Text

Proposed Tech Specs & Bases Pages Incorporating NRC Approved TS Change 354,requiring Oscillation PRM to Be Integrated Into Approved Power uprate,24-month Operating Cycle & Single Recirculation Loop Operation
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Issue date:	02/22/1999
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ENCLOSURE 1 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)

UNIT 2 TS-354 CLEAN PAGES 9903090022 990222 eOa aDOCX OSOOoaSO t PDR .'

Technical Specification 354 Unit 2 Remove Insert 3~3 1 3.3-1 3 3 2

~ 3~3 2 3~3 3 3 3 3

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3.3-6 3.3-6 3.3-8 3.3-8 3.3-9 3.3-9 3.4"1 3.4-1 3.4-2 3.4-2 3.4-3 3.4-3 3.4-4 3.4-4 B 3 '-9 B 3.3-9 B 3.3-9a B 3 '-14 B 3.3-14 B 3.3-15 B 3.3-15 B 3.3-15a B 3.3-15b B 3.3-30 B 3.3-30 B 3.3-32 B 3.3-32 B 3.3-34 B 3 '-34 B 3.3-35 B 3.3-35 B 3.3-35a B 3.3-44 B 3.3-44 B 3.3-45a B 3.3-46 B 3.3-46 B 3.3-46a B 3.4-4 B 3.4-4 B 3.4-5 B 3.4-5 B 3.4-5(1)

B 3.4-5a B 3.4-6 B 3.4-6 B 3.4-7 B 3.4-7 B 3.4-8 B 3.4-8 B 3.4-9 B 3.4-9 B 3.4-10 B 3.4-10

RPS Instrumentation 3.3.1.1 3.3 INSTRUMENTATION 3.3.1.1 Reactor Protection System (RPS) Instrumentation LCO 3.3.1.1 The RPS instrumentation for each Function in Table 3.3.1.1-1 shall be OPERABLE.

APPLICABILITY: According to Table 3.3.1.1-1.

ACTIONS NOTE Separate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETION TIME A. One or more required A.1 Place channel in trip. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months channels inoperable.

OR A.2 NOTE Not applicable for Functions 2.a, 2.b, 2.c, 2.d, or 2.f.

Place associated trip 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months system in trip.

(continued)

BFN-UNIT 2 3.3 1 Amendment No. 258

RPS Instrumentation 3.3.1.1 ACTIONS continued CONDITION REQUIRED ACTION COMPLETION TIME B. NOTE B.1 Place channel in one trip 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Not applicable for system in trip.

Functions 2.a, 2.b, 2.c, 2.d, or 2.f. OR B.2 Place one trip system in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months One or more Functions trip.

with one or more required channels inoperable in both trip systems.

C. One or more Functions C.1 Restore RPS trip 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months with RPS trip capability capability.

not maintained.

D. Required Action and D.1 Enter the Condition Immediately associated Completion referenced in Time of Condition A, B, or Table 3.3.1.1-1 for the C not met. channel.

E. As required by Required E.1 Reduce THERMAL 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Action D.1 and (

POWER to 30% RTP.

referenced in Table 3.3.1 1-1.

~

F. As required by Required F.1 Be in IVIODE 2. 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Action D.1 and referenced in Table 3.3.1 1-1

~ ~

(continued)

BFN-UNIT 2 3.3-2 Amendment No. 258

RPS Instrumentation 3.3.1.1 ACTIONS continued CONDITION REQUIRED ACTION COMPLETION TIME, G. As required by Required G.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Action D.1 and referenced in Table 3.3.1.1-1.

H. As required by Required H.1 Initiate action to fully Immediately Action D.1 and insert all insertable referenced in control rods in core cells Table 3.3.1.1-1. containing one or more fuel assemblies.

I~ As required by Required l.1 Initiate alternate method 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Action D.1 and to detect and suppress referenced in Table thermal hydraulic 3.3.1.1-1. instability oscillations.

AND l.2 Restore required 120 days channels to OPERABLE.

J. Required Action and J.1 Be in Mode 2. 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months associated Completion Time of Condition I not met.

BFN-UNIT 2 3.3-3 Amendment No. 258

RPS Instrumentation 3.3.1.1 SURVEILLANCE REQUIREMENTS continued SURVEILLANCE FREQUENCY SR 3.3.1.1.10 Perform CHANNEL CALIBRATION. 184 days SR 3.3.1.1.11 (Deleted)

SR 3.3.1.1.12 Perform CHANNEL FUNCTIONALTEST. 24 months SR 3.3.1.1 13

~ NOTE Neutron detectors are excluded.

Perform CHANNEL CALIBRATION. 24 months SR 3.3.1.1.14 Perform LOGIC SYSTEM FUNCTIONAL 24 months TEST.

SR 3.3.1.1.15 Verify Turbine Stop Valve - Closure and 24 months Turbine Control Valve Fast. Closure, Trip Oil Pressure - Low Functions are not bypassed when THERMAL POWER is 30% RTP. t SR 3.3.1.1.16 NOTE For Function 2.a, not required to be performed when entering MODE 2 from MODE 1 until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering MODE 2.

Perform CHANNEL FUNCTIONALTEST. 184 days SR 3.3.1.1.17 Verify OPRM is not bypassed when APRM. 24 months Simulated Thermal Power is a 25% and recirculation drive flow is (60% of rated recirculation drive flow.

BFN-UNIT.2 3.3-6 Amendment No. 258

RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 2 of 3)

Reactor Protection System Instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED FUNCTION OTHER CHANNELS FROM SURVEILLANCE ALLOWABLE SPECIFIED PER TRIP REQUIRED REQUIREMENTS VALUE CONDITIONS SYSTEM ACTION D.1

2. Average Power Range Monitors (continued)

d. In op 12 3(b) G SR 3.3.1.1.16 NA

e. 2-Out-Ofd Voter 12 SR 3.3.1.1.1 NA SR 3.3.1.1.14 SR 3.3.1.1.16

f. OPRM Upscale 3(b) SR 3.3.1.1.1 NA SR 3.3.1.1.7 SR 3.3.1.1.13 SR 3.3.1.1.16 SR 3.3.1.1.17

3. Reactor Vessel Steam Dome 1,2 SR 3.3.1.1.1, 5 1090 pslg Pressure - High SR 3.3.1.1.8 SR 3.3.1.1.10 SR 3.3.1.1.14

4. Reactor Vessel Water Level- 12 SR 3.3.1.1.1 h 538 inches Low, Level 3 SR 3.3.1.1.8 above vessel SR 3.3.1.1.13 zero SR 3.3.1.1.14

5. Main Steam Isolation Valve- SR 3.3.1.1.8 5 10% closed Closure SR 3.3.1.1.13 SR 3.3.1.1.14

6. Drywall Pressure - High 1.2 SR 3.3.1.1.8 52.5 psig SR 3.3.1.1.13 SR 3.3.1.1.14

7. Scram Discharge Volume Water Level - High

a. Resistance Temperature 1,2 SR 3.3.1.1.8 S 50 gallons Detector "SR 3.3.1.1.13 SR 3.3.1.1.14 5(a) H SR 3.3.1.1.8 s 50 gallons SR 3.3.1.1.13 SR 3.3.1.1.14 continued (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

(b) Each APRM channel provides Inputs to both trip systems.

BFN-UNIT 2 3.3-8 .Amendment No. 258

RPS Instrumentation 3.3.1.1 Table 3.3.1.1-1 (page 3 of 3)

Reactor Protection System instrumentation APPLICABLE CONDITIONS MODES OR REQUIRED REFERENCED FUNCTION OTHER CHANNELS FROM SURVEILLANCE ALLOWABLE SPECIFIED PER TRIP REQUIRED REQUIREMENTS VALUE CONDITIONS SYSTEM ACTION D.1

7. Scram Discharge Volume Water Level - High (continued)

b. Float Switch 1,2 SR 3.3.1.1.8 5 50 gallons SR 3.3.1.1.13 SR 3.3.1.1.14 5(a) SR 3.3.1.1.8 S 50 gallons SR 3.3.1.1.13 SR 3.3.1.1.14

8. Turbine Stop Valve - Closure 230% RTP 4 - E SR 3.3.1.1.8 5 10% closed SR 3.3.1.1.13 SR 3.3.1.1.14 SR 3.3.1.1.15

9. Turbine Control Valve Fast a 30% RTP SR 3.3.1.1.8 Closure, Trip Oil Pressure- SR 3.3.1.1.13 Low SR 3.3.1.1.14 SR 3.3.1.1.15

10. Reactor Mode Switch- 1,2 SR 3.3.1.1.12 NA Shutdown Position 'R 3.3.1.1.14 5(a) SR 3.3.1.1.12 NA SR 3.3.1.1.14

11. Manual Scram 1,2 SR 3.3.1.1.8 NA SR 3.3.1.1.14 5(a) SR 3.3.1.1.8 NA SR 3.3.1.1.14

12. RPS Channel Test Switches 1,2 SR 3.3.1.1.4 NA 5(a) SR 3.3.1.1.4

13. Low Scram Pilot Air Header 12 G SR 3.3.1.1.13 Pressure SR 3.3.1.1.14 SR 3.3.1.1.16 5(a) SR 3.3.1.1.13 2 50 psig SR 3.3.1.1.14 SR 3.3.1.1.16 (a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

8FN-UNIT 2 3.3-9 Amendment No. 258

ecirculation Loops Operating 3.4.1 3.4 REACTOR COOLANT SYSTEM (RCS) 3.4.1 Recirculation Loops Operating LCO 3.4.1 Two recirculation loops with matched flows shall be in operation.

OR One recirculation loop may be in operation provided the following'imits are applied when the associated LCO is applicable:

a. LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)," single loop operation limits specified in the COLR;

b. LCO 3.2.2, "MINIMUMCRITICAL POWER RATIO (MCPR),"

single loop operation limits specified in the COLR;

c. LCO 3.3.1.1, "Reactor Protection System (RPS)

Instrumentation," Function 2.b (Average Power Range Monitors Flow Biased Simulated Thermal Power - High), Allowable Value of Table 3.3.1.1-1 is reset for single loop operation; APPLICABILITY: MODES 1 and 2.

BFN-UNIT 2 3.4-1 Amendment No. 258

ecirculation Loops Operating 3.4.1 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Requirements of the LCO A.1 Satisfy the requirements 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months not met. of the LCO.

B. Required Action and B.1 Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time of Condition A not met.

OR No recirculation loops in operation.

BFN-UNIT 2 3.4-2 Amendment No. 258

C

'I

ecirculation Loops Operating 3 4.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 3.4.1.1 NOTE Not required to be performed until 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both recirculation loops are in operation.

Verify recirculation loop jet pump flow 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months mismatch with both recirculation loops in operation is:

a. s 10% of rated core flow when operating at ( 70% of rated core flow; and I

b. 6 5% of rated core flow when operating at a 70% of rated core flow.

BFN-UNIT 2 3.4-3 Amendment No. 258

ecirculation Loops Operating 3.4.1 Figure 3.4.1-1 (Deleted Per TS 354)

BFN-UNIT 2 3.4-4 Amendment No. 258

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE Avera e Power Ran e Monitor SAFETYANALYSES, LCO, and The APRM channels provide the primary indication of neutron APPLICABILITY flux within the core and respond almost instantaneously to (continued) neutron flux increases. The APRM channels receive input signals from the local power range monitors (LPRMs) within the reactor core to provide an indication of the power distribution and local power changes. The APRM channels average these LPRM signals to provide a continuous indication of average reactor power from a few percent to greater than RTP. Each APRM also includes an Oscillation Power Range Monitor (OPRM) Upscale Function which monitors small groups of LPRM signals to detect thermal hydraulic instabilities.

The APRM System is divided into four APRM channels and four 2-out-of-4 voter channels. Each APRM channel provides inputs to each of the four voter channels. The four voter channels are divided into two groups of two each, with each group of two providing inputs to one RPS trip system. The system is designed to allow one APRM channel, but no voter channels, to be bypassed. A trip from any one unbypassed APRM will result in a "half-trip" in all four of the voter channels, but no trip inputs to either RPS trip system. APRM trip Functions 2.a, 2.b, 2.c, and 2.d are voted independently from OPRM Upscale Function 2.f. Therefore, any Function 2.a, 2.b, 2.c, or 2.d trip from any '.

two unbypassed APRM channels will result in a full trip in each of the four voter channels, which in turn results in two trip inputs to each RPS trip system logic channel (A1, A2, B1, or, 82).

Similarly, a Function 2.f trip from any two unbypassed APRM channels will result in a full trip from each of the four voter channels. Three of the four APRM channels and all four of the voter channels are required to be OPERABLE to ensure that no single failure will preclude a scram on a valid signal. In addition, to provide adequate coverage of the entire core, consistent with the design bases for the APRM Functions 2.a, 2.b, and 2.c, at least twenty (20) LPRM inputs, with at least continued BFN-UNIT 2 8 3.3-9 Amendment No. 258

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE Avera e Power Ran e Monitor (continued)

SAFETYANALYSES, LCO, and three (3) LPRM inputs from each of the four axial levels at APPLICABILITY which the LPRMs are located, must be operable for each APRM channel. For the OPRM Upscale Function 2.f, LPRMs are assigned to "cells" with either 3 or 4 detectors, with a total of 33 "cells" assigned to each OPRM channel. A minimum of 23 cells, each with a minimum of 2 LPRMs must be OPERABLE for the OPRM Upscale Function 2.f to be OPERABLE.

continued BFN-UNIT 2 B 3.3-9a Amendment No. 258

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.d. Avera e Power Ran e Monitor - tno SAFETY ANALYSES, LCO, and Three of the four APRIVI channels are required to be APPLICABILITY OPERABLE for each of the APRM Functions. This Function (continued) (Inop) provides assurance that the minimum number of APRMs are OPERABLE. For any APRM channel, any time its mode switch is in any position other than "Operate," an APRM module is unplugged, or the automatic self-test system detects a critical fault with the APRM channel, an Inop trip is sent to all four voter channels. Inop trips from two or more unbypassed APRM channels result in a trip output from all four voter channels to their associated trip system.

This Function was not specifically credited in the accident analysis, but it is retained for the overall redundancy and diversity of the RPS as required by the NRC approved licensing basis.

There is no Allowable Value for this Function.

This Function is required to be OPERABLE in the MODES where the APRM Functions are required.

continued BFN-UNIT 2 B 3.3-14 Amendment No. 258

RPS Instrumentation 8 3.3.1.1 BASES APPLICABLE 2.e. 2-Out-Of-4 Voter SAFETY ANALYSES, LCO, and The 2-Out-Of-4 Voter Function provides the interface between APPLICABILITY the APRM Functions, including the OPRM Upscale Function, (continued) and the final RPS trip system logic. As such, it is required to be OPERABLE in the MODES where the APRM Functions are required and is necessary to support the safety analysis applicable to each of those Functions. Therefore, the 2-Out-Of-4 Voter Function needs to be OPERABLE in MODES 1 and 2.

All four voter channels are required to be OPERABLE. Each voter channel includes self-diagnostic functions. If any voter channel detects a critical fault in its own processing, a trip is issued from that voter channel to the associated trip'system.

The 2-Out-Of-4 Voter Function votes APRM Functions 2.a, 2.b, 2.c, and 2.d independently of Function 2.f. The voter also includes separate outputs to RPS for the two independently voted sets of Functions, each of which is redundant (four total outputs). The Voter Function 2.e must be declared inoperable if any of its functionality is inoperable. However, due to the independent voting of APRM trips, and the redundancy of outputs, there may be conditions where the Voter Function 2.e is inoperable, but trip capability for one or more of the other APRM Functions through that voter is still maintained. This may be considered when determining the condition of other APRM Functions resulting from partial inoperability of the Voter Function 2.e.

There is no Allowable Value for this Function.

continued BFN-UNIT 2 B 3.3-15 Amendment No. 258

.4 RPS Instrumentation B 3.3.1.1 BASES APPLICABLE 2.f. Oscillation Power Ran e Monitor OPRM U scale SAFETYANALYSES, LCO, and The OPRIVI Upscale Function provides compliance with GDC 10 APPLICABILITY and GDC 12, thereby providing protection from exceeding the (continued) fuel MCPR safety limit (SL) due to anticipated thermal hydraulic power oscillations.

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

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

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

The OPRM Upscale Function is required to be OPERABLE when the plant is in a region of power flow operation where anticipated events could lead to thermal hydraulic instability and related neutron flux oscillations. Within this region, the automatic trip is enabled when THERMAL POWER, as indicated by the APRM Simulated Thermal Power, is z 25%

RTP and reactor core flow, as indicated by recirculation drive flow is ( 60% of rated flow, the operating region where actual thermal hydraulic oscillations may occur. Requiring the OPRM Upscale Function to be OPERABLE in MODE 1 provides consistency with operability requirements for other APRM functions and assures that the OPRM Upscale Function is OPERABLE whenever reactor power could increase into the region of concern without operator action.

continued BFN-UNIT 2 8 3.3-15a Amendment No. 258

RPS Instrumentation 8 3.3.1.1 BASES APPLICABLE 2.f. Oscillation Power Ran e Monitor OPRM U scale SAFETY ASAAYSES~ti d LCO, and

,APPLICABILITY An OPRM U p scale trip is issued from an APRM charm el when the period based detection algorithm in that channel detects oscillatory changes in the neutron flux, indicated by the combined signals of the LPRM detectors in a cell, with period confirmations and relative cell amplitude exceeding specified setpoints. One or more cells in a channel exceeding the trip conditions will result in a channel trip. An OPRM Upscale trip is also issued from the channel if either the growth rate or amplitude based algorithms detect growing oscillatory changes in the neutron flux for one or more cells in that channel.

Three of the four channels are required to be OPERABLE.

Each channel is capable of detecting thermal hydraulic instabilities, by detecting the related neutron flux oscillations, and issuing a trip signal before the MCPR SL is exceeded.

There is no allowable value for this function.

continued BFN-UNIT 2 B 3.3-15b Amendment No. 258

RPS Instrumentation B 3.3.1.1 BASES ACTIONS A.1 and A.2 (continued) 1 Because of the diversity of sensors available to provide trip signals and the redundancy of the RPS design, an allowable out of service time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months has been shown to be acceptable (Ref. 9 and 12) to permit restoration of any inoperable channel to OPERABLE status. However, this out of service time is only acceptable provided the associated Function's inoperable channel is in one trip system and the Function still maintains RPS trip capability (refer to Required Actions B.1, B.2, and C.1 Bases). If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel or the associated trip system must be placed in the tripped condition per Required Actions A.1 and A.2. Placing the inoperable channel in trip (or the associated trip system in trip) would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.

Alternatively, if it is not desired to place the channel (or trip system) in trip (e.g., as in the case where placing the inoperable channel in trip would result in a full scram),

Condition D must be entered and its Required Action taken.

As noted, Action A.2 is not applicable for APRM Functions 2.a, 2.b, 2.c, 2.d, cr 2.f. Inoperability of one required APRM channel affects both trip systems. For that condition, Required Action A.1 must be satisfied, and is the only action (other than restoring operability) that will restore capability to accommodate a single failure.

Inoperability of more than one required APRM channel of the same trip function results in loss of trip capability and entry into Condition C, as well as entry into Condition A for each channel.

continued BFN-UNIT 2 B 3.3-30 Amendment No. 258

f RPS Instrumentation B 3.3.1.1 BASES ACTIONS B.1 and 8.2 (continued)

The 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months Completion Time is judged acceptable based on the remaining capability to trip, the diversity of the sensors available to provide the trip signals, the low probability of extensive numbers of inoperabilities affecting all diverse Functions, and the low probability of an event requiring the initiation of a scram.

Alternately, if it is not desired to place the inoperable channels (or one trip system) in trip (e.g., as in the case where placing

- the inoperable channel or associated trip system in trip would result in a scram or RPT), Condition D must be entered and its Required Action taken.

As noted, Condition B is not applicable for APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f. Inoperability of an APRM channel affects both trip systems and is not associated with a specific trip system as are the APRM 2-out-of-4 voter and other non-APRM channels for which Condition 8 applies. For an inoperable APRM channel, Required Action A.1 must be satisfied, and is the only action (other than restoring operability) that will restore capability to accommodate a single failure.

Inoperability of a Function in more than one required APRIVI channel results in loss of trip capability for that Function and entry into Condition C, as well as entry into Condition A for each channel. Because Conditions A and C provide Required Actions that are appropriate for the inoperability of APRM Functions 2.a, 2.b, 2.c, 2.d, or 2.f; and these functions are not associated with specific trip systems as are the APRM 2-out-of-4 voter and other non-APRM channels, Condition B does not apply.

continued BFN-UNIT 2 8 3.3-32 Amendment No. 258

RPS Instrumentation 8 3.3.1.1 BASES ACTIONS D.1 (continued)

Required Action D.1 directs entry into the appropriate Condition referenced in Table 3.3.1.1-1. The applicable Condition specified in the Table is Function and MODE or other specified condition dependent.and may change, as the Required Action of a previous Condition is completed. Each time an inoperable channel has not met any Required Action of Condition A, B, or C and the associated Completion Time has expired, Condition D will be entered for that channel and provides for transfer to the appropriate subsequent Condition.

E.1 F.1 G.1 and J.1 If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply.

The allowed Completion Times are reasonable, based on operating experience, to reach the specified condition from full power conditions in an orderly manner and without challenging plant systems. In addition, the Completion Time of Required Action E.1 is consistent with the Completion Time provided in LCO 3.2.2, "MINIMUIVlCRITICAL POWER RATIO (MCPR)."

continued BFN-UNIT 2 B 3.3-34 Amendment'No. 258

RPS Instrumentation B 3.3.1.1 BASES ACTIONS (continued)

If the channel(s) is not restored to OPERABLE status or placed in trip (or the associated trip system placed in trip) within the allowed Completion Time, the plant must be placed in a MODE or other specified condition in which the LCO does not apply..

This is done by immediately initiating action to fully insert all insertable control rods in core cells containing one or more fuel assemblies. Control rods in core cells containing no fuel assemblies do not affect the reactivity of the core and are, therefore, not required to be inserted. Action must continue until all insertable control rods in core cells containing one or more fuel assemblies are fully inserted.

If OPRM Upscale trip capability is not maintained, Condition I exists. Reference 12 justified use of alternate methods to detect and suppress oscillations for 'a limited period of time.

The alternate methods are procedurally established consistent with the guidelines identified in Reference 17 requiring manual operator action to scram the plant if certain predefined events occur. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowed action time is based on engineering judgment to allow orderly transition to the alternate methods while limiting the period of time during which no automatic or alternate detect and suppress trip capability is formally in place. Based on the small probability of an instability event occurring at all, the 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is judged to be reasonable.

continued BFN-UNIT 2 B 3.3-35 Amendment No. 258

RPS Instrumentation B 3.3.1.1 BASES ACTIONS I.2 (continued)

The alternate method to detect and suppress oscillations implemented in accordance with I.1 was evaluated (Reference

12) based on use up to 120 days only. The evaluation, based on engineering judgment, concluded that the likelihood of an .

instability event that could not be adequately handled by the alternate methods during this 120 day period was negligibly small. The 120 day period is intended to be an outside limit to allow for the case where design changes or extensive analysis might be required to understand or correct some unanticipated characteristic of the instability detection algorithms or equipment. This action is not intended and was not evaluated as a routine alternative to returning failed or inoperable equipment to OPERABLE status. Correction of routine equipment failure or inoperability is expected to normally be accomplished within the completion times allowed for Actions for Conditions A and B.

SURVEILLANCE As noted at the beginning of the SRs, the SRs for each RPS REQUIREMENTS instrumentation Function are located in the SRs column of Table 3.3.1.1-1.

The Surveillances are modified by a Note to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , provided the associated Function maintains RPS trip capability. Upon completion of the Surveillance, or expiration of the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken. This Note is based on the reliability analysis (Ref. 3) assumption of the average time required to perform channel Surveillance. That analysis demonstrated that the 6 hour6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months testing allowance does not significantly reduce the probability that the RPS will trip when necessary.

continued BFN-UNIT 2 B 3.3-35a Amendment No. 258

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.11 REQUIREMENTS (continued) (Deleted)

SR 3.3.1.1.14 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITYof the required trip logic for a specific channel.

The functional testing of control rods (LCO 3.1.3), and SDV vent and drain valves (LCO 3.1.8), overlaps this Surveillance to provide complete testing of the assumed. safety function.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

Operating experience with these components supports performance of the Surveillance at the 24 month Frequency.

The LOGIC SYSTEM FUNCTIONALTEST for APRM Function 2.e simulates APRM and OPRM trip conditions at the 2-out-of-4 voter channel inputs to check all combinations of two tripped inputs to the 2-out-of-4 logic in the voter channels and APRM related redundant RPS relays.

continued BFN-UNIT 2 B 3.3-44 Amendment No. 258

RPS Instrumentation 8 3.3.1.1 BASES SURVEILLANCE SR 3.3.1.1.17 REQUIREMENTS (continued) This SR ensur es that scrams initiated from OPRM Upscale Function'(Function 2.f) will not be inadvertently bypassed when THERMAL POWER, as indicated by the APRM Simulated Thermal Power, is a 25% RTP and core flow, as indicated by recirculation .

drive flow, is ( 60% rated core flow. This normally involves confirming the bypass setpoints. Adequate margins for the setpoint methodologies are incorporated into the actual

'nstrument setpoint. The actual surveillance ensures that the OPRM Upscale Function is enabled (not bypassed) for the correct values of APRM Simulated Thermal Power and recirculation drive flow. Other surveillances ensure that the APRM Simulated Thermal Power and recirculation flow properly correlate with THERMAL POWER and core flow, respectively.

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

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

(continued)

BFN-UNIT 2 B 3.3-45a Amendment No. 258

RPS Instrumeritation B 3.3.1.1 BASES (continued)

REFERENCES 1. FSAR, Section 7.2.

2. FSAR, Chapter 14.

3. NEDO-23842, "Continuous Control Rod Withdrawal in the Startup Range," April 18, 1978.

4. FSAR, Appendix N.

5. FSAR, Section 14.6.2.

6. FSAR, Section 6.5.

7. FSAR, Section 14.5.

8. P. Check (NRC) letter to G. Lainas (NRC), "BWR Scram Discharge System Safety Evaluation,." December 1, 1980.

9. NEDC-30851-P-A, "Technical Specification Improvement Analyses for BWR Reactor Protection System,"

March 1988.

10. NRC No. 93-1 02, "Final Policy Statement on Technical Sp'ecification Improvements," July 23, 1993.

11 ~ MED-32-0286, "Technical Specification Improvement Analysis for Browns Ferry Nuclear Plant, Unit 2," October 1995.

12. NEDC-32410P-A, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM)

Retrofit Plus Option III Stability Trip Function," October 1995.

13. NED0-31960-A, "BWR Owners'roup Long-Term Stability Solutions Licensing Methodology," November 1995.

continued BFN-UNIT 2 B 3.3-46 Amendment No. 258

RPS Instrumentation B 3.3.1.1 BASES REFERENCES 14. NEDO-31960-A, Supplement 1, "BWR Owners'roup (continued) Long-Term Stability Solutions Licensing Methodology,"

November 1995.

15. NEDO-32465-A, "BWR Owners'roup Long-Term Stability Detect and Suppress Solutions Licensing Basis Methodology and Reload Applications," August 1996.

16. NEDC-32410P-A, Supplement 1, "Nuclear Measurement Analysis and Control Power Range Neutron Monitor (NUMAC PRNM) Retrofit Plus Option III Stability Trip Function," August 1996.

17. Letter, L.A. England (BWROG) to M.J. Virgilio, "BWR Owners'roup Guidelines for Stability Interim Corrective Action," June 6, 1994.

BFN-UNIT 2 B 3.3-46a Amendment No. 258

ecirculation Loops Operating B 34.1 BASES APPLICABLE Plant specific LOCA analyses have been performed assuming SAFETY ANALYSES only one operating recirculation loop. These analyses have (continued) demonstrated that, in the event of a LOCA caused by a pipe break in the operating recirculation loop, the Emergency Core Cooling System response will provide adequate core cooling, provided the APLHGR requirements are modified accordingly .

(Refs. 7 and 8).

The transient analyses of Chapter 14 of the FSAR have also been performed for single recirculation loop operation (Ref. 7) and demonstrate sufficient flow coastdown characteristics to maintain fuel thermal margins during the abnormal operational transients analyzed provided the MCPR requirements are modified. During single recirculation loop operation, modification to the Reactor Protection System (RPS) average power range monitor (APRM) instrument is also required to account for the different relationships between recirculation drive flow and reactor core flow. =The APLHGR and MCPR setpoints for single loop operation are specified in the COLR.

The APRM Flow Biased Simulated Thermal Power-High setpoint is in LCO 3.3.1.1, "Reactor Protection System (RPS)

Instrumentation."

Recirculation loops operating satisfies Criterion 2 of the NRC Policy Statement (Ref. 6).

(continued)

BFN-UNIT 2 B 3.4-4 Amendment No. 258

t Recirculation Loops Operating B 3.4.1 BASES (continued)

LCO Two recirculation loops are required to be in operation with their flows matched within the limits specified in SR 3.4.1.1 to ensure that during a LOCA caused by a break of the piping of one recirculation loop the assumptions of the LOCA analysis are satisfied. With the limits specified in SR 3.4.1.1 not met, the recirculation loop with the lower flow must be considered not in operation. With only one recirculation loop in operation, modifications to the required APLHGR Limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), MCPR limits (LCO 3.2.2, 'MINIMUMCRITICAL POWER RATIO (MCPR)"), and APRM Flow Biased Simulated Thermal Power-High Setpoint (LCO 3.3.1.1) may be applied to allow continued operation consistent with the assumptions of References 7 and 8.

APPLICABILITY In MODES 1 and 2, requirements for operation of the Reactor Coolant Recirculation System are necessary since there is considerable energy in the reactor core and the limiting design basis transients and accidents are assumed to occur.

In MODES 3, 4, and 5, the consequences of an accident are

=-

reduced and the coastdown characteristics of the recirculation loops are not important.

(continued)

BFN-UNIT 2 B 3.4-5 Amendment No. 268

ecirculation Loops Operating B 3.4.1 BASES (continued)

ACTIONS A.'I With the requirements of the LCO not met, the recirculation loops must be restored to operation with matched flows within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . A recirculation loop is considered not in operation when the pump in that loop is idle or when the mismatch between total jet pump flows of the two loops is greater than required limits. The loop with the lower flow must be considered not in operation. Should a LOCA occur with one recirculation loop not in operation, the core flow coastdown and resultant core response may not be bounded by the LOCA analyses. Therefore, only a limited time is allowed to restore the inoperable loop to operating status.

Alternatively, if the single loop requirements of the LCO are applied to the operating limits and RPS setpoints, operation with only one recirculation loop would satisfy the requirements of the LCO and the initial conditions of the accident sequence.

continued BFN-UNIT 2 B 3.4-6 Amendment No. 258

ecirculation Loops Operating B 3.4.1 BASES ACTIONS A.1 (continued)

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is based on the low probability of an accident occurring during this time period, on a reasonable time to complete the Required Action, and on frequent core monitoring by operators allowing abrupt changes in core flow .

conditions to be quickly detected.

This Required Action does not require tripping the recirculation pump in the lowest flow loop when the mismatch between total jet pump flows of the two loops is greater than the required However, in cases where large flow mismatches occur, 'imits.

low flow or reverse fiow can occur in the low flow loop jet pumps, causing vibration of the jet pumps. If zero or reverse flow is detected, the condition should be alleviated by changing pump speeds to re-establish forward flow or by tripping the pump.

continued BFN-UNIT 2 8 3.4-7 Amendment No. 258

ecirculation Loops Operating B 3.4.1 BASES ACTIONS B.1 (continued)

With no recirculation loops in operation while in MODES 1 or 2 or the Required Action and associated Completion Time of Condition A not met, the plant must be brought to a MODE in )

which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . In this condition, the recirculation loops are not required to be operating because of the reduced severity of DBAs and minimal dependence on the recirculation loop coastdown characteristics. The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

(continued)

BFN-UNIT 2 B 3.4-8 Amendment No. 258

., Recirculation Loops Operating 8 3.4.1 BASES (continued)

SURVEILLANCE SR 3.4.1.1 REQUIREMENTS This SR ensures the recirculation loops are within the allowable limits for mismatch. At low core flow (i.e., < 70% of rated core flow), the MCPR requirements provide larger margins to the fuel cladding integrity Safety Limit such that the potential adverse .

effect of early boiling transition during a LOCA is reduced. A larger flow mismatch can therefore be allowed when core flow is

< 70% of rated core flow. The recirculation loop jet pump flow, as used in this Surveillance, is the summation of the flows from all of the jet pumps associated with a single recirculation loop.

The mismatch is measured in terms of percent of rated core flow. If the flow mismatch exceeds the specified limits, the loop with the lower flow is considered inoperable. The SR is not required when both loops are not in operation since the mismatch limits are meaningless during single loop or natural

'circulation operation. The Surveillance must be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both loops are in operation. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is consistent with the Surveillance Frequency for jet pump OPERABILITYverification and has been shown by operating experience to be adequate to detect off normal jet pump loop flows in a timely manner.

(continued)

BFN-UNIT 2 8 3.4-9 Amendment No. 258

.'.Recirculation Loops Operating B 3.4.1 BASES (continued)

REFERENCES 1. FSAR, Section 14.6.3.

2. FSAR,- Section 4.3.5.

3. Deleted.

4. Deleted.

5. Deleted.

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

7. NEDO-24236, "Browns Ferry Nuclear Plant Units 1, 2, and 3, Single-Loop Operation," May 1981.

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

BFN-UNIT 2 B 3.4-10 Amendment No. 258

Mo Distri63.txt Distribution Sheet Priority: Normal From: Stefanie Fountain Action Recipients: Copies:

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Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 003693731:1

Subject:

Browns Ferry Units 2 8 3- Technical Specifications Change 401 - Changes to Limiting C ondition for Operation (LCO) Time for Containment Atmosphere Dilution (CAD) Subsyst em Inoperability Body:

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D030 - TVA Facilities - Routine Correspondence Docket: 05000260 Docket: 05000296 Page 2

(

Tennessee Valley Authority. Post Oifice Box 2000, Decatur, Afabama 35609

\

March 15, 2000 TVA-BFN-TS-401 10 CFR 50.4 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Gentlemen:

In the Matter of ) Docket Nos. 50-260 Tennessee Valley Authority ) 50-296 BROWNS FERRY NUCLEAR PLANT (BFN) UNITS 2 AND 3 TECHNICAL SPECIFICATIONS (TS) CHANGE 401 CHANGES TO LIMITING CONDITION FOR OPERATION (LCO) TIME FOR CONTAINMENT ATMOSPHERE DILUTION (CAD) SUBSYSTEM INOPERABILITY In accordance with the provisions of 10 CFR 50.4 and 50.90, TVA is submitting a request for a TS amendment (TS-401) to licenses DPR-52 and DPR-68 to revise LCO 3.6.3.1, CAD System, to provide 7 days of continued operation with two inoperable CAD subsystems.

This TS change request is consistent with the TS provisions for the CAD system in NUREG-1433, Revision 1, Improved Standard Technical Specifications for BWR/4 Plants.

Regarding precedent, several other boiling water reactors, including Hatch 1, Duane Arnold, and Peach Bottom, all have TS which provide for comparable periods of continued operation with inoperable CAD subsystems. to this letter provides the description and justification for the proposed TS change, and the significant hazards and environmental impact considerations. contains mark-up copies of the appropriate pages from the current Unit 2 and 3 TS showing the proposed revisions.

U.S. Nuclear Regulatory Commission

&age 2 March 15, 2000 TVA has determined that there are no significant hazards considerations associated with the proposed change and that the TS change qualifies for a categorical exclusion from environmental review pursuant to the provisions of 10 CFR 51.22(c) (9). The BFN Plant Operations Review Committee and the Nuclear Safety Review Board have reviewed this proposed change, and determined that operation of BFN Units 2 and 3 in accordance with the proposed change will not endanger the health and safety of the public. Additionally, in accordance with 10 CFR 50.91(b)(1), TVA is sending a copy of this letter and enclosures to the Alabama State Department of Public Health.

If 'you have any questions, please contact me at(256)729-2636.

ce y,,

E. y Manager ice s zng and ndustry A fairs Subsc ibed and s orn to before me on his da of March 2000.

Notary Public My Commission Expires 09/22/2002 Enclosures cc,:. See page 3

~ ~

1I

. t *4

.U.S. Nuclear Regulatory Commission Page 3 March 15, 2000 Enclosures cc (Enclosures):

Chairman Limestone County Commission 310 West Washington Street Athens, Alabama 35611 Mr. Paul Fredrickson, Branch Chief U.S. Nuclear Regulatory Commission Region II 61 Forsyth Street, ST W.

Suite 23T85 Atlanta, Georgia 30303 Mr. William O. Long, Project Manager U.S. Nuclear Regulatory Commission One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852 NRC Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, Alabama 35611 State Health Officer Alabama State Department of Public Health 434 Monroe Street Montgomery, Alabama 36130-3017

TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)

UNITS 2 and 3 PROPOSED TECHNICAL SPECIFICATIONS (TS) CHANGE TS-401 CHANGES TO LIMITING CONDITION FOR OPERATION (LCO) TIME FOR CONTAINMENT ATMOSPHERE DILUTION (CAD) SUBSYSTEM INOPERABILITY INDEX OF ENCLOSURES ENCLOSURE 1 - DESCRIPTION OF PROPOSED CHANGE AND JUSTIFICATION I. DESCRIPTION OF THE PROPOSED TS CHANGE El- 1 II. REASON FOR THE PROPOSED CHANGE .El- 1 III. DISCUSSION .El- 3 IV. I CONCLUS ONS ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ .El- 9 V. NO SIGNIFICANT HAZARDS CONSIDERATION DETERMINATION .El-10 VI. ENVIRONMENTAL IMPACT CONSIDERATION .El-12 VII. REFERENCES .El-12 ENCLOSURE 2 - MARKED-UP TS/BASES CHANGES

0 l

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

UNITS 2 and 3 PROPOSED TECHNICAL SPECIFICATIONS (TS) CHANGE TS-401 CHANGES TO LIMITING CONDITION FOR OPERATION (LCO) TIME FOR CONTAXNMENT ATMOSPHERE DILUTION (CAD) SUBSYSTEM INOPERABILITY DESCR'IPTION OF PROPOSED CHANGE AND JUSTIFICATION I. DESCRIPTION OF THE PROPOSED TS CHANGE TVA is requesting changes to the Units 2 and 3 TS LCO 3.6.3.1, CAD System, to provide a completion time of 7 days of continued reactor operation with two CAD subsystems inoperable. This change is consistent with the BWR/4 Standard Technical Specifications (STS),

NUREG-1433, Revision 1, for the CAD system. The current TS LCO requires reactor shutdown within 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months under LCO 3.0.3 when both CAD subsystems are inoperable.

The TS Bases are likewise being modified to match the proposed TS changes. A mark-up copy showing the proposed TS and Bases changes is provided in Enclosure 2 A ~

change to Unit 1 TS is not being requested at this time since the CAD system connection to Unit 1 is capped off, and Unit 1 is defueled and in an extended outage.

II. REASON FOR THE PROPOSED CHANGE BFN Units 1, 2, and 3 share a common CAD system. The system is comprised of two redundant subsystems each of which contains an external liquid nitrogen storage tank and the piping, valving, instrumentation, and controls necessary to inject nitrogen gas to the primary containment of any of the BFN units. The current TS for BFN provides for a 30-day LCO whenever one of the two redundant CAD subsystems becomes inoperable. No specific LCO is provided for the condition when both CAD subsystems are inoperable. Therefore, should both CAD subsystems become inoperable, the current TS would require that all operating units be placed in MODE 3 within 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months in accordance with the requirements of LCO 3.0.3.

The current TS, which requires an expedited forced shutdown of one or both BFN units because of short-term CAD system inoperability, is disproportionate with the overall safety function of the CAD system. Therefore, a relaxation to the CAD system LCO to provide a limited 7-day time period of continued operation is being proposed. This change is consistent with BWR/4 STS which already provide for a 7-day Completion Time when both CAD subsystems are inoperable if an alternate hydrogen control function is maintained. For BFN, the containment inerting system provides the alternate means of hydrogen control.

The primary objective of this proposed TS change is to reduce the likelihood of the forced shutdown of the reactor(s) resulting from short-term loss of the CAD subsystems due to unanticipated maintenance problems.

This would avoid the inherent risks associated with reactor shutdown activities resulting from maintenance issues that could be corrected in a timely manner. This risk avoidance concern is exacerbated by'the prospect of shutting down two units in a short time period.

Although it is not typical for both CAD systems to be inoperable, there is a reasonable probability that this situation may occur, particularly during periods when one of the CAD subsystems is out of service for scheduled testing, or corrective or preventive maintenance. For this situation with the existing TS, the invocation of LCO 3.0.3 for two inoperable CAD systems is very restrictive with regard to being able to return a subsystem to service or to perform unanticipate'd corrective maintenance within the 13-hour LCO. With the proposed 7-day completion time, we expect that a subsystem could be returned to service or corrective maintenance be performed to remedy any likely CAD system equipment problem prior to exceeding the LCO.

Therefore, we believe it is prudent to propose adoption of STS provisions for the CAD system to reduce the probability of a multi-unit forced shutdown and the associated risk factors.

III. DISCUSSION CAD S stem Descri tion and Desi Basis During normal power operation, the containment inerting system is used to maintain the primary containment atmosphere at less than 4.0 percent oxygen by volume, with the balance in nitrogen. Following a loss-of-coolant accident (LOCA), hydrogen is postulated to be evolved within the containment from metal-water reactions, and hydrogen and oxygen are produced by radiolysis of water. These are the only significant sources of hydrogen and oxygen. 3f the concentrations of hydrogen and oxygen were not controlled, a combustible gas mixture could theoretically be produced. To ensure that a combustible gas mixture does not form, the oxygen concentration is kept below 5 percent by volume, or the hydrogen concentration is kept below 4 percent by volume by operation of the CAD system.

Assuming the analytic hydrogen and oxygen generation rates as specified in Safety Guide 7, Control of Combustible Gas Concentrations in Containment Following a Loss-of-Coolant Accident, the concentration of combustible gases in containment following a LOCA is controlled by the CAD system. This is accomplished by injecting nitrogen gas into the containment from one of two redundant CAD liquid nitrogen storage tanks to dilute any oxygen generated by the LOCA and by venting the containment atmosphere as necessary through the standby gas treatment system. Refer to the 5.2-7 and 5.2-8 Figures in the Final Safety Analysis Report (FSAR) for a flow diagram of the CAD system.

This system is capable of keeping the concentration of oxygen in the containment atmosphere below 5 percent.

Xn the event that postaccident monitoring showed that hydrogen and oxygen generation rates were substantially below those specified in the Safety Guide, the CAD system could be operated as necessary to maintain either the hydrogen concentration below 4 percent or the oxygen concentration below 5 percent. The time required to produce significant amounts of oxygen through radiolysis is lengthy and in the LOCA analysis CAD operation is not required until hours after a LOCA.

The CAD system can also be used to provide a non-safety grade, backup pneumatic supply to the drywell control air system, primarily for the purpose of increasing the availability of long-term main steam relief valve (MSRV) operation for beyond design basis events such as those associated with Appendix R. This control air backup capability is not addressed in the TS, and the Appendix R program allows the use of alternate methods and/or compensatory measures such as nitrogen bottles in instances where normal drywell control air equipment is not available. For design basis considerations, selected MSRVs are equipped with safety grade accumulators which are designed to ensure each MSRV can be opened 5 times as discussed in. FSAR Section 4.4.5 on the Automatic Depressurization System description.

CAD Subsystem A provides a backup pneumatic source for operation of the Hardened Wetwell Vent valves and the torus vacuum breaker isolation valves. The current TS allows for a single CAD subsystem to be inoperable for 30 days, where, in the case of CAD Subsystem A, this backup function is not available. Therefore the requested TS LCO of allowing both CAD subsystems to be inoperable for 7-days does not extend the period that this backup function may be unavailable.

BWR OWNERS GROUP EVALUATION OF COMBUSTIBLE GAS CONTROL The BWR Mark I Owners Group undertook a substantial study in response to the addition of the provisions in 10 CFR 50.44(c)(3) requiring recombiner capability for those light water reactors that rely upon purge/repressurization systems as a primary means of hydrogen control. This study was published as NED0-22155, Generation and Mitigation of Combustible Mixtures in Inerted BWR Mark I Containments, June 1982.

This NEDO concluded that the oxygen generation rates assumed in Safety Guide 7 (subsequently Regulatory Guide 1.7) were overly conservative and that maintaining an inerted containment during operation was sufficient to provide combustible gas control.

El-4

Following review of this study, NRC issued Generic Letter 84-09, which stated that the BWR Mark I plants affected by the recombiner rule (including BFN) did not need to rely on use of a safety grade purge/repressurization system (CAD) specified by 10 CFR 50.44(f) and (g) as a primary means of hydrogen control provided that three technical criteria were met.

These three criteria from GL 84-09 are summarized below:

1. The plant has TS LCOs requiring containment atmosphere oxygen concentration to be maintained less than 4. by volume;

2. The plant has only nitrogen or recycled containment atmosphere for use in all pneumatic control systems within containment, and;

3. There are no potential sources of oxygen in containment other than that resulting from radiolysis of the reactor coolant.

BFN is designed and operated in accordance with these criteria as follows: 1) The BFN primary containment is maintained below 4 percent oxygen by volume during normal operation in accordance with TS LCO 3.6.3.2 using nitrogen gas from the containment inerting system;

2) All pneumatic equipment located inside the primary containment utilizes recycled containment atmosphere (drywell compressor system) as its'pneumatic supply.

Furthermore, station control air is not used to provide the pneumatic supply to containment equipment during periods of reactor operation; 3) Pathways which could introduce oxygen into the primary containment are isolated during normal operation.

El-5

Subsequently NRC issued an SER dated July 6, 1989, which evaluated NEDO-22155. The SER concluded that, in some areas, the NEDO-221SS analysis under-predicts oxygen radiolysis generation rates. However, the SER also stated that Regulatory Guide 1.7 (which superseded Safety Guide 7) is conservative in its overall oxygen generation prediction. Therefore, a technical basis exists that the AEC Safety Guide 7 oxygen generation rates assumed in the BFN LOCA analysis are more conservative than necessary. This provides additional justification for a TS allowance for a short period of CAD system inoperability.

Ado tion of STS CAD LCO BWR/4 Standard Technical Specifications, NUREG-1433, Revision 1, provide a 7-day continued operation allowance with two CAD systems inoperable if an alternate hydrogen control system is verified available.

For BFN, the normal containment inerting system provides this hydrogen control function.

The normal containment inerting system is used during the initial purging of the primary containment to establish an inerted containment, and it also provides a supply of make up nitrogen during reactor operation.

The system consists of a liquid nitrogen storage tank, a purge vaporizer, a makeup vaporizer, pressure-reducing valves and controllers, and instrumentation, valves, and associated piping. Refer to the FSAR 5.2.6.a series of figures for flow diagrams of the system.

The normal inerting system supplies nitrogen from a common onsite storage tank through a common purge vaporizer or makeup vaporizer where the liquid nitrogen is converted to the gaseous state. The gaseous nitrogen then flows through the purge or make up pressure-reducing valves and flow meters into the torus or drywell.

E1-6

In the event of a LOCA, the Core Standby Cooling Systems are designed to prevent significant fuel damage and the generation of significant quantities of hydrogen.

Should fuel damage be postulated, and hydrogen and oxygen be generated per AEC Safety Guide 7 assumptions, the inerted primary containment at'mosphere ensures that the oxygen concentration is too low to react with this hydrogen gas. Hence, any oxygen which can react must be generated from the radiolytic decomposition of water under post-LOCA conditions.

The primary containment inerting system can be used to provide nitrogen dilution in a manner analogous to the CAD system. In fact, the BFN Emergency 'Operating Instructions (EOIs) preferentially direct the use of the normal primary containment inerting system for purging and venting during emergency conditions. The EOI procedural policy, which is in accordance with industry emergency procedure guidelines, recognizes that the inerting system is well suited for use under emergency conditions since it is routinely used for purge and vent operations under normal operations. Under this procedural direction, CAD serves as the backup method rather than the primary means to mitigate any combustible mixture formation. Therefore, the proposed TS change is consistent with this EOI usage of the normal inerting system by requiring it to be functional as the alternate hydrogen control function during any period of reactor operation if both CAD subsystems are inoperable. This is consistent with STS provisions for CAD.

Risk Considerations In a qualitative sense, the Browns Ferry PSA baseline CDF values for Unit 2 and Unit 3 indicate a low probability per reactor year of a core-damaging event.

Since CAD's formal design function is not needed unless core damage has already occurred, and the core damage probability is low, a low probability of needing CAD for its design use can be observed directly from the baseline CDF value. Since the baseline CDF value is based on an annual time frame, and the proposed LCO under discussion is only a small part of a year, then these low probabilities can be seen to be reduced even further during an LCO period.

There are no planned maintenance or test activities which remove both CAD systems from service. Therefore, the proposed TS is requested as a contingency provision for situations when both subsystems become inoperable due to unexpected circumstances. The most likely circumstance for this situation would be an unexpected maintenance problem on a CAD subsystem while the other subsystem was out of service for preventive or corrective maintenance.

The CAD design basis oxygen control function is not required until well, after a hydrogen producing LOCA event has occurred because of the time necessary for radiolysis to produce sufficient oxygen inside primary containment. Since the safety-related design function of CAD is not required prior to the occurrence of a core damaging event (the interval evaluated by the BFN Level I PSA), it follows that'(CDF) thi's,CAD function cannot impact core damage frequency values.

BFN design basis calculations indicate that the CAD function would not be needed sooner than 42 hours4.861111e-4 days 0.0117 hours 6.944444e-5 weeks 1.5981e-5 months post-accident under anticipated containment conditions.

The BFN Level II PSA evaluation for large early release frequency (LERF) is concerned with the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months post-accident, therefore, the availability of the CAD function does not affect LERF.

Also, as noted earlier, the proposed LCO will also provide that the containment inerting system be verified available if both CAD subsystems are inoperable. The containment inerting system, although not safety-grade,

'can provide the analogous combustible gas control function as CAD. In the BFN symptom based EOIs, it is used in several contingencies to provide containment inerting functions. The inerting system tank as well as the CAD tanks are located external to the reactor building and can be easily accessed. Therefore, it is easy to refill the inerting tank or CAD tanks using nitrogen tank trucks as contingency options.

El-8

The CAD system non-safety function of supplying backup pneumatic motive energy for long term MSRV operation has nominal relevance to PSA core damage frequency (CDF) calculations, because MSRV operation can affect CDF.

However, the PSA modeling shows there is no significant change to the Unit 2 or Unit 3 CDF when the CAD backup pneumatic supply function is assumed to be either 100%

available or never available (i.e., risk-reduction worth or risk-achievement worth values are not significant).

In summary, the addition of TS provisions for the 7-day CAD LCO has little impact on risk. Anticipated use of the LCO is as a contingency specification for unexpected maintenance problems on the CAD system. The CAD system is monitored under the BFN Maintenance Rule Program, and CAD subsystem unavailability is unlikely to increase as a result of issue of the proposed TS change. A longer LCO would provide an opportunity to remedy the system problem and return a subsystem to service in an orderly manner. This would avoid the inherent transition risk associated with an expedited shutdown of multiple units.

Therefore, the proposed TS change is considered beneficial with regard to risk considerations.

IV. CONCLUSION The BFN Unit 2 and Unit 3 Technical Specifications currently require a shutdown to Mode 3 under the conditions of LCO 3.0.3 if both CAD subsystems become inoperable. The low probability of a fuel-damaging accident occurring during a 7-day.,period, the fact that CAD is not required to be put in service immediately post-accident, and the availability of oxygen mitigation systems other than CAD which are preferred under the EOIs make the requested TS change acceptable. The proposed change is also consistent with STS. Also, previous regulatory studies (NEDO-22155) concluded that the AEC oxygen generation source terms are conservative, and that the inerted containment provides the chief protection against the creation of combustible mixtures in the primary containment atmosphere.

El-9

A review of Improved TS approved at other BWRs of similar design, such as Peach Bottom Units 2 and 3, and Hatch Unit 1, found that 7 days or greater LCO times were typical for conditions where both CAD subsystems were inoperable. The justification provided at these plants is similar to that used in this submittal, i.e.,

the risk of a LOCA during the LCO interval is small, CAD usage is not immediately required even should a fuel-damaging accident occur, and that alternate hydrogen control capability exists within the plant design. As noted previously, 7-days is provided in STS for plants with an alternate hydrogen control function such as Browns Ferry.

V. NO SIGNIFICANT HAZARDS CONSIDERATION DETERMINATION DESCRIPTION OF PROPOSED AMENDMENT The proposed amendment to the BFN Unit 2 and Unit 3 TS would establish an LCO time of up to 7 days with no operable CAD subsystem provided the unit's Primary Containment Inerting System is available to provide an alternate hydrogen control capability.

TVA has concluded that operation of BFN Units 2 and 3 in accordance with the proposed change to the TS does not involve a significant hazards consideration. TVA's conclusion is based on its evaluation, in accordance with 10 CFR 50.91(a)(1), of the three standards set forth in 10 CFR 50.92(c).

A. The ro osed amendment does not involve a si ificant increase in the robabilit or conse ences of an accident reviousl evaluated.

The safety-related function of the Containment Atmosphere Dilution (CAD) system is to mitigate the effects of a loss-of-coolant-accident (LOCA) by limiting the volumetric concentration of oxygen in the primary containment atmosphere. The CAD System is not an event initiator, therefore, the probability of the occurrence of an accident is not affected by this proposed Technical Specification (TS) change. Emergency procedures preferentially use the normal containment inerting system to

provide post-accident vent and purge capability, with the CAD system only serving in a backup role to this system. Hence, in the event of the inoperability of both CAD subsystems, the proposed TS require the normal containment inerting system to be verified available as an alternate oxygen control means. Therefore, the proposed TS change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

B. The ro osed amendment does not create the ossibilit of a new or different kind of accident from an accident reviousl evaluated.

This TS change does not result in any changes to the CAD equipment design or capabilities or to the operation of the plant. Since the change impacts only the required action completion time for periods of CAD subsystem inoperability and does not result in any change in the response of the equipment to an accident, the change does not create the possibility of a new or different kind of accident from any previously analyzed.

C. The ro osed amendment does not involve a si ificant reduction in a mar in of safet As stated in GL 84-09, a Mark I type boiling water reactor (BWR) plant is not considered to rely upon purge/repressurization systems such as CAD as its primary means of hydrogen control when the unit(s) is operated in accordance with certain technical criteria. The BFN units are operated in accordance with these criteria. The BFN Unit 2 and Unit 3 containments are inerted with nitrogen during normal operation, recycled containment atmosphere is used for pneumatically operated components inside containment, and there are no potential sources of oxygen generation inside containment other than the radiolytic decomposition of water.

The system preferred by the EOIs for oxygen control post-accident is the normal primary containment

inerting system. Because the probability of an accident involving hydrogen and oxygen production is small; CAD is not the primary system used to mitigate the creation of combustible containment atmosphere mixtures, and because the requested LCO where both CAD subsystems is inoperable is not long, no significant reduction in the margin of safety is associated. with this proposed amendment.

VI. ENVIRONMENTAL IMPACT CONSIDERATION The proposed change does not involve a significant hazards consideration, a change in the types of, or increase in, the amounts of any effluents that may be released off-site, or a significant increase in individual or cumulative occupational radiation exposure. Therefore, the proposed change meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c) (9). Therefore, pursuant to 10 CFR 51.22(b), an environmental assessment of the proposed change is not required.

VII. REFERENCES

1. General Electric report, NED0-22155, Generation and Mitigation of Combustible Mixtures in Inerted BWR Mark I Containments, June 1982

2. NRC Generic Letter 84-09, May 8, 1984, Recombiner Capability Requirements of 10 CFR 50.44(c) (3)(ii)

3. NRC SER on General Electric Company's Methodology for Determining Rates of Generation of Oxygen by Radiolytic Decomposition (NEDO 22155) - July 6, 1989 E1-12

ENCLOSURE 2 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)

UNITS 2 and 3 PROPOSED TECHNICAL SPECIFICATIONS (TS) CHANGE TS-401 CHANGES TO LIMITING CONDITION FOR OPERATION (LCO) TIME FOR CONTAINMENT ATMOSPHERE DILUTION (CAD) SUBSYSTEM INOPERABILITY AFFECTED PAGE LIST Unit 2 Unit 3 3 '-41 3.6-41 B 3.6-98 B 3.6-98

CAD System 3.6.3.1

3.6 CONTAINMENTSYSTEMS 3.6.3.1 Containment Atrriosphere Dilution (CAD) System LCO 3.6.3.1 Two CAD subsystems shall be OPERABLE.

[note: new text below, APPLICABILITY: MODES 1 and 2. is shown in bold type in the shaded areasi ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One CAD subsystem inoperable.

NOTE LCO 3.0.4 is not applicable A.1 Restore CAD subsystem 30 days to OPERABLE status.

Two CAD B.1 Verify by administrative hour subsystems means that the, inoperable= hydrogen-control function is maintained. ' AND, once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND B.2 Restore CAD subsystem nitrogen admission 7 days flowpath'o OPERABLE status 8-. Required Action and BA Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. C.1 BFN-UNIT 2 3.6-41 Amendment No. 253

CAD System B 3.6.3.1 insert text from next page here BASES ACTIONS C.1 (continued)

If any Required Action cannot be met within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.3.1.1 REQUIREMENTS t

Verifying that there is 2500 gal of liquid nitrogen supply in each nitrogen storage tank will ensure at least 7 days of post-LOCA CAD operation. This minimum volume of liquid nitrogen allows sufficient time after an accident to replenish the nitrogen supply for long term inerting. This is verified every 31 days to ensure that the system is capable of performing its intended function when required. The 31 day Frequency is based on operating experience, which has shown 31 days to be an acceptable period to verify the liquid nitrogen supply and on the availability of other hydrogen mitigating systems.

continued BFN-UNIT 2 B 3.6-98 Revision 0

t This new text will e added to the Unit 2 TS Bases as indicated on the previous page.

B.1 and 8.2 With two CAD subsystems inoperable, the ability to control the hydrogen control function via alternate capabilities must be verified by administrative means within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

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

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

CAD System 3.6.3.1

, 3.6 CONTAINMENTSYSTEMS 3.6.3.1 Containment Atmosphere Dilution (CAD) System LCO 3.6.3.1 Two CAD subsystems shall be OPERABLE.

[note: new text below APPLICABILITY: MODES 1 and 2. is shown in bold type in the shaded areas]

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One CAD subsystem NOTE inoperable. LCO 3.0.4 is not applicable A.1 Restore CAD subsystem 30 days to OPERABLE status.

Two CAD Verify by administrative 1- hour subsystems means that the inoperable'.1 hydrogen control function is maintained. AND, once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter AND B.2 Restore CAD subsystem nitrogen admission 7 days

, flowpath. to OPERABLE status 8-. Required Action and SA. Be in MODE 3. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met. C.1 BFN-UNIT 3 3.6-41 Amendment No. 212

CAD System B 3.6.3.1 Insert text from next page here BASES ACTIONS (continued)

S4 ~ C.1 If any Required Action cannot be met within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.3.1.1 REQUIREMENTS Verifying that there is > 2500 gal of liquid nitrogen supply in each nitrogen storage tank will ensure at least 7 days of post-LOCA CAD operation. This minimum volume of liquid nitrogen allows sufficient time after an accident to replenish the nitrogen supply for long term inerting. This is verified every 31 days to ensure that the system is capable of performing its intended function when required. The 31 day Frequency is

=

based on operating experience, which has shown 31 days to be an acceptable period to verify the liquid nitrogen supply and on the availability of other hydrogen mitigating systems.

continued BFN-UNIT 3 B 3.6-98 Revision 0

This new text will be added to the Unit 3 TS Bases as indicated on the previous page.

B.1 and B.2 With two CAD subsystems inoperable, the ability to control the hydrogen control function via alternate capabilities must be verified by administrative means within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

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

. 7 days is permitted with two CAD subsystems inoperable.

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

Distri66.txt Distribution Sheet Priority: Normal From: Stefanie Fountain Action Recipients: Copies:

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Item: ADAMS Package Library: ML ADAMS"HQNTAD01 ID: 003684247

Subject:

OR Submittal: Append J Containment Leak Rate Testing Body:

Docket: 05000260, Notes: N/A Docket: 05000296, Notes: N/A Page 1

~w n

0 I

Tennessee Valley Authority, Post Olfice Box 2000, Oecatur. Alabama,35609 February 4, 2000 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555 Gentlemen:

In the Matter of Docket. Nos. 50-260 Tennessee Valley Authority 50-296 BROWNS FERRY NUCLEAR PLANT (BFN) UNITS 2 AND 3 RESPONSE TO REQUEST FOR ADDITIONAL INFORMATION REGARDING TECHNICAL SPECIFICATIONS (TS) CHANGE NO. 399 INCREASED MAIN STEAM ISOLATION VALVE (MS IV) LEAKAGE RATE LIMITS AND EXEMPTION FROM 10 CFR 50 APPENDIX J REVISED TS PAGES FOR INCREASED MSIV LEAKAGE LIMITS (TAC NOS MA64 05 r MA64 0 6 r MA68 1 5 AND MA68 1 6)

This letter responds to the November 23, 1999, Request for Additional Information (RAI) regarding (TS-399) change request 399. TS-399, which was submitted on September 28, 1999, proposes changes to the Unit 2 and 3 TS to increase the allowable leakage rate criteria for the MSIVs. In addition, in the September, 28, 1999, submittal, TVA requested exemption to specific portions of 10 CFR 50, Appendix J to allow the exclusion of MSIV leakage from the summation of containment leak rate test results. of this letter provides the TVA response to the nine RAI questions. Enclosure 2 contains supporting calculations for the condenser seismic assessment associated with RAI Item 7. provides additional details regarding RAI Item 8 which addresses specific NRC staff questions on dose analysis methods. Additionally, as discussed in Enclosure 3, TVA has performed specific MSIV dose calculations rather than using extrapolation factors for the MSIV leakage. This revised

U.S. Nuclear Regulatory Commission Page 2 February 4, 2000 analysis resulted in a reduction of the requested MSIV allowable leakage rate requested in the September 28, 1999 letter. Accordingly, a revised change request is provided in . Enclosure 5 contains marked-up copies of the appropriate pages from the current Units 2 and 3 TS showing the proposed revisions.

The revised pages provided in Enclosure 5 do not alter the original determination that there are no significant hazards considerations associated with the proposed changes, nor does it alter the originally submitted Environmental Assessment and Finding of No Significant Impact provided by the September 28, 1999 letter. The BFN Plant Operations Review Committee and the BFN Nuclear Safety Review Board have reviewed this proposed change and determined that operation of BFN Units 2 and 3 in accordance with the proposed change will not endanger the health and safety of the public.

Pursuant to 10 CFR 50.12, an exemption to 10 CFR 50, Appendix J containment leakage requirements was requested in the September 28, 1999, submittal which would allow exclusion of the MSIV leakage from the summation of containment leak rate test results. This exemption request supports the TS change to increase the MSIV leakage criteria and is still being requested. Additional information regarding the need for the exemption is provided in the response to RAI Item 9. provides a listing of commitments made in this submittal. If you have any questions, please contact me at (256) 729-2636.

S'er y, Manager lcen lng and I ustry Aff irs Enclosures cc: see pag 3

e4-)

'(

U.S. Nuclear Regulatory Commission Page 3 February 4, 2000 Enclosures cc (Enclosures):

Mr. Paul Frederickson, Branch Chief U.S. Nuclear Regulatory Commission Region II 61 Forsyth Street, S.W.

Suite 23T85 Atlanta, Georgia 30303 Mr. William 0. Long, Project Manager U.S. Nuclear Regulatory Commission One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852 NRC Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, Alabama 35611

Distri68.txt Distribution Sheet Priority: Normal From: Andy Hoy Action Recipients: Copies:

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Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 993430105

Subject:

BROWNS FERRY NUCUAR PLANT (BFN) UNITS 2 AND 3, CORRECTED INFORMATION FOR TECHNICAL SPECIFICATION CHANGE REQUEST TS-384, POWER UPRATE.

Body:

PDR ADOCK 05000260 P Docket: 05000260, Notes: N/A Docket;: 05000296, Notes: N/A Page 1

Tennessee Valley Authority, Post Office Box 2000, Decatur, Alabama 35609-2000 December 1, 1999 U.S. Nuclear Regulatory Commission ATTN; Document Control Desk Washington, D.C. 20555 Gentlemen:

I In the Matter of Docket No. 50-260 Tennessee Valley Authority 50-296 BROWNS FERRY NUCLEAR PLANT (BFN) UNITS 2 AND 3, CORRECTED INFORMATION FOR TECHNICAL SPECIFICATION CHANGE REQUEST TS-384, POWER UPRATE (TAC NOS. M99711 AND M99712)

In a letter dated October 1, 1997 (Reference 1), TVA provided a proposed Technical Specification change that would allow BFN Units 2 and 3 to operate at an uprated power of 3458 megawatts thermal. In a September 8, 1998 letter (Reference 2), NRC issued license amendments 254 and 214 approving TVA's request for uprated power operation,. for Units 2 and 3 respectively.

TVA's October 1, 1997 letter, contains information which TVA has determined to be inaccurate. In Enclosure 5, Section 4.1.1.1 b of General Electric (GE) NEDC 32751P-

"Power Uprate Safety Analysis For Browns Ferry Nuclear Plant Units 2 and 3", TVA stated that the main steam relief valve (MSRV) T-Quenchers are located above the elevation of the emergency core cooling systems (ECCS) torus suction while in fact the T-Quenchers are located below the ECCS torus suction.

The relative location of the two points (MSRV T-Quencher versus ECCS suction) formed the basis of TVA's conclusion that an evaluation of local suppression pool temperature was not required for power uprate.

~pO

U. S. Nuclear Regulatory Commission Page 2 December 1, 1999 TVA's evaluation of local suppression pool temperature is provided below:

Back round On October 1, 1981, NRC published NUREG-0783, "Suppression Pool Temperature Limits For Boiling Water Reactor (BWR)

Containments (Reference 3)." The NUREG established local temperature limits for BWR suppression pools during MSRV discharge. The primary plant transient of interest was an extended MSRV discharge such as a single stuck open MSRV which would produce high localized pool temperatures in one suppression pool bay. NRC's concern was that high localized suppression pool temperatures could result in unstable condensation of the steam bubbles thus inducing excessive loads on the suppression chamber internal structures. In response to NUREG-0783, each plant was required to prepare a localized pool temperature analysis. For BFN, a local suppression pool temperature analysis was documented by GE report NEDC-22004, issued October 1981, "Browns Ferry Nuclear Power Plant Units 1, 2, and 3 Suppression Pool Temperature Response."

GE report NED0-30832, "Elimination of Limit on BWR Suppression Pool Temperature for SRV Discharge with Quenchers", approved in a Safety Evaluation Report (SER) on August 29, 1994 (Reference 4), generically analyzed the issue using revised techniques. The report concludes that for plants employing T-Quenchers, the condensation loads over the full range of pool temperatures up to the saturation temperature are low compared to loads from MSRV discharge line air clearing and the Loss of Coolant Accidents (LOCA). The GE report concludes that the NUREG-0783 limit on the suppression pool temperature for MSRV discharge through T-Quenchers is unnecessary and associated plant operating limits may be replaced by limits based on other considerations.

A Brookhaven National Laboratory Report, prepared for the staff to assist them in the review of NED0-30832, supports the NRC SER for NED0-30832, concurring with the GE findings regarding structural loads. Additionally, the report discussed steam ingestion by the ECCS pumps resulting in the potential for pump cavitation or condensation induced water hammer in the suction piping following collapse of the steam bubbles or plume.

U. S. Nuclear Regulatory Commission Page 3 December

.~ '.C 1, 1999 Based on information received from the Massachusetts Institute of Technology (MIT), the Brookhaven report concluded that the maximum extent of any steam plume formed when saturated conditions exist in the vicinity of a T-Quencher device will be no greater than approximately 1.5 meters (4.92 feet).

Thus, the Brookhaven report concluded that if the ECCS suction is horizontally separated from the T-Quencher by at least 1.5 meters (4.92 feet) (irrespective of the vertical relationship of the two points), the plume/bubbles would not be ingested by the ECCS suction.

The NRC agreed with GE report NEDO-30832 concerning loads on the suppression chamber internal structures. However, the NRC disregarded Brookhaven's 1.5 meter separation criteria for ECCS suction separation and instead, stipulated in the 1994 NRC SER for NEDO-30832 that the local suppression pool temperature is limit can be eliminated if the below the elevation of the pump MSRV inlet for T-Quenchers.

the ECCS pumps This was intended to geometrically preclude the ingestion of a thermal/steam plume and thus its potential impact on both the net positive suction head (NPSH) of the ECCS pumps and water hammer loads on the piping.

The October 1, 1997, BFN Power Uprate submittal stated that the evaluation of local pool temperature limit is not necessary in accordance with NEDO-30832 since the T-Quenchers are above the RHR suction elevation. It has subsequently been determined that the T-Quenchers are located below the ECCS torus suction strainers.

Evaluation Because of the discrepancy identified in the October 1, 1997 letter, TVA re-evaluated the impact on local suppression pool temperatures resulting from the five percent power uprate.

The local suppression pool temperature analysis for Browns Ferry provided in GE report NEDC-22004-P, was reevaluated.

The results of the re-evaluation show that the local pool temperature is not sensitive to the small (5 percent) change in the initial reactor thermal power due to power uprate. The report contains a case for a stuck open relief valve (SORV) at both hot shutdown and full power conditions with the same

U. S. Nuclear Regulatory Commission Page 4 December 1, 1999 assumptions regarding RHR cooling. The difference in suppression pool local temperature for these two cases is only 9 degrees F. Assuming a linear relationship to power, a five percent increase in power would result in less than 0.5 degrees F additional temperature at the uprated condition. The highest temperature for any case in GE report NEDC-22004-P is 198 degrees F. Even with an additional 0.5 degrees F, the report's conclusion that the local suppression pool temperature remains below the 200 degrees F limit remains valid.

Xn order to further address ECCS suction separation, TVA has evaluated the physical configuration of the suppression pool, MSRV T-Quenchers, and ECCS suction strainers utilizing the information contained in NED0-30832, the NRC SER and the associated Brookhaven report; The ECCS system pumps take suction from the suppression pool through an ECCS ring header by way of four strainers connected in parallel. The strainers inside the suppression chamber are GE stacked disk design, with a very large external open flow area. The main steam relief valves discharge though T-Quenchers located on the opposite side of the suppression chamber centerline from the ECCS strainers.

At the closest point, between the ECCS strainers and the T-Quenchers, the T-Quencher outer edge is approximately 2.3 meters (7.54 feet) horizontal distance from the strainer outer edge, substantially exceeding the criteria provided by the Brookhaven report. This point on the ECCS strainers is at approximately 528 feet 10 inches elevation.

The centerline of the MSRV T-Quenchers is at elevation 526 feet 6 inches.

The Brookhaven 4.92 feet criteria is based on the horizontal distance from the T-Quencher to the outer edge of the steam plume at the surface of the pool. The horizontal extent of the steam plume is greatest at the pool surface since the horizontal size of the steam plume would increase from the T-Quencher up to the surface due to the steam plume mixing horizontally (i.e., expanding) as it rises through the pool.

The steam plume should be even smaller than 4.92 feet near the elevation of the T-Quenchers which further increases the separation between the steam plume and the strainers.

U. S. Nuclear Regulatory Commission Page 5 December 1, 1999 In the event of one stuck open MSRV at high reactor pressure, the ECCS systems would not operate at their full flow capacity. In the initial phase of the event, reactor vessel makeup would be accomplished via the normal feedwater system.

it If became necessary to initiate ECCS makeup, the reactor core isolation cooling (RCIC) system at 600 gallons per minute (gpm) and/or the high pressure coolant injection system at 5000 gpm would be initiated. Normal suction for these two systems is the condensate storage tanks. However, these pumps can be aligned to the suppression pool and, therefore, were considered for evaluation.

Due to the initiation of the RCIC and/or HPCI or due to high suppression pool temperatures, both loops of the residual heat removal (RHR) system in the suppression pool cooling mode at 13000 gpm per loop would be initiated. If necessary, the operator could also initiate two loops of Core Spray on their minimum flow paths at 620 gpm each loop. With a tota'l flow of 32840 gpm through the four strainers, TVA estimates that the approach velocity to each strainer would be approximately 0.06 feet per second.

In the event of one stuck open MSRV at a reactor pressure below the shutoff head of the low pressure ECCS pumps, the ECCS, systems would operate at their full flow capacity; however, the size of the steam/bubble plume would be significantly smaller due to the lower reactor pressure and thus the separation criteria would be conservative.

The 7.54 feet of horizontal separation provided in the BFN suppression chamber would prevent the steam plume/bubbles from reaching the ECCS suction strainers. Also, because the ECCS suction strainers have a very large external open flow area, they have a low approach velocity. The low approach velocity would reasonably be expected to prevent the ECCS suction from hydraulically distorting the steam plume (i.e., drawing the plume nearer to the strainer) and thus, further minimizes the potential for ingesting the plume/bubbles into the strainer.

Based on the Brookhaven criteria, the 7.54 feet of horizontal separation at BFN would prevent the steam plume/bubbles from .

reaching the ECCS suction strainers. However, even if the plume were to extend to a small portion of the strainer, the large size of the strainer would result in the majority of the flow being drawn from the cooler pool water outside of the plume. The cool water would mix with the thermal plume inside

U. S. Nuclear Regulatory Commission Page 6 December 1, 1999 the strainer and form a mixture of water substantially below the plume temperature before being sent to the ECCS pumps.

As previously noted, the ECCS system pumps take suction through a ECCS ring header by way of four strainers connected in parallel. The strainers are at four nearly equal distant locations separated by approximately 25 percent of the circumference of the ring header. Since the extended MSRV actuation discussed in this letter involves only one MSRV, the transient can potentially interact with only one ECCS suction strainer. The ring header design ensures that the flow to a specific pump is not from a single strainer but is instead a mixture of flow from the widely separated strainers.

Conclusion The geometry of the torus and ECCS piping coupled with the thermal-hydraulic conditions discussed abov'e will ensure that:

1) the local suppression pool temperature will remain below the 200 degrees F limit for structural loads, 2) the ECCS suction piping would not ingest steam bubbles which could later collapse and induce water hammer loads, and 3) the ECCS pumps and their associated NPSH will not be subjected to elevated temperature suction flows. Therefore, the ECCS systems are fully capable of performing their design and licensing basis functions and thus there is no impact on the operability of the systems. Hence, the staff's conclusions published in NRC's September 8, 1998, Safety Evaluation regarding the acceptability of Browns Ferry's power uprate remain valid.

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

S'ere ey Manager of Li ens'n and Industr Affa' rs cc: See Page

1 0

l

U. S. Nuclear Regulatory Commission Page 7 December 1, 1999 REFERENCES TVA Letter to NRC dated October 1, 1997, Browns Ferry Nuclear Plant (BFN) Units 2 and 3 Technical Specification (TS) CHANGE TS-384 Request For Power Uprate Operation

2. NRC Letter to TVA dated September 8, 1998, Issuance of Regarding: Power Uprate Browns Ferry "'mendments Nuclear Plant Units 2 and 3 (TAC NOS. M99711 and M99712)

3. NUREG 0783, Suppression Pool Temperature Limits For Boiling Water Reactor (BWR) Containments, published October 1, 1981

4. August 29, 1994, Safety Evaluation of General Electric Co. Topical Reports; NEDO-30832 Entitled, Elimination of Limit on BWR Suppression Pool Temperature For Steam Relief Valve Discharge With Quenchers and NEDO-31695 Entitled, BWR Suppression Pool Temperature Technical Specification Limits

U. S. Nuclear Regulatory Commission Page 8 December 1, 1999 Mr. William 0 Long, Senior Project Manager U.S. Nuclear Regulatory Commission One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852 Mr. Paul E. Fredrickson, Branch Chief U.S. Nuclear Regulatory Commission Region II 61 Forsyth Street, S. W.

Suite 23T85 Atlanta, Georgia 30303 NRC Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, Alabama 35611

OKC 8 1899 November 23, 1999 Mr. J. A. Scalice Chief Nuclear Officer and Executive Vice President Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, Tennessee 37402-2801

SUBJECT:

BROWNS FERRY UNITS 2 AND 3, MAIN STEAM ISOLATION VALVE LEAK RATE LIMITS, REQUEST FOR ADDITIONALINFORMATION (TAC NOS.

MA6405, MA6406, MA6815 AND MA6816)

Dear Mr. Scalice:

By letter dated September 28, 1999 (TS399), you submitted a license amendment application for Browns Ferry Units 2 and 3. The application also requests exemptions to requirements contained in Title 10, Code of Federal Regulations Part 50, Appendix J. The proposed amendment would revise the technical specifications (TS) leakage limits for main steam isolation valves. The staff has determined that it needs additional information to determine the acceptability of the proposed TS changes and exemptions.

Our request for additional information is enclosed. These questions were discussed with Mike Morrison and Bert Morris, of your staff, in a telecon on November 23, 1999. It was agreed that TVA would respond to these questions by December 27, 1999. If you have any questions regarding this issue, please contact me at 301-415-3026.

Sincerely, Original signed by:

William O. Long, Senior Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket Nos. 50-260 8 50-296 I'~ t. Il lLj l (;*

Enclosure:

Request for Additional Information I Jk ii) cc wlenclosure: See next page DISTRIBUTION:

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= Copy with attachment/enclosure "N" = No copy *See Previous Concurrence OFF!CE PDII-2/PH PDII-2/LA EHEB:SC SCSB SPLB:SC PDI HAME WLong BCla ton 'Hanot MRienhart* GHubbard* RCor DATE 11/ '99 11/ 5 /99 11/16/99 11/22/99 11/23/99 1'I/ . /99 Official Record Copy lof Pz) Anzac l( ( ( p'-",'/"Rgb P

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Mr. J. A. Scalice Chief Nuclear Officer and Executive Vice President Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, Tennessee 37402-2801

SUBJECT:

BROWNS FERRY UNITS 2 AND 3, MAIN STEAM ISOLATION VALVE LEAK RATE LIMITS, REQUEST FOR ADDITIONALINFORMATION (TAC NOS.

MA6405, MA6406, MA6815 AND MA6816)

Dear Mr. Scalice:

By letter dated September 28, 1999 (TS399), you submitted a license amendment application for Browns Ferry Units 2 and 3. The application also requests exemptions to requirements contained in Title 10, Code of Federal Regulations Part 50, Appendix J. The proposed amendment would revise the technical specifications (TS) leakage limits for main steam isolation valves. The staff has determined that it needs additional information to determine the acceptability of the proposed TS changes and exemptions.

Our request for additional information is enclosed. These questions were discussed with Mike Morrison and Bert Morris, of your staff, in a telecon on November 23, 1999. It was agreed that TVA would respond to these questions by'December 27, 1999. If you have any questions regarding this issue, please contact me at 301-415-3026.

Sincerely,

'l//>g 'g pl

.I William O. Long, Senior Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket Nos. 50-260 8 50-296

Enclosure:

Request for Additional Information cc w/enclosure: See next page

REQUEST FOR ADDITIONALINFORMATION BROWNS FERRY UNITS 2 AND 3 APPLICATION DATED SEPTEMBER 28 1999 Section 5.2 of the March 3, 1999 safety evaluation for NEDC-31858, states that a secondary ALT path to the condenser, having an orifice, should exist. Your application states that in the event that FCV-1-58 were to fail to open, the leakage flow would split, with part of the flow going to the condenser via a 0.1875 inch diameter orifice in a normally open bypass around FCV 1-58, and the remainder going to the condenser via normal leakage paths through the main steam stop/control valves and through the high pressure turbine. It is noted that NEDC-31858 para. 6.1.1(2) states that the ALT flow path should, based on the radiological dose methodology, be at least 1-square inch in internal cross sectional area. Please describe the effect on offsite dose and control room habitability, of this single failure. In particular, will dose consequences remain acceptable in the event of single-failure of FCV-1-58?

Your application indicates that sealing steam supply valve, PCV 1-147, will be modified so that it fails closed instead of open. Assuming that fails-open was the original "safe" fail position, please confirm that the new fail position will not adversely affect the capability to mitigate design basis accidents and other postulated events.

3. Your application indicates that check valves are to be added to preheater steam lines to ensure ALT boundary integrity. Please describe any proposed measures surveillance tests for these valves. Does the use of these valves create a single-failure concern?

4. In allowing nonseismic piping to perform an engineered safety feature (ESF) function, it is expected that licensees will include the ALT system in the American Society of Mechanical Engineers (ASME)Section XI inservice inspection (ISI) and inservice testing programs, and perform augmented ISI and motor-operated valve inspections in a manner consistent with ongoing ASME and approved risk-based programs applicable to ESF piping systems. Please confirm if this is your intention.

Also, your application states that the most limiting single active failure would be failure of valve FCV-1-58 to open. Please describe any augmented periodic testing (i.e., Generic Letter (GL) 89-10/GL 96-05 diagnostics) that will be performed on this valve.

Section 4.1.2 of your EQE Report identifies the load combinations and stress allowables utilized in seismic assessments. Please provide a discussion of the extent to which the criteria used are consistent with the licensing basis requirements for other engineered safety features.

6. Referring to Page 10 of the EQE Report, and noting that different Class I buildings at Browns Ferry Nuclear Plant have different vertical soil amplification factors, please explain the basis for the specific scaling factors selected for the Turbine Building.

~ ~

. 7. In Table 4-8 and Figures 4-2 thru 4-5 of the EQE Seismic Evaluation Report, only Moss Landing Units 6 & 7 condensers are provided for comparison with the Browns Ferry condensers. This is too limited to support a finding that the earthquake experience database demonstrates the seismic adaquacy of Browns Ferry's condensers. Please provide additional condenser data.

As stated in the staffs March 3, 1999 safety evaluation, there is no standard at the present time, endorsed by NRC, that provides guidance for determining the required number of piping and equipment items, that should be referenced in the earthquake experience database when utilizing the BWROG methodology. Therefore, you are responsible for ensuring the sufficiency of the above data submitted for staff review and determination. If sufficient data are not provided for the condenser, the NRC may require that the condenser be analytically evaluated against all the pertinent operating and design loadings, in accordance with the plant's design basis methodology and criteria.

The radiological analysis description provided in the application does not provide an adequate basis for the staff to determine whether or not those analyses are acceptable.

The staff notes that the reported increase in doses appears to be inconsistent with the proposed eight fold increase in the allowable MSIV leakage. Please provide the analysis assumptions, methods, and input parameters used in your calculations, in sufficient detail for the staff to resolve the apparent inconsistency and, if deemed necessary by the staff, to perform independent calculations to confirm your reported results. Your response should identify any. changes made to the assumptions, methods, and inputs used in analyses previously approved by the NRC for Browns Ferry Units 2 and 3.

Your application requests an exemption from the requirement that MSIV leakage be included the overall Type A leakage limit (in addition to the 0.6 L, limit for the sum of Types B and C penetration leakage). Is it your understanding that this is consistent with NEDC-31858? Is there a valid need for this exemption?

t V

v e o Mr. J. A. Scalice BROWNS FERRY NUCLEAR PLANT Tennessee Valley Authority CC: I Mr. Karl W. Singer, Senior Vice President Mr. Mark J. Burzynski, Managar Nuclear Operations Nuclear Licensing Tennessee Valley Authority Tennessee Valley Authority 6A Lookout Place 4X Blue Ridge 1101 Market Street 1101 Market Street Chattanooga, TN 37402-2801 Chattanooga, TN 37402-2801 Mr. Jack A. Bailey, Vice President Mr. Timothy E. Abney, Manager Engineering & Technical Services Licensing and Industry Affairs Tennessee Valley Authority Browns Ferry Nuclear Plant 6A Lookout Place Tennessee Valley Authority 1101 Market Street P.O. Box 2000 Chattanooga, TN 37402-2801 Decatur, AL 35609 Mr. John T. Herron, Site Vice President Senior Resident Inspector Browns Ferry Nuclear Plant U.S. Nuclear Regulatory Commission Tennessee Valley Authority Browns Ferry Nuclear Plant P.O. Box 2000 I0833 Shaw Road Decatur, AL 35609 Athens, AL 35611 General Counsel State Health Officer Tennessee Valley Authority Alabama Dept. of Public Health ET 10H RSA Tower - Administration 400 West Summit Hill Drive Suite 1552 Knoxville, TN 37902 P.O. Box 303017 Montgomery, AL 36130-3017 Mr. N. C. Kazanas, General Manager Nuclear Assurance Chairman Tennessee Valley Authority Limestone County Commission 5M Lookout Place 310 West Washington Street 1101 Market Street Athens, AL 35611 Chattanooga, TN 37402-2801 Mr. Robert G. Jones, Plant Manager Browns Ferry Nuclear Plant Tennessee Valley Authority P.O. Box 2000 Decatur, AL 35609

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Item: ADAMS Document Library: ML ADAMS"HQNTAD01 ID: 993340068

Subject:

BROWNS FERRY UNITS 2 AND 3 MAIN STEAM ISOLATION VALVE LEAK RATE LIMIT S ~ REQUEST FOR ADDITIONAL IN FORMAT ION (TAC NOS MA64 05 ~ MA64 0 6 g MA68 1 5 AND MA6816)

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PDR ADOCK 05000260 P Docket: 05000260, Notes: N/A Docket: 05000296, Notes: N/A Page 1

ML18039A699

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