

mentioned bypass power level.

The MCPR satisfies Criterion 2 of the NRC Policy Statement(Ref. 7).

MCPR B 3.2.2 (continued)

BFN-UNIT 2B 3.2-8 Revision 0, 31 April 6, 2005 BASES (continued)

LCO The MCPR operating limits specified in the COLR are the result of the Design Basis Accident (DBA) and transient analysis.

Additional MCPR operating limits may be provided in the COLR to support analyzed equipment out-of-service operation. The operating limit MCPR is determined by the larger of the MCPR f and MCPR p limits. APPLICABILITYThe 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 minimum

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 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 range

of power and flow conditions. These studies 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 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.

MCPR B 3.2.2 (continued)

BFN-UNIT 2B 3.2-9 Revision 0 BASES (continued)

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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 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 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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.

MCPR B 3.2.2 (continued)

BFN-UNIT 2B 3.2-10 Revision 0, 31 April 6, 2005 BASES (continued) SURVEILLANCESR 3.2.2.1 REQUIREMENTS The MCPR is required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is

based on both engineering judgment and recognition of the

slowness of changes in power distribution during normal

operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.SR 3.2.2.2 Because the transient analysis takes credit for conservatism in the scram speed performance, it must be demonstrated that the

specific scram speed distribution is consistent with that used in the transient analysis. SR 3.2.2.2 determines the actual scram speed distribution and compares it with the assumed distribution. The MCPR operating limit is determined based either on the applicable limit associated with scram times of LCO 3.1.4, "Control Rod Scram Times," or the nominal scram times. The scram speed-dependent MCPR limits are contained in the COLR. This determination must be performed within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after each set of control rod scram time tests required bySR 3.1.4.1 and SR 3.1.4.2 because the effective scram speed distribution may change during the cycle. The 72-hour Completion Time is acceptable due to the relatively minor changes in the actual control rod scram speed distribution expected during the fuel cycle.

LHGR B 3.2.3 (continued)

BFN-UNIT 2B 3.2-13a Revision 31 , 61 December 7, 2010 BASES (continued)

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. Additional LHGR

operating limits adjustments may be provided in the COLR to

support analyzed equipment out-of-service operation.

Additional LHGR operating limits adjustments may be provided in the COLR to support analyzed equipment out-of-service operation. APPLICABILITYThe 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.

LHGR B 3.2.3 (continued)

BFN-UNIT 2B 3.2-14 Revision 0 BASES (continued)

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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 is reduced to < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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.

LHGR B 3.2.3 BFN-UNIT 2B 3.2-15 Revision 0 BASES (continued) SURVEILLANCESR 3.2.3.1 REQUIREMENTS The LHGR is required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is

based on both engineering judgment and recognition of the

slow changes in power distribution during normal operation.

The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels. REFERENCES1.FSAR, Chapter 14.2.FSAR, Chapter 3.3.NUREG-0800, Standard Review Plan 4.2,Section II.A.2(g), Revision 2, July 1981.4.NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-5 Revision 0 BASES APPLICABLE The trip setpoints are then determined accounting for the SAFETY ANALYSES, remaining in strument errors (e.g., drift). The trip setpoints LCO, and derived in this manner pr ovide adequate protection because APPLICABILITY instrumentation uncertain ties, process effects, calibration (continued) tolerances, instrument dr ift, and severe environmental effects (for channels that must func tion 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 or other specified conditions in the Table, which may require an RPS trip to mitigat e the consequences of a design basis accident or transient. To ensure a reliable scram function, a combination of Functions are required in each MODE to

provide primary and diverse initiation signals.

The only MODES specified in Table 3.3.1.1-1 are MODES 1 (which encompasses 30% RTP) and 2, and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies. No RPS Function is required in MODES 3 and 4 since all control rods are fu lly inserted and the Reactor Mode Switch Shutdown Position control rod withdrawal block (LCO 3.3.2.1) does not allow an y control rod to be withdrawn.

In MODE 5, control rods withdraw n from a core cell containing no fuel assemblies do not affect t he reactivity of the core and, therefore, are not required to have the capability to scram.

Provided all other control rods remain inserted, no RPS function

is 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.

The specific Applicable Safety Analyses, LCO, and Applicability

discussions are listed below on a Function by Function basis.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-10 Revision 0 BASES APPLICABLE 2.a. Average Power Range Monitor Neutron Flux - High, SAFETY ANALYSES, (Setdown)

LCO, and APPLICABILITY For operation at low power (i.e., MODE 2), the Average Power (continued) Range Monitor Neutron Flux - High, (Setdown) Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operatin g 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 Rang e 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 r un position, reactor power does not exceed 25% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow. Theref ore, it indirectly prevents fuel damage during significant reacti vity increases with THERMAL POWER < 25% RTP.

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 sinc e the potential for criticality exists. In MODE 1, the Average Power Range Monitor Neutron Flux - High Function provides protection against reactivity

transients and the RWM and rod block monitor protect against

control rod withdrawal error events.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-15a Amendment No. 258 March 05, 1999 BASES APPLICABLE 2.f. Oscillation Power Range Monitor (OPRM) Upscale SAFETY ANALYSES, LCO, and The OPRM Upscale Function provides compliance with GDC 10 APPLICABILITY and GDC 12, thereby providing protection from exceeding the (continued) fuel MCPR safety limit (S L) due to anticipated thermal hydraulic power oscillations.

References 13, 14, and 15 describe three algorithms for detecting thermal hydraulic inst ability related neutron flux oscillations: the period based de tection algorith m, the amplitude based algorithm, and the growth ra te algorithm. All three are implemented in the OPRM Upscal e Function, but the safety analysis takes credit only for the period based detection algorithm. The remaining algori thms provide defense in depth and additional protection against unanticipated oscillations.

OPRM Upscale Function OPERABILITY for Technical Specification purposes is based only on the period based detection algorithm.

The OPRM Upscale Function receives input signals from the local power range monitors (LPRMs) within the reactor core, which are combined into "cells" for evaluation of the OPRM algorithms.

The OPRM Upscale Function is required to be OPERABLE when the plant is in a region of power flow operation where anticipated events could lead to thermal hydraulic instability and related neutron flux oscillations. Within this region, the automatic trip is enabled when THERMAL POWER, as indicated by the APRM Simulated Thermal Power, is 25% RTP and reactor core flow, as i ndicated by recirculation drive flow is < 60% of rated flow, the operating region where actual thermal hydraulic oscillations ma y occur. Requiring the OPRM Upscale Function to be OPERABLE in MODE 1 provides consistency with operability requirements for other APRM functions and assures that the OPRM Upscale Function is OPERABLE whenever reactor power could increase into the region of concern wit hout operator action.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-23 Revision 0 41 November 09, 2006 BASES APPLICABLE 8. Turbine Stop Valve - Closure (continued) SAFETY ANALYSES, LCO, and Turbine Stop Valve - Closure signals are initiated from position APPLICABILITY switches located on each of the four TSVs. Two independent position switches are associated with each stop valve. One of the two switches provides input to RPS trip system A; the other, to RPS trip system B. Thus, each RPS trip system receives an

input from four Turbine Stop Valve - Closure channels, each consisting of one position switch.

The logic for the Turbine Stop Valve - Closure Function is such that three or more TSVs must

be closed to produce a scram. This Function must be enabled at THERMAL POWER 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this function.

The Turbine Stop Valve - Closure 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 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 Func tion if any three TSVs should close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is 30% RTP.

This Function is not required when THERMAL POWER is < 30% 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.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-24 Revision 0 41 November 09, 2006 BASES APPLICABLE 9. Turbine Control Valve Fa st Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and APPLICABILITY Fast closure of the TCVs re sults in the loss of a heat sink that (continued) 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 clos ure 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 7. For this event, the reactor scram

reduces the amount of energy re quired 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 electrohydraulic control (EHC) fluid pressure at each control valve. One pressure switch is

associated with each control valve, and the signal from each switch is assigned to a separat e RPS logic channel. This Function must be enabled at THERMAL POWER 30% RTP.

This is normally accomplished automatically by pressure

transmitters sensing turbine fi rst stage pressure; therefore, opening the turbine bypass valves may affect this function.

The Turbine Control Valve Fast Closure, Trip Oil Pressure -

Low Allowable Value is selected high enough to detect imminent TCV fast closure.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-25 Revision 0, 41 November 09, 2006 BASES APPLICABLE 9. Turbine Control Valve Fa st Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and (continued)

APPLICABILITY

Four channels of Turbine Contro l 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, consist ent with the analysis assumptions, whenever THERMAL POWER is 30% RTP. This Function is not required when THERMAL POWE R is < 30% 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.

For this instrument function, the nominal trip setpoint including the as-left tolerances is defi ned as the LSSS. The acceptable as-found band is based on a statistical combination of possible measurable uncertainties (i.e., setting tolerance, drift, temperature effects, and meas urement and test equipment). During instrument calibrations, if the as-found setpoint is found to be conservative with respect to the Allowable Value, but outside its acceptable as-f ound band (tolerance range), as defined by its associated Survei llance Requirement procedure, then there shall be an initial determination to ensure confidence that the channel can perform as required before returning the channel to service in accordance with the Surveillance. The technician performing the Su rveillance will evaluate the instrument's ability to maintain a stable setpoint within the as-left tolerance. The technician's ev aluation will be reviewed by on shift personnel during the approval of the Surveillance data prior to returning the channel back to se rvice at the completion of the Surveillance. This shall consti tute the initial determination of operability. If a channel is found to exceed the channel's Allowable Value or c annot be reset within the RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-37 Revision 0 BASES SURVEILLANCE SR 3.3.1.1.2 REQUIREMENTS (continued) To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor power calculated from a heat balance. The Frequency of once

per 7 days is based on minor c hanges in LPRM sensitivity, which could affect the APRM reading, between performances of

SR 3.3.1.1.7.

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 mainta in 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 satisfactor ily performed within the last 7 days, in accordance with SR 3.0.

2. A Note is provided which allows an increase in THERMAL POWER above 25% if the 7 day Frequency is not met per SR 3.

0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-45 Amendment No. 255 November 30, 1998 BASES SURVEILLANCE SR 3.3.1.1.15 REQUIREMENTS (continued) This SR ensures that scrams initiated from the Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions wi ll not be inadvertently bypassed when THERMAL POWER is 30% RTP. This involves calibration of the bypass channels (PIS-1-81A, PIS-1-81B, PIS-1-91A, and PIS-1-91B). Adequate margins for the

instrument setpoint methodolog ies are incorporated into the actual setpoint.

If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at 30% RTP, either due to open main turbine bypass valve(s) or other reasons), then the affected Turbine Stop Valve - Closure 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 (nonb ypass). If placed in the nonbypass condition (Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low

Functions are enabled), this SR is met and the channel is considered OPERABLE.

The Frequency of 24 months is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 2 B 3.3-45a Amendment No. 258 March 05, 1999 BASES SURVEILLANCE SR 3.3.1.1.17 REQUIREMENTS (continued) This SR ensures that scrams initiated from OPRM Upscale Function (Function 2.f) will not be inadvertently bypassed when THERMAL POWER, as indica ted by the APRM Simulated Thermal Power, is 25% RTP and core flow, as indicated by recirculation drive flow, is < 60% rated core flow. This normally involves confirming the bypass setpoints. Adequate margins for the instrument setpoint methodol ogies are incorporated into the actual setpoint. The actual surveillance ensures that the OPRM Upscale Function is enabled (not bypassed) for the correct values of APRM Simulated Thermal Power and recirculation drive flow. Other surveillances ensure that the APRM Simulated Thermal Power and recirculation flow properly correlate with THERMAL POWER and core flow, respectively.

If any bypass setpoint is nonconservative (i.e., the OPRM Upscale Function is bypassed when APRM Simulated Thermal Power 25% RTP and recirculation drive flow < 60% rated), then the affected channel is co nsidered inoperable for the OPRM Upscale Function. Alter natively, the bypass setpoint may be adjusted to place the channel in a conservative condition (unbypass). If placed in the unbypassed condition, this SR is met and the channel is considered OPERABLE.

The frequency of 24 months is based on engineering judgment and reliability of the components.

Feedwater and Main Turbine High Wa ter Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 2 B 3.3-76 Revision 0 BASES (continued)

APPLICABLE The feedwater and main turbine high water level trip SAFETY ANALYSES instrumentation is assum ed to be capable of providing a turbine trip in the design basis transient analysis for a feedwater controller failure, maximum demand event (Ref. 1). The reactor vessel high water level trip indirectly initiates a reactor scram

from the main turbine trip (above 30% RTP) and trips the

feedwater pumps, thereby terminating the event. The reactor scram mitigates the reduction in MCPR.

Feedwater and main turbine high water level trip instrumentation satisfies Criterion 3 of the NRC Policy Statement (Ref. 3).

LCO The LCO requires two channels of the Reactor Vessel Water Level - High instrumentation per trip system to be OPERABLE to ensure that no single instru ment failure will prevent the feedwater pump turbines and ma in turbine trip on a valid Reactor Vessel Water Level - High signal. Both channels in

either trip system are needed to pr ovide trip signals in order for the feedwater and main turbine trips to occur. Each channel

must have its setpoint set withi n the specified Allowable Value of SR 3.3.2.2.3. The Allowable Value is se t to ensure that the thermal limits are not exceeded during the event. The actual setpoint is calibrated to be consistent with the applicable setpoint methodology assumptions.

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 successive CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.

Feedwater and Main Turbine High Wa ter Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 2 B 3.3-77 Revision 0, 31 April 6, 2005 BASES LCO Trip setpoints are those pr edetermined values of output at (continued) 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 out put value of the process parameter exceeds the se tpoint, the associated device (e.g., trip unit) changes state. The analyt ic limits are derived from the limiting values of the process parameter s obtained from the safety analysis. The Allowabl e Values are derived from the analytic limits, corrected for calib ration, process, and some of the instrument errors. A channel is inoperable if its actual trip setpoint is not within its requir ed Allowable Value. The trip setpoints are then determined a ccounting 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 environmental effects (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.

APPLICABILITY The feedwater and main turbine high water level trip instrumentation is required to be OPERABLE at 25% RTP to ensure that the fuel cladding in tegrity Safety Limit and the cladding 1% plastic strain lim it are not violated during the feedwater controller failure, maximum demand event. As discussed in the Bases for LCO 3.2.1, "Average Planar Linear Heat Generation Rate (APLHGR)," LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)

," and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)," sufficient margin to these limits exists below 25% RTP; t herefore, these requirements are only necessary when operating at or above this power level.

Feedwater and Main Turbine High Wa ter Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 2 B 3.3-80 Revision 0 BASES ACTIONS B.1 (continued)

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is suff icient for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of f eedwater and main turbine high water level trip instrumentation occurring during this period. It is also consistent with the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in

LCO 3.2.2 for Required Action A.1, since this instrumentation's purpose is to preclude a MCPR violation.

C.1 With the required channels not re stored to OPERABLE status or placed in trip, THERMAL POWER must be reduced to

< 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. As discussed in the Applicability

section of the Bases, operation below 25% RTP results in sufficient margin to the required limits, and the feedwater and main turbine high water level trip instrumentation is not required to protect fuel integrity during the feedwater controller failure, maximum demand event. The allowed Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is based on operating ex perience to reduce THERMAL POWER to < 25% RTP from full pow er conditions in an orderly manner and without chall enging plant systems.

SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for performance of required Surveill ances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains feedwater

and main turbine high water level trip capability. Upon

completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channe l must be returned to OPERABLE status

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 2 B 3.3-109 Revision 0 , 31 , 61 December 7, 2010 BASES BACKGROUND Each EOC-RPT trip system is a two-out-of-two logic for each (continued) Function; thus, either two TSV - Closure 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 syst em 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 and the TCV Fast Closure, Trip Oil SAFETY ANALYSES, Pressure - Low Functions are designed to trip the recirculation LCO, and pumps in the event of a turb ine trip or generator load rejection APPLICABILITY to mitigate the increase in neutron flux, heat flux, and reactor pressure, and to increase the margin to the MCPR SL and LHGR limits. The analytical methods and assumptions used in

evaluating the turbine trip and generator load rejection are summarized in References 2, 3, and 4.

To mitigate pressurization transi ent effects, the EOC-RPT must trip the recirculation pumps afte r initiation of cl osure movement of either the TSVs or the TCVs. The combined effects of this trip and a scram reduce fuel bundle power more rapidly than a

scram alone, resulting in an increased margin to the MCPR SL

and LHGR limits. Alternatively, MCPR limits for an inoperable EOC-RPT, as specified in the CO LR, are sufficient to prevent

violation of the MCPR Safety Li mit and fuel mechanical limits.

The EOC-RPT function is automatically disabled when turbine first stage pressure is < 30% RTP.

EOC-RPT instrumentation sati sfies Criterion 3 of the NRC Policy Statement (Ref. 6).

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 2 B 3.3-112 Revision 0 , 31 , 61 December 7, 2010 BASES APPLICABLE Turbine Stop Valve - Closure (continued) SAFETY ANALYSES, LCO, and Closure of the TSVs is dete rmined by measuring the position of APPLICABILITY each valve. There are two separate position signals associated with each stop valve, the signal from each switch being assigned to a separate trip channel. The logic for the TSV -

Closure Function is such that two or more TSVs must be closed to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves

may affect this function. To consider this function OPERABLE, bypass of the function must not occur when bypass valves are open. Four channels of TSV - Closure, with two channels in each trip system, are availabl e 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 Allowable Value is selected to detect imminent TSV

closure.

This protection is required, c onsistent with the safety analysis assumptions, whenever THERMAL POWER is 30% RTP. Below 30% RTP, the Reactor Vessel Steam Dome Pressure -

High and the Average Power Ra nge Monitor (APRM) Fixed Neutron Flux - High Functions of the Reactor Protection System (RPS) are adequate to maintain the necessary margin to the MCPR SL and LHGR limits.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 2 B 3.3-113 Revision 0, 31 April 6, 2005 BASES APPLICABLE Turbine Control Valve Fast Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and APPLICABILITY Fast closure of the TCVs during a generator load rejection (continued) results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transie nts 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 va lves. The EOC-RPT decreases reactor power and aids the reactor scram in ensuring that the MCPR SL and LHGR limits are not exceeded during the worst case transient.

Fast closure of the TCVs is determined by measuring the

electrohydraulic control fluid pre ssure at each control valve.

There is one pressure switch associated with each control valve, and the signal from each switch is assigned to a separate trip channel. The logic for t he TCV Fast Closure, Trip Oil Pressure - Low Function is such that two or more TCVs must be closed (pressure switch trips) to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 30% RTP.

This is normally accomplished automatically by pressure transmitters sensing turbine fi rst stage pressure; therefore, opening the turbine bypass valves may affect this function. To consider this function OPERABLE, bypass of the function must not occur when bypass valves are open. Four channels of TCV Fast Closure, Trip Oil Pressure - Low, with two channels in each trip system, are availabl e 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 immi nent TCV fast closure.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 2 B 3.3-114 Revision 0 BASES APPLICABLE Turbine Control Valve Fast Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and (continued)

APPLICABILITY

This protection is required c onsistent with the safety analysis whenever THERMAL POWER is 30% RTP. Below 30% RTP, the Reactor Vessel Steam Dome Pressure - High and the APRM Fixed Neutron Flux - Hi gh Functions of the RPS are adequate to maintain the necessary safety margins.

ACTIONS A Note has been provided to modify the ACTIONS related to EOC-RPT instrumentation channel

s. 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 sepa rate 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 inst rumentation channel.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 2 B 3.3-116 Revision 0 , 31 , 61 December 7, 2010 BASES ACTIONS B.1 and B.2 (continued)

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 capabilit

y. 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.

Alternately, Required Action B.2 requires the MCPR and LHGR limits for inoperable EOC-RPT, as specified in the COLR, to be

applied. This also restores the margin to MCPR and LHGR limits assumed in the safety analysis.

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is suff icient time 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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in LCO 3.2.2 for Required Action A.1, since this instrumentation's purpose is to preclude a MCPR or LHGR violation.

C.1 With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to < 30% RTP within

4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Comp letion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is reasonable, based on operating experience, to reduce THERMAL POWER to < 30% RTP fr om full power conditions in an orderly manner and without challenging plant systems.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 2 B 3.3-118 Amendment No. 255 November 30, 1998 BASES SURVEILLANCE SR 3.3.4.1.2 REQUIREMENTS (continued) This SR ensures that an EOC-RPT initiated from the TSV - Closure and TCV Fast Closure, Trip Oil Pressure - Low

Functions will not be inadvertently bypassed when THERMAL POWER is 30% RTP. This involves calibration of the bypass channels. Adequate margins fo r the instrument setpoint methodologies are incorporated into the actual setpoint. If any bypass channel's setpoint is nonc onservative (i.e., the Functions are bypassed at 30% RTP, either due to open main turbine bypass valves or other reasons), the affected TSV - Closure and TCV Fast Closure, Trip Oil Pressure - Low Functions are considered inoperable. Alter natively, the bypass channel can be placed in the conservative condition (nonbypass). If placed

in the nonbypass condition, th is SR is met with the channel considered OPERABLE.

The Frequency of 24 months is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

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 param eter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account fo r instrument drifts between successive calibrations consist ent with the plant specific setpoint methodology. The Frequency is based upon the assumption of an 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

Jet Pumps B 3.4.2 BFN-UNIT 2 B 3.4-16 Revision 0 BASES SURVEILLANCE SR 3.4.2.1 (continued)

REQUIREMENTS

Note 2 allows this SR not to be performed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after THERMAL POWER exceeds 25% of RTP. During low flow

conditions, jet pump noise approaches the threshold response

of the associated flow instru mentation and precludes the collection of repeatable and meaningful data. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is an acceptable time to establish conditions appropriate to perform this SR.

REFERENCES 1. FSAR, Section 14.6.3.

2. GE Service Information Letter No. 330, "Jet Pump Beam Cracks," June 9, 1980.

3. NUREG/CR-3052, "Closeout of IE Bulletin 80-07: BWR Jet Pump Assembly Failure," November 1984.

4. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

Primary Containment B 3.6.1.1

(continued)

BFN-UNIT 2 B 3.6-3 Amendment No. 254 September 08, 1998 BASES APPLICABLE The maximum allowable leakage rate for the primary SAFETY ANALYSES containment (L a) is 2.0% by weight of the containment air per (continued) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the design bas is LOCA maximum peak containment pressure (P a) of 50.6 psig (Ref. 1).

Primary containment satisfies Criterion 3 of the NRC Policy Statement (Ref. 6).

LCO Primary containment OPERABILITY is maintained by limiting leakage to 1.0 L a , except prior to the first startup after performing a required Primary Containment Leakage Rate Testing Program leakage test. At this time, applicable leakage limits must be met. Compliance with this LCO will ensure a

primary containment configuration, including equipment hatches, that is structurally s ound and that will limit leakage to those leakage rates assumed in the safety analyses.

Individual leakage rates specif ied for the prim ary containment air lock 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 primar y 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, prim ary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of

radioactive material from primary containment.

Primary Containment B 3.6.1.1 BFN-UNIT 2 B 3.6-6 Amendment No. 255 November 30, 1998 BASES SURVEILLANCE SR 3.6.1.1.2 (continued)

REQUIREMENTS

Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber and veri fying that the pressure in either the suppression chambe r or the drywell does not change by more than 0.25 inch of wate r per minute over a 10 minute period. The leakage test is per formed every 24 months. The 24 month Frequency was developed considering it is prudent that this Surveillance be performed during a unit outage and

also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs.

REFERENCES 1. FSAR, Section 5.2.

2. FSAR, Section 14.6.

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

4. NEI 94-01, Revision O, "Industr y Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J." 5. ANSI/ANS-56.8-1994, "Ame rican National Standard for Containment System Leakage Testing Requirement."

6. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

Primary Containment Air Lock B 3.6.1.2

(continued)

BFN-UNIT 2 B 3.6-8 Amendment No. 254 September 08, 1998 BASES BACKGROUND the air lock to remain open for extended periods when frequent (continued) primary containment entry is necessary. Under some conditions allowed by this LCO, the prim ary containment may be accessed through the air lock, when the interlock mechanism has failed, by manually performing the interlock function.

The primary containment air lock forms 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 t hat assumed in the unit safety analysis.

APPLICABLE The DBA that postulates the maximum release of radioactive SAFETY ANALYSES material within primary containment is a LOCA. In the analysis of this accident, it is assum ed that primary containment is OPERABLE, such that releas e of fission products to the environment is controlled by the rate of primary containment leakage. The primar y containment is designed with a maximum allowable leakage rate (L a) of 2.0% by weight of the containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the calculat ed maximum peak containment pressure (P a) of 50.6 psig (Ref. 3). This allowable leakage rate forms the basis for the acceptance criteria imposed on the SRs associated with the air lock.

Primary containment air lock OPERABILITY is also required to

minimize the amount of fission product gases that may escape

primary containment through t he air lock and contaminate and pressurize the secondary containment.

The primary containment air lo ck satisfies Criterion 3 of the NRC Policy Statement (Ref. 4).

CAD System B 3.6.3.1

(continued)

BFN-UNIT 2 B 3.6-90 Revision 0 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.1 Containment Atmosphere Dilution (CAD) System BASES BACKGROUND The CAD Syst em functions to maintain combustible gas concentrations within the primary containment at or below the flammability limits following a postulated loss of coolant accident (LOCA) by diluting hydrogen and oxygen with nitrogen. To ensure that a combustible gas mixture does not occur, oxygen

concentration is kept < 5.0 volume percent (v/o), or hydrogen

concentration is kept < 4.0 v/o.

The CAD System is manually initiated and consists of two

independent, 100% capacity sub systems, each of which is capable of supplying nitrogen through separate piping systems to the drywell and suppression chamber of each unit. Each

subsystem includes a liquid nitrogen supply tank, ambient vaporizer, electric heater, and a m anifold with branches to each primary containment (for Unit s 1, 2, and 3).

The nitrogen storage tanks each contain 2500 gal, which is adequate for 7 days of CAD subsystem operation.

The CAD System operates in conjunction with emergency

operating procedures that ar e used to reduce primary containment pressure peri odically during CAD System operation. This combination results in a feed and bleed approach to maintaining hydrogen and oxygen concentrations below combustible levels.

CAD System B 3.6.3.1 (continued)

BFN-UNIT 2 B 3.6-95 Amendment No. 265 Revision 0 May 24, 2000 BASES (continued)

SURVEILLANCE SR 3.6.3.1.1 REQUIREMENTS Verifying that there is 2500 gal of liquid nitrogen supply in each nitrogen storage tank will ensure at least 7 days of post-LOCA CAD operation. This minimum volume of liquid

nitrogen allows sufficient time a fter an accident to replenish the nitrogen supply for long term inerti ng. This is verified every 31 days to ensure that the system is capable of performing its intended function when required. The 31 day Frequency is based on operating experience, which has shown 31 days to be an acceptable period to verify the liquid nitrogen supply and on

the availability of other hydrogen mitigating systems.

SR 3.6.3.1.2

Verifying the correct alignment for manual, power operated, and

automatic valves in each of the CAD subsystem flow paths provides assurance that the prop er flow paths exist for system operation. This SR does not appl y to valves that are locked, sealed, or otherwise secured in position, since these valves

were verified to be in the co rrect position prior to locking, sealing, or securing.

A valve is also allowed to be in the nonaccident position provided it can be aligned to t he accident position within the time assumed in the accident analysis. This is acceptable because the CAD System is manually initiated. This SR 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 mis positioned are in the correct position.

CAD System B 3.6.3.1 BFN-UNIT 2 B 3.6-96 Amendment No. 265 Revision 0 May 24, 2000 BASES SURVEILLANCE SR 3.6.3.1.2 (continued)

REQUIREMENTS

The 31 day Frequency is appropriate because the valves are

operated under procedural control, improper valve position would only affect a single subsystem, the probability of an event requiring initiation of the system is low, and the system is a manually initiated system.

REFERENCES 1. AEC Safety Guide 7, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident, March 10, 1971.

2. FSAR, Section 5.2.6.

3. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-1 Revision 73 Amendment No. 254 January 3, 2013 B 3.7 PLANT SYSTEMS B 3.7.1 Residual Heat Removal Service Water (RHRSW) System and Ultimate Heat Sink (UHS)

BASES BACKGROUND The RHRSW System is designed to provide cooling water for the Residual Heat Removal (RHR) System heat exchangers, required for a safe reactor shut down following a Design Basis Accident (DBA) or transient.

The RHRSW System is operated whenever the RHR heat exchanger s are required to operate in the shutdown cooling mode or in the suppression pool cooling or spray mode of the RHR System.

The RHRSW System is common to the three BFN units and consists of the UHS and four independent and redundant subsystems, each of which f eeds one RHR heat exchanger in each unit. Each subsystem is made up of a header, two 4500 gpm pumps, a suction source, valves, piping, and associated

instrumentation. Two subsyst ems, with one pump operating in each subsystem, are capable of pr oviding 100% of the required cooling capacity to maintain safe shutdown conditions for one unit. The RHRSW System is designed with sufficient redundancy so that no single active component failure can prevent it from achieving its design function. The RHRSW System is described in the FSAR, Section 10.9 (Ref. 1).

Cooling water is pumped by the RHRSW pumps from the Wheeler Reservoir through the tube side of the RHR heat exchangers, and discharged back to the Wheeler Reservoir.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-2 Revision 73 Ame ndment No. 254 January 3, 2013 BASES BACKGROUND The system is initiated manually from each of the three units (continued) control r ooms. If operating during a loss of coolant accident (LOCA), the system is automatic ally tripped on degraded bus voltage to allow the diesel gener ators to automatically power only that equipment necessary to reflood the core. The system can be manually started any time the degraded bus voltage signal clears, and is assumed to be manually started within 10 minutes after the LOCA.

APPLICABLE The RHRSW S ystem removes heat fr om the suppression pool SAFETY ANALYSES to limit the suppr ession pool temperature and primary containment pressure following a LOCA. This ensures that the primary containment can perform its function of limiting the release of radioactive materials to the environment following a

LOCA. The ability of the RHR SW System to support long term cooling of the reactor or primar y containment is discussed in the FSAR, Chapters 5 and 14 (Refs. 2 and 3, respectively). These analyses explicitly assume that the RHRSW System will provide adequate cooling support to the equipment required for safe

shutdown. These analyses include the evaluation of the long term primary containment response after a design basis LOCA.

The safety analyses for long term cooling were performed for various combinations of RHR System failures and considers the

number of units fueled. With one unit fueled, the worst case single failure that would affect the performance of the RHRSW System is any failure that would disable two subsystems of the RHRSW System.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-3 Revision 73 Ame ndment No. 254 January 3, 2013 BASES APPLICABLE With two and three units fueled, a worst case single failure SAFETY ANALYSES could also include the loss of two RHRSW pumps caused by (continued) losing a 4 kV shutdown board since there are certain alignment configurations that allow two RHRSW pumps to be powered from the same 4 kV shutdown bo ard. As discussed in the FSAR, Section 14.6.3.3.2 (Ref.

4) for these analyses, manual initiation of the OPERABLE RHRSW subsystems and the associated RHR System is assumed to occur 10 minutes after a

DBA. The analyses assume that there are two RHRSW subsystems operating in each unit, with one RHRSW pump in each subsystem capable of producing 4000 gpm of flow. In this case, the maximum suppression chamber water temperature and pressure are 177°F (as reported in Reference 3) and 50.6 psig, respectively, well below the design temperature of

281°F and maximum allowable pressure of 62 psig.

The RHRSW System together with the UHS satisfies Criterion 3

of the NRC Policy Statement (Ref 5).

LCO Four RHRSW subsystems are required to be OPERABLE to provide the required redundancy to ensure that the system

functions to remove post a ccident heat loads, assuming the worst case single active failure o ccurs coincident with the loss of offsite power. Additionally, since the RHRSW pumps are

shared between the three BFN unit s, the number of OPERABLE pumps required is also dependent on the number of units

fueled.

An RHRSW subsystem is considered OPERABLE when:

a. At least one RHRSW pump (i.e., one required RHRSW pump) is OPERABLE; and

b. An OPERABLE flow path is capable of taking suction from the intake structure and tr ansferring the water to the associated RHR heat exchanger at the assumed flow rate.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-4 Revision 44 , 73 Amendment No. 254 January 3, 2013 BASES LCO In addition to the required number of OPERABLE subsystems, (continued) there must be an adeq uate number of pumps OPERABLE to provide cooling for the fueled non-accident units.

The total number of required RHRSW pumps must take into consideration the required numbe r of pumps required for the specific unit along with the number of pumps required for other units that are fueled. Hence, when one unit contains fuel, four RHRSW pumps are required to be OPERABLE. When two units contain fuel, six RHRSW pumps are required to be OPERABLE. When three units contain fuel, eight RHRSW pumps are required to be OPERABLE. The minimum specified number of pumps gives consider ation to all units capable of producing heat in aggregate and a ccounts for a single active failure. The above pre-accident configuration ensures that during a design basis accident with a postulated single active failure, the resulting configuration for the accident unit has at least two RHRSW subsystems OPERABLE to supply 100 percent of the long term RHR cooling water. The resulting configuration for the non-accident units has at least two RHRSW subsystems per unit OPERABLE to supply 100 perc ent of the required cooling capacity to maintain safe shutdown conditions.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-4a Revision 44 , 73 January 3, 2013 BASES LCO The number of required OPERABLE RHRSW pumps (continued) is modified by a Note which specifies that the number of required RHRSW pumps may be reduced by one for each

fueled unit that has been in MODE 4 or 5 for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

This Note acknowledges the fa ct that decay heat removal requirements are substantially reduced for fueled units in

MODE 4 or 5 for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The OPERABILITY of the UHS for RHRSW is based on having

a maximum water temperature wit hin the limits specified in Figure 3.7.1-1.

APPLICABILITY In MODES 1, 2, and 3, the RHRSW System and UHS are required to be OPERABLE to s upport the OPERABILITY of the RHR System for primary containment cooling (LCO 3.6.2.3, "Residual Heat Removal (RHR) Suppression Pool Cooling," and LCO 3.6.2.4, "Residual Heat Removal (RHR) Suppression Pool

Spray") and decay heat removal (L CO 3.4.7, "Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown"). The Applicability is therefore c onsistent with the requirements of these systems.

In MODES 4 and 5, the OPER ABILITY requirements of the RHRSW System and UHS are dete rmined by the systems they support.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-5 Revision 73 Amendment No. 254 January 3, 2013 BASES (continued)

ACTIONS Since the RHRSW System is common to all three units, the following requirements must be followed when multiple units contain fuel:

a. With one or more requir ed RHRSW pumps inoperable, all applicable ACTIONS must be entered for each unit.

b. With one or more RHRSW subsystems inoperable, all applicable ACTIONS for inoperable subsystems must be entered on the unit(s) that hav e the inoperable subsystem.

The Required Actions and associated Completion Times of Conditions A, B, C, and D are based on a reduction in redundancy of the RHRSW System, not a loss of RHRSW safety function. The Required Actions and associated Completion Times of Conditions E, F, and G consider that the RHRSW safety function is lost.

RHRSW safety function is maintained when at least two RHRSW subsystems, with two separate RHRSW pumps (i.e. one per subsystem), on a per fuel ed unit basis, are OPERABLE. Additionally, the total number of RHRSW pumps must be such that the RHRSW pumps credited for maintaining the RHRSW safety function for a specific unit are not credited for maintaining the RHRSW safety function for a different fueled unit.

When there are three fueled units, the RHRSW safety function is maintained when:

• Two RHRSW subsystems per fu eled unit are OPERABLE;

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-5a Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS

• Six RHRSW pumps are OPERABLE (two RHRSW pumps (continued) per fueled unit);

• Each OPERABLE RHRSW subsystem has one required RHRSW pump OPERABLE; and

• The required RHRSW pump that is OPERABLE in an RHRSW subsystem is not cr edited for maintaining the RHRSW safety function for another fueled unit (i.e., it is not one of the two RHRSW pumps that is required to be OPERABLE for another fueled unit).

When there are two fueled units, the RHRSW safety function is maintained when:

• Two RHRSW subsystems per fueled unit are OPERABLE;

• Four RHRSW pumps are O PERABLE (two RHRSW pumps per fueled unit);

• Each OPERABLE RHRSW subsystem has one required RHRSW pump OPERABLE; and

• The required RHRSW pump that is OPERABLE in an RHRSW subsystem is not cr edited for maintaining the RHRSW safety function for another fueled unit (i.e., it is not one of the two RHRSW pumps that is required to be OPERABLE for another fueled unit).

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-5b Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS When there is one fueled unit, the RHRSW safety function is (continued) maintained when:

• Two RHRSW subsystems are OPERABLE and

• Two RHRSW pumps are OPERABLE (i.e., one per OPERABLE RHRSW subsystem).

When any combination of pump(s) and other subsystem components, e.g., heat exchanger(s), are inoperable such that three or more components of the RHRSW System (on any or all fueled units) are inoperable, the capability to meet the safety function must be evaluated by all fueled units. When an RHRSW pump is credited by one f ueled unit for maintaining the RHRSW safety function, then the other fueled units cannot also credit this same RHRSW pump with maintaining their RHRSW afety function since the capacity of a single RHRSW pump is not sufficient to support the r equired heat removal function of more than one RHR heat exchanger. Therefore, in this condition, the RHRSW pump credited with maintaining RHRSW safety function on a fueled unit must be considered inoperable for the other fueled units for purpose of determining if RHRSW safety function is maintained. The other fueled units must then include the additional inoperable RHRSW pump(s) with the total number of inoperable components when determining if RHRSW safety function is maintained. If RHRSW safety function is determined to be lost, then Conditi on E or F is required to be entered. The examples, with respect to RHRSW pumps, used in the following descriptions of the ACTIONS assume that three units are fueled.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-6 Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS A.1 and A.2 (continued)

With one required RHRSW pum p inoperable, the inoperable RHRSW pump must be restored to OPERABLE status within 30 days. With the unit in this condition, the remaining OPERABLE RHRSW pumps are adequate to perform the RHRSW heat

removal function. However, t he overall reliability is reduced because a single failure could result in reduced primary containment cooling capability. The 30 day Completion Time is based on the availability of equipment in excess of normal redundancy requirements and the low probability of an event occurring requiring RHRSW during this period.

Alternatively, five RHRSW pum ps may be verified to be OPERABLE with power being su pplied from separate 4 kV shutdown boards.

Required Action A1 is modified by two Notes. Note 1 indicates that the Required Action is applicable only when two units are fueled. In the two unit fueled condit ion, a single failure (loss of a 4 kV shutdown board) could result in inadequate RHRSW pumps if two pumps are powered fr om the same power supply.

If five RHRSW pumps are pow ered from separate 4 kV shutdown boards, then no postulated single active failure could occur to prevent the RHRSW system from performing its design function. Operation can continue indefinitely if Required Action A.1 is met.

Note 2 requires only four RHRSW pumps powered from separate 4 kV shutdown boards to be OPERABLE if the other fueled unit has been in Mode 4 or 5 greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This acknowledges the fact that decay heat removal requirements are substantially reduced for fueled units in Mode 4 or 5 for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

These two Notes clarify the situations under Required Action A.1 would be the appropria te Required Action.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-6a Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS B.1 (continued)

With one RHRSW subsystem inoperable (e.g., one RHR heat exchanger inoperable or an RHRSW header isolated) for reasons other than inoperable RHRSW pumps, which are covered by separate Conditions, the inoperable RHRSW subsystem must be restored to OPERABLE status within 30 days. With the unit in th is condition, the remaining OPERABLE RHRSW subsystems are adequate to perform the

RHRSW heat removal function. However, the overall reliability is reduced because a single failure could result in reduced

primary containment cooling cap ability. The 30 day Completion

Time is based on the availability of equipment in excess of

normal redundancy requirements and the low probability of an event occurring requiring RHRSW during this period.

The Required Action is modified by a Note indicating that the

applicable Conditions of LCO 3.4.7 be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-7 Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS C.1 (continued)

With two required RHRSW pumps inoperable (i.e., one required RHRSW pump inoperable in each of two separate RHRSW subsystems or two RHRSW pumps inoperable in the same RHRSW subsystem), the remaining RHRSW pumps are adequate to perform the RHRSW heat removal function.

However, the overall reliability is reduced because a single failure of the OPERABLE RHRSW pumps could result in a loss of RHRSW function. The seven day Completion Time is based

on the redundant RHRSW capabilities afforded by the

OPERABLE RHRSW pumps and the low probability of an event occurring during this period.

D.1 With two RHRSW subsystems inoperable (e.g., two RHR heat exchangers inoperable) for reas ons other than inoperable RHRSW pumps, which are covered by separate Conditions, the remaining OPERABLE RHRSW subsystems are adequate to perform the RHRSW heat removal function. However, the overall reliability is reduced becau se a single failure could result

in reduced primary containment cooling capability. The seven day Completion Time is based on the availability of equipment in excess of normal redundancy requirements and

the low probability of an event occurring requiring RHRSW during this period.

The Required Action is modified by a Note indicating that the

applicable Conditions of LCO 3.4.7 be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-8 Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS E.1 (continued)

With three or more requir ed RHRSW pumps inoperable, the RHRSW System is not capable of performing its intended function. The requisite number of pumps must be restored to OPERABLE status within ei ght hours. The eight hour Completion Time is based on the Completion Times provided for the RHR suppression pool c ooling and spray functions.

F.1 With three or more required RHRSW subsystems inoperable (e.g., one RHR heat exchanger inoperable in each of three or four separate RHRSW subsystems) for reasons other than inoperable RHRSW pumps, which are covered by separate Conditions, the RHRSW System is not capable of performing its intended function. The requisite number of subsystems must be restored to OPERABLE status within eight hours. The eight hour Completion Time is based on the Completion Times provided for the RHR suppression pool cooling and spray functions.

The Required Action is modified by a Note indicating that the

applicable Conditions of LCO 3.4.7 be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 2 B 3.7-9 Revision 73 Amendment No. 254 January 3, 2013 BASES ACTIONS G.1 and G.2 (continued)

If the RHRSW subsystem(s) or the RHRSW pump(s) cannot be restored to OPERABLE status wit hin the associated Completion Times or the UHS is determi ned inoperable, 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating

experience, to reach the require d unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.1.1 REQUIREMENTS

Verifying the correct alignment for each manual and power operated valve in each RHRSW sub system flow path provides assurance that the proper flow paths will exist for RHRSW

operation. This SR does not appl y to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct positi on prior to locking, sealing, or securing. A valve is also al lowed to be in the nonaccident position, and yet considered in t he correct position, provided it can be realigned to its accident po sition. This is acceptable because the RHRSW System is a manually initiated system.

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 is based on engineering judgment, is

consistent with the procedural controls governing valve operation, and ensures correct valve positions.

RHRSW System and UHS B 3.7.1 BFN-UNIT 2 B 3.7-10 Revision 69 Amendment No. 254 October 5, 2012 BASES SURVEILLANCE SR 3.7.1.2 REQUIREMENTS (continued) Verification of the UHS te mperature is within t he limits of Figure 3.7.1-1 ensures the heat removal capability of the RHRSW System is within the assumptions of the DBA analysis (Ref. 6).

The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Frequencies are based on operating

experience relating to trends of the parameter variations during the applicable MODES.

REFERENCES 1. FSAR, Section 10.9.

2. FSAR, Chapter 5.

3. FSAR, Chapter 14.

4. FSAR, Section 14.6.3.3.2.

5. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

6. FSAR, Section 14.6.3.3.2.3.

EECW System and UHS B 3.7.2 (continued)

BFN-UNIT 2 B 3.7-13 Amendment No. 254 September 08, 1998 BASES LCO The EECW System is consi dered OPERABLE when it has an (continued) OPERABLE UHS, three OPERABLE pumps, and two OPERABLE flow paths capable of taking suction from the intake structure and transferring t he water to the appropriate equipment.

The OPERABILITY of the UHS for EECW is based on having a maximum water temperature of 95°F. Additional requirements for UHS temperature are pr ovided in SR 3.7.1.2

The isolation of the EECW S ystem to components or systems may render those components or systems inoperable, but does

not affect the OPERABIL ITY of the EECW System.

APPLICABILITY In MODES 1, 2, and 3, the EECW System and UHS are required to be OPERABLE to support OPERABILITY of the

equipment serviced by the EECW System. Therefore, the EECW System and UHS are required to be OPERABLE in these MODES.

In MODES 4 and 5, the OPER ABILITY requirements of the EECW System and UHS are determined by the systems they support.

ACTIONS A.1

With one required EECW pump inoperable, the required EECW pump must be restored to OPERABLE status within 7 days.

With the system in this condition, the remaining OPERABLE

EECW pumps are adequate to perform the heat removal function. However, the overall reliability is reduced because a single failure in the EECW System could result in loss of EECW

function.

EECW System and UHS B 3.7.2 (continued)

BFN-UNIT 2 B 3.7-14 Revision 0 , 69 October 5, 2012 BASES ACTIONS A.1 (continued)

The 7 day Completion Time is based on the redundant EECW System capabilities afforded by the remaining OPERABLE

pumps, the low probability of an accident occurring during this time period and is consistent wit h the allowed Completion Time for restoring an inoperable DG.

B.1 and B.2

If the required EECW pump cannot be restored to OPERABLE status within the associated Comp letion Time, or two or more EECW pumps are inoperable or the UHS is determined inoperable, 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4

within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allo wed Completion Times are reasonable, based on operating experience, to reach the

required unit conditions from full power conditions in an orderly manner and without chall enging unit systems.

SURVEILLANCE SR 3.7.2.1 REQUIREMENTS

Verification of the UHS tem perature ensures that the heat removal capability of the EEC W System is within the

assumptions of the DBA analysis.

Additional requirements for UHS temperature to ensure RHRSW System heat removal capability is maintained within the assumptions of the DBA analysis are provided in SR 3.

7.1.2. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on operating experience related to trending of the

parameter variations during the applicable MODES.

Main Turbine Bypass System B 3.7.5 (continued)

BFN-UNIT 2 B 3.7-32 Revision 0 B 3.7 PLANT SYSTEMS B 3.7.5 Main Turbine Bypass System BASES BACKGROUND The Main Turbine Bypass S ystem is designed to control steam pressure when reactor steam generation exceeds turbine requirements during unit start up, sudden load reduction, and cooldown. It allows excess steam flow from the reactor to the

condenser without going through t he turbine. The bypass capacity of the system is 25%

of the Nuclear Steam Supply System rated steam flow. Sudde n load reductions within the capacity of the steam bypa ss can be accommodated without reactor scram. The Main Turbi ne Bypass System consists of nine valves connected to the ma in steam lines between the main steam isolation valves and the turbine stop valve bypass valve chest. Each of these nine valves is operated by hydraulic cylinders. The bypass valves are controlled by the pressure regulation function of the Pressure Regulator and Turbine Generator Control System, as discussed in the FSAR, Section 7.11.3.3 (Ref. 1).

The bypass valves are normally

closed, and the pressure regulator controls the turbine control valves that direct all steam flow to the turbine. If the speed governor or the load limiter restricts steam flow to the turbine, the pressure regulator controls the system pressure by opening the bypass valves. When the bypass valves open, the steam

flows from the bypass chest, th rough connecting piping, to the pressure breakdown assemblies, w here a series of orifices are used to further reduce the steam pressure before the steam enters the condenser.

Main Turbine Bypass System B 3.7.5 (continued)

BFN-UNIT 2 B 3.7-34 Revision 0, 31 April 6, 2005 BASES (continued)

APPLICABILITY The Main Turbine Bypass System is required to be OPERABLE at 25% RTP to ensure that the f uel cladding integrity Safety Limit is not violated during abnorma l operational transients. As

discussed in the Bases for LCO 3.2.1 and LCO 3.2.2, sufficient

margin to these limits exists at < 25% RTP. T herefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A.1

If the Main Turbine Bypass Syst em is inoperable (one or more bypass valves inoperable), or the APLHGR, MCPR, and LHGR limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are not ap plied, the assumptions of the design basis transient analysis may not be met. Under such circumstances, prompt action should be taken to restore the

Main Turbine Bypass System to OPERABLE status or adjust the APLHGR, MCPR, and LHGR limits accordingly. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is reasonable, based on the time to complete the Required Action and the low probability of an event occurring during this period requiring the Main Turbine Bypass

System.

B.1 If the Main Turbine Bypass S ystem cannot be restored to OPERABLE status or the APLHG R, MCPR, and LHGR limits for an inoperable Main Turbine Bypass System are not applied, THERMAL POWER must be reduced to < 25% RTP. As

discussed in the Applicability section, operation at < 25% RTP

results in sufficient margin to the required limits, and the Main

Reactor Core SLs B 2.1.1 (cont inued)BFN-UNIT 3B 2.0-3 Revision 0 , 25 , 61 December 7, 2010 BASES APPLICABLE2.1.1.1 Fuel Cladding Integrity SAFETY ANALYSES (continued)The SPCB critical power correlation is used for AREVA fuel and is valid at pressures 700 psia and bundle mass fluxes 0.1 x 10 6 lb m/hr-ft 2 (>12,000 lb m/hr, i.e., >

10% core flow, on a per bundle basis). For thermal margin monitoring at 25% power andhigher, the hot channel flow rate will be >28,000 lb m/hr (core flow not less than natural circulation, i.e., 25%-30% core flow for 25% power); therefore, the fuel cladding integrity SL is conservative relative to the applicable range of the SPCB critical power correlation. For operation at low pressures or low flows, another basis is used, as follows:

The static head across the fuel bundles due only to

elevation effects from liquid only in the channel, core

bypass region, and annulus at zero power, zero flow is

approximately 4.5 psi. At all operating conditions, this

pressure differential is maintained by the bypass region of

the core and the annulus region of the vessel. The

elevation head provided by the annulus produces natural

circulation flow conditions which have balancing pressure

head and loss terms inside the core shroud. This natural

circulation principle maintains a core plenum to plenum

pressure drop of about 4.5 to 5 psid along the natural

circulation flow line of the P/F operating map. In the range

of power levels of interest, approaching 25% of rated

power below which thermal margin monitoring is not

required, the pressure drop and density head terms

tradeoff for power changes such that natural circulation

flow is nearly independent of reactor power. This

characteristic is represented by the nearly vertical portion

of the natural circulation line on the P/F operating map.

Analysis has shown that the hot channel flow rate is

>28,000 lb m/hr (>0.23 x 10 6 lb m/hr-ft 2) in the region of operation with power ~25% and core pressure drop of

about 4.5 to 5 psid. Full scale ATLAS test data taken at

pressures from 14.7 psia to 800 psia indicate that the fuel

assembly critical power at 28,000 lb m/hr is approximately 3 Reactor Core SLs B 2.1.1 (cont inued)BFN-UNIT 3B 2.0-4 Revision 0 , 25 , 61 December 7, 2010 BASES APPLICABLE2.1.1.1 Fuel Cladding Integrity (continued)

SAFETY ANALYSES MW t. With the design peaking factors, this corresponds to a core thermal power of more than 50%.

Thus operation up to 25% of rated power with normal

natural circulation available is conservatively acceptable

even if reactor pressure is equal to or below the lower

pressure limit of the SPCB correlation. If reactor power is

significantly less than 25% of rated (e.g., below 10% of

rated), the core flow and the channel flow supported by the

available driving head may be less than 28,000 lb m/hr (along the lower portion of the natural circulation flow

characteristic on the P/F map). However, the critical power

that can be supported by the core and hot channel flow

with normal natural circulation paths available remains well

above the actual power conditions. The inherent

characteristics of BWR natural circulation make power and

core flow follow the natural circulation line as long as

normal water level is maintained.

Thus, operation with core thermal power below 25% of rated

without thermal margin surveillance is conservatively

acceptable even for reactor operations at natural circulation.

Adequate fuel thermal margins are also maintained without

further surveillance for the low power conditions that would be

present if core natural circulation is below the lower flow limit of

the SPCB correlation.

SLC System B 3.1.7 (cont inued)BFN-UNIT 3B 3.1-48 Revision 0 , 29 January 25, 2005 BASES BACKGROUNDThe worst case sodium pentaborate solution concentration (continued)required to shutdown the reactor with sufficient margin to account for 0.05 k/k and Xenon poisoning effects is 9.2 weight percent. This corresponds to a 40 F saturation temperature.

The worst case SLCS equipment area temperature is not predicted to fall below 50 F. This provides a 10 F thermal margin to unwanted precipitation of the sodium pentaborate.

Tank heating components provide backup assurance that the

sodium pentaborate solution temperature will never fall below 50 F but are not required for TS operability considerations. APPLICABLEThe SLC System is manually initiated from the main controlSAFETY ANALYSESroom, as directed by the emergency operating instructions, if the operator believes the reactor cannot be shut down, or kept

shut down, with the control rods. The SLC System is used in

the event that enough control rods cannot be inserted to

accomplish shutdown and cooldown in the normal manner. The

SLC System injects borated water into the reactor core to add

negative reactivity to compensate for all of the various reactivity

effects that could occur during plant operations. To meet this

objective, it is necessary to inject a quantity of boron, which

produces a concentration of 660 ppm of natural boron, in the reactor coolant at 70 F. To allow for imperfect mixing, leakage and the volume in other piping connected to the reactor system, an amount of boron equal to 25% of the amount cited above is

added (Ref. 2). This volume versus concentration limit and 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 entire 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.

SLC System B 3.1.7 (cont inued)BFN-UNIT 3B 3.1-52 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCESR 3.1.7.1 (continued)

REQUIREMENTS pentaborate solution concentration requirements ( 9.2% by weight) and the required quantity of Boron-10 ( 186 lbs)establish the tank volume requirement. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency

is based on operating experience that has shown there are

relatively slow variations in the solution volume.SR 3.1.7.2SR 3.1.7.2 verifies the continuity of the explosive charges in the injection valves to ensure that proper operation will occur if

required. An automatic continuity monitor may be used to

continuously satisfy this requirement. 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 and has demonstrated the reliability of the

explosive charge continuity.SR 3.1.7.3SR 3.1.7.3 requires an examination of sodium pentaborate solution by using chemical analysis to ensure that the proper concentration of boron exists in the storage tank for post-LOCA suppression pool pH control. This parameter is used as inputto determine the volume requirements for SR 3.1.7.1. The concentration is dependent upon the volume of water and quantity of boron in the storage tank.

SR 3.1.7.3 must be performed every 31 days or within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of when boron or water is added to the storage tank solution to determine that the boron solution concentration is within the specified limits. The 31 day Frequency of this Surveillance is appropriate because of the relatively slow variation of boron concentration between surveillances.

SLC System B 3.1.7 (cont inued)BFN-UNIT 3B 3.1-53 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCESR 3.1.7.4 and SR 3.1.7.6 REQUIREMENTS (continued)SR 3.1.7.4 requires an examination of the sodium pentaborate solution by using chemical analysis to ensure that the proper

concentration of boron exists in the storage tank. The

concentration is dependent upon the volume of water and

quantity of boron in the storage tank. SR 3.1.7.6 requires verification that the SLC system conditions satisfy the following

equation:( C )( Q )( E ) ( 13 WT % )( 86 GPM )( 19.8 ATOM % ) > = 1.0 C = sodium pentaborate solution weight percent

concentration

Q = SLC system pump flow rate in gpm

E = Boron-10 atom percent enrichment in the sodium

pentaborate solutionTo meet 10 CFR 50.62, the SLC System must have a minimum flow capacity and boron content equivalent in control capacity

to 86 gpm of 13 weight percent natural sodium pentaborate

solution. The atom percentage of natural B-10 is 19.8%. This

equivalency requirement is met when the equation given above

is satisfied. The equation can be satisfied by adjusting the

solution concentration, pump flow rate or Boron-10 enrichment.

If the results of the equation are < 1, the SLC System is no

longer capable of shutting down the reactor with the margin

described in Reference 2. However, the quantity of stored

boron includes an additional margin (25%) beyond the amount

needed to shut down the reactor to allow for possible imperfect

mixing of the chemical solution in the reactor water, leakage, and the volume in other piping connected to the reactor system.

The sodium pentaborate solution (SPB) concentration is allowed to be > 9.2 weight percent provided the concentration

and temperature of the sodium pentaborate solution are verified SLC System B 3.1.7 BFN-UNIT 3B 3.1-57 Revision 0 , 29 January 25, 2005 BASES SURVEILLANCESR 3.1.7.11 REQUIREMENTS (continued)SR 3.1.7.11 verifies that 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 Flowpath

provides assurance 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 also

does not apply to valves that are locked, sealed, or otherwise

secured in position since they are verified to be in the correct

position prior to locking, sealing or securing. This verification of

valve alignment 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 is

based on engineering judgment and is consistent with the

procedural controls governing valve operation that ensures

correct valve positions. REFERENCES1.10 CFR 50.62.2.FSAR, Section 3.8.4.3. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.4. FSAR, Section 14.6.

APLHGR B 3.2.1 (continued)

BFN-UNIT 3B 3.2-3b Revision 25 , 61 December 7, 2010 BASES (continued) APPLICABILITYAPLHGR limits are primarily derived from fuel design evaluations and LOCA and transient analyses assumed to occur at high power levels. Design calculations 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 scram function provides prompt scram 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 is operating with substantial margin to the APLHGR limits; thus, this LCO is not required.

APLHGR B 3.2.1 (continued)

BFN-UNIT 3B 3.2-4 Amendment No. 213 September 03, 1998 BASES (continued)

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 should be taken to

restore the APLHGR(s) to within the required limits such that

the plant operates within analyzed conditions and within design limits of the fuel rods. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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. SURVEILLANCESR 3.2.1.1 REQUIREMENTS APLHGRs are required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is

based on both engineering judgment and recognition of the

slowness of changes in power distribution during normal

operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

MCPR B 3.2.2 (continued)

BFN-UNIT 3B 3.2-7 Revision 25 , 61 Amendment No. 216 December 7, 2010 BASES APPLICABLEevaluated are loss of flow, increase in pressure and power, SAFETY ANALYSESpositive reactivity insertion, and coolant temperature decrease. (continued)The limiting transient yields the largest change in CPR (CPR).When the largest CPR is added to the MCPR SL, the required operating limit MCPR is obtained.

The MCPR operating limits derived from the transient analysis are dependent on the operating core flow and power to ensure adherence to fuel design limits during the worst transient that

occurs with moderate frequency. Flow dependent MCPR (MCPR f) limits are determined by steady-state thermal hydraulic methods using the three-dimensional BWR simulator code (Reference 12) and the multichannel thermal hydraulic code (Reference 13). The operating limit is dependent on the

maximum core flow limiter setting in the Recirculation Flow

Control System.

Power-dependent MCPR limits (MCPR p) are determined by the three-dimensional BWR simulator code (Ref. 12) and the one-dimensional transient codes (Refs. 14 and 15). 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 scrams are

bypassed, high and low flow MCPR p operating limits are provided for operating between 25% RTP and the previously

mentioned bypass power level.

The MCPR satisfies Criterion 2 of the NRC Policy Statement(Ref. 7).

MCPR B 3.2.2 (continued)

BFN-UNIT 3B 3.2-8 Revision 25 Amendment No. 213 March 12, 2004 BASES (continued)

LCO The MCPR operating limits specified in the COLR are the result of the Design Basis Accident (DBA) and transient analysis.

Additional MCPR operating limits may be provided in the COLR to support analyzed equipment out-of-service operation. The operating limit MCPR is determined by the larger of the MCPR f and MCPR p limits. APPLICABILITYThe 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 minimum

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 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 range

of power and flow conditions. These studies 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 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.

MCPR B 3.2.2 (continued)

BFN-UNIT 3B 3.2-9 Amendment No. 213 September 03, 1998 BASES (continued)

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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 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 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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.

MCPR B 3.2.2 (continued)

BFN-UNIT 3B 3.2-10 Revision 25 Amendment No. 213 March 12, 2004 BASES (continued) SURVEILLANCESR 3.2.2.1 REQUIREMENTS The MCPR is required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is

based on both engineering judgment and recognition of the

slowness of changes in power distribution during normal

operation. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.SR 3.2.2.2 Because the transient analysis takes credit for conservatism in the scram speed performance, it must be demonstrated that the

specific scram speed distribution is consistent with that used in the transient analysis. SR 3.2.2.2 determines the actual scram speed distribution and compares it with the assumed distribution. The MCPR operating limit is determined basedeither on the applicable limit associated with scram times of LCO 3.1.4, "Control Rod Scram Times," or the nominal scramtimes. The scram speed-dependent MCPR limits are contained in the COLR. This determination must be performed within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> after each set of control rod scram time tests required bySR 3.1.4.1 and SR 3.1.4.2 because the effective scram speed distribution may change during the cycle. The 72-hour Completion Time is acceptable due to the relatively minor changes in the actual control rod scram speed distribution expected during the fuel cycle.

LHGR B 3.2.3 (continued)

BFN-UNIT 3B 3.2-13a Revision 25 , 61 December 7, 2010 BASES (continued)

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. Additional LHGR

operating limits adjustments may be provided in the COLR to

support analyzed equipment out-of-service operation.

Additional LHGR operating limits adjustments may be provided in the COLR to support analyzed equipment out-of-service operation. APPLICABILITYThe 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.

LHGR B 3.2.3 (continued)

BFN-UNIT 3B 3.2-14 Amendment No. 213 September 03, 1998 BASES (continued)

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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> 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 is reduced to < 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. 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.

LHGR B 3.2.3 BFN-UNIT 3B 3.2-15 Amendment No. 213 September 03, 1998 BASES (continued) SURVEILLANCESR 3.2.3.1 REQUIREMENTS The LHGR is required to be initially calculated within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after THERMAL POWER is 25% RTP and then every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> 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 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is

based on both engineering judgment and recognition of the

slow changes in power distribution during normal operation.

The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> allowance after THERMAL POWER 25% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels. REFERENCES1.FSAR, Chapter 14.2.FSAR, Chapter 3.3.NUREG-0800, Standard Review Plan 4.2,Section II.A.2(g), Revision 2, July 1981.4.NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-5 Revision 0 BASES APPLICABLE The trip setpoints are then determined accounting for the SAFETY ANALYSES, remaining in strument errors (e.g., drift). The trip setpoints LCO, and derived in this manner pr ovide adequate protection because APPLICABILITY instrumentation uncertain ties, process effects, calibration (continued) tolerances, instrument dr ift, and severe environmental effects (for channels that must func tion 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 or other specified conditions in the Table, which may require an RPS trip to mitigat e the consequences of a design basis accident or transient. To ensure a reliable scram function, a combination of Functions are required in each MODE to

provide primary and diverse initiation signals.

The only MODES specified in Table 3.3.1.1-1 are MODES 1 (which encompasses 30% RTP) and 2, and MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies. No RPS Function is required in MODES 3 and 4 since all control rods are fu lly inserted and the Reactor Mode Switch Shutdown Position control rod withdrawal block (LCO 3.3.2.1) does not allow an y control rod to be withdrawn.

In MODE 5, control rods withdraw n from a core cell containing no fuel assemblies do not affect t he reactivity of the core and, therefore, are not required to have the capability to scram.

Provided all other control rods remain inserted, no RPS function

is 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.

The specific Applicable Safety Analyses, LCO, and Applicability

discussions are listed below on a Function by Function basis.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-10 Amendment No. 213 September 03, 1998 BASES APPLICABLE 2.a. Average Power Range Monitor Neutron Flux - High, SAFETY ANALYSES, (Setdown)

LCO, and APPLICABILITY For operation at low power (i.e., MODE 2), the Average Power (continued) Range Monitor Neutron Flux - High, (Setdown) Function is capable of generating a trip signal that prevents fuel damage resulting from abnormal operatin g 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 r un position, reactor power does not exceed 25% RTP (SL 2.1.1.1) when operating at low reactor pressure and low core flow. Theref ore, it indirectly prevents fuel damage during significant reacti vity increases with THERMAL POWER < 25% RTP.

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 sinc e the potential for criticality exists. In MODE 1, the Average Power Range Monitor Neutron Flux - High Function provides protection against reactivity

transients and the RWM and rod block monitor protect against

control rod withdrawal error events.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-15a Amendment No. 221 September 27, 1999 BASES APPLICABLE 2.f. Oscillation Power Range Monitor (OPRM) Upscale SAFETY ANALYSES, LCO, and The OPRM Upscale Function provides compliance with GDC 10 APPLICABILITY and GDC 12, thereby providing protection from exceeding the (continued) fuel MCPR safety limit (S L) due to anticipated thermal hydraulic power oscillations.

References 13, 14, and 15 describe three algorithms for detecting thermal hydraulic inst ability related neutron flux oscillations: the period based de tection algorith m, the amplitude based algorithm, and the growth ra te algorithm. All three are implemented in the OPRM Upscal e Function, but the safety analysis takes credit only for the period based detection algorithm. The remaining algori thms provide defense in depth and additional protection against unanticipated oscillations.

OPRM Upscale Function OPERABILITY for Technical Specification purposes is based only on the period based detection algorithm.

The OPRM Upscale Function receives input signals from the local power range monitors (LPRMs) within the reactor core, which are combined into "cells

" for evaluation of the OPRM algorithms.

The OPRM Upscale Function is required to be OPERABLE when the plant is in a region of power flow operation where anticipated events could lead to thermal hydraulic instability and related neutron flux oscillations. Within this region, the automatic trip is enabled when THERMAL POWER, as indicated by the APRM Simulated Thermal Power, is 25% RTP and reactor core flow, as i ndicated by recirculation drive flow is 60% of rated flow, the oper ating region where actual thermal hydraulic oscillations ma y occur. Requiring the OPRM Upscale Function to be OPERABLE in MODE 1 provides consistency with operability requirements for other APRM functions and assures that the OPRM Upscale Function is OPERABLE whenever reactor power could increase into the region of concern with out operator action.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-23 Amendment No. 213 September 03, 1998 BASES APPLICABLE 8. Turbine Stop Valve - Closure (continued) SAFETY ANALYSES, LCO, and Turbine Stop Valve - Closure signals are initiated from position APPLICABILITY switches located on each of the four TSVs. Two independent position switches are associated with each stop valve. One of the two switches provides input to RPS trip system A; the other, to RPS trip system B. Thus, each RPS trip system receives an

input from four Turbine Stop Valve - Closure channels, each consisting of one position switch.

The logic for the Turbine Stop Valve - Closure Function is such that three or more TSVs must

be closed to produce a scram. This Function must be enabled at THERMAL POWER 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves may affect this function.

The Turbine Stop Valve - Closure 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 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 Func tion if any three TSVs should close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is 30% RTP.

This Function is not required when THERMAL POWER is < 30% 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.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-24 Amendment No. 213 September 03, 1998 BASES APPLICABLE 9. Turbine Control Valve Fa st Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and APPLICABILITY Fast closure of the TCVs re sults in the loss of a heat sink that (continued) 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 clos ure 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 7. For this event, the reactor scram

reduces the amount of energy re quired 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 electrohydraulic control (EHC) fluid pressure at each control valve. One pressure switch is

associated with each control valve, and the signal from each switch is assigned to a separat e RPS logic channel. This Function must be enabled at THERMAL POWER 30% RTP.

This is normally accomplished automatically by pressure

transmitters sensing turbine fi rst stage pressure; therefore, opening the turbine bypass valves may affect this function.

The Turbine Control Valve Fast Closure, Trip Oil Pressure -

Low Allowable Value is selected high enough to detect imminent TCV fast closure.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-25 Amendm ent No. 213, Revision 41 November 09, 2006 BASES APPLICABLE 9. Turbine Control Valve Fa st Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and (continued)

APPLICABILITY

Four channels of Turbine Contro l 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, consist ent with the analysis assumptions, whenever THERMAL POWER is 30% RTP. This Function is not required when THERMAL POWE R is < 30% 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.

For this instrument function, the nominal trip setpoint including the as-left tolerances is defi ned as the LSSS. The acceptable as-found band is based on a statistical combination of possible measurable uncertainties (i.e., setting tolerance, drift, temperature effects, and meas urement and test equipment). During instrument calibrations, if the as-found setpoint is found to be conservative with respect to the Allowable Value, but outside its acceptable as-f ound band (tolerance range), as defined by its associated Survei llance Requirement procedure, then there shall be an initial determination to ensure confidence that the channel can perform as required before returning the channel to service in accordance with the Surveillance. The technician performing the Surveillance will evaluate the instrument's ability to maintain a stable setpoint within the as-left tolerance. The technician's ev aluation will be reviewed by on shift personnel during the approval of the Surveillance data prior to returning the channel back to se rvice at the completion of the Surveillance. This shall consti tute the initial determination of operability. If a channel is found to exceed the channel's Allowable Value or c annot be reset within the RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-37 Amendment No. 213 September 03, 1998 BASES SURVEILLANCE SR 3.3.1.1.2 REQUIREMENTS (continued) To ensure that the APRMs are accurately indicating the true core average power, the APRMs are calibrated to the reactor power calculated from a heat balance. The Frequency of once per 7 days is based on minor c hanges in LPRM sensitivity, which could affect the APRM reading, between performances of

SR 3.3.1.1.7.

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 mainta in 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 satisfactor ily performed within the last 7 days, in accordance with SR 3.0.

2. A Note is provided which allows an increase in THERMAL POWER above 25% if the 7 day Frequency is not met per SR 3.

0.2. In this event, the SR must be performed within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> 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.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-45 Amendment No. 215 November 30, 1998 BASES SURVEILLANCE SR 3.3.1.1.15 REQUIREMENTS (continued) This SR ensures that scrams initiated from the Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low Functions wi ll not be inadvertently bypassed when THERMAL POWER is 30% RTP. This involves calibration of the bypass channels (PIS-1-81A, PIS-1-81B, PIS-1-91A, and PIS-1-91B). Adequate margins for the

instrument setpoint methodolog ies are incorporated into the actual setpoint.

If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at 30% RTP, either due to open main turbine bypass valve(s) or other reasons), then the affected Turbine Stop Valve - Closure 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 (nonb ypass). If placed in the nonbypass condition (Turbine Stop Valve - Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure - Low

Functions are enabled), this SR is met and the channel is considered OPERABLE.

The Frequency of 24 months is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

RPS Instrumentation B 3.3.1.1 (continued)

BFN-UNIT 3 B 3.3-45a Amendment No. 221 September 27, 1999 BASES SURVEILLANCE SR 3.3.1.1.17 REQUIREMENTS (continued) This SR ensures that scrams initiated from OPRM Upscale Function (Function 2.f) will not be inadvertently bypassed when THERMAL POWER, as indica ted by the APRM Simulated Thermal Power, is 25% RTP and core flow, as indicated by recirculation drive flow, is

< 60% rated core flow. This normally involves confirming the bypass setpoints. Adequate margins for the instrument setpoint methodol ogies are incorporated into the actual setpoint. The actual surveillance ensures that the OPRM Upscale Function is enabled (not bypassed) for the correct values of APRM Simulated Thermal Power and recirculation drive flow. Other surveillances ensure that the APRM Simulated Thermal Power and recirculation flow properly correlate with THERMAL POWER and core flow, respectively.

If any bypass setpoint is nonconservative (i.e., the OPRM Upscale Function is bypassed when APRM Simulated Thermal Power 25% RTP and recirculation drive flow

< 60% rated), then the affected channel is co nsidered inoperable for the OPRM Upscale Function. Alternatively, the bypass setpont may be adjusted to place the channel in a conservative condition (unbypass). If placed in the unbypassed condition, this SR is met and the channel is considered OPERABLE.

The frequency of 24 months is based on engineering judgment and reliability of the components.

Feedwater and Main Turbine High Wa ter Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 3 B 3.3-76 Amendment No. 213 September 03, 1998 BASES (continued)

APPLICABLE The feedwater and main turbine high water level trip SAFETY ANALYSES instrumentation is assum ed to be capable of providing a turbine trip in the design basis transient analysis for a feedwater controller failure, maximum demand event (Ref. 1). The reactor vessel high water level trip indirectly initiates a reactor scram

from the main turbine trip (above 30% RTP) and trips the

feedwater pumps, thereby terminating the event. The reactor scram mitigates the reduction in MCPR.

Feedwater and main turbine high water level trip instrumentation satisfies Criterion 3 of the NRC Policy Statement (Ref. 3).

LCO The LCO requires two channels of the Reactor Vessel Water Level - High instrumentation per trip system to be OPERABLE to ensure that no single instru ment failure will prevent the feedwater pump turbines and ma in turbine trip on a valid Reactor Vessel Water Level - High signal. Both channels in

either trip system are needed to pr ovide trip signals in order for the feedwater and main turbine trips to occur. Each channel

must have its setpoint set withi n the specified Allowable Value of SR 3.3.2.2.3. The Allowable Value is se t to ensure that the thermal limits are not exceeded during the event. The actual setpoint is calibrated to be consistent with the applicable setpoint methodology assumptions.

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 successive CHANNEL CALIBRATIONS. Operation with a trip setpoint less conservative than the nominal trip setpoint, but within its Allowable Value, is acceptable.

Feedwater and Main Turbine High Wa ter Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 3 B 3.3-77 Revision 25 Amendment No. 213 March 12, 2004 BASES LCO Trip setpoints are those pr edetermined values of output at (continued) 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 out put value of the process parameter exceeds the setpoint, the associated device (e.g., trip unit) changes state. The analyt ic limits are derived from the limiting values of the process parameter s obtained from the safety analysis. The Allowabl e Values are derived from the analytic limits, corrected for calib ration, process, and some of the instrument errors. A channel is inoperable if its actual trip setpoint is not within its requir ed Allowable Value. The trip setpoints are then determined a ccounting 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 environmental effects (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for.

APPLICABILITY The feedwater and main turbine high water level trip instrumentation is required to be OPERABLE at 25% RTP to ensure that the fuel cladding in tegrity Safety Limit and the cladding 1% plastic strain lim it are not violated during the feedwater controller failure, maximum demand event. As

discussed in the Bases for LCO 3.2.1, "Average Planar Linear

Heat Generation Rate (APLHGR)," LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)

," and LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)," sufficient margin to these limits exists below 25% RTP; t herefore, these requirements are only necessary when operating at or above this power level.

Feedwater and Main Turbine High Wa ter Level Trip Instrumentation B 3.3.2.2 (continued)

BFN-UNIT 3 B 3.3-80 Amendment No. 213 September 03, 1998 BASES ACTIONS B.1 (continued)

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is suff icient for the operator to take corrective action, and takes into account the likelihood of an event requiring actuation of f eedwater and main turbine high water level trip instrumentation occurring during this period. It is also consistent with the 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in

LCO 3.2.2 for Required Action A.1, since this instrumentation's purpose is to preclude a MCPR violation.

C.1 With the required channels not re stored to OPERABLE status or placed in trip, THERMAL POWER must be reduced to

< 25% RTP within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. As discussed in the Applicability

section of the Bases, operation below 25% RTP results in sufficient margin to the required limits, and the feedwater and main turbine high water level trip instrumentation is not required to protect fuel integrity during the feedwater controller failure, maximum demand event. The allowed Completion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is based on operating ex perience to reduce THERMAL POWER to < 25% RTP from full pow er conditions in an orderly manner and without chall enging plant systems.

SURVEILLANCE The Surveillances are modified by a Note to indicate that REQUIREMENTS when a channel is placed in an inoperable status solely for performance of required Surveill ances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> provided the associated Function maintains feedwater

and main turbine high water level trip capability. Upon

completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowance, the channe l must be returned to OPERABLE status

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 3 B 3.3-109 Revision 25 , 61 Amendment No. 213 December 7, 2010 BASES BACKGROUND Each EOC-RPT trip system is a two-out-of-two logic for each (continued) Function; thus, either two TSV - Closure 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 syst em 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 and the TCV Fast Closure, Trip Oil SAFETY ANALYSES, Pressure - Low Functions are designed to trip the recirculation LCO, and pumps in the event of a turb ine trip or generator load rejection APPLICABILITY to mitigate the increase in neutron flux, heat flux, and reactor pressure, and to increase the margin to the MCPR SL and LHGR limits. The analytical methods and assumptions used in

evaluating the turbine trip and generator load rejection are summarized in References 2, 3, and 4.

To mitigate pressurization transi ent effects, the EOC-RPT must trip the recirculation pumps afte r initiation of cl osure movement of either the TSVs or the TCVs. The combined effects of this trip and a scram reduce fuel bundle power more rapidly than a

scram alone, resulting in an increased margin to the MCPR SL

and LHGR limits. Alternatively, MCPR limits for an inoperable EOC-RPT, as specified in the CO LR, are sufficient to prevent

violation of the MCPR Safety Li mit and fuel mechanical limits.

The EOC-RPT function is automatically disabled when turbine first stage pressure is < 30% RTP.

EOC-RPT instrumentation sati sfies Criterion 3 of the NRC Policy Statement (Ref. 6).

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 3 B 3.3-112 Revision 25 , 61 Amendment No. 213 December 7, 2010 BASES APPLICABLE Turbine Stop Valve - Closure (continued) SAFETY ANALYSES, LCO, and Closure of the TSVs is dete rmined by measuring the position of APPLICABILITY each valve. There are two separate position signals associated with each stop valve, the signal from each switch being assigned to a separate trip channel. The logic for the TSV -

Closure Function is such that two or more TSVs must be closed to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 30% RTP. This is normally accomplished automatically by pressure transmitters sensing turbine first stage pressure; therefore, opening the turbine bypass valves

may affect this function. To consider this function OPERABLE, bypass of the function must not occur when bypass valves are open. Four channels of TSV - Closure, with two channels in each trip system, are availabl e 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 Allowable Value is selected to detect imminent TSV

closure.

This protection is required, c onsistent with the safety analysis assumptions, whenever THERMAL POWER is 30% RTP. Below 30% RTP, the Reactor Vessel Steam Dome Pressure -

High and the Average Power Ra nge Monitor (APRM) Fixed Neutron Flux - High Functions of the Reactor Protection System (RPS) are adequate to maintain the necessary margin to the MCPR SL and LHGR limits.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 3 B 3.3-113 Revision 25 Amendment No. 213 March 12, 2004 BASES APPLICABLE Turbine Control Valve Fast Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and APPLICABILITY Fast closure of the TCVs during a generator load rejection (continued) results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transie nts 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 va lves. The EOC-RPT decreases reactor power and aids the reactor scram in ensuring that the MCPR SL and LHGR limits are not exceeded during the worst case transient.

Fast closure of the TCVs is determined by measuring the

electrohydraulic control fluid pre ssure at each control valve.

There is one pressure switch associated with each control valve, and the signal from each switch is assigned to a separate trip channel. The logic for t he TCV Fast Closure, Trip Oil Pressure - Low Function is such that two or more TCVs must be closed (pressure switch trips) to produce an EOC-RPT. This Function must be enabled at THERMAL POWER 30% RTP.

This is normally accomplished automatically by pressure transmitters sensing turbine fi rst stage pressure; therefore, opening the turbine bypass valves may affect this function. To

consider this function OPERABLE , bypass of the function must not occur when bypass valves are open. Four channels of TCV Fast Closure, Trip Oil Pressure - Low, with two channels in each trip system, are availabl e 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 immi nent TCV fast closure.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 3 B 3.3-114 Amendment No. 213 September 03, 1998 BASES APPLICABLE Turbine Control Valve Fast Closure, Trip Oil Pressure - Low SAFETY ANALYSES, (PS-47-142, PS-47-144, PS-47-146, and PS-47-148)

LCO, and (continued)

APPLICABILITY

This protection is required c onsistent with the safety analysis whenever THERMAL POWER is 30% RTP. Below 30% RTP, the Reactor Vessel Steam Dome Pressure - High and the APRM Fixed Neutron Flux - Hi gh Functions of the RPS are adequate to maintain the necessary safety margins.

ACTIONS A Note has been provided to modify the ACTIONS related to EOC-RPT instrumentation channel

s. 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 sepa rate 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 inst rumentation channel.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 3 B 3.3-116 Revision 25 , 61 Amendment No. 213 December 7, 2010 BASES ACTIONS B.1 and B.2 (continued)

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 capabilit

y. 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.

Alternately, Required Action B.2 requires the MCPR and LHGR limits for inoperable EOC-RPT, as specified in the COLR, to be

applied. This also restores the margin to MCPR and LHGR limits assumed in the safety analysis.

The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is suff icient time 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 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time provided in LCO 3.2.2 for Required Action A.1, since this instrumentation's purpose is to preclude a MCPR or LHGR violation.

C.1 With any Required Action and associated Completion Time not met, THERMAL POWER must be reduced to < 30% RTP within

4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The allowed Comp letion Time of 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> is reasonable, based on operating experience, to reduce THERMAL POWER to < 30% RTP fr om full power conditions in an orderly manner and without challenging plant systems.

EOC-RPT Instrumentation B 3.3.4.1 (continued)

BFN-UNIT 3 B 3.3-118 Amendment No. 215 November 30, 1998 BASES SURVEILLANCE SR 3.3.4.1.2 REQUIREMENTS (continued) This SR ensures that an EOC-RPT initiated from the TSV - Closure and TCV Fast Closure, Trip Oil Pressure - Low

Functions will not be inadvertently bypassed when THERMAL POWER is 30% RTP. This involves calibration of the bypass channels. Adequate margins fo r the instrument setpoint methodologies are incorporated into the actual setpoint. If any bypass channel's setpoint is noncons ervative (i.e., the Functions are bypassed at 30% RTP, either due to open main turbine bypass valves or other reasons), the affected TSV - Closure and TCV Fast Closure, Trip Oil Pressure - Low Functions are considered inoperable. Alter natively, the bypass channel can be placed in the conservative condition (nonbypass). If placed

in the nonbypass condition, th is SR is met with the channel considered OPERABLE.

The Frequency of 24 months is based upon the assumption of a 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

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 param eter within the necessary range and accuracy. CHANNEL CALIBRATION leaves the channel adjusted to account fo r instrument drifts between successive calibrations consist ent with the plant specific setpoint methodology. The Frequency is based upon the assumption of an 24 month calibration interval in the determination of the magnitude of equipment drift in the setpoint analysis.

Jet Pumps B 3.4.2 BFN-UNIT 3 B 3.4-16 Revision 0 BASES SURVEILLANCE SR 3.4.2.1 (continued)

REQUIREMENTS

Note 2 allows this SR not to be performed until 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after THERMAL POWER exceeds 25% of 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. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is an acceptable time to establish conditions appropriate to perform this SR.

REFERENCES 1. FSAR, Section 14.6.3.

2. GE Service Information Letter No. 330, "Jet Pump Beam Cracks," June 9, 1980.

3. NUREG/CR-3052, "Closeout of IE Bulletin 80-07: BWR Jet Pump Assembly Failure," November 1984.

4. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

Primary Containment B 3.6.1.1

(continued)

BFN-UNIT 3 B 3.6-3 Amendment No. 214 September 08, 1998 BASES APPLICABLE The maximum allowable leakage rate for the primary SAFETY ANALYSES containment (L a) is 2.0% by weight of the containment air per (continued) 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the design bas is LOCA maximum peak containment pressure (P a) of 50.6 psig (Ref. 1).

Primary containment satisfies Criterion 3 of the NRC Policy Statement (Ref. 6).

LCO Primary containment OPERABILITY is maintained by limiting leakage to 1.0 L a , except prior to the first startup after performing a required Primary Containment Leakage Rate Testing Program leakage test. At this time, applicable leakage limits must be met. Compliance with this LCO will ensure a

primary containment configur ation, including equipment hatches, that is structurally s ound and that will lim it leakage to those leakage rates assumed in the safety analyses.

Individual leakage rates specif ied for the prim ary containment air lock 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 primar y 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, prim ary containment is not required to be OPERABLE in MODES 4 and 5 to prevent leakage of

radioactive material from primary containment.

Primary Containment B 3.6.1.1 BFN-UNIT 3 B 3.6-6 Amendment No. 215 November 30, 1998 BASES SURVEILLANCE SR 3.6.1.1.2 (continued)

REQUIREMENTS

Satisfactory performance of this SR can be achieved by establishing a known differential pressure between the drywell and the suppression chamber and veri fying that the pressure in either the suppression chamber or the drywell does not change by more than 0.25 inch of wate r per minute over a 10 minute period. The leakage test is per formed every 24 months. The 24 month Frequency was developed considering it is prudent that this Surveillance be performed during a unit outage and

also in view of the fact that component failures that might have affected this test are identified by other primary containment SRs.

REFERENCES 1. FSAR, Section 5.2.

2. FSAR, Section 14.6.

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

4. NEI 94-01, Revision O, "Industr y Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J." 5. ANSI/ANS-56.8-1994, "Ame rican National Standard for Containment System Leakage Testing Requirement."

6. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

Primary Containment Air Lock B 3.6.1.2

(continued)

BFN-UNIT 3 B 3.6-8 Amendment No. 214 September 08, 1998 BASES BACKGROUND the air lock to remain open for extended periods when frequent (continued) primary containment entry is necessary. Unde r some conditions allowed by this LCO, the prim ary containment may be accessed through the air lock, when the interlock mechanism has failed, by manually performing the interlock function.

The primary containment air lock forms 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 t hat assumed in the unit safety analysis.

APPLICABLE The DBA that postulates the maximum release of radioactive SAFETY ANALYSES material within primary containment is a LOCA. In the analysis of this accident, it is assum ed that primary containment is OPERABLE, such that releas e of fission products to the environment is controlled by the rate of primary containment leakage. The primar y containment is designed with a maximum allowable leakage rate (L a) of 2.0% by weight of the containment air per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> at the calculat ed maximum peak containment pressure (P a) of 50.6 psig (Ref. 3). This allowable leakage rate forms the basis for the acceptance criteria imposed on the SRs associated with the air lock.

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.

The primary containment air lo ck satisfies Criterion 3 of the NRC Policy Statement (Ref. 4).

CAD System B 3.6.3.1

(continued)

BFN-UNIT 3 B 3.6-90 Revision 0 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.1 Containment Atmosphere Dilution (CAD) System BASES BACKGROUND The CAD Syst em functions to maintain combustible gas concentrations within the primary containment at or below the flammability limits following a postulated loss of coolant accident (LOCA) by diluting hydrogen and oxygen with nitrogen. To ensure that a combustible gas mixture does not occur, oxygen

concentration is kept < 5.0 volume percent (v/o), or hydrogen

concentration is kept < 4.0 v/o.

The CAD System is manually in itiated and consists of two independent, 100% capacity sub systems, each of which is capable of supplying nitrogen through separate piping systems to the drywell and suppression chamber of each unit. Each

subsystem includes a liquid nitrogen supply tank, ambient vaporizer, electric heater, and a m anifold with branches to each primary containment (for Unit s 1, 2, and 3).

The nitrogen storage tanks each contain 2500 gal, which is adequate for 7 days of CAD subsystem operation.

The CAD System operates in conjunction with emergency

operating procedures that ar e used to reduce primary containment pressure peri odically during CAD System operation. This combination results in a feed and bleed approach to maintaining hydrogen and oxygen concentrations below combustible levels.

CAD System B 3.6.3.1 (continued)

BFN-UNIT 3 B 3.6-95 Amendment No. 225 Revision 0 May 24, 2000 BASES (continued)

SURVEILLANCE SR 3.6.3.1.1 REQUIREMENTS Verifying that there is 2500 gal of liquid nitrogen supply in each nitrogen storage tank will ensure at least 7 days of post-LOCA CAD operation. This minimum volume of liquid

nitrogen allows sufficient time a fter an accident to replenish the nitrogen supply for long term inerti ng. This is verified every 31 days to ensure that the system is capable of performing its intended function when required. The 31 day Frequency is based on operating experience, which has shown 31 days to be an acceptable period to verify the liquid nitrogen supply and on

the availability of other hydrogen mitigating systems.

SR 3.6.3.1.2

Verifying the correct alignment for manual, power operated, and

automatic valves in each of the CAD subsystem flow paths provides assurance that the prop er flow paths exist for system operation. This SR does not appl y to valves that are locked, sealed, or otherwise secured in position, since these valves

were verified to be in the co rrect position prior to locking, sealing, or securing.

A valve is also allowed to be in the nonaccident position

provided it can be aligned to t he accident position within the time assumed in the accident analysis. This is acceptable because the CAD System is manually initiated. This SR 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 mis positioned are in the correct position.

CAD System B 3.6.3.1 BFN-UNIT 3 B 3.6-96 Amendment No. 225 Revision 0 May 24, 2000 BASES SURVEILLANCE SR 3.6.3.1.2 (continued)

REQUIREMENTS

The 31 day Frequency is appropriate because the valves are

operated under procedural control, improper valve position would only affect a single subsystem, the probability of an event requiring initiation of the system is low, and the system is a manually initiated system.

REFERENCES 1. AEC Safety Guide 7, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident, March 10, 1971.

2. FSAR, Section 5.2.6.

3. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-1 Revision 73 Amendment No. 214 January 3, 2013 B 3.7 PLANT SYSTEMS B 3.7.1 Residual Heat Removal Service Water (RHRSW) System and Ultimate Heat Sink (UHS)

BASES BACKGROUND The RHRSW System is designed to provide cooling water for the Residual Heat Removal (RHR) System heat exchangers, required for a safe reactor shut down following a Design Basis Accident (DBA) or transient.

The RHRSW System is operated whenever the RHR heat exchanger s are required to operate in the shutdown cooling mode or in the suppression pool cooling or spray mode of the RHR System.

The RHRSW System is common to the three BFN units and consists of the UHS and four independent and redundant subsystems, each of which f eeds one RHR heat exchanger in each unit. Each subsystem is made up of a header, two 4500 gpm pumps, a suction source, valves, piping, and associated

instrumentation. Two subsyst ems, with one pump operating in each subsystem, are capable of pr oviding 100% of the required cooling capacity to maintain safe shutdown conditions for one unit. The RHRSW System is designed with sufficient redundancy so that no single active component failure can prevent it from achieving its design function. The RHRSW System is described in the FSAR, Section 10.9 (Ref. 1).

Cooling water is pumped by the RHRSW pumps from the Wheeler Reservoir through the tube side of the RHR heat exchangers, and discharged back to the Wheeler Reservoir.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-2 Revision 73 Amendment No. 214 January 3, 2013 BASES BACKGROUND The system is initiated manually from each of the three units (continued) control r ooms. If operating during a loss of coolant accident (LOCA), the system is automatic ally tripped on degraded bus voltage to allow the diesel gener ators to automatically power only that equipment necessary to reflood the core. The system can be manually started any time the degraded bus voltage signal clears, and is assumed to be manually started within 10 minutes after the LOCA.

APPLICABLE The RHRSW Syst em removes heat from the suppression pool SAFETY ANALYSES to limit the suppre ssion pool temperature and primary containment pressure following a LOCA. This ensures that the primary containment can perform its function of limiting the release of radioactive materials to the environment following a

LOCA. The ability of the RHR SW System to support long term cooling of the reactor or primar y containment is discussed in the FSAR, Chapters 5 and 14 (Refs. 2 and 3, respectively). These analyses explicitly assume that the RHRSW System will provide adequate cooling support to the equipment required for safe

shutdown. These analyses includ e the evaluation of the long term primary containment response after a design basis LOCA.

The safety analyses for long term cooling were performed for various combinations of RHR System failures and considers the

number of units fueled. With one unit fueled, the worst case single failure that would affect the performance of the RHRSW System is any failure that would disable two subsystems of the RHRSW System.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-3 Revision 73 Amendment No. 214 January 3, 2013 BASES APPLICABLE With two and three units fueled, a worst case single failure SAFETY ANALYSES could also include the loss of two RHRSW pumps caused by (continued) losing a 4 kV shutdown board since there are certain alignment configurations that allow two RHRSW pumps to be powered from the same 4 kV shutdown bo ard. As discussed in the FSAR, Section 14.6.3.3.2 (Ref.

4) for these analyses, manual initiation of the OPERABLE RHRSW subsystems and the associated RHR System is assumed to occur 10 minutes after a

DBA. The analyses assume that there are two RHRSW subsystems operating in each unit, with one RHRSW pump in each subsystem capable of producing 4000 gpm of flow. In this case, the maximum suppression chamber water temperature and pressure are 177°F (as reported in Reference 3) and 50.6 psig, respectively, well below the design temperature of

281°F and maximum allowable pressure of 62 psig.

The RHRSW System together with the UHS satisfies Criterion 3

of the NRC Policy Statement (Ref 5).

LCO Four RHRSW subsystems are required to be OPERABLE to provide the required redundancy to ensure that the system

functions to remove post a ccident heat loads, assuming the worst case single active failure o ccurs coincident with the loss of offsite power. Additionally, since the RHRSW pumps are

shared between the three BFN unit s, the number of OPERABLE pumps required is also dependent on the number of units

fueled.

An RHRSW subsystem is considered OPERABLE when:

a. At least one RHRSW pump (i.e., one required RHRSW pump) is OPERABLE, and

b. An OPERABLE flow path is capable of taking suction from the intake structure and tr ansferring the water to the associated RHR heat exchanger at the assumed flow rate.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-4 Revision 44 , 73 Amendment No. 214 January 3, 2013 BASES LCO In addition to the required number of OPERABLE subsystems, (continued) there must be an adeq uate number of pumps OPERABLE to provide cooling for the fueled non-accident units.

The total number of required RHRSW pumps must take into consideration the required numbe r of pumps required for the specific unit along with the number of pumps required for other units that are fueled. Hence, when one unit contains fuel, four RHRSW pumps are required to be OPERABLE. When two units contain fuel, six RHRSW pumps are required to be OPERABLE. When three units contain fuel, eight RHRSW pumps are required to be OPERABLE. The minimum specified number of pumps gives consider ation to all units capable of producing heat in aggregate and a ccounts for a single active failure. The above pre-accident configuration ensures that during a design bases accident with a postulated single active failure, the resulting configuration for the accident unit has at least two RHRSW subsystems OPERABLE to supply 100 percent of the long term RHR cooling water. The resulting configuration for the non-accident units has at least two RHRSW subsystems per unit OPERABLE to supply 100 perc ent of the required cooling capacity to maintain safe shutdown conditions.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-4a Revision 44 , 73 January 3, 2013 BASES LCO The number of required OPERABLE RHRSW pumps (continued) is modified by a Note which specifies that the number of required RHRSW pumps may be reduced by one for each

fueled unit that has been in MODE 4 or 5 for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

This Note acknowledges the fa ct that decay heat removal requirements are substantially reduced for fueled units in

MODE 4 or 5 for over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

The OPERABILITY of the UHS for RHRSW is based on having

a maximum water temperature wit hin the limits specified in Figure 3.7.1-1.

APPLICABILITY In MODES 1, 2, and 3, the RHRSW System and UHS are required to be OPERABLE to s upport the OPERABILITY of the RHR System for primary containment cooling (LCO 3.6.2.3, "Residual Heat Removal (RHR) Suppression Pool Cooling," and LCO 3.6.2.4, "Residual Heat Removal (RHR) Suppression Pool

Spray") and decay heat removal (L CO 3.4.7, "Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown"). The Applicability is therefore c onsistent with the requirements of these systems.

In MODES 4 and 5, the OPER ABILITY requirements of the RHRSW System and UHS are dete rmined by the systems they support.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-5 Revision 73 Amendment No. 214 January 3, 2013 BASES (continued)

ACTIONS Since the RHRSW System is common to all three units, the following requirements must be followed when multiple units contain fuel:

a. With one or more requir ed RHRSW pumps inoperable, all applicable ACTIONS must be entered for each unit.

b. With one or more RHRSW subsystem inoperable, all applicable ACTIONS for inoperable subsystems must be entered on the unit(s) that hav e the inoperable subsystem.

The Required Actions and associated Completion Times of Conditions A, B, C, and D are based on a reduction in redundancy of the RHRSW Syst em, not a loss of RHRSW safety function. The Required Actions and associated Completion Times of Conditions E, F, and G consider that the RHRSW safety function is lost.

RHRSW safety function is maintained when at least two RHRSW subsystems, with two separate RHRSW pumps (i.e., one per subsystem), on a per fuel ed unit basis, are OPERABLE. Additionally, the total number of RHRSW pumps must be such that the RHRSW pumps credited for maintaining the RHRSW safety function for a specific unit are not credited for maintaining the RHRSW safety function for a different fueled unit.

When there are three fueled units, the RHRSW safety function is maintained when:

• Two RHRSW subsystems per fueled unit are OPERABLE;

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-5a Revision 73 Amendment No. 214 January 3, 2013 BASES (continued)

ACTIONS

• Six RHRSW pumps are OPERABLE (two RHRSW pumps (continued) per fueled unit);

• Each OPERABLE RHRSW subsystem has one required RHRSW pump OPERABLE; and

• The required RHRSW pump that is OPERABLE in an RHRSW subsystem is not cr edited for maintaining the RHRSW safety function for another fueled unit (i.e., it is not one of the two RHRSW pumps that is required to be OPERABLE for another fueled unit).

When there are two fueled units, the RHRSW safety function is maintained when:

• Two RHRSW subsystems per fueled unit are OPERABLE;

• Four RHRSW pumps are O PERABLE (two RHRSW pumps per fueled unit);

• Each OPERABLE RHRSW subsystem has one required RHRSW pump OPERABLE; and

• The required RHRSW pump that is OPERABLE in an RHRSW subsystem is not cr edited for maintaining the RHRSW safety function for another fueled unit (i.e., it is not one of the two RHRSW pumps that is required to be OPERABLE for another fueled unit).

When there is one fueled unit, the RHRSW safety function is maintained when:

• Two RHRSW subsystems are OPERABLE and

• Two RHRSW pumps are OPERABLE (i.e., one per OPERABLE RHRSW subsystem).

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-5b Revision 73 Amendment No. 214 January 3, 2013 BASES (continued)

ACTIONS When any combination of pump(s) and other subsystem (continued) components, e.g., heat exc hanger(s), are inoper able such that three or more components of t he RHRSW System (on any or all fueled units) are inoperable, the capability to meet the safety function must be evaluated by all fueled units. When an RHRSW pump is credited by one f ueled unit for maintaining the RHRSW safety function, then the other two fueled units cannot also credit this same RHRSW pump with maintaining their RHRSW safety function since t he capacity of a single RHRSW pump is not sufficient to support the required heat removal function of more than one RHR heat exchanger. Therefore, in this condition, the RHRSW pum p credited with maintaining RHRSW safety function on a f ueled unit must be considered inoperable for the other fueled units for purpose of determining if RHRSW safety function is mainta ined. The other fueled units must then include the additio nal inoperable RHRSW pump(s) with the total number of inoperable components when determining if RHRSW safety function is maintained. If RHRSW safety function is deter mined to be lost, then Condition E or F is required to be entered.

The examples, with respect to RHRSW pumps, used in the following descriptions of the AC TIONS assume that all three units are fueled.

A.1 and A.2 With one required RHRSW pum p inoperable, the inoperable RHRSW pump must be restored to OPERABLE status within 30 days. With the unit in th is condition, the remaining OPERABLE RHRSW pumps are adequate to perform.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-6 Revision 73 Amendment No. 214 January 3, 2013 BASES ACTIONS A.1 and A.2 (continued)

the RHRSW heat removal function. However, the overall reliability is reduced because a single failure could result in

reduced primary containment cool ing capability. The 30 day Completion Time is based on the availability of equipment in

excess of normal redundancy requirements and the low

probability of an event occurring requiring RHRSW during this period. Alternatively, five RHRSW pum ps may be verified to be OPERABLE with power being su pplied from separate 4 kV shutdown boards.

Required Action A1 is modified by two Notes. Note 1 indicates that the Required Action is applicable only when two units are fueled. In the two unit fueled condit ion, a single failure (loss of a 4 kV shutdown board) could result in inadequate RHRSW pumps if two pumps are powered from the same power supply.

If five RHRSW pumps are pow ered from separate 4 kV shutdown boards, then no postulated single active failure could occur to prevent the RHRSW system from performing its design function. Operation can continue indefinitely if Required Action A.1 is met.

Note 2 requires only four RHRSW pumps powered from separate 4 kV shutdown boards to be OPERABLE if the other fueled unit has been in MODE 4 or 5 greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This acknowledges the fact that decay heat removal requirements are substantially reduced for fueled units in MODE 4 or 5 for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

These two Notes clarify the situations under which Required Action A.1 would be the appr opriate Required Action.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-6a Revision 73 Amendment No. 214 January 3, 2013 BASES ACTIONS B.1 (continued)

With one RHRSW subsystem inoperable (e.g., one RHR heat exchanger inoperable or an RHRSW header isolated) for reasons other than inoperable RHRSW pumps, which are covered by separate Conditions, the inoperable RHRSW subsystem must be restored to OPERABLE status within 30 days. With the unit in th is condition, the remaining OPERABLE RHRSW subsystems are adequate to perform the

RHRSW heat removal function. However, the overall reliability is reduced because a single failure could result in reduced

primary containment cooling cap ability. The 30 day Completion

Time is based on the availability of equipment in excess of

normal redundancy requirements and the low probability of an event occurring requiring RHRSW during this period.

The Required Action is modified by a Note indicating that the

applicable Conditions of LCO 3.4.7 be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-7 Revision 73 Amendment No. 214 January 3, 2013 BASES ACTIONS C.1 (continued)

With two required RHRSW pumps inoperable (i.e., one required RHRSW pump inoperable in each of the two separate RHRSW subsystems or two RHRSW pumps inoperable in the same RHRSW subsystem), the remaining RHRSW pumps are adequate to perform the RHRSW heat removal function.

However, the overall reliability is reduced because a single failure of the OPERABLE RHRSW pumps could result in a loss of RHRSW function. The seven day Completion Time is based

on the redundant RHRSW capabilities afforded by the

OPERABLE RHRSW pumps and t he low probability of an event occurring during this period.

D.1 With two RHRSW subsystems inoperable (e.g., two RHR heat exchangers inoperable) for reas ons other than inoperable RHRSW pumps, which are covered by separate Conditions, the remaining OPERABLE RHRSW subsystems are adequate to perform the RHRSW heat removal function. However, the

overall reliability is reduced becau se a single failure could result

in reduced primary containment cooling capability. The seven day Completion Time is based on the availability of equipment in excess of normal redundancy requirements and

the low probability of an event occurring requiring RHRSW during this period.

The Required Action is modified by a Note indicating that the

applicable Conditions of LCO 3.4.7 be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-8 Revision 73 Amendment No. 214 January 3, 2013 BASES ACTIONS E.1 (continued)

With three or more requir ed RHRSW pumps inoperable, the RHRSW System is not capabl e of performing its intended function. The requisite number of pumps must be restored to

OPERABLE status within ei ght hours. The eight hour Completion Time is based on the Completion Times provided for the RHR suppression pool cooling and spray functions.

F.1 With three or more required RHRSW subsystems inoperable (e.g., one RHR heat exchanger inoperable in each of three of four separate RHRSW subsystems) for reasons other than inoperable RHRSW pumps, which are covered by separate Conditions, the RHRSW System is not capable of performing its intended function. The requisite number of subsystems must be restored to OPERABLE status within eight hours. The eight hour Completion Time is based on the Completion Times provided for the RHR suppression pool cooling and spray functions.

The Required Action is modified by a Note indicating that the

applicable Conditions of LCO 3.4.7 be entered and Required Actions taken if the inoperable RHRSW subsystem results in inoperable RHR shutdown cooling. This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.

RHRSW System and UHS B 3.7.1 (continued)

BFN-UNIT 3 B 3.7-9 Revision 73 Amendment No. 214 January 3, 2013 BASES ACTIONS G.1 and G.2 (continued)

If the RHRSW subsystem(s) or the RHRSW pump(s) cannot be restored to OPERABLE status within the associated Completion Times or the UHS is determi ned inoperable, 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating

experience, to reach the require d unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.1.1 REQUIREMENTS

Verifying the correct alignment for each manual and power operated valve in each RHRSW sub system flow path provides assurance that the proper flow paths will exist for RHRSW

operation. This SR does not appl y to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct positi on prior to locking, sealing, or securing. A valve is also al lowed to be in the nonaccident position, and yet considered in t he correct position, provided it can be realigned to its accident po sition. This is acceptable because the RHRSW System is a manually initiated system.

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 is based on engineering judgment, is

consistent with the procedural controls governing valve operation, and ensures correct valve positions.

RHRSW System and UHS B 3.7.1 BFN-UNIT 3 B 3.7-10 Revision 69 Amendment No. 214 October 5, 2012 BASES SURVEILLANCE SR 3.7.1.2 REQUIREMENTS (continued) Verification of the UHS te mperature is within t he limits of Figure 3.7.1-1 ensures that the heat removal capability of the RHRSW System is within the assumptions of the DBA analysis (Ref. 6).

The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> and 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Frequencies are based on operating

experience relating to trending of the parameter variations during the applicable MODES.

REFERENCES 1. FSAR, Section 10.9.

2. FSAR, Chapter 5.

3. FSAR, Chapter 14.

4. FSAR, Section 14.6.3.3.2.

5. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

6. FSAR, Section 14.6.3.3.2.3..

EECW System and UHS B 3.7.2 (continued)

BFN-UNIT 3 B 3.7-13 Amendment No. 214 September 08, 1998 BASES LCO The EECW System is consi dered OPERABLE when it has an (continued) OPERABLE UHS, three OPERABLE pumps, and two OPERABLE flow paths capable of taking suction from the intake structure and transferring t he water to the appropriate equipment.

The OPERABILITY of the UHS for EECW is based on having a maximum water temperature of 95°F. Additional requirements for UHS temperature are pr ovided in SR 3.7.1.2.

The isolation of the EECW S ystem to components or systems may render those components or systems inoperable, but does

not affect the OPERABIL ITY of the EECW System.

APPLICABILITY In MODES 1, 2, and 3, the EECW System and UHS are required to be OPERABLE to support OPERABILITY of the

equipment serviced by the EECW System. Therefore, the EECW System and UHS are required to be OPERABLE in these MODES.

In MODES 4 and 5, the OPER ABILITY requirements of the EECW System and UHS are determined by the systems they support.

ACTIONS A.1

With one required EECW pump inoperable, the required EECW pump must be restored to OPERABLE status within 7 days.

With the system in this condition, the remaining OPERABLE

EECW pumps are adequate to perform the heat removal function. However, the overall reliability is reduced because a single failure in the EECW System could result in loss of EECW

function.

EECW System and UHS B 3.7.2 (continued)

BFN-UNIT 3 B 3.7-14 Revision 0 , 69 October 5, 2012 BASES ACTIONS A.1 (continued)

The 7 day Completion Time is based on the redundant EECW System capabilities afforded by the remaining OPERABLE

pumps, the low probability of an accident occurring during this time period and is consistent wit h the allowed Completion Time for restoring an inoperable DG.

B.1 and B.2

If the required EECW pump cannot be restored to OPERABLE status within the associated Comp letion Time, or two or more EECW pumps are inoperable or the UHS is determined inoperable, 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 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in MODE 4

within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allo wed Completion Times are reasonable, based on operating experience, to reach the

required unit conditions from full power conditions in an orderly manner and without chall enging unit systems.

SURVEILLANCE SR 3.7.2.1 REQUIREMENTS

Verification of the UHS tem perature ensures that the heat removal capability of the EEC W System is within the

assumptions of the DBA analysis.

Additional requirements for UHS temperature to ensure RHRSW System heat removal capability is maintained within the assumptions of the DBA analysis are provided in SR 3.

7.1.2. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Frequency is based on operating experience related to trending of the

parameter variations during the applicable MODES.

Main Turbine Bypass System B 3.7.5 (continued)

BFN-UNIT 3 B 3.7-32 Revision 0 B 3.7 PLANT SYSTEMS B 3.7.5 Main Turbine Bypass System BASES BACKGROUND The Main Turbine Bypass S ystem is designed to control steam pressure when reactor steam generation exceeds turbine requirements during unit start up, sudden load reduction, and cooldown. It allows excess steam flow from the reactor to the

condenser without going through t he turbine. The bypass capacity of the system is 25%

of the Nuclear Steam Supply System rated steam flow. Sudd en load reductions within the capacity of the steam bypa ss can be accommodated without reactor scram. The Main Turbi ne Bypass System consists of nine valves connected to the ma in steam lines between the main steam isolation valves and the turbine stop valve bypass valve chest. Each of these nine valves is operated by hydraulic cylinders. The bypass valves are controlled by the pressure regulation function of the Pressure Regulator and Turbine Generator Control System, as discussed in the FSAR, Section 7.11.3.3 (Ref. 1).

The bypass valves are normally

closed, and the pressure regulator controls the turbine control valves that direct all steam flow to the turbine. If the speed governor or the load limiter restricts steam flow to the turbine, the pressure regulator controls the system pressure by opening the bypass valves. When the bypass valves open, the steam

flows from the bypass chest, th rough connecting piping, to the pressure breakdown assemblies, w here a series of orifices are used to further reduce the steam pressure before the steam enters the condenser.

Main Turbine Bypass System B 3.7.5 (continued)

BFN-UNIT 3 B 3.7-34 Revision 0, 25 March 12, 2004 BASES (continued)

APPLICABILITY The Main Turbine Bypass System is required to be OPERABLE at 25% RTP to ensure that the f uel cladding integrity Safety Limit is not violated during abnorma l operational transients. As

discussed in the Bases for LCO 3.2.1 and LCO 3.2.2, sufficient

margin to these limits exists at < 25% RTP. T herefore, these requirements are only necessary when operating at or above this power level.

ACTIONS A.1

If the Main Turbine Bypass Syst em is inoperable (one or more bypass valves inoperable), or the APLHGR, MCPR, and LHGR limits for an inoperable Main Turbine Bypass System, as specified in the COLR, are not ap plied, the assumptions of the design basis transient analysis may not be met. Under such circumstances, prompt action should be taken to restore the

Main Turbine Bypass System to OPERABLE status or adjust the APLHGR, MCPR, and LHGR limits accordingly. The 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> Completion Time is reasonable, based on the time to complete the Required Action and the low probability of an event occurring during this period requiring the Main Turbine Bypass

System.

B.1 If the Main Turbine Bypass S ystem cannot be restored to OPERABLE status or the APLHG R, MCPR, and LHGR limits for an inoperable Main Turbine Bypass System are not applied, THERMAL POWER must be reduced to < 25% RTP. As

discussed in the Applicability section, operation at < 25% RTP

results in sufficient margin to the required limits, and the Main