ML101590108

Technical Specification Change - TS-468 - Responses to Request for Additional Information Regarding Extending Completion Times for Emergency Diesel Generators

ML101590108
Person / Time
Site:	Browns Ferry
Issue date:	05/28/2010
From:	Krich R Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
TAC ME3423, TAC ME3424, TAC ME3425
Download: ML101590108 (16)

Text

Tennessee Valley Authority 1101 Market Street, LP 3R Chattanooga, Tennessee 37402-2801 R. M. Krich Vice President Nuclear Licensing May 28, 2010 10 CFR 50.4 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Browns Ferry Nuclear Plant, Units 1, 2, and 3 Facility Operating License Nos. DPR-33, DPR-52, and DPR-68 NRC Docket Nos. 50-259, 50-260, and 50-296

Subject:

Technical Specification Change - TS-468 - Responses to Request for Additional Information Regarding Extending Completion Times for Emergency Diesel Generators, (TAC Nos. ME3423, ME3424, and ME3425)

Reference:

1. Letter from Tennessee Valley Authority to NRC dated February 18, 2010, "Technical Specifications Change TS-468 - Request to Extend Completion Time for TS 3.8.1 Required Action B.4 - Emergency Diesel Generators A, B, C, D, 3A, 3B, 3C, and 3D" [ML100550700]

2. Letter from NRC to Tennessee Valley Authority dated May 7, 2010, "Browns Ferry Nuclear Plant, Units 1, 2, and 3 - Request For Additional Information Regarding Extending Completion Times For Emergency Diesel Generators (TAC Nos. ME3423, ME3424, and ME3425)"

[ML101180466]

This letter provides Tennessee Valley Authority's (TVA's) response to the NRC request for additional information provided in Reference 2 above. Enclosure 1 provides TVA's response. Enclosure 2 provides a single line drawing depicting the major loads on the 4kV shutdown boards as discussed in Enclosure 1.

By letter dated February 18, 2010 (Reference 1), TVA submitted a license amendment request to NRC to revise the Browns Ferry Nuclear Plant (BFN) Units 1, 2, and 3 Technical Specifications (TSs) to extend the Completion Times for TS 3.8.1 Required Action B.4. By letter dated May 7, 2010 (Reference 2), the NRC requested additional information be submitted to support their review of the license amendment application.

printed on recycled paper

U. S. Nuclear Regulatory Commission Page 2

- May 28, 2010 TVA has determined that the additional information provided by this letter does not affect the no significant hazards considerations associated with the proposed TS changes.

Theproposed TS changes still qualify for a categorical exclusion from environmental review pursuant to the provisions of 10 CFR 51.22(c)(9).

There is one regulatory commitment associated with this response as reflected in Enclosure 3. Should there be any questions regarding this letter, please contact Terry Cribbe at (423) 751-3850.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on the 28th day of May, 2010.

Respectfully, R. M. Krich

Enclosures:

1. Response to Request For Additional Information Regarding Extending Completion Times For Emergency Diesel Generators

2. Single Line Drawing Depicting Loads On 4kV Shutdown Boards

3. Regulatory Commitment cc: (Enclosures)

NRC Regional Administrator - Region II NRC Senior Resident Inspector - Browns Ferry Nuclear Plant State Health Officer, Alabama State Department of Public Health

ENCLOSURE1 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT UNITS 1, 2, AND 3 Response to Request for Additional Information Regarding Extending Completion Times for Emergency Diesel Generators NRC Question I License amendment request (LAR) Section 3.2.2.3, states, "It is possible using the 4kV [kilo volt] bus tie board (UFSAR [UpdatedFinal Safety Analysis Report] Figure 8.4-2), to make any DG [diesel generator]available to any 4kV Shutdown Board." Browns Ferry Nuclear Plant's (BFN) UFSAR, Section 8.5.2, "Safety Design Basis,"states "The Standby AC Power System will meet or exceed the requirements of [Institute of Electrical and ElectronicsEngineers (IEEE) standard]IEEE-308 and -279." Explain how the cross-tie connections are made such that redundancy, separation,and isolation criteriaare met. Given BFN's unique electrical design, describe, in detail the capability of the OPERABLE emergency DGs to replace the power lost due to removing a DG from service for an extended period. In your response, provide a summary description with drawings, as appropriate,showing DG operatingconfigurationsand theirrequiredloads for the worst-case design basis events. If applicable, describe the time requiredto interconnect a DG to anothershutdown board and the procedures used.

TVA Response The response to Question 1 is based on clarification provided during a teleconference between the NRC and TVA personnel conducted on April 26, 2010. During the teleconference the NRC indicated it was difficult to follow the various descriptions of breaker and shutdown board alignments without additional information regarding which shutdown boards supplied specific loads. The NRC indicated a drawing showing the location of the major loads on the 4 kV shutdown boards would be helpful. is an information only copy of the BFN electrical distribution system depicting the major loads associated with each 4kV shutdown board. The drawing is provided to assist in understanding the various configurations and required loads for the design basis events. This drawing, along with the narrative description provided in the LAR starting on page El-10, provides the information requested. The narrative in the LAR describes operation of the Emergency Equipment Cooling Water (EECW) system pumps. The EECW system is supplied by Residual Heat Removal Service Water (RHRSW) system pumps A3, B3, C3, and D3, which are dedicated to supply the EECW system. RHRSW system pumps A2, B2, C2, and D2 are dedicated to supply the RHRSW system. RHRSW system pumps Al, B1, C1, and D1 are swing pumps, which can supply either the RHRSW or EECW systems.

The 4kV bus tie board is only used for outside design basis event scenarios where redundancy, separation, and isolation criteria do not apply. The 4kV bus tie board breakers are normally open and can only be manually closed. Bus intertie capabilities exist which can be used to supply a Unit 1 and 2 4kV shutdown board (A, B, C, or D) having an inoperable DG from a corresponding Unit 3 DG (DG 3A, 3B, 3C, or 3D) and corresponding Unit 3 4kV shutdown board (3EA, 3EB, 3EC, or 3ED). These intertie connections do not use the 4kV bus tie board.

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Loads associated with a DG that is out-of-service are not generally pre-aligned to another Operable DG during the extended out-of-service period.

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NRC Question 2 LAR page EI-17 states, "StationBlackout (SBO) coping duration for BFN is four hours. Coping strategy is to shutdown the blacked-out unit with equipment powered from the 250 volt direct current battery system." Consideringthe extended allowed outage times and the current reliability and availability values of the DGs (as of March 2010), provide a summary of the evaluation and analysis to confirm that the original SBO assumptions, including the coping strategy and duration,remain the same as previously submitted.

TVA Response The coping strategy and duration for a SBO at BFN are not affected by the proposed changes to the DG Completion Times. The coping strategy and duration are dependent on the reliability of the associated DGs. SBO coping strategy and duration are not dependent on DG availability.

The DG reliability goal supporting the SBO strategy and duration is > 0.95. This reliability is determined based a failure data for the last 25, 50 and 100 starts for each DG. The failure data supporting DG reliability at the time of initial submittal of the proposed LAR is provided in Table 19 on page E1-44. The data supports the reliability goal of > 0.95.

More recent DG data based on a 24 month rolling interval (as of March 2010) is given below:

This data continues to support the reliability goal of > 0.95.

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NRC Question 3 LAR Page E1-17 states, "SBO on Unit 2 is the loss of DGs B and D and loss of DGs A and C for SBO on Unit 1. SBO on Unit 3 is the loss of DGs 3A and 3C. Consideringthe failure of one DG in each of the nonblacked-out units (A or C for Unit 1, B or D for Unit 2, and 3A or 3C for Unit 3),

and an additionalfailure of DG 3B or 3D, a minimum of three DGs remain available for SBO.

These provide sufficient power to supply required HVAC and common loads." Clarify whether three DGs have sufficient capacity to supply safe shutdown loads of non-SBO units and any required alternateAC power for the SBO unit. Provide a summary of the loading requirements for each DG and the loading margins.

TVA Response SBO is postulated as the failure of the two DGs that normally feed a respective unit's 480V AC shutdown boards concurrent with the loss of all offsite power. The coping strategy is to shutdown the blacked-out unit with equipment powered from the 250V DC battery system.

Alternate AC power from the DGs in the non-blacked-out units will be made available to power the required Heating, Ventilation, and Cooling (HVAC) components and common loads. As set forth in Nuclear Management and Resource Council (NUMARC) 87-00, Appendix B, the alternate AC will be available within one hour through existing cross-ties.

The 250V unit batteries 1, 2, and 3 are adequate to supply the required Unit 1, Unit 2, and Unit 3 loads for the coping duration of four hours. SBO on Unit 2 includes the loss of DGs B and D.

SBO on Unit 1 includes the loss of DGs A and C. SBO on Unit 3 includes the loss of DGs 3A and 3C. Considering the failure of one DG in each of the non-blacked out units (A or C for Unit 1, B or D for Unit 2, and 3A or 3C for Unit 3), and an additional failure of DG 3B or 3D, a minimum of three DGs remain available for SBO. The three available DGs will provide sufficient power to supply the required HVAC components and common loads.

SBO is a special event as opposed to a design basis event. Special events are evaluated in accordance with the rules that define the event. For BFN, special events are not coupled with design basis events. Thus, the station would not be required to assume a SBO on one unit coupled with a design basis accident or design basis transient on the other unit(s). The design basis assumptions regarding single failures such as those imposed by 10 CFR 50, Appendix A are applicable only to design basis events unless imposed explicitly by the associated specific special event rule. Thus, the requirements/restrictions for automatic actions and single failure protection specified in BFN's Updated Final Safety Analysis Report (UFSAR) sections 1.5.1.5, 1.5.1.6, and 8.5.2 are not applied to a SBO. For the multi-unit site, only one unit is assumed to experience the full SBO while the other units experience a loss of offsite power with only the specified equipment failures (i.e., a failure of one of the two dedicated DGs plus one of the two common DGs, 3B or 3D). The postulated SBO and prescribed failures result in 24 possible combinations with three available EDGs.

The three available DGs can be demonstrated to power sufficient combinations of equipment to bring both non-SBO units to a safe shutdown while maintaining the blacked out unit during the four-hour coping period as well as to provide HVAC to the main control rooms, control bay and required reactor building electric equipment areas within one hour. See Table 1 for a listing of the considered equipment and applicability requirements.

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Table 1

-eactor uore isolation L;ooiing (luIL;) -jy High Pressure Coolant Injection (HPCI) System DC powered - Backup of RCIC functions Three Main Steam Safety Relief Valves (MSRVs) DC powered - Reactor pressure control 120V Instrumentation and Control (I&C) Bus Control and Instrumentation Power Additional Equipment Available for Each Non- Notes/Applicability SBO Unit One Residual Heat Removal system (RHR) pump Suppression Pool Cooling One Residual Heat Removal Service Water Cooling the in-use RHR heat exchanger (RHRSW) pump RHR Pump Cooler Cooling the operating RHR pump Core Spray Cooler (Northwest) NW for RCIC Not required, but may auto start on high room Cooling temperature if AC is available.

Additional Equipment Available for Each Non- Noe/plcblt cniued)

SSO Unit (continued) Nts~piaiiy(ni Containment Atmosphere Dilution Nitrogen makeup to MSRVs if required. It is lined up by manual valve operation.

One RHR Heat Exchanger (HX) RHRSW Outlet Cooling the RHR heat exchanger Valve I One RHR system I(11) Suppression Chamber/PooJ Suppression Pool Cooling Isolation Valve One RHR system I(11) Suppression Pool Suppression Pool Cooling Cooling/Test Valve RHR system I Minimum Flow Valve Suppression Pool Cooling (includes Low Pressure Coolant Injection (LPCI) Motor Generator (MG) Set I I Load for Units 2 and 3)

Battery Chargers for Unit Batteries and Boards Unit Batteries are qualified for four hours and thus can be load shed for SBO.

Battery Chargers for 4kV Shutdown (SD) Board Only battery chargers associated with the in-use 4kV Batteries and 480V SD Board are required.

Diesel Generator Battery Chargers Only battery chargers associated with the in-use DGs are required.

Two Emergency Equipment Cooling Water (EECW) Cooling plant equipment (primarily the DGs)

Pumps Containment Atmosphere Dilution Nitrogen makeup to MSRVs if required. It is lined up by manual valve operation.

Common HVAC Equipment Notes/Applicabilty DG Exhaust Fan Only the fans associated with the in-use EQGs are required.

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Only the fan associated with the in-use DGs are required.

DG Auxiliary Board Room 3EN3EB Exhaust Fan Only the fan associated with the in-use DGs are required.

DG Battery Exhaust Fan Only the fans associated with the in-use DGs are required.

Control Bay Supply Fan 1A/1B One fan is required.

Control Bay Supply Fan 3A/3B One fan is required.

Battery and Board Room Exhaust Fan 1A/1B One fan is required.

Battery and Board Room Exhaust Fan 3A/3B One fan is required.

Shutdown Board Room Exhaust Fan 1A Not required for SBO but load is counted if running.

Shutdown Board Room Exhaust Fan 2A Not required for SBO but load is counted if running.

Electric Board Room Exhaust Fan 3A Not required for SBO but load is counted if running.

250V Battery and Board Room Exhaust Fan One fan is required.

lA/lB 250V Battery and Board Room Supply Fan lA/1 B One fan is required.

250V Battery and Board Room Exhaust Fan One fan is required.

2A/2B 250V Battery and Board Room Supply Fan 2A/2B One fan is required.

Elevation 593 AHU 1A/1 B One fan is required.

Elevation 593 AHU 3A/3B One fan is required.

250V Battery Room 3EB Exhaust Fan A/B One fan is required.

Main Control Room Air Handling Unit (AHU) One fan is required.

1A/lB Unit 3 Control Room AHU 3A/3B One fan is required.

Spreading Room Supply Fan 1/2 One fan is required.

Spreading Room Exhaust Fan A/B One fan is required.

Relay Room AHU A/B One fan is required.

Control Bay Chiller A/B One chiller is required.

Control Bay Chiller 3A/3B One chiller is required.

Chilled Water Circulation Pump 1A/lB One pump associated with the in-use chiller is required.

Chilled Water Circulation Pump 3A/3B One pump associated with the in-use chiller is required.

Shutdown Board Room 3EA& 3EB Chiller3A-1/3B-1 Only required if either 4kV Shutdown Board 3EA or 3EBis in use.

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lrd Room 3EA and 3EB CW Pump 3A-1 / Only required if either 4kV 1 3EB is in use.

Shutlown Board Room3ECand3EDCWPump3A-2/3B- Only required if either 4kV Shutdown Board 3EC or 2 3ED is in use.

Shutdown Board Room 3EAand 3EBAHU 3A-1 3B-1 Only required if either 4kV Shutdown Board 3EA or 3EB is in use.

Shutdown Board Room 3EC and 3EDAHU 3A-2/3B-2 Only required if either 4kV Shutdown Board 3EC or 3ED is in use.

Unit 1 Electric Board Room Air Handling Unit 1A/ 1B One fan is required.

Unit 2 Electric Board Room Air Handling One fan is required.

Unit 2A / 2B I Unit 3 Electric Board Room Air Conditioning Unit 3A / 3B One fan is required.

Due to the diversity of BFN's electrical distribution system, the following scenarios could use a 4kV board to provide power to other 4kV board(s) without defeating interlocks as long as DG load restrictions are not exceeded:

• Energizing a Unit 1 or Unit 2 4kV board directly from its corresponding Unit 3 4kV board (i.e., 3EA to A, 3EB to B, 3EC to C, or 3ED to D).

" Energizing any Unit 1 or Unit 2 4kV board using another Unit 1 or Unit 2 4kV board via the shutdown busses (e.g., A to B, A to C, or A to D; the same can be shown for B, C, and D.)

• Energizing Unit 3 4kV board 3EA or 3EC directly from 3EB or 3ED respectively.

• Energizing a Unit 1 or Unit 2 4kV board via the Bus-Tie Board from a Unit 3 4kV board (e.g. 3EA to B, C, or D; the same can be shown for 3EB, 3EC, and 3ED.). This option can be used for any Unit 3 4kV shutdown board to supply any Unit 1 or Unit 2 4kV shutdown board; however, the bus-tie board is for emergency use only and it is only permitted to tie one pair of 4kV shutdown boards together in order to not exceed the load ratings of the bus-tie board and its breakers. The SBO analysis (which assumes that equipment other than the failed EDGs is available) demonstrates that required loads from Table 1 can be supplied without use of the bus-tie board.

The analyzed cases require at least one board transfer as shown above to supply the requi'red loads. Table 2 provides the summary of loads in kilowatts for each DG for each of the analyzed cases. Cases prefixed with 1, 2, and 3 are associated with a station blackout in the respective unit. The load ratings include the following conservatisms:

• RHR pump motors use 1260 kW based upon 7200 gpm, although the design flow rate is only 6500 gpm (= 1175 kW).

• 30 kW is added to each DG's total.

• Some loads which may occur but are not required to mitigate SBO are counted if the power source is energized (i.e., Unit 1 and Unit 2 shutdown board room exhaust fans, Unit 3 electric board room exhaust, Standby Gas Treatment System (SGTS) and Control Room Emergency Ventilation System (CREVS)

The load ratings do not include the:

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0 Unit battery chargers which are not required for SBO; 0 Excess EECW pumps which are to be secured during the event; and 0 Drywell Blowers and Reactor Building Closed Cooling Water Pumps because these loads are assumed to be load shed prior to placing suppression pool cooling for any unit into service.

Load shedding of this equipment is acceptable. The operators are instructed that prior to depressurizing below 450 psig reactor pressure to inhibit the high drywell pressure signal by placing drywell pressure "TEST/INHIBIT" switches on Main Control Room (MCR) panel 9-3 (HS-75-59 and 60) to the TEST/INHIBIT position to prevent the spurious initiation of the accident signal logic on high drywell pressure-low reactor pressure.

Table 2 2339.67 2248.88 297.16 4885.71 1737.32 2248.88 925.25 4911.45 2339.67 2209.66 382.67 4932.04 2365.41 2210.87 356.93 4933.21 2339.67 2312.02 297.16 4948.85 1963.12 2371.17 640.48 4974.77 2339.67 2075.76 505.29 4920.72 2085.74 2461.84 356.93 4904.51 2058.00 1819.49 987.06 4864.55 1758.17 2180.21 952.09 4890.47 2250.42 1877.09 792.90 4920.41 1880.93 2246.58 792.90 4920.41 2031.83 2224.97 625.16 4881.96 2107.07 1868.71 952.09 4927.87 2040.60 2393.17 465.97 4899.74 2238.60 1851.85 792.90 4883.35 2058.00 2352.16 455.56 4865.72 1792.63 2304.70 777.92 4875.25 2195.84 2006.73 714.55 4917.12 1900.16 2285.39 715.36 4900.91 2058.00 1718.82 1114.64 4891.46 1788.06 2045.75 1067.18 4900.99 2267.48 2085.74 547.69 4900.91 1924.16 2085.74 874.62 4884.52 Summary of Table 2 Table 2 shows that for all cases, each DG will experience a continuous loading of less than its most limiting maximum steady-state active power output of 2,550 kW. The values shown in bold are the highest loading totals of any one DG and the highest total for each set of SBO cases. It should also be noted that no case results in more than one DG reaching the worse case loading at the same time.

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NRC Question 4 The LAR states that the proposed change is needed because the existing 7-day completion time (CT) does not permit adequate time to perform some planned and corrective maintenance, and discusses the 12-year preventative maintenance that requires extensive diesel engine disassembly (pages E1-2 to EI-4). Later discussionsin Section E describe the extended CT as being used "toperform maintenance or to trouble shoot and repairan inoperableDG. " of the LAR provides the regulatorycommitments. It is not clear to the staff that the extended CT will be typically used to perform infrequent diesel manufacturer'srecommended inspections and preventive maintenance activities or that the extended CT would reduce entries into the limiting condition for operation (LCO) and reduce the number of DG starts for major DG maintenance activities. Clarify the regulatorycommitments regarding the use of the extended CT for maintenance activities and/or the compensatory measures that will be used for LCO entries that are not part of a planned maintenance activity.

TVA Response The DG manufacturer and the owners group are recommending additional preventive maintenance activities to be performed during the 12-year or other long term maintenance intervals that may require multiple entries into the LCO (i.e., Technical Specification (TS)

Actions) and multiple DG starts if all of the planned activities cannot be completed within the existing 7-day CT. The extended CTs are requested to permit performing DG manufacturer and owners group recommended replacement activities using fewer TS Action entries than can be accomplished within the current 7-day CT. Ifthese activities (listed below) can be combined and performed over an extended CT, the number of entries into the TS Actions and the number of associated DG starts performed for post-maintenance testing prior to exiting the TS Actions will be reduced. I Planned replacement activities over the next 5 years include the following:

1. Lube oil modification (estimated at 178 hours0.00206 days <br />0.0494 hours <br />2.943122e-4 weeks <br />6.7729e-5 months <br />)

2. Governor modification (estimated at 124 hours0.00144 days <br />0.0344 hours <br />2.050265e-4 weeks <br />4.7182e-5 months <br />)

3. Starting air modification (estimated at 124 hours0.00144 days <br />0.0344 hours <br />2.050265e-4 weeks <br />4.7182e-5 months <br />)

4. Battery replacement (estimated at 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />)

5. Heat exchanger modification (estimated at 144 hours0.00167 days <br />0.04 hours <br />2.380952e-4 weeks <br />5.4792e-5 months <br />)

6. Generator vibration/alignment (estimated at 96 hours0.00111 days <br />0.0267 hours <br />1.587302e-4 weeks <br />3.6528e-5 months <br />)

7. Stub shaft upgrade (estimated at 120 hours0.00139 days <br />0.0333 hours <br />1.984127e-4 weeks <br />4.566e-5 months <br />)

These component upgrades are important to maintaining the reliability and availability of~this important system.

In addition, TVA is also considering other long term improvements such as:

1. Replacing the governor booster pumps with pneumatic boosters

2. Upgrading the air start flow control system to eliminate the 3 way pilot valves

3. Upgrading the 7 day fuel tank level indication/annunciation

4. Modifying the DGs to provide a larger more corrosion resistant heat exchangers

5. Installing generator heaters

6. Upgrading diesel controls for more auto trips when in test/maintenance mode

7. Upgrading the DG instrumentation system to be consistent with that provided for WBN and SQN (i.e., cylinder exhaust temperature monitoring system, etc.)

With respect to clarifying the regulatory commitments regarding the use of the extended CT for maintenance activities and/or the compensatory measures that will be used for TS Action E1-9

entries that are not part of a planned maintenance activity, TVA will revise the proposed Technical Specifications and Bases and submit them to the NRC by July 30, 2010 to include the previous commitments in the proposed change as follows:

• For the condition of one required DG inoperable, a new proposed Required Action B. 1 will be added to TS 3.8.1, AC Sources - Operating, Actions to verify the applicable compensatory actions and configuration risk management controls are satisfied immediately and periodically thereafter during the proposed 14 day CT for restoration of the required DG to Operable status. The proposed CT of "Immediately" for proposed Required Action B.1 reflects that fact that in order to ensure a full 14 day CT, for restoration of the required DG to Operable status, is available for completing preplanned maintenance of a required DG, prudent plant practice dictates that the applicable compensatory actions and configuration risk management controls be verified to be satisfied prior to making a required DG inoperable for the preplanned maintenance.

• The Bases of proposed Required Action B.1 will be revised to describe the applicable compensatory actions and configuration risk management controls that must be satisfied to support the extended CT of 14 days. The compensatory measures and configuration risk management controls to be included in the Bases description are as follows.

o Increased administrative control will be exercised for any proposed hot work in the vicinity of protected equipment and in the impacted fire zones (Prior to entering the period of extended CT and maintained for the duration of the 14 day DG CT).

o No planned maintenance on fire detection or fire suppression equipment that will cause the fire detection or fire suppression equipment in the impacted fire zones to be inoperable (For the duration of the 14 day DG CT).

o Transient combustible loading in the impacted fire zones will be reviewed and any unnecessary transient combustibles will be removed. (Prior to entering the period of 14 day DG CT and maintained for the duration of the 14 day DG CT).

o Only one of the eight DGs will be taken out of service. Maintenance on more than one DG will not be permitted during the 14 day DG CT.

o Electrical boards or transformers will not be removed from service for planned maintenance activities during the 14 day DG CT.

o Weather conditions will be evaluated prior to entering the 14 day DG CT for elective maintenance. A 14 day DG CT will not be entered for elective maintenance purposes if official weather forecasts are predicting severe conditions (tornado or thunderstorm warnings).

o Elective maintenance will not be performed in the switchyard that would challenge offsite power availability during the 14 day DG CT.

o The condition of the offsite power supply and switchyard will be evaluated prior to entering the 14 day DG CT for elective maintenance. TVA procedures exist to determine acceptable grid conditions for entering the 14 day DG CT to perform elective maintenance.

o The system dispatcher will be contacted once per day and informed of the DG status along with the power needs of the facility during the 14 day DG CT.

o For Units 1 and 2, the HPCI pumps, RCIC pumps, and RHR pumps will not be removed from service for planned maintenance activities during the 14 day DG CT for Unit 1 and Unit 2 DGs.'

o For Unit 3, the HPCI pump, RCIC pump, and RHR pumps will not be removed from service for planned maintenance activities during the 14 day DG CT for Unit 3 DGs.

o Operating crews will be briefed on the DG work plan and procedural actions regarding Loss of Offsite Power and Station Blackout.

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" In addition, a new proposed Condition C and associated Required Action C.1 will be added to TS 3.8.1 Actions. Condition C addresses the condition of the applicable compensatory actions and configuration risk management controls (i.e., Required Action B. 1) not met within the associated CT. In this condition (i.e., applicable compensatory actions and configuration risk management controls not satisfied), Required Action C. 1 will require the required inoperable DG be restored to Operable status within 7 days (consistent with the current TS CT for restoration of an inoperable DG).

" Commensurate changes are also proposed to be made to the numbering of the subsequent Conditions and Required Actions of TS 3.8.1.

The proposed changes described above are modeled after the approach for Conditions and Required Actions used in the Peach Bottom Atomic Power Station (PBAPS) Units 2 and 3 TS 3.8.1, AC Sources - Operating, to support an extended CT for restoring an inoperable DG to Operable status. These TS changes were included in approved Amendments 210 and 214, dated August 30, 1995, for PBAPS Units 2 and 3, respectively.

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ENCLOSURE 2 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT UNITS 1, 2, AND 3 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING EXTENDING COMPLETION TIMES FOR EMERGENCY DIESEL GENERATORS SINGLE LINE DRAWING DEPICTING LOADS ON 4KV SHUTDOWN BOARDS

THIS PAGE IS AN OVERSIZED DRAWING OR FIGURE, THAT CAN BE VIEWED AT THE RECORD TITLED:

"BROWNS FERRY ELECTRICAL DISTRIBUTION SYSTEM" WITHIN THIS PACKAGE...OR BY SEARCHING USING THE DOCUMENT/REPORT NO.

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ENCLOSURE 3 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT UNITS 1, 2, AND 3 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING EXTENDING COMPLETION TIMES FOR EMERGENCY DIESEL GENERATORS REGULATORY COMMITMENT With respect to clarifying the regulatory commitments regarding the use of the extended CT for maintenance activities and/or the compensatory measures that will be used for TS Action entries that are not part of a planned maintenance activity, TVA will revise the proposed Technical Specifications and Bases and submit them to the NRC by July 30, 2010 to include the previous commitments in the proposed change as stated in Enclosure 1.