ML051190274

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Technical Specification (TS) Change TS 452 - Revision to Low Pressure Emergency Core Cooling System Allowed Outage Time
ML051190274
Person / Time
Site: Browns Ferry Tennessee Valley Authority icon.png
Issue date: 04/26/2005
From: Abney T
Tennessee Valley Authority
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
TVA-BFN-TS-452
Download: ML051190274 (35)
v • d • e


Text

Tennessee Valley Authority, Post Office Box 2000, Decatur, AJabarna 35609-2000 TVA-BFN-TS-452 April 26, 2005 10 CFR 50.90 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 No. 50-260 Tennessee Valley Authority BROWNS FERRY NUCLEAR PLANT (BFN) UNIT 2 - TECHNICAL SPECIFICATION (TS) CHANGE TS 452 - REVISION TO LOW PRESSURE EMERGENCY CORE COOLING SYSTEM ALLOWED OUTAGE TIME Pursuant to 10 CFR 50.90, Tennessee Valley Authority (TVA) is submitting a request for an emergency TS change (TS 452) to license DPR-52 for BFN Unit 2. The proposed change revises the current Unit 2 low pressure Emergency Core Cooling System (ECCS) injection/spray seven day allowed outage time (AOT) to 14 days.

The purpose of increasing the AOT is to provide additional flexibility for preventive or corrective maintenance and repair of the Residual Heat Removal (RHR) or Low Pressure Core Spray subsystems.

On April 22, 2005 at 12:20 pm, TVA declared Unit 2 RHR Subsystem 2A and RHR Service Water Subsystem 2A inoperable due to indications of internal RHR Heat Exchanger 2A leakage. In accordance with TS Limiting Condition for Operations (LCOs) 3.6.2.3.A, 3.6.2.4.A, 3.6.2.5.A, and 3.7.1.B, TVA has 30 days to restore these subsystems to operable status for containment cooling purposes or be in Mode 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. RHR Heat Exchangers 2B, 2C and 2D are operable.

In order to repair the heat exchanger, TVA will have to isolate the associated RHR pump. TVA is estimating that the earliest it could be ready to begin the repairs on the RHR heat exchanger is the morning of Thursday, April 28, 2005. When the RHR pump associated with this heat exchanger is isolated, TVA will enter 4kD\

U.S. Nuclear Regulatory Commission Page 2 April 26, 2005 LCO 3.5.1 and will have seven days to restore the associated ECCS injection/spray subsystem to operable status or be in Mode 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. TVA can not identify the cause of the leakage or estimate repair time until it inspects the heat exchanger internals. Disassembling the heat exchanger, conducting troubleshooting, developing a repair plan, obtaining parts, writing the work orders, performing the repairs, reassembling the heat exchanger, conducting post-maintenance testing, removing clearances and returning the subsystem to an operable status may take longer than the current 7 day AOT. Without approval of this proposed change, TVA may be required to be progressing to Mode 3 on Thursday, May 5, 2005. Therefore, pursuant to 10 CFR 50.91(a)(5), TVA requests approval of this application on an emergency basis.

TVA has evaluated the proposed extension of the Unit 2 low pressure ECCS injection/spray seven day AOT to 14 days based upon both a deterministic evaluation and a risk-informed assessment.

As discussed in the enclosure:

  • The proposed AOT extension complies with all regulatory requirements and TVA commitments;
  • Since a single failure is not considered while a plant is in a LCO Action Statement, the operable redundant equipment is capable of performing its required function and to maintain the plant design basis. Thus, the requested action will not alter the assumptions relative to the mitigation of a design basis accident or transient. However, margin exists both in the ECCS performance analysis (i.e., the calculated peak clad temperature is below regulatory limits) and additional ECCS equipment is available to mitigate the consequences of the worst case design basis accident which is not credited in the ECCS performance analysis.
  • TVA has evaluated the risk impacts of having one low pressure ECCS injection/spray subsystem or one LPCI pump in both subsystems inoperable for an additional seven days.

The resulting increase in core damage frequency and large early release frequency are small and consistent with the intent of the Commission's Safety Goal Policy Statement and the regulatory position contained in Regulatory Guides 1.174 and 1.177. In addition, BFN uses a proceduralized risk-based approach for scheduling maintenance, which limits

U.S. Nuclear Regulatory Commission Page 3 April 26, 2005 removal of risk sensitive equipment from service during ECCS subsystem outages.

When taken together, the results of the deterministic evaluation and risk-informed assessment provide a high degree of assurance that the ECCS will remain capable of performing its safety function with the proposed AOT.

As previously discussed, the repair time for RHR Heat Exchanger 2A is not known and will not be known until the 7 day LCO is entered and the heat exchanger is disassembled.

RIS 2005-01, Changes to Notice of Enforcement Discretion (NOED)

Process and Staff Guidance, states that an NOED request will not be considered if at least 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> of completion time remains for the affected LCO at the time the problem is identified. Based on the guidance in RIS 2005-01, a license amendment request is required. Additionally, RIS 2005-01 stipulates that a permanent license amendment should be requested to address operational issues. While this situation is unusual and is not expected to recur, TVA is submitting this as a permanent license amendment to comply with RIS 2005-01.

TVA requests the amendment be approved by Wednesday, May 4, 2005, and that the implementation of the revised TS be within 2 days after receipt of NRC approval.

It should be noted that BFN Unit 2 is currently operating in Mode 1. In the lower temperature ranges of Mode 3, the RHR system is used in shutdown cooling mode for decay heat removal.

Reactor coolant is pumped by the RHR pumps from one of the recirculation loops through the RHR heat exchangers, where cooling takes place by transferring heat to the RHR service water system. During a nuclear system shutdown and cooldown, any one of the four RHR shutdown cooling subsystems can provide the required decay heat removal function and maintain or reduce the reactor coolant temperature as required. However, TVA believes that the plant should not be required to go to Mode 3 to conduct the repair. Although it is feasible from an RHR subsystem availability standpoint, the associated risk from the operational transient and unnecessarily using shutdown cooling with only three RHR subsystems operable is judged to be greater than conducting the repair in the present plant condition.

U.S. Nuclear Regulatory Commission Page 4 April 26, 2005 TVA has determined there are no significant hazards considerations associated with the proposed TS change and the change qualifies for a categorical exclusion from environmental review pursuant to the provisions of 10 CFR 51.22(c)(9).

Additionally, in accordance with 10 CFR 50.91(b)(1), TVA is sending a copy of this letter and attachments to the Alabama State Department of Public Health. provides TVA's evaluation of the proposed change. provides a mark-up of the proposed TS changes. provides retyped TS pages that incorporated the proposed change.

There are no regulatory commitments associated with this submittal. If you have any questions about this amendment, please contact me at (256) 729-2636.

I declare under penalty of perjury that the foregoing is true and correct. Executed on April 2 6 th, 2005.

St cerely, Abney Manager of censing and Indu ry Affairs Enclosur 5:

1. TVA valuation of P posed Change
2. Propo ed Technical ecification Changes (mark-up)
3. Propos d Technical pecification Changes (retyped)

Enclosure cc (Enclosure):

State Health Officer Alabama Dept. of Public Health RSA Tower - Administration Suite 1552 P.O. Box 303017 Montgomery, AL 36130-3017

U.S. Nuclear Regulatory Commission Page 5 April 26, 2005 Enclosure cc (Enclosure):

U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-3415 Mr. Stephen J. Cahill, 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, AL 35611-6970 Margaret Chernoff, 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 Browns Ferry Nuclear Plant (BFN) Unit 2 Technical Specification (TS) Change TS 452 Revision to Emergency Core Cooling System (ECCS)

Allowed Outage Time TVA Evaluation of Proposed Change INDEX SECTION TOPIC PAGE 1.0 Description ......... ............................ 1 2.0 Proposed Change ................................. 1 3.0 Background ......... ............................. 1 3.1 Reason for Proposed Change ...................... 1 3.2 Description of Emergency Core Cooling System ....2 3.3 Low Pressure Coolant Injection .... .............. 3 3.4 Containment Cooling ............................. 4 3.5 Shutdown Cooling ................................ 5 3.6 Low Pressure Core Spray ......................... 5 3.7 Applicability of the Maintenance Rule .... ....... 6 4.0 Technical Analysis .............................. 7 4.1 Compliance with Current Regulations and 8 Commitments ....................................

4.2 Deterministic Engineering Evaluation .... ........ 9 4.3 Evaluation of Risk Impact ....................... 14 4.4 Summary and Conclusion .......................... 20 5.0 Regulatory Safety Analysis ...................... 21 5.1 No Significant Hazards Consideration .... ........ 21 5.2 Applicable Regulatory Requirements/Criteria ..... 23 6.0 Environmental Consideration ..................... 24 7.0 References .......... ............................ 25 El-i

1.0 DESCRIPTION

This letter requests an emergency amendment to Operating License DPR-52 for BFN Unit 2. The proposed change revises the current Unit 2 low pressure ECCS injection/spray seven day allowed outage time (AOT) to 14 days. The increased AOT will provide additional flexibility for preventive or corrective maintenance and repair of the Residual Heat Removal (RHR) or Low Pressure Core Spray (LPCS) subsystems.

Because of a current maintenance issue on RHR Heat Exchanger 2A, TVA may be required to be progressing to Mode 3 on May 9, 2005 without approval of this proposed change. Therefore, pursuant to 10 CFR 50.91(a)(5), TVA requests approval of this application on an emergency basis.

2.0 PROPOSED CHANGE

The proposed change revises the current Unit 2 low pressure ECCS injection/spray seven day AOT to 14 days. The specific changes are described below:

Revise Unit 2 TS Page 3.5-1 (Limiting Condition for Operation (LCO) 3.5.1:

In the COMPLETION TIME for REQUIRED ACTION 3.5.1.A, 14 days is substituted for the existing 7 days.

A mark-up of the TS showing the proposed changes is provided in . Enclosure 3 provides retyped TS page that incorporated the proposed change.

3.0 BACKGROUND

3.1 Reason for the Proposed Change The underlying reason for the Unit 2 TS change is to provide additional flexibility for preventive or corrective maintenance and repair of the RHR or LPCS subsystems.

In general, the seven day AOT in the current Unit 2 TS is adequate for the planned and unplanned maintenance necessary to support the operation of Unit 2. However, on April 22, 2005 at 12:20 pm, TVA declared Unit 2 RHR Subsystem 2A and RHR Service Water Subsystem 2A inoperable due to indications of internal RHR Heat Exchanger 2A leakage. In accordance with TS LCOs 3.6.2.3.A, 3.6.2.4.A, 3.6.2.5.A, and 3.7.1.B, TVA has 30 days to restore El-1

these subsystems to operable status for containment cooling purposes or be in Mode 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. RHR Heat Exchangers 2B, 2C and 2D are operable.

In order to repair RHR Heat Exchanger 2A, TVA will have to isolate the associated RHR pump. TVA is estimating that the earliest it could be ready to begin the repairs on the RHR heat exchanger is the morning of Thursday, April 28, 2005. When the RHR pump associated with this heat exchanger is isolated, TVA will enter LCO 3.5.1 and will have seven days to restore the associated ECCS injection/spray subsystem to operable status or be in Mode 3 in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. TVA can not identify the cause of the leakage or estimate repair time until it inspects the heat exchanger internals. Disassembling the heat exchanger, conducting troubleshooting, developing a repair plan, obtaining parts, writing the work orders, performing the repairs, reassembling the heat exchanger, conducting post-maintenance testing, removing clearances and returning the subsystem to an operable status may take longer than the current 7 day AOT. The current LCO 3.5.1 would require Unit 2 to be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> if the RHR pump heat exchanger could not be made operable within 7 days.

3.2 Description of Emergency Core Cooling System The BFN ECCS consists of the following:

. Automatic Depressurization System (ADS),

. Low Pressure Core Spray (LPCS), and

The ECCS subsystems are designed to limit clad temperature over the complete spectrum of possible break sizes in the nuclear system process barrier, including the design basis break. The design basis break is defined as the complete and sudden circumferential rupture of the largest pipe connected to the reactor vessel (i.e., one of the recirculation loop pipelines) with displacement of the ends so that blowdown occurs from both ends. A simplified diagram showing the ECCS flow paths after an initiation signal is provided below.

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2A LPCCI 2CLmuA PCJPCECT LPCI INJECTION LLP VCAIE VALVE INJECTIONN VVALVE f

A A VLVE VALVE RECIRO RECIRC PUM U Pru A Assumed analysis flow rates:

- One Core Spray loop (Two pumps) = 5600 gpm - HPCI = 4500 gpm

- One LPCI pump in one loop = 9700 gpm -Two LPCI pumps in one loop = 18,000 gpm NOTE: Both Core Spray pumps ina loop must operate for the loop to be considered available.

Taking an RHR heat exchanger out of service results in one of the two LPCI subsystems being inoperable. In addition, the containment cooling and shutdown cooling functions of RHR are affected. In addition, LCO 3.5.1 also applies to the LPCS system. A description of LPCI, containment cooling, shutdown cooling and LPCS are provided below.

3.3 Low Pressure Coolant Injection LPCI is an operating mode of RHR. There are two LPCI subsystems, each consisting of two motor driven pumps, piping and valves that transfer water from the suppression pool to the reactor vessel through the corresponding recirculation loop. LPCI operates to restore and maintain the coolant inventory in the reactor vessel after a loss-of-coolant accident so that the core is sufficiently cooled to preclude fuel clad temperatures in excess of 2200'F and subsequent energy release due to a metal-water reaction. The LPCI subsystem operates in conjunction with HPCI, ADS, and the LPCS system to achieve this goal.

HPCI is a high-head, low-flow system and pumps water into the reactor vessel when the nuclear system is at high pressure. If HPCI fails to maintain the required level of water in the reactor vessel, the automatic depressurization feature of the Nuclear System Pressure Relief System functions to reduce nuclear system E1-3

pressure so that LPCI operates to inject water into the pressure vessel. LPCI is a low-head, high-flow subsystem. All these operations are carried out automatically. LPCI is designed to reflood the reactor vessel to at least two-thirds core height and to maintain this level. After the core has been flooded to this height, the capacity of one RHR pump is more than sufficient to maintain the level. During LPCI operation, the RHR pumps take suction from the pressure suppression pool and discharge to the reactor vessel into the core region through both of the recirculation loops. Two pumps discharge to each recirculation loop header, assuring flooding of the vessel through at least one loop. Any spillage through a break in the lines within the primary containment returns to the pressure suppression pool through the pressure suppression vent lines.

Additional information regarding the requirements and response of the equipment which operates during LPCI for a LOCA is provided in Chapter 6.0, Core Standby Cooling Systems, and Section 4.8.6.3, Low Pressure Coolant Injection, of the Updated Final Safety Analysis Report (UFSAR).

3.4 Containment Cooling The containment cooling subsystem is an integral part of RHR and is placed in operation to limit the temperature of the water in the pressure suppression pool. With RHR in the suppression pool cooling mode of operation, the RHR pumps are aligned to pump water from the pressure suppression pool through the RHR heat exchangers where cooling takes place by transferring heat to the RHR service water. For adequate containment cooling, a minimum of two RHR pumps and associated heat exchangers must remain available for several hours after a design basis LOCA. The pressure suppression pool cooling mode of RHR is also initiated to restore pressure suppression pool temperatures to.within allowed limits during plant operation.

The containment spray cooling mode of operation provides additional redundancy to the Core Standby Cooling Systems for post-accident conditions. The water pumped through the RHR heat exchangers may be diverted to spray headers in the drywell and above the pressure suppression pool. The spray headers in the drywell condense any steam that may exist in the drywell, thereby lowering containment pressure. The spray collects in the bottom of the drywell until the water level rises to the level of the pressure suppression vent lines, where it overflows and drains back to the pressure suppression pool. TS LCO 3.6.2.3, RHR Suppression Pool Cooling, allows one RHR suppression pool cooling subsystem to be inoperable for 30 days. Additional information is provided in UFSAR Section 7.4, Core Standby Cooling Control and Instrumentation.

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3.5 Shutdown Cooling The shutdown cooling subsystem is an integral part of RHR and is placed in operation during a normal shutdown and cooldown. The initial phase of nuclear system cooldown is accomplished by dumping steam from the reactor vessel to the main condenser with the main condenser acting as the heat sink. RHR is placed in the shutdown cooling mode of operation when reactor vessel pressure has decreased sufficiently to clear the interlocks associated with the shutdown cooling suction valves.

Reactor coolant is pumped by the RHR pumps from one of the recirculation loops through the RHR heat exchangers, where cooling takes place by transferring heat to the RHR service water system. Reactor coolant is returned to the reactor vessel via either recirculation loop.

During a nuclear system shutdown and cooldown, any one of the four RHR shutdown cooling subsystems can provide the required decay heat removal function and maintain or reduce the reactor coolant temperature as required.

In addition, standby coolant supply connection from the RHR Service Water System and RHR crossties are provided to maintain a long-term reactor core and primary containment cooling capability irrespective of primary containment integrity or operability of the RHR System associated with a given unit. The standby coolant supply connection and RHR crossties provide added long-term redundancy to the other emergency core and containment cooling systems and are designed to accommodate certain situations which, although unlikely to occur, could jeopardize the functioning of these systems. By proper valve alignment (see UFSAR Figure 4.8-1), the network created by the RHR crossties permits two RHR pumps on Unit 1 or Unit 3 to circulate Unit 2 pressure suppression pool or reactor vessel water through the heat exchangers on Unit 1 or Unit 3. The crosstie network is sized for a minimum flow of 5,000 gpm, which will achieve about 91 percent of full flow heat transfer capability of the RHR heat exchangers.

3.6 Low Pressure Core Spray Two independent loops are provided as a part of the LPCS System.

Each loop consists of two 50 percent-capacity centrifugal pumps driven by electric motors, a spray sparger in the reactor vessel above the core, piping and valves to convey water from the pressure suppression pool to the sparger, and the associated controls and instrumentation.

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In the case of low-low-low water level in the reactor vessel or high pressure in the drywell plus low reactor vessel pressure, the LPCS System, when reactor vessel pressure is low enough, automatically sprays water onto the top of the fuel assemblies in time and at a sufficient flow rate to cool the core and limit fuel cladding temperature. (LPCI starts from the same signals and operates independently to achieve the same objective by flooding the reactor vessel). The LPCS System provides protection to the core for the large break in the nuclear system when the control rod drive water pumps, RCIC, and the HPCI are unable to maintain reactor vessel water level. The protection provided by the LPCS System also extends to a small break in which the control rod drive water pumps, RCIC, and HPCI are all unable to maintain the reactor vessel water level and ADS has operated to lower the reactor vessel pressure so LPCI and the LPCS System can provide core cooling.

3.7 Applicability of the Maintenance Rule TVAN Standard Programs and Processes (SPP) 6.6, "Maintenance Rule Performance Indicator Monitoring, Trending and Reporting -

10 CFR 50.65," and Technical Instruction 0-TI-346, "Maintenance Rule Performance Indicator Monitoring, Trending, And Reporting -

10CFR50.65," provide guidance for analysis, retrieval, trending, and reporting of data relative to plant level, function specific, and repetitive preventable functional failure indicators of performance required by the Maintenance Rule. The requirements of these procedures are in compliance with 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," and NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." Specific performance criteria have been developed for the following RHR system functions:

. Providing core cooling (LPCI mode);

. Providing containment cooling (wetwell and drywell spray):

and

. Removing decay and residual heat from the core (shutdown cooling mode).

The potentially applicable performance criteria and the impact of revising the current Unit 2 low pressure ECCS injection/spray seven day AOT to 14 days are provided below:

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Maintenance Rule Performance Criteria for the RHR System:

1. The loss of a Division within LPCI, Containment Cooling, Suppression Pool Cooling, or Shutdown Cooling modes is a Functional Failure. There shall be no more than one Functional Failure in a rolling 24 month interval.

Extending the AOT will have no impact on this criterion.

2. The RHR pump trains shall maintain an unavailability factor of less than or equal to 0.022 as monitored over a 24 month rolling interval. While the current equipment situation will increase RHR system unavailability for the short term, the proposed AOT change will not significantly increase system unavailability during the long term due to the emphasis placed on maintaining equipment in service.
3. Considering all operational modes, there shall be no more than one failure per unit of a RHR pump train to start and run during a rolling 24 month interval. Extending the AOT will have no impact on this criterion.

Maintenance Rule Performance Criteria for the LPCS System:

1. A functional failure is the loss of a Division (pumps and/or flow path). No more than one functional failure per unit is allowed as monitored over a 24 month rolling interval. Extending the AOT will have no impact on this criterion.
2. Each division and associated components shall maintain an unavailability factor of less than or equal to 0.020 as monitored over a 24 month rolling interval. The proposed AOT change will not significantly increase system unavailability during the long term due to the emphasis placed on maintaining equipment in service.
3. No more than two Core Spray pump failures per unit are allowed over a 24 month rolling interval. Extending the AOT will have no impact on this criterion.

4.0 TECHNICAL ANALYSIS

TVA has evaluated the proposed extension of the Unit 2 low pressure ECCS injection/spray seven day AOT to 14 days both deterministically and through a risk-informed assessment. As discussed below, the proposed AOT extension complies with all regulatory requirements and TVA commitments.

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Since a single failure is not considered while a plant is in a LCO Action Statement, the operable redundant equipment is capable of performing its required function and to maintain the plant design basis. Thus, the requested action will not alter the assumptions relative to the mitigation of a design basis accident or transient. As discussed below, margin exists both in the ECCS performance analysis (i.e., the calculated Peak Clad Temperature (PCT) is below regulatory limits) and additional ECCS equipment is available to mitigate the consequences of the worst case design basis accident which is not credited in the ECCS performance analysis. Therefore, the proposed AOT extension is acceptable from a deterministic standpoint.

TVA has evaluated the risk impacts of having one low pressure ECCS injection/spray subsystem or one LPCI pump in both subsystems inoperable for an additional seven days. The resulting increase in core damage frequency (CDF) and large early release frequency (LERF) are small and consistent with the intent of the Commission's Safety Goal Policy Statement and the regulatory position contained in Regulatory Guides 1.174 and 1.177. In addition, BFN uses a proceduralized risk-informed approach for scheduling maintenance, which limits removal of risk sensitive equipment from service during ECCS subsystem outages.

When taken together, the results of the deterministic evaluation and risk-informed assessment provide a high degree of assurance that the ECCS will remain capable of performing its safety function with the proposed AOT.

4.1 Compliance with Current Regulations and Commitments The RHR system complies with the applicable NRC General Design Criteria and AEC/NRC Safety/Regulatory Guides as described in the Safety Evaluation of the Tennessee Valley Authority Browns Ferry Nuclear Plant Units 1, 2 and 3, dated June 26, 1972, as supplemented, and Chapters 4, 6, 7 and 14 of the UFSAR. The proposed extension of the Unit 2 low pressure ECCS injection/spray AOT does not add or delete any safety-related systems, equipment, or loads, or alter the design or function of the RHR system. Therefore, compliance with the applicable NRC General Design Criteria and AEC/NRC Safety/Regulatory Guides as described in the above correspondence is not affected by this proposed change. TVA has reviewed its Licensing Basis and determined that no commitments are affected by this proposed change.

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4.2 Deterministic Engineering Evaluation 4.2.1 Defense in Depth As described below, the impact of the proposed extension of the Unit 2 low pressure ECCS injection/spray TS AOT was evaluated and is consistent with the defense-in-depth philosophy and ensures the protection of the public health and safety. The limited unavailability of a water or heat removal subsystem does not significantly change the balance among the defense-in-depth principles of prevention of core damage, prevention of containment failure, and consequence mitigation. The BFN Emergency Core Cooling subsystems are robust and diverse.

Administrative controls ensure system redundancy. Independence and diversity are maintained during the increased AOT. The potential for a common cause failure is not increased and the independence of physical barriers is not degraded. Defenses against human errors are maintained. Compliance with the applicable NRC General Design Criteria and AEC/NRC Safety/RGs is not affected by this proposed change.

4.2.1.1 Overall Philosophy The impact of the proposed extension of the Unit 2 low pressure ECCS injection/spray AOT was evaluated and determined to be consistent with the defense-in-depth philosophy. The limited unavailability of a single water or heat removal subsystem does not significantly change the balance among the defense-in-depth principles of prevention of core damage, prevention of containment failure, and consequence mitigation. The proposed change does not introduce the possibility of new accidents or transients nor increase the likelihood of an accident or transient.

4.2.1.2 Strength of Overall Plant Design The proposed extension of the Unit 2 low pressure ECCS injection/spray AOT is not being requested to compensate for a weakness in plant design. The robustness of the ECCS systems is demonstrated by the ability of the plant to mitigate the consequences of a design basis accident coupled with a single failure. The following single failures were considered in the LOCA analysis:

1. Battery
2. Opposite Unit False LOCA Signal
3. LPCI System Injection Valve EI-9
4. Diesel Generator
5. HPCI ECCS cooling performance must be calculated in accordance with an acceptable evaluation model and must be calculated for a number of postulated loss-of-coolant accidents of different sizes, locations, and other properties sufficient to provide assurance that the most severe postulated loss-of-coolant accidents are calculated.

For peak cladding temperature for GE fuel, the limiting break is a 4.2 sq ft break in a recirculation suction line as documented in NEDC-32484PA and for FANP fuel, the limiting break is a 0.6 sq ft split in a recirculation discharge line as documented in EMF-2950P('3 . Information on GE LOCA models currently in use is given in NEDO-205669 and NEDC-32484PA. LOCA models used for FANP reload fuel analyses are described in EMF-2361PA12 1. Plant specific information on models used and results of the LOCA analysis for the current operating cycle is given in a separate document prepared in conjunction with the reload licensing amendments. Additional information on the sequence of events during a LOCA and the response of the primary containment during a LOCA is given in NEDC-32484PA and NEDO-1032013 1. TVA has recently submitted1 4 1 the results of its current ECCS performance analysis for Unit 2:

FUEL VENDOR FUEL TYPE PCT Global Nuclear Fuels GE13 1810 Global Nuclear Fuels GE14 1760 Framatome Advanced Nuclear Power ATRIUM-10 2007

  • - Note that the value for Framatome fuel was calculated for Extended Power Uprate operation (3,952 MWt). The calculation is bounding for the current Unit 2 thermal power of 3,458 M~t.

The most limiting single failure for BFN is the battery failure.

The current LOCA analysis for a recirculation suction break takes credit only for ADS, 1 LPCS and 2 LPCI (2 pumps into 1 loop).

Whereas, ADS, 1 LPCS and 3 LPCI (3 pumps into 2 loops) would actually be available. Similar robustness is also found if the 1 EMF-2950(P) Revision 0, Browns Ferry Units 1, 2, and 3 Extended Power Uprate LOCA Break Spectrum Analysis, December 2003.

2 EMF-2361 (P)(A) Revision 0, EXEM BWR-2000 ECCS Evaluation Model, Framatome ANP, May 2001.

3 The General Electric Pressure Suppression Containment Analytical Model, NEDO-10320.

4 TVA letter to NRC, dated April 8, 2005, OReport of Emergency Core Cooling System (ECCS)

Evaluation Model Changes.

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battery failure scenario during the recirculation discharge line break. The current LOCA analysis takes credit only for ADS and 1 LPCS. Whereas, ADS, 1 LPCS and 1 LPCI (1 pump into 1 loop) would actually be available. A summary of the ECCS performance was recently submitted to NRC as part of TS 424 (Reference 1) and approved by NRC in Reference 2.

4.2.1.3 System Redundancy, Independence and Diversity As described below, administrative controls ensure system redundancy, independence and diversity are maintained commensurate with the expected frequency and consequences of challenges to the on-site standby power system:

A. Restrictions are placed on simultaneous equipment outages that would erode the principles of redundancy and diversity; B. Voluntary removal of equipment from service is not scheduled when adverse weather conditions are predicted or at times when the plant may be subjected to other abnormal conditions.

These administrative controls are described in more detail below:

A. TVA uses proceduralized risk-based approaches for scheduling maintenance for all modes of plant operation, which limits removal of risk sensitive equipment from service.

SPP 7.1, "Work Control Process", defines the risk assessment methodology that is used for Power Operations (Mode 1) and Startup (Mode 2). For on-line maintenance a risk assessment is performed before implementation and emergent work is evaluated against the assessed scope. For those SSCs modeled in the PSA, the following risk thresholds are established with approval/ actions described below:

  • Incremental core damage probability (ICDP) greater than lE-05 should not be entered voluntarily(RED);
  • ICDP greater than 5E-06 but less than lE-05, assess non quantifiable factors, establish risk management actions per 3.5.2.1 (ORANGE);

ICDP greater than 1E-06 but less than 5E-06, assess non quantifiable factors, establish risk management actions per 3.5.2.1 (YELLOW); and

  • ICDP less than 1E-06, no separate risk management plans or approval are required (GREEN).

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Activities requiring risk management actions include, as appropriate, actions to provide risk awareness and control, actions to reduce duration, and actions to reduce magnitude of risk increase. These actions might include:

  • Discussion of activity with operating shift approval of planned evolution;
  • Pre-job briefing of maintenance personnel emphasizing the risk aspects of the evolution;
  • Presence of appropriate technical personnel for appropriate portions of the activity;
  • Pre-staging of parts and materials;
  • Walk down tagout and activity prior to conducting maintenance;
  • Conduct of training and mock ups to familiarize personnel with the activity;
  • Perform activity around the clock;
  • Establish contingency plans to restore the out of service rapidly, if needed;
  • Minimizing other work in areas that could affect event initiators to decrease the frequency of initiating events mitigated by the safety function served by the out of service SSC;

. Minimize work in areas that could affect other redundant systems such that there is continued likelihood of the availability of the safety functions served by the SSCs in those areas;

. Establishment of alternate success paths for performance of the safety function of the out of service SSC (note; this equipment does not necessarily have to be in the scope of the Maintenance Rule per SPP-6.6); and Risk management plans are required to be approved by senior plant management.

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B. Administrative controls ensure that voluntary removal of equipment from service is not scheduled when adverse weather conditions are predicted or at times when the plant may be subjected to other abnormal conditions.

SPP 7.1, "Work Control Process", requires an assessment of scheduled activities be performed before implementation of a work window. The assessment includes external event considerations involving the potential impacts of weather or other external conditions relative to the proposed maintenance evolution if these external impacts (e.g.,

weather, external flooding, and other external impacts) are imminent or have a high probability of occurring during the planned out of service duration.

4.2.1.4 Potential for Common Cause Failures The proposed extension of the Unit 2 low pressure ECCS injection/spray TS AOT does not add or delete any safety-related systems, equipment, or loads, or alter the design or function of the RHR system. Therefore, the potential for a common cause failure is not increased.

4.2.1.5 Independence of Physical Barriers The proposed extension of the Unit 2 low pressure ECCS injection/spray TS AOT does not affect fuel cladding, primary coolant systems, or containment. Therefore, the independence of physical barriers is not degraded.

4.2.1.6 Defense against Human Error The proposed extension of the Unit 2 low pressure ECCS injection/spray TS AOT does not affect any operator response to a postulated event. Therefore, defenses against human errors are maintained.

4.2.1.7 Compliance with General Design Criteria The affect of the proposed extension of the Unit 2 low pressure ECCS injection/spray TS AOT has no impact on compliance with General Design Criteria as discussed in Section 4.1, Compliance with Current Regulations.

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4.2.2 Safety Margins 4.2.2.1 Codes and Standards The proposed extension of the Unit 2 low pressure ECCS injection/spray TS AOT remains consistent with the codes and standards applicable to the Browns Ferry.

4.2.2.2 Safety Analysis and Final Safety Analysis Report Acceptance Criteria The proposed extension of the Unit 2 low pressure ECCS injection/spray TS AOT is consistent with the safety analysis and UFSAR acceptance criteria.

4.3 Evaluation of Risk Impact 4.3.1 Three Tiered Approach In Regulatory Guide 1.177, the NRC staff identified a three-tiered approach for licensees to evaluate the risk associated with proposed TS AOT changes.

Tier 1 is an evaluation of the impact on plant risk of the proposed TS change as expressed by the change in CDF, the incremental conditional core damage probability (ICCDP), and, when appropriate, the change in LERF and the incremental conditional large early release probability (ICLERP).

Tier 2 is an identification of potentially high-risk configurations that could exist if equipment in addition to that associated with the change were to be taken out of service simultaneously, or other risk-significant operational factors such as concurrent system or equipment testing were also involved. The objective of this part of the evaluation is to ensure that appropriate restrictions on dominant risk-significant configurations associated with the change are in place.

Tier 3 is the establishment of an overall configuration risk management program to ensure that other potentially lower probability, but nonetheless risk-significant configurations resulting from maintenance and other operational activities are identified and appropriate compensation taken. If the Tier 2 assessment demonstrates, with reasonable assurance, that there are no risk-significant configurations involving the subject equipment, the application of Tier 3 to the proposed TS AOT may not be necessary. Although defense in depth is protected to some degree by most current TS, application of the three-tiered approach to risk-informed TS AOT changes discussed below provides EI-14

additional assurance that defense in depth will not be significantly impacted by such changes to the licensing basis.

TVA has evaluated the proposed extension of the TS AOT using the guidance of Regulatory Guide 1.177 and the results are provided below.

A. Tier 1, PSA Capability and Insights Tier 1 is an evaluation of the impact on plant risk of the proposed TS change as expressed by the change in CDF, the ICCDP, and when appropriate, the change in the LERF and ICLERP. The validity of the PSA, the PSA insights and findings, and a discussion of the uncertainty associated Kith these results are presented below.

Validity of the PSA Regulatory Guide 1.174 provides the guidance framework for using PSA in risk-informed decisions for plant-specific changes to the licensing basis. The acceptance guidelines consider the baseline CDF and LERF values as well as the changes to them. The guidance included in Regulatory Guide 1.174 provides a framework in assisting in the interpretation of the numerical results of the PSA.

As stated in Regulatory Guide 1.174:

  • "When the calculated increase in CDF is in the range of 10-6 per reactor year to 10-5 per reactor year, applications will be considered only if it can be reasonably shown that the total CDF is less than 10-4 per reactor year (Region II)."
  • "When the calculated increase in LERF is in the range of 10-7 per reactor year to 10-6 per reactor year, applications would be considered only if it can be reasonably shown that the total CDF is less than 10-5 per reactor year (Region II)."

In order to model the impact of the proposed AOT extension, four models were run:

  • RHR Pump 2A Model (Current situation) - The base case model was revised to reflect 14 days of unavailability.
  • RHR Loop 1 Model (One low pressure ECCS injection/spray subsystem [LPCIJ inoperable) - The base case model was revised to reflect RHR pumps 2A and 2C being unavailable for 14 days.

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  • RHR Pump 2A and 2B Model(One LPCI pump in both LPCI subsystems inoperable) - The base case model was revised to reflect RHR pumps 2A and 2B being unavailable for 14 days.
  • Core Spray Loop 1 (One low pressure ECCS injection/spray subsystem [LPCS] inoperable) - The base case model was revised to reflect LPCS pumps 2A and 2C being unavailable for 14 days.

Insights and Findings The unavailability data was used to quantify the Unit 2 model using RISKMAN software for both the seven day AOT base case and the requested 14-day AOT case for CDF and LERF.

ICCDP is defined by Regulatory Guide 1.177 as:

ICCDP = [(Conditional CDF w/ equipment out of service) -

(Baseline CDF w/ nominal expected equipment unavailabilities)] x (duration under consideration)

The conditional CDF is calculated by multiplying the baseline CDF by the maximum top event Risk Achievement Worth (RAW). For multiple equipment being out of service (e.g.

RHR Loop 1 or Core Spray Loop 1), the conditional CDF and LERF is calculated by quantifying the PSA model with the identified component (top event) failed. The duration of the event under consideration is seven days, which is the difference between the current AOT and the requested AOT (this must be adjusted for the duration on a yearly basis by dividing by 365).

Therefore, ICCDP is derived as:

ICCDP = [(RAW x (Baseline CDF)) - (Baseline CDF)] x (duration under consideration)

Similarly, ICLERP is derived as:

ICLERP = [(RAW x (Baseline LERF)) - (Baseline LERF)] x (duration under consideration)

In order to model the impact of the proposed AOT extension, four additional models were run:

  • The base case model was used to calculate the RAW value for RHR pump 2A. The conditional CDF was then calculated reflecting RHR pump 2A being out of service.

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  • The base case model was revised to reflect RHR loop 1 being out of service and conditional CDF was then calculated.
  • The base case model was revised to reflect RHR pumps 2A and 2B being out of service and conditional CDF was then calculated.
  • The base case model was revised to reflect Core Spray loop 1 being out of service and conditional CDF was then calculated.

The results of the CDF/ICCDP and LERF/ICLERP risk measures calculations are presented below:

DESCRIPTION BASE CASE:- EXTENDEDCASE CHANGE CHANGE CDF lLERF

__ CDF:. LERF  ;DF "' ERF11 ICCDP 2 ) CLERP.:3

)

RHR 2A 1.30E-06 2.99E-07 1.38E-06 3.71E-07 8.58E-08 7.24E-08 4.67E-08 1.41E-08 RHR Loop 1 1.30E-06 2.99E-07 1.38E-06 3.71E-07 8.73E-08 7.23E-08 6.07E-08 9.84E-09 RHR Pumps 2A & 2B 1.30E-06 2.99E-07 1.38E-06 3.71E-07 8.16E-08 7.21E-08 8.98E-08 1.94E-08 Core Spray Loop 1 1.25E-06 2.46E-07 1.26E-06 2.46E-07 1.40E-09 5.OOE-10 2.47E-09 5.43E-11 (1) The changes in CDF and LERF are below the Regulatory Guide 1.174 guidelines of IE-6 for CDF and IE-7 for LERF.

(2) The value for ICCDP is below the Regulatory Guide 1.177 guideline for acceptability of 5.0E-7.

(3) The value for ICLERP is below the Regulatory Guide 1.177 guideline for acceptability of 5.OE-8.

As can be seen from the above table, the change due to extension of the current seven day Unit 2 low pressure ECCS injection/spray AOT to 14 days is not risk significant and is below the NRC acceptance criteria specified in Regulatory Guides 1.174 and 1.177.

B. Tier 2: Avoidance of Risk Significant Configurations As described in Section 4.2.1.3, administrative controls ensure that system redundancy, independence and diversity are maintained commensurate with the expected frequency and consequences of challenges to the ECCS:

  • Restrictions are placed on simultaneous equipment outages that would erode the principles of redundancy and diversity;
  • Voluntary removal of equipment from service is not scheduled when adverse weather conditions are predicted or at times when the plant may be subjected to other abnormal conditions.

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In summary, TVA's administrative controls and evaluations provide reasonable assurance that risk-significant plant equipment outage configurations will not occur as a result of the proposed extension of the Unit 2 low pressure ECCS injection/spray AOT.

C. Tier 3: Risk-Informed Configuration Risk Management Regulatory Guide 1.177 recommends that a formal Tier 3 Configuration Risk Management Program (CRMP) be developed and implemented for systems for which a PSA AOT extension has been granted to identify possible risk significant configurations under Tier 2 that could be encountered over extended periods of time. BFN complies with 10 CFR 50.65(a)(4),"Requirements for monitoring the effectiveness of maintenance at nuclear power plants," which requires that risk assessments be performed on safety-related systems and other systems important to the safe operation of the plant as part of the maintenance process.

The requirements for complying with 10 CFR 50.65(a)(4) are incorporated into SPP-7.1, "Work Control Process" as discussed in Section 4.2.1.3 and are equivalent to the recommended CRMP. Hence, BFN's compliance with 10 CFR 50.65(a)(4), which applies to RHR and many other systems, supersedes the need to have a separate CRMP which applies solely to RHR.

Regulatory Guide 1.177 recommends for the Tier 3 program there be an evaluation of compensatory measures. As described in Section 4.2.1.3, administrative controls ensure that system redundancy, independence and diversity are maintained commensurate with the expected frequency and consequences of challenges to the low pressure ECCS subsystems:

  • Restrictions are placed on simultaneous equipment outages that would erode the principles of redundancy and diversity;
  • Voluntary removal of equipment from service is not scheduled when adverse weather conditions are predicted or at times when the plant may be subjected to other abnormal conditions.

BFN has not identified additional TS restrictions or compensatory measures required to avoid potential risk significant configurations due to the proposed extension of the current seven day Unit 2 low pressure ECCS injection/spray AOT to 14 days.

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4.3.2 Evaluation of PSA Quality The Unit 2 and 3 PSAs are maintained and were updated as recently as early 2003. TVA procedures provide the details describing the use of the PSA at Browns Ferry to support the Maintenance Rule.

The PSA assists in establishing performance criteria, balancing unavailability and reliability for risk significant SSCs and goal setting and provides input to the onsite Expert Panel for the risk significance determination process when revisions to the PSA take place. Functions are potentially considered risk significant if any of the following conditions are satisfied:

- Functions modeled in the level 1 PSA have a risk achievement worth greater than or equal to 2.0;

- Functions modeled in the level 1 PSA have a risk reduction worth of less than or equal to 0.995; or

- Functions modeled in the level 1 PSA have a cumulative contribution of 90% of the CDF.

Because the PSAs are actively used at BFN, a formal process is in place to evaluate and resolve PSA model-related issues as they are identified. The PSA Update Report is evaluated for updating every other refueling outage.

During November 1997, TVA participated in a PSA Peer Review Certification of the Browns Ferry Unit 2 and 3 PSAs administered under the auspices of the BWROG Peer Certification Committee. The purpose of the peer review process is to establish a method of assessing the technical quality of the PSA for its potential applications.

The Peer Review evaluation process utilized a tiered approach using standardized checklists allowing a detailed review of the elements and the sub-elements of the Browns Ferry PSAs to identify strengths and areas that need improvement. The review methodology allowed the Peer Review team to focus on technical issues and to issue their assessment results in the form of a "grade" of 1 through 4 on a PSA sub-element level. To reasonably span the spectrum of potential PSA applications, the four grades of certification as defined by the BWROG document "Report to the Industry on PSA Peer Review Certification Process - Pilot Plant Results" were employed.

The BFN Unit 2 and 3 Peer Review resulted in a consistent evaluation across all elements and sub-elements. Also, during the Unit 2 and 3 PSAs updates in 2003, the significant findings (i.e.,

designated as Level A or B) from the Peer Certification were resolved, resulting in the PSA elements now having a minimum EI-19

certification grade of 3. A copy of the significant peer findings and their disposition was provided in Reference 3.

In summary, TVA concludes the BFN PSA model used for evaluating the risk change in the Unit 2 TS AOT extension request is appropriate and adequate to support the request. NRC has accepted the BFN PSA in previous actions, such as an extension to the Units 2 and 3 Diesel Generator AOT (Reference 4) and Risk Informed In Service Inspection program (Reference 5).

4.4 Summary and Conclusion TVA has evaluated the proposed extension of the Unit 2 low pressure ECCS injection/spray seven day AOT to 14 days both deterministically and through a risk-informed assessment. The deterministic evaluation concluded the proposed change is consistent with the defense-in-depth philosophy, in that:

  • TVA's ECCS is diverse, reliable, has redundancy and is capable of compensating for an out-of-service low pressure ECCS subsystem.

. BFN uses a proceduralized risk-based approach for scheduling maintenance, which limits removal of risk sensitive equipment from service during outages.

The deterministic evaluation concluded that the proposed change to the Unit 2 low pressure ECCS injection/spray AOT will not adversely affect any of the safety analyses assumptions or conclusions described in the UFSAR. This ensures the protection of the public health and safety.

The risk-informed assessment concluded the increase in plant risk is small. The proposed change results in small increases, within acceptable guidelines, in the Unit 2 Conditional Core Damage Probability and the Conditional Large Early Release Probability.

The proposed change is consistent with:

  • The NRC's "Safety Goals for the Operations of Nuclear Power Plants; Policy Statement," Federal Register, Volume 51, Page 30028 (51 FR 30028), dated August 4, 1996;

. Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," Revision 1; and

. Regulatory Guide 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications,"

Revision 1.

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When taken together, the results of the deterministic evaluation and risk-informed assessment provide a high degree of assurance the equipment required to safely shutdown the plant and mitigate the effects of a design basis accident or transient will remain capable of performing their safety function when a Unit 2 low pressure ECCS injection/spray subsystem is out of service for maintenance or repairs in accordance with the proposed AOT.

5.0 REGULATORY SAFETY ANALYSIS The Tennessee Valley Authority (TVA) is submitting an amendment request to license DPR-52 for the Browns Ferry Nuclear Plant Unit 2.

The proposed change revises the current Unit 2 low pressure Emergency Core Cooling System (ECCS) injection/spray seven day allowed outage time (AOT) to 14 days. The proposed change provides additional flexibility for preventive or corrective maintenance and repair of the Residual Heat Removal or Low Pressure Core Spray pumps and other supporting equipment.

5.1 No Significant Hazards Consideration TVA has evaluated whether or not a significant hazards consideration is involved with the proposed amendment by focusing on the three standards set forth in 10 CFR 50.92, "Issuance of amendment", as discussed below:

1. Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No The low pressure ECCS subsystems are designed to reflood the reactor vessel after a design basis Loss of Coolant Accident (LOCA). The proposed 14 day AOT does not change the conditions, operating configurations, or minimum amount of operating equipment assumed in the safety analysis for accident mitigation. No changes are proposed in the manner in which the ECCS provides plant protection or which create new modes of plant operation. In addition, a Probabilistic Safety Assessment (PSA) evaluation concluded that the risk contribution of the AOT extension is non-risk significant.

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The proposed request will not affect the probability of any event initiators. There will be no degradation in the performance of, or an increase in the number of challenges imposed on, safety related equipment assumed to function during an accident situation. There will be no change to normal plant operating parameters or accident mitigation performance.

Therefore, the proposed amendment does not involve a significant increase in the probability or consequences of an accident previously evaluated.

2. Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No There are no hardware changes nor are there any changes in the method by which any plant system performs a safety function. This request does not affect the normal method of plant operation.

The proposed amendment does not introduce new equipment, which could create a new or different kind of accident.

No new external threats, release pathways, or equipment failure modes are created. No new accident scenarios, transient precursors, failure mechanisms, or limiting single failures are introduced as a result of this request. Therefore, the implementation of the proposed amendment will not create a possibility for an accident of a new or different type than those previously evaluated.

3. Does the proposed amendment involve a significant reduction in a margin of safety?

Response: No BFN's ECCS is designed with sufficient redundancy such that a low pressure ECCS subsystem may be removed from service for maintenance or testing. The remaining subsystems are capable of providing water and removing heat loads to satisfy the UFSAR requirements for accident mitigation or unit safe shutdown.

A PSA evaluation concluded that the risk contribution of the AOT extension is non-risk significant.

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There will be no change to the manner in which safety limits or limiting safety system settings are determined nor will there be any change to those plant systems necessary to assure the accomplishment of protection functions. There will be no change to post-LOCA peak clad temperatures. For these reasons, the proposed amendment does not involve a significant reduction in a margin of safety.

Based on the above, TVA concludes that the proposed amendment presents no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

5.2 Applicable Regulatory Requirements/Criteria The performance of the ECCS was analyzed using the approved LOCA application methodology. The requirements of 10 CFR 50.46 and Appendix K are met.

Browns Ferry was constructed before the General Design Criteria (GDC) of 10 CFR 50 were promulgated. However, the applicable GDC to this proposed change are:

. GDC 35, "Emergency Core Cooling," requires that a system be provided for abundant emergency core cooling. The GDC requires redundancy be provided such that the safety function of the ECCS shall be met while energized from either offsite or onsite power, assuming a single failure.

requires the ECCS to be designed to permit periodic inspections.

. GDC 37, "Testing of Emergency Core Cooling System," requires the ECCS to be designed to permit periodic demonstrations of the full operational sequence that brings the system into operation.

There have been no changes to the ECCS design such that conformance to any of the above regulatory requirements and criteria would be changed. This emergency amendment application revises the current Unit 2 low pressure ECCS injection/spray seven day AOT to 14 days. The discussions under Section 4.0, Safety Analysis, provide the justification for granting this emergency amendment application.

ECCS system maintenance activities are appropriately controlled as required by 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." SPP 6.6, EI-23

"Maintenance Rule Performance Indicator Monitoring, Trending and Reporting - 10 CFR 50.65," Technical Procedure NETP-100, "Emergency Diesel Generator Reliability Program" and Technical Instruction 0-TI-346, "Maintenance Rule Performance Indicator Monitoring, Trending, And Reporting - 10 CFR 50.65," provide guidance for analysis, retrieval, trending, and reporting of data relative to plant level, function specific, and repetitive preventable functional failure indicators of performance required by the Maintenance Rule. The requirements of these procedures are in compliance with 10 CFR 50.65, and NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."

RGs 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis", and 1.177, "An Approach for Using Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications" provide NRC guidance regarding the use of PSA to support TS changes for extended TS AOT and extended surveillance test intervals.

BFN has an active and comprehensive risk management program. For on-line maintenance, risk is controlled through a 12 week rolling schedule. A schedule of sequenced work windows is established for on-line periods when combinations of plant systems can acceptably be out of service to perform preventative maintenance and surveillance activities. The predetermined work windows incorporate risk assessments to determine potential impacts to the safe and reliable operation of the unit and assure long-term maintenance activities are performed within required frequencies to maximize plant equipment availability.

In conclusion, based on the considerations discussed above, (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendment will not be inimical to the common defense and security or the health and safety of the public.

6.0 ENVIRONMENTAL CONSIDERATION

A review has determined that the proposed amendment would change a requirement with respect to installation or use of a facility component located within the restricted area, as defined in 10 CFR 20, or would change an inspection or surveillance requirement. However, the proposed amendment does not involve (i) a significant hazards consideration, (ii) a significant change in the types or significant increase in the amounts of any EI-24

effluent that may be released offsite, or (iii) a significant increase in individual or cumulative occupational radiation exposure. Accordingly, the proposed amendment meets the eligibility criterion for categorical exclusion set forth in 10 CFR 51.22(9). Therefore, pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment need be prepared in connection with the proposed amendment.

7.0 REFERENCES

1. TVA letter to NRC, dated April 11, 2003, Browns Ferry Nuclear Plant (BFN) - Units 1, 2 and 3 - License Amendments and Technical Specification Changes - Revision in the Number of Emergency Core Cooling Systems Required in Response to a Loss of Coolant Accident (TS-424).
2. NRC letter to TVA, dated April 1, 2004, Browns Ferry Nuclear Plant, Units 1, 2 and 3 - Issuance of Amendments regarding the Emergency Core Cooling Systems (TAC Nos. MB8423, MB8424 and MB8425) (TS-424).
3. TVA letter to NRC, "Browns Ferry Nuclear Plant (BFN) -

Unit 1 - Response to Request for Additional Information to Generic Letter 88-20, Individual Plant Examination for Severe Accident Vulnerability (TAC No. MC1895)," August 17, 2004.

4. NRC letter to TVA, "Brown Ferry Nuclear Amendments Regarding Authorization of 14-Day Allowable Outage Time for Emergency Diesel Generators (TAC Nos. M98205 and M98206),"

August 2, 1999.

5. NRC letter to TVA, "Browns Ferry Nuclear Plant (BFN) -

Unit 2 - American Society of Mechanical Engineers (ASME)

Section XI, Inservice Inspection and System Pressure Test Programs for the Third Ten-Year Inspection Interval (TAC No.

MB0400)," February 5, 2001.

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Enclosure 2 Ferry Nuclear Plant (BFN) Unit 2 Technical Specification (TS) Change TS 452 Revision to Emergency Core Cooling System (ECCS)

Allowed Outage Time Proposed Technical Specification Changes (mark-up)

ECCS - Operating 3.5.1 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM 3.5.1 ECCS - Operating LCO 3.5.1 Each ECCS injection/spray subsystem and the Automatic Depressurization System (ADS) function of six safety/relief valves shall be OPERABLE.

APPLICABILITY: MODE 1, MODES 2 and 3, except high pressure coolant injection (HPCI) and ADS valves are not required to be OPERABLE with reactor steam dome pressure < 150 psig.

ACTIONS

_____-__- __--------------------------------------- IN I-------____-_________________

LCO 3.0.4.b is not applicable to HPCI.

CONDITION REQUIRED ACTION COMPLETION TIME A. One low pressure ECCS A.1 Restore low pressure days injection/spray subsystem ECCS injection/spray inoperable. subsystem(s) to OPERABLE status.

OR One low pressure coolant injection (LPCI) pump in both LPCI subsystems inoperable.

(continued)

BFN-UNIT 2 3.5-1 Amendment No. 253, 269, 286 December 1, 2003

Enclosure 3 Ferry Nuclear Plant (BFN) Unit 2 Technical Specification (TS) Change TS 452 Revision to Emergency Core Cooling System (ECCS)

Allowed Outage Time Proposed Technical Specification Changes (retyped)

3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM 3.5.1 ECCS - Operating LCO 3.5.1 Each ECCS injection/spray subsystem and the Automatic Depressurization System (ADS) function of six safety/relief valves shall be OPERABLE.

APPLICABILITY: MODE 1, MODES 2 and 3, except high pressure coolant injection (HPCI) and ADS valves are not required to be OPERABLE with reactor steam dome pressure < 150 psig.

ACTIONS

r'uI Ir--------------------------------------------------

LCO 3.0.4.b is not applicable to HPCI.

CONDITION REQUIRED ACTION COMPLETION TIME A. One low pressure ECCS A.1 Restore low pressure 14 days injection/spray subsystem ECCS injection/spray inoperable. subsystem(s) to OPERABLE status.

OR One low pressure coolant injection (LPCI) pump in both LPCI subsystems inoperable.

(continued)

BFN-UNIT 2 3.5-1 Amendment No. 253, 269, 286 December 1, 2003

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