ML063380325

Summary Report for July 1, 2005 Through June 30, 2006

ML063380325
Person / Time
Site:	Browns Ferry
Issue date:	11/30/2006
From:	Crouch W Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML063380325 (79)

Text

Tennessee Valley.Authority, Post Office Box 2000; Decatur, AJabama 35609-2000 November 30, 2006 10 CFR 50.4 10 CFR 50.59 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop: OWFN P1-35 Washington, D.C. 20555-0001 Gentlemen:

In the Matter of )) Docket Nos. 50-259 Tennessee Valley Authority 50-260 50-296 BROWNS FERRY NUCLEAR PLANT (BFN) - UNITS 1, 2, AND 3 -

SUMMARY

REPORT FOR JULY 1, 2005 THROUGH JUNE 30, 2006 The enclosures to this letter provide the BFN Summary Report (SR) for July 1, 2005 through June 30, 2006. contains 10 CFR 50.59(d)(2)summaries which include brief descriptions of changes, tests, and experiments with safety evaluations prepared for design changes, revisions to plant procedures (new and revised), temporary alterations, and other activities that were completed during this reporting period.

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U.S. Nuclear Regulatory Commission Page 2 November 30, 2006 Since the last SR, there have been five revisions to the Fire Protection Report (FPR). Enclosure 2 contains BFN FPR, Revision 36, which includes all five revisions. includes copies of changes to the BFN Technical Specifications (TS) Bases in accordance with BFN TS Section 5.5.10, TS Bases Control Program, for Units 1, 2, and 3. contains copies of changes to the BFN Technical Requirements Manual (TRM) in accordance with TRM Section 5.1.4, Technical Requirements Control Program, for Units 1, 2, and 3.

During this reporting period, there were no previous NRC commitments that TVA evaluated and revised using administrative controls that incorporate the Nuclear Energy Institute's 99-04 "Guideline For Managing NRC Commitments" in accordance with 10 CFR 50.109(a) (7).

There are no commitments contained in this letter. If you have any questions regarding this report, please contact me at (256) 729-2636.

Sincerely, William D. Crouch Manager of Licensing and Industry Affairs

Enclosures:

1. 10 CFR 50.59(d) (2) Summaries

2. Fire Protection Report, Revision 36

3. Technical Specifications Bases Changes and Additions

4. Technical Requirements Manual Changes and Additions cc: See Page 3

U.S. Nuclear Regulatory Commission Page 3 November 30, 2006 cc: w/o Enclosures Regional Administrator (w/Enclosures)

U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-3415 Mr. Malcolm T. Widmann, Branch Chief U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-8931 NRC Senior Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, Alabama 35611-6970 Margaret Chernoff, Senior Project Manager U.S. Nuclear Regulatory Commission (MS 08G9)

One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739 Eva A. Brown, Project Manager U.S. Nuclear Regulatory Commission (MS 08G9)

One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739

ENCLOSURE 1 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)

UNITS 1, 2, AND 3 10 CFR 50.59(d) (2) SUMMARIES Safety Evaluation Summaries July 1, 2005 - June 30, 2006

DESIGN CHANGE NOTICES DCN W12437B The original scope of this Design Change Notice (DCN) was to provide mechanical, civil, and electrical designs to support the construction of the TVA-BFN Fuel Facility. This facility is intended to provide fuel (gasoline and diesel) for TVA vehicles assigned to the BFN site. This facility is designed to meet all federal and state regulations and requirements regarding the storage and dispensing of gasoline. The subject facility satisfies these requirements as well as the applicable National Fire Protection Association and building code standards.

Revision 0 change addressed the removal of the service island from the Service Air and Potable Water system drawings.

Revision 1 change addressed field work implemented to remove the gasoline storage tank within the protected area along with the Service Air and Potable Water service connections at the service island. Some valves in these systems were relabeled to reflect their current usage. The plant is not affected by this change and, therefore, this DCN does not affect nuclear safety.

DCN 50189A This DCN changed the description of the Permanent Record Storage Room to a generic term "Mezzanine Area" so that future changes will not require revision of drawings. The C02 System, including the fire detection and alarm components for this station and associated electrical systems, can be removed from the room or abandoned in place since records are no longer stored there, and the area will have regular personnel occupancy. The alarm station only alarms after C02 initiation and does not provide early detection of a fire.

The air conditioning system including its associated electrical system and the raw cooling water supply to the air conditioning (A/C) system will be affected by the room name change. The air ducts may be redirected without changing the system capacity or affecting operation of the A/C unit. This DCN does not affect nuclear safety.

DCN 51323 This change revised Unit 3 condenser instrumentation to provide for improved condenser performance monitoring for Extended Power Uprate. In conjunction with the changes to improve condenser instrumentation, the following changes to other condenser pressure instrumentation were made:

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1. Reactor Feed Pump Turbine (RFPT) control circuit (loops 3-PS-003-200, 3-PS-003-201 and 3-PS-003-202) were revised to replace the existing one out of one logic with a two out of three logic for the RFPT trip signal per recommendations in TVA Standard Design Standard (DS)-22.02,

2. The controls for Steam Jet Air Ejector (SJAE) were modified to remove input from pressure switch 3-PS-002-008B and eliminate the SJAE Auto-Start function. Since the SJAEs are not operated in the Auto mode, it was elected to eliminate this feature rather than move and re-wire the existing pressure switch.

Modifying the SJAE automatic start logic removes the capability to automatically perform this function and ensures that operator actions will be required to start the standby SJAE. The evaluation concluded that this was an adverse effect on a FSAR described design function. All other changes made in DCN 51323 were determined to have no adverse impact. The SJAE automatic start logic uses a low condenser vacuum signal as the controlling parameter to initiate the start of the standby SJAE. Due to problems with the ability to automatically start and maintain an SJAE inservice, the automatic start logic is administratively prohibited by the Off-Gas System Operating Procedure 3-01-66. The pressure switch that provides the input to the SJAE automatic start logic is located on one of the panels that is being modified to upgrade the condenser performance monitoring instrumentation. Rather than move and rewire these pressure switches, it was elected to eliminate the automatic start feature. As a part of the SJAE automatic start change, relays in the SJAE control panel are abandoned, and the associated three position hand switches on the main control panel are replaced with two position control switches.

The loss of both SJAEs could cause an eventual loss of condenser vacuum, resulting in a main turbine trip and subsequent reactor scram. Thus, the loss of the SJAEs is postulated as being a transient initiator. No credit is taken in Final Safety Analysis Report (FSAR) Section 14.5.2.3 for the automatic start of the standby SJAE in assessing the frequency of occurrence of the loss of condenser vacuum transient.

Eliminating the capability for the standby SJAE to start automatically does not reduce the capability of the operating SJAE to perform its design function. The SJAEs are not relied upon to mitigate accidents or transients and the El-3

failure of the SJAEs do not prevent safety related structures, systems, or components (SSCs) from fulfilling their design function. As such, the SJAEs are not classified as SSCs important to safety.

DCN 50927A This change tied a nitrogen gas supply from the Containment Inerting (CI) System 2" Makeup supply line located in the Reactor Building on Elevation 565 feet to the Unit 3 Drywell Control Air (DCA) system in order to replace the existing DCA compressor, surge tank, and dryer system. The DCA system which serves pneumatic equipment inside the drywell will be supplied dry, oil free, regulated nitrogen from the CI System through a 1" supply line which will bypass the existing two DCA trains of compressors and refrigerant dryers and tie directly into the two existing DCA receiver tanks. The compressors, refrigerant dryers, surge tanks and supporting instruments and piping will be removed. The common, 3" compressor suction line at drywell penetration X-48, will be isolated by closing containment isolation valves, 3-FCV-32-62 and 3-FCV-32-63. These isolation valves will be maintained closed and will remain in the Appendix J Local Leak Rate Testing (LLRT) program until a future DCN removes the valves and installs a blind flange arrangement on drywell penetration X-48. This change is being made to eliminate frequent and costly maintenance efforts presently required to keep the compressor and refrigerant dryer equipment operational.

Evaluation of the proposed DCA system modification shows that the change does not involve any SSCs with the potential to adversely affect fission product barriers, and the system interaction analysis did not identify any new failure modes, adverse impacts, or new challenges to other systems.

The evaluation also concluded that providing the DCA system with dry, oil free nitrogen from the CI system will improve the DCA system reliability by reducing maintenance efforts on the system and that the change will not reduce nuclear safety.

DCN 60718A This change removed primary containment isolation valves 3-FCV-32-62 and -63 and installed a 3", blind, double O-ring flange on the outside of drywell penetration X-48. A 6" bolted flange with cover plate and threaded test connection was installed inside the drywell on the 6" sleeve of penetration X-48 to facilitate Appendix J leak testing of El-4

the 3" flange. The unused DCA compressor suction piping, filter housing, and associated shutoff valves inside the Clean Room will be cut out and removed and the 3" DCA line will be capped at a location outside the Clean Room. The pneumatic air supply and controls associated with 3-FCV-32-62 and -63 will be removed or spared in place. Electrical controls and valve position indication for these valves will be removed from panels in the main control room.

Evaluation of the proposed modification to drywell penetration X-48 shows that the change does not involve any SSCs with the potential to adversely affect fission product barriers. System interaction analysis did not identify any new failure modes, adverse impacts or new challenges to other systems. Upon removal of the containment isolation valves at penetration X-48, the replacement 3", blind, double O-ring flange arrangement will1*-provide suitable primary containment barrier integrity. The double O-ring configuration will be leak tested in accordance with the plants Appendix J, LLRT program. Since the new barrier is static, control room status and annunciation for the old isolation valves is eliminated thereby eliminating unnecessary operator interface efforts for maintaining the pressure boundary. The installation work will be performed during a plant outage with the containment isolation system out of service. It is concluded that this change will provide improved reliability and maintainability for the primary containment pressure

• barrier at drywell penetration X-48. Therefore, nuclear safety is improved by this modification.

DCN 50583A This change replaced obsolete flow switches 1-FS-90-134B and I-FS-90-134C. Flow transmitters 1-FT-23-48 and 1-FT-23-54 monitor the Residual Heat Removal Service Water (RHRSW) discharge flow from the Residual Heat Removal (RHR) heat exchangers and provide a signal to respective square-root-extractors. The flow switches receive a current signal from the square-root-extractors, which produce a linear current signal proportional to the RHRSW flow. The signals from the square-root-extractors also drive associated computer inputs and respective flow indicators. The flow switches activate the sample pump associated with Radiation Monitor (RM) 1-RM-90-134 upon RHRSW flow through the heat exchangers. The function of the radiation monitors is to detect radiation in the RHRSW samples which would indicate the presence of a leak in the RHR heat exchangers. The proposed modification replaces the existing flow switches with switches that perform the same function while not El-5

affecting the system setpoints, system logic, flow rates, the function of the pumps or the piping configuration. The cables routed between Panels 1-9-19 and. 1-9-93 are affected by this change. The replacement flow switches will perform the same function and will fail in the same manner as the existing, which is either a sample pump start when not required (i.e., inadvertent contact closure) or failure of a sample pump to start when required (i.e., incomplete contact closure). Since the operation of the sample pump is to provide a sample of RHRSW for radiation monitoring, its inadvertent operation or failure to operate does not affect the operation of either the RHR system or the RHRSW system.

These failures are no different than a loop power supply failure or a short in the flow indicator. Hence, there is no increase in the probability that the radiation monitor will fail to monitor the effluent release. Therefore, this change will not increase the probability of occurrence of a malfunction of equipment important to safety previously evaluated in the FSAR.

DCN T39933A This change documented the addition of Control Air (CA)

System, namely, air compressor G. This compressor will become the primary source for the CA system. The new compressor is capable of supplying 1445 standard cubic foot per minute (SCFM) at 120 psig and is set at 105 psig which provides-all the control air needed for normal operation of the plant (based on operating experience) and also pressurizes the accumulator tanks for the Main Steam Isolation Valves (MSIV), Automatic Depressurization System Relief valves, and the Reactor Building equipment access lock inflatable seals. The safety-related portion of the CA system starts at the check valve upstream of the accumulator tanks and runs through to the isolation valves and inflatable seals. The compressors (including the new compressor),

receiver tanks, and piping up to the accumulator tank check valve are in the non-safety related portion of the CA system.

The four existing compressors will remain in service and will start/load sequentially as needed to supplement the new compressor. The new compressor is a centrifugal two stage compressor with an intercooler, aftercooler and lube oil cooler mounted on the same skid. The coolers are connected to a closed loop cooling system with a plate type heat exchanger and pump skid with two 100 percent capacity recirculation pumps. Isolation valves on each pump have been provided to allow maintenance on one pump while the other pump is operating, thereby assuring operability of the El-6

compressor. The secondary side of the heat exchanger will be fed from a 4" raw water tie-in to the 24" Unit 1 header. Its return line will be feed to a 16" Raw Cooling Water drain.

Emergency Equipment Cooling Water (EECW) system will be supplied to the heat exchanger of the new compressor in the same manner as the existing compressors, to provide a backup cooling water supply. This will be done by a tie-in to the 4" EECW header, which supplies the other four compressors.

Control air will be provided to the compressor for sealing air and control valve functions. The new compressor will tie into the CA system header downstream of the receiver tank located in Unit 3. Power is supplied to the new compressor from 4160V Shutdown Board B. Power to the cooling water and lubrication pumps and compressor control panel is supplied from the 480V Reactor Motor Operated Valve (RMOV) Board 2A.

The new compressor will automatically load shed on loss of voltage to the 4160V Shutdown Board B. This load shedding prevents overloading the diesel generators. If there is available margin on the diesel generators, the new control air compressor can be manually restarted.

The equipment added to the plant under this change is in the non-safety related portion of the CA system and does not adversely affect the function or operation of the safety-related portion of the CA system, or any other safety related system or component. Additionally, this change has no impact on Design Basis Accident (DBA) and operational transients discussed in FSAR Chapter 14.

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MISCELLANEOUS TVA-COLR-BF-UNIT 3, Cycle 12, Rev 1 This Safety Evaluation (SE) addresses the BFN Plant U3C12 (U3C12) Core Operating Limits Report (COLR) Revision 1, updated Framatome-ANP (FANP), FANP ATRIUM-10 Loss of Coolant Accident (LOCA) analysis, and application of a cycle-specific Delta over Initial CPR vs. Oscillation Magnitude (DIVOM) curve (change in the Oscillation Power Range Monitor (OPRM) setpoints). This SE also addresses associated FSAR and Unit 3 Technical Requirements Manual (TRM) revisions which include:

• Revision to FSAR Appendix N to incorporate the revised BFN U3C12 Reload Analysis report.

S..*Revision to FSAR Section 14.6.3 to change limiting break size for LOCA analysis and update the references to the revised LOCA analyses.

Revision to FSAR Section 14.5.1.5 to clarify that the Power-Load-Unbalance Out-of-Service (PLUOOS) option was not included as part of the BFN Power Uprate licensing analysis.

Revision to FSAR Section 3.7.7.2.2 to make consistent with sections 14.5.1.5 (i.e., add PLUOOS and End of Cycle-Recirculation Pump Trip Out-of-Service-.

operating flexibility options).

• Revision to Unit 3 TRM Appendix B, COLR to incorporate a new Unit 3 COLR containing the revised Cycle 12 operating limits and setpoints.

The U3C12 COLR is being revised to incorporate PLUOOS thermal limit options as a continuation of corrective actions initiated in response to Problem Evaluation Report 66916.

These values were calculated by FANP and documented in the Reload Analysis Revision 2 report. These new thermal limits will be incorporated in the U3C12 POWERPLEX Core Monitoring Deck.

The methodology for the calculation of the reload specific OPRM Period Based Detection Algorithm (PBDA) setpoints is described in Licensing Topical Report (LTR) NEDO-32465A.

Part of this methodology involves the use of a generic regional mode DIVOM slope. The use of a generic regional mode DIVOM slope was determined to be potentially El-8

non-conservative for some fuel and core designs.

Consequently, an interim conservative methodology enhancement using a Figure-Of-Merit (FOM) derived slope has been used in PBDA setpoint analyses for the intervening operating cycles.

This FOM method is the one originally used for the determination of OPRM setpoints for U3C12. One of the changes being evaluated in this SE is the use of a plant/cycle specific DIVOM calculation that is included in the U3C12 Reload Analysis Revision 2 report. This plant-specific approach was developed by the BWR Owners Group for closure of the original 10 CFR Part 21 issue. This closure method was communicated to and concurred with by the NRC. OPRM setpoints based upon a plant-specific DIVOM calculation are already being used in current U2C14 operation. The revised Reload Report includes a change in the reference basis LOCA analysis for the FANP ATRIUM-10 fuel. This revised analysis has been performed using NRC approved methodologies and meets 10 CFR 50.46 acceptance criteria. The change in Peak Cladding Temperature was reported to the NRC under the 10 CFR 50.46 process and, therefore, is already part of the U3C12 reported licensing basis.

TVA-COLR-BF-UNIT 3, Cycle 13, Rev 0 This is the second BFN 3 reload using the ATRIUM-10 fuel from FANP. ATRIUM-10 fuel suitability for use in the BFN cores has been previously generically addressed in Engineering Design Change 60038A. The licensing requirements for new assembly designs for FANP are defined within Licensing Topical Report LTR XN-NF-89-98(P) (A). This LTR identifies specific evaluations that must be performed for each new assembly design. These evaluations can be subdivided into generic, plant specific, and cycle-specific categories. The adequacy of the generic and plant-specific evaluations is the subject of EDC 60038A. This SE does not specifically address ATRIUM-10 introduction since that has been previously addressed; however, it does address the cycle specific evaluations for U3C13 and the effect of the ATRIUM-10 new fuel on these evaluations and analyses.

This reload includes the first use of Blended Low Enriched Uranium (BLEU) material for Unit 3; however, BLEU is already in use in the U2C14 core. The BLEU program makes use of some of the government's excess High Enriched Uranium which was declared surplus to national security needs in 1995. The BLEU containing ATRIUM-10 fuel is essentially identical to Commercial Grade Uranium (CGU) containing ATRIUM-10 fuel previously approved Engineering Design Change 60038A for use El1-9

at BFN. The primary differences from CGU are the presence in the initial fuel of:

a) Very small quantities of two uranium isotopes (U-232 and U-233) that are not contained in new fuel that has been enriched from natural uranium, b) Higher concentrations of U-234, a naturally occurring isotope contained in CGU but in lower amounts, and U-236 which is normally present only after CGU has been irradiated, and c) Trace amounts of fission products and U-232 daughter products - these differences are due to fact that the source material that is blended down into BLEU was previously irradiated in DOE reactors.

The results of the U3C13 Safety Limit Minimum Critical Power Ratio (SLMCPR) analysis indicated that the Unit 3 MCPR Safety Limit continues to support 1.09 (dual loop) and 1.11 (single loop). No change to the Unit 3 SLMCPR Technical Specification was required for Cycle 13. Cycle 13 is licensed to operate at a power level of 3458 MWth (105% power uprate) which is the same as U3C12.

TVA-COLR-BF-UNIT 2, Cycle 14, Rev 1 This SE addresses the BFN Plant U2C14 COLR, Revision 1. This SE also addresses associated FSAR and Unit 2 TRM revisions which include:

Revision to FSAR Appendix N to incorporate the revised BEN U2C14 Reload Analysis report.

Revision to Unit 2 TRM Appendix B, "COLR" to incorporate a new Unit 2 COLR containing the revised Cycle 14 operating limits and setpoints.

The U2C14 COLR is being revised to incorporate PLUOOS thermal limit options as a continuation of corrective actions initiated in response to Problem Evaluation Report 66916.

These values were calculated by FANP and documented in the Reload Analysis Revision 2 report. These new thermal limits will be incorporated in the U2C14 POWERPLEX Core Monitoring Deck. An additional change is being made in the Core Monitoring Deck to change the coefficient used by the software to model reactor pressure versus core power. This change is being made to more accurately model actual system pressure and will make it consistent with the corresponding model in the U3C13 PowerPlex input deck.

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Functional Evaluation 41246 Functional Evaluation 41246 addresses the condition of a planned outage of the Unit 1 Main Bank Transformer, including simultaneous outages of both Unit Station Service Transformers (USSTs) lA and 1 B while:

(a) Unit 1 is in a defueled condition; (b) Unit 2 is in any MODE including MODES 1,2, or 3; and (c) Unit 3 is in any MODE including MODES 1, 2 or 3.

The functional evaluation corresponds to Precaution/

Limitation 3.30 of Procedure 0-0I-57A which states "Prior to taking out a USST or Common Station Service Transformer (CSST) or prior to placing a 4kV Unit Board or 4kV Common Board on its alternate supply, contact Electrical Design Engineering to perform a functional evaluation to determine what actions, if any, are required to maintain an operable offsite power supply.

For the subject condition, the functional evaluation found that specific compensatory measures are needed in advance and during the outage of the Unit 1 Main Bank Transformer. The specific compensatory measures, identified in Calculation EDQ0057950036, Rev. 10, are:

4-kV Unit Board 2C AUTO/MAN Transfer (43 Switch) in Manual aligned to USST 2A 4-kV Unit Board 3C AUTO/MAN Transfer (43 Switch) in Manual aligned to USST 3A 4-kV Shutdown Bus 1 aligned to 4-kV Unit Board 2B as power supply(alternate supply) 4-kV shutdown Bus 2 aligned to 4-kV Unit Board 2A as power supply (normal supply)

Operation of Unit 1 Condenser Circulating Water pumps is not permitted.

Compensatory measures identified in any functional evaluation performed in accordance with NEDP-22, Section 3.1 include a note that states in part:

If compensatory measures are necessary to maintain operability, the compenpsatory measures shall be subjected to a 50.59 review and/or 72.49 review or FPDP-3, "Management of the Fire Protection Report" for fire EI-ll

protection and Appendix R issues. The intent is to determine if the compensatory measures (not the degraded/

non-conforming condition) impacts other aspects of the facility A conservative assessment to address the contingency actions in a 10 CFR 50.59 evaluation is based on the reduction in the number of automatically powered Unit Boards providing power to loads that support safe shutdown of any unit during scenarios that include loss of 500-kV to circuits between the offsite transmission network and USSTs.

The implementation of the subject compensatory measures, directly or indirectly impacts the operation of the following systems analyzed in the FSAR and Safe Shutdown Analysis:

4-kV Auxiliary Power System (57-5), and switchyard components required to interface the distribution of the offsite power sources to the emergency shutdown busses of the 4-kV auxiliary power system.

Based on a review of the FSAR and the Safe Shutdown Analysis, the implementation of the subject compensatory measures does not introduce any new failure modes.

PER 90518 This evaluation addresses the safety function with respect to design bases of the offsite power system and the changes referenced below which received inadequate 10 CFR 50.59 safety assessment evaluation initially.

A FSAR revision added wording changes to pages 8.4-1 and 8.4-2 to allow either a manual or automatic transfer of the 4-kV Unit Boards to their alternate connection.

FSAR sections 8.3 (Transmission System) and 8.4 (Normal Auxiliary Power) were revised to clearly define the safety design bases for the 500 and 161-kV switchyards and associated offsite power circuits. The FSAR change required the normal and alternate offsite power circuits for each unit to be sufficient to supply the power to at least one division of safety-related buses under normal or accident conditions.

The change identified that for some alignments that the offsite power circuits through the CSST's may not have sufficient capacity, but this is addressed by manually disabling the automatic transfers for some 4.16-kV boards.

Therefore,-this activity does not result in a depa-rture from or impact to a method of evaluation described in the FSAR E1-12

used in establishing the design bases or in the safety analysis.

DCN (T37517B) issued in November 1995 established electrical loading limitations for the restart on Unit 3 that included a "LOAD LIMIT MATRIX" which allowed blocking the automatic transfer of 4-kV Unit Boards to their alternate source (161-kV via the CSSTs) under various plant conditions involving USST outages while still taking credit for 161-kV as a Technical Specifications (TS) offsite power source. The "LOAD LIMIT MATRIX" was incorporated into Operating Instruction, O-OI-57A, Revision 5. With this automatic transfer blocked, only 1 of the 2 divisions of safety related boards would have an immediate alternate offsite power circuit capable of mitigating a DBA.

Inhibiting the automatic transfer of loads to the 161-kVy supplied Start Buses for certain alternate alignments will not result in more than a minimal increase of the consequences of an accident previously evaluated in the FSAR.

For BFN Units, only a single division of engineered safeguard systems is required to safely shutdown the plant during normal or accident conditions in accordance with TS Bases section 3.8.1. The actions will ensure that at least one division will always have an immediate offsite power circuit available from the alternate offsite power source should the normal offsite power source/circuit become unavailable. The plant response to- an accident with the actions in place is bounded by the existing plant Loss of Offsite Power/LOCA analysis and Chapter 14 of the FSAR.-

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TEMPORARY ALTERATIONS (TACF) 2-05-009-003 This TACF will defeat the automatic RFPTs trip function of the Thrust Bearing Wear Detection (TBWD) circuits for the 2B RFPT. On 08/05/2005 at approximately 1708, BFN Unit 2 automatically scrammed on loss of two RFPTs. The sequence of events indicated that the first pump to fail was the 2C RFPT.

The Reactor Feedwater Level Control System responded to the trip by increasing the speed demand on the 2A and 2B RFPTs.

At approximately 5400 rpms, the 2B RFPT tripped on activation of TBWD circuits. The 2B RFPT trip was an unexpected response to the ongoing plant transient (2C RFPT trip

• response) and presented an unnecessary challenge to the engineering safety features by causing the reactor to scram on low reactor coolant level. The 2B RFPT thrust bearing clearance has been verified tobe within acceptable limits.

No normal mechanical or electrical conditions have been discovered that would explain the unexpected trip of the 2B RFPT from the TBWD circuits. Oil samples have confirmed a lack of babbit material (bearing particles) in the bearing oil which indicates no actual thrust bearing damage has occurred.

The TACF will be implemented by: (1) Installing a jumper across Terminal Points 122 and 124 (wires 2M969 and 2M969A) on Terminal Strip LL in Panel 2-9-6, and (2) 'placing 2B RFPT

-TBWD test switch, 2-HS-3-139, in the TEST position. Placing the hand switch 2-HS-3-139 in the TEST position will defeat both the automatic trip function and the Main Control Room indications associated with the TBWD circuits which include:

(1) Panel 2-9-6 white indicating test lights, (2) Integrated Computer System (ICS) displays, and (3) The ICS alarm output log printer (alarm typer).

When the hand switch 2-HS-3-139 is in NORM, the Active and Inactive Face white test lights located above the hand switch on Panel 2-9-6 are extinguished. Placing the hand switch 2-HS-3-139 in the TEST position will illuminate the test lights. The test lights will remain illuminated unless the associated TBWD circuit is tripped. Therefore, the illuminated test lights will provide the Operations with a visual indication that the TBWD circuits are not tripped under the proposed TACF configuration.

The jumper installed with this TACF will restore the ICS displays and the ICS alarm typer. Banana 4acks will be.

installed on the terminal strip for ease of jumper installation. TBWD System

Description:

The TBWD system EI-14

consists of a pair of oil nozzles mounted at a fixed distance from a sensor disc. The spacing between the nozzles and the sensor disc is at fixed distance. Therefore, with the turbine rotor positioned within the normal limits, the oil pressure in the supply line is maintained at a pressure below the switch setpoint. In the event the turbine rotor moves axially in either direction, the spacing between the oil nozzle and the sensor disc will decrease and restrict the oil flowing from the nozzle. The decreasing nozzle-to-disc space results in an increased control oil supply pressure. If the amount of axially movement is sufficient, then the control oil pressure will exceed the pressure switch setpoint of 40 psig increasing, and the associated RFPT turbine trip solenoid will energize.

The impact of defeating the TBWD trip feature is primarily limited to economic and industrial safety areas. The potential economic impact would be the increased repair costs due to a thrust bearing failure without an automatic trip.

The potential industrial safety impact is an increased possibility of personnel injury resulting from a catastrophic failure of the RFPT due to a thrust bearing failure.

However, the RFPTs are located in a concrete enclosed high radiation area, where personnel access is limited during normal operation. Therefore, the potential industrial safety impacts are judged to be not significant.

2-05-12-005 TACF 2-05-012-005 will disable the test control pushbutton and the position indicating light on Main Control Room panel 2-9-7. During troubleshooting of 2-BKR-248-0001/115 to determine reason for failure to re-close after breaker trip, it was identified that there was an electrical short at a local device (2-FCV-005-0001) which created the problem.

Electrical isolation will clear the fault and.allow control and indication of other components connected to the circuit.

The alteration requires lifting the leads EVTI, EVT2, EVT3, EVTP, and EVTN in cable 2V1681 at terminal block AA in Control Building panel 2-9-7. The valve test pushbutton shall be tagged and the lifted cable wires shall be insulated and tagged. Repairs shall be accomplished at a later date as plant conditions and work schedule allows. Number 1 Extraction Non-return valve 2-FCV-005-0001 is a testable check valve. The valve is classified non-quality related and does not perform any active or passive safety function. The primary purpose of the non-return valves in the extraction system is to prevent the water in the heaters from flashing into steam and flowing through the turbine to the condenser after the turbine is tripped. Failure mode for the valve is EI-15

failure to close upon loss of steam flow. FSAR Section 11.2.2 describes that testing intervals of the extraction system check valve may have an impact to turbine missile generation evaluation and Section 11.2.4 describes periodic testing of these valves to insure functional performance as required for continued safe turbine generator operation, and to provide maximum protection for operating personnel. Per GET-8039.1, Probability of Missile Generation in General Electric Nuclear Turbines, the probability of a turbine missile is dependent upon the probability of turbine over-speed. Turbine overspeed is dependent on the probability that the main steam valves and/or intermediate steam valves fail to close when required. For example, both a turbine control valve and a stop valve must fail, in combination with a load rejection, to develop a high overspeed event. Testing the extraction check valve before plant startup is adequate to insure no increase in probability of a turbine missile event. The valve may be operated to the closed position by a spring loaded piston and outside lever and weight. During plant operation, the spring loaded piston is maintained in a compressed condition by compressed air to the cylinder. This allows the check valve to open or closed based on steam flow.

Upon loss of steam flow the outside weighted lever will tend to close the valve. The operator can test closure function of the valve from the control room by controlling a solenoid valve which takes air off of the compressed piston which allows the valve to move toward closure (test) or to close (under no steam flow). Operating Instruction 2-01-47, Turbine-Generator System, describes daily test of the valves' capability to close. The failure of the valve to close or partially close is addressed by prescribed operator action.

Not being able to test the check valve does not have an impact on plant safety, as noted above, by not contributing to the probability of a turbine missile. Also, as needed, the operator may close extraction steam valves 2-FCV-005-0005, 0009 and 0013 to Feedwater Heaters A-1, B-l, and C-1 to prevent backflow to the turbine. Plant tests of the above extraction steam heater isolation valves provide adequate assurance of their operability. The present circuit failure (Work Orders 05-721377-000 and 05-71 8734-000) prevents the operator from receiving an unambiguous indication of valve status. TACF 2-05-012-005 will allow disabling the test control and valve position indication to clear the circuit fault. Based on the above, this change will have minimal or no impact on plant safety or operability.

El-16

2-05-013-085 One and one-half inch CA line upstream of valve 2-TV-085-0791 on the Control Rod Drive (CRD) air header was separated at a solder joint elbow. Work Order 05-723447-000 was initiated to implement a TACF to immediately temporarily repair the joint. The tubing was reseated in the elbow and carbon steel wire was used to tie the joint together. This joint can not be re-soldered on-line since the unit would scram if air pressure is lost to the valves served by this header.

Therefore, TACF 2-05-013-085 allows an optional method of repair for the tubing in accordance with an approved procedure.

This TACF provides the design evaluations necessary to allow an optional repair method for solder joints on the CA header which restores the structural integrity of the CRD CA header.

The component addressed by this review is a leaking solder joint on the CRD CA header. TACF 2-05-013-085 allows a temporary repair method for solder joints on the CA header which restores the integrity of the CRD CA header, the design functions of the CRD CA header are not changed since the restoration of the degraded component maintains structural integrity.

The temporary joint repair method using wire does not adversely change the configuration, function or operation of the CA system to the CRDs. This repair option retains the original structural integrity of the tubing without adding a significant amount of weight. The proposed repair does not affect any system such that it could cause a credible accident. The changes are made to non-safety related components in a Class I seismic structure (Reactor Building).

However, structural integrity during a seismic event will be maintained by meeting the designated seismic class II or I(L) requirements for position retention. This change will not adversely affect the ability of any Safety System to perform its intended design function.

E1-17

PROCEDURE S O-AOI-100-8 NRC Safeguard Advisory 05-02 delineates the site action requirements for airborne threats. This is a procedure change which incorporates operations actions from Safeguard Advisory 05-02 into this Abnormal Operating Instruction.

These actions will attempt to place the Units/Site and personnel in a safe condition in order to minimize the radiological and personnel hazards associated with this event. These changes do not operate plant equipment outside of their intended functions, it only places the plant in a condition to minimize the effects of the event. Part of the response is to relocate an operator. This relocation takes us below the TS minimum staffing for the control rooms, but any of the scenarios associated with SA-05-02 would occur within the two hours allowed by TS. TS 5.2.2.b allows going below the minimum staffing for unanticipated absences provided actions to restore the staffing level occur within two hours. For this advisory, the operator is absent from the control room, but is still on site, just relocated to another area. Therefore, these procedural changes do not involve a change to a procedure that adversely affects how FSAR described SSCs design functions are performed or controlled.

1-POI-64-2 Periodic Operating Instruction I-POI-64-2, MSIV Secondary Containment System, is a new procedure to be implemented for Unit 1. The procedure includes instructions for infrequent operations that support the maintenance/modifications of outboard MSIVs. Units 2 and 3 utilize similar approved instructions in 2-01-64 and 3-01-64 allowing the same maintenance and modification activities to be performed.

To perform maintenance or modification on outboard MSIVs, it will be necessary to extend the Secondary Containment membrane into the turbine building by utilizing the Main Steam piping and associated valves as the barrier. The seismic ruggedness of these valves and piping is documented in calculation CDN199920040166,R001.

The new instruction 1-POI-64-2 contains instructions to ensure that Secondary Containment will continue to perform its design safety function as described in the FSAR and maintain 1-4"water (negative) differential pressure. The extended secondary containment membrane will also support FSAR Chapter 14 accident analyses with implementation of the controls in this new POI.

E1-18

WORK ORDER 06-711138-000 The proposed activities under this work order (06-711138-0000) consist of the following actions listed below to resolve a Generic Letter 91-18 issue regarding the failure of this obsolete valve to pass administrative leak rate limit.

The obsolete Suppression Chamber Standby Gas Inboard Isolation Valve 1-FCV-064-0034 will be removed from its installed location and transported to a suitable work area. The valve will be temporarily replaced with a spacer until a suitable replacement is installed per DCN 51189. Foreign Material Exclusion considerations, along with the de-fueled status of the Unit 1 Reactor justify no further discussions regarding effects on Unit 1 in this evaluation.

The sealing liner and seating surfaces of the removed valve will be repaired using an elastomeric compound (i.e., Belzona © 2111 -D&A High Build Elastomer) that is a durable and abrasion resistant material for repairing, rebuilding and resurfacing elastomeric components. The repaired valve, upon demonstrating acceptable leak tightness, will replace the existing Suppression Chamber Standby Gas Inboard Isolation Valve 3-FCV-064-0034.

These activities are designed to restore the ability of valve 3-FCV-064-0034 to seal while performing its containment isolation function and to stay intact during normal operation. The DBAs associated with primary containment and considered for this evaluation are those associated with low vessel level, high drywell pressure, and high radiation in the reactor building or refueling ventilation systems (i.e.,

rod drop accident and LOCA accident).

The credible failure modes considered are the failure of the applied substance to maintain leak-tightness and the failure of the material to stay intact and subsequently traveling into the Suppression Chamber and/or the Drywell to Torus Delta-P Compressor. Therefore, the proposed activities do not involve changes that adversely affect how a FSAR described design function is performed or controlled.

EI-19

ENCLOSURE 3 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)

UNITS 1, 2, AND 3 TECHNICAL SPECIFICATIONS BASES CHANGES AND ADDITIONS

Secondary Containment Isolation Instrumentation B 3.3.6.2 B 3.3 INSTRUMENTATION B 3.3.6.2 Secondary Containment Isolation Instrumentation BASES BACKGROUND The secondary containment isolation instrumentation automatically initiates closure of appropriate secondary containment isolation valves (SCIVs) and starts the Standby Gas Treatment (SGT) System. The function of these systems, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) (Ref. 1). Secondary containment isolation and establishment of vacuum with the SGT System within the assumed time limits ensures that fission products that leak from primary containment following a DBA, or are released outside primary containment, or are released during certain operations when primary containment is not required to be OPERABLE are maintained within applicable limits.

The isolation instrumentation includes the sensors, relays, and switches that are necessary to cause initiation of secondary containment isolation. Most channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a secondary containment isolation signal to the isolation logic. Functional diversity is provided by monitoring a wide range'of independent parameters. The input parameters to the isolation logic are (1) reactor vessel water level, (2) drywell pressure, (3) reactor zone exhaust high radiation, and (4) refueling floor high radiation. Redundant sensor input signals from each parameter are provided for initiation of isolation. The refueling floor exhaust radiation monitors referred to in Table 3.3.6.2-1 are the same instruments called refueling floor radiation monitors in the Bases discussion.

(continued)

BFN-UNIT 1 B 3.3-223 Revision e-,-35 February 14. 2006

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE 2. Drywell Pressure - High (PIS-64-56A-D) (continued)

SAFETY ANALYSES, LCO, and The Allowable Value was chosen to be the same as the ECCS APPLICABILITY Drywell Pressure - High Function Allowable Value (LCO 3.3.5.1) since this is indicative of a loss of coolant accident (LOCA).

The Drywell Pressure - High Function is required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists in the RCS; thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas.

This Function is not required in MODES 4 and 5 because the probability and consequences of these events are low due to the RCS pressure and temperature limitations of these MODES, 3, 4. Reactor Zone Exhaust and Refueling Floor Radiation -

High (RM-90-140, 141, 142, 143)

High secondary containment exhaust radiation is an indication of possible gross failure of the fuel cladding. The release may have originated from the primary containment due to a break in the RCPB. When Exhaust Radiation - High is detected, secondary containment isolation and actuation of the SGT System are initiated to limit the release of fission products as assumed in the FSAR safety analyses (Ref. 4).

The Exhaust Radiation - High signals are initiated from radiation detectors located on the reactor zone ventilation exhaust and the common refueling zone. There are two radiation monitors and two divisional trip systems for each unit (Units 1, 2, and 3). Each monitor has one channel of Reactor Zone Exhaust Radiation - High and one channel of Refueling Floor Radiation - High. Each monitor's channels provide signals to its associated divisional trip system. Each channel has two radiation elements which monitor the (continued)

BFN-UNIT 1 B 3.3-228 Revision 2-9-, 35 February 14, 2006

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE 3. 4. Reactor Zone Exhaust and Refueling Floor Radiation -

SAFETY ANALYSES, --ij (RM-90-140, 141, 142, 143) (continued)

LCO, and APPLICABILITY ventilation exhaust both of which must be OPERABLE or tripped for the channel to be OPERABLE. Both radiation elements must provide a High signal to trip the associated channel (two-out-of-two). However, the output relays from the divisional trip systems are arranged in logic systems such that if either channel for a zone trips, a secondary containment isolation signal is initiated (one-out-of-two). Six channels of

-Reactor Zone Exhaust Radiation - High Function and six channels of Refueling Floor Radiation - High Function are available (two channels of each Function from each unit) and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Values are chosen to provide timely detection of nuclear system process barrier leaks inside containment but are far enough above background levels to avoid spurious isolation.

The Reactor Zone Exhaust and Refueling Floor Radiation -

High Functions are required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists; thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas. In MODES 4 and 5, the probability and consequences of these events are low due to the RCS pressure and temperature limitations of these MODES; thus, these Functions are not required. In addition, the Functions are also required to be OPERABLE during OPDRVs because the capability of detecting radiation releases due to fuel failures (due to fuel uncovery) must be provided to ensure that offsite dose limits are not exceeded.

(continued)

BFN-UNIT 1 B 3.3-229 --

Revision 0-2 *935 February 14, 2006

CREV System Instrumentation B 3.3.7.1 B 3.3 INSTRUMENTATION B 3.3.7.1 Control Room Emergency Ventilation (CREV) System Instrumentation BASES BACKGROUND The CREV System is designed to provide a radiologically controlled environment to ensure the habitability of the control room for the safety of control room operators under all plant conditions. Two independent CREV subsystems are each capable of fulfilling the stated safety function. The instrumentation and controls for the CREV System automatically initiate action to pressurize the control room (CR) to minimize the consequences of radioactive material in the control room environment.

In the event of a Reactor Vessel Water Level - Low, Level 3, Drywell Pressure - High, Reactor Zone Exhaust Radiation -

High, Refueling Floor Radiation - High, or Control Room Air Supply Duct Radiation - High signal, the CREV System is automatically started in the pressurization mode. The air is then recirculated through the charcoal filter, and sufficient outside air is drawn in through the normal intake to maintain the CR slightly pressurized.

The CREV System instrumentation has two control logic systems, which can initiate their associated CREV subsystem (only the selected subsystem will be initiated) (Ref. 1). Each control logic system receives input from each of the Functions listed above. The Functions are arranged as follows for each control logic system. The Reactor Vessel Water Level - Low, Level 3 and Drywell Pressure - High are each arranged in a one-out-of-two taken twice logic (these signals are the same that isolate the primary containment and additional information (continued)

BFN-UNIT 1 B 3.3-237 Revision 9-35 February 14, 2006

CREV System Instrumentation B 3.3.7.1 BASES BACKGROUND on the arrangement of these channels in the PCIS trip systems

.-(continued) can be found in the Bases for LCO 3.3.6.1, 'Primary Containment Isolation Instrumentation," Function 2). The Reactor Zone Exhaust Radiation - High and Refueling Floor Radiation - High are each arranged in a one-out-of-two logic (these signals are the same that isolate the secondary containment and additional information on the arrangement of these channels in the divisional trip systems can be found in the Bases for LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation,". Functions 3 and 4). The control Room Air Supply Duct Radiation - High Function contains two radiation monitors (one per trip system). The refueling floor exhaust radiation monitors referred to in Table 3.3.7.1-1 are the same instruments called refueling floor radiation monitors in the Bases discussion.

The output relays from the trip systems are arranged in the control logic systems in a one-out-of-two logic. Some of the channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a CREV System initiation signal to the initiation logic.

APPLICABLE The ability of the CREV System to maintain the habitability of SAFETY ANALYSES, the CR is explicitly assumed for certain accidents as discussed LCO, and in the FSAR safety analyses (Ref. 2). CREV System operation APPLICABILITY ensures that the radiation exposure of control room personnel, through the duration of any one of the postulated accidents, does not exceed the limits set by GDC 19 of 10 CFR 50, Appendix A.

CREV System instrumentation satisfies Criterion 3 of the NRC Policy Statement (Ref. 5).

(continued)

BFN-UNIT 1 B 3.3-238 Revision &,-35 February 14, 2006

CREV System Instrumentation B 3.3.7.1 BASES APPLICABLE 3.- 4. Reactor Zone Exhaust and Refuelinq Floor SAFETY ANALYSES, Radiation- High (RM-90-140, 141, 142, 143)

LCO, and APPLICABILITY High secondary containment exhaust radiation is an indication (continued) of possible gross failure of the fuel cladding. The release may have originated from the primary containment due to a break in the RCPB. A reactor zone or refueling floor exhaust high radiation signal will automatically initiate the CREV System, since this radiation release could result in radiation exposure to control room personnel.

The reactor zone and refueling floor exhaust radiation monitors provide two independent channels for each ventilation exhaust path coming from the reactor zones and the refueling zone.

There are two radiation monitors (each monitor provides one channel of each Function) and two divisional trip systems for each unit (Units 1, 2, and 3). Six channels of each function are available (two channels of each Function from each unit) and are required to be OPERABLE to ensure that no single instrument failure can preclude CREV System initiation. The Allowable Value was selected to ensure that the Function will promptly detect high activity that could threaten exposure to control room personnel.

The Reactor Zone Exhaust and Refueling Floor Radiation - I High Functions are required to be OPERABLE in MODES 1, 2, and 3 and during operations with a potential for draining the reactor vessel (OPDRVs), to ensure that control room personnel are protected during a LOCA or vessel draindown event. During MODES 4 and 5, when these specified conditions are not in progress (e.g., OPDRVs), the probability of a LOCA or fuel damage is low; thus, the Function is not required.

(continued)

BFN-UNIT 1 B 3.3-242 Revision Q-22-35 February 14, 2006

ECCS - Operating B 3.5.1 BASES BACKGROUND immediately when offsite power is available and B, C, and D (continued) pumps approximately 7, 14, and 21 seconds afterwards and if offsite power is not available all pumps 7 seconds after AC power is available). When the RPV pressure drops sufficiently, CS System flow to the RPV begins. A full flow test line is provided to route water from and to the suppression pool to allow testing of the CS System without spraying water in the RPV.

LPCI is an independent operating mode of the RHR System.

There are two LPCI subsystems (Ref. 2), each consisting of two motor driven pumps and piping and valves to transfer water from the suppression pool to the RPV via the corresponding recirculation loop.

The two LPCI pumps and associated motor operated valves in each LPCI subsystem are powered from separate 4 kV shutdown boards. Both pumps in a LPCI subsystem inject water into the reactor vessel through a common inboard injection valve and depend on the closure of the recirculation pump discharge valve following a LPCI injection signal.

Therefore, each LPCI subsystem's common inboard injection valve and recirculation pump discharge valve are powered from one of the two 4 kV shutdown boards associated with that subsystem.

I (continued)

BFN-UNIT 1 B 3.5-3 Revision 07 33 August 4, 2005

ECCS - Operating B 3.5.1 BASES SURVEILLANCE SR 3.5.1.11 (continued)

REQUIREMENTS The Frequency of 18 months is based on the need to perform the Surveillance under the conditions that apply just prior to or during a startup from a plant outage. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

(continued)

BFN-UNIT 1 B 3.5-21 Revision & 33 August 4, 2005

CAD System B 3.6.3.1 BASES (continued)

ACTIONS A..1 If one CAD subsystem is inoperable, it must be restored to OPERABLE status within 30 days. In this Condition, the remaining OPERABLE CAD subsystem is adequate to perform the oxygen control function. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced oxygen control capability. The 30 day Completion Time is based on the low probability of the occurrence of a LOCA that would generate hydrogen and oxygen in amounts capable of exceeding the flammability limit, the amount of time available after the event for operator action to prevent exceeding this limit, and the availability of the OPERABLE CAD subsystem and other hydrogen mitigating systems.

B,1 and B.2 With two CAD subsystems inoperable, the ability to control the hydrogen control function via alternate capabilities must be verified by administrative means within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. The alternate hydrogen control capabilities are provided by the Primary Containment Inerting System. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Completion Time allows a reasonable period of time to verify that a loss of hydrogen control function does not exist. In addition, the alternate hydrogen control system (Primary Containment Inerting) capability must be verified once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter to ensure its continued availability. Both the initial verification and all subsequent verifications may be performed as an administrative check by examining logs or other information to determine the availability of the alternate hydrogen control system (Primary Containment Inerting). If the ability to perform the hydrogen control function is maintained via the Primary Containment Inerting System, continued operation for up to 7 days is permitted with two CAD subsystems inoperable.

(continued)

BFN-UNIT 1 B 3.6-93 Revision-0-, 34 Alrniedm*li.t No. 249 September 07, 2005

CAD System B 3.6.3.1 BASES ACTIONS B. land 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 occurrence of a LOCA that would generate hydrogen in amounts capable of exceeding the flammability limit.

C._1 If any Required Action cannot be met within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 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 reach 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 after an accident to replenish the nitrogen supply for long term inerting. 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.

(continued)

BFN-UNIT 1 B 3.6-94 Revision,-+, 34 September 07, 2005

Distribution Systems - Operating B 3.8.7 BASES (continued)

LCO The required electrical power distribution subsystems listed in Table B 3.8.7-1 ensure the availability of AC and DC electrical power for the systems required to shut dowri-the reactor and maintain it in a safe condition after an abnormal operational transient or a postulated DBA. The AC and DC electrical power distribution subsystems are required to be OPERABLE.

Maintaining the AC and DC electrical power distribution subsystems OPERABLE ensures that the redundancy incorporated into the design of ESF is not defeated. Therefore, a single failure within any system or within the electrical power distribution subsystems will not prevent safe shutdown of the reactor.

The AC electrical power distribution subsystems require the associated buses and electrical circuits to be energized to their proper voltages. OPERABLE DC electrical power distribution subsystems require the associated buses to be energized to their proper voltage from either the associated battery or charger.

Based on the number of safety significant electrical loads associated with each board listed in Table B 3.8.7-1, if one or more of the boards becomes inoperable, entry into the appropriate ACTIONS of LCO 3.8.7 is required. Other boards, such as motor control centers (MCC) and distribution panels which help comprise the AC and DC distribution systems may not be listed in Table B 3.8.7-1. The loss of electrical loads associated with these boards may not result in a complete loss of a redundant safety function necessary to shut down the reactor and maintain it in a safe condition. Therefore, should (continued)

BFN-UNIT 1 B 3.8-86 Revision 6, 33 August 4, 2005

Distribution Systems - Operating B 3.8.7 BASES (continued)

ACTIONS A.1 With one Unit 1 and 2 4.16 kV shutdown board inoperable, the remaining Unit 1 and 2 4.16 kV shutdown boards are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition. The overall reliability is reduced, I however, because another single failure in the remaining three 4.16 kV shutdown boards could result in the minimum required ESF functions not being supported. Therefore, the 4.16 kV shutdown board must be restored to OPERABLE status within 5 days.

The 5 day time limit before requiring a unit shutdown in this Condition is acceptable because the remaining 4.16 kV shutdown boards have AC power available, and the probability of an event in conjunction with a single failure of a redundant component in the 4.16 kV shutdown board with AC power is low. (The redundant component is verified OPERABLE in accordance with Specification 5.5.11, "Safety Function Determination Program (SFDP)y")

(continued)

BFN-UNIT 1 B 3.8-89 Revision e, 36 June 22, 2006

Distribution Systems - Operating B 3.8.7 BASES ACTIONS A.'1 (continued)

The second Completion Time for Required Action A.1 establishes a limit on the maximum time allowed for any combination of required distribution subsystems to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a Unit DC board is inoperable and subsequently returned.

OPERABLE, this LCO may already have been not met for up to 7 days. This situation could lead to a total duration of 12 days, since initial failure of the LCO, to restore the 4.16 kV shutdown board. At this time a Unit DC board could again become inoperable, and the 4.16 kV shutdown board could be restored OPERABLE. This could continue indefinitely.

This Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This results in establishing the "time zero" at the time this LCO was initially not met, instead of at the time Condition A was entered.

The 12 day Completion Time is an acceptable limitation on this potential to fail to meet the LCO indefinitely.

Pursuant to LCO 3.0.6, the Distribution System Actions B, C, or F would not be entered even if the 4.16 kV shutdown board was inoperable, resulting in de-energization of a 480 V board.

Therefore, the Required Actions of Condition A are modified by a Note to indicate that when Condition A is entered with no power source to a required 480 V board, Actions B, C, or F must be immediately entered. This allows Condition A to provide requirements for the loss of the 4.16 kV shutdown board without regard to whether a 480 V shutdown board is de-energized. Actions B, C, or F provide the appropriate restrictions for a de-energized 480 V board.

(continued)

BFN-UNIT 1 B 3.8-90 Revision 0, 33 August 4, 2005

Distribution Systems - Operating B 3.8.7 BASES ACTIONS C.1 (continued)

With one Units 1 and 2 480 V diesel auxiliary board inoperable, the remaining 480 V diesel auxiliary board is capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition assuming no single failure. The overall reliability is reduced because a single failure in the remaining 480 V diesel auxiliary board could result in the minimum required ESF functions not being supported. Therefore, the 480 V diesel auxiliary board must be restored to OPERABLE status within 5 days.

(continued)

BFN-UNIT B 3.8-93 Revision 0, 33 August 4, 2005

Distribution Systems - Operating B 3.8.7 BASES ACTIONS C._1 (continued)

The Condition C postulated worst scenario is one 480 V diesel I auxiliary board without AC power (i.e., no offsite power to the diesel auxiliary board). In this Condition, the Unit 1 and 2 DGs and SGT trains A and B are more vulnerable to a complete loss of AC power. These boards are normally fed from Shutdown Boards A and D. However, both of these boards have an alternate source of power coming from 4.16 kV shutdown board B. Thus, each auxiliary board has access to two DGs.

Therefore, the 5 day time limit before requiring a unit shutdown in this Condition is acceptable because;

a. The remaining diesel auxiliary board has an alternate source of AC power in addition to the normal source and their dedicated DG.

b. The potential for an event in conjunction with a single failure of a redundant component in the 480 V diesel auxiliary board with AC power is minimal. (The redundant component is verified OPERABLE in accordance with Specification 5.5.11, "Safety Function Determination Program (SFDP).")

(continued)

BFN-UNIT 1 B 3.8-94 Revision 0, 33 August 4, 2005

Distribution Systems - Operating B 3.8.7 BASES ACTIONS C.1 (continued)

The second Completion Time (12 days) for Required Action C.1 establishes a limit on the maximum time allowed for any combination of required distribution subsystems to be inoperable in any single contiguous occurrence of failing to meet the LCO. If Condition C is entered while, for instance, a 4.16 kV shutdown board is inoperable and subsequently restored OPERABLE, the LCO may already have been not met for up to 5 days. This situation could lead to a total duration of 10 days; since initial failure of the LCO, to restore the 480 V DG auxiliary board. At this time, a 4.16 kV shutdown board could again become inoperable, and the 480 V DG auxiliary board could be restored OPERABLE. This could continue indefinitely.

This Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This allowance results in establishing the "time zero" at the time the LCO was initially not met, instead of at the time Condition C was entered. The 12 day Completion Time is an acceptable limitation on this potential of failing to meet the LCO indefinitely.

D.

With one Unit DC board or one Unit 1 and 2 Shutdown Board DC Distribution Panel inoperable, the remaining boards are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The overall reliability is reduced, however, because a single failure in the remaining boards could result in the minimum required ESF functions not being supported. Therefore, the required Unit DC board or Unit 1 and 2 Shutdown Board DC Distribution Panel must be restored to OPERABLE status within 7 days by powering it from the associated battery or charger. This condition also bounds the inoperability of 250 V RMOV boards 1A, 1B, or 1C.

(continued)

BFN-UNIT 1 B 3.8-95 Revision 07 33 August 4, 2005

Distribution Systems - Operating B 3.8.7 BASES ACTIONS D..1 (continued)

Condition D represents one Unit DC board or one Unit 1 and 2 Shutdown Board DC Distribution Panel without adequate DC power, potentially with both the battery significantly degraded and the associated charger nonfunctioning. In this situation the plant is significantly more vulnerable to a partial loss of DC power. However, the three Unit DC boards have ESF loads for the three BFN units distributed among them so that redundant subsystems on each unit have separate normal and alternate power supplies. The 7 day Completion Time is partially based on this and reflects a reasonable time to assess unit status as a function of the inoperable Unit DC board or Unit 1 and 2 Shutdown Board DC Distribution Panel and, if not restored to OPERABLE status, to prepare to effect an orderly and safe shutdown.

The second Completion Time for Required Action D. 1 establishes a limit on the maximum time allowed for any combination of required distribution subsystems to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition D is entered while, for instance, a

• 4.16 kV shutdown board is inoperable and subsequently restored OPERABLE, the LCO may already have been not met for up to 5 days. This situation could lead to a total duration of 12 days, since initial failure of the LCO, to restore the Unit DC board or the Shutdown Board DC Distribution Panel. At this time, a 4.16 kV shutdown board could again become inoperable, and the Unit DC board or the Shutdown Board DC Distribution Panel could be restored OPERABLE. This could continue indefinitely.

(continued)

BFN-UNIT 1 B 3.8-96 Revision 6 33 August 4, 2005

Distribution Systems - Operating B 3.8.7 BASES ACTIONS D.1 (continued)

This Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This allowance results in establishing the "time zero" at the time the LCO was initially not met, instead of at the time Condition D was entered. The 12 day Completion Time is an acceptable limitation on this potential of failing to meet the LCO indefinitely.

E._1 With one division of 4.16 kV shutdown boards inoperable, the remaining division of shutdown boards is capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition assuming no single failure. The overall reliability is reduced because a single failure in the remaining 4.16 kV shutdown boards could result in the minimum required ESF functions not being supported.

Therefore, one of the inoperable 4.16 kV shutdown boards must be restored to OPERABLE status within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

The Condition E postulated worst case scenario is one division of 4.16 kV shutdown board without AC power (i.e., no offsite power to the division and the associated DGs inoperable). In this condition, the unit is more vulnerable to a complete loss of AC power. It is, therefore, imperative that the unit operators' attention be focused on minimizing the potential for loss of power to the remaining division by stabilizing the unit, and on restoring power to the affected division. The 8 hour9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> time period before requiring a unit shutdown is acceptable because:

(continued)

BFN-UNIT 1 B 3.8-97 Revision +, 33 August 4, 2005

Distribution Systems - Operating B 3.8.7 BASES ACTIONS E.1 (continued)

a. There is a potential for decreased safety if the unit operator's attention is diverted from the evaluations and actions necessary to restore power to the affected division to the actions associated with taking the unit to shutdown within this time limit.

b. The potential for an event in conjunction with a single failure of a redundant component in the division with AC power is minimal. (The redundant component is verified OPERABLE in accordance with Specification 5.5.11, "Safety Function Determination Program (SFDP).")

The second Completion Time (12 days) for Required Action E.1 establishes a limit on the maximum time allowed for any combination of required distribution subsystems to be inoperable in any single contiguous occurrence of failing to meet the LCO. If Condition E is entered while, for instance, a 480 V DG auxiliary board is inoperable and subsequently restored OPERABLE, the LCO may already have been not met for up to 5 days. This situation could lead to a total duration of 5 days and 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, since initial failure of the LCO, to restore the 480 V shutdown board. At this time, a 480 V DG auxiliary board could again become inoperable, and a 4.16 kV shutdown board could be restored OPERABLE. This could continue indefinitely.

This Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."

This allowance results in establishing the "time zero" at the time the LCO was initially not met, instead of at the time Condition E was entered. The 12 day Completion Time is an acceptable limitation on this potential of failing to meet the LCO indefinitely.

(continued)

BFN-UNIT 1 B 3.8-98 Revision 6, 33 August 4, 2005

Distribution Systems - Operating B 3.8.7 BASES ACTIONS E._1 (continued)

Pursuant to LCO 3.0.6, the Distribution System Actions B, C, or F would not be entered even if the 4.16 kV shutdown boards were inoperable, resulting in de-energization of a 480 V board.

Therefore, the Required Actions of Condition E are modified by a Note to indicate that when Condition E is entered with no AC source to the 4.16 kV shutdown boards, Actions B, C, or F must be immediately entered. This allows Condition E to provide requirement for the loss of the 4.16 kV shutdown boards without regard to whether 480 V board- is de-energized. Actions B, C, or F provide the appropriate restrictions for a de-energized I 480 V board.

F.1 Required Action F. 1 is intended to provide assurance that a I loss of one or more required Unit 2 or 3 AC or DC boards does not result in a complete loss of safety function of critical systems (i.e., SGT or CREVS). With one or more of the required boards inoperable, the SGT or CREVS train supported by each affected board is inoperable. Therefore, the associated SGT or CREVS subsystem must be declared inoperable immediately, and the ACTIONS in the appropriate system Specification taken.

(continued)

BFN-UNIT 1 B 3.8-99 Revision 0 33 August 4, 2005

Distribution Systems - Operating B 3.8.7 BASES ACTIONS G.,1 and G.2 (continued)

If the inoperable distribution subsystem cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the 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 /> and to 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 required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

H.i1 Condition H corresponds to a level of degradation in the electrical distribution system that causes a required safety function to be lost. When more than one AC or DC electrical power distribution subsystem is lost, and this results in the loss of a required function, the plant is in a condition outside the accident analysis. Therefore, no additional time is justified for continued operation. LCO 3.0.3 must be entered immediately to commence a controlled shutdown.

SURVEILLANCE SR 3.8.7.1 REQUIREMENTS This Surveillance verifies that the AC and DC electrical power distribution subsystem is functioning properly, with the buses energized. The verification of proper voltage availability on the buses ensures that the required power is readily available for motive as well as control functions for critical system loads connected to these buses. The 7 day Frequency takes into account the redundant capability of the electrical power distribution subsystems, as well as other indications available in the control room that alert the operator to subsystem malfunctions.

(continued)

BFN-UNIT 1 B 3.8-100 Revision , 33 August 4, 2005

Distribution Systems - Operating B 3.8.7 Table B 3.8.7-1 (page 1 of 1)

AC and DC Electrical Power Distribution Systems TYPE VOLTAGE ELECTRICAL POWER DISTRIBUTION SUBSYSTEMS AC safety 4160 V Shutdown Board A boards Shutdown Board B Shutdown Board C Shutdown Board D Shutdown Board 3EB or 3EC Shutdown Board 3ED 480 V Shutdown Board 1A Shutdown Board 1B Shutdown Board 3B RMOV Board 1A RMOV Board 1B SGT Board Diesel Auxiliary Board A Diesel Auxiliary Board B DC boards 250 V Unit DC Board 1 Unit DC Board 2 Unit DC Board 3 250 V DC RMOV Board lA 250 V DC RMOV Board 1 B 250 V DC RMOV Board 1BC Shutdown Board DC Distribution Panel A Shutdown Board DC Distribution Panel B Shutdown Board DC Distribution Panel C Shutdown Board DC Distribution Panel D Shutdown Board DC Distribution Panel 3EB BFN-UNIT 1 B 3.8-102 Revision e 33 August 4, 2005

Control Rod Scram Times B 3.1.4 BASES SURVEILLANCE SR 3.1.4.2 REQUIREMENTS (continued) Additional testing of a sample of control rods is required to verify the continued performance of the scram function during the cycle. A representative sample contains at least 10% of the control rods. This sample remains representative if no more than 7.5% of the control rods in the sample tested are determined to be "slow." With more than 7.5% of the sample declared to be "slow" per the criteria in Table 3.1.4-1, additional control rods are tested until this 7.5% criterion (i.e., 7.5% of the I entire sample) is satisfied, or until the total number of "slow" control rods (throughout the core from all Surveillances) exceeds the LCO limit. For planned testing, the control rods selected for the sample should be different for each test. Data from inadvertent scrams should be used whenever possible to avoid unnecessary testing at power, even if the control rods with data may have been previously tested in a sample. The 120 day Frequency is based on operating experience that has shown control rod scram times do not significantly change over an operating cycle. This Frequency is also reasonable based on the additional Surveillances done on the CRDs at more frequent intervals in accordance with LCO 3.1.3 and LCO 3.1.5, "Control Rod Scram Accumulators."

(continued)

BFN-UNIT 2 B 3.1-31 RevisionG,9, 35 Amebndment N. 26 February 14, 2006

Secondary Containment Isolation Instrumentation B 3.3.6.2 B 3.3 INSTRUMENTATION B 3.3.6.2 Secondary Containment Isolation Instrumentation BASES BACKGROUND The secondary containment isolation instrumentation automatically initiates closure of appropriate secondary containment isolation valves (SCIVs) and starts the Standby Gas Treatment (SGT) System. The function of these systems, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) (Ref. 1). Secondary containment isolation and establishment of vacuum with the SGT System within the assumed time limits ensures that fission products that leak from primary containment following a DBA, or are released outside primary containment, or are released during certain operations when primary containment is not required to be OPERABLE are maintained within applicable limits.

The isolation instrumentation includes the sensors, relays, and switches that are necessary to cause initiation of secondary containment isolation. Most channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a secondary containment isolation signal to the isolation logic. Functional diversity is provided by monitoring a wide range of independent parameters. The input parameters to the isolation logic are (1) reactor vessel water level, (2) drywell pressure, (3) reactor zone exhaust high radiation, and (4) refueling floor high radiation. Redundant sensor input I signals from each parameter are provided for initiation of isolation. The refueling floor exhaust radiation monitors referred to in Table 3.3.6.2-1 are the same instruments called refueling floor radiation monitors in the Bases discussion.

(continued)

BFN-UNIT 2 B 3.3-226 Revision Q-,35 February 14, 2006

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE 2, Drywell Pressure - High (PIS-64-56A-D) (continued)

SAFETY ANALYSES, LCO, and The Allowable Value was chosen to be the same as the ECCS APPLICABILITY Drywell Pressure - High Function Allowable Value (LCO 3.3.5.1) since this is indicative of a loss of coolant accident (LOCA).

The Drywell Pressure - High Function is required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists in the RCS; thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas.

This Function is not required in MODES 4 and 5 because the probability and consequences of these events are low due to the RCS pressure and temperature limitations of these MODES.

3. 4. Reactor Zone Exhaust and Refueling Floor Radiation -

High (RM-90-140, 141, 142, 143)

High secondary containment exhaust radiation is an indication

.of possible gross failure of the fuel cladding. The release may have originated from the primary containment due to a break in the RCPB. When Exhaust Radiation - High is detected, secondary containment isolation and actuation of the SGT System are initiated to limit the release of fission products as assumed in the FSAR safety analyses (Ref. 4).

The Exhaust Radiation - High signals are initiated from radiation detectors located on the reactor zone ventilation exhaust and the common refueling zone. There are two radiation monitors and two divisional trip systems for each unit (Units 1, 2, and 3). Each monitor has one channel of Reactor Zone Exhaust Radiation - High and one channel of Refueling Floor Radiation - High. Each monitor's channels provide signals to its associated divisional trip system. Each channel has two radiation elements which monitor the (continued)

BFN-UNIT 2 B 3.3-231 Revision 0-,2-35 February 14, 2006

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE 3. 4. Reactor Zone Exhaust and Refueling Floor Radiation -

SAFETY ANALYSES, Hig (RM-90-140, 141, 142, 143) (continued)

LCO, and APPLICABILITY ventilation exhaust both of which must be OPERABLE or tripped for the channel to be OPERABLE. Both radiation elements must provide a High signal to trip the associated channel (two-out-of-two). However, the output relays from the divisional trip systems are arranged in logic systems such that if either channel for a zone trips, a secondary containment isolation signal is initiated (one-out-of-two). Six channels of Reactor Zone Exhaust Radiation - High Function and six channels of Refueling Floor Radiation - High Function are available (two channels of each Function from each unit) and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Values are chosen to provide timely detection of nuclear system process barrier leaks inside containment but are far enough above background levels to avoid spurious isolation.

The Reactor Zone Exhaust and Refueling Floor Radiation -

High Functions are required to be OPERABLE in MODES 1, 2, I

and 3 where considerable energy exists; thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas. In MODES 4 and 5, the probability and consequences of these events are low due to the RCS pressure and temperature limitations of these MODES; thus, these Functions are not required. In addition, the Functions are also required to be OPERABLE during OPDRVs because the capability of detecting radiation releases due to fuel failures (due to fuel uncovery) must be provided to ensure that offsite dose limits are not exceeded.

(continued)

BFN-UNIT 2 B 3.3-232 Revision 0,2-4-, m'9-, 35 February 14, 2006

CREV System Instrumentation B 3.3.7.1 B 3.3 INSTRUMENTATION B 3.3.7.1 Control Room Emergency Ventilation (CREV) System Instrumentation BASES BACKGROUND The CREV System is designed to provide a radiologically controlled environment to ensure the habitability of the control room for the safety of control room operators under all plant conditions. Two independent CREV subsystems are each capable of fulfilling the stated safety function. The instrumentation and controls for the CREV System automatically initiate action to pressurize the control room (CR) to minimize the consequences of radioactive material in the control room environment.

In the event of a Reactor Vessel Water Level - Low, Level 3, Drywell Pressure - High, Reactor Zone Exhaust Radiation -

High, Refueling Floor Radiation - High, or Control Room Air Supply Duct Radiation - High signal, the CREV System is automatically started in the pressurization mode. The air is then recirculated through the charcoal filter, and sufficient outside air is drawn in through the normal intake to maintain the CR slightly pressurized.

The CREV System instrumentation has two control logic systems, which can initiate their associated CREV subsystem (only the selected subsystem will be initiated) (Ref. 1). Each control logic system receives input from each of the Functions listed above. The Functions are arranged as follows for each control logic system. The Reactor Vessel Water Level - Low, Level 3 and Drywell Pressure - High are each arranged in a one-out-of-two taken twice logic (these signals are the same that isolate the primary containment and additional information (continued)

BFN-UNIT 2 B 3.3-240 Revision e-,-35 February 14, 2006

CREV System Instrumentation B 3.3.7.1 BASES BACKGROUND on the arrangement of these channels in the PClS trip systems (continued) can be found in the Bases for LCO 3.3.6.1, "Primary Containment Isolation Instrumentation," Function 2). The Reactor Zone Exhaust Radiation - High and Refueling Floor Radiation - High are each arranged in a one-out-of-two logic I (these signals are the same that isolate the secondary containment and additional information on the arrangement of these channels in the divisional trip systems can be -found in the Bases for LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation," Functions 3 and 4). The control Room Air Supply Duct Radiation - High Function contains two radiation monitors (one per trip system). The refueling floor exhaust radiation monitors referred to in Table 3.3.7.1-1 are the same instruments called refueling floor radiation monitors in the Bases discussion.

The output relays from the trip systems are arranged in the control logic systems in a one-out-of-two logic. Some of the channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a CREV System initiation signal to the initiation logic.

APPLICABLE The ability of the CREV System to maintain the habitability of SAFETY ANALYSES, the CR is explicitly assumed for certain accidents as discussed LCO, and in the FSAR safety analyses (Ref. 2). CREV System operation APPLICABILITY ensures that the radiation exposure of control room personnel, through the duration of any one of the postulated accidents, does not exceed the limits set by GDC 19 of 10 CFR 50, Appendix A.

CREV System instrumentation satisfies Criterion 3 of the NRC Policy Statement (Ref. 5).

(continued)

BFN-UNIT 2 B 3.3-241 Revision &9-,35 February 14, 2006

CREV System Instrumentation B 3.3.7.1 BASES APPLICABLE 3., 4. Reactor Zone Exhaust and Refueling Floor SAFETY ANALYSES, Radiation - High (RM-90-140, 141, 142, 143)

LCO, and APPLICABILITY High secondary containment exhaust radiation is an indication (continued) of possible gross failure of the fuel cladding. The release may have originated from the primary containment due to a break in the RCPB. A reactor zone or refueling floor exhaust high radiation signal will automatically initiate the CREV System, since this radiation release could result in radiation exposure to control room personnel.

The reactor zone and refueling floor exhaust radiation monitors provide two independent channels for each ventilation exhaust path coming from the reactor zones and the refueling zone.

There are two radiation monitors (each monitor provides one channel of each Function) and two divisional trip systems for each unit (Units 1, 2, and 3). Six channels of each function are available (two channels of each Function from each unit) and are required to be OPERABLE to ensure that no single instrument failure can preclude CREV System initiation. The Allowable Value was selected to ensure that the Function will promptly detect high activity that could threaten exposure to control room personnel.

The Reactor Zone Exhaust and Refueling Floor Radiation - I High Functions are required to be OPERABLE in MODES 1, 2, and 3 and during operations with a potential for draining the reactor vessel (OPDRVs), to ensure that control room personnel are protected during a LOCA or vessel draindown event. During MODES 4 and 5, when these specified conditions are not in progress (e.g., OPDRVs), the probability of a LOCA or fuel damage is low; thus, the Function is not required.

(continued)

BFN-UNIT 2 B 3.3-245 Revision 29, 35 February 14, 2006

Distribution Systems - Operating B 3.8.7 BASES (continued)

ACTIONS A._1 With one Unit 1 and 2 4.16 kV shutdown board inoperable, the remaining Unit 1 and 2 4.16 kV shutdown boards are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition. The overall reliability is reduced, I however, because another single failure in the remaining three 4.16 kV shutdown boards could result in the minimum required ESF functions not being supported. Therefore, the 4.16 kV shutdown board must be restored to OPERABLE status within 5 days.

The 5 day time limit before requiring a unit shutdown in this Condition is acceptable because the remaining 4.16 kV shutdown boards have AC power available, and the probability of an event in conjunction with a single failure of a redundant component in the 4.16 kV shutdown board with AC power is low. (The redundant component is verified OPERABLE in accordance with Specification 5.5.11, "Safety Function Determination Program (SFDP).")

(continued)

BFN-UNIT 2 B 3.8-89 Revision-er 36 June 22, 2006

Control Rod Scram Times B 3.1.4 BASES SURVEILLANCE SR 3.1.4.2 REQUIREMENTS (continued) Additional testing of a sample of control rods is required to verify the continued performance of the scram function during the cycle. A representative sample contains at least 10% of the control rods. This sample remains representative if no more than 7.5% of the control rods in the sample tested are determined to be "slow." With more than 7.5% of the sample declared to be "slow" per the criteria in Table 3.1.4-1, additional control rods are tested until this 7.5% criterion (i.e., 7.5% of the I entire sample) is satisfied, or until the total number of "slow" control rods (throughout the core from all Surveillances) exceeds the LCO limit. For planned testing, the control rods selected for the sample should be different for each test. Data from inadvertent scrams should be used whenever possible to avoid unnecessary testing at power, even if the control rods with data may have been previously tested in a sample. The 120 day Frequency is based on operating experience that has shown control rod scram times do not significantly change over an operating cycle. This Frequency is also reasonable based on the additional Surveillances done on the CRDs at more frequent intervals in accordance with LCO 3.1.3 and LCO 3.1.5, "Control Rod Scram Accumulators."

(continued)

BFN-UNIT 3 B 3.1-31 Revision-GQ,-9 35 AmFedraryt No. 226 February 14, 2006

Secondary Containment Isolation Instrumentation B 3.3.6.2 B 3.3 INSTRUMENTATION B 3.3.6.2 Secondary Containment Isolation Instrumentation BASES BACKGROUND The secondary containment isolation instrumentation automatically initiates closure of appropriate secondary containment isolation valves (SCIVs) and starts the Standby Gas Treatment (SGT) System. The function of these systems, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) (Ref. 1). Secondary containment isolation and establishment of vacuum with the SGT System within the assumed time limits ensures that fission products that leak from primary containment following a DBA, or are released outside primary containment, or are released during certain operations when primary containment is not required to be OPERABLE are maintained within applicable limits.

The isolation instrumentation includes the sensors, relays, and switches that are necessary to cause initiation of secondary containment isolation. Most channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a secondary containment isolation signal to the isolation logic. Functional diversity is provided by monitoring a wide range of independent parameters. The input parameters to the isolation logic are (1) reactor vessel water level, (2) drywell pressure, (3) reactor zone exhaust high radiation, and (4) refueling floor high radiation. Redundant sensor input I signals from each parameter are provided for initiation of isolation. The refueling floor exhaust radiation monitors referred to in Table 3.3.6.2-1 are the same instruments called refueling floor radiation monitors in the Bases discussion.

fcontinued)

BFN-UNIT 3 B 3.3-226 Revision 35 Ameldmcn N, .2-1 lt February 14, 2006

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE 2. Drywell Pressure - High (PIS-64-56A-D) (continued)

SAFETY ANALYSES, LCO, and The Allowable Value was chosen to be the same as the ECCS APPLICABILITY Drywell Pressure - High Function Allowable Value (LCO 3.3.5.1) since this is indicative of a loss of coolant accident (LOCA).

The Drywell Pressure - High Function is required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists in the RCS; thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas.

This Function is not required in MODES 4 and 5 because the probability and consequences of these events are low due to the RCS pressure and temperature limitations of these MODES.

3, 4. Reactor Zone Exhaust and Refueling Floor Radiation -

Higq (RM-90-140, 141, 142, 143)

High secondary containment exhaust radiation is an indication of possible gross failure of the fuel cladding. The release may have originated from the primary containment due to a break in the RCPB. When Exhaust Radiation - High is detected, secondary containment isolation and actuation of the SGT System are initiated to limit the release of fission products as assumed in the FSAR safety analyses (Ref. 4).

The Exhaust Radiation - High signals are initiated from radiation detectors located on the reactor zone ventilation exhaust and the common refueling zone. There are two radiation monitors and two divisional trip systems for each unit (Units 1, 2, and 3). Each monitor has one channel of Reactor Zone Exhaust Radiation - High and one channel of Refueling Floor Radiation - High. Each monitor's channels provide signals to its associated divisional trip system. Each channel has two radiation elements which monitor the (continued)

BFN-UNIT 3 B 3.3-231 Revision 29-,35 Amcndment No. 21ý3 February 14, 2006

Secondary Containment Isolation Instrumentation B 3.3.6.2 BASES APPLICABLE 3, 4. Reactor Zone Exhaust and Refuelinq Floor Radiation -

SAFETY ANALYSES, Hign (RM-90-140, 141,142, 143) (continued)

LCO, and APPLICABILITY ventilation exhaust both of which must be OPERABLE or tripped for the channel to be OPERABLE. Both radiation elements must provide a High signal to trip the associated channel (two-out-of-two). However, the output relays from the divisional trip systems are arranged in logic systems such that if either channel for a zone trips, a secondary containment isolation signal is initiated (one-out-of-two). Six channels of Reactor Zone Exhaust Radiation. - High Function and six channels of Refueling Floor Radiation - High Function are available (two channels of each Function from each unit) and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Values are chosen to provide timely detection of nuclear system process barrier leaks inside containment but are far enough above background levels to avoid spurious isolation.

The Reactor Zone Exhaust and Refueling Floor Radiation - I High Functions are required to be OPERABLE in MODES 1, 2, and 3 where considerable energy exists; thus, there is a probability of pipe breaks resulting in significant releases of radioactive steam and gas. In MODES 4 and 5, the probability and consequences of these events are low due to the RCS pressure and temperature limitations of these MODES; thus, these Functions are not required. In addition, the Functions are also required to be OPERABLE during OPDRVs because the capability of detecting radiation releases due to fuel failures (due to fuel uncovery) must be provided to ensure that offsite dose limits are not exceeded.

(continued)

BFN-UNIT 3 B 3.3-232 Revision 24-129,-35 Amendment No. 213 February 14, 2006

CREV System Instrumentation B 3.3.7.1 B 3.3 INSTRUMENTATION B 3.3.7.1 Control Room Emergency Ventilation (CREV) System Instrumentation BASES BACKGROUND The CREV System is designed to provide a radiologically controlled environment to ensure the habitability of the control room for the safety of control room operators under all plant conditions. Two independent CREV subsystems are each capable of fulfilling the stated safety function. The instrumentation and controls for the.CREV System automatically initiate action to pressurize the control room (CR) to minimize the consequences of radioactive material in the control room environment.

In the event of a Reactor Vessel Water Level - Low, Level 3, Drywell Pressure - High, Reactor Zone Exhaust Radiation -

High, Refueling Floor Radiation - High, or Control Room Air I Supply Duct Radiation - High signal, the CREV System is automatically started in the pressurization mode. The air is then recirculated through the charcoal filter, and sufficient outside air is drawn in through the normal intake to maintain the CR slightly pressurized.

The CREV System instrumentation has two control logic systems, which can initiate their associated CREV subsystem (only the selected subsystem will be initiated) (Ref. 1). Each control logic system receives input from each of the Functions listed above. The Functions are arranged as follows for each control logic system. The Reactor Vessel Water Level - Low, Level 3 and Drywell Pressure - High are each arranged in a one-out-of-two taken twice logic (these signals are the same that isolate the primary containment and additional information (continued)

BFN-UNIT 3 B 3.3-240 Revision 35 Afn-IIndIcI t Pie. 2+13 February 14, 2006

CREV System Instrumentation B 3.3.7.1 BASES BACKGROUND on the arrangement of these channels in the PCIS trip systems (continued) can be found in the Bases for LCO 3.3.6.1, "Primary Containment Isolation Instrumentation," Function 2). The Reactor Zone Exhaust Radiation - High and Refueling Floor Radiation - High are each arranged in a one-out-of-two logic (these signals are the same that isolate the secondary containment and additional information on the arrangement of these channels in the divisional trip systems can be found in the Bases for LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation," Functions 3 and 4). The control Room Air Supply Duct Radiation - High Function contains two radiation monitors (one per trip system). The refueling floor exhaust radiation monitors referred to in Table 3.3.7.1-1 are the same instruments called refueling floor radiation monitors in the Bases discussion.

The output relays from the trip systems are arranged in the control logic systems in a one-out-of-two logic. Some of the channels include electronic equipment (e.g., trip units) that compares measured input signals with pre-established setpoints. When the setpoint is exceeded, the channel output relay actuates, which then outputs a CREV System initiation signal to the initiation logic.

APPLICABLE The ability of the CREV System to maintain the habitability of SAFETY ANALYSES, the CR is explicitly assumed for certain accidents as discussed LCO, and in the FSAR safety analyses (Ref. 2). CREV System operation APPLICABILITY ensures that the radiation exposure of control room personnel, through the duration of any one of the postulated accidents, does not exceed the limits set by GDC 19 of 10 CFR 50, Appendix A.

CREV System instrumentation satisfies Criterion 3 of the NRC Policy Statement (Ref. 5).

(continued)

BFN-UNIT 3 B 3.3-241 Revision 35 Arm--fc.m, rt N.. 21a February 14, 2006

CREV System Instrumentation B 3.3.7.1 BASES APPLICABLE 3., 4. Reactor Zone Exhaust and Refuelinq Floor SAFETY ANALYSES, Radiation - High (RM-90-140, 141, 142, 143)

LCO, and APPLICABILITY High secondary containment exhaust radiation is an indication (continued) of possible gross failure of the fuel cladding. The release may have originated from the primary containment due to a break in the RCPB. A reactor zone or refueling floor exhaust high radiation signal will automatically initiate the CREV System, since this radiation release could result in radiation exposure to control room personnel.

The reactor zone and refueling floor exhaust radiation monitors provide two independent channels for each ventilation exhaust path coming from the reactor zones and the refueling zone.

There are two radiation monitors (each monitor provides one channel of each Function) and two divisional trip systems for each unit (Units 1, 2, and 3). Six channels of each function are available (two channels of each Function from each unit) and are required to be OPERABLE to ensure that no single instrument failure can preclude CREV System initiation. The Allowable Value was selected to ensure that the Function will promptly detect high activity that could threaten exposure to control room personnel.

The Reactor Zone Exhaust and Refueling Floor Radiation - I High Functions are required to be OPERABLE in MODES 1, 2, and 3 and during operations with a potential for draining the reactor vessel (OPDRVs), to ensure that control room personnel are protected during a LOCA or vessel draindown event. During MODES 4 and 5, when these specified conditions are not in progress (e.g., OPDRVs), the probability of a LOCA or fuel damage is low; thus, the Function is not required.

(continued)

BFN-UNIT 3 B 3.3-245 Revision 9,-35 A,,.,*,.mnt N*. 213 February 14, 2006

RCS P/T Limits B 3.4.9 BASES SURVEILLANCE SR 3.4.9.5 SR 3.4.9.6, and SR- 3.4.9.7 (continued)

REQUIREMENTS Surveillance to be initiated 30 minutes after RCS temperature

_ 85 0F in MODE 4. SR 3.4.9.7 is modified by a Note that requires the Surveillance to be initiated 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> after RCS temperature _<1000 F in MODE 4. The Notes contained in these SRs are necessary to specify when the reactor vessel flange and head flange temperatures are required to be verified

> 83 0F.

REFERENCES 1. 10 CFR 50, Appendix G.

2. ASME, Boiler and Pressure Vessel Code,Section III, Appendix G.

3. ASTM E 185-82, July 1982.

4. 10 CFR 50, Appendix H.

5. Regulatory Guide 1.99, Revision 2, May 1988.

6. ASME, Boiler and Pressure Vessel Code,Section XI, Appendix E.

7. NEDO-21778-A, December 1978.

8. FSAR, Section 14.5.6.2..

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

10. GE Nuclear Energy, NEDC-32983P, "General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluation (TAC No. MA9891)".

11. Regulatory Guide 1.190, "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence".

(continued)

BFN-UNIT 3 B 3.4-66 Revision-.-,-.&, 36 June 22, 2006

Distribution Systems - Operating B 3.8.7 BASES (continued)

ACTIONS A..1 With one Unit 3 4.16 kV shutdown board inoperable, the remaining Unit 3 4.16 kV shutdown boards are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition. The overall reliability is reduced, however, I because another single failure in the remaining three 4.16 kV shutdown boards could result in the minimum required ESF functions not being supported. Therefore, the 4.16 kV shutdown board must be restored to OPERABLE status within 5 days.

The 5 day time limit before requiring a unit shutdown in this Condition is acceptable because the remaining 4.16 kV shutdown boards have AC power available, and the probability of an event in conjunction with a single failure of a redundant component in the 4.16 kV shutdown board with AC power is low. (The redundant component is verified OPERABLE in accordance with Specification 5.5.11, "Safety Function Determination Program (SFDP).")

(continued)

BFN-UNIT 3 B 3.8-90 Revisiorn-O, 36 June 22, 2006

ENCLOSURE 4 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)

UNITS 1, 2, AND 3 TECHNICAL REQUIREMENTS MANUAL CHANGES AND ADDITIONS

Seismic Monitoring Instrumentation TR 3.3.8 Table 3.3.8-1 Seismic Monitoring Instrumentation Technical Required Measurement Surveillance Allowable Function UNID Channels Range - RequirementsMs) Value TRIAXIAL TIME HISTORY ACCELEROGRAPtIS:

U-1 reactor bldg. Base slab 1 0-1.0g TSR 3.3.8.1 .01g BFN-0-ACGR-052-0005 TSR 3.3.8.2 (El. 519.0) TSR 3.3.8.3 U-1 reactor bldg. floor slab 1 0-1 .0g TSR 3.3.8.1 .01g BFN-0-ACGR-052-0004 TSR 3.3.8.2 (El. 621.25) TSR 3.3.8.3 Diesel-gen. Bldg. Base slab 0-1.0g TSR 3.3.8.1 .01g BFN-0-ACGR-052-0006 TSR 3.3.8.2 (El. 565.5) TSR 3.3.8.3 TRIAXIL* PEAK ACCELEROGRAPHS:

U-1 RBCCW, 10" pipe 0-5.0g TSR 3.3.8.3 NA BFN-O-ACGR-052-0007 (El. 625.75)

U-1 RHRSW, 16" pipe 0-5.0g TSR 3.3.8.3 NA BFN-0-ACGR-052-0008 (El. 580.0)

U-1 core spray system, 0-5.0g TSR 3.3.8.3 NA 14" pipe BFN-0-ACGR-052-0009 (El. 544.0)

BIAXIAL SEISMIC SWITCHES:

U-1 reactor bldg. Base slab I(b) .025-.25g TSR 3.3.8.1 0.1g BFN-0-ACCL-052-0001 TSR 3.3.8.2 (El. 519.0) North Monitor TSR 3.3.8.3 U-1 reactor bldg. Base slab 1 (b) .025-.25g TSR 3.3.8.1 0.1g BFN-0-ACCL-052-0002 TSR 3.3.8.2 (El. 519.0) Middle Monitor TSR 3.3.8.3 U-1 reactor bldg. Base slab 1 (b) .025-.25g TSR 3.3.8.1 0.1g BFN-0-ACCL-052-0003 TSR 3.3.8.2 (El. 519.0) South Monitor TSR 3.3.8.3 (a) TSR 3.3.8.4 applies to all seismic monitoring instrumentation.

(b) With control room indication.

BFN-UNIT 1 3.3-53 TRM Revision e, 53 October 21, 2005

Seismic Monitoring Instrumentation TR 3.3.8 Table 3.3.8-1 Seismic Monitoring Instrumentation Technical.

Required Measurement Surveillance Allowable Function UNID Channels Range Requirements(a) Value TRIAXIAL TIME HISTORY ACCELERO-GRAPHS:

U-1 reactor bldg. Base slab 0-1.0g TSR 3.3.8.1 .01g BFN-0-ACGR-052-0005 TSR 3.3.8.2 (El. 519.0) TSR 3.3.8.3 U-1 reactor bldg. floor slab 0-1.0g TSR 3.3.8.1 .01g BFN-0-ACGR-052-0004 TSR 3.38.2 (El. 621.25) TSR 3.3.8.3 Diesel-gen. Bldg. Base slab 0-1.0g TSR 3.3.8.1 .01g BFN-0-ACGR-052-0006 TSR 3.3.8.2 (El. 565.5) TSR 3.3.8.3 ACCELEROGRAPHS:

U-1 RBCCW, 10" pipe 0-5.Og TSR 3.3.8.3 NA BFN-0-ACGR-052-0007 (El. 625.75)

U-1 RHRSW, 16" pipe 0-5.0g TSR 3.3.8.3 NA BFN-0-ACGR-052-0008 (El. 580.0)

U-1 core spray system, 0-5.Og TSR 3.3.8.3 NA 14" pipe BFN-0-ACGR-052-0009 (El. 544.0)

BIAXIAL SEISMIC SWITCHES:

U-1 reactor bldg. Base slab l(b) .025-259 TSR 3.3.8.1 0.1g BFN-0-ACCL-052-0001 TSR 3.3.8.2 (El. 519.0) North Monitor TSR 3.3.8.3 U-1 reactor bldg. Base slab 1 (b) .025-.25g TSR 3.3.8.1 0.1g BFN-0-ACCL-052-0002 TSR 3.3.8.2 (El. 519.0) Middle Monitor TSR 3.3.8.3 U-1 reactor bldg. Base slab 1 .025-.25g TSR 3,3.8.1 0.1g BFN-O-ACCL-052-0003 TSR 3.3.8.2 (El. 519.0) South Monitor TSR 3.3.8.3 (a) TSR 3.3.8.4 applies to all seismic monitoring instrumentation.

(b) With control room indication.

BFN-UNIT 2 3.3-54 TRM Revision e, 53 October 21,2005

Hydrogen Monitoring Instrumentation TR 3.3.11 TR 3.3 INSTRUMENTATION TR 3.3.11 Hydrogen Monitoring Instrumentation LCO 3.3.11 One drywell and suppression chamber hydrogen analyzer shall be OPERABLE APPLICABILITY: MODE 1 during the time period

a. From 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after THERMAL POWER is > 15% RTP following startup, to

b. 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to reducing THERMAL POWER to < 15% RTP prior to the next scheduled reactor shutdown.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. No drywell hydrogen A. 1 Restore one drywell 7 days analyzer operable, hydrogen analyzer to OPERABLE status.

B. No suppression B.1 Restore suppression 7 days chamber hydrogen chamber hydrogen analyzer operable. analyzer to OPERABLE status.

C. Required Action and C.1 Initiate a Problem 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> associated Completion Evaluation Report Time of Condition A or (PER)/Corrective Actions B not met. Program (CAP) document to develop plans and schedule for restoring the analyzer to OPERABLE status.

BFN-UNIT 2 3.3-61 TRM Revision 48, 53 October 21, 2005

Hydrogen Monitoring Instrumentation B 3.3.11 TR 3.3 INSTRUMENTATION TR 3.3.11 Hydrogen Monitoring Instrumentation BASES BACKGROUND Containment hydrogen monitors are required to diagnose the course of beyond design basis accidents.

APPLICABLE As part of the rulemaking that revised 10 CFR 50.44, NRC SAFETY ANALYSES eliminated the design basis loss-of-coolant accident hydrogen release from 10 CFR 50.44 and consolidated the requirements for hydrogen monitors to 10 CFR 50.44 while relaxing safety classifications and licensee commitments to certain design and qualification criteria. Specifically, the NRC found that the hydrogen monitors no longer meet the definition of Category 1 in Regulatory Guide (RG) 1.97. The NRC concluded that Category 3, as defined in RG 1.97, is an appropriate categorization for the hydrogen monitors because the monitors were only required to diagnose the course of beyond design basis accidents. Hydrogen monitoring is not the primary means of indicating a significant abnormal degradation of the reactor coolant pressure boundary.

Section 4 of Attachment 2 to SECY-00-01 98, "Status Report on Study of Risk-Informed Changes to the Technical Requirements of 10 CFR Part 50 (Option 3) and Recommendations on Risk-Informed Changes to 10 CFR 50.44 (Combustible Gas Control)," (Reference 1) found that the hydrogen monitors were not risk-significant. Therefore, the NRC determined that hydrogen monitoring equipment requirements no longer meet any of the four criteria in 10 CFR 50.36(c)(2)(ii) for retention in Technical Specifications, and, so may be relocated to other licensee-controlled documents. However, because the monitors are required to diagnose the course of beyond design basis accidents, plants were to maintain a hydrogen monitoring system capable of diagnosing beyond design basis accidents. Browns Ferry committed to maintain the hydrogen monitors in the TRM.

(References 2 and 3)

BFN-UNIT 2 B 3.3-61 TRM Revision 48, 53 October 21, 2005

Hydrogen Monitoring Instrumentation B 3.3.11 BASES LCO 3.3.11 The drywell and suppression chamber hydrogen recorders allow the operators to detect trends in hydrogen concentration to diagnose the course of beyond design basis accidents. High hydrogen concentration is measured by two independent analyzers and continuously recorded and displayed on one control room recorder and one control room indicator. The analyzers have the capability for sampling both the drywell and the suppression chamber. LCO 3.3.11 requires that one hydrogen drywell and one hydrogen suppression chamber sample analyzer be OPERABLE.

The operable analyzer may be from either division of the instrumentation.

APPLICABILITY The primary containment hydrogen concentration analyzers are required to be OPERABLE when primary containment is inerted, except as allowed by the relaxations during startup and shutdown addressed below. The primary containment must be inert in MODE 1, since this is the condition with the highest probability of an event that could produce hydrogen.

Inerting the primary containment is an operational problem because it prevents containment access without an appropriate breathing apparatus. Therefore, the primary containment is inerted as late as possible in the plant startup and de-inerted as soon as possible in the plant shutdown. As long as reactor power is

< 15% RTP, the potential for an event that generates significant hydrogen is low and the primary containment need not be inert.

Furthermore, the probability of an event that generates hydrogen occurring within the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of a startup, or within the last 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before a shutdown, is low enough that these "windows,"

when the primary containment is not inerted, are also justified. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time period is a reasonable amount of time to allow plant personnel to perform inerting or de-inerting.

ACTIONS A..1 Seven days to restore the instrument is reasonable given the requirements to be available for use in diagnosing beyond design basis events.

BFN-UNIT 2 B 3.3-62 TRM Revision 48, 53 October 21, 2005

Hydrogen Monitoring Instrumentation B 3.3.11 BASES ACTIONS (continued)

Seven days to restore the instrument is reasonable given the requirements to be available for use in diagnosing beyond design basis events.

If the instrument cannot be made OPERABLE in the allowed time frame, then a Corrective Action Program document must be initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in order to develop a plan and schedule for restoring the instrument to an OPERABLE status.

TECHNICAL TSR 3.3.11.1 SURVEILLANCE REQUIREMENTS Surveillance requirement times are based on equipment reliability and engineering judgment and conservatively set to provide adequate assurance of safety function performance.

REFERENCES 1. SECY-00-0198, "Status Report on Study of Risk-Informed Changes to the Technical Requirements of 10 CFR Part 50

.(Option 3) and Recommendations on Risk-Informed Changes to 10 CFR 50.44 (Combustible Gas Control),

September 14, 2000.

2. Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 -

Technical Specifications (TS) Change 422 - Application for TS Improvement to Eliminate Requirements for Hydrogen Monitors Using the Consolidated Line Item Improvement Process, July 8, 2004.

3. NRC Letter - Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 - Issuance of Amendments Regarding Elimination of Requirements for Hydrogen Monitors Using the Consolidated Line Item Improvement Process (TAC Nos. MC3780, MC3781, and MC3782), February 14, 2005.

BFN-UNIT 2 B 3.3-63 TRM Revision 49, 53 October 21, 2005

Seismic Monitoring Instrumentation TR 3.3.8 Table 3.3.8-1 Seismic Monitoring Instrumentation Technical Required Measurement Surveillance Allowable Function UNID Channels Range Requirements(a) Value TRIAXIAL TIME HISTORY AC CELF ROG RAPH S U-1 reactor bldg. Base slab 1 0-1.0g TSR 3.3.8.1 .01g BFN-0-ACGR-052-0005 TSR 3.3.8.2 (El. 519.0) TSR 3.3.8.3 U-1 reactor bldg. floor slab 1 0-1.0g TSR 3.3.8.1 .01g BFN-0-ACGR-052-0004 TSR 3.3.8.2 (El. 621.25) TSR 3.3.8.3 Diesel-gen. Bldg. Base slab 1 0-1.Og TSR 3.3.8.1 .01g BFN-0-ACGR-052-0006 TSR 3.3.8.2 (El -56 5.5) TSR 3.3-8.3 TI~AXALPEL AQQFCELRG.RAPHS:

U-I RBCCW, 10" pipe 1 0-5.Og TSR 3.3.8.3 NA BFN-0-ACGR-052-0007 (El. 625.75)

U-1 RHRSW, 16" pipe 1 0-5.Og TSR 3.3.8.3 NA BFN-0-ACGR-052-0008 (El. 580.0)

U-1 core spray system, 1 0-5.Og TSR 3.3.8.3 NA 14" pipe BFN-0-ACGR-052-0009 (El. 544.0)

BIAXIAL SEISMIC SWITCHES:

U-1 reactor bldg. Base slab 1(b) .025-.25g TSR 3.3.8.1 0.1g BFN-0-ACCL-052-0001 TSR 3.3.8.2 (El. 519.0) North Monitor TSR 3.3.8.3 U-1 reactor bldg. Base slab I(bj .025-.25g TSR 3.3.8.1 0.1g BFN-O-ACCL-052-0002 TSR 3.3.8.2 (El. 519.0) Middle Monitor TSR 3.3.8.3 U-1 reactor bldg. Base slab 1 (bj .025-.25g TSR 3.3.8.1 0.1g BFN-O-ACCL-052-0003 TSR 3.3.8.2 (El. 519.0) South Monitor TSR 3.3.8.3 (a) TSR 3.3.8.4 applies to all seismic monitoring instrumentation.

(b) With control room indication.

BFN-UNIT 3 3.3-53 TRM Revision e, 53 October 21, 2005

Hydrogen Monitoring Instrumentation TR 3.3.11 TR 3.3 INSTRUMENTATION TR 3.3.11 Hydrogen Monitoring Instrumentation LCO 3.3.11 One drywell and suppression chamber hydrogen analyzer shall be OPERABLE I

APPLICABILITY: MODE 1 during the time period

a. From 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> after THERMAL POWER is > 15% RTP following startup, to

b. 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to reducing THERMAL POWER to < 15% RTP prior to the next scheduled reactor shutdown.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. No drywell hydrogen A 1 Restore one drywell 7 days analyzer operable. hydrogen analyzer to OPERABLE status.

B. No suppression B.1 Restore suppression 7 days chamber hydrogen chamber hydrogen analyzer operable. analyzer to OPERABLE status.

C. Required Action and C. 1 Initiate a Problem 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> associated Completion Evaluation Report Time of Condition A or (PER)/Corrective Actions B not met. Program (CAP) document to develop plans and schedule for restoring the analyzer to OPERABLE status.

BFN-UNIT 3 3.3-60 TRM Revision 48, 53 October 21, 2005

Drywell Control Air System TR 3.6.3 TR 3.6 CONTAINMENT SYSTEMS 4 TR 3.6.3 Drywell Control Air System LCO 3.6.3 The pneumatic control system inside primary containment shall be supplied from the Drywell Control Air system or the Containment Atmosphere Dilution system.

APPLICABILITY: When primary containment inerting is required ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Plant control air is A. 1 Reduce THERMAL 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> being used to supply POWER to _ 15% RTP.

the pneumatic control system inside primary containment.

TECHNICAL SURVEILLANCE REQUIREMENTS J TSR 3.6.3. 1 The plant control air supply valve located Prior to outside primary containment for the completing pneumatic control system inside primary primary containment shall be verified closed, containment inerting during reactor startup AND Every 31 days thereafter BFN-UNIT 3 3.6-5 TRM Revision ,&-55 March 09, 2006

Hydrogen Monitoring Instrumentation B 3.3.11 TR 3.3 INSTRUMENTATION TR 3.3.11 Hydrogen Monitoring Instrumentation BASES BACKGROUND Containment hydrogen monitors are required to diagnose the course of beyond design basis accidents.

APPLICABLE As part of the rulemaking that revised 10 CFR 50.44, NRC SAFETY ANALYSES eliminated the design basis loss-of-coolant accident hydrogen release from 10 CFR 50.44 and consolidated the requirements for hydrogen monitors to 10 CFR 50.44 while relaxing safety classifications and licensee commitments to certain design and qualification criteria. Specifically, the NRC found that the hydrogen monitors no longer meet the definition of Category 1 in Regulatory Guide (RG) 1.97. The NRC concluded that Category 3, as defined in RG 1.97, is an appropriate categorization for the hydrogen monitors because the monitors were only required to diagnose the course of beyond design basis accidents. Hydrogen monitoring is not the primary means of indicating a significant abnormal degradation of the reactor coolant pressure boundary.

Section 4 of Attachment 2 to SECY-00-01 98, "Status Report on Study of Risk-Informed Changes to the Technical Requirements of 10 CFR Part 50 (Option 3) and Recommendations on Risk-Informed Changes to 10 CFR 50.44 (Combustible Gas Control)," (Reference 1) found that the hydrogen monitors were not risk-significant. Therefore, the NRC determined that hydrogen monitoring equipment requirements no longer meet any of the four criteria in 10 CFR 50.36(c)(2)(ii) for retention in Technical Specifications, and, so may be relocated to other licensee-controlled documents. However, because the monitors are required to diagnose the course of beyond design basis accidents, plants were to maintain a hydrogen monitoring system capable of diagnosing beyond design basis accidents. Browns Ferry committed to maintain the hydrogen monitors in the TRM.

(References 2 and 3)

BFN-UNIT 3 B 3.3-62 TRM Revision 48, 53 October 21, 2005

Hydrogen Monitoring Instrumentation B 3.3.11 BASES LCO 3.3.11 The drywell and suppression chamber hydrogen recorders allow the operators to detect trends in hydrogen concentration to diagnose the course of beyond design basis accidents. High hydrogen concentration is measured by two independent analyzers and continuously recorded and displayed on one control room recorder and one control room indicator. The analyzers have the capability for sampling both the drywell and the suppression chamber. LCO 3.3.11 requires that one hydrogen drywell and one hydrogen suppression chamber sample analyzer be OPERABLE.

The operable analyzer may be from either division of the instrumentation.

APPLICABILITY The primary containment hydrogen concentration analyzers are required to be OPERABLE when primary containment is inerted, except as allowed by the relaxations during startup and shutdown addressed below. The primary containment must be inert in MODE 1, since this is the condition with the highest probability of an event that could produce hydrogen.

Inerting the primary containment is an operational problem because it prevents containment access without an appropriate breathing apparatus. Therefore, the primary containment is inerted as late as possible in the plant startup and de-inerted as soon as possible in the plant shutdown. As long as reactor power is

< 15% RTP, the potential for an event that generates significant hydrogen is low and the primary containment need not be inert.

Furthermore, the probability of an event that generates hydrogen occurring within the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of a startup, or within the last 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> before a shutdown, is low enough that these "windows,"

when the primary containment is not inerted, are also justified. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> time period is a reasonable amount of time to allow plant personnel to perform inerting or de-inerting.

ACTIONS A.1 Seven days to restore the instrument is reasonable given the requirements to be available for use in diagnosing beyond design basis events.

BFN-UNIT 3 B.3.3-63 TRM Revision 48, 53 October 21, 2005

Hydrogen Monitoring Instrumentation B 3.3.11 BASES ACTIONS B.1 (continued)

Seven days to restore the instrument is reasonable given the requirements to be available for use in diagnosing beyond design basis events.

C._1 If the instrument cannot be made OPERABLE in the allowed time frame, then a Corrective Action Program document must be initiated within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> in order to develop a plan and schedule for restoring the instrument to an OPERABLE status.

TECHNICAL TSR 3.3.11.1 SURVEILLANCE REQUIREMENTS Surveillance requirement times are based on equipment reliability and engineering judgment and conservatively set to provide adequate assurance of safety function performance.

REFERENCES 1. SECY-00-0198, "Status Report on Study of Risk-Informed Changes to the Technical Requirements of 10 CFR Part 50 (Option 3) and Recommendations on Risk-Informed Changes to 10 CFR 50.44 (Combustible Gas Control),

September 14, 2000.

2. Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 -

Technical Specifications (TS) Change 422 - Application for TS Improvement to Eliminate Requirements for Hydrogen Monitors Using the Consolidated Line Item Improvement Process, July 8, 2004.

3. NRC Letter - Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 - Issuance of Amendments Regarding Elimination of Requirements for Hydrogen Monitors Using the Consolidated Line Item Improvement Process (TAC Nos. MC3780, MC3781, and MC3782), February 14, 2005.

BFN-UNIT 3 B 3.3-64 TRM Revision 48, 53 October 21, 2005

Drywell Control Air System B 3.6.3 TR 3.6 CONTAINMENT SYSTEMS

) TR 3.6.3 Drywell Control Air System BASES BACKGROUND The primary containment is purged with nitrogen to reduce and maintain the containment atmosphere to less than 4 percent oxygen. Maintaining the oxygen content of the primary containment atmosphere at less than 4 percent ensures no combustion of the hydrogen and oxygen, thus assuring containment integrity.

The Drywell Control Air System is supplied dry, oil free, nitrogen from the common Containment Inerting System liquid nitrogen storage tanks located in the yard. This system eliminates the dilution of nitrogen from operation of pneumatic equipment inside the drywell.

Normally, the Drywell Control Air System furnishes control air for the drywell equipment and the plant Control Air System provides control air for the outboard main steam isolation valves. However,

,) provisions, with closed isolation valves and check valves, are made to use the plant Control Air System to supply the drywell control air if the need arises.

Although the Drywell Control Air System is not essential for safe shutdown of the plant, it could be effectively utilized during this operation. Therefore, redundant components and a backup source of control air from the plant Control Air System or nitrogen from the Containment Atmosphere Dilution (CAD) System are provided to increase the reliability of these drywell air systems.

APPLICABLE The primary containment is purged with nitrogen to reduce and SAFETY ANALYSIS maintain the containment atmosphere to less than 4 percent oxygen as required by Technical Specification LCO 3.6.3.2. The use of the Plant Control Air System to supply the pneumatic control system inside primary containment challenges the ability to meet this Limiting Condition for Operation.

.)

BFN-UNIT 3 B 3.6-7 TRM Revision 6 55 March 09, 2006

Drywell Control Air System B 3.6.3 BASES LCO 3.6.3 The Plant Control Air System shall not be used to supply the pneumatic control system inside primary containment during the required APPLICABILITY to preclude dilution of nitrogen and the buildup of pressure from the operation of pneumatic equipment I inside the drywell.

APPLICABILITY The use of the Plant Control Air System to supply the pneumatic control system inside primary containment is not allowed when the primary containment is required to be inert.

ACTIONS A.1 I If Plant Control Air is being used to supply the pneumatic control system inside primary containment when primary containment inerting is required, the reactor THERMAL POWER shall be brought to < 15% RTP in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

TECHNICAL TSR 3.6.3.1 SURVEILLANCE REQUIREMENTS The Plant Control Air supply valve located outside primary containment for the pneumatic control system inside the primary containment shall be verified closed prior to completing containment inerting during reactor startup and monthly thereafter.

REFERENCES 1. BFN Technical Specifications (version prior to standardized version).

2. BFN FSAR Sections 5.2 and 10.14.

7, BFN-UNIT 3 B 3.6-8 TRM Revision 07 55 March 09, 2006

Nitrogen Makeup to Containment B 3.6.5 TR 3.6 CONTAINMENT SYSTEMS I TR 3.6.5 Nitrogen Makeup to Containment BASES BACKGROUND Primary containment nitrogen consumption including Drywell Control Air nitrogen usage shall be monitored to determine the average daily nitrogen consumption for the last 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Excessive leakage is indicated by a nitrogen consumption rate of

> 542 scfh per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (corrected for drywell temperature, pressure, and venting operations) at normal drywell operating pressure of 1.1 psig.

APPLICABLE Establishing the test limit of 542 scfh provides an adequate SAFETY ANALYSES margin of safety to assure the health and safety of the general public. A leakage of > 542 scfh would provide an indication of gross failure of the primary containment pressure boundary which would defeat the design leak-tightness capability of the structure over its service lifetime. Monitoring the integrity of the primary containment during normal operation ensures its capability to I perform its safety function following a design basis accident.

LCO 3.6.5 When the primary containment is inerted the containment shall be continuously monitored for gross leakage by review of the inerting system makeup requirements. Nitrogen makeup to the primary containment plus Drywell Control Air nitrogen usage, averaged over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, shall not exceed 542 scfh.

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BFN-UNIT 3 B 3.6-12 TRM Revision 9, 2,-4, 55 March 09, 2006

Nitrogen Makeup to Containment B 3.6.5 BASES

) APPLICABILITY The requirement for monitoring the containment for gross leakage is only applicable when the primary containment is inerted.

ACTIONS A._1 If nitrogen makeup to the primary containment, averaged over 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, exceeds 542 scfh, then primary containment is inoperable and Technical Specification LCO 3.6.1.1 is entered.

TECHNICAL TSR 3.6.5.1 SURVEILLANCE REQUIREMENTS When the primary containment is inerted, the containment shall be continuously monitored for gross leakage by review of the inerting system makeup requirements and Drywell Control Air System nitrogen usage every 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

This TSR is modified by two Notes. Note 1 allows the monitoring system to be taken out of service for maintenance provided the j monitoring system is returned to service as soon as practical.

Note 2 allows this TSR not to be performed until after primary containment is inerted. This allowance is required to prevent conflicts with TSR 3.0.4 and since the surveillance can not be performed until after containment is inerted.

REFERENCES 1. BFN Technical Specifications (version prior to standardized version)

BFN-UNIT 3 B 3.6-13 TRM Revision (,1-4, 55 March 09, 2006