Nuclear Regulatory Commission.1 4.1 REACTOR PROTEC SYSTEM LIMITINGCONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.1 Reactor P otect on S ste 4.1 Reactor otection S …

Enclosure lPROPOSED TECHNICAL SPECIFICATION

UNITS 1, 2, AND 3

(TVA BFN TS 286)

9006070am> 900eonPDR ADOCK 05000259P PDC

UNIT 1EFFECTIVE PAGE LIST

REMOVE INSERT

3.1/4.1-13;1/4.1-2

3.1/4.1-13.1/4.1-2

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.1 4.1 REACTOR PROTEC SYSTEM

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS

3.1 Reactor P otect on S ste 4.1 Reactor otection S ste

Applies to the instrumentationand associated devices whichinitiate a reactor scram.

Applies to the surveillanceof the instrumentation andassociated devices whichinitiate reactor

scram.'Ob

'ective ~Ob ective

To assure the operability of thereactor protection system.

To specify the type andfrequency of surveillance tobe applied to the protectioninstrumentation.

S ec cation S ecification

A. When there is fuel in the vessel,the setpoints, minimum number of

~ 'rip. systems, and minimum numberof instrument channels that must-'be OPERABLE for each MODE ofOPERATION shall be as givenin Table 3.1.A.

A. Instrumentation systems shallbe functionally tested andcalibrated as indicated inSables 4.1.A and 4.1.B,respectively.

B. Two RPS power monitoring channels

!for each inservice RPS MG set oralternate source shall be operable.

B. The RPS power monitoringsystem instrumentation shallbe determined operable:

With one RPS electric powermonitoring channel forinservice RPS MG set oralternate power supplyinoperable, restore theinoperable channel to operablestatus within 72 hours or removethe associated RPS MG set oralternate power supply fromservice.

l.. At least once per6 months by performanceof channel functionaltests.

BFNUnit 1

3.1/4.1-1

4 REACTOR RO EC S ST

LIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS

3.1 Reactor Protection S stem 4.1 Reactor Protection S stem

3.1.B. (Cont'd)

2. With both RPS electric powermonitoring channels for aninservice RPS MG set oralternate power supplyinoperable, restore at leastone to OPERABLE status within30 minutes or remove theassociated RPS MG set oralternate power supply fromservice.

4.1.B. (Cont'd)

2. At least once per 18 monthsby demonstrating the OPERA-BILITY of overvoltage, under-voltage and underfrequency.protective instrumentation bysimulated automatic logicactuation and verification ofthe circuit protector triplevel setting as follows.

(a) overvoltage g 132.0 VAC(b) undervoltage g 108.5 VAC(c) underfrequency g 56.0 Hz

BFNUnit 1

3.1/4.1-2


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1 4 3. REACTOR PROTEC SYSTEM~

'IMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS

3.1 Reactor Protection S stem 4;1 eactor Protection S stem

A cabi itApplies to the instrumentationand associated devices whichinitiate a reactor scram.

Applies to the surveillanceof the instrumentation andassociated devices whichinitiate reactor scram.

Ob ective Ob ective

To assure the operability of thereactor protection, system.

To specify the type andfrequency of surveillance tobe applied to the protectioninstrumentation.

S ecification S ecification

A. When there is fuel in the vessel,the setpoints, minimum number oftrip systems, and minimum numberof instrument channels that mustbe OPERABLE for MODE OF OPERATIONshall be as given in Table 3.1.A.

A. Instrumentation systems shallbe functionally tested andcalibrated as indicated inTables 4.1.A and 4.1.B,respectively.

B. Two RPS power monitoring channels

!for each inservice RPS MG set oralternate source shall be OPERABLE.

B. The RPS power monitoringsystem instrumentation shall

, be determined OPERABLE:

1. With one RPS electric powermonitoring channel forinservice RPS MG set oralternate power supplyinoperable, restore theinoperable channel to OPERABLEstatus within 72 hours or removethe associated RPS MG set oralternate power supply fromservice.

l. At least once per6 months by performanceof channel functionaltests.

BFNUnit 2

3.1/4.1-1

1 4 1 REACTOR ROTEC SYSTE


3.1 Reactor Protection S stem 4.1 Reactor Protection S stem

3.1.B. (Cont'd)

2. With both RPS electric powermonitoring channels for aninservice RPS MG set oralternate power supplyinoperable, restore at leastone to O'PERABLE status within30 minutes or remove theassociated RPS MG set oralternate power supplyfrom service.

4.1.B. (Cont'd)

2. At least once per 18 monthsby demonstrating the OPERA-BILITY of overvoltage, under-voltage and underfrequencyprotective instrumentation bysimulated automatic logicactuation and verification ofthe circuit protector triplevel setting as follows.

(a) overvoltage g 132.0 VAC(b) undervoltage g 108.5 VAC(c) underfrequency g 56.0 Hz

BFNUnit 2

3;1/4.1-2


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4 1 REAC S S E


3.1 Reactor Protectio S ste 4.1 'Reactor P otect on S stem

cab itApplies to the instrumentationand associated devices whichinitiate a reactor scram.

Applies to the surveillanceof the instrumentation andassociated devices whichinitiate reactor scram.

Ob ective ~Oh 'ective

To assure the operability of thereactor protection system.

To specify the type andfrequency of surveillance tobe applied .to the protectioninstrumentation.

S ecification S ecification

A. When there is fuel in thevessel, the setpoints, minimumnumber of trip systems, andminimum number of instrument,channels that must be OPERABLEfor each MODE OF OPERATIONshall be as given in Table 3.1.A.

A. Instrumentation systemsshall be functionallytested and calibrated asindicated in Tables 4.1.Aand 4.1.B, respectively.

B. Two RPS power monitoring channelsfor each inservice RPS MG setor alternate source shall beOPERABLE.

B. The RPS power monitoringsystem instrumentation shallbe determined OPERABLE:

1. With one RPS electric powermonitoring channel for-inservice RPS MG set oralternate power supply inop-erable, restore the inoper-able channel to OPERABLEstatus within 72 hours orremove the associated RPSMG set or alternate powersupply from service.

l. At least once per6 months by performanceof channel functionaltests.

BFNUnit 3

3.1/4.1-1

3 1 4 1 REACTOR PROTEC SYSTEM

KIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS

3.1 Reacto Protection S ste

3.1.B. (Cont'd)

4.1 Reactor Protection S ste

4.1.B. (Cont'd)

2. With both RPS electric powermonitoring channels for aninservice RPS MG set oralternate power supplyinoperable, restore at leastone to OPERABLE status within30 minutes or remove theassociated RPS MG set oralternate power supplyfrom service.

2. At least once per 18 monthsby demonstrating the OPERA-BILITY of overvoltage, under-voltage and underfrequencyprotective instrumentation bysimulat'ed automatic logicactuation and verification ofthe circuit protector triplevel setting as follows.

(a) overvoltage g 132.0 VAC(b) undervoltage g 108.5 VAC(c) underfrequency y 56.0 Hz

BFNUnit 3

3.1/4.1-1a

ENCLOSURE 2

SUMMARY OF CHANGES

l. Add surveillance requirement 4.1.B.2 for unit 1."2. At least once per 18 months by demonstrating the OPERABILITY of

overvoltage, undervoltage, and underfrequency protective.instrumentation by simulated automatic. logic actuation andverification of the circuit protector trip level setting as follows.

(a) overvoltage(b) undervoltage(c) underfrequency

g 132.0 VACg 108.5 VACy 56.0 Hz"

2. Revise surveillance requirement 4.1.B.2 for unit 2.

Existing surveillance requirement 4.1.B.2 reads in part:

.(a) overvoltage (all device)(b) undervoltage (MG set)(c) undervoltage (alt. supply)(d) underfrequency (all devices)

g 126.5 VACg 113.4 VACg 111.8 VACg 57.0 Hz"

Revised surveillance requirement 4.1.B.2 would read in part:

.(a) overvoltage(b) undervoltage(c) underfrequency

~132.0 VACg 108.'5 VACg 56.0 Hz"

3. Add limiting conditions for operation 3.1.B.1 and 3.1.B.2 for unit 3."B, Two RPS power monitoring channels for each inseryice RPS MG set or

alternate source shall be OPERABLE.

l. With one RPS electric power monitoring channel for inservice RPSMG set or alternate power supply inoperable, restore theinoperable channel to OPERABLE status within 72 hours or removethe associated RPS MG set or alternate power supply from service.

2. With both RPS electric power monitoring channels for an inserviceRPS MG set or alternate power supply inoperable, restore at leastone to OPERABLE status within 30 minutes or remove the associatedRPS MG set or alternate power'upply from service."

4. Add surveillance requirements 4.1.B.1 and 4.1.B.2 for unit 3.

"B. The RPS power monitoring system instrumentation shall bedetermined OPERABLE:

1. At least once per 6 months by performance of channelfunctional 'tests.

2. At least once per 18 months by demonstrating the OPERABILITYof overvoltage, undervoltage, and underfrequency protectiveinstrumentation by simulated automatic logic actuation andverification of the circuit protector trip level setting asfollows.

(a) overvoltage(b) undervoltage(c) underfrequency

g 132.0 VACg 108.5 VACg 56.0 Hz"

ENCLOSURE 3

EASO AND JUSTIFICATIO FOR THE PROPOSED CHANGES

Reason for Chan es

In June 1978, during a review of the Hatch Unit 2 operating license, NRCquestioned the adequacy of the Reactor Protective System (RPS) class lEcomponents against possible overvoltage or undervoltage conditions .from thenon-class 1E RPS power supplies. In applying single failure criteria, it waspostulated that during a seismic event a non-class lE Motor Generator (MG)voltage regulator could fail in a manner that would allow the MG outputvoltage to remain outside the voltage rating of the class lE RPS components.Such an abnormal voltage could go undetected and if it persisted for,asufficient time, could result in damage to RPS components with the potentialloss of capability to scram the plant. Subsequently, NRC requested eachutility with similar MG power supplies (e.g., Browns Ferry Nuclear Plant[BFN]) to implement interim surveillance procedures on the-RPS, to log RPSvoltage each shift, and to conduct additional RPS functional tests -.~very sixmonths after detection'of RPS bus, voltage outside its designed range or afteran operating basis earthquake. NRC further required these utilities toinstall class lE circuit protectors on the RPS power supplies to isolate theRPS bus upon detection of adverse RPS.voltage. NRC also required thatL'imiting Conditions for Operation (LCOs), surveillance requirements andsetpoints be developed for these circuit protectors and that they be includedin Che,Technical Specifications (TSs)..'FN implemented the interim RPSsurveillance requirements and a design change to install RPS power monitoringsystem circuit protectors. By letter dated December 22, 1988, TVA submittedTS 264 for unit 2. This TS added surveillance requirement 4.1.B.2 whichestablished values for RPS instrumentation overvoltage, undervoltage, andunderfrequency. The staff approved these changes by Amendment No. 164 to unit2 dated May 16, 1989.

The proposed changes will'revise these values for unit 2, add surveillancerequirement 4.1.B.2 to the unit 1 TS, add LCOs 3.1.B.l and 3.1.B.2 to the unit3 TS, and add surveillance requirements 4.1.B.1 and 4.1.B.2 to the unit 3 TS.These changes are because of modifications to the RPS which resulted from are-evaluation of RPS circuit protector setpoints committed to in licenseeevent report 50-296190001. The modifications will be made to reduce thenumber of spurious RPS circuit protector trips. The new setpoints allowincreased voltage and/or frequency variations without the possibility of RPScomponent damage or malfunction.

A summary of the proposed changes is provided by Enclosure 2.

of 2

Justificat on fo Chan es

The primary function of the RPS is to automatically initiate a reactor scramin a timely manner in order to 1) preserve the integrity of the fuel cladding,2) preserve the integrity of the nuclear system process barrier, and 3) limitthe uncontrolled release of radioactive material following an accident. Inorder to assure that the appropriate class lE RPS equipment is adequatelyprotected from an overvoltage, undervoltage, or underfrequency conditionresulting from a non-class 1E system powered from the same MG set, BFNimplemented a modification. This modification provided two redundant, class1E, seismic category l power monitoring systems on the output of each RPS MGset and the alternate power supply transformer. Each device, upon detectionof one of the above mentioned conditions, trips to open power contactors whichisolate the class lE RPS bus from the non-class lE RPS power supply.

The proposed TS change is necessitated by another ~dification which willremove excess conservatism from the RPS circuit protector undervoltage andovervoltage trip setpoints resulting in an increase in the overvoltage tripsetpoint and a decrease in the undervoltage trip setpoint. This is being doneto reduce the number of spurious RPS circuit protector trips.

r~ . The limiting factor for overvoltage is the rating of the average power range

monitor power supply, which may experience transformer-overheating above151V.- Based on this, the TS limit was set at 132.0V and the circuit protectorovervoltage trip at 129.02V.The limiting factor for undervoltage is the onset of humming and vibration inthe scram valve solenoids which.may occur below 97.0V. Based on this the TSlimit was set at 108.5V and the circuit protector undervoltage trip at 110.46V.The limiting factor for underfrequency is the onset of lower case overcurrentin scram valve solenoids, other solenoids, or relays rated at 60 Hz(equivalent to overcurrent at maximum rated voltage) which may occur below55.0 Hz. The underfrequency relay TS limit was set at 56.0 Hz and theunderfrequency relay setpoint was set at 57.0 Hz. As a result of themodification, the underfrequency trip will occur in 3.07 seconds. This iswithin the design limit of 4 seconds.These changes will allow the RPS bus circuit protectors to withstand a greaterrange of voltage and frequency excursions without exposing RPS components todamage or malfunction. This will reduce the number of spurious RPS trips,improving plant reliability.

ENCLOSURE 4

PROPOSED DETE A ION OF NO S G IFICA HAZARDS CO SIDER T 0

Descr tion of Pro osed Technical S ecificat on TS Amendment

The BFN unit 1, 2, and 3 TSs are being revised as follows:

l. Add surveillance requirement to demonstrate operability of theundervoltage, overvoltage, and underfrequency RPS circuit protector tripinstrumentation to unit l.

2. Revise the values for the RPS circuit protector trip level settings forunit 2.

3. Add Limiting Conditions for Operation (LCOs) for the RPS power monitoringchannels and alternate sources to unit 3.

4. Add surveillance requirements for RPS power monitoring systeminstrumentation to demonstrate operability of the undervoltage,overvoltage, and underfrequency RPS circuit protector trip instrumentationto unit 3.

A summary of the changes is provided by Enclosure 2.

as s ' P o osed o Si ni icant Hazards Cons derat o -Determ nation

NRC has provided standards for determining whether a significant hazards.consideration exists as stated in 10 CFR 50.92(c). A proposed amendment to anoperating license involves no.significant hazards consideration if operationof the facility in accordance with the proposed amendment would not (1)involve a significant increase in the probability or consequences of anaccident previously evaluated, or (2) create the possibility of a new ordifferent kind of accident from an accident previously evaluated', or (3)involve a significant reduction in margin of safety.

1. The proposed change does not involve a significant increase in theprobability or consequences of accident previously evaluated.

The BFN Final Safety Analysis (FSAR) section 7.2.3.2 states that the powerto each of the two reactor protection trip systems is supplied, via aseparate bus, by its own high-inertia, a-c motor generator (MG) set. Thehigh inertia is provided by a flywheel. The inertia is sufficient tomaintain voltage and frequency within g 5 percent of rated values for atleast 1.0 second following total loss of power to the MG set. In applyingthis to section 14.5.4.4.b of the FSAR .accident analysis, loss ofauxiliary power assumes the RPS MG set coastdown time until loss of MGgenerator output voltage to be 5.0 seconds. The upper and lower boundsfor voltage output and time delay are identified as significantperformance parameters expected from the MG set design.

\Page 2 of 2

The installed RPS power monitoring system is designed for the MG sets toprovide the time delay. Consequently, the trip level settings for the RPSpower monitor must be outside the expected operating range of the MG set.For a nominal 120 VAC MG output voltage, the 5 percent regulation band(114 to 126 volts) is within the allowable TS trip level setting of 108.5to 132 VAC. This will allow the MG set to function within its designedtime and voltage range before the RPS power monitoring system trips.These settings support the design and function of the high-inertia MGsets, and therefore, support the assumptions made in the BFN FSAR. Thedesign, trip level settings, and intended function of the RPS power ~monitoring system are both bounded and support the current BFH FSARaccident analysis.

This TS change will result in spurious RPS circuit protector trips beingreduced or eliminated, resulting in fewer challenges to safety-relatedsystems involved in maintaining fuel cladding integrity and 'reactorcoolant pressure boundary integrity. This modification, by improving RPSpower supply reliability, fully supports the mitigation of design basisevents involving components that are supplied power from the RPS buses or,which receive signals from those components. The plant's capability todetect radiological problems and to maintain radiological barriers is notadversely affected by this modification. Therefore, this modification

, will not result in an increase in. the probability-or consequences of an, accident.

2. The proposed change wi'll not create the possibility of a new or differentkind of accident from an accident previously evaluated.

This change is the result of a modification to increase the RPS powersupply reliability. This is being accomplished without introducing thepossibility of damaging components which are supplied power from the RPSbuses. This change does not create any new accident scenarios forconsideration because all components supplied power from RPS buses willcontinue to function 'as they did before this change. Therefore, thischange does not create a possibility of a new or different type ofaccident.

3. The proposed change will not involve a significant reduction in a marginof safety.

The purpose of the RPS circuit protectors is to protect componentssupplied power from the RPS buses from damage or malfunction resultingfrom sustained undervoltage, overvoltage, or underfrequency conditions.The purpose of this change is to reduce or eliminate spurious RPS circuitprotector trips which could result in unnecessary reactor shutdowns andchallenges to safety-related and important-to-safety equipment. Althoughthe change increases the range of voltage and frequency to which the RPScircuit protectors can be exposed prior to tripping, sufficient marginexists to ensure that the limiting voltages and frequencies for theprotected equipment are not reached. Based on engineering judgment,reducing the possibility of unnecessary reactor scrams and equipmentchallenges, while continuing to adequately protect the most limitingcomponents that are supplied power from the RPS buses, increases themargin of, safety by reducing the number of times that safety equipment ischallenged to function.

/

'1 I

April 16, .19913

Docket Nos. 50-259, 50-260,50-296, 50-327,50-328, 50-390$50-391, 50-438,

and 50-439

Mr. Dan A. NaumanSenior Vice President, Nuclear PowerTennessee Valley Authority6N 38A Lookout Place1101 Market

Place>'hattanooga,Tennessee 37402-2801

Dear Mr. Nauman:

SUBJECT: SAFETY EVALUATION ON THE TVA CORRECTIVE ACTION PLAN DEVIATIONPROCESS AND SUPPLEMENT TO SAFETY EVALUATIONS ON THE TENNESSEEVALLEY AUTHORITY EMPLOYEE CONCERNS SUBCATEGORY REPORTS - BROWNSFERRY NUCLEAR PLANT, UNITS 1, 2 AND 3 AND SEQUOYAH NUCLEAR PLANT,UNITS 1 AND 2 (TAC NOS . 76941, 76942 AND 76944)

This letter forwards an evaluation of the Tennessee Valley Authority's (TVA)Employee Concerns Special Program (ECSP) process for deviating from a correctiveaction plan (CAP) (Enclosure 1). In addition, a review is provided of BrownsFerry and Sequoyah deviations, including one Sequoyah ECSP deviation that wasunacceptable to the staff (Enclosure 2). The original Sequoyah Nuclear Plantevaluations to which these deviations apply were forwarded to TVA on March 11,1988 and November 4, 1988, and the Browns Ferry Nuclear Plant evaluation, onMay 31, 1990.

'he staff reaffirms its conclusion that TVA has sufficiently resolved therestart employee concerns in the ECSP to support the restart of Browns FerryNuclear Plant, Unit 2.

Sincerely,Original signed by Suzanne Black for

Frederick J. Hebdon, DirectorProject Directorate II-4Division of Reactor Projects - I/IIOffice of Nuclear Reactor Regulation

cc w/enclosures:See next page*SEE PREVIOUS CONCURRENCE

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DATE:1/14/91

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DistribUtion

NRC PDRLocal PDRS. VargaG. LainasF. HebdonS. BlackB. WilsonW. LittleJ. BradyP. HarmonP. KelloggC. PattersonM. BranchK. BarrH. LivermoreG. WaltonM. KrebsT. RossJ. WilliamsD. MoranD. LaBargeP. TamL. RaghavanOGC

E. JordanACRS (10)BFN Rdg. FileSQN Rdg. FileWBN Rdg. FileBEL. Rdg. FileL. ReyesJ. Fair

14-E-414-H-'3

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15-B-18MNBB-3701

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Mr. Dan A. Nauman

CC:Mr. Marvin Runyon, ChairmanTennessee Valley AuthorityET 12A400 West Summit Hill DriveKnoxville, Tennessee 37902

Mr. Edward G. WallaceManager, Nuclear Licensing

and Regulatory AffairsTennessee Valley Authority5B Lookout PlaceChattanooga, Tennessee 37402-2801

Mr. John B. Waters, DirectorTennessee Valley AuthorityET 12A400 West Summit Hill DriveKnoxville, Tennessee 37902

Mr. W. F. WillisSenior Executive OfficerET 12B400 West Summit Hill DriveKnoxville, Tennessee 37402-2801

General CounselTennessee Valley AuthorityET 11H400 West Summit Hill DriveKnoxville, Tennessee 37902

Mr. Dwight NunnVice President, Nuclear ProjectsTennessee Valley Authority6A Lookout Place1101 Market StreetChattanooga, Tennessee 37402-2801

Dr. Mark 0. MedfordVice President, Nuclear Assurance,

Licensing and FuelsTennessee Valley Authority6A Lookout Place1101 Market StreetChattanooga, Tennessee 37402-2801

Mr. 0. J. Zeringue, Site DirectorBrowns Ferry Nuclear PlantTennessee Valley AuthorityP. 0. Box 2000Decatur, Alabama 35602

Mr. P. Carier, Site Licensing ManagerBrowns Ferry Nuclear PlantTennessee Valley AuthorityP. Q. Box 2000Decatur, Alabama 35602

Mr. L. W. Myers, Plant ManagerBrowns Ferry Nuclear PlantTennessee Valley AuthorityP. 0. Box 2000Decatur, Alabama 35602

Chairman, Limestone County CommissionP. Q. Box 188Athens, Alabama 35611

Claude Earl Fox, M.D.State Health OfficerState Department of Public HealthState Office BuildingMontgomery, Alabama 36130

Regional Administrator, Region IIU.S. Nuclear Regulatory Commission101 Marietta Street, N.W.Atlanta, Georgia 30323

Mr. Charles PattersonSenior Resident InspectorBrowns Ferry Nuclear PlantU.S. Nuclear Regulatory CommissionRoute 12, Box 637Athens, Alabama 35611

Mr. Dan A. Nauman

CC:Mr. Jack Wilson, Vice PresidentSequoyah Nuclear PlantTennessee Valley AuthorityP. 0. Box 2000Soddy Daisy, Tennessee 37379

Vs. Marci CooperSite Licensing ManagerSequoyah Nuclear PlantP. 0. Box 2000Soddy Daisy, Tennessee 37379

County JudgeHamilton County CourthouseChattanooga, Tennessee 37402

Mr. Paul E. HarmonSenior Resident InspectorSequoyah Nuclear PlantU.S. Nuclear Regulatory Commission2600 Igou Ferry RoadSoddy Daisy, Tennessee 37379

Mr. Michael H. Mobley, DirectorDivision of Radiological Health .,T.E.R.R.A. Building, 6th Floor"150 9th Avenue NorthNashville, Tennessee 37219-5404

Mr. John H. Garrity, Site Vice PresidentWatts Bar Nuclear PlantTennessee Valley AuthorityP. 0. Box 800Spring City, Tennessee 37381

Mr. George L. PannellSite Licensing ManagerWatts Bar Nuclear PlantTennessee Valley AuthorityP. 0. Box 800Spring City, Tennessee 3738l

Chairman, Jacksor. County CommissionCourthouseScottsboro, Alabama 35752-0200

Resident InspectorBeliefonte Nuclear PlantU. S. Nuclear Regulatory ComissionP. 0. Box 477Hollywood, Alabama 35752

Honorable Robert AikmanCounty JudgeRhea County CourthouseDayton, Tennessee 37321

Honorable Johnny PowellCounty JudgeMeigs County CourthouseRoute 2Decatur, Tennessee 37322

Senior Resident InspectorWatts Bar Nuclear PlantU.S. Nuclear Regulatory CommissionRoute 2, Box 700Spring City, Tennessee 37381

Mr. W. J. Museler, Site'Vice PresidentBellefonte Nuclear PlantTennessee Valley AuthorityP. 0. Pox 20GGHo 1 lywood, Alabama 35752

Mr. Bruce SchofieldSite Licensing ManagerBellefonte Nuclear PlantTennessee Valley AuthorityP. 0. Box 2000Ho 1 lywood, Alabama 35752

ChairmanBoard of County CommissionersJackson County CourthouseScottsboro, Alabama 35768

Mr. Richard F.Wilson'ice

President, New Generationand BLN Construction

Tennessee Valley Authority6A Lookout PlaceChattanooga, Tennessee 37402-2801

Tennessee Valley AuthorityRockville Office11921 Rnckvi1 le PikeSuite 402Roc kvi1 le, Maryland 20852

gAs AEC(zP0

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UNITED STATESNUCLEAR REGULATORY COMMISSION

WASHINGTON, D. C. 20555

ENCLOSURE-1

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION

TVA CORRECTIVE ACTION PLAN DEVIATION PROCESS

TENNESSEE VALLEY AUTHORITY

BELLEFONTE NUCLEAR PLANT UNITS 1 AND 2

BROWNS FERRY NUCLEAR PLANT UNITS 1 2 AND 3

SE UOYAH NUCLEAR PLANT UNITS 1 AND 2

WATTS BAR NUCLEAR PLANT UNITS 1 AND 2

DOCKET NOS. 50-259 50-260 -50-296 50-327 50-328 50»390 50-391

50-438 AND 50-439

1.0 INTRODUCTION

The TVA Employee Concerns Special Program (ECSP) was established to investigateemployee concerns and track corrective actions. The ECSP includes employeeconcerns received prior to February 1, 1986. TVA's evaluations and correctiveaction plans were submitted to NPC as element reports for Sequoyah and assubcategory, reports for the other plants. In some cases, TVA revised the plansafter submission to the NRC. An NRC safety evaluation may have been issued onthe original plan. The deviation process is contained in TVA Nuclear PowerStandard 1.4.2 (Reference 1), Paragraph 3.3, "Corrective Action Plan Deviations".

By letter dated July 6, 1988 (Reference 2), TVA committed to inform thestaff thirty days prior to implementing a level I deviation, and to providean annual report on all deviations. Annual reports have been received forthe February 1, 1986 - September 30, 1988 (Peference 3) and October 1, 1988-December 31, 1989 (Reference 4) time periods. This staff evaluation wasperformed to determine the adequacy of the deviation process.

2.0 EVALUATION

TVA developed a set of criteria for judging the significance of a deviation toa corrective action plan (CAP). Deviations to CAPs were divided into threelevels of impottance in STD-1.4.2 (Reference 1) and stated as follows:

"Level I Deviation - A proposed change to a previously approved CAPwhose implementation would (1) deviate from technical specifications,the design basis, or the Final Safety Analysis Report, or (2) cause areduction in safety margins."

"Level II Deviation - A proposed change to a previously approved CAPwhose implementation would (1) affect multiple plants; or (2) affect aprogrammatic area of weakness; or (3) deviate from the techniques ormethods established by the commitments previously made; or (4) involveorganizational changes that directly affect CAP closures."

"Level III Deviation - Any other change to a previously approved CAP."The staff reviewed the definitions of the three levels and found themacceptable for the purpose of initiating the appropriate level of review andapproval.

TVA 's STD-1.4 .2, (Reference 1) par. 3 .3.1.A states, "Determine the need todeviate from a previously approved CAP."'TD-1.4.2, par. 3.3.1.C states,"Prepare a justification clearly explaining the need for a deviation to theoriginal CAP, and define the new CAP." STD-1.4.2, Appendix A, "ProcessFlowchart," shows that all Level I deviations are submitted to NRC 30-days priorto implementation. If the NRC does not respond, the deviation is implemented.According to this procedure, changes are identified and justified before theyare implemented, and NRC is notified about Level I deviations prior to implemen-tation. The Employee Concerns Special Program Annual Report includes theprogram status and descriptions of all Level I and II CAP deviations andstatistics relating to Level III CAP deviations that were implemented duringthe report period.

Step 3.3.1.C of the deviation process states, "Prepare a justification clearlyexplaining the need for a deviation to the original CAP, and define the newCAP." The staff reviewed the six Level I deviations to determine that justifi-cations were prepared, and that the deviations were correctly categorized.This review did not evaluate the technical adequacy of the justifications forthe deviations.

1. 11103-WBN-08. (submitted May 5, 1989) This is a deviation to the cabletray and cable tray support CAP. The staff has this issue under review.

2. 19201-SgN-08. (submitted July 19, 1989) This is a deviation to thecable monitoring program. The staff has not completed its review ofthis deviation. Its evaluation will be issued as a separate letterunder NRC TAC Numbers 77129 and 77130 for Sequoyah Nuclear Plant,Units 1 and 2, respectively.

3. 22303-SAN-01. (submitted February 26, 1990) TVA performed anoperability and safety evaluation on September 19, 1989 and said, "Theproposed CAP revision does not adversely affect the evaluation/quali-fication of any instrument required to detect and/or mitigate FSARChapter 15 design basis events. These instruments were evaluated priorto restart of Unit 2 and Unit 1, respectively. Therefore, the resolutionof the instrument seismic qualification issues can be accomplished in aprogrammatic fashion without impacting the safe operation of the plant."The staff review of this deviation is contained in Enclosure 2.

4 ~ 23101-SgN-01. Update Sequoyah Fire Protection Suppression System intoCompliance with National Fire Protection Association. The change wasforwarded to NRC in the annual report (Reference 3} on June 8, 1990.The staff was informed that this deviation did not meet the criteria ofLevel I per STD-1.4.2 and TVA furnished documentation showing that thedeviation had been downgraded to Level II on May 22, 1990. Level IIdeviations do not require prior NRC notification. TVA performed anoperability and safety evaluation on September 22, 1989 and said, "Thefollowing constitutes the technical justification that the proposed CAPwill not jeopardize plant operation or safety. The implementation ofthe proposed corrective actions are technically acceptable because allsafety-related areas needed for Appendix R safe shutdown capability havebeen evaluated and upgraded under Phase I Engineering Change NoticesL6300 and L6319". Sprinkler head obstructions and required relocationsare identified by SI-241, which is performed once per 18 months asrequired by Technical Specification 4.7.11.2. This is an ongoingprocess for which either 10 CFR 50.59 safety evaluations are written toaccept the sprinkler conditions, or necessary modifications are institutedthrough the Design Change Review (DCR) process. Sprinkler system addi-tions are also handled through the DCR process. The areas currentlywithout sprinkler fire suppression are not needed for plant shutdown.The areas identified as having sprinkler fire suppression with obstructedsprinklers will provide partial suppression capability until the firebrigade can respond. No degradations of the existing stand pipes andfire hoses (secondary fire suppression system) will exist." The staffagrees that this is a Level II deviation.

5. 30100-NPS-01. (submitted January 24, 1990) This Corrective ActionTracking Document (CATO) concerns corporate guidance for the maintenanceand testing of diesel generators and the change in the corrective actionplan provided more detail and included a status report. The staffbelieves this was conservatively classified as a Level I deviation.

6. 80101-S(N-01. (submitted February 10, 1988) This CATD concerns theSequoyah Replacement Items Program (RIP). The procurement program forSequoyah had not ensured that replacement items for safety-relatedmaterials, components, devices, equipment, and systems complies withapplicable regulatory, design bases, and qualification requirements.Actions were underway through the RIP, the primary objectives of whichwere to (1) verify that equipment previously qualified for seismic andenvironmental requirements had not been degraded through the use ofspare and replacement items; and (2) establish programs and practicesthat will ensure that equipment previously qualified for seismic andenvironmental requirements will not be degraded in the future throughthe use of spare and replacement parts.

In the original RIP Plan and Sequoyah Element Report, TVA had committedto review and evaluate all installed replacement items within the scopeof 10 CFR 50.49 and seismically sensitive replacement items within theboundary of the Sequoyah Unit 2 pre-restart phase of the Design Baseline

Verification Program (DBVP).replacement items were to bereviews and evaluations werepre-restart and post-restart

All other Unit 2 installed safety-relatedreviewed and evaluated post-restart. Similarto be performed on Unit 1 with the samescheduling commitments.

The Unit 2 pre-restart reviews and evaluations were performed as required.Pased on these reviews, TVA concluded that past maintenance practiceshave had an insigni icant impact on the ability,of Sequoyah's plantequipment to perform its intended safety function.. Therefore, TVAproposed a change in its RIP Plan for Unit 2 post-restart items and Unit 1pre-restart and post-restart items in its letter to NRC dated February 10,1988.

The revised RIP Plan allowed for the substitution of a warehouse inventoryreview and evaluation uf safety-related replacement items for adequacy ofqualification instead of performing the review and evaluations on actualinstalled replacement items covered within the original scope of Unit 2post-restart items and Unit 1 pre-restart and post-restart items. Theplan also provided for review of deficiencies identified during the Unit2 pre-restart efforts and the warehouse inventory efforts relative to theneed for corrective action on replacement items installed in the plant.

In the letter dated May 25, 1988, the NRC accepted the revised RIP Planand requested a schedule for the implementation of the plan. On August 10,1988, TVA reported to NRC that many of the elements of the revised planhad been implemented already and that several were complete and statedthat items related to 10 CFR 50.49 and seismically sensitive items withinthe restart phase of the DBVP had been sufficiently addressed for restartof Unit 1.

The staff reviewed the six Level I deviation justifications. It is notedthat one of these deviations was downgraded from Level I to Level IIafter the justification was written. The staff found the evaluations tobe adequate for correctly classifying the deviatior. as Level I.STD-1.4.2 (Reference 1) does not specifically require an operability andsafety evaluation, but it does require members of the Senior Management

'Review Group to review the technical justification and concur with therequest for a significant change to the Corrective Action Plan. Thisprocess also includes consideration of any required 10 CFR 50.59 evalua-tions.

The annual reports for 1988 (Reference 2) and 1989 (Reference 3) containinformation about 22 Level II deviations and identify 80 Level IIIdeviations. The staff audited 11 of the deviations (4 Level II and 7Level III) to determine if they had justifications and the correct leveldesignation.

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Level I I Deviations

2.

3.

22800-BFN-01. Unistrut Clamp Load Test Discrepancies. One of thecorrective actions was to review all field records for a specifictype of clamp. Browns Ferry decided to review all pipe support drawingsto identify where the clamps had been used and felt that this was morereliable. Another of the corrective actions was to incorporate atemporary requirement into the pipe support handbook. To prevent arecurrence of the problem, the Browns Ferry Pipe Support Design Handbooksection on Unistrut-type clamps was issued as a Lead Civil EngineerInstruction. The staff found the justifications to be adequate. Theseare not Level I changes.

23105-SQN-01. Adequacy of Battery Room Ventilation System. The vitalbattery room for the fifth diesel generator did not have a hydrogen con-centration survey and the corrective action was to drill ventilationholes. After further evaluation, TVA said no action was required because(1) tests did not show hydrogen accumulation, (2) failure of both ventila-tion trains is beyond single failure criteria, and (3) the existing dampersand fan housings permit bypass flow. The staff finds a justification forthe change, and since the fifth diesel generator is not relied upon in thesafety analysis, it is not a Level I deviation.24102-SQN-01 and 24102-SQN-02. Rework of Specific Terminal Connectors.The corrective action was to accept by evaluation, replace, or solder,as appropriate, the PIDG stranded wire connectors on Class 1E solid wireare suppressor and non-arc suppressor circuits in Units 1 and 2 prior to

,

restart. The deviation appears to be written against the 1986 Signifi-cant Condition Report rather than Revision 2 to the Element Report for-warded to NRC in 1987. This change was made prior to the establishmentof the deviation system.

Level III Deviations

2.

17101-BLN-03. Limitorque Valve Maintenance and Storage Requirements.The corrective action was to add the more stringent requirements fromthe construction manuals to the operations manuals. The changes were todelete the phrase "other TVA special preventive maintenance require-ments," and incorporate the corrective action into an additionalBellefonte procedure. This meets the intent of the corrective actionplan. The staff considers these changes to be Level III deviations.17301-SQN-01 and'17301-SQN-02. Evaluation of Instrument Sensing Lines.The corrective actions were to (1) perform a formal analysis of out-gassing in the sensing lines during an accident condition, (2) reviewand respond to another report addressing the required flow rates forbackfilling, and (3) review and respond to a report on thermal shockanalysis. This was accomplished at Sequoyah using more in-depthevaluations including walkdowns of instrument lines and some fieldmodifications. The staff considers these changes to be Level IIIdeviations.

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3. 20501-BFN-02. Calculation Prepar ation and Updating. The correctiveactions were to implement the essential calculation program, andcomplete the programs and the review of calculations that supportmodifications. to safety systems. The change was to complete theanalysis in a different manner. The staff considers this change to be aLevel III deviation.

4 ~ 22800-WBN-04. Allowable Clamp Loads. The corrective action was torevise calculation NCRWBNSWP8237 to correct the bolt ultimate shearstrength value. The change was to incorporate the calculation intoCivil Design Standard DS.C1.6.14. The staff considers this change to bea Level III deviation.

5.

6.

30709-NPS-Ol. Nuclear Experience Review Program. The corrective actionwas to incorporate the nuclear experience review programs requirementsinto specific site standard practices. Subsequently, two site standardprocedures were superseded and the corrective actions were incorporatedinto the new documents. The staff considers this change to be a LevelIII deviation.80106-BLN-03. Inspection Rejection Notices. The corrective action wasto make Inspection Rejection Notices a permanent quality assurancerecord by revising Bellefonte procedure BNP-gCP-10.43. Subsequently,this procedure was superseded and the corrective action was incorporatedinto BNP-gCP-10.58. The staff considers this change to be a Level IIIdeviation.

The staff determined that these changes were correctly categorized to beLevel II or III deviations. The staff therefore finds that the deviationprocess is being appropriately implemented by TVA.

3.0 CONCLUSIONSi

The staff reviewed the definitions of the three deviation levels and findsthem acceptable for the purpose of initiating the appropriate level of reviewand approval. The staff found that for the Level I deviations, technicaljustifications existed, and the Senior, Management Review was performed. Thestaff found from a sample review that the deviations appear to be appropriatelycategorized as Level I, II, or III. The staff finds the deviation process forthe Employee Concerns Special Program to be acceptable. Although we approveyour use of these definitions, it does not relieve your reporting responsibi-lities under NRC regulations. Also, our review of Level II deviations maydetermine that changes in methodology or scope which you implemented withoutprior NRC notification were not acceptable. Therefore, you should considerdiscussing any significant changes with the NRC.

4.0 REFERENCES

2.

TVA Nuclear Power Standard STD-1.4.2 Revision 0, "Resolution and Closureof Employee Concerns Special Program Corrective Action TrackingDocuments," dated April 2, 1990.

Letter from R. Gridley (TVA) to NRC, dated July 6, 1988, "EmployeeConcerns Task Group (ECTG)."

3. Letter from C. H. Fox, Jr. (TVA) to NRC, dated April 3, 1989, forwardingthe "Annual Report of Employee Concerns Special Program CorrectiveActions Implementation, February 1, 1986 - September 30, 1988."

4. Letter from E. G. Mallace (TVA) to HRC, Dated June 8, 1990, forwardingthe "Second Annual Report of Employee Concerns Special Program Correc-tive Actions Implementation, October 1, 1988 - December 31, 1989."

Principal Contributor: P. Cortland and J. Fair

Dated: April 15, 1991

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UNITED STATESNUCLEAR REGULATORY COMMISSION

WASHINGTON, D.C. 20555

ENCLOSURE 2

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR. REGULATION

TVA CORRECTIVE ACTION PLAN DEVIATIONS

TENNESSEE VALLEY AUTHORITY

SE UOYAH NUCLEAR PLANT UNITS 1 AND 2

BROWNS FERRY NUCLEAR PLANT UNITS 1 2 AND 3

DOCKET NOS. 50-259 50-260 50-296 50-327 AND 50-328

1.0 REVIEW OF SE UOYAH DEVIATIONS

The NRC staff reviewed deviation 22303-SQN-01 which was identified in TVAreport dated June 8, 1990 (Reference 1). The deviation involved changes tocorrective actions that TVA had previously committed to implement in itsresolution of employee concerns. These corrective actions had been previouslyreviewed by the NRC staff and found acceptable. The previous staff evaluationwas forwarded to TVA on March 11, 1988 (Reference 2).

Deviation 22303-SQN-Ol was a significant change to the proposed corrective actionfor establishing the seismic adequacy 'of the field-mounted instruments. Theoriginal corrective action was to be implemented in two phases. The first phaserequired TVA to establish the seismic adequacy of field-mounted instruments forthe Sequoyah Unit 2 restart boundary prior to Unit 2 restart. The second phaserequired TVA to establish the seismic adequacy of the remaining 'safety-relatedfield-mounted instruments for Units 1 and 2 prior to the Unit 1 restart. TVA'sdeviation changed the second phase of the corrective action from a requirement toestablish the seismic adequacy of the remaining field-mounted instruments prior toUnit 1 restart to a requirement to. establish the adequacy of the remaining field-mounted instruments as maintenance activities are performed. Based on TVA's June 8,1990 letter, it appears that this deviation was approved after the Sequoyah Unit 1restart. NRC discussed this issue with TVA in a conference call on August 24, 1990.In a subsequent call between TVA and the staff, TVA stated that work associatedwith the Sequoyah Unit 1 restart boundary had been completed.

Since TVA's June 8, 1990 letter did not provide any justification for thedeviation, the staff does not concur with the proposed deviation to theoriginal corrective action. A schedule for completion of the originalcorrective action plan (CAP) should be given to the staff.The staff reviewed the other Sequoyah-related Level II and III CAP deviationsdiscussed in the TVA submittals of April 3, 1989 (Reference 3) and June 8, 1990(Reference 1) and found them acceptable. The Sequoyah-related Level I deviationsare discussed in Enclosure 1 to this letter.

2.0 REVIEW OF BROWNS FERRY DEVIATIONS

The staff reviewed the Browns Ferry-related Level I, II and III CAP deviationsdiscussed in the TVA submittals of April 3, 1989 (Reference 3), June 8, 1990(Reference 1) and October 29, 1990 (Reference 4) found them acceptable.

3.0 CONCLUSIONS

The staff reviewed TVA's Level I, II and III CAP deviations or Browns Ferryand Sequoyah and found them acceptable except for 22303-SgN-Ol. A schedulefor completion of this corrective action program plan should be given to thestaff.

4.0 REFERENCES

1. Letter from E. G. Wallace (TVA) to NRC, dated June 8, 1990, forwardingthe "Second Annual Report of Employee Concerns Special ProgramCorrective Actions Implementation, October 1, 1988 - December 31, 1989."

2. Letter from G. G. Zech (NRC) to S. A. White (TVA), dated March 11, 1988,forwarding the "Preliminary Safety Evaluations on the Tennessee ValleyAuthority Employee Concern Element Reports."

3. Letter from C. H. Fox, Jr. (TVA) to NRC, dated April 3, 1989, forwardingthe "Annual Report of Employee Concerns Special Program CorrectiveActions Implementation, February 1, 1986 - September 30, 1988."

4. Letter from E. G. Wallace (TVA) to NRC, dated October 29, 1990, "SafetyEvaluation Report on the Tennessee Valley Authority Employee ConcernsSubcategory Reports - Browns Ferry Nuclear Plant, Units 1, 2, and 3-May 31, 1990."

Principal Contributor: P. Cortland

Dated: April 15, 1991