Proposed tech specs & bases pages incorporating NRC ...ENCLOSURE 1 TENNESSEE VALLEYAUTHORITY BROWNS...

ENCLOSURE 1

TENNESSEE VALLEY AUTHORITYBROWNS FERRY NUCLEAR PLANT (BFN)

UNIT 2

TS-354 CLEAN PAGES

9903090022 990222eOa aDOCX OSOOoaSOt PDR .'

Technical Specification 354

Unit 2

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3 ~ 3 13 ~ 3 23 ~ 3 33.3-63.3-83.3-93.4"13.4-23.4-33.4-4B 3 '-9B 3 '-14B 3.3-15

B 3.3-30B 3.3-32B 3.3-34B 3.3-35

B 3.3-44

B 3.3-46

B 3.4-4B 3.4-5B 3.4-5(1)B 3.4-5aB 3.4-6B 3.4-7B 3.4-8B 3.4-9B 3.4-10

Insert3.3-13 ~ 3 23 ~ 3 33.3-63.3-83.3-93.4-13.4-23.4-33.4-4B 3.3-9B 3.3-9aB 3.3-14B 3.3-15B 3.3-15aB 3.3-15bB 3.3-30B 3.3-32B 3 '-34B 3.3-35B 3.3-35aB 3.3-44B 3.3-45aB 3.3-46B 3.3-46aB 3.4-4B 3.4-5

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

RPS Instrumentation3.3.1.1

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 shallbe OPERABLE.

APPLICABILITY: According to Table 3.3.1.1-1.

ACTIONS

NOTESeparate Condition entry is allowed for each channel.

CONDITION REQUIRED ACTION COMPLETIONTIME

A. One or more requiredchannels inoperable.

A.1 Place channel in trip.

OR

12 hours

A.2 NOTENot applicable forFunctions 2.a, 2.b, 2.c,2.d, or 2.f.

Place associated tripsystem in trip.

12 hours

(continued)

BFN-UNIT2 3.3 1 Amendment No. 258


ACTIONS continued


B. —NOTENot applicable forFunctions 2.a, 2.b, 2.c,2.d, or 2.f.

One or more Functionswith one or more requiredchannels inoperable inboth trip systems.

B.1 Place channel in one tripsystem in trip.

OR

B.2 Place one trip system intrip.

6 hours

6 hours

C. One or more Functionswith RPS trip capabilitynot maintained.

C.1 Restore RPS tripcapability.

1 hour

D. Required Action andassociated CompletionTime of Condition A, B, orC not met.

D.1 Enter the Conditionreferenced inTable 3.3.1.1-1 for thechannel.

Immediately

E. As required by RequiredAction D.1 andreferenced inTable 3.3.1 ~ 1-1.

E.1 Reduce THERMALPOWER to ( 30% RTP.

4 hours

F. As required by RequiredAction D.1 andreferenced inTable 3.3.1 ~ 1-1 ~

F.1 Be in IVIODE 2. 6 hours

(continued)

BFN-UNIT2 3.3-2 Amendment No. 258


ACTIONS continued

CONDITION REQUIRED ACTION COMPLETIONTIME,

G. As required by RequiredAction D.1 andreferenced inTable 3.3.1.1-1.

G.1 Be in MODE 3. 12 hours

H. As required by RequiredAction D.1 andreferenced inTable 3.3.1.1-1.

H.1 Initiate action to fullyinsert all insertablecontrol rods in core cellscontaining one or morefuel assemblies.

Immediately

I ~ As required by RequiredAction D.1 andreferenced in Table3.3.1.1-1.

l.1 Initiate alternate methodto detect and suppressthermal hydraulicinstability oscillations.

12 hours

AND

l.2 Restore requiredchannels to OPERABLE.

120 days

J. Required Action andassociated CompletionTime of Condition I notmet.

J.1 Be in Mode 2. 4 hours



SURVEILLANCEREQUIREMENTS continued

SURVEILLANCE FREQUENCY

SR 3.3.1.1.10 Perform CHANNELCALIBRATION. 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 NOTENeutron detectors are excluded.

Perform CHANNELCALIBRATION. 24 months

SR 3.3.1.1.14 Perform LOGIC SYSTEM FUNCTIONALTEST.

24 months

SR 3.3.1.1.15 VerifyTurbine Stop Valve - Closure andTurbine Control Valve Fast. Closure, Trip OilPressure - Low Functions are not bypassedwhen THERMALPOWER is t 30% RTP.

24 months

SR 3.3.1.1.16 NOTEFor Function 2.a, not required to beperformed when entering MODE 2 fromMODE 1 until 12 hours after enteringMODE 2.

Perform CHANNEL FUNCTIONALTEST. 184 days

SR 3.3.1.1.17 Verify OPRM is not bypassed when APRM.Simulated Thermal Power is a 25% andrecirculation drive flow is (60% of ratedrecirculation drive flow.

24 months

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


Table 3.3.1.1-1 (page 2 of 3)Reactor Protection System Instrumentation

FUNCTION

APPLICABLEMODES OR REQUIRED

OTHER CHANNELSSPECIFIED PER TRIP

CONDITIONS SYSTEM

CONDITIONSREFERENCED

FROM SURVEILLANCE ALLOWABLEREQUIRED REQUIREMENTS VALUE

ACTION D.1

2. Average Power RangeMonitors (continued)

d. Inop

e. 2-Out-Ofd Voter

12

12

3(b) G SR 3.3.1.1.16 NA

SR 3.3.1.1.1 NASR 3.3.1.1.14SR 3.3.1.1.16

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

3. Reactor Vessel Steam DomePressure - High

4. Reactor Vessel Water Level-Low, Level 3

5. Main Steam Isolation Valve-Closure

6. Drywall Pressure - High

7. Scram Discharge VolumeWater Level - High

1,2

12

1.2

SR 3.3.1.1.1,SR 3.3.1.1.8SR 3.3.1.1.10SR 3.3.1.1.14

SR 3.3.1.1.1SR 3.3.1.1.8SR 3.3.1.1.13SR 3.3.1.1.14

SR 3.3.1.1.8SR 3.3.1.1.13SR 3.3.1.1.14

SR 3.3.1.1.8SR 3.3.1.1.13SR 3.3.1.1.14

5 1090 pslg

h 538 inchesabove vesselzero

5 10% closed

52.5 psig

a. Resistance TemperatureDetector

1,2

5(a) H

SR 3.3.1.1.8 S 50 gallons"SR 3.3.1.1.13SR 3.3.1.1.14

SR 3.3.1.1.8 s 50 gallonsSR 3.3.1.1.13SR 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-UNIT2 3.3-8 .Amendment No. 258


Table 3.3.1.1-1 (page 3 of 3)Reactor Protection System instrumentation

FUNCTION

APPLICABLEMODES OR REQUIRED

OTHER CHANNELSSPECIFIED PER TRIP

CONDITIONS SYSTEM

CONDITIONSREFERENCED

FROM SURVEILLANCE ALLOWABLEREQUIRED REQUIREMENTS VALUE

ACTION D.1

7. Scram Discharge VolumeWater Level - High(continued)

b. Float Switch 1,2

5(a)

SR 3.3.1.1.8SR 3.3.1.1.13SR 3.3.1.1.14

SR 3.3.1.1.8SR 3.3.1.1.13SR 3.3.1.1.14

5 50 gallons

S 50 gallons

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

5 10% closed

9. Turbine Control Valve FastClosure, Trip Oil Pressure-Low

10. Reactor Mode Switch-Shutdown Position

11. Manual Scram

a 30% RTP

1,2

5(a)

1,2

5(a)

SR 3.3.1.1.8SR 3.3.1.1.13SR 3.3.1.1.14SR 3.3.1.1.15

SR 3.3.1.1.12 NA'R 3.3.1.1.14SR 3.3.1.1.12 NASR 3.3.1.1.14

SR 3.3.1.1.8 NASR 3.3.1.1.14

SR 3.3.1.1.8 NASR 3.3.1.1.14

12. RPS Channel Test Switches

13. Low Scram Pilot AirHeaderPressure

1,2

5(a)

12 G

SR 3.3.1.1.4

SR 3.3.1.1.4

SR 3.3.1.1.13SR 3.3.1.1.14SR 3.3.1.1.16

NA

5(a) SR 3.3.1.1.13SR 3.3.1.1.14SR 3.3.1.1.16

2 50 psig

(a) With any control rod withdrawn from a core cell containing one or more fuel assemblies.

8FN-UNIT2 3.3-9 Amendment No. 258

ecirculation Loops Operating3.4.1

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 thefollowing'imits

are applied when the associated LCO is applicable:

a. LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATIONRATE (APLHGR)," single loop operation limits specified in theCOLR;

b. LCO 3.2.2, "MINIMUMCRITICALPOWER 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 MonitorsFlow Biased Simulated Thermal Power - High), Allowable Valueof Table 3.3.1.1-1 is reset for single loop operation;

APPLICABILITY: MODES 1 and 2.



ACTIONS


A. Requirements of the LCOnot met.

A.1 Satisfy the requirementsof the LCO.

24 hours

B. Required Action andassociated CompletionTime of Condition A notmet.

B.1 Be in MODE 3. 12 hours

OR

No recirculation loops inoperation.


ecirculation Loops Operating3 4.1

SURVEILLANCEREQUIREMENTS

SURVEILLANCE FREQUENCY

SR 3.4.1.1 NOTENot required to be performed until 24 hoursafter both recirculation loops are in operation.

Verify recirculation loop jet pump flowmismatch with both recirculation loops inoperation is:

24 hours

a. s 10% of rated core flowwhen operatingat ( 70% of rated core flow; and

I

b. 6 5% of rated core flowwhen operating ata 70% of rated core flow.



Figure 3.4.1-1(Deleted Per TS 354)


RPS InstrumentationB 3.3.1.1

BASES

APPLICABLESAFETYANALYSES,LCO, andAPPLICABILITY

(continued)

Avera e Power Ran e Monitor

The APRM channels provide the primary indication of neutronfluxwithin the core and respond almost instantaneously toneutron flux increases. The APRM channels receive inputsignals from the local power range monitors (LPRMs) within thereactor core to provide an indication of the power distributionand local power changes. The APRM channels average theseLPRM signals to provide a continuous indication of averagereactor power from a few percent to greater than RTP. EachAPRM also includes an Oscillation Power Range Monitor(OPRM) Upscale Function which monitors small groups ofLPRM signals to detect thermal hydraulic instabilities.

The APRM System is divided into four APRM channels and four2-out-of-4 voter channels. Each APRM channel provides inputsto each of the four voter channels. The four voter channels aredivided into two groups of two each, with each group of twoproviding inputs to one RPS trip system. The system isdesigned to allow one APRM channel, but no voter channels, tobe bypassed. A trip from any one unbypassed APRM will resultin a "half-trip" in all four of the voter channels, but no trip inputsto either RPS trip system. APRM trip Functions 2.a, 2.b, 2.c,and 2.d are voted independently from OPRM Upscale Function2.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 eachof the four voter channels, which in turn results in two trip inputsto each RPS trip system logic channel (A1, A2, B1, or, 82).Similarly, a Function 2.f trip from any two unbypassed APRMchannels will result in a full trip from each of the four voterchannels. Three of the four APRM channels and all four of thevoter channels are required to be OPERABLE to ensure that nosingle failure will preclude a scram on a valid signal. Inaddition, 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-UNIT2 8 3.3-9 Amendment No. 258


BASES

APPLICABLE Avera e Power Ran e Monitor (continued)SAFETYANALYSES,LCO, and three (3) LPRM inputs from each of the four axial levels atAPPLICABILITY which the LPRMs are located, must be operable for each APRM

channel. For the OPRM Upscale Function 2.f, LPRMs areassigned to "cells" with either 3 or 4 detectors, with a total of 33"cells" assigned to each OPRM channel. A minimum of 23cells, each with a minimum of 2 LPRMs must be OPERABLE forthe OPRM Upscale Function 2.f to be OPERABLE.

continued

BFN-UNIT2 B 3.3-9a Amendment No. 258


BASES

APPLICABLESAFETY ANALYSES,LCO, andAPPLICABILITY

(continued)

2.d. Avera e Power Ran e Monitor - tno

Three of the four APRIVI channels are required to beOPERABLE for each of the APRM Functions. This Function(Inop) provides assurance that the minimum number of APRMsare OPERABLE. For any APRM channel, any time its modeswitch is in any position other than "Operate," an APRM moduleis unplugged, or the automatic self-test system detects a criticalfault with the APRM channel, an Inop trip is sent to all four voterchannels. Inop trips from two or more unbypassed APRMchannels result in a trip output from all four voter channels totheir associated trip system.

This Function was not specifically credited in the accidentanalysis, but it is retained for the overall redundancy anddiversity of the RPS as required by the NRC approved licensingbasis.

There is no Allowable Value for this Function.

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

continued

BFN-UNIT2 B 3.3-14 Amendment No. 258

RPS Instrumentation8 3.3.1.1

BASES

APPLICABLESAFETY ANALYSES,LCO, andAPPLICABILITY

(continued)

2.e. 2-Out-Of-4 Voter

The 2-Out-Of-4 Voter Function provides the interface betweenthe APRM Functions, including the OPRM Upscale Function,and the final RPS trip system logic. As such, it is required to beOPERABLE in the MODES where the APRM Functions arerequired and is necessary to support the safety analysisapplicable to each of those Functions. Therefore, the2-Out-Of-4 Voter Function needs to be OPERABLE in MODES1 and 2.

All four voter channels are required to be OPERABLE. Eachvoter channel includes self-diagnostic functions. Ifany voterchannel detects a critical fault in its own processing, a trip isissued 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 alsoincludes separate outputs to RPS for the two independentlyvoted sets of Functions, each of which is redundant (four totaloutputs). The Voter Function 2.e must be declared inoperableifany of its functionality is inoperable. However, due to theindependent voting of APRM trips, and the redundancy ofoutputs, there may be conditions where the Voter Function 2.eis inoperable, but trip capability for one or more of the otherAPRM Functions through that voter is still maintained. Thismay be considered when determining the condition of otherAPRM Functions resulting from partial inoperability of the VoterFunction 2.e.

There is no Allowable Value for this Function.

continued



BASES

APPLICABLESAFETYANALYSES,LCO, andAPPLICABILITY

(continued)

2.f. Oscillation Power Ran e Monitor OPRM U scale

The OPRIVI Upscale Function provides compliance with GDC 10and GDC 12, thereby providing protection from exceeding thefuel MCPR safety limit (SL) due to anticipated thermal hydraulicpower oscillations.

References 13, 14, and 15 describe three algorithms fordetecting thermal hydraulic instability related neutron fluxoscillations: the period based detection algorithm, theamplitude based algorithm, and the growth rate algorithm. Allthree are implemented in the OPRM Upscale Function, but thesafety analysis takes credit only for the period based detectionalgorithm. The remaining algorithms provide defense in depthand additional protection against unanticipated oscillations.OPRM Upscale Function OPERABILITYfor TechnicalSpecification purposes is based only on the period baseddetection algorithm.

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

The OPRM Upscale Function is required to be OPERABLEwhen the plant is in a region of power flow operation whereanticipated events could lead to thermal hydraulic instabilityand related neutron flux oscillations. Within this region, theautomatic trip is enabled when THERMALPOWER, asindicated by the APRM Simulated Thermal Power, is z 25%RTP and reactor core flow, as indicated by recirculation driveflow is ( 60% of rated flow, the operating region where actualthermal hydraulic oscillations may occur. Requiring the OPRMUpscale Function to be OPERABLE in MODE 1 providesconsistency with operability requirements for other APRMfunctions and assures that the OPRM Upscale Function isOPERABLE whenever reactor power could increase into theregion of concern without operator action.

continued

BFN-UNIT2 8 3.3-15a Amendment No. 258


BASES

p p el whenthe period based detection algorithm in that channel detectsoscillatory changes in the neutron flux, indicated by thecombined signals of the LPRM detectors in a cell, with periodconfirmations and relative cell amplitude exceeding specifiedsetpoints. One or more cells in a channel exceeding the tripconditions will result in a channel trip. An OPRM Upscale trip isalso issued from the channel ifeither the growth rate oramplitude based algorithms detect growing oscillatory changesin the neutron flux for one or more cells in that channel.

APPLICABLE 2.f. Oscillation Power Ran e Monitor OPRM U scaleSAFETY ASAAYSES„~ti dLCO, and

,APPLICABILITY An OPRM U scale tri is issued from an APRM charm

Three of the four channels are required to be OPERABLE.Each channel is capable of detecting thermal hydraulicinstabilities, 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-UNIT2 B 3.3-15b Amendment No. 258


BASES

ACTIONS(continued)

A.1 and A.21

Because of the diversity of sensors available to provide tripsignals and the redundancy of the RPS design, an allowableout of service time of 12 hours has been shown to beacceptable (Ref. 9 and 12) to permit restoration of anyinoperable channel to OPERABLE status. However, this out ofservice time is only acceptable provided the associatedFunction's inoperable channel is in one trip system and theFunction still maintains RPS trip capability (refer to RequiredActions B.1, B.2, and C.1 Bases). Ifthe inoperable channelcannot be restored to OPERABLE status within the allowableout of service time, the channel or the associated trip systemmust be placed in the tripped condition per RequiredActions A.1 and A.2. Placing the inoperable channel in trip (orthe associated trip system in trip) would conservativelycompensate for the inoperability, restore capability toaccommodate a single failure, and allow operation to continue.Alternatively, if it is not desired to place the channel (or tripsystem) in trip (e.g., as in the case where placing theinoperable 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 channelaffects both trip systems. For that condition, Required ActionA.1 must be satisfied, and is the only action (other thanrestoring operability) that will restore capability to accommodatea single failure.

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

continued



BASES

ACTIONS B.1 and 8.2 (continued)

The 6 hour Completion Time is judged acceptable based on theremaining capability to trip, the diversity of the sensorsavailable to provide the trip signals, the low probability ofextensive numbers of inoperabilities affecting all diverseFunctions, and the low probability of an event requiring theinitiation 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 wouldresult in a scram or RPT), Condition D must be entered and itsRequired Action taken.

As noted, Condition B is not applicable for APRM Functions2.a, 2.b, 2.c, 2.d, or 2.f. Inoperability of an APRM channelaffects both trip systems and is not associated with a specifictrip system as are the APRM 2-out-of-4 voter and othernon-APRM channels for which Condition 8 applies. For aninoperable APRM channel, Required Action A.1 must besatisfied, 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 APRIVIchannel results in loss of trip capability for that Function andentry into Condition C, as well as entry into Condition A foreach channel. Because Conditions A and C provide RequiredActions that are appropriate for the inoperability of APRMFunctions 2.a, 2.b, 2.c, 2.d, or 2.f; and these functions are notassociated with specific trip systems as are the APRM2-out-of-4 voter and other non-APRM channels, Condition Bdoes not apply.

continued



BASES

ACTIONS(continued)

D.1

Required Action D.1 directs entry into the appropriate Conditionreferenced in Table 3.3.1.1-1. The applicable Conditionspecified in the Table is Function and MODE or other specifiedcondition dependent.and may change, as the Required Action ofa previous Condition is completed. Each time an inoperablechannel has not met any Required Action of Condition A, B, orC and the associated Completion Time has expired,Condition D will be entered for that channel and provides fortransfer to the appropriate subsequent Condition.

E.1 F.1 G.1 and J.1

Ifthe channel(s) is not restored to OPERABLE status or placedin trip (or the associated trip system placed in trip) within theallowed Completion Time, the plant must be placed in a MODEor other specified condition in which the LCO does not apply.The allowed Completion Times are reasonable, based onoperating experience, to reach the specified condition from fullpower conditions in an orderly manner and without challengingplant systems. In addition, the Completion Time of RequiredAction E.1 is consistent with the Completion Time provided inLCO 3.2.2, "MINIMUIVlCRITICALPOWER RATIO (MCPR)."

continued

BFN-UNIT2 B 3.3-34 Amendment'No. 258


BASES

ACTIONS(continued)

Ifthe channel(s) is not restored to OPERABLE status or placedin trip (or the associated trip system placed in trip) within theallowed Completion Time, the plant must be placed in a MODEor other specified condition in which the LCO does not apply..This is done by immediately initiating action to fully insert allinsertable control rods in core cells containing one or more fuelassemblies. Control rods in core cells containing no fuelassemblies do not affect the reactivity of the core and are,therefore, not required to be inserted. Action must continueuntil all insertable control rods in core cells containing one ormore fuel assemblies are fully inserted.

If OPRM Upscale trip capability is not maintained, Condition Iexists. Reference 12 justified use of alternate methods todetect and suppress oscillations for 'a limited period of time.The alternate methods are procedurally established consistentwith the guidelines identified in Reference 17 requiring manualoperator action to scram the plant ifcertain predefined eventsoccur. The 12 hour allowed action time is based onengineering judgment to allow orderly transition to the alternatemethods while limiting the period of time during which noautomatic or alternate detect and suppress trip capability isformally in place. Based on the small probability of aninstability event occurring at all, the 12 hours is judged to bereasonable.

continued



BASES

ACTIONS(continued)

I.2

The alternate method to detect and suppress oscillationsimplemented in accordance with I.1 was evaluated (Reference12) based on use up to 120 days only. The evaluation, basedon engineering judgment, concluded that the likelihood of an .instability event that could not be adequately handled by thealternate methods during this 120 day period was negligiblysmall. The 120 day period is intended to be an outside limit toallow for the case where design changes or extensive analysismight be required to understand or correct some unanticipatedcharacteristic of the instability detection algorithms orequipment. This action is not intended and was not evaluatedas a routine alternative to returning failed or inoperableequipment to OPERABLE status. Correction of routineequipment failure or inoperability is expected to normally beaccomplished within the completion times allowed for Actionsfor Conditions A and B.


As noted at the beginning of the SRs, the SRs for each RPSinstrumentation Function are located in the SRs column ofTable 3.3.1.1-1.

The Surveillances are modified by a Note to indicate that whena channel is placed in an inoperable status solely forperformance of required Surveillances, entry into associatedConditions and Required Actions may be delayed for up to6 hours, provided the associated Function maintains RPS tripcapability. Upon completion of the Surveillance, or expiration ofthe 6 hour allowance, the channel must be returned toOPERABLE status or the applicable Condition entered andRequired Actions taken. This Note is based on the reliabilityanalysis (Ref. 3) assumption of the average time required toperform channel Surveillance. That analysis demonstrated thatthe 6 hour testing allowance does not significantly reduce theprobability that the RPS will trip when necessary.

continued



BASES


(continued)

SR 3.3.1.1.11

(Deleted)

SR 3.3.1.1.14

The LOGIC SYSTEM FUNCTIONALTEST demonstrates theOPERABILITYof the required trip logic for a specific channel.The functional testing of control rods (LCO 3.1.3), and SDVvent and drain valves (LCO 3.1.8), overlaps this Surveillance toprovide complete testing of the assumed. safety function.

The 24 month Frequency is based on the need to perform thisSurveillance under the conditions that apply during a plantoutage and the potential for an unplanned transient if theSurveillance were performed with the reactor at power.Operating experience with these components supportsperformance of the Surveillance at the 24 month Frequency.

The LOGIC SYSTEM FUNCTIONALTEST for APRM Function2.e simulates APRM and OPRM trip conditions at the 2-out-of-4voter channel inputs to check all combinations of two trippedinputs to the 2-out-of-4 logic in the voter channels and APRMrelated redundant RPS relays.

continued



BASES

SURVEILLANCE SR 3.3.1.1.17REQUIREMENTS

(continued) This SR ensur es that scrams initiated from OPRM UpscaleFunction'(Function 2.f) will not be inadvertently bypassed whenTHERMALPOWER, as indicated by the APRM Simulated ThermalPower, is a 25% RTP and core flow, as indicated by recirculation .drive flow, is ( 60% rated core flow. This normally involvesconfirming the bypass setpoints. Adequate margins for the

'nstrumentsetpoint methodologies are incorporated into the actualsetpoint. The actual surveillance ensures that the OPRM UpscaleFunction is enabled (not bypassed) for the correct values of APRMSimulated Thermal Power and recirculation drive flow. Othersurveillances ensure that the APRM Simulated Thermal Power andrecirculation flow properly correlate with THERMALPOWER andcore flow, respectively.

Ifany bypass setpoint is nonconservative (i.e., the OPRM UpscaleFunction is bypassed when APRM Simulated Thermal Power z25% RTP and recirculation drive flow( 60% rated), then theaffected channel is considered inoperable for the OPRM UpscaleFunction. Alternatively,'he bypass setpoint may be adjusted toplace the channel in a conservative condition (unbypass). Ifplaced in the unbypassed condition, this SR is met and the channelis considered OPERABLE.

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

(continued)


RPS InstrumeritationB 3.3.1.1

BASES (continued)

REFERENCES 1. FSAR, Section 7.2.

2. FSAR, Chapter 14.

3. NEDO-23842, "Continuous Control Rod Withdrawal in theStartup 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 ScramDischarge System Safety Evaluation,." December 1, 1980.

9. NEDC-30851-P-A, "Technical Specification ImprovementAnalyses for BWR Reactor Protection System,"March 1988.

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

11 ~ MED-32-0286, "Technical Specification ImprovementAnalysis for Browns Ferry Nuclear Plant, Unit 2," October1995.

12. NEDC-32410P-A, "Nuclear Measurement Analysis andControl Power Range Neutron Monitor (NUMAC PRNM)Retrofit Plus Option III Stability Trip Function," October1995.

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

continued



BASES

REFERENCES(continued)

14. NEDO-31960-A, Supplement 1, "BWR Owners'roupLong-Term Stability Solutions Licensing Methodology,"November 1995.

15. NEDO-32465-A, "BWR Owners'roup Long-Term StabilityDetect and Suppress Solutions Licensing BasisMethodology and Reload Applications," August 1996.

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

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


ecirculation Loops OperatingB 34.1

BASES

APPLICABLE Plant specific LOCA analyses have been performed assumingSAFETY ANALYSES only one operating recirculation loop. These analyses have

(continued) demonstrated that, in the event of a LOCA caused by a pipebreak in the operating recirculation loop, the Emergency CoreCooling 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 alsobeen performed for single recirculation loop operation (Ref. 7)and demonstrate sufficient flow coastdown characteristics tomaintain fuel thermal margins during the abnormal operationaltransients analyzed provided the MCPR requirements aremodified. During single recirculation loop operation,modification to the Reactor Protection System (RPS) averagepower range monitor (APRM) instrument is also required toaccount for the different relationships between recirculationdrive flow and reactor core flow. =The APLHGR and MCPRsetpoints for single loop operation are specified in the COLR.The APRM Flow Biased Simulated Thermal Power-Highsetpoint is in LCO 3.3.1.1, "Reactor Protection System (RPS)Instrumentation."

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

(continued)


tRecirculation Loops OperatingB 3.4.1

BASES (continued)

LCO Two recirculation loops are required to be in operation with theirflows matched within the limits specified in SR 3.4.1.1 to ensurethat during a LOCA caused by a break of the piping of onerecirculation loop the assumptions of the LOCA analysis aresatisfied. With the limits specified in SR 3.4.1.1 not met, therecirculation loop with the lower flowmust be considered not inoperation. 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, 'MINIMUMCRITICALPOWER RATIO (MCPR)"), and APRM Flow Biased SimulatedThermal Power-High Setpoint (LCO 3.3.1.1) may be applied toallow continued operation consistent with the assumptions of

!

References 7 and 8.

APPLICABILITY In MODES 1 and 2, requirements for operation of the ReactorCoolant Recirculation System are necessary since there isconsiderable energy in the reactor core and the limiting designbasis 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)


ecirculation Loops OperatingB 3.4.1

BASES (continued)

ACTIONS A.'I

With the requirements of the LCO not met, the recirculationloops must be restored to operation with matched flows within24 hours. A recirculation loop is considered not in operationwhen the pump in that loop is idle or when the mismatchbetween total jet pump flows of the two loops is greater thanrequired limits. The loop with the lower flow must beconsidered not in operation. Should a LOCA occur with onerecirculation loop not in operation, the core flow coastdown andresultant core response may not be bounded by the LOCAanalyses. Therefore, only a limited time is allowed to restorethe inoperable loop to operating status.

Alternatively, ifthe single loop requirements of the LCO areapplied to the operating limits and RPS setpoints, operationwith only one recirculation loop would satisfy the requirementsof the LCO and the initial conditions of the accident sequence.

continued



BASES

ACTIONS A.1 (continued)

The 24 hour Completion Time is based on the low probability ofan accident occurring during this time period, on a reasonabletime to complete the Required Action, and on frequent coremonitoring by operators allowing abrupt changes in core flow .conditions to be quickly detected.

This Required Action does not require tripping the recirculationpump in the lowest flow loop when the mismatch between totaljet pump flows of the two loops is greater than the required

'imits.However, in cases where large flow mismatches occur,low flow or reverse fiow can occur in the low flow loop jetpumps, causing vibration of the jet pumps. Ifzero or reverseflow is detected, the condition should be alleviated by changingpump speeds to re-establish forward flow or by tripping thepump.

continued



BASES

ACTIONS(continued)

B.1

With no recirculation loops in operation while in MODES 1 or 2or the Required Action and associated Completion Time ofCondition A not met, the plant must be brought to a MODE in )which the LCO does not apply. To achieve this status, the plantmust be brought to MODE 3 within 12 hours. In this condition,the recirculation loops are not required to be operating becauseof the reduced severity of DBAs and minimal dependence onthe recirculation loop coastdown characteristics. The allowedCompletion Time of 12 hours is reasonable, based on operatingexperience, to reach MODE 3 from full power conditions in anorderly manner and without challenging plant systems.

(continued)


., Recirculation Loops Operating8 3.4.1

BASES (continued)


SR 3.4.1.1

This SR ensures the recirculation loops are within the allowablelimits for mismatch. At low core flow (i.e., < 70% of rated coreflow), the MCPR requirements provide larger margins to the fuelcladding integrity Safety Limitsuch that the potential adverse .effect of early boiling transition during a LOCA is reduced. Alarger 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 fromall of the jet pumps associated with a single recirculation loop.

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

'circulation operation. The Surveillance must be performedwithin 24 hours after both loops are in operation. The 24 hourFrequency is consistent with the Surveillance Frequency for jetpump OPERABILITYverification and has been shown byoperating experience to be adequate to detect offnormal jetpump loop flows in a timely manner.

(continued)


.'.Recirculation Loops OperatingB 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 TechnicalSpecification Improvements," July 23, 1993.

7. NEDO-24236, "Browns Ferry Nuclear Plant Units 1, 2, and3, Single-Loop Operation," May 1981.

8. NEDC-32484P, "Browns Ferry Nuclear Plant Units 1, 2, and3, SAFER/GESTR-LOCA Loss-of-Coolant AccidentAnalysis," Revision 2, December 1997.


MoDistribution Sheet

Distri63.txt

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Item: ADAMS DocumentLibrary: ML ADAMS"HQNTAD01ID: 003693731:1

Subject:Browns Ferry Units 2 8 3- Technical Specifications Change 401 - Changes to Limiting Condition for Operation (LCO) Time for Containment Atmosphere Dilution (CAD) Subsystem Inoperability

Body:ADAMS DISTRIBUTION NOTIFICATION.

Electronic Recipients can RIGHT CLICK and OPEN the first Attachment to Viewthe Document in ADAMS. The Document may also be viewed by searching for

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Accession Number ML003693731.Distri63.txt

D030 - TVA Facilities - Routine Correspondence

Docket: 05000260Docket: 05000296

Page 2

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

March 15, 2000

TVA-BFN-TS-40110 CFR 50.410 CFR 50.90

U.S. Nuclear Regulatory CommissionATTN: Document Control DeskWashington, D.C. 20555

Gentlemen:

Docket Nos. 50-26050-296

In the Matter of )Tennessee Valley Authority )

BROWNS FERRY NUCLEAR PLANT (BFN) — UNITS 2 AND 3 — TECHNICALSPECIFICATIONS (TS) CHANGE 401 — CHANGES TO LIMITINGCONDITION FOR OPERATION (LCO) TIME FOR CONTAINMENTATMOSPHERE 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) tolicenses DPR-52 and DPR-68 to revise LCO 3.6.3.1, CADSystem, to provide 7 days of continued operation with twoinoperable CAD subsystems.

This TS change request is consistent with the TS provisionsfor the CAD system in NUREG-1433, Revision 1, ImprovedStandard Technical Specifications for BWR/4 Plants.Regarding precedent, several other boiling water reactors,including Hatch 1, Duane Arnold, and Peach Bottom, all haveTS which provide for comparable periods of continuedoperation with inoperable CAD subsystems.

Enclosure 1 to this letter provides the description andjustification for the proposed TS change, and thesignificant hazards and environmental impact considerations.Enclosure 2 contains mark-up copies of the appropriate pagesfrom the current Unit 2 and 3 TS showing the proposedrevisions.

U.S. Nuclear Regulatory Commission&age 2March 15, 2000

TVA has determined that there are no significant hazardsconsiderations associated with the proposed change and thatthe TS change qualifies for a categorical exclusion fromenvironmental review pursuant to the provisions of 10 CFR51.22(c) (9). The BFN Plant Operations Review Committee andthe Nuclear Safety Review Board have reviewed this proposedchange, and determined that operation of BFN Units 2 and 3in accordance with the proposed change will not endanger thehealth and safety of the public. Additionally, in accordancewith 10 CFR 50.91(b)(1), TVA is sending a copy of thisletter and enclosures to the Alabama State Department ofPublic Health.

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

E. yManager ice s

and ndustry Azngfairs

Subsc ibed and s orn to before meon his da of March 2000.

Notary PublicMy Commission Expires 09/22/2002

Enclosurescc,:. See page 3

~ ~

1I. t *4

.U.S. Nuclear Regulatory CommissionPage 3March 15, 2000

Enclosurescc (Enclosures):

ChairmanLimestone County Commission310 West Washington StreetAthens, Alabama 35611

Mr. Paul Fredrickson, Branch ChiefU.S. Nuclear Regulatory CommissionRegion II61 Forsyth Street, ST W.Suite 23T85Atlanta, Georgia30303

Mr. William O. Long, Project ManagerU.S. Nuclear Regulatory CommissionOne White Flint, North11555 Rockville PikeRockville, Maryland 20852

NRC Resident InspectorBrowns Ferry Nuclear Plant10833 Shaw RoadAthens, Alabama 35611

State Health OfficerAlabama State Department of Public Health434 Monroe StreetMontgomery, Alabama 36130-3017


UNITS 2 and 3

PROPOSED TECHNICAL SPECIFICATIONS (TS) CHANGE TS-401CHANGES TO LIMITING CONDITION FOR OPERATION (LCO) TIME FOR

CONTAINMENT ATMOSPHERE DILUTION (CAD) SUBSYSTEM INOPERABILITYINDEX OF ENCLOSURES

ENCLOSURE 1 - DESCRIPTION OF PROPOSED CHANGE AND JUSTIFICATION

I.II.

III.IV.V.

VI.VII.

DESCRIPTION OF THE PROPOSED TS CHANGEREASON FOR THE PROPOSED CHANGEDISCUSSIONCONCLUS IONS ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~NO SIGNIFICANT HAZARDS CONSIDERATIONDETERMINATIONENVIRONMENTAL IMPACT CONSIDERATIONREFERENCES

El- 1.El- 1.El- 3.El- 9

.El-10

.El-12

.El-12

ENCLOSURE 2 - MARKED-UP TS/BASES CHANGES

ENCLOSURE 1


UNITS 2 and 3


CONTAXNMENT ATMOSPHERE DILUTION (CAD) SUBSYSTEMINOPERABILITY

DESCR'IPTION OF PROPOSED CHANGE AND JUSTIFICATION

I. DESCRIPTION OF THE PROPOSED TS CHANGETVA is requesting changes to the Units 2 and 3 TS LCO3.6.3.1, CAD System, to provide a completion time of7 days of continued reactor operation with two CADsubsystems inoperable. This change is consistent withthe BWR/4 Standard Technical Specifications (STS),NUREG-1433, Revision 1, for the CAD system. The currentTS LCO requires reactor shutdown within 13 hours underLCO 3.0.3 when both CAD subsystems are inoperable.

The TS Bases are likewise being modified to match theproposed TS changes. A mark-up copy showing the proposedTS and Bases changes is provided in Enclosure 2 ~ Achange to Unit 1 TS is not being requested at this timesince 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 CHANGEBFN Units 1, 2, and 3 share a common CAD system. Thesystem is comprised of two redundant subsystems each ofwhich contains an external liquid nitrogen storage tankand the piping, valving, instrumentation, and controlsnecessary to inject nitrogen gas to the primarycontainment of any of the BFN units. The current TS forBFN provides for a 30-day LCO whenever one of the tworedundant CAD subsystems becomes inoperable. Nospecific LCO is provided for the condition when both CADsubsystems are inoperable. Therefore, should both CADsubsystems become inoperable, the current TS wouldrequire that all operating units be placed in MODE 3within 13 hours in accordance with the requirements ofLCO 3.0.3.

The current TS, which requires an expedited forcedshutdown of one or both BFN units because of short-termCAD system inoperability, is disproportionate with theoverall safety function of the CAD system. Therefore, arelaxation to the CAD system LCO to provide a limited7-day time period of continued operation is beingproposed. This change is consistent with BWR/4 STSwhich already provide for a 7-day Completion Time whenboth CAD subsystems are inoperable if an alternatehydrogen control function is maintained. For BFN, thecontainment inerting system provides the alternate meansof hydrogen control.

The primary objective of this proposed TS change is toreduce the likelihood of the forced shutdown of thereactor(s) resulting from short-term loss of the CADsubsystems due to unanticipated maintenance problems.This would avoid the inherent risks associated withreactor shutdown activities resulting from maintenanceissues that could be corrected in a timely manner. Thisrisk avoidance concern is exacerbated by'the prospect ofshutting down two units in a short time period.

Although it is not typical for both CAD systems to beinoperable, there is a reasonable probability that thissituation may occur, particularly during periods whenone of the CAD subsystems is out of service forscheduled testing, or corrective or preventivemaintenance. For this situation with the existing TS,the invocation of LCO 3.0.3 for two inoperable CADsystems is very restrictive with regard to being able toreturn a subsystem to service or to performunanticipate'd corrective maintenance within the 13-hourLCO. With the proposed 7-day completion time, we expectthat a subsystem could be returned to service orcorrective maintenance be performed to remedy any likelyCAD system equipment problem prior to exceeding the LCO.

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

III. DISCUSSIONCAD S stem Descri tion and Desi BasisDuring normal power operation, the containment inertingsystem is used to maintain the primary containmentatmosphere at less than 4.0 percent oxygen by volume,with the balance in nitrogen. Following aloss-of-coolant accident (LOCA), hydrogen is postulatedto be evolved within the containment from metal-waterreactions, and hydrogen and oxygen are produced byradiolysis of water. These are the only significantsources of hydrogen and oxygen. 3f the concentrations ofhydrogen and oxygen were not controlled, a combustiblegas mixture could theoretically be produced. To ensurethat a combustible gas mixture does not form, the oxygenconcentration is kept below 5 percent by volume, or thehydrogen concentration is kept below 4 percent by volumeby operation of the CAD system.

Assuming the analytic hydrogen and oxygen generationrates as specified in Safety Guide 7, Control ofCombustible Gas Concentrations in Containment Followinga Loss-of-Coolant Accident, the concentration ofcombustible gases in containment following a LOCA iscontrolled by the CAD system. This is accomplished byinjecting nitrogen gas into the containment from one oftwo redundant CAD liquid nitrogen storage tanks todilute any oxygen generated by the LOCA and by ventingthe containment atmosphere as necessary through thestandby gas treatment system. Refer to the 5.2-7 and5.2-8 Figures in the Final Safety Analysis Report (FSAR)for a flow diagram of the CAD system.This system is capable of keeping the concentration ofoxygen in the containment atmosphere below 5 percent.Xn the event that postaccident monitoring showed thathydrogen and oxygen generation rates were substantiallybelow those specified in the Safety Guide, the CADsystem could be operated as necessary to maintain eitherthe hydrogen concentration below 4 percent or the oxygenconcentration below 5 percent. The time required toproduce significant amounts of oxygen through radiolysisis lengthy and in the LOCA analysis CAD operation is notrequired until hours after a LOCA.

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

CAD Subsystem A provides a backup pneumatic source foroperation of the Hardened Wetwell Vent valves and thetorus vacuum breaker isolation valves. The current TSallows for a single CAD subsystem to be inoperable for30 days, where, in the case of CAD Subsystem A, thisbackup function is not available. Therefore therequested TS LCO of allowing both CAD subsystems to beinoperable for 7-days does not extend the period thatthis backup function may be unavailable.

BWR OWNERS GROUP EVALUATION OF COMBUSTIBLE GAS CONTROL

The BWR Mark I Owners Group undertook a substantialstudy in response to the addition of the provisions in10 CFR 50.44(c)(3) requiring recombiner capability forthose light water reactors that rely uponpurge/repressurization systems as a primary means ofhydrogen control. This study was published asNED0-22155, Generation and Mitigation of CombustibleMixtures in Inerted BWR Mark I Containments, June 1982.This NEDO concluded that the oxygen generation ratesassumed in Safety Guide 7 (subsequently RegulatoryGuide 1.7) were overly conservative and that maintainingan inerted containment during operation was sufficientto provide combustible gas control.

El-4

Following review of this study, NRC issued GenericLetter 84-09, which stated that the BWR Mark I plantsaffected by the recombiner rule (including BFN) did notneed to rely on use of a safety gradepurge/repressurization system (CAD) specified by 10 CFR50.44(f) and (g) as a primary means of hydrogen controlprovided that three technical criteria were met.

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

1. The plant has TS LCOs requiring containmentatmosphere oxygen concentration to be maintainedless than 4. by volume;

2. The plant has only nitrogen or recycled containmentatmosphere for use in all pneumatic control systemswithin containment, and;

3. There are no potential sources of oxygen incontainment other than that resulting fromradiolysis of the reactor coolant.

BFN is designed and operated in accordance with thesecriteria as follows: 1) The BFN primary containment ismaintained below 4 percent oxygen by volume duringnormal operation in accordance with TS LCO 3.6.3.2 usingnitrogen gas from the containment inerting system;2) All pneumatic equipment located inside the primarycontainment utilizes recycled containment atmosphere(drywell compressor system) as its'pneumatic supply.Furthermore, station control air is not used to providethe pneumatic supply to containment equipment duringperiods of reactor operation; 3) Pathways which couldintroduce oxygen into the primary containment areisolated during normal operation.

El-5

Subsequently NRC issued an SER dated July 6, 1989, whichevaluated NEDO-22155. The SER concluded that, in someareas, the NEDO-221SS analysis under-predicts oxygenradiolysis generation rates. However, the SER alsostated that Regulatory Guide 1.7 (which supersededSafety Guide 7) is conservative in its overall oxygengeneration prediction. Therefore, a technical basisexists that the AEC Safety Guide 7 oxygen generationrates assumed in the BFN LOCA analysis are moreconservative than necessary. This provides additionaljustification for a TS allowance for a short period ofCAD system inoperability.

Ado tion of STS CAD LCO

BWR/4 Standard Technical Specifications, NUREG-1433,Revision 1, provide a 7-day continued operationallowance with two CAD systems inoperable if analternate hydrogen control system is verified available.For BFN, the normal containment inerting system providesthis hydrogen control function.

The normal containment inerting system is used duringthe initial purging of the primary containment toestablish an inerted containment, and it also provides asupply of make up nitrogen during reactor operation.The system consists of a liquid nitrogen storage tank, apurge vaporizer, a makeup vaporizer, pressure-reducingvalves and controllers, and instrumentation, valves, andassociated piping. Refer to the FSAR 5.2.6.a series offigures for flow diagrams of the system.

The normal inerting system supplies nitrogen from acommon onsite storage tank through a common purgevaporizer or makeup vaporizer where the liquid nitrogenis converted to the gaseous state. The gaseous nitrogenthen flows through the purge or make uppressure-reducing valves and flow meters into the torusor drywell.

E1-6

In the event of a LOCA, the Core Standby Cooling Systemsare designed to prevent significant fuel damage and thegeneration of significant quantities of hydrogen.Should fuel damage be postulated, and hydrogen andoxygen be generated per AEC Safety Guide 7 assumptions,the inerted primary containment at'mosphere ensures thatthe oxygen concentration is too low to react with thishydrogen gas. Hence, any oxygen which can react must begenerated from the radiolytic decomposition of waterunder post-LOCA conditions.

The primary containment inerting system can be used toprovide nitrogen dilution in a manner analogous to theCAD system. In fact, the BFN Emergency 'OperatingInstructions (EOIs) preferentially direct the use of thenormal primary containment inerting system for purgingand venting during emergency conditions. The EOIprocedural policy, which is in accordance with industryemergency procedure guidelines, recognizes that theinerting system is well suited for use under emergencyconditions since it is routinely used for purge and ventoperations under normal operations. Under thisprocedural direction, CAD serves as the backup methodrather than the primary means to mitigate anycombustible mixture formation. Therefore, the proposedTS change is consistent with this EOI usage of thenormal inerting system by requiring it to be functionalas the alternate hydrogen control function during anyperiod of reactor operation if both CAD subsystems areinoperable. This is consistent with STS provisions forCAD.

Risk ConsiderationsIn a qualitative sense, the Browns Ferry PSA baselineCDF values for Unit 2 and Unit 3 indicate a lowprobability per reactor year of a core-damaging event.Since CAD's formal design function is not needed unlesscore damage has already occurred, and the core damageprobability is low, a low probability of needing CAD forits design use can be observed directly from thebaseline CDF value. Since the baseline CDF value isbased on an annual time frame, and the proposed LCOunder discussion is only a small part of a year, thenthese low probabilities can be seen to be reduced evenfurther during an LCO period.

There are no planned maintenance or test activitieswhich remove both CAD systems from service. Therefore,the proposed TS is requested as a contingency provisionfor situations when both subsystems become inoperabledue to unexpected circumstances. The most likelycircumstance for this situation would be an unexpectedmaintenance problem on a CAD subsystem while the othersubsystem was out of service for preventive orcorrective maintenance.

The CAD design basis oxygen control function is notrequired until well, after a hydrogen producing LOCAevent has occurred because of the time necessary forradiolysis to produce sufficient oxygen inside primarycontainment. Since the safety-related design functionof CAD is not required prior to the occurrence of a coredamaging event (the interval evaluated by the BFN LevelI PSA), it follows that thi's,CAD function cannot impactcore damage frequency '(CDF) values.

BFN design basis calculations indicate that the CADfunction would not be needed sooner than 42 hourspost-accident under anticipated containment conditions.The BFN Level II PSA evaluation for large early releasefrequency (LERF) is concerned with the first 24 hourspost-accident, therefore, the availability of the CADfunction does not affect LERF.

Also, as noted earlier, the proposed LCO will alsoprovide that the containment inerting system be verifiedavailable if both CAD subsystems are inoperable. Thecontainment inerting system, although not safety-grade,'can provide the analogous combustible gas controlfunction as CAD. In the BFN symptom based EOIs, it isused in several contingencies to provide containmentinerting functions. The inerting system tank as well asthe CAD tanks are located external to the reactorbuilding and can be easily accessed. Therefore, it iseasy to refill the inerting tank or CAD tanks usingnitrogen tank trucks as contingency options.

El-8

The CAD system non-safety function of supplying backuppneumatic motive energy for long term MSRV operation hasnominal relevance to PSA core damage frequency (CDF)calculations, because MSRV operation can affect CDF.However, the PSA modeling shows there is no significantchange to the Unit 2 or Unit 3 CDF when the CAD backuppneumatic supply function is assumed to be either 100%available or never available (i.e., risk-reduction worthor risk-achievement worth values are not significant).

In summary, the addition of TS provisions for the 7-dayCAD LCO has little impact on risk. Anticipated use ofthe LCO is as a contingency specification for unexpectedmaintenance problems on the CAD system. The CAD systemis monitored under the BFN Maintenance Rule Program, andCAD subsystem unavailability is unlikely to increase asa result of issue of the proposed TS change. A longerLCO would provide an opportunity to remedy the systemproblem and return a subsystem to service in an orderlymanner. This would avoid the inherent transition riskassociated with an expedited shutdown of multiple units.Therefore, the proposed TS change is consideredbeneficial with regard to risk considerations.

IV. CONCLUSION

The BFN Unit 2 and Unit 3 Technical Specificationscurrently require a shutdown to Mode 3 under theconditions of LCO 3.0.3 if both CAD subsystems becomeinoperable. The low probability of a fuel-damagingaccident occurring during a 7-day.,period, the fact thatCAD is not required to be put in service immediatelypost-accident, and the availability of oxygen mitigationsystems other than CAD which are preferred under theEOIs make the requested TS change acceptable. Theproposed change is also consistent with STS. Also,previous regulatory studies (NEDO-22155) concluded thatthe AEC oxygen generation source terms are conservative,and that the inerted containment provides the chiefprotection against the creation of combustible mixturesin the primary containment atmosphere.

El-9

A review of Improved TS approved at other BWRs ofsimilar design, such as Peach Bottom Units 2 and 3, andHatch Unit 1, found that 7 days or greater LCO timeswere typical for conditions where both CAD subsystemswere inoperable. The justification provided at theseplants is similar to that used in this submittal, i.e.,the risk of a LOCA during the LCO interval is small, CADusage is not immediately required even should a fuel-damaging accident occur, and that alternate hydrogencontrol capability exists within the plant design. Asnoted previously, 7-days is provided in STS for plantswith an alternate hydrogen control function such asBrowns Ferry.

V. NO SIGNIFICANT HAZARDS CONSIDERATION DETERMINATION

DESCRIPTION OF PROPOSED AMENDMENT

The proposed amendment to the BFN Unit 2 and Unit 3 TSwould establish an LCO time of up to 7 days with nooperable CAD subsystem provided the unit's PrimaryContainment Inerting System is available to provide analternate hydrogen control capability.

TVA has concluded that operation of BFN Units 2 and 3 inaccordance with the proposed change to the TS does notinvolve a significant hazards consideration. TVA'sconclusion is based on its evaluation, in accordancewith 10 CFR 50.91(a)(1), of the three standards setforth in 10 CFR 50.92(c).

A. The ro osed amendment does not involve asi ificant increase in the robabilit orconse ences of an accident reviousl evaluated.

The safety-related function of the ContainmentAtmosphere Dilution (CAD) system is to mitigate theeffects of a loss-of-coolant-accident (LOCA) bylimiting the volumetric concentration of oxygen inthe primary containment atmosphere. The CAD Systemis not an event initiator, therefore, theprobability of the occurrence of an accident is notaffected by this proposed Technical Specification(TS) change. Emergency procedures preferentiallyuse the normal containment inerting system to

provide post-accident vent and purge capability,with the CAD system only serving in a backup roleto this system. Hence, in the event of theinoperability of both CAD subsystems, the proposedTS require the normal containment inerting systemto be verified available as an alternate oxygencontrol means. Therefore, the proposed TS changedoes not involve a significant increase in theprobability or consequences of an accidentpreviously evaluated.

B. The ro osed amendment does not create theossibilit of a new or different kind of accident

from an accident reviousl evaluated.

This TS change does not result in any changes tothe CAD equipment design or capabilities or to theoperation of the plant. Since the change impactsonly the required action completion time forperiods of CAD subsystem inoperability and does notresult in any change in the response of theequipment to an accident, the change does notcreate the possibility of a new or different kindof accident from any previously analyzed.

C. The ro osed amendment does not involve asi ificant reduction in a mar in of safet

As stated in GL 84-09, a Mark I type boiling waterreactor (BWR) plant is not considered to rely uponpurge/repressurization systems such as CAD as itsprimary means of hydrogen control when the unit(s)is operated in accordance with certain technicalcriteria. The BFN units are operated in accordancewith these criteria. The BFN Unit 2 and Unit 3containments are inerted with nitrogen duringnormal operation, recycled containment atmosphereis used for pneumatically operated componentsinside containment, and there are no potentialsources of oxygen generation inside containmentother than the radiolytic decomposition of water.The system preferred by the EOIs for oxygen controlpost-accident is the normal primary containment

inerting system. Because the probability of anaccident involving hydrogen and oxygen productionis small; CAD is not the primary system used tomitigate the creation of combustible containmentatmosphere mixtures, and because the requested LCOwhere both CAD subsystems is inoperable is notlong, no significant reduction in the margin ofsafety is associated. with this proposed amendment.

VI. ENVIRONMENTAL IMPACT CONSIDERATION

The proposed change does not involve a significanthazards consideration, a change in the types of, orincrease in, the amounts of any effluents that may bereleased off-site, or a significant increase inindividual or cumulative occupational radiationexposure. Therefore, the proposed change meets theeligibility criteria for categorical exclusion setforth in 10 CFR 51.22(c) (9). Therefore, pursuant to10 CFR 51.22(b), an environmental assessment of theproposed change is not required.

VII. REFERENCES

1. General Electric report, NED0-22155, Generationand Mitigation of Combustible Mixtures in InertedBWR Mark I Containments, June 1982

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

3. NRC SER on General Electric Company's Methodologyfor Determining Rates of Generation of Oxygen byRadiolytic Decomposition (NEDO 22155) - July 6,1989

E1-12

ENCLOSURE 2


UNITS 2 and 3


CONTAINMENT ATMOSPHERE DILUTION (CAD) SUBSYSTEM INOPERABILITY

AFFECTED PAGE LIST

Unit 23 '-41

B 3.6-98

Unit 33.6-41

B 3.6-98

: 3.6 CONTAINMENTSYSTEMS

3.6.3.1 Containment Atrriosphere Dilution (CAD) System

CAD System3.6.3.1

LCO 3.6.3.1 Two CAD subsystems shall be OPERABLE.


ACTIONS

[note: new text below,is shown in bold typein the shaded areasi


A. One CAD subsysteminoperable.

—————NOTELCO 3.0.4 is notapplicable

A.1 Restore CAD subsystemto OPERABLE status.

30 days

Two CADsubsystemsinoperable=

B.1 Verify by administrativemeans that the,hydrogen-controlfunction is maintained. '

hour

AND,

once per 12hours thereafter

AND

8-. Required Action andassociated CompletionTime not met.

B.2 Restore CAD subsystemnitrogen admissionflowpath'o OPERABLEstatus

BA Be in MODE 3.

C.1

7 days

12 hours


BASESinsert text from next page here

CAD SystemB 3.6.3.1

ACTIONS(continued)

C.1

Ifany Required Action cannot be met within the associatedCompletion Time, the plant must be brought to a MODE inwhich the LCO does not apply. To achieve this status, the plantmust be brought to at least MODE 3 within 12 hours. Theallowed Completion Time of 12 hours is reasonable, based onoperating experience, to reach MODE 3 from full powerconditions in an orderly manner and without challenging plantsystems.


SR 3.6.3.1.1

Verifying that there is t 2500 gal of liquid nitrogen supply ineach nitrogen storage tank will ensure at least 7 days ofpost-LOCA CAD operation. This minimum volume of liquidnitrogen allows sufficient time after an accident to replenish thenitrogen supply for long term inerting. This is verified every31 days to ensure that the system is capable of performing itsintended function when required. The 31 day Frequency isbased on operating experience, which has shown 31 days to bean acceptable period to verify the liquid nitrogen supply and onthe availability of other hydrogen mitigating systems.

continued

BFN-UNIT2 B 3.6-98 Revision 0

t This new text will e added tothe Unit 2 TS Bases as indicatedon the previous page.

B.1 and 8.2With two CAD subsystems inoperable, the ability to controlthe hydrogen control function via alternate capabilitiesmust be verified by administrative means within 1 hour.The alternate hydrogen control capabilities are provided bythe Primary Containment lnerting System. The 1 hourCompletion Time allows a reasonable period of time toverify that a loss of hydrogen control function does notexist In addition, the alternate hydrogen control system(Primary Containment lnerting) capability must be verifiedonce per 12 hours thereafter to ensure its continuedavailability. Both the initial verification and all subsequentverifications may be performed as an administrative checkby examining logs or other information to determine theavailability of the alternate hydrogen control system(Primary Containment Inerting). Ifthe ability to perform thehydrogen control function is maintained via the PrimaryContainment Inerting System, continued operation for up to7 days is permitted with two CAD subsystems inoperable.

The Completion Time of 7 days is a reasonable time toallow continued reactor operation with two CADsubsystems inoperable because the hydrogen controlfunction is maintained (via the Primary ContainmentInerting System) and because of the low probability of theoccurrence of a LOCA that would generate hydrogen inamounts capable of exceeding the flammability limit.

, 3.6 CONTAINMENTSYSTEMS

3.6.3.1 Containment Atmosphere Dilution (CAD) System

CAD System3.6.3.1

LCO 3.6.3.1 Two CAD subsystems shall be OPERABLE.


ACTIONS

[note: new text belowis shown in bold typein the shaded areas]


A. One CAD subsysteminoperable.

—————NOTE————LCO 3.0.4 is notapplicable

A.1 Restore CAD subsystemto OPERABLE status.

30 days

Two CADsubsystemsinoperable'.1

Verify by administrativemeans that thehydrogen controlfunction is maintained.

1- hour

AND,

once per 12hours thereafter

AND

B.2 Restore CAD subsystemnitrogen admission

, flowpath. to OPERABLEstatus

7 days

8-. Required Action andassociated CompletionTime not met.

SA. Be in MODE 3.

C.1

12 hours

BFN-UNIT 3 3.6-41 Amendment No. 212

BASESInsert text from next page here

CAD SystemB 3.6.3.1

ACTIONS(continued)

S4 ~ C.1Ifany Required Action cannot be met within the associatedCompletion Time, the plant must be brought to a MODE inwhich the LCO does not apply. To achieve this status, the plantmust be brought to at least MODE 3 within 12 hours. Theallowed Completion Time of 12 hours is reasonable, based onoperating experience, to reach MODE 3 from full powerconditions in an orderly manner and without challenging plantsystems.


SR 3.6.3.1.1

Verifying that there is > 2500 gal of liquid nitrogen supply ineach nitrogen storage tank willensure at least 7 days ofpost-LOCA CAD operation. This minimum volume of liquidnitrogen allows sufficient time after an accident to replenish thenitrogen supply for long term inerting. This is verified every31 days to ensure that the system is capable of performing itsintended function when required. The 31 day Frequency is

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

continued

BFN-UNIT3 B 3.6-98 Revision 0

This new text will be added tothe Unit 3 TS Bases as indicatedon the previous page.

B.1 and B.2With two CAD subsystems inoperable, the ability to controlthe hydrogen control function via alternate capabilitiesmust be verified by administrative means within 1 hour.The alternate hydrogen control capabilities are provided bythe Primary Containment Inerting System. The 1 hourCompletion Time allows a reasonable period of time toverify that a loss of hydrogen control function does notexist. In addition, the alternate hydrogen control system(Primary Containment lnerting) capability must be verifiedonce per 12 hours thereafter to ensure its continuedavailability. Both the initial verification and all subsequentverifications may be performed as an administrative checkby examining logs or other information to determine theavailability of the alternate hydrogen control system(Primary Containment Inerting). Ifthe ability to perform thehydrogen control function is maintained via the PrimaryContainment 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 toallow continued reactor operation with two CADsubsystems inoperable because the hydrogen controlfunction is maintained (via the Primary Containmenttnerting System) and because of the low probability of theoccurrence of a LOCA that would generate hydrogen inamounts capable of exceeding the flammability limit.

Distribution Sheet

Priority: Normal

From: Stefanie Fountain

Distri66.txt

Action Recipients:W Long

Internal Recipients:RES/DET/ERABOGC/RPNRR/DgFILE CENTER 0ACRS

Copies:1 Not Found

Not FoundNot Found

Not FoundNot Found

Not Found

External Recipients:NOAC Not Found

Total Copies:

Item: ADAMS PackageLibrary: ML ADAMS"HQNTAD01ID: 003684247

Subject:OR Submittal: Append J Containment Leak Rate Testing

Body:

Docket: 05000260, Notes: N/A


Page 1

~ w

n

0I

!'

Tennessee Valley Authority, Post Olfice Box 2000, Oecatur. Alabama,35609

February 4, 2000

U.S. Nuclear Regulatory CommissionATTN: Document Control DeskWashington, D.C. 20555

Gentlemen:

In the Matter ofTennessee Valley Authority

Docket. Nos. 50-26050-296

BROWNS FERRY NUCLEAR PLANT (BFN) — UNITS 2 AND 3 — RESPONSETO REQUEST FOR ADDITIONAL INFORMATION REGARDING TECHNICALSPECIFICATIONS (TS) CHANGE NO. 399 — INCREASED MAIN STEAMISOLATION VALVE (MS IV) LEAKAGE RATE LIMITS AND EXEMPTION FROM10 CFR 50 APPENDIX J — REVISED TS PAGES FOR INCREASED MSIVLEAKAGE LIMITS (TAC NOS MA6405 r MA640 6 r MA681 5 AND MA681 6)

This letter responds to the November 23, 1999, Request forAdditional Information (RAI) regarding (TS-399) changerequest 399. TS-399, which was submitted on September 28,1999, proposes changes to the Unit 2 and 3 TS to increase theallowable leakage rate criteria for the MSIVs. In addition,in the September, 28, 1999, submittal, TVA requested exemptionto specific portions of 10 CFR 50, Appendix J to allow theexclusion of MSIV leakage from the summation of containmentleak rate test results.

Enclosure 1 of this letter provides the TVA response to thenine RAI questions. Enclosure 2 contains supportingcalculations for the condenser seismic assessment associatedwith RAI Item 7.

Enclosure 3 provides additional details regarding RAI Item 8which addresses specific NRC staff questions on dose analysismethods. Additionally, as discussed in Enclosure 3, TVA hasperformed specific MSIV dose calculations rather than usingextrapolation factors for the MSIV leakage. This revised

U.S. Nuclear Regulatory CommissionPage 2February 4, 2000

analysis resulted in a reduction of the requested MSIVallowable leakage rate requested in the September 28, 1999letter. Accordingly, a revised change request is provided inEnclosure 4. Enclosure 5 contains marked-up copies of theappropriate pages from the current Units 2 and 3 TS showingthe proposed revisions.

The revised pages provided in Enclosure 5 do not alter theoriginal determination that there are no significant hazardsconsiderations associated with the proposed changes, nor doesit alter the originally submitted Environmental Assessmentand Finding of No Significant Impact provided by theSeptember 28, 1999 letter. The BFN Plant Operations ReviewCommittee and the BFN Nuclear Safety Review Board havereviewed this proposed change and determined that operationof BFN Units 2 and 3 in accordance with the proposed changewill 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 inthe September 28, 1999, submittal which would allow exclusionof the MSIV leakage from the summation of containment leakrate test results. This exemption request supports the TSchange to increase the MSIV leakage criteria and is stillbeing requested. Additional information regarding the needfor the exemption is provided in the response to RAI Item 9.

Enclosure 6 provides a listing of commitments made in thissubmittal. If you have any questions, please contact me at(256) 729-2636.S'er y,

Manager lcenand I ustry Aff

lngirs

Enclosurescc: see pag 3

e4-)

'(

U.S. Nuclear Regulatory CommissionPage 3February 4, 2000

Enclosurescc (Enclosures):

Mr. Paul Frederickson, Branch ChiefU.S. Nuclear Regulatory CommissionRegion II61 Forsyth Street, S.W.Suite 23T85Atlanta, Georgia30303

Mr. William 0. Long, Project ManagerU.S. Nuclear Regulatory CommissionOne White Flint, North11555 Rockville PikeRockville, Maryland 20852

NRC Resident InspectorBrowns Ferry Nuclear Plant10833 Shaw RoadAthens, Alabama 35611

Distri68.txtDistribution Sheet

Priority: NormalFrom: Andy Hoy

Action Recipients:W LongNRR/DLPM/LPD2-2B Clayton

Internal Recipients:RES/DE/SSEB/SESOGC/HDS3F ENTER

Copies:111

Not FoundNot FoundNot Found

Not FoundNot FoundNot FoundNot Found

External Recipients:NRC PDRNOAC

Not'oundNot Found

Total Copies:

Item: ADAMS DocumentLibrary: ML ADAMS"HQNTAD01ID: 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;: 05000296, Notes: N/A

Page 1

Tennessee Valley Authority, Post Office Box 2000, Decatur, Alabama 35609-2000

December 1, 1999

U.S. Nuclear Regulatory CommissionATTN; Document Control DeskWashington, D.C. 20555

Gentlemen:

In the Matter ofTennessee Valley Authority

Docket No. 50-260I50-296

BROWNS FERRY NUCLEAR PLANT (BFN) — UNITS 2 AND 3, CORRECTEDINFORMATION FOR TECHNICAL SPECIFICATION CHANGE REQUEST TS-384,POWER UPRATE — (TAC NOS. M99711 AND M99712)

In a letter dated October 1, 1997 (Reference 1), TVA provideda proposed Technical Specification change that would allow BFNUnits 2 and 3 to operate at an uprated power of 3458 megawattsthermal. In a September 8, 1998 letter (Reference 2), NRCissued license amendments 254 and 214 approving TVA's requestfor uprated power operation,. for Units 2 and 3 respectively.

TVA's October 1, 1997 letter, contains information which TVAhas 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 PlantUnits 2 and 3", TVA stated that the main steam relief valve(MSRV) T-Quenchers are located above the elevation of theemergency core cooling systems (ECCS) torus suction while infact the T-Quenchers are located below the ECCS torus suction.The relative location of the two points (MSRV T-Quencherversus ECCS suction) formed the basis of TVA's conclusion thatan evaluation of local suppression pool temperature was notrequired for power uprate.

~pO

U. S. Nuclear Regulatory CommissionPage 2December 1, 1999

TVA's evaluation of local suppression pool temperature isprovided below:

Back round

On October 1, 1981, NRC published NUREG-0783, "SuppressionPool Temperature Limits For Boiling Water Reactor (BWR)Containments (Reference 3)." The NUREG established localtemperature limits for BWR suppression pools during MSRVdischarge. The primary plant transient of interest was anextended MSRV discharge such as a single stuck open MSRV whichwould produce high localized pool temperatures in onesuppression pool bay. NRC's concern was that high localizedsuppression pool temperatures could result in unstablecondensation of the steam bubbles thus inducing excessiveloads on the suppression chamber internal structures. Inresponse to NUREG-0783, each plant was required to prepare alocalized pool temperature analysis. For BFN, a localsuppression pool temperature analysis was documented by GEreport NEDC-22004, issued October 1981, "Browns Ferry NuclearPower Plant Units 1, 2, and 3 Suppression Pool TemperatureResponse."

GE report NED0-30832, "Elimination of Limit on BWR SuppressionPool Temperature for SRV Discharge with Quenchers", approvedin a Safety Evaluation Report (SER) on August 29, 1994(Reference 4), generically analyzed the issue using revisedtechniques. The report concludes that for plants employingT-Quenchers, the condensation loads over the full range ofpool temperatures up to the saturation temperature are lowcompared to loads from MSRV discharge line air clearing andthe Loss of Coolant Accidents (LOCA). The GE report concludesthat the NUREG-0783 limit on the suppression pool temperaturefor MSRV discharge through T-Quenchers is unnecessary andassociated plant operating limits may be replaced by limitsbased on other considerations.

A Brookhaven National Laboratory Report, prepared for thestaff to assist them in the review of NED0-30832, supports theNRC SER for NED0-30832, concurring with the GE findingsregarding structural loads. Additionally, the reportdiscussed steam ingestion by the ECCS pumps resulting in thepotential for pump cavitation or condensation induced waterhammer in the suction piping following collapse of the steambubbles or plume.

U. S. Nuclear Regulatory CommissionPage 3December 1, 1999.~ '.C

Based on information received from the Massachusetts Instituteof Technology (MIT), the Brookhaven report concluded that themaximum extent of any steam plume formed when saturatedconditions exist in the vicinity of a T-Quencher device willbe no greater than approximately 1.5 meters (4.92 feet).Thus, the Brookhaven report concluded that if the ECCS suctionis horizontally separated from the T-Quencher by at least1.5 meters (4.92 feet) (irrespective of the verticalrelationship of the two points), the plume/bubbles would notbe ingested by the ECCS suction.

The NRC agreed with GE report NEDO-30832 concerning loads onthe suppression chamber internal structures. However, the NRCdisregarded Brookhaven's 1.5 meter separation criteria forECCS suction separation and instead, stipulated in the 1994NRC SER for NEDO-30832 that the local suppression pooltemperature limit can be eliminated if the pump inlet for theECCS pumps is below the elevation of the MSRV T-Quenchers.This was intended to geometrically preclude the ingestion of athermal/steam plume and thus its potential impact on both thenet positive suction head (NPSH) of the ECCS pumps and waterhammer loads on the piping.

The October 1, 1997, BFN Power Uprate submittal stated thatthe evaluation of local pool temperature limit is notnecessary in accordance with NEDO-30832 since the T-Quenchersare above the RHR suction elevation. It has subsequently beendetermined that the T-Quenchers are located below the ECCStorus suction strainers.

Evaluation

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

The local suppression pool temperature analysis for BrownsFerry provided in GE report NEDC-22004-P, was reevaluated.The results of the re-evaluation show that the local pooltemperature is not sensitive to the small (5 percent) changein the initial reactor thermal power due to power uprate. Thereport contains a case for a stuck open relief valve (SORV) atboth hot shutdown and full power conditions with the same


assumptions regarding RHR cooling. The difference insuppression pool local temperature for these two cases isonly 9 degrees F. Assuming a linear relationship to power, afive percent increase in power would result in lessthan 0.5 degrees F additional temperature at the upratedcondition. The highest temperature for any case in GE reportNEDC-22004-P is 198 degrees F. Even with anadditional 0.5 degrees F, the report's conclusion that thelocal suppression pool temperature remains below the 200degrees F limit remains valid.Xn order to further address ECCS suction separation, TVA hasevaluated the physical configuration of the suppression pool,MSRV T-Quenchers, and ECCS suction strainers utilizing theinformation contained in NED0-30832, the NRC SER and theassociated Brookhaven report;

The ECCS system pumps take suction from the suppression poolthrough an ECCS ring header by way of four strainers connectedin parallel. The strainers inside the suppression chamber areGE stacked disk design, with a very large external open flowarea. The main steam relief valves discharge thoughT-Quenchers located on the opposite side of the suppressionchamber centerline from the ECCS strainers.

At the closest point, between the ECCS strainers and theT-Quenchers, the T-Quencher outer edge isapproximately 2.3 meters (7.54 feet) horizontal distance fromthe strainer outer edge, substantially exceeding the criteriaprovided by the Brookhaven report. This point on the ECCSstrainers is at approximately 528 feet 10 inches elevation.The centerline of the MSRV T-Quenchers is at elevation 526feet 6 inches.

The Brookhaven 4.92 feet criteria is based on the horizontaldistance from the T-Quencher to the outer edge of the steamplume at the surface of the pool. The horizontal extent ofthe steam plume is greatest at the pool surface since thehorizontal size of the steam plume would increase from theT-Quencher up to the surface due to the steam plume mixinghorizontally (i.e., expanding) as it rises through the pool.The steam plume should be even smaller than 4.92 feet near theelevation of the T-Quenchers which further increases theseparation between the steam plume and the strainers.


In the event of one stuck open MSRV at high reactor pressure,the ECCS systems would not operate at their full flowcapacity. In the initial phase of the event, reactor vesselmakeup would be accomplished via the normal feedwater system.If it became necessary to initiate ECCS makeup, the reactorcore isolation cooling (RCIC) system at 600 gallons perminute (gpm) and/or the high pressure coolant injection systemat 5000 gpm would be initiated. Normal suction for these twosystems is the condensate storage tanks. However, these pumpscan be aligned to the suppression pool and, therefore, wereconsidered for evaluation.

Due to the initiation of the RCIC and/or HPCI or due to highsuppression pool temperatures, both loops of the residual heatremoval (RHR) system in the suppression pool cooling modeat 13000 gpm per loop would be initiated. If necessary, theoperator could also initiate two loops of Core Spray on theirminimum flow paths at 620 gpm each loop. With a tota'l flowof 32840 gpm through the four strainers, TVA estimates thatthe approach velocity to each strainer would beapproximately 0.06 feet per second.

In the event of one stuck open MSRV at a reactor pressurebelow the shutoff head of the low pressure ECCS pumps, theECCS, systems would operate at their full flow capacity;however, the size of the steam/bubble plume would besignificantly smaller due to the lower reactor pressure andthus the separation criteria would be conservative.The 7.54 feet of horizontal separation provided in the BFNsuppression chamber would prevent the steam plume/bubbles fromreaching the ECCS suction strainers. Also, because the ECCSsuction strainers have a very large external open flow area,they have a low appro

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