ML18033B346

Proposed Tech Specs Re Reactor Protection Sys Circuit Trip Level Setpoints

ML18033B346
Person / Time
Site:	Browns Ferry
Issue date:	06/04/1990
From:	TENNESSEE VALLEY AUTHORITY
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ML18033B345	List: ML18033B344 ML18033B346
References
NUDOCS 9006070451
Download: ML18033B346 (44)

Text

Enclosure l PROPOSED TECHNICAL SPECIFICATION UNITS 1, 2, AND 3 (TVA BFN TS 286) 9006070am> 900eon PDR ADOCK 05000259 P PDC

UNIT 1 EFFECTIVE PAGE LIST REMOVE INSERT 3.1/4.1-1 3.1/4.1-1 3;1/4.1-2 3.1/4.1-2

• Denote's overleaf or spillover page.

.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 instrumentation Applies to the surveillance and associated devices which of the instrumentation and initiate a reactor scram. associated devices which initiate reactor scram.'Ob

'ective ~Ob ective To assure the operability of the To specify the type and reactor protection system. frequency of surveillance to be applied to the protection instrumentation.

S ec cation S ecification A. When there is fuel in the vessel, A. Instrumentation systems shall the setpoints, minimum number of be functionally tested and

~

'rip. systems, and minimum number calibrated as indicated in of instrument channels that must Sables 4.1.A and 4.1.B,

-'be OPERABLE for each MODE of respectively.

OPERATION shall be as given in Table 3.1.A.

B. Two RPS power monitoring channels B. The RPS power monitoring for each inservice RPS MG set or system instrumentation shall alternate source shall be operable. be determined operable:

With one RPS electric monitoring channel for power l.. At least once per 6 months by performance inservice RPS MG set or of channel functional alternate power supply tests.

inoperable, restore the inoperable channel to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or remove the associated RPS MG set or alternate power supply from service.

BFN 3.1/4.1-1 Unit 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) 4.1.B. (Cont'd)

2. With both RPS electric power 2. At least once per 18 months monitoring channels for an by demonstrating the OPERA-inservice RPS MG set or BILITY of overvoltage, under-alternate power supply voltage and underfrequency.

inoperable, restore at least protective instrumentation by one to OPERABLE status within simulated automatic logic 30 minutes or remove the actuation and verification of associated RPS MG set or the circuit protector trip alternate power supply from level setting as follows.

service.

(a) overvoltage g 132.0 VAC (b) undervoltage g 108.5 VAC (c) underfrequency g 56.0 Hz BFN 3.1/4.1-2 Unit 1

UNIT 2 EFFECTIVE PAGE LIST REMOVE INSERT 3.1/4.1-1 3.1/4.1-1 3.1/4.1-2 3.1/4.1-2

• Denotes overleaf or spillover page.

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 it Applies to the instrumentation Applies to the surveillance and associated devices which of the instrumentation and initiate a reactor scram. associated devices which initiate reactor scram.

Ob ective Ob ective To assure the operability of the To specify the type and reactor protection, system. frequency of surveillance to be applied to the protection instrumentation.

S ecification S ecification A. When there is fuel in the vessel, A. Instrumentation systems shall the setpoints, minimum number of be functionally tested and trip systems, and minimum number calibrated as indicated in of instrument channels that must Tables 4.1.A and 4.1.B, be OPERABLE for MODE OF OPERATION respectively.

shall be as given in Table 3.1.A.

B. Two RPS power monitoring channels B. The RPS power monitoring for each inservice RPS MG set or system instrumentation shall

! alternate source shall be OPERABLE. , be determined OPERABLE:

1. With one RPS electric power l. At least once per monitoring channel for 6 months by performance inservice RPS MG set or of channel functional alternate power supply tests.

inoperable, restore the inoperable channel to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or remove the associated RPS MG set or alternate power supply from service.

BFN 3.1/4.1-1 Unit 2

1 4 1 REACTOR ROTEC SYSTE LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.1 Reactor Protection S stem 4.1 Reactor Protection S stem 3.1.B. (Cont'd) 4.1.B. (Cont'd)

2. With both RPS electric power 2. At least once per 18 months monitoring channels for an by demonstrating the OPERA-inservice RPS MG set or BILITY of overvoltage, under-alternate power supply voltage and underfrequency inoperable, restore at least protective instrumentation by one to O'PERABLE status within simulated automatic logic 30 minutes or remove the actuation and verification of associated RPS MG set or the circuit protector trip alternate power supply level setting as follows.

from service.

(a) overvoltage g 132.0 VAC (b) undervoltage g 108.5 VAC (c) underfrequency g 56.0 Hz BFN 3;1/4.1-2 Unit 2

UNIT 3 EFFECTIVE PAGE LIST REMOVE INSERT 3.1/4.1-1 3.1/4.1-1 3.1/4.l-la

• Denotes overleaf or spillover page.

4 1 REAC S S E LIMITING CONDITIONS FOR OPERATION SURVEILLANCE REQUIREMENTS 3.1 Reactor Protectio S ste 4.1 'Reactor P otect on S stem cab it Applies to the instrumentation Applies to the surveillance and associated devices which of the instrumentation and initiate a reactor scram. associated devices which initiate reactor scram.

Ob ective ~Oh 'ective To assure the operability of the To specify the type and reactor protection system. frequency of surveillance to be applied .to the protection instrumentation.

S ecification S ecification A. When there is fuel in the A. Instrumentation systems vessel, the setpoints, minimum shall be functionally number of trip systems, and tested and calibrated as minimum number of instrument, indicated in Tables 4.1.A channels that must be OPERABLE and 4.1.B, respectively.

for each MODE OF OPERATION shall be as given in Table 3.1.A.

B. Two RPS power monitoring channels B. The RPS power monitoring for each inservice RPS MG set system instrumentation shall or alternate source shall be be determined OPERABLE:

OPERABLE.

1. With one RPS electric power l. At least once per monitoring channel for- 6 months by performance inservice RPS MG set or of channel functional alternate power supply inop- tests.

erable, restore the inoper-able channel to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or remove the associated RPS MG set or alternate power supply from service.

BFN 3.1/4.1-1 Unit 3

3 1 4 1 REACTOR PROTEC SYSTEM KIMITING CONDITIONS FOR OPERATION SURVEILLANCE RE UIREMENTS 3.1 Reacto Protection S ste 4.1 Reactor Protection S ste 3.1.B. (Cont'd) 4.1.B. (Cont'd)

2. With both RPS electric power 2. At least once per 18 months monitoring channels for an by demonstrating the OPERA-inservice RPS MG set or BILITY of overvoltage, under-alternate power supply voltage and underfrequency inoperable, restore at least protective instrumentation by one to OPERABLE status within simulat'ed automatic logic 30 minutes or remove the actuation and verification of associated RPS MG set or the circuit protector trip alternate power supply level setting as follows.

from service.

(a) overvoltage g 132.0 VAC (b) undervoltage g 108.5 VAC (c) underfrequency y 56.0 Hz BFN 3.1/4.1-1a Unit 3

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 and verification of the circuit protector trip level setting as follows.

(a) overvoltage g 132.0 VAC (b) undervoltage g 108.5 VAC (c) underfrequency y 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) g 126.5 VAC (b) undervoltage (MG set) g 113.4 VAC (c) undervoltage (alt. supply) g 111.8 VAC (d) underfrequency (all devices) g 57.0 Hz" Revised surveillance requirement 4.1.B.2 would read in part:

.(a) overvoltage ~132.0 VAC (b) undervoltage g 108.'5 VAC (c) underfrequency g 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 RPS MG set or alternate power supply inoperable, restore the inoperable channel to OPERABLE status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or remove the associated RPS MG set or alternate power supply from service.

2. With both RPS electric power monitoring channels for an inservice RPS MG set or alternate power supply inoperable, restore at least one to OPERABLE status within 30 minutes or remove the associated RPS 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 be determined OPERABLE:

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

2. At least once per 18 months by demonstrating the OPERABILITY of overvoltage, undervoltage, and underfrequency protective instrumentation by simulated automatic logic actuation and verification of the circuit protector trip level setting as follows.

(a) overvoltage g 132.0 VAC (b) undervoltage g 108.5 VAC (c) underfrequency g 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, NRC questioned the adequacy of the Reactor Protective System (RPS) class lE components against possible overvoltage or undervoltage conditions .from the non-class 1E RPS power supplies. In applying single failure criteria, it was postulated that during a seismic event a non-class lE Motor Generator (MG) voltage regulator could fail in a manner that would allow the MG output voltage to remain outside the voltage rating of the class lE RPS components.

Such an abnormal voltage could go undetected and if it persisted for,a sufficient time, could result in damage to RPS components with the potential loss of capability to scram the plant. Subsequently, NRC requested each utility with similar MG power supplies (e.g., Browns Ferry Nuclear Plant

[BFN]) to implement interim surveillance procedures on the-RPS, to log RPS voltage each shift, and to conduct additional RPS functional tests -.~very six months after detection'of RPS bus, voltage outside its designed range or after an operating basis earthquake. NRC further required these utilities to install class lE circuit protectors on the RPS power supplies to isolate the RPS bus upon detection of adverse RPS.voltage. NRC also required that L'imiting Conditions for Operation (LCOs), surveillance requirements and setpoints be developed for these circuit protectors and that they be included in Che,Technical Specifications (TSs)..'FN implemented the interim RPS surveillance requirements and a design change to install RPS power monitoring system circuit protectors. By letter dated December 22, 1988, TVA submitted TS 264 for unit 2. This TS added surveillance requirement 4.1.B.2 which established values for RPS instrumentation overvoltage, undervoltage, and underfrequency. The staff approved these changes by Amendment No. 164 to unit 2 dated May 16, 1989.

The proposed changes will'revise these values for unit 2, add surveillance requirement 4.1.B.2 to the unit 1 TS, add LCOs 3.1.B.l and 3.1.B.2 to the unit 3 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 a re-evaluation of RPS circuit protector setpoints committed to in licensee event report 50-296190001. The modifications will be made to reduce the number of spurious RPS circuit protector trips. The new setpoints allow increased voltage and/or frequency variations without the possibility of RPS component damage or malfunction.

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

Page 2 of 2 Justificat on fo Chan es The primary function of the RPS is to automatically initiate a reactor scram in 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) limit the uncontrolled release of radioactive material following an accident. In order to assure that the appropriate class lE RPS equipment is adequately protected from an overvoltage, undervoltage, or underfrequency condition resulting from a non-class 1E system powered from the same MG set, BFN implemented a modification. This modification provided two redundant, class 1E, seismic category l power monitoring systems on the output of each RPS MG set and the alternate power supply transformer. Each device, upon detection of one of the above mentioned conditions, trips to open power contactors which isolate the class lE RPS bus from the non-class lE RPS power supply.

The proposed TS change is necessitated by another ~dification which will remove excess conservatism from the RPS circuit protector undervoltage and overvoltage trip setpoints resulting in an increase in the overvoltage trip setpoint and a decrease in the undervoltage trip setpoint. This is being done to 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 above 151V.- Based on this, the TS limit was set at 132.0V and the circuit protector overvoltage trip at 129.02V.

The limiting factor for undervoltage is the onset of humming and vibration in the scram valve solenoids which.may occur below 97.0V. Based on this the TS limit 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 overcurrent in scram valve solenoids, other solenoids, or relays rated at 60 Hz (equivalent to overcurrent at maximum rated voltage) which may occur below 55.0 Hz. The underfrequency relay TS limit was set at 56.0 Hz and the underfrequency relay setpoint was set at 57.0 Hz. As a result of the modification, the underfrequency trip will occur in 3.07 seconds. This is within the design limit of 4 seconds.

These changes will allow the RPS bus circuit protectors to withstand a greater range of voltage and frequency excursions without exposing RPS components to damage 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 the undervoltage, overvoltage, and underfrequency RPS circuit protector trip instrumentation to unit l.

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

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

4. Add surveillance requirements for RPS power monitoring system instrumentation to demonstrate operability of the undervoltage, overvoltage, and underfrequency RPS circuit protector trip instrumentation to 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 an operating license involves no.significant hazards consideration of the facility in accordance with the proposed amendment would not (1) if operation involve a significant increase in the probability or consequences of an accident previously evaluated, or (2) create the possibility of a new or different 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 the probability or consequences of accident previously evaluated.

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

\

Page 2 of 2 The installed RPS power monitoring system is designed for the MG sets to provide the time delay. Consequently, the trip level settings for the RPS power 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 108.5 to 132 VAC. This will allow the MG set to function within its designed time and voltage range before the RPS power monitoring system trips.

These settings support the design and function of the high-inertia MG sets, and therefore, support the assumptions made in the BFN FSAR. The design, trip level settings, and intended function of the RPS power ~

monitoring system are both bounded and support the current BFH FSAR accident analysis.

This TS change will result in spurious RPS circuit protector trips being reduced or eliminated, resulting in fewer challenges to safety-related systems involved in maintaining fuel cladding integrity and 'reactor coolant pressure boundary integrity. This modification, by improving RPS power supply reliability, fully supports the mitigation of design basis events involving components that are supplied power from the RPS buses or

,which receive signals from those components. The plant's capability to detect radiological problems and to maintain radiological barriers is not adversely 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 different kind of accident from an accident previously evaluated.

This change is the result of a modification to increase the RPS power supply reliability. This is being accomplished without introducing the possibility of damaging components which are supplied power from the RPS buses. This change does not create any new accident scenarios for consideration because all components supplied power from RPS buses will continue to function 'as they did before this change. Therefore, this change does not create a possibility of a new or different type of accident.

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

The purpose of the RPS circuit protectors is to protect components supplied power from the RPS buses from damage or malfunction resulting from sustained undervoltage, overvoltage, or underfrequency conditions.

The purpose of this change is to reduce or eliminate spurious RPS circuit protector trips which could result in unnecessary reactor shutdowns and challenges to safety-related and important-to-safety equipment. Although the change increases the range of voltage and frequency to which the RPS circuit protectors can be exposed prior to tripping, sufficient margin exists to ensure that the limiting voltages and frequencies for the protected equipment are not reached. Based on engineering judgment, reducing the possibility of unnecessary reactor scrams and equipment challenges, while continuing to adequately protect the most limiting components that are supplied power from the RPS buses, increases the margin of, safety by reducing the number of times that safety equipment is challenged 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. Nauman Senior Vice President, Nuclear Power Tennessee Valley Authority 6N 38A Lookout Place 1101 Market Tennessee Place>'hattanooga, 37402-2801

SUBJECT:

SAFETY EVALUATION ON THE TVA CORRECTIVE ACTION PLAN DEVIATION PROCESS AND SUPPLEMENT TO SAFETY EVALUATIONS ON THE TENNESSEE VALLEY AUTHORITY EMPLOYEE CONCERNS SUBCATEGORY REPORTS - BROWNS FERRY 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 corrective action plan (CAP) (Enclosure 1). In addition, a review is provided of Browns Ferry and Sequoyah deviations, including one Sequoyah ECSP deviation that was unacceptable to the staff (Enclosure 2). The original Sequoyah Nuclear Plant evaluations to which these deviations apply were forwarded to TVA on March 11, 1988 and November 4, 1988, and the Browns Ferry Nuclear Plant evaluation, on May 31, 1990.

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

Sincerely, Original signed by Suzanne Black for Frederick J. Hebdon, Director Project Directorate II-4 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation cc w/enclosures:

See next page

• SEE PREVIOUS CONCURRENCE WO W W NAME:MKreb s  ::JNorberg :SBlack :FHebd JDonohew WWWO>>

DATE: 1/14/91 :1/10/91  : 4//5/91: 4//+91 W 0

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NAME :TRoss :MThadani :PTam DATE: 4/9/91: 4/3/91 :4/9 /91 Document Name: REVISED ECSP SER

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DistribUtion NRC PDR Local PDR S. Varga 14-E-4 G. Lainas 14-H-'3 F. Hebdon S. Black B. Wilson R II W. Little RI I J. Brady RII P. Harmon RI I P. Kellogg RII C. Patterson RI I M. Branch RII K. Barr RII H. Livermore RI I G. Walton RI I M. Krebs T. Ross J. Williams D. Moran D. LaBarge P. Tam L. Raghavan OGC 15-B-18 E. Jordan MN BB-3701 ACRS (10)

BFN Rdg. File SQN Rdg. File WBN Rdg. File BEL. Rdg. File L. Reyes RII J. Fair RI I

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Mr. Dan A. Nauman CC:

Mr. Marvin Runyon, Chairman Mr. 0. J. Zeringue, Site Director Tennessee Valley Authority Browns Ferry Nuclear Plant ET 12A Tennessee Valley Authority 400 West Summit Hill Drive P. 0. Box 2000 Knoxville, Tennessee 37902 Decatur, Alabama 35602 Mr. Edward G. Wallace Mr. P. Carier, Site Licensing Manager Manager, Nuclear Licensing Browns Ferry Nuclear Plant and Regulatory Affairs Tennessee Valley Authority Tennessee Valley Authority P. Q. Box 2000 5B Lookout Place Decatur, Alabama 35602 Chattanooga, Tennessee 37402-2801 Mr. John B. Waters, Director Mr. L. W. Myers, Plant Manager Tennessee Valley Authority Browns Ferry Nuclear Plant ET 12A Tennessee Valley Authority 400 West Summit Hill Drive P. 0. Box 2000 Knoxville, Tennessee 37902 Decatur, Alabama 35602 Mr. W. F. Willis Chairman, Limestone County Commission Senior Executive Officer P. Q. Box 188 ET 12B Athens, Alabama 35611 400 West Summit Hill Drive Knoxville, Tennessee 37402-2801 Claude Earl Fox, M.D.

State Health Officer General Counsel State Department of Public Health Tennessee Valley Authority State Office Building ET 11H Montgomery, Alabama 36130 400 West Summit Hill Drive Knoxville, Tennessee 37902 Regional Administrator, Region II U.S. Nuclear Regulatory Commission Mr. Dwight Nunn 101 Marietta Street, N.W.

Vice President, Nuclear Projects Atlanta, Georgia 30323 Tennessee Valley Authority 6A Lookout Place Mr. Charles Patterson 1101 Market Street Senior Resident Inspector Chattanooga, Tennessee 37402-2801 Browns Ferry Nuclear Plant U.S. Nuclear Regulatory Commission Dr. Mark 0. Medford Route 12, Box 637 Vice President, Nuclear Assurance, Athens, Alabama 35611 Licensing and Fuels Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, Tennessee 37402-2801

V f

Mr. Dan A. Nauman CC:

Mr. Jack Wilson, Vice President Honorable Robert Aikman Sequoyah Nuclear Plant County Judge Tennessee Valley Authority Rhea County Courthouse P. 0. Box 2000 Dayton, Tennessee 37321 Soddy Daisy, Tennessee 37379 Honorable Johnny Powell Vs. Marci Cooper County Judge Site Licensing Manager Meigs County Courthouse Sequoyah Nuclear Plant Route 2 P. 0. Box 2000 Decatur, Tennessee 37322 Soddy Daisy, Tennessee 37379 Senior Resident Inspector County Judge Watts Bar Nuclear Plant Hamilton County Courthouse U.S. Nuclear Regulatory Commission Chattanooga, Tennessee 37402 Route 2, Box 700 Spring City, Tennessee 37381 Mr. Paul E. Harmon Senior Resident Inspector Mr. W. J. Museler, Site'Vice President Sequoyah Nuclear Plant Bellefonte Nuclear Plant U.S. Nuclear Regulatory Commission Tennessee Valley Authority 2600 Igou Ferry Road P. 0. Pox 20GG Soddy Daisy, Tennessee 37379 Ho 1 lywood, Alabama 35752 Mr. Michael H. Mobley, Director Mr. Bruce Schofield Division of Radiological Health ., Site Licensing Manager T.E.R.R.A. Building, 6th Floor" Bellefonte Nuclear Plant 150 9th Avenue North Tennessee Valley Authority Nashville, Tennessee 37219-5404 P. 0. Box 2000 Ho 1 lywood, Alabama 35752 Mr. John H. Garrity, Site Vice President Chairman Watts Bar Nuclear Plant Board of County Commissioners Tennessee Valley Authority Jackson County Courthouse P. 0. Box 800 Scottsboro, Alabama 35768 Spring City, Tennessee 37381 Mr. Richard F.

Mr. George L. Pannell Wilson'ice President, New Generation Site Licensing Manager and BLN Construction Watts Bar Nuclear Plant Tennessee Valley Authority Tennessee Valley Authority 6A Lookout Place P. 0. Box 800 Chattanooga, Tennessee 37402-2801 Spring City, Tennessee 3738l Tennessee Valley Authority Chairman, Jacksor. County Commission Rockville Office Courthouse 11921 Rnckvi1 le Pike Scottsboro, Alabama 35752-0200 Suite 402 Roc kvi1 le, Maryland 20852 Resident Inspector Belief onte Nuclear Plant U. S. Nuclear Regulatory Comission P. 0. Box 477 Hollywood, Alabama 35752

gAs AEC(z P

0 UNITED STATES NUCLEAR 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 50-260 296 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 investigate employee concerns and track corrective actions. The ECSP includes employee concerns received prior to February 1, 1986. TVA's evaluations and corrective action plans were submitted to NPC as element reports for Sequoyah and as subcategory, reports for the other plants. In some cases, TVA revised the plans after submission to the NRC. An NRC safety evaluation may have been issued on the original plan. The deviation process is contained in TVA Nuclear Power Standard 1.4.2 (Reference 1), Paragraph 3.3, "Corrective Action Plan Deviations".

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

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

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

~,

"Level II Deviation - A proposed change to a previously approved CAP whose implementation would (1) affect multiple plants; or (2) affect a programmatic area of weakness; or (3) deviate from the techniques or methods established by the commitments previously made; or (4) involve organizational 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 them acceptable for the purpose of initiating the appropriate level of review and approval.

TVA 's STD-1.4 .2, (Reference 1) par. 3 .3.1.A states, "Determine the need to deviate 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 the original CAP, and define the new CAP." STD-1.4.2, Appendix A, "Process Flowchart," shows that all Level I deviations are submitted to NRC 30-days prior to implementation. If the NRC does not respond, the deviation is implemented.

According to this procedure, changes are identified and justified before they are implemented, and NRC is notified about Level I deviations prior to implemen-tation. The Employee Concerns Special Program Annual Report includes the program status and descriptions of all Level I and II CAP deviations and statistics relating to Level III CAP deviations that were implemented during the report period.

Step 3.3.1.C of the deviation process states, "Prepare a justification clearly explaining the need for a deviation to the original CAP, and define the new CAP." 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 for the deviations.

1. 11103-WBN-08. (submitted May 5, 1989) This is a deviation to the cable tray 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 the cable monitoring program. The staff has not completed its review of this deviation. Its evaluation will be issued as a separate letter under 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 an operability and safety evaluation on September 19, 1989 and said, "The proposed CAP revision does not adversely affect the evaluation/quali-fication of any instrument required to detect and/or mitigate FSAR Chapter 15 design basis events. These instruments were evaluated prior to restart of Unit 2 and Unit 1, respectively. Therefore, the resolution of the instrument seismic qualification issues can be accomplished in a programmatic 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 into Compliance with National Fire Protection Association. The change was forwarded to NRC in the annual report (Reference 3} on June 8, 1990.

The staff was informed that this deviation did not meet the criteria of Level I per STD-1.4.2 and TVA furnished documentation showing that the deviation had been downgraded to Level II on May 22, 1990. Level II deviations do not require prior NRC notification. TVA performed an operability and safety evaluation on September 22, 1989 and said, "The following constitutes the technical justification that the proposed CAP will not jeopardize plant operation or safety. The implementation of the proposed corrective actions are technically acceptable because all safety-related areas needed for Appendix R safe shutdown capability have been evaluated and upgraded under Phase I Engineering Change Notices L6300 and L6319". Sprinkler head obstructions and required relocations are identified by SI-241, which is performed once per 18 months as required by Technical Specification 4.7.11.2. This is an ongoing process for which either 10 CFR 50.59 safety evaluations are written to accept the sprinkler conditions, or necessary modifications are instituted through the Design Change Review (DCR) process. Sprinkler system addi-tions are also handled through the DCR process. The areas currently without sprinkler fire suppression are not needed for plant shutdown.

The areas identified as having sprinkler fire suppression with obstructed sprinklers will provide partial suppression capability until the fire brigade can respond. No degradations of the existing stand pipes and fire hoses (secondary fire suppression system) will exist." The staff agrees that this is a Level II deviation.

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

6. 80101-S(N-01. (submitted February 10, 1988) This CATD concerns the Sequoyah Replacement Items Program (RIP). The procurement program for Sequoyah had not ensured that replacement items for safety-related materials, components, devices, equipment, and systems complies with applicable regulatory, design bases, and qualification requirements.

Actions were underway through the RIP, the primary objectives of which were to (1) verify that equipment previously qualified for seismic and environmental requirements had not been degraded through the use of spare and replacement items; and (2) establish programs and practices that will ensure that equipment previously qualified for seismic and environmental requirements will not be degraded in the future through the use of spare and replacement parts.

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

I' Verification Program (DBVP). All other Unit 2 installed safety-related replacement items were to be reviewed and evaluated post-restart. Similar reviews and evaluations were to be performed on Unit 1 with the same pre-restart and post-restart scheduling commitments.

The Unit 2 pre-restart reviews and evaluations were performed as required.

Pased on these reviews, TVA concluded that past maintenance practices have had an insigni icant impact on the ability, of Sequoyah's plant equipment to perform its intended safety function.. Therefore, TVA proposed a change in its RIP Plan for Unit 2 post-restart items and Unit 1 pre-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 inventory review and evaluation uf safety-related replacement items for adequacy of qualification instead of performing the review and evaluations on actual installed replacement items covered within the original scope of Unit 2 post-restart items and Unit 1 pre-restart and post-restart items. The plan also provided for review of deficiencies identified during the Unit 2 pre-restart efforts and the warehouse inventory efforts relative to the need for corrective action on replacement items installed in the plant.

In the letter dated May 25, 1988, the NRC accepted the revised RIP Plan and 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 plan had been implemented already and that several were complete and stated that items related to 10 CFR 50.49 and seismically sensitive items within the restart phase of the DBVP had been sufficiently addressed for restart of Unit 1.

The staff reviewed the six Level I deviation justifications. It is noted that one of these deviations was downgraded from Level I to Level II after the justification was written. The staff found the evaluations to be adequate for correctly classifying the deviatior. as Level I.

STD-1.4.2 (Reference 1) does not specifically require an operability and safety evaluation, but it does require members of the Senior Management

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

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

Level I I Deviations 22800-BFN-01. Unistrut Clamp Load Test Discrepancies. One of the corrective actions was to review all field records for a specific type of clamp. Browns Ferry decided to review all pipe support drawings to identify where the clamps had been used and felt that this was more reliable. Another of the corrective actions was to incorporate a temporary requirement into the pipe support handbook. To prevent a recurrence of the problem, the Browns Ferry Pipe Support Design Handbook section on Unistrut-type clamps was issued as a Lead Civil Engineer Instruction. The staff found the justifications to be adequate. These are not Level I changes.

2. 23105-SQN-01. Adequacy of Battery Room Ventilation System. The vital battery room for the fifth diesel generator did not have a hydrogen con-centration survey and the corrective action was to drill ventilation holes. 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 dampers and fan housings permit bypass flow. The staff finds a justification for the change, and since the fifth diesel generator is not relied upon in the safety analysis, it is not a Level I deviation.

3. 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 wire are 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 establishment of the deviation system.

Level III Deviations 17101-BLN-03. Limitorque Valve Maintenance and Storage Requirements.

The corrective action was to add the more stringent requirements from the construction manuals to the operations manuals. The changes were to delete the phrase "other TVA special preventive maintenance require-ments," and incorporate the corrective action into an additional Bellefonte procedure. This meets the intent of the corrective action plan. The staff considers these changes to be Level III deviations.

2. 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) review and respond to another report addressing the required flow rates for backfilling, and (3) review and respond to a report on thermal shock analysis. This was accomplished at Sequoyah using more in-depth evaluations including walkdowns of instrument lines and some field modifications. The staff considers these changes to be Level III deviations.

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3. 20501-BFN-02. Calculation Prepar ation and Updating. The corrective actions were to implement the essential calculation program, and complete the programs and the review of calculations that support modifications. to safety systems. The change was to complete the analysis in a different manner. The staff considers this change to be a Level III deviation.

4~ 22800-WBN-04. Allowable Clamp Loads. The corrective action was to revise calculation NCRWBNSWP8237 to correct the bolt ultimate shear strength value. The change was to incorporate the calculation into Civil Design Standard DS.C1.6.14. The staff considers this change to be a Level III deviation.

5. 30709-NPS-Ol. Nuclear Experience Review Program. The corrective action was to incorporate the nuclear experience review programs requirements into specific site standard practices. Subsequently, two site standard procedures were superseded and the corrective actions were incorporated into the new documents. The staff considers this change to be a Level III deviation.

6. 80106-BLN-03. Inspection Rejection Notices. The corrective action was to make Inspection Rejection Notices a permanent quality assurance record by revising Bellefonte procedure BNP-gCP-10.43. Subsequently, this procedure was superseded and the corrective action was incorporated into BNP-gCP-10.58. The staff considers this change to be a Level III deviation.

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

3.0 CONCLUSION

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The staff reviewed the definitions of the three deviation levels and finds them acceptable for the purpose of initiating the appropriate level of review and approval. The staff found that for the Level I deviations, technical justifications existed, and the Senior, Management Review was performed. The staff found from a sample review that the deviations appear to be appropriately categorized as Level I, II, or III. The staff finds the deviation process for the Employee Concerns Special Program to be acceptable. Although we approve your use of these definitions, it does not relieve your reporting responsibi-lities under NRC regulations. Also, our review of Level II deviations may determine that changes in methodology or scope which you implemented without prior NRC notification were not acceptable. Therefore, you should consider discussing any significant changes with the NRC.

4.0 REFERENCES

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

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

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

4. Letter from E. G. Mallace (TVA) to HRC, Dated June 8, 1990, forwarding the "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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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 TVA report dated June 8, 1990 (Reference 1). The deviation involved changes to corrective actions that TVA had previously committed to implement in its resolution of employee concerns. These corrective actions had been previously reviewed by the NRC staff and found acceptable. The previous staff evaluation was forwarded to TVA on March 11, 1988 (Reference 2).

Deviation 22303-SQN-Ol was a significant change to the proposed corrective action for establishing the seismic adequacy 'of the field-mounted instruments. The original corrective action was to be implemented in two phases. The first phase required TVA to establish the seismic adequacy of field-mounted instruments for the Sequoyah Unit 2 restart boundary prior to Unit 2 restart. The second phase required TVA to establish the seismic adequacy of the remaining 'safety-related field-mounted instruments for Units 1 and 2 prior to the Unit 1 restart. TVA's deviation changed the second phase of the corrective action from a requirement to establish the seismic adequacy of the remaining field-mounted instruments prior to Unit 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 1 restart. 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 associated with the Sequoyah Unit 1 restart boundary had been completed.

Since TVA's June 8, 1990 letter did not provide any justification for the deviation, the staff does not concur with the proposed deviation to the original corrective action. A schedule for completion of the original corrective action plan (CAP) should be given to the staff.

The staff reviewed the other Sequoyah-related Level II and III CAP deviations discussed 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 deviations are 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 deviations discussed 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 CONCLUSION

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

4.0 REFERENCES

1. Letter from E. G. Wallace (TVA) to NRC, dated June 8, 1990, forwarding the "Second Annual Report of Employee Concerns Special Program Corrective 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 Valley Authority Employee Concern Element Reports."

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

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

Principal Contributor: P. Cortland Dated: April 15, 1991

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