ML20235T954

Safety Evaluation Report on Tennessee Valley Authority: Sequoyah Nuclear Performance Plan.Sequoyah Unit 1 Restart

ML20235T954
Person / Time
Site:	Sequoyah
Issue date:	01/31/1989
From:	Office of Nuclear Reactor Regulation
To:
References
NUREG-1232, NUREG-1232-S01, NUREG-1232-S1, NUREG-1232-V02-S01, NUREG-1232-V2-S1, NUDOCS 8903080538
Download: ML20235T954 (84)

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NUREG-1232 Vol. 2, Supp.1 Safety Evaluation Report on Tennessee Valley Aut7ority:

Sequoyaa \luclear Performance Plan Sequoyah Unit 1 Restart U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation January 1989 Nhhhb;?

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NOTICE Availability of Reference Materials Cited in NRC Publications

-Most documents cited in N RC publications will be available from one of the following sources:

1. The NRC Public Document Room,1717 H Street, N.W.

Washington, DC 20555 l 2. The Superintendent of Documents, U.S. Government Printing Office, Post Office Box 37082, .

Washington, DC 20013-7082

3. The National Technical Information Service, Springfield, VA 22161 Although the listing that follows represents the majority of documents cited in NRC publications, it is not intended to be exhaustive.

Referenced documents available for inspection and copying for a fee from the NRC Public Docu-ment Ro'om include NRC correspondence and internal NRC memoranda; NRC Office of Inspection and Enforsment bulletins, circulars, information notices, inspection and investigation notices; .

Licensee Event Reports; vendor reports and correspondence; Commission papers; and applicant and licensee documents and correspondence.-

The following documents in the NUREG series are available for purchase frorn the GPO Sales

- Program:; formal NRC staff and contractor reports, NRC-sponsored conference proceedings, and NRC booklets and brochures.' Also available are Regulatory Guides, NRC regulations in the Code of Federal Regulations, and Nuclear Regulatory Commission Issuances.

Documents available from the National Technical Information Service include NUREG series reports and technical reports prepared by other federal agencies and reports prepared by the Atomic Energy Commission, forerunner agency to the Nuclear Regulatory Commission.

Documents available from public and special technical libraries ' include all open literature items, such as books, journal and periodical articles, and transactions. Federal Register notices, federal and state legislation, and congressional reports can usually be obtained from these libraries.

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Single copies of NRC draft reports are available free, to the extent of supply, upon written request to the Division of Information Support Services, Distribution Section, U.S. Nuclear Regulatory Commission, Washington, DC 20555.

e.,opies of industry codes and standards used in a substantive manner in the NRC regulatory process are maintained at the NRC Library,7920 Norfolk Avenue, Bethesda, Maryland, and are available there for reference use by the public. Codes and standards are usually copyrighted and may be purchased from the originating organization or, if they are American National Standards, from the American National Standards Institute,1430 Broadway, New York, NY 10018.

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NUREG-1232 Vol. 2, Supp.1 Safety Evaluation Report on Tennessee Valley Authority:

Sequoyah Nuclear Performance Plan Sequoyah Unit 1 Restart U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation January 1989

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ABSTRACT The Safety Evaluation Report (SER) on the Sequoyah Nuclear Performance Plan, NUREG-1232,. Volume 2, was based on the information submitted by the Tennessee Valley Authority (TVA) in its Sequoyah Nuclear Performance Plan (SNPP), through Revision 2, and on supporting documents. It was issued on May 18, 1988, by the U.S. Nuclear Regulatory Commission staff for the restart of Sequoyah Unit 2.

, The SNPP addresses the plant-specific concerns requiring resolution before startup of either of the Sequoyah units. In particular, the SER addressed required actions for Unit 2 restart.

, In most_ cases, the programmatic aspects for Unit 1 are identical to those for Unit 2. TVA described the differences in programs between Unit 1 and Unit 2 in Revision 3 of the SNPP. This was submitted by TVA in its letter dated May 9, 1988. Where the Unit 1 program is different, the staff's evaluation is provided in this supplement'to the staff's SER in NUREG-1232, Volume 2.

On the basis of its review, the staff concludes that Sequoyah-specific issues have been resolved to the extent that would support the restart of Sequoyah Unit 1.

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.l NUREG-1232, Vol. 2, Supp. 1 iii

TABLE 1F CONTENTS Page ABSTRACT ............................................................. iii ABBREVIATIONS ........................................................ xi 1 INTRODUCTION ....................... .............................. 1-1 2 ADEQUACY OF DESIGN ................................................ 2 ..

2.1 Plant Modification and Design Control ........................ 2-2 2.1.1 Introduction .......................................... 2-2 2.1.2 E v al u a ti o n . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-2 2.1.3 Conclusion ............................................ 2-3 2.2 Design Baseline and Verification Program ..................... 2-3 2.2.1 Introduction .......................................... 2-3 2.2.2 Evaluation ............................................ 2-3 2.2.2.1 Unit 1 and Unit 2 Program Differences ....... 2-4 2.2.2.2 TVA Independent Oversight Review ............ 2-5 2.2.3 Conclusions ........................................... 2-6 2.3 Design Calculations Program .................................. 2-6 2.3.1 Nuclear and Mechanical Calculations ................... 2-7 2.3.2 Civil Calculations .................................... 2-7 l 2.3.2.1 Introduction ................................. 2-7 2.3.2.2 Evaluation ................................... 2-9 2.3.2.3 Conclusions .................................. 2-10 2.3.3 Electrical Calculations ............................... 2-10 2.3.3.1 Introduction ................................. 2-10 2.3.3.2 E v a l ua ti o n . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-11 2.3.3.2.1 Auxiliary Power Systems (APS) ......... 2-11 2.3.3.2.2 Control Power Systems.................. 2-15 2.3.3.2.3 Instrumentation and Control Systems Instrumentation Accuracy Calculations ........................ 2-17 2.3.3.2.4 Raceway Systems ....................... 2-17 2.3.3.2.5 Short-Circuit Study--Medium Voltage Systems ............................. 2-17 2.3.3.2.6 Technical Specification Surveillance Requirements ......................... 2-17 NUREG-1232, Vol. 2, Supp. 1 v 1

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L _ TABLE OF CONTENTS'(Continued) i 1 ,

l Pgte 2.3.3.3. General Conclusions on the Sequoyah Electrical Calculations Program ............ 2-18  ;

2.3.4 Branch Technical Position PSB-1 ....................... 2-19' 2.4- Alternately Analyzed Piping and Supports'..................... 2-19 2.4.1 Introduction .......................................... 2-19 2.4.2 Evaluation ............................................. 2-19 2.4.3 Conclusions .................................... .. ... 2-20

.2.5 Cable Tray Supports .......................................... 2-20 .

2.5.1 Interim Acceptance Criteria ........................... 2-21 2.5.1.1 Evaluation ................................... l2-21 2.5.1.2' Implementation of Interim Criteria ........... 2-21 2.5.1.3_ Anchoring.'in Concrete ........................ 2-22 2.5.1.4 Base Plate Analysis .......................... 2-22 t 2.5.1.5 Concrete ..................................... 2-22 2.5.1.6 Co n fi rma to ry I tem s . . . . . . . . . . . . . . . . . . . . . . . . . . . 2-23 2.5.1.7 Conclusion ................................... 2-23 2.5.2 Diesel Generator Building Supports Analysis ...... .... 2-23 2.5.3 ' Cable Tray Support Base Plate Installations ........... 2-23 2.6 Concrete Quality ............................................. 2-24 2.7. Miscellaneous Civil Engineering Issues ....................... 2-24 2.8 Heat Code Traceability ....................................... 2-24

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3 SPECIAL PROGRAMS .................................................. 3-1 3.1 Fire Protection .............................................. 3-1 3.1.1 Introduction .......................................... 3-1 3.1.2 Evaluation ............................................ 3-1 3.1.2.4 Interim Compensatory Fire Protection Measures ................................... 3-1 3.1.2.5 Staffing of the Fire Brigade ................. 3-2 3.1.2.6 Fire Pump Design Deficiency .................. 3-3 3.1.2.7 Fire Protection Calculations, Revision 9 ..... 3-4 3.1.2.8 Inspection ................................... 3-4 3.1.2.9 Deviation From 10 CFR Part 50 Appendix R ..... 3-4 3.1.3 Conclusion ............................................ 3-5 3.2 Environmental Qualification of Electric Equipment Important to Safety .................................................. 3-5 lNUREG-1232, Vol. 2, Supp. 1 vi

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TABLE OF CONTENTS (Continued) pg 3.2.1 Comoliance With 10 CFR 50.49 ............................. 3-5 3.2.1.1 Introduction ................................. 3-5 3.2.1.2 Evaluation ................................... 3-5 3.2.1.3 Conclusions .................................. 3-6 3.2.2' Superheat Transient (Main Steam Temperature Issue) ..

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.3.2.2.1 Main Steam Line Break in Main Steam Valve Vaults ............................... 3-6 3.2.2.2 Main Steam Line Break Inside the Containment.. 3-7 3.3 Piece Parts Qualification (Procurement) ...................... 3-7 3.3.1 Introduction............................................ 3-7 3.3.2 -Evaluation............................................. 3-7 3.3.3 Conclusion............................................. 3-8 3.4 Sensing Line Issues .......................................... 3-8 3.5 Welding ...................................................... 3-8 3.5.1 Introduction .......................................... 3-8 3.5.2 Evaluation ......................'....................... 3-9 3.5.3 Conclusions ........................................... 3-9 3.6 Containment Isolation ........................................ 3-12 3.6.1 Containment Isolation System Design ................... 3-12 3.6.2 Containment Isolation Leakage Testing Program ......... 3-12 3.6.3 Containment Leakage Testing............................ 3-13 3.7 Containment Coatings .......................................... 3-14 3.8 Moderate-Energy Li ne Breaks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-14

3. 9 ECCS Water Loss Outside Crane Wall / Air Return Fan Operability ................................................ 3-14 3.10 Platform Thermal Growth ...................................... 3-15 3.11 Pipe Vall Thinning Assessment ................................ 3-15 3.11.1 Introduction ......................................... 3-15 3.11.2 Evaluation ........................................... 3-16 3.11.3 Conclusion ........................................... 3-16 3.12 Cable Installation ........................................... 3-16 3.12.1 Program Evaluation..................................... 3-16 3.12.2 Silicone Rubber-Insulated Cable Environmental Qualification....................s................. 3-17 3.13 Fuse Replacement ............................................. 3-18 NUREG-1232, Vol. 2, Supp. 1 vii

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I TABLE OF CONTENTS (Continued)

P. age 4 RESTART READINESS ................................................. 4-1 4.1 Operational Readiness .................................,....... 4-1 4.1.1 Introduction .......................................... 4-1 4.1.2 Evaluation ............................................ 4-2 4.1.3 Conclusions ........................................... 4-4 4.2 Management ................................................... 4-4 4.2.1 Introduction .......................................... 4-4 4.2.2 Evaluation ............................................ 4-4 4.2.2.6 Procedures ................................... 4-4 4.2.3 Conclusion ............................................ 4-5 4.3 Quality Assurance ............................................ 4-5 4.3.1 Conditions Adverse to Quality ......................... 4-5 4.3.2 Quality Assurance Program.............................. 4-6 4.4 Operating Experience Improvement ............................. 4-7 4.5 Post-Modification Testing .................................... 4-7 4.6 Surveillance Instruction Review .............................. 4-7 4.6.1 Introduction .......................................... 4-7 4.6.2 Evaluation ............................................ 4-8 4.6.3 Conclusions ........................................... 4-9 4.7 Op e ra b i l i ty " Lo o k B a c k" . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4-9 4.8 Maintenance .................................................. 4-9 4.821 Introduction .. ....................................... 4-9 4.8.2 Evaluation ............................................ 4-9 4.8.3 Conclusions ........................................... 4-10 4.9 Restart Test Program ......................................... 4-10 4.9.1 Introduction........................................... 4-10 4.9.2 Evaluation............................................. 4-11 4.9.3 Conclusion ............................................ 4-12 4.10 Training .................................................... 4-12 4.11 Security..................................................... 4-13 j 4.12 Emergency Preparedness....................................... 4-13 1 l

4.12.1 Introduction ......................................... 4-13 1 4.12.2 Evaluation ........................................... 4-14 l 4.12.3 Conclusion ........................................... 4-14 l NUREG-1232, Vol. 2, Supp. 1 viii

TABLE OF CONTENTS:(Continued)

Paste 4.13 Radiological Controls......................................... 4-14' 4.14 . Restart Activities List....................................... 4-14 4.14.1 Introduction ........................................ 4-14 4.14.2 Evaluation .......................................... 4-15 4.14.3 Conclusion .......................................... 4-16 5 EMPLOYEE C0NCERNS.................................................. 5-1 6 ALLEGATIONS........................................................ 6-1 APPENDICES, A LIST OF NRC CONTRIBUTORS

- B REFERENCES-1 huREG-1232,Vol.2,Supp.1 ix

ABBREVIATIONS AA alternate analysis AFW auxiliary feedwater AISC American Institute of Steel Construction AIW American Insulated Wire ANI American Nuclear Insurers ANSI American National Standards Institute APS auxiliary power system ASME American Society of Mechanical Engineers AWS American Welding Society BTP branch technical position CAQR condition adverse to quality report CAR corrective action report CFR Code of Federal Regulations CNPP Corporate Nuclear Performance Plan CSS containment spray system CSST common station service transformer CVCS . chemical and volume control system DBA design-basis accident DBVP design baseline and verification program DC design criteria DCRDR detailed control room design review DNE Division of Nuclear Engineering (TVA)

DR discrepancy report EA Engineering Assurance (TVA)

ECCS emergency core cooling system

.ECN engineering change notice ECP employee concerns program l ECSP employee concerns special program l ECTG employee concerns task group EDG emergency diesel generator EQ environmental qualification J

FAR functional analysis report FSAR Final Safety Analysis Report GDC general design criteria IE Inspection and Enforcement, Office of IEEE Institute of Electrical and Electronics Engineers INPO Institute of Nuclear Power Operations IR inspection report l

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=l ABBREVIATIONS (Continued)

LER licensee event report LOCA loss-of-coolant accident MELB moderate energy line break MI- maintenance instruction MSLB main steam line break MSVV main steam valve vault

-NCR nonconformance report NDE non-destructive examination NERP- ' nuclear experience review program NFPA National Fire Protection Association NRC Nuclear Regulatory Commission NSRB Nuclear Safety Review Board (TVA).

NSRS- Nuclear Safety Review Staff (TVA)

-OL ' operating license ONP Office of Nuclear Power (TVA)

P&ID piping and instrument drawing

PAM post-accident monitoring PORC -plant operation review committee

-PR0 'potentially reportable occurrence QA quality assurance QC quality control QTC Quality Technology Company RCPB reactor coolant pressure boundary

.RDBD- restart design-basis document RG regulatory guide RHRSS residual heat removal spray system RIP Replacement Items Project RTG restart test group RTP restart test program SAL Sequoyah Activities List SALP systematic assessment of licensee performance SCV steel containment vessel SER safety evaluation report SI surveillance instruction SMI special maintenance instruction SNPP Sequoyah Nuclear Performance Plan SPDS safety parameter display. system

.SQN Sequoyah Nuclear P1 ant SR0 senior reactor operator SRSS square root of the sum of the squares "

SSE safe-shutdown earthquake SSQE safety system quality evaluation STA shift technical advisor NUREG-1232, Vol. 2, Supp. 1 xii

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ABBREVIATIONS (Continued)

,TMI. 'Three Mile Island' TOL. ' thermal' overload TVA '. Tennessee Valley _ Authority --

URI' unresolved item USST unit station service transformer VSB vital station battery

'ZPA zero period acceleration 5-4-

1 NUREG-1232, Vol. 2, Supp. 1 xiii L _ _ _ _ - _ - - _ _ - _ _ -

1 INTRODUCTION On September 17, 1985, the Nuclear Regulatory Commission (NRC) Executive Director for Operations issued a letter to the Chairman of the Board of Directors of the Tennessee Valley Authority (TVA) pursuant to Title 10 of the Code of Federal Regulations Section 50.54(f) [10 CFR 50.54(f)]. This letter requested informa-tion on the actions TVA was taking to resolve NRC's concerns about TVA's nuclear program. These concerns were divided into four categories: (1) corporate activities, (2) the Sequoyah Nuclear Plant (SQN), (3) the Browns Ferry Nuclear Power Station, and (4) the Watts Bar Nuclear Plant.

TVA's Corporate Nuclear Performance Plan (CNPP), which was prepared in response to the NRC letter, was originally submitted to the NRC on November 1, 1985.

The revised plan was submitted on March 10, 1986, and subsequent revisions were submitted to the NRC on July 17, July 31 and December 4,1986, and March 26 and December 10, 1987. The NRC staff safety evaluation on the revised CNPP, through Revision 4, was issued on July 28, 1987, as NUREG-1232, Volume 1.

In addition to its corporate plan, TVA prepared separate plans to address site-specific problems at its Sequoyah and Browns Ferry sites. A separate plan has yet not been submitted for the Watts Bar site. Volume 2 of NUREG-1232 documents the staff's evaluation of the corrective actions implemented by TVA to resolve problems at Sequoyah. In many cases, long-term corrective actions, extending beyond startup, are required to fully resolve these issues. The Sequoyah Nuclear

' Performance Plan (SNPP) was submitted on November 1, 1985. TVA provided NRC with Revisions 1, 2, and 3 to the plan on April 1, 1987(a); and July 2, 1987; and May 9, 1988, respectively. The staff will issue separate evaluations for Browns Ferry and Watts Bar at a later date.

This report supplements Volume 2 of NUREG-1232. Volume 2, the staff's evaluation of the restart of Sequoyah Unit 2, was issued by the staff's letter dated May 18, 1988. Supplement 1 is the staff's evaluation on the restart of Sequoyah Unit 1.

In this supplement, the NRC staff evaluates the differences in the Unit 1 SNPP programs from the programs evaluated and approved for Unit 2. These differences were documented in TVA's letters dated March 31 and May 9, 1988, and in the meet-ing with the staff on April 14, 1988. The meeting summary was issued on May 4, 1988.

For Sequoyah Unit 2, TVA established a Sequoyah Task Force on March 19, 1986, to review implementation of the corrective actions applicable to Sequoyah, to initiate specific actions to address Sequoyah problems, to monitor and ensure that a list of all known work items has been compiled, and to review the process and identification of those items required to be completed before restart of Sequoyah Units 1 and 2, which were shut down by TVA in August 1985. This task force examined the disposition of Sequoyah-related issues that had been identi-fied by the corporate level team of industry advisors, to confirm that root causes of problems were suitably addressed. Sequoyah site-specific issues deal primarily with operations, maintenance, design control, and management system implementation. The SNPP describes the programs and activities planned by TVA to improve performance in each of these areas.

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To complete its assignment, the Sequoyah Task Force developed a list of Sequoyah plant activities (except for those of a routine nature) to be completed before j restart. The Sequoyah Activities List (SAL) was based on issues identified in  !

i NRC inspections, TVA quality assurance (QA) audits, American Nuclear Insurers (ANI) audits, Institute of Nuclear Power Operations (INP0) inspection reports, Sequoyah corrective action reports (CARS) and discrepancy reports (DRs), TVA )

Nuclear Safety Review Staff (NSRS) and Nuclear Safety Review Board (NSRB) reports,  !

employee concerns, Sequoyah reactor trip reports and licensee event reports (LERs), and technical issues identified by TVA's Division of Nuclear Engineering (DNE).

The Sequoyah Task Force established criteria (Section IV.2.0 of the SNPP) to determine which items were required to be resolved for restart. The staff re-viewed and accepted these criteria by letter dated June 9, 1987. The task force reviewed the process the line organization used to identify, evaluate, disposi-tion, and close out items and reviewed the adequacy of planned actions to be taken before Sequoyah Unit 2 restart. As new issues arose and work activities were developed, they were reviewed by Sequoyah management to determine their importance to restart. The Site Director had to approve all new items added to the restart list; however, only the Manager of the Office of Nuclear Power (ONP)

(present title is Senior Vice President / Nuclear Power) could delete items that had been designated for restart.

For Unit 1, restart items are being identified and tracked by means of TVA's computer system TROI (that trackt, and reports open items) rather than by the SAL used for Unit 2. The Unit 1 restart list was developed by an item-by-item review of completed and open Unit 2 and common restart activities and of open Unit 1 issues. The criteria used to guide the line organizations in raising potential restart issues and making recommendations to management have been the same restart criteria used for Unit 2. The Site Director has designated either the Restart Director or the Assistant to the Site Director to evaluate proposed new activities and ascertain that these activities meet the restart criteria.

1 TVA described a number of special programs to ensure integrated corrective '

actions dealing with problems created by deficiencies in the past conduct of activities.Section III of the original SNPP identified special programs that needed to be resolved before restart of Sequoyah Unit 2. These include programs to:

Complete the documentation and resolve electrical equipment environmental qualification questions initially raised at the time Sequoyah was shut >

down.

Verify the adequacy, with regard to safe plant restart, of past selected I safety-related design modifications, keeping in mind the weaknesses in past design control programs.

Reexamine cable tray support analysis for weaknesses in the analytical basis.

Complete system analyses where proper design documentation did not exist in the past.

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• Verify the adequacy of piping and supports that were not rigorously analyzed and where alternate analysis methodology has been poorly applied in the past.

• Resolve any differences in the effects of increased temperatures during main steam line breaks engendered by revised vendor analysis.

• Resolve identified areas of noncompliance with 10 CFR Part 50, Appendix R, fire protection requirements.

• Assess the adequacy of the welding program at Sequoyah, an issue raised through the employee concerns program.

• Examine issues with regard to instrumentation sensing lines.

Since the SNPP was first issued, TVA added other special programs to Section III of the plan. These include programs to:

• Determine if a problem exists with regard to pipe wall thinning, similar to that which led to a pipe rupture at the Surry Power Station, Unit 2, in December 1986.

• Establish a restart test program.

• Review replacement components and parts and resolve those that do not meet the same quality requirements as the installed equipment.

• Assess the adequacy of cable ampacity design calculations.

• Resolve cable pulling concerns such as sidewall pressure, bend radius, jamming, and vertical drop.

• Correct a misapplication of actuator fuses.

• Resolve an apparent nonconformance with 10 CFR Part 50, Appendix A, involv-ing containment penetrations.

There are other programs as well to consider miscellaneous civil engineering issues, moderate energy line break flooding, containment coatings, emergency core cooling system (ECCS) water loss outside the crane wall, platform thermal growth, and heat code traceability. Many of these programs are applicable to Units 1 and 2, although actual implementation for Unit 1 may not have been completed until after Unit 2 restart.

The programs mentioned above were evaluated for Sequoyah Unit 2 in Sections 2 through 4 of the safety evaluation report (SER) on the SNPP through Revision 2.

That SER was issued as NUREG-1232, Volume 2, on May 18, 1988.

This supplement addresses the differences in the SNPP programs between Unit 1 and Unit 2. These differences were described in Revision 3 to the SNPP which TVA submitted to the staff by letter dated May 9, 1988. This supplement closely follows the format of NUREG-1232, Volume 2. Where TVA has stated that no differ-ences exist between this supplement and NUREG-1232, Volume 2, the appropriate section in NUREG-1232, Volume 2 will be referenced.

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.Another major problem area included the concerns expressed by TVA employees regarding the quality of.TVA's nuclear activities. The programs relating to j

. employee concerns are briefly described in Section 5 of this evaluation.

The NRC plans for addressing allegations are discussed in-Section 6 of this supplement.

Jack Donohew of the NRC Office of Nuclear Reactor Regulation coordinated the staff's efforts involved in preparing the safety evaluations for TVA's Sequoyah Unit 1 restart efforts. Mr. Donohew may be contacted by telephone at (301) 492-0704 or by writing to the following address:

Mr. Jack Donohew Office of Nuclear Reactor Regulation U.S.' Nuclear Regulatory Commission Washington, D.C. 20555 4

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2 ADEQUACY OF DESIGN One of the root causes of the problems at Sequoyah was the failure of TVA to.

consistently document changes to the plant's design basis and to maintain the plant's configuration in accordance with that basis. TVA's efforts to strengthen its design control programs and to assess the effects of past weaknesses on the plant are discussed below.

In preparation for restarting Sequoyah Unit 2, the NRC staff evaluated TVA's efforts in its design control programs and documented NRC's evaluation in a safety evaluation report on the TVA Sequoyah Nuclear Performance Plan (SNPP)

-(NUREG-1232, Volume 2). This section deals with the differences in the SNPP programs for Unit 1 concerning the adequacy of design. Where there are no dif-ferences in the SNPP program from that evaluated in NUREG-1232, Volume 2, for Unit 2, the reader will be referred to the appropriate section of NUREG-1232, Volume 2 which this safety evaluation supplements.

By letters dated March 31 and May 9, 1988 and in a meeting on April 14, 1988, TVA identified the differences in the SNPP programs for Unit 1 from those ap-proved by the NRC staff for Unit 2. The summary for the April 14, 1988 meeting was issued on May 4, 1988. Programs that concern the adequacy of design, are:

design baseline and verification program (DBVP) (Section 2.2) and civil engineer-ing design calculations program (Section 2.3.2.). TVA assumed Unit 1 was in cold shutdown (Mode 5) for many electrical design calculations. TVA revised these before the restart of Unit 1, and they are discussed in Section 2.3.3.

As with Unit 2, there are Phase II programs for DBVP, design calculations program, alternatively analyzed piping and supports, and cable tray supports for Unit 1.

As discussed in NUREG-1232, Volume 2, the Phase I programs are completed before

! the restart of the unit and the Phase II programs will be completed after restart.

On June 22 and Ju!y 21, 1988, NRC met with TVA to discuss its Phase II pregrams.

The meeting summaries were issued on July 1 and August 4,1988, respectively.

The staff conducted the safety system quality evaluation (SSQE) inspection be-tween June 20 and July 18, 1988, on the Unit 1 containment spray system (CSS) in part to audit the adequacy of the design programs for Unit 1. The S$QE was to provide additional assurance that the major programs had been properly imple-mented by TVA on Unit 1 and that the major design and construction problems had been identified and resolved before Unit 1 restart. The SSQE is discussed in Inspection Report (IR) 50-327, 328/88-29 issued on October 20, 1988.

The inspection report confirmed five commitments made by TVA during the exit meeting on July 8,1988, conducted for the SSQE inspection. On the basis of the review of the CSS, there appeared to be adequate program implementation to support Unit 1 startup, with the exception of five programs. In addition, TVA was asked to respond to three Severity Level IV and one Severity Level V violations identified during this inspection. On November 21, 1988, TVA responded by letter identifying root causes, corrective steps, and results of TVA actions. TVA also identified corrective steps that would avoid further violations.

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All commitments made by TVA for these programs for Units 1 and 2 are identified i in the appropriate sections below. The commitments that were made for the re- i I

start of Unit 2 are also stated in NUREG-1232, Volume 2.

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2.1 Plant Modification and Design Control 2.1.1 Introduction 1 TVA did not identify any differences between the Unit 1 and Unit 2 programs for plant modification and design control. The staff's evaluation of this program for Unit 2 is addressed in Section 2.1.2 of NUREG-1232, Volume 2.

2.1.2 Evaluation TVA's improved design change control program will be implemented in two phases for current and future plant modifications.

The first phase was to be implemented before restart of Unit 2 and included a change control board and a transitional design control system. This process requires that design changes that are to be implemented be contained in complete packages specific to the appropriate unit. This will facilitate the reviews required to ensure that each change has been quality engineered, that it can be installed and tested, and that documentation and safety analyses are complete and based on actual plant configuration. A task engineer was assigned to coordinate these efforts.

The second phase in the development of the improved design control program is to establish a permanent design control system based on the plant modification package concept. A procedure will be developed to ensure a comprehensive and focused evaluation of modifications and proper implementation and follow-through. Improved aspects of this program include the use of the actual plant configuration for design, updated design criteria, accurate reflection of the modification in licensing documents, and an integrated, project-oriented <

approach to handle changes to the plant, as opposed to the fragmented work plan approach used in the past.

In its December 11, 1986 letter, TVA committed to consolidate the "as-constructed" and "as-designed" information on DBVP primary drawings before the end of the sec-ond refueling outage (Cycle 4) after restart of Unit 2. The staff finds this commitment acceptable because (1) the first refueling is presently planned for several months after restart and (2) in the interim, the actual configuration will be depicted on marked-up drawings available for engineering and operational purposes.

By letter dated December 15, 1987, TVA stated that Division of Nuclear Engineering (DNE) procedures, which were needed to establish the process for preparing Sequoyah implementing procedures, have been implemented. Site level procedures and training were completed by March 31, 1988.

TVA has not cocynitted to implement a single drawing system for drawings other than DBVP drawings which are used by operations personnel to operate the plant (primary drawings such as piping and instrument drawings [P& ids]). Other draw- '

ings will apparently be produced only as needed to support modifications. The NUREG-1232, Vol. 2, Supp. 1 2-2

staff believes that a more comprehensive approach, which includes scheduling details and identification of all other drawings to be maintained as configured, is needed. In a letter dated April.1, 1987(b), TVA stated that the details ,

regarding comprehensive scheduling of drawings to be maintained as configured is_still being developed. The staff considers this item to be a post-restart issue for both Unit 1 and Unit 2. i 2.1.3 Conclusion On the basis of the findings documented in NUREG-1232, Volume 2, the staff concludes that TVA has taken the appropriate steps to correct design control problems at Sequoyah for the restart of Unit 1. The staff will review the transitional design control system during its review of the Phase II portion of the DBVP. The staff's evaluation of the DBVP is given in Section 2.2 below.

2.2 Design Baseline and Verification Program .

2.2.1 Introduction TVA's Unit 2 DBVP, developed to assess the effect of past weaknesses in design and configuration control and to identify any corrective actions that may be required, is discussed in SNPP Section III.2. The intent of this program was to provide additional confidence that the plant meets its original licensing basis.

The staff's evaluation of the Unit 2 DBVP is provided in Section 2.2 of NUREG-1232, Volume 2.

TVA's DBVP was developed to address, in part, the effect of past weaknesses in design and configuration control at Sequoyah and to identify required corrective actions. The Unit 1 program includes (1) verifying and establishing the plant functional configuration, (2) reconstructing the design basis, (3) reviewing and evaluating modifications since the operating license was issued against the design basis, and (4) performing the modifications developed from this review.

2.2.2 Evaluation The Unit 1 DBVP was initially described in TVA's March 31, 1988 submittal on I the Unit 1 restart plan. The Unit 1 DBVP is being implemented in two phases.

The pre-restart phase (Phase I) addresses the Unit 1 portion of the systems ,

required to mitigate accidents addressed in Chapter 15 of the final safety an-alysis report (FSAR) and systems required to provide safe shutdown. The post-restart phase (Phase II) continues engineering activities within the pre-restart phase that TVA considered not essential to safe restart but that are needed for addressing identified design control problems. The post-restart phase will also include other safety-related systems.

TVA defined the scope of the Phase II portion of the DBVP in a May 12, 1987 letter. Although the staff continues its review of the Phase II program, this review is not essential to determine the acceptability of TVA's programs to sup-port restart of Sequoyah Unit 1 and Unit 2. The staff will issue its eveluation of the Phase II program at a later date.

The scope of the Unit 1 pre-restart phase of the DBVP as described in Revi-sion 3 of the SNPP is identical to the scope of the Unit 2 program. The staff NUREG-1232, Vol. 2, Supp. 1 2-3 1

l l

' l documented its review and acceptance of the Unit 2 pre restart phase of the DBVP )

in Section 2.2.2 of NUREG-1232, Vol. 2. On the basis of the staff's previous {

review and acceptance of the Unit 2 pre-restart scope, the staff concludes that d the same scope and system selection for Unit 1 is acceptable.

2.2.2.1 Unit 1 and Unit 2 Program Differences Revision 3 of the SNPP identified two program differences between the Unit 1 and Unit 2 DBVPs: (1) the Unit 1 program takes credit for reviews that had been performed under the Unit 2 program and (2) responsibility for the review of testing has been transferred to the restart test program. The first item is acceptable to the staff provided TVA identifies and evaluates all areas of the Unit 2 program reviews where Unit 1 differences exist.

In conjunction with the Unit 2 DBVP, functional test requirements were identified by the DBVP and provided to the restart test program. For Unit 1, the functional test requirements will be evaluated by the restart test program and the results provided to the DBVP for acceptance. TVA's Engineering Assurance (EA) group assessed the management controls established for the con-duct of Unit 1 restart testing. On the basis of its review, EA supported the DBVP plan to review the results of the restart test program for acceptability in order to satisfy the functional test requirements. The staff considers TVA's plan to transfer responsibility for the review of testing to the restart test program acceptable. The staff evaluation of the restart test program is further discussed in Section 4.9 of this supplement.

During a meeting with TVA on July 21, 1988 (meeting summary dated August 4, 1988),

the staff identified two areas of the Unit 1 program description for system eval-uations and corrective actions that were different from the Unit 2 program de-scription. TVA stated that these areas were identical for both units and com-mitted to provide a revision to the Unit 1 program description to clarify these items. In a subsequent conference call on September 16, 1988, TVA stated that one area, the use of the DNE review board, had been deleted from the Unit 1 program. In a letter to the NRC dated September 30, 1988, TVA provided its justification for deleting the DNE review board. TVA's letter stated that the primary comments provided by the DNE review board were incorporated in the Unit 1 review process and procedures. In addition, TVA stated that the Unit 2 system evaluation reports which had been reviewed by the DNE review board were used in the Unit 1 program. The deletion of the DNE review board from the Unit 1 l program was a procedural change that did not affect the scope of the Unit 1 DBVP. 1 On the basis of (1) TVA's incorporation of the previous DNE review board comments in the Unit 1 DBVP implementation and (2) the results of the EA independent review of the DBVP implementation, the staff finds that the deletion of the DNE review board from the Unit 1 DBVP does not result in an overall programmatic change that would significantly alter the validity of the staff's conclusions on the adequacy of the DBVP. Thus, the staff considers this procedural change to the DBVP for Unit 1 acceptable.

TVA also stated in its September 30, 1988 letter that the DBVP corrective action reviews for the potential impact on environmental qualification (EQ) program requirements, which were associated with the DBVP in the SNPP, were actually performed as part of the plant design-control process. This process was inde-pendent of DBVP. By a telephone conference call on October 20, 1988 and in a l

l i

NUREG-1232, Vol. 2, Supp. 1 2-4

letter dated October 26, 1988, TVA explained that these EQ reviews for both Units 1 and 2 were conducted in the same manner. The staff concludes that this EQ review process is acceptable.

2.2.2.2 TVA Independent Oversight Review As an integral part of the DBVP, TVA's Engineering Assurance group (EA) of the Division of Nuclear Engineering (DNE) performed an independent oversight review of the DBVP. An in-depth description of the independent oversight review process and its results for Unit 1 is contained in TVA Report EA-0R-003, " Engineering Assurance Oversight Report, SQN Unit 1 DBVP," which was submitted to NRC by let- ]

ter dated July 28, 1988. TVA also transmitted a supplemental TVA Report EA-OR-003S, " Supplemental Engineering Assurance Oversight Review Report, SQN Unit 1 DBVP," by a letter dated September 19, 1988. The objectives of this independent review are the same for Unit 1 as they were for Unit 2.

The supplemental EA report addressed the open items in EA-0R-003, the original l EA oversight review report on the DBVP for Unit 1. The restart items identified I in the original report have been completed in terms of DBVP Phase I (pre-restart).

One issue was determined to be a DBVP Phase II (post-restart) issue. This issue and the verification in DBVP Phase II will be completed after the restart of Unit 1.

l In an effort to gain further confidence in TVA's DBVP and, in particular, the l independent oversight activities of the EA organization relating to this DBVP, the NRC staff has reviewed a sample of five supporting backup data packages.

These documents address the results of the EA oversight review afforts including an independent evaluation and verification of actions to correct and close out- 1 standing issues. This review was performed in addition to the NRC inspections l of TVA's DBVP (

Reference:

Inspection Reports 50-327, 328/86-38 (September 17, 1986), 86-45 (October 31, 1986), and 86-55 (February 3, 1987); 50-327, 328/87-14 (June 4, 1987) and 87-31 (December 3, 1987)) which also assessed the effective-ness of the EA oversight effort.

The five data packages (Action Items C28 and C40 [0bservation C6], E25 [0bserva-tion E6], E65 [0bservation E3], E91 [0bservation E14], and Q12 [0bservation Q2]) l consisted of results of analysis reviews and verifications by the DNE and the EA organizations which support the action items / observations in EA reports EA-OR-001 and EA-0R-001S. These EA reports were submitted by TVA in letters dated May 15 and October 23, 1987, respectively. As a result of reviewing each of the five packages, the staff found that the EA organization was actively and effec-tively involved in evaluating and reviewing the DNE activities related to the DBVP and in assessing and verifying the findings, corrective actions, and close- ,

out of these packages. Further, the staff concluded that the restart open issues ]

previously reported in EA-0R-001 and EAd R-0015 have been adequately resolved ]'

and closed out.

l Of particular interest has been the resolution of Action Item Q12 (Observation Q2).

This action item resulted from a design deficiency identified in a condi-tion adverse to quality report (CAQR) 86-03-012 and pertains to: Part A, design l

criteria not being maintained; Part B, design calculations not being maintained; and Part C, plant configuration (as-built) design documents being different from FSAR commitments.

NUREG-1232, Vol. 2, Supp. 1 2-5

l l

1

' In regard.to Part A, EA has verified that all Sequoyah Unit 2 design criteria are complete with the issuance of the restart design-basis document (RDBD). .

All post restart design criteria development is committed to be completed by June 1, 1989. This latter issue is a post-restart open item. In regard to Part B, EA has verified that DNE has adequately reviewed all safety-related calculations to ensure they are technically adequate and up to date and that a cross-reference information system has been established to maintain accountabil-ity of the status of calculations against pertinent documents, drawings, and other calculations. All issues in Part B are, therefore, closed.

The deficiency and corrective action associated with Part C was transferred to a separate corrective action report, SQ-CAR-86-04-021. The corrective action requires that the FSAR be updated and verified to the current design and as-built conditions. This action is scheduled for completion in April 1989.

This issue remains open.

The. restart open issues previously reported in EA-0R-001 and EA-0R-001S have been adequately resolved and are closed out.

The staff will verify that all committed post-restart design criteria are com-pleted by June 1989. The staff will also verify the completion of corrective action report SQ-CAR-86-04-021 by April 1989. In the process of completing these actions, the resolution of design deficiencies will involve consideration of unreviewed safety questions pursuant to 10 CFR 50.59 as appropriate.

On this basis and on the basis of the staff's previous review of the program and its implementation on Unit 2, the staff concludes that the EA program for Unit 1 is acceptable.

2.2.3 Conclusions TVA initiated the DBVP and EA independent oversight review as part of its effort to correct past design-control deficiencies identified by employee concerns and design-control reviews. This program was extensively reviewed and inspected by the staff before Sequoyah Unit 2 restart. The staff concludes that the same program with the modifications discussed above is sufficient to correct design-control problems at Sequoyah Unit 1.

On the basis of the inspections of Unit 2, as discussed in Section 2.2 of NUREG-1232, Volume 2, and the SSQE inspection of the Unit 1 CSS, the staff con-cludes that Phase I of the DBVP has been sufficiently implemented for Unit 1 to restart. The staff will review the transitional design control system during its review of the Phase II portion of the DBVP.

2.3 Design Calculations Program i On the basis of past findings from TVA and the NRC reviews, it was determined that there was inadequate documentation of the calculations supporting the design i basis for TVA's nuclear plants. Calculations were determined to be missing, l incomplete, or outdated. TVA's engineering disciplines (nuclear, mechanical, I civil, and electrical) have each developed programs to resolve these problems. l These efforts include (1) identifying essential calculations; (2) verifying the i

NUREG-1232, Vol. 2, Supp. 1 2-6 l

, l

existence of, or regenerating, essential calculations; (3) ensuring the technical adequacy of these calculations; and (4) ensuring the calculations are current.

Essential calculations are those that qualify existing plant systems or features whose failure could (1) result in a loss of integrity of the reactor coolant +

system, (2) result in the loss of ability to place the plant in a safe shutdown condition, or (3) result in a release of radioactivity off site in excess of a significant fraction of the 10 CFR Part 100 guidelines.

The calculations review efforts for the engineering disciplines are discussed in detail in Section 2.3 of NUREG-1232, Volume 2. The sections that follow discuss and evaluate the identified differences in the TVA design calculation program for Unit 1.

2.3.1 Nuclear and Mechanical Calculations The nuclear and mechanical calculation review program for Unit 2 is described in Sections III.4.2 and III.4.3 of the SNPP. TVA did not identify any differ-ences between the programs for Unit 1 and Unit 2. On the basis of Section 2.3.1 of NUREG-1232, Volume 2, the staff concludes that the nuclear and mechanical engineering calculation review effort has been adequately defined and implemented to identify the necessary essential calculations for the operation of Sequoyah; that the technical adequacy of the calculations has been adequately demonstrated; and that necessary corrective actions are being scheduled in accordance with the staff-approved restart criteria. Therefore, the staff finds the TVA actions for resolving concerns about nuclear and mechanical calculations acceptable for the restart of Unit 1.

2.3.2 Civil Calculations 2.3.2.1 Introduction The civil calculation review program for Sequoyah Unit 2 is described in Section III.4.4 of the SNPP.

I The staff safety evaluation of the SNPP through Revision 2 is contained in Sec-tion 2.3.2 of NUREG-1232, Volume 2. The staff concluded that all pre-restart items for Unit 2 in this area have been resolved.

Unit 1 and Unit 2 Program Differences TVA submitted Revision 3 to the SNPP to the NRC on May 9, 1988. Part 2 of Revi-sion 3 described Sequoyah Unit 1 startup programs that differ from the Unit 2 startup programs. The Sequoyah civil engineering program was identified A difference as a program area in which differences ex'ist between Unit 1 and Unit 2.

identified was that TVA would submit a final report on the Office of Inspection and Enforcement (IE) Bulletin 79-14, " Seismic Analyses for As-Built Safety-Related Piping" (including Revision 1 and Supplements 1 and 2) for Unit 1. TVA had completed its work on IE Bulletin 79-14 for Sequoyah Unit 2; however, TVA still considered the bulletin open on Unit 1.

I TVA originally identified concerns with IE Bulletin 79-14 in Section III.15.1 of the SNPP under the heading of " Miscellaneous Civil Engineering Issues." The l

NUREG-1232, Vol. 2, Supp. 1 2-7

i staff's evaluation of this topic was contained in Section 2.7 of NUREG-1232, Volume 2. TVA had also covered the topic of piping and supports in the civil calculation program in Section III.4.4 of the SNPP. The staff evaluation of the civil calculation program was contained in Section 2.3.2 of NUREG-1232, Volume 2. For Sequoyah Unit 1, TVA combined the discussions of IE Bulletin 79-14 and the pipe support calculation effort under the heading of " Civil Engineering Program" in Revision 3 to the SNPP.

l The Unit I civil engineering program was initially described in TVA's March 31, 1988 submittal on the Unit 1 restart plan. The TVA submittal stated that the Unit 1 civil engineering program was essentially the same as the Unit 2 program with the exception that a final report would be submitted on IE Bulletin 79-14 for Unit 1. The Unit 1 IE Bulletin 79-14 implementation had been addressed by an employee concerns report (EN 21202). EN 21202 stated that discrepancies existed with previous TVA pipe support inspections on Unit 1 and that TVA initiated a pipe support enhancement program as a corrective action.

In a meeting with the staff on April 14, 1988 (meeting summary dated May 4, 1988),

TVA presented additional details on the program scope of the IE Bulletin 79-14 and pipe support calculation efforts. In addition, TVA stated it would use the same criteria for determining required restart modifications for Unit 1 as were used for Unit 2. TVA submitted the results of this IE Bulletin 79-14 evaluation in a letter dated August 4, 1988(b).

IE Bulletin 79-14 requires licensees to verify that the seismic analysis of pip-ing applies to the actual configuration of the plant. As a result of concerns raised by the original NRC inspections of TVA's IE Bulletin 79-14 program at Sequoyah Unit 1, TVA initiated a sampling inspection program. As part of this

l. program, 80 piping isometrics inside the containment were inspected using Main-tenance Instruction MI-6.17. In December 1985 and February 1986, TVA's quality assurance staff identified weaknesses in the MI-6.17 walkdowns and, as a result, two corrective action reports (CARS) were issued. In response to the CARS, TVA performed additional inspections of the 80 piping isometrics to Special Mainten-ance Instruction SMI-1-317-24.(SMI-24). This program was reviewed by the em-ployee concerns program (Report EN 21202). The employee concerns report found the Sequoyah Unit 1 program had been substantially improved to correct past deficiencies and concluded that no further corrective action was required.

In its August 4, 1988(b) submittal, TVA identified a more comprehensive program for the evaluation of rigorously analyzed piping at Sequoyah Unit 1. This I

program included the evaluation of all open items that had been identified from previous programs against the piping analysis and support designs, and the i

l upgrading of the support calculations to the new design criteria SQN-DC-V-24.2.

The scope included 162 piping analyses and approximately 2900 piping supports.

TVA developed Special Maintenance Instruction SMI-0-317-69 (SMI-69) to control the collection of additional as-built data for the Unit 1 rigorously analyzed piping. In its submittal, TVA stated that approximately one-third of the pipe supports and all but six piping isometrics were inspected to SMI-69. SMI-69 contained requirements for as-built dimensioning of piping that had not been obtained by some of TVA's previous walkdowns.

NUREG-1232, Vol. 2, Supp. 1 2-8

TVA used the criteria in SQN-DC-V-24.2 to evaluate supports and CEB-CI-21.89 to identify the required restart modifications. TVA stated that 373 modifications were required to meet the criteria in SQN-DC-V-24.2 and 179 restart modifica-tions were required to meet the criteria in CEB-CI-21.89.

TVA's submittal also stated that the closure of IE Bulletin 79-14 for Unit 1 rigorously analyzed piping in common plant areas was based on TVA's original inspections supplemented by the additional SMI-24 inspections. TVA also stated tM the common area supports had been previously evaluated by the Unit 2 cal-c..ation program which included a functional verification inspection per CEB-CI-21.83. In addition to the rigorously analyzed piping, TVA stated that alter-nately analyzed piping within the scope of IE Bulletin 79-14 had been addressed by the Sequoyah alternate analysis program. This program had been previously described in Section III.5.0 of the SNPP.

2.3.2.2 Evaluation TVA's civil calculation program for Sequoyah Unit 2 as described in Section III.4.4 of the SNPP involved the identification of essential calculations, verification of retrievability, regeneration of missing essential calculations, and verification of the technical adequacy of existing calculations. The Unit 2 civil calculation program was extensively audited by NRC calculation program inspections and the NRC integrated design inspections. Tne staff's evaluation of the Unit 2 program is contained in NUREG-1232, Volume 2.

During the review of civil engineering calculations, TVA determined that a large number of rigorously analyzed pipe support calculations were not retrievable.

The Sequoyah Unit 1 program combines the regeneration of the pipe support calcu-lations with the resolution of IE Bulletin 79-14. The Unit 1 program scope for rigorously analyzed pipe supports as described by TVA is more comprehensive than the Unit 2 program since additional detailed walkdowns were performed for Unit 1.

On the basis of the staff's previous review of the Unit 2 program, the same prog-ram for Unit 1 with the addition of a final report on IE Bulletin 79-14 is acceptable.

TVA stated that it did not use the upgraded (SMI-69) IE-Bulletin 79-14 walkdowns for common areas where the supports had been previously evaluated by the Unit 2 program or for piping covered by the alternate analysis program. The supports in Unit 1 common areas had been functionally verified during the Unit 2 pipe support calculation effort. In addition, the NRC's integrated design inspection of the essential raw cooling water system had performed as-built inspections of the common area for Unit 2. TVA's alternate analysis program procedures for piping inspections had been previously reviewed and the staff presented its evaluation in Section 2.4 of NUREG-1232, Volume 2. On the basis of the staff's previous acceptance of the Unit 2 piping and support evaluations and the Unit 2 alternate analysis program, the same programs applied to Unit 1 are also acceptable.

TVA stated that it used the same criteria for Unit 1 to evaluate rigorously analyzed pipe supports that had been used for Unit 2. The staff's evaluation of these criteria is contained in Section 2.3.2 of NUREG-1232, Volume 2. By evaluating SQN-DC-V-24.2, the staff determined that the criteria were accept-able for restart, and that the staff would be performing additional evaluations NUREG-1232, Vol. 2, Supp. 1 2-9

of the standard component supports as a post-restart effort. The staff evalua- l tion of CEB-CI-21.89 approved the criteria, with certain restrictions, in a letter.to TVA dated February 23, 1988. In addition, the staff cited several concerns with TVA's implementation of the pipe support criteria for Unit 2 in Inspection Report 50-327, 328/88-12 (June 24, 1988). TVA's resolution of these inspection items is also applicable to Unit 1. The present schedule for compli-ance with the long-term criteria is the end of Cycle 4 for Unit 1 (TVA's Aug-- 3 ust 4, 1988(b) submittal). . TVA's use of the same criteria for Unit 1, as ac- I cepted by the staff for Unit 2 is acceptable.

TVA's' implementation of its program for addressing IE Bulletin 79-14 for Unit 1 was reviewed during.several.NRC inspections. The NRC's original inspections identified concerns with TVA's IE-Bulletin 79-14 program on Unit 1. TVA's sub-sequent corrective actions were reviewed in Inspection Report 50-327, 328/85-49 (February 6, 1986). The inspection report noted several discrepancies regarding pipe supports and TVA was cited with a violation. Inspection Report 50-327, 328/86-16 (March 26, 1986) identified additional discrepancies in a followup inspection. Inspection Report 50-327, 328/86-55 (February 3, 1987) closed the violation from Inspection Report 50-327, 328/85-49 (February 6,1986). The in-spection report also contained a review of the work being performed under Special Maintenance Instruction SMI-1-317-24. The inspection report did not identify any violations or deviations. The staff also performed a safety system quality evaluation inspection of the Unit 1 containment spray system as documented in Inspection Report 50-327, 328/88-29 (October 20, 1988). This inspection included a sample review of pipe support calculations and pipe support as-built configu-ration. In addition to these inspections, the NRC conducted a special as-built inspection of the essential raw cooling water system, Inspection Report 50-327, 328/87-52 (September 25,1987) which covered the Unit 1 and Unit 2 common plant piping.

On the basis of inspections the staff performed regarding IE Bulletin 79-14, review of TVA's implementation of the bulletin by the employee concerns pro-gram, and TVA's additional inspections using SMI-69, the staff concludes that TVA's program to address IE Bulletin 79-14 for Unit 1 is adequate to verify the as-built piping configuration. The staff plans to document the final closeout of the bulletin for Sequoyah Unit 1 after the restart of Unit 1.

2.3.2.3 Conclusions TVA initiated a civil calculation program to assess the adequacy of existing civil calculations and to regenerate missing calculations. The staff exten-sively reviewed and inspected this program before Sequoyah Unit 2 restart. The staff concludes that the same program with the additional as-built verification performed for Sequoyah Unit 1 is acceptable for restart.

l 2.3.3 Electrical Calculations  !

2.3.3.1 Introduction 1 The electrical calculation review program is described in Section III.4.1 of 3 l

the SNPP. The TVA electrical calculation review program is divided into two  !

phases. Phase I for each unit is to be completed before plant restart of that unit and covers the essential minimum set of safety related electrical calcula-tions needed for restart. Phase 11 covers the remaining non-safety-related NUREG-1232, Vol. 2, Supp. 1 2-10

c electrical calculations and will be completed after plant restart. The staff notes that TVA has committed to expand and formalize its calculation control program over the long term to cover additional selected electrical calculations beyond the essential minimum set. The staff relies on this commitment as the most effective means to ensure that TVA's electrical calculations required to ensure safety are maintained in the acceptable condition that the present program has established.

The staff evaluated the restart electrical design calculations for Unit 2 in Section 2.3.3 of NUREG-1232, Volume 2. The staff concluded that there was reasonable reassurance that electrical systems are adequate for the safe restart and operation of Unit 2. The staff's conclusion on the general adequacy of the electrical calculation program for Unit 2 did not extend to Unit 1 restart for the following reasons:

(1) A number of calculations do not assume two-unit operation and require l l

upgrading to support Unit 1 operation.

(2) A number of deficiencies identified as required for restart have been completed for Unit 2 but not for Unit 1.

i TVA provided information on the restart electrical design calculations for Unit 1 in its submittals dated August 4(a) and 11, and September 15, 1988.

A number of deficiencies are designated to be corrected after restart and TVA has committed to a number of long-term programs to be undertaken after restart.

These are listed in the various documents cited in Section 2.3.3.1 of NUREG-1232, Volume 2. Expeditious completion of these long-term commitments was assumed in the staff's evaluation of the adequacy of the TVA electrical calculations pro-gram for Unit 1 and Unit 2.

2.3.3.2 Evaluation The staff's evaluation of the calculations for Unit 1 operations will follow '

the format of the evaluation for Unit 2 included in Section 2.3.3.2 of NUREG-1232, Volume 2. <

2.3.3.2.1 Auxiliary Power Systems (APS)

(1) APS Load Analysis and (2) APS Voltage Calculations The staff's evaluation of the auxiliary power system (APS) load analysis for Unit 2 is documented in Sections 2.3.3.2.1 and 2.3.4 of NUREG-1232, Volume 2.

This load analysis was performed on the RADIAL computer code which is documented in Section 2.3.3.2.1 of NUREG-1232, Volume 2.

On August 4, 1988(a), TVA submitted an Electrical Calculations Plan to address l calculations required for the Unit I restart, and on September 15, 1988, However, TVA submitted the results of the APS analysis for the two-unit operation.

this new analysis was performed on a new computer code developed by Sargent & i Lundy Engineers. This code is called Electrical Load Monitoring System for Alternating Current (ELMSAC). TVA's decision to utilize ELMSAC for the Unit 1 restart was based upon TVA's commitment to the following:

NUREG-1232, Vol. 2, Supp. 1 2-11

o standardized calculation methods o use of readily assessable, easily maintained, industry proven, quality assurance (QA) software to produce technically superior calculations The ELMSAC load flow computer code performs APS loading, voltage, and fault 4 current analysis. The calculation for Unit I restart is EEB-SQN-MS-T106-002, Revision 0 (ELMSAC). The input data to ELMSAC comes from a QA load and cable computer database program, the "TVA Electrical Auxiliary System" (TELAS).

In its letter of September 15, 1988, TVA provided a confirmatory analysis to demonstrate that (1) there is no appreciable difference from previously calcu-lated voltages and (2) ELMSAC results are within 3 percent of measured values established by the guidelines in Branch Technical Position PBS-1. This con-firmatory analysis used the Test I configuration listed in the table on page 2-48 of NUREG-1232, Volume 2. This test configuration is based on TVA data of July 12,1980.

Load Analysis The worst-case APS loading was analyzed during full-load operation. The elec-trical power for full-load operation would be supplied from the unit station service transformers and the worst-case fault currents would occur when the APS is supplied from these transformers because of the fault current available from both the main generator and the offsite grid. The analysis has demonstrated that the steady-state maximum loads are within the APS equipment ratings.

Fault Current Analysis The analysis has demonstrated that the transient available symmetrical fault current is less than the Class 1E 6.9-kilovolt shutdown board breaker interrup-ting rating and the asymmetrical fault current is less than the breaker momen-tary (close and latch) rating, when the emergency diesel generators (EDGs) are not paralleled with the grid for testing. When the EDGs are being tested, for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> each month the available symmetrical fault current exceeds the shutdown board breaker interrupting rating by 2 percent. However, since the 2 percent  ;

over the rating only occurs during EDG testing, there is minimal effect in the '

capability of this system to perform its safety function during emergencies.

The analysis has demonstrated that the available symmetrical fault current for the unit board supply breaker is greater than the interrupting rating but within the one-time capability test; and, for the feeder breakers, the symmetrical fault current is greater than the one-time test capability. However, the available asymmetrical fault current is less than all unit board momentary ratings.

Insofar as available fault currents and unit board breaker interrupting ratings and capability, these results are similar to those results evaluated for Unit 2 restart. The staff's evaluation is documented in Section 2.3.3.2.5 of I NUREG-1232, Volume 2.

TVA made a commitment, in a letter dated August 10, 1987, to submit a corrective action plan to resolve the problem of unit board available fault current before NUREG-1232, Vol. 2, Supp. 1 2-12

June 30, 1989. This corrective action plan will ensure that all circuit breakers will always operate within their service capability as defined by appropriate standards and verified by test or manufacturer's guarantees.

Voltage Analysis TVA's APS voltage analysis was performed for two-unit operation, during normal and accident conditions, with electrical offsite power supplied from either the generator or the 161-kilovolt switchyard. During a unit trip, except for a gen-erator fault, the APS continues to receive power from the generator for an addi-tional 30 seconds and then power is transferred from the unit station service transformers (USSTs) to the 161-kilovolt common station service transformers (CSSTs). However, TVA's analysis conservatively considered time zero as the timo of transfer of the unit boards to CSST and includes all initial starting acci-dent loads when the CSST voltage taps are set at -2.5 percent (159 kilovolts).

Both time zero and 5 seconds were analyzed with both units tripping, one unit having an accident and the other at full-load rejection.

The analysis indicated that the unit with a safety injection and containment isolation phase B accident condition will have the following shutdown board voltages:

Shutdown board Bus voltage 1A-A 1B-B 2A-A 2B-B Time zero 6130 6275 6206 6192 Time 5 sec 6648 6694 6623 6656 The ELMSAC calculations of the APS for all plant operating conditions during two-unit operation, indicate that adequate voltage is available to all electrical equipment, during transient and steady-state conditions, with the minimum source J voltages.

Conclusion l The staff concludes that the ELMSAC calculations for the APS are acceptable for i two-unit operation during all plant operating conditions.

(3) Class IE Motor Control Center (MCC) Control Circuit and Cable Length Calculations i

The staff's evaluation of the 480-volt APS voltage for Unit 2 is included in  ;

Section 2.3.3.2.1(3) of NUREG-1232, Volume 2. The staff concluded that the ]

)

Class IE motor control center (MCC) contactor and associated control devices will function properly during low-voltage conditions associated with either the offsite grid or the EDGs.

The evaluation in Section 2.3.3.2.1(3) cf NUREG-1232, Volume 2, is limited to 1 l

Unit 2 operation since the EDG load analysis, on which the analysis of MCC con-trol performance during sequencing depends, assumed Unit 1 was in cold shutdown.

The staff, therefore, concluded that the load analysis and the voltage from it will require recalculation for two-unit operation.

NUREG-1232, Vol. 2, Supp. 1 2-13

The 480-volt ac APS voltage is related to its associated 6.9-kilovolt ac APS. 1 The staff's evaluation of the 6.9-kilovolt ac APS for Unit 1 and Unit 2 opera-

' tion is included in Section 2.3.3.2.1(1) above. The worst-case transient voltage associated with the offsite source occurs after a unit trip concurrent with an accident condition. This low voltage is less than the Class 1E APS degraded grid protective relays setpoint; however, the APS voltage recovers to above the protective relays setpoint after 5 seconds and blocks the 10-second time delay from causing system separation. The degraded grid relays associated with both Unit 1 and Unit 2 provide protection to both the 6.9-kilovolt and 480-volt APS from transient or steady-state low-voltage condition when the power is from off the site. The APS voltage analysis, when supplied power from the onsite EDG, was evaluated by the staff in Section 2.3.3.2.1(4) of NUREG-1232, Volume 2.

The basis for the staff's evaluation was TVA analysis of the worst-case transi-ent EDG voltages. This worst-case transient voltage was determined by TVA from testing conducted on all four EDGs in July 1987. TVA used these test results which were adjusted for the maximum load condition to determine the transient voltage response during the EDG loading sequence. Using data from this transi-ent voltage response, TVA submitted a revised analysis on March 10,.1988 for the 480-volt APS voltage. The analysis evaluated the Unit 2 worst-case actual MCC contactor circuit control wire length and parallel load combination concur-rent with the lowest voltage, resulting from a 6.6-kilovolt motor starting, during EDG loading' sequence. TVA also evaluated the worst case control-circuit maximum current caused by low voltage for control circuit fuse protection coordi-nation. The staff finds that the worst case used by TVA for Unit 2 analysis also applies to Unit 1. Therefore, the conclusion that the Class 1E MCC contactor .

and associated control devices can perform their safety function during transient voltage conditions is applicable to Unit 1 and Unit 2.

(4) Emergency Diesel Generator (EDG) Load Analysis The calculations that represent the performance of the EDG for all plant condi-tions for Unit 2 operation were submitted to the NRC on February 29, March 3, I and March 10, 1988. The staff documented its review of these calculations in l Section 2.2.3.2.1(4) of NUREG-1232, Volume 2. The calculations were based on EDG 28-B which TVA had determined was the most heavily loaded EDG.

i On August 11, 1988, TVA submitted the results of the revised calculations for l two-unit operation. The revised calculation SQN-E3-002, Revision 10, includes all the EDGs in all operating modes for both units.

The EDG 2B-B loading was not increased with both Unit 1 and Unit 2 in operation because no additional loads were applied with the restart of Unit 1. Further review of the EDG 2B-B loading has demonstrated an overall reduction in load demand for this EDG. The additional review has demonstrated that some loads were conservatively assumed at a higher load demand than their actual require-ment and, by letter dated September 28, 1988, TVA submitted a listing of the ,

differences in loading.  !

The steff was able to reconcile the loading differences of EDG 28-B between Revisions 7 and 10 of calculation SQN-E3-002 and found them acceptable.

The staff's evaluation of EDG 2B-B transient and steady-state loading for two- i unit operation indicates that for all plant operating conditions the loading is below the EDG's rating. The EDG 1A-A, IB-B, 2A-A loading requirements are less NUREG-1232, Vol. 2, Supp. 1 2-14

than EDG 2B-B and are, therefore, also acceptable since all the EDGs have the same capacity rating.

The staff concludes that the present EDG load analysis is acceptable for use as the basis for determining the EDG loads for all plant operating conditions.

Further, there is sufficient margin between the worst-case transient and steady-state loading of the EDGs and the manufacturer's ratings to permit TVA to operate Unit 1 or both units at full power.

2.3.3.2.2 Control Power Systems (1) 125-Volt dc Vital Instrument Power System Voltage Calculations The staff's evaluation of the 125-volt de vital power system voitage is included in Section 2.3.3.2.2 of NUREG-1232, Volume 2. On the basis of its evaluation of the 125-volt de voltage calculations, the staff concludes that adequate voltage is available for proper operation, during a loss of ac power, for all four vital de systems associated with Unit 1 and Unit 2.

Employees voiced no specific concerns regarding the de system loads, battery sizing, and battery charger sizing. However, TVA's QA audit prior to mid-1987 indicated that proper documentation of calculations should be made to verify de system loads, adequate sizing of batteries, and adequate sizing of battery chargers. In addition, the same concerns were mentioned in allegations.

TVA analyzed the de power system to determine the adequacy of the 125-volt de vital battery sizing and battery charger sizing for theThis conditions analysisdefined in is included the FSAR and in TVA s Design Criteria SQN-DC-V-11.2.

in calculation SQN-CPS-004, Revision 4. The staff's evaluation is given below.

Vital Batteries The loading for vital battery I was determined by TVA to be the highest and this was used as the basis for the sizing evaluation. TVA used a Sargent &

Lundy validated computer code, " Electrical Load Management System Direct Current" (ELMSDC), for battery sizing. Although vital batteries II, III, and IV have lower load requirements, the batteries are all Gould Type NCX 2100.

Future load could be put on these batteries or lighting loads could be shifted over if necessary from vital battery I.

The staff has reviewed the battery load data and finds the load data comprehen-sive and representative of the de loads associated with this type of facility.

The assumptions used in the analysis appear to be reasonable. The battery sizing included an aging factor of 1.25 and a minimum electrolyte temperature of 60 F.

This battery sizing indicated that there was a 1.1 percent remaining margin for the worst-case station blackout (no alternating current off site or on site) condition.

TVA revised the calculation to include the following:

• Simplify the timing of the switchgear breaker-indicating lights.

• The lighting loads were applied over the total time period.

NUREG-1232, Vol. 2, Supp. 1 2-15

y 1

l o The electrically operated 480 volt breakers were considered clcsed for the accident condition.

o The inverter load was reduced from 17.5 kilovolt-amperes to 15 kilovolt-amperes which is the limit imposed by the FSAR and Inverter Load Calcula-tion SQN-CPS-004. This corrected the last unverified assumption.

e ELMSDC record numbers were revised for many loads due to the addition of multiple load records for switchgear and to simplify load sequence documentation.

Calculation SQN-LPS-004, Revision 6, was approved by TVA on September 26, 1988 and the results of the last revision changes the worst case, station blackout, battery capacity margins from 1.1 percent to 7.7 percent. This is in addition to margins included for 60 F ambient temperature (1.11), battery aging (1.25),

and the load growth margins built into the individual battery loads.

Therefore, the staff concludes that the analysis has demonstrated that the batteries are adequately sized.

Vital Battery Chargers The criteria in the FSAR and design criteria for the battery chargers are:

o Condition 1: The charger output current must provide the continuous load after a 2-hour station blackout and recharge the batteries in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.

o Condition 2: The charger output current must provide the continuous load for an accident condition af ter 30 minutes and recharge the battery in 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.

For condition 1, the battery charger requirement is 112 amperes and for condi-tion 2, the requirement is 85 amperes. Since the battery chargers have been purchased with a rating of 150 amperes, the margin for condition 1 is 25 percent and for condition 2 is 43 percent.

Therefore, the staff concludes that the analysis has demonstrated that the battery chargers are adequately sized.

Conclusions The staff concludes that the ELMSDC calculations for the direct-current systems  ;

are acceptable for all plant operating conditions. Further, the analysis has  !

, demonstrated that the batteries and battery chargers are adequately sized and have sufficient margin between their requirements and their ratings.

In addition, on the basis of the staff's evaluation in Section 2.3.3.2.2(1) in NUREG-1232, Volume 2, on the 125-volt dc voltage calculations, the staff concludes that adequate voltage is available for proper operation of Units 1 and 2 during a loss of ac power and no further corrective action by TVA is required.

l l

NUREG-1232, Vol. 2, Supp. 1 2-16

(2) 120-Volt AC Vital Instrument Power System Voltage Calculations

' This is evaluated in Section 2.3.3.2.3(2) of NUREG-1232, Volume 2. On the basis of its evaluation of the 120-volt ac calculations and TVA's corrective actions which were completed for the restart of Unit 2, the staff concludes that the safety-related 120-volt ac loads powered from the 120-volt ac vital instrument power boards will have adequate voltage for safe operation of Units 1 and 2.

2.3.3.2.3 Instrumentation and Control Systems Instrumentation Accuracy Calculations The staff evaluated the two Sequoyah units in Section 2.3.3.2,3 of NUREG-1232, Volume 2 and concluded that the instrument accuracy calculations for both units were satisfactory.

2.3.3.2.4 Raceway Systems The staff evaluated raceways systems for Units 1 and 2 in Section 2.3.3.2.4 of NUREG-1232, Volume 2 and concluded that TVA's justification for using its ampacity tables and the justification of these tables as applied to control level' cable trays, grouped conduits, and conduits with more than three cables-and duct banks was acceptable. Therefore, the staff concludes that this issue is resolved for the safe operation of Unit 1 and Unit 2.

2.3.3.2.5 Short-Circuit Study--Medium Voltage Systems This is addressed in Section 2.3.3.2.1(3) above. The staff concludes that TVA's corrective action plan will ensure that all circuit breakers will always operate within their service capability as defined by standards and verified by test or manufacturer's guarantees.

2.3.3.2.6 Technical Specification Surveillance Requirements During the safety systems quality evaluation (SSQE) inspection conducted by the staff on the containment spray system, the Class 1E electrical system design was reviewed. This review included surveillance testing of Class IE electric systems, as required by the Technical Specifications (TS). The TS surveillance tests reviewed by the staff are listed in Inspection Report 50-327, 328/88-29 (October 20,1988). The latest tests reviewed were for the emergency diesel I generators (EDGs), EDG batteries, vital station batteries (VSBs), motor control i

center protection thermal overload (TOL) heaters, and containment penetration electrical protection.

l

( The staff's review of these surveillance test procedures indicates that TVA has been improving them with respect to the latest Institute of Electrical and Elec-

tronics Engineers (IEEE) standards. The staff's review of vital battery II capacity test, which was conducted on August 1, 1988, found both the procedure, conduct, and results of the test acceptable. This was also true of the vital battery III service test, which was conducted on August 28, 1988. This test was conducted using the latest load profile from vital battery I which has the highest load requirements.

NUREG-1232, Vol. 2, Supp. 1 2-17

4

. Vital battery V may be used to replace any of the other four vital batteries and

.has the same surveillance requirements for operable status. The staff's review

' of the vital battery V capacity test, which was conducted on May 10,.1988, indi-cates that the battery is.. approaching the end of its life. The Technical Spe-cifications define this battery as showing signs of. degradation since its capa-

. city is 83 percent of the manufacturer's rating and' must be given an annual performance discharge test of battery capacity instead of the normal 60 month interval. The TS require that batteries have at least 82 percent capacity to be considered operable.

TVA considers that vital battery V is operable and may be used in place of the other batteries during maintenance and test activities for one year. The staff agrees with this position because vital battery V was purchased as a 2250 ampere-hour battery and the other four batteries were purchased as 2100 ampere-hour bat-teries. Further, the TS require that 7-day and 90-day surveil-lances be con-ducted concerning individual cell voltage and electrolyte specific gravity. The parameters must also be within limits for the battery to be considered operable.

On this basis, the staff concludes, from the surveillance tests reviewed, that the tests conducted by TVA are adequate to determine the operability of the electrical power systems in the TS.

2.3.3.3 General Conclusions on the Sequoyah Electrical Calculations Program The staff's conclusions on the electrical calculations program for Unit 2 are given in Section 2.3.3.3 of NUREG-1232, Volume 2. The staff concluded the following for Unit 2:

o TVA's analysis includes the essential auxiliary power systems required for safe plant operation.

.o The input data are sufficiently comprehensive and detailed for considera-tion of all modes of plant operation. The calculations assumed worst-case system and plant conditions. The methodology used in these analyses was appropriate for assessing problems in the systems. TVA has stated that it will correct the problems identified in the specific areas before restart.

o TVA's proposed resolutions for each deficiency identified in the electrical 1 l

calculations are acceptable. TVA has committed to implement the proposed j resolutions before restart.

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o The content and format of each system calculation are adequate for documen-tation purposes.

o 1 All documentation of the electrical calculations necessary for restart is '

in place and up to date by computer program for easy manipulation (i.e. ,  !

data are retrievable for maintenance and revision).

Thus, the staff concluded that there is reasonable assurance that the systems addressed will provide safe restart and operation of Sequoyah Unit 2.

On the basis of its review of the electrical calculations program for Unit 1 as {

discussed above, the staff concludes that the above conclusions for Unit 2 l

NUREG-1232, Vol. 2, Supp. 1 2-18

i J

, i I

apply also-.to Unit 1 and that'there is reasonable assurance that the systems .  :

addressed will provide safe restart and operation of Sequoyah Unit 1 and Unit 2.

1 2.3.4 Branch Technical Position PSB The staff's evaluation of Unit 2 against Branch Technical Position (BTP) PSB-1, is given in Section 2.3.4 of NUREG-1232, Volume 2. The staff concluded that i Unit 2' acceptably met the BTP. l 4

p' The staff evaluated Unit 1 against BTP PSB-1 as part of its evaluation of the Unit 1 electrical design calculations. This is discussed in Section 2.3.3 -  ;

above. The staff concluded in Section 2.3.3 that Unit 1 acceptably met  ;

BTP PSB-1.

2.4-AlternatelyAnalyzedPipingandSupports l 2.4.1 Introduction  !

SNPP Section III.5 describes a TVA special program to verify the adequacy'of.

-piping and pipe supports that had been installed and qualified by alternate

' analysis (AA) criteria. TVA's AA criteria use simplified design rules and guidelines to locate supports in lieu of rigorous piping analysis. This is discussed in Section 2.4 of NUREG-1232, Volume 2.

1 TVA is conducting a two phase program to resolve the concerns on the Category I (safety class) AA piping systems.

2.4.2 Evaluation Phase I Scope I

TVA described the Phase I program activities in Section 111.5.2.1 of the SNPP. 1 The scope of the Phase I program includes those systems required to mitigate events addressed in FSAR Chapter 15 and safely shut the plant down. This scope is consistent with the scope of Phase I of the design baseline and verification program. The Phase I review effort involved screening AA piping systems for specific deficiencies that had been identified in TVA s AA program as discussed earlier. The Phase I scope is evaluated in Section 2.4.2 of NUREG-1232, ,

Volume 2.

The staff evaluation of restart program implementation was based on an audit of the Unit 2 program. On the basis of this audit, the staff concluded that TVA had adequately defined and was adequately implementing a program to ensure that safety concerns applicable to plant restart would be identified, evaluated, and resolved before Unit I restart. TVA was unable to provide the basis for the deflection criteria that ensure that pipe supports are rigid. In a letter dated January 28, 1987, TVA stated it will perform an evaluation during the long-term program to justify the adequacy of the criteria. This was acceptable to the staff.

TVA, in a letter dated August 18, 1986, defined a set of interim acceptance criteria for evaluating piping and pipe supports in the restart program. TVA originally defined the proposed interim criteria in terms of exceptions to FSAR

)

NUREG-1232, Vol. 2, Supp. 1 2-19 I

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commitments. . These exceptions and the staff's acceptance of them are listed in Section 2.4.2 of HUREG-1232, Volume 2. In addition, TVA proposed criteria for support evaluations taken from Section 3.8.4 of the current NRC Standard Review Plan (NUREG-0800) and from Subsection NF of Section III of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code. These criteria are not in accordance with the Sequoyah FSAR; nonetheless, the use of these cri-teria on an interim basis to support restart of Sequoyah Unit 1 is acceptable to the staff. However, for the long-term program, TVA should use the criteria that meet the commitments in the FSAR.

Phase II Scope TVA discussed the scope and activities of the Phase II effort in Section 111.5.2.2 of the SNPP. This is evaluated in Section 2.4.2 of NUREG-1232, Volume 2. In Phase II, TVA will evaluate the remaining Category I AA safety class piping systems not required for restart for the areas of concern identi-fied in the Phase I program. In Phase II, TVA also will address instrument lines and their supports. The acceptance criteria for Phase II will be TVA's established design criteria for piping and supports. TVA presented the scope and the schedule for Phase II in a letter dated April 8, 1987(a). In addition to the deficiencies evaluated in the Phase I program, TVA also will address the areas of concern listed below in the Phase II program:

o consideration of thermal flexibility analyses for piping systems with operating temperatures between 120 F and 200 F o

consideration of the interface between AA piping and deadweight supported piping for pipe sizes less than or equal to 2 inches in nominal diameter o

consideration of the effects of long piping runs and large concentrated weights 2.4.3 Conclusions As discussed in Section 2.4.2 of NUREG-1232, Volume 2, the staff concludes that TVA has defined an adequate program for resolving safety concerns applicable to plant restart. On the basis of its audit of sample . design packages and a field inspection of sample Unit 2 piping systems, the staff found that the pro-gram was adequately implemented. The staff concludes that completion of the Phase I program for Units 1 and 2 will provide confidence that sufficient safety margins exist in the design of AA piping / support systems required to mitigate FSAR Chapter 15 events and safely shut the plant down to allow Unit 1 to restart.

2.5 Cable Tray Supports TVA's original design criteria for cable tray supports were developed between 1972 and 1974. Although these design criteria included the effects of earth-quakes, they did not consider the effects of design-basis accidents (DBAs). In j 1975, TVA revised the original design criteria to include the DBA loads, but l the original designs were never reviewed to ensure that they complied with the l revised criteria. This deficiency affected only the cable tray supports I attached to the steel containment vessel; however, other deficiencies found in l

1984 and 1986 dictated a thorough review of the adequacy of all the cable tray l

l NUREG-1232, Vol. 2, Supp. 1 2-20 s l

supports. During that review, TVA discovered that the existing cable tray sup-ports could not satisfy the basic commitments made in the FSAR. At a meeting on July 17 and 18, 1986 (meeting summary issued on July 24,1986), TVA proposed a set of interim acceptance criteria for cable tray supports that were less stringent than those in the FSAR. As a part of its request, TVA also committed to restore the original FSAR criteria for the affected cable tray. supports in an orderly manner after restart.

2.5.1 Interim Acceptance Criteria 2.5.1.1 Evaluation The staff's evaluation of the interim acceptance criteria proposed by TVA is discussed in Section 2.5.1.1 of NUREG-1232, Volume 2. The applicability of the staff's evaluation to Unit 1 is discussed below.

(1) Damping TVA proposed to use a 7 percent critical damping ratio for the cable tray for the safe-shutdown earthquake and design-basis accident (SSE/DBA) loading, instead of the 5-percent damping ratio described in the FSAR. For restart of Unit 1, the 7 percent damping proposed by TVA for DBA/SSE loading is acceptable to the staff.

(2) DBA/SSE Load Combination In the FSAR, TVA committed to using the absolute sum combination of SSE and DBA loading effects. For restart, TVA proposed to use the square-root-of-the-sum-of-the-squares (SRSS) combination for the interim acceptance criteria. The staff finds the SRSS method a reasonable load combination approach for Unit 1 restart and is thus acceptable.

(3) Elimination of 1/2 SSE Load Case In the FSAR, TVA committed to considering the SSE and 1/2 SSE loads. For re-start, TVA proposed to use the SSE loading only for the interim acceptance cri-teria. The proposed elimination of the 1/2 SSE case is acceptable to the staff on an interim basis.

(4) Allowable Stresses

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In the FSAR, TVA makes a commitment that the cable tray support stresses be less than 0.9 times the yield strength for SSE/DBA loading. For restart, TVA proposed to change this requirement to 1.7 times the American Institute of Steel Construction (AISC) allowables for SSE plus DBA loading, and 1.6 times the AISC allowables for the SSE alone. The criteria proposed by TVA for cable tray support calculations are acceptable on an interim basis.

2.5.1.2 Implementation of Interim Criteria The staff's evaluation of the implementation by TVA of the interim criteria is given in Section 2.5.1.2 of NUREG-1232, Volume 2. The applicability of the staff's evaluation to Unit 1 is discussed below.

NUREG-1232, Vol . 2, Supp. I 2-21 l . _ _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ ,

(1) Cable Tray Supports Attached to Steel Containment Vessel The' reevaluation of supports attached to the steel containment vessel was required to resolve Nonconformance Report (NCR) SQNCER 8414. The NCR addressed.

the fact that the cable tray supports on the steel containment vessel were not designed for DBA loadings. The staff concluded that methods used in reevaluat-ing the SCV cable tray supports were adequate and that the interim acceptance criteria w'ere appropriately implemented to qualify the supports for the restart of Unit 1.

(2) Cable Tray Supports on the Reactor Building Shield Wall Many cable trays located in the annulus between the steel containment vessel and the reactor building shield wall are supported from the shield wall. The staff concluded that TVA has demonstrated that each cable-tray support attached to the shield wall had sufficient capacity to meet the interim criteria for the SSE load condition.

(3) All Other Cable Tray Supports There are 2900 cable tray supports in Category I structures (excluding the steel containment building and the reactor building shield wall). Most of these are in the auxiliary building (1700 supports) and the control building (850 supports). The staff concluded that the program conducted by TVA for qualification of these cable tray brackets and supports was adequate and acceptable for Unit 1 restart.

2.5.1.3 Anchoring in Concrete This discussion applies to supports that are anchored in concrete by means of base plates, anchor bolts, and embedded plates. The staff's evaluation is provided in Section 2.5.1.3 of NUREG-1232, Volume 2.

The staff concluded that TVA should use, as a minimum, the original FSAR design criterion requiring a factor of safety of 2.5 for wedge-type anchor bolts and 2.8 for self-drilling anchor bolts as safety factors for the interim period.

As discussed in Section 2.5.1.3 of NUREG-1232, Volume 2, TVA committed to the interim criteria proposed by the staff; therefore, this is acceptable. For the long-term effort, TVA should determine the actual safety factors and evaluate them against the requirements of IE Bulletin 79-02, " Pipe Support Base Plate Designs Using Concrete Expansion Anchor Bolts," March 8, 1979.

2.5.1.4 Base Plate Analysis The staff's evaluation is given in Section 2.5.1.4 of NUREG-1232, Volume 2.

The staff concluded that the modeling and analysis of base plates are acceptable.

2.5.1.5 Concrete The resolution of this issue is discussed in Section 2.6 of this supplement.

NUREG-1232, Vol. 2, Supp. 1 2-22

2.5.1.6 Confirmatory Items The staff identified 10 confirmatory items in Section 2.5.1.6 of NUREG-1232, Volume 2. These items were identified during the NRC audit of September 29 through October 3, 1986, and TVA was required to resolve them before restart of a unit From reviewing the information provided in TVA submittals dated-January 14 and l

February 4, 1987, the staff concluded that TVA had taken proper corrective action for the 10 confirmatory items and that this is acceptable for restart of Unit 1 and Unit 2. TVA conducted a test for the wedge-type anchor bolt in the area of the cracked concrete in accordance with TVA construction specifications and ob-served no degradation of the base plate anchor. On the basis of an engineering judgment, this is considered to be acceptable for restart. However, these items, including the cracked concrete, will be audited following restart of the plant.

-2.5.1.7 Conclusion The staff concluded that the interim acceptance criteria proposed by TVA for Sequoyah Unit 1 and Unit 2 restart, as modified in accordance with this supple-ment, are acceptable for the restart of both units.

2.5.2 Diesel Generator Building Supports Analysis All of the four diesel generators are required for the operation of either unit.

The conclusion,.as discussed in Section 2.5.2 of NUREG-1232, Volume 2, applies to both units. TVA has evaluated all cable tray support calculations in the diesel generator building and the additional diesel generator building for a failure to take the effect of zero period acceleration (ZPA) into account. In those instances in which the originally calculated acceleration was less than the ZPA, the ZPA was applied in the reanalysis. Results of the reanalysis indi-cate that the existing cable tray supports are still able to serve their intended function during a seismic event. Therefore, on the basis of its inspection and its review of the information presented by TVA, the staff finds that no struc-tural modifications are required.

2.5.3 Cable.. Tray Support Base Plate Installations Sixteen base plates (eight per unit) for the cable tray supports in the auxil-iary building were improperly installed because every hole in the base plates was drilled per the engineering drawing with a diameter 3/8 inch larger than i

specified by TVA procedures.

On the basis of its evaluation in Section 2.5.3 of NUREG-1232, Volume 2, the staff concludes that TVA has completed all the necessary corrective actions regarding deficiencies in the base plate installation. As a result, the modi-fied connections are adequate to serve their intended function as required by the design. On this basis and on the basis of its review of Sect. ion III.3 of the SNPP, the staff finds the issue of oversize holes in the base plate has been acceptably resolved for both Unit 1 and Unit 2.

NUREG-1232, Vol. 2, Supp. 1 2-23

2.6 Concrete Quality-

'The TVA evaluation of employee concern IN-85-995-002, related to the adequacy of.the concrete quality at the Watts Bar Nuclear Plant site, prompted the NRC staff to request further evaluations of the in place' strength of the concrete at the Sequoyah site.

On the basis of its evaluation in Section 2.6 of NUREG-1232, Volume 2, the staff concludes that all previous concerns related to adequacy of the structural cri-teria for concrete strength and frequency of sampling and controls and standards for the bedding mortar have been resolved for the restart cf Unit 1.

2.7 Miscellaneous Civil Engineering Issues TVA identified a'need to address the seismic qualification of components in meeting code and regulatory requirements. This effort includes the review of components (piping, pipe supports, cable tray supports, conduit supports, and' heating / ventilating duct supports) as well as structures.Section III.15 of the SNPP addresses miscellaneous civil engineering issues related to Sequoyah.

The staff evaluated TVA's special programs to resolve the miscellaneous civil engineering issues in Section 2.7 of NUREG-1232, Volume 2.

zTVA stated that there were program differences between Unit 1 and Unit 2 in this area; however, the' differences were concerned with TVA's implementation of its program for addressing IE Bulletin 79-14. This is discussed in Section 2.3.2,

" Civil Calculations," in this supplement.

As discussed in Section 2.7 of NUREG-1232, Volume 2, and on the basis of its review of the TVA plans to execute these special programs, the NRC staff finds that with proper implementation of the plans, the miscellaneous civil engineer-ing issues should be fully resolved for Unit 1 and Unit 2.

2.8 Heat Code Traceability i Section III.15.6 of the SNPP describes a TVA commitment to investigate materials i control concerns involving FSAR' commitments, design requirements, and traceabil- )

ity relative to pressure boundary piping components in the Sequoyah safety-related piping systems. j The issue of heat code traceability has been evaluated through the employee concerns' program (element report MC-40703). The staff's evaluation of this issue is discussed in Section 2.8.2 of NUREG-1232, Volume 2.

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In addition, the issue of heat code traceability has been evaluated through the I employee concerns program in element report MC-40705-SQN, " Material Control," '

Revision 4, and in Investigation Report ECP-87-SQ-510-09, " Heat Number Validation for QA Level Structural Steel Materials During the Construction Phase of Sequoyah Nuclear Plant."

The staff concludes that TVA has properly characterized the problems with heat code traceability and has adequately addressed the employee concerns.

NUREG-1232, Vol. 2, Supp. 1 2-24

3 SPECIAL PROGRAMS The Sequoyah Restart Task Force identified a number of technical issues of par-  ;

ticular interest that were to be addressed before the restart of either of the '

Sequoyah units. These issues include major regulatory programs, such as environ-mental qualification of equipment and fire protection, as well as specific tech-nical issues, such as adequacy of electrical cables. The resolution of these issues is discussed in the sections below. In some cases, related employee con-cerns exist; the individual evaluations of the element reports are discussed in Chapter 5.

In its letters dated March 31 and May 9,1988, TVA did not identify any differ-ences between the Unit 1 Sequoyah Nuclear Performance Plan (SNPP) special prog-rams and the Unit 2 programs that resolved the technical issues discussed in this chapter. The staff did conduct an additional inspection on Unit 1 on fire pro-tection. This inspection and the commitments made by TVA to NRC to resolve these special programs discussed below.

3.1 Fire Protection 3.1.1 Introduction Following a staff inspection of July 16-20, 1984, at Watts Bar on compliance with Appendix R to 10 CFR Part 50, the staff issued a confirmatory action letter to TVA on August 10, 1984. This letter identified the actions to be taken by TVA to implement a complete review of the Appendix R program at Sequoyah.

3.1.2 Evaluation 3.1.2.4 Interim Compensatory Fire Protection Measures In accordance with NRC's confirmatory action letter, TVA established roving l firewatches to provide continued surveillance of selected areas in the auxiliary ,

building, the control building, and the turbine building. These firewatches covered areas of the plant that contain cable / safe-shutdown-system interactions that did not meet the requirements of 10 CFR Part 50, Appendix R, Section III.G.

In addition, these roving firewatches were required to cover their assigned areas at least once an hour and to document their actions in accordance with TVA's l Operations Section Administrative Letter 73.

The staff evaluated the Appendix R program at Sequoyah in Section 3.1 of NUREG-1232, Volume 2. This evaluation discusses the deviations requested by TVA from the requirements of Appendix R to 10 CFR Part 50 and the compliance of Sequoyah to Sections III.G, III.J, and III.0 of Appendix R.

Conclusion On the basis of this evaluation, the staff concluded that when the modifications and implementation of the procedural corrective actions associated with TVA's NUREG-1232, Vol. 2, Supp. 1 3-1

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a deviation requests (as identified in the staff's safety evaluations of May 29 t and October 6, 1986) and modifications and procedures (as identified in Inspec- I tion Report 50-327, 328/88-37 [0ctober 28,1988]) are completed, TVA's Appendix R program will provide an acceptable level of fire protection, equal to that re-  !

quired by 10 CFR Part 50, Appendix R, Sections III.G, III.J, III.L, and III.0 for Unit 1.

As a result of a recent inspection (July 25-29,1988), the staff found addi- J tional items that had to be addressed. These are discussed in Section 3.1.2.8 below.

3.1.2.5 Staffing of the Fire Brigade By letter dated June 13, 1988, TVA submitted a description of the reorganized fire brigade at Sequoyah Units 1 and 2. This reorganization is part of an over-all plan to strengthen the fire fighting capabilities at all TVA nuclear plants with professional fire brigade personnel. The new fire brigade organization is in compliance with Sequoyah Technical Specification change 87-44 submitted to NRC by TVA letter dated March 1, 1988. The staff issued this Technical Specifi-cation change by letter dated June 30, 1988.

TVA is committed to meeting the requirements of Appendix A of Branch Technical Position (BTP) ASB 9.5-1 at Sequoyah. The original NRC staff approval of the Sequoyah fire brigade is addressed in Section 9.5, " Fire Protection Systems," V.

" Administrative Controls," of Supplement 1 of the Sequoyah SER that supports the licensing of Sequoyah (NUREG-0011). That SER describes the Sequoyah fire  !

brigade as comprised of at least five members equipped with breathing apparatus, i portable communications equipment, portable lanterns, and other fire fighting equipment. The SER also states that the fire brigade participates in periodic drills and meets the requirements of Appendix A to Branch Technical Position (BTP) ASB 9.5-1, National Fire Protection Association (NFPA) recommendations, and supplemental staff guidelines.

The original fire brigade was staffed by the Assistant Shift Engineer as the fire brigade leader and four operations personnel. The reorganized fire brigade will be controlled by the Assistant Shift Operations Supervisor (formerly Assistant Shift Engineer). The Assistant Shift Operations Supervisor will serve as the Incident Commander but the brigade will be staffed by the brigade leader and four individuals from the onsite Fire Operations Unit. The Incident Commander will respond to all fire emergencies at the plant and will provide the technical knowledge of safe-shutdown systems to determine the effects of fire and fire suppressants on safety-related systems. The Incident Commander will also remain in direct communications with the Shift Operations Supervisor / Emergency Coordination in order to provide any technical information that may be required for the plant operations staff to safely shut down an operating rra 'or. Each duty shift of the Fire Operations Unit is staffed by a Fire Captaia . brigade leader) who has professional fire service experience and four fire optrators. The fire operators have met the minimum standards for ,

certificatico as Firefighter II as defined by NFPA, have had 80 hours9.259259e-4 days <br />0.0222 hours <br />1.322751e-4 weeks <br />3.044e-5 months <br /> of classroom instructions on site-specific fire protection systems as well as

, on-the-job training, emergency health physics training, and emergency medical training.

It is the licensee's position, and the staff agrees, that the reorganized fire brigade meets or exceeds the existing fire brigade commitments and requirements.

NUREG-1232, Vol. 2, Supp. 1 3-2

The licensee has provided a comparison of its fire brigade to the requirements of BTP CMEB 9.5-1 (which the licensee is not committed to). The comparison shows that the reorganized Fire Operations Unit meets the intent of the requirements of BTP CMEB 9.5-1 in Section C.3, " Fire Brigade."

The staff concludes that the reorganized Fire Operations Unit meets the staff guidance in Appendix A of BTP APCSB 9.5-1, in regard to the staffing, training, and equipping of the plant fire brigade, and is acceptable.

3.1.2.6 Fire Pump Design Deficiency TVA identified a design deficiency on April 14, 1987 which could cause Class 1E electrical components to operate outside of their design limits during a postu-lated loss-of-coolant accident (LOCA). TVA reported the design deficiency to NRC in accordance with the requirements of 10 CFR 50.73 on August 18, 1987 in Unit 1 Licensee Event Report (LER)87-042.

The design basis of the plant does not provide for a LOCA condition concurrent with a fire. This occurrence would be considered a low probability event.

However, TVA identified the potential of the fire pumps starting automatically as the result of a LOCA condition. TVA's electrical analysis of the Class 1E electrical system also identified that the fire pump starting and running during a LOCA condition resulted in degraded voltage of the Class 1E electric auxiliary systems. Further, if power is supplied from the standby emergency diesel generators (EDGs) these EDGs could also be overloaded.

There are two fire pumps associated with each Sequoyah unit. The pump motors are supplied electrical power from their respective redundant Class 1E electrical auxiliary systems. The pumps of each unit discharge into their respective headers. The headers from each unit are interconnected by a normally open isolation valve.

The fire pump control logic was designed to provide an automatic start from the fire protection heat sensors within the containment. The heat sensor actuation design setpaint temperature was specified as 220 F. The containment temperature during a LOCA can exceed 240 F, causing the fire pumps to start. The starting of the fire pumps during a LOCA condition would result in the degradation of the Class 1E electrical auxiliary power system.

TVA took a short-term corrective action to prevent problems during the Unit 2 restart by placing the Unit 2 fire pump control switches in the lockout position.

This operation would prevent the automatic start of the fire pumps associated with Unit 2 should there be a Unit 2 LOCA. The Unit 1 fire pumps would be available, if needed, to serve both units.

TVA's long-term corrective action before Unit 1 startup involves modification of all fire pump start logic. This modification blocks the automatic start of Unit 1 fire pumps 1A and 1B during a Unit 1 LOCA condition. Similarly, the Unit 2 fire pumps 2A and 2B would also be modified to prevent their automatic start during a Unit 2 LOCA condition.

1 On the basis of its review, the staff concludes that the modification proposed by TVA to correct the design deficiency is acceptable. The staff reviewed the NUREG-1232, Vol. 2, Supp. 1 3-3

1 electrical calculations for two-unit operations to verify.that' automatic start- i ing of the fire pumps concurrent with other unit operating conditions does not cause degrading of the Class 1E auxiliary electrical systems. {

This review is discussed in Section 2.3.3 above.

3.1.2.7 Fire Protection Calculations, Revision 9 i By letter dated June 10, 1988, TVA submitted Revision 9 of the Sequoyah Appen-dix R shutdown logic calculations. TVA stated that the Unit 2 plant configura-I

' tion and associated Appendix R documentation reflect this revision to the calcul-ations except where interim compensatory measures exist. TVA explained that Unit 1 is in a verification process and any modifications identified during this l process will be completed before Unit I restart except where interim compensatory measures exist.

The staff conducted an inspection between July 25 and'29,1988. The inspection team reviewed Revision 9 of these shutdown logic. calculations. Its evaluation is given in Inspection Report 50-327, 328/88-37 which was issued on October 28, 1988.

3.1.2.8 Inspection The Unit 1 fire protection program was inspected between July 25 and 29,1988.

The details of the inspection and the conclusions of the staff were issued in Inspection Report 50-327, 328/88-37 on October 28, 1988. Unresolved items from the inspection report remaining at this time are:

(1) Unresolved Item (50-327, 328/88-37-01). Failure to meet the requirements of 10 CFR Part 50, Appendix R, Section III.G.3 with regard to maintaining one 'j train of hot standby systems free of fire damage because high impedance faults were not addressed in the associated circuits analysis. This was not a Sequoyah Unit I restart item.

(2) Inspector Followup Item (50-327, 328/88-87-02). The requirements of 10 CFR l Part 50, Appendix R,Section III.G.2 with respect to separation of cables I associated with the volume control tank and charging pump B will not be met until completion of certain modifications. This was not a Sequoyah Unit 1 restart item.

3.1.2.9 Deviation From 10 CFR Part 50 Appendix R On October 13, 1988, TVA requested a temporary deviation from the requirements of 10 CFR Part 50, Appendix R, Section III.G.2. This was requested because TVA discovered that the vital battery board rooms had fixed manual fire suppression rather than automatic suppression. Automatic suppression is required by the ,

fire resistance of the cable wrap around the redundant trains passing through the rooms. The licensee requested relief from these requirements until the Unit 1, Cycle 4 refueling outage. As a compensatory measure, an hourly fire watch will be provided until the rooms are in conformance with the regulation.

The staff safety evaluation approving the deviation was enclosed in a letter to TVA dated November 4, 1988(b).

NUREG-1232, Vol. 2, Supp. 1 3-4

3.1.3 Conclusion The staff has evaluated the Sequoyah fire protection as discussed above. The staff issued its evaluation of Revision 9 of the Sequoyah Appendix R shutdown logic in Inspection Report 50-327, 328/88-37 (October 28,1988).

3.2 Environmental Qualification of Electric Equipment Important to Safety 3.2.1 Compliance With 10 CFR 50.49 3.2.1.1 Introduction A licensee must demonstrate that equipment used to perform a necessary safety function is capable of maintaining functional operability under all service con-ditions postulated to occur during its installed life for the time it is required to operate. This requirement is applicable to equipment located inside as well as outside the containment. More detailed requirements and guidance relating to the methods and procedures for demonstrating this electrical equipment capa-bility are in 10 CFR 50.49, " Environmental Qualification of Electric Equipment l Important to Safety for Nuclear Power Plants"; in NUREG-0588, " Interim Staff Position on Environmental Qualification on Safety-Related Electrical Equipment" (which supplements Institute of Electrical and Electronics Engineers (IEEE)

Standard 323 and various NRC regulatory guides and industry standards); and  !

l

" Guidelines for Evaluating Environmental Qualification of Class 1E Electrical Equipment in Supply Operating Reactors" (Division of Operating Reactors (DOR)

Guidelines) (Enclosure 4 to IE Bulletin 79-01B issued on January 14,1980).

3.2.1.2 Evaluation Evaluation of Compliance With 10 CFR 50.49 The staff evaluation of the compliance of Sequoyah to requirements in 10 CFR ,

50.49 on environmental qualification is in Section 3.2 of NUREG-1232, Volume 2.

In this evaluation, the staff concluded that the methodology being used by TVA for identifying equipment within the scope of 10 CFR 50.49(b)(1), (b)(2), and (b)(3) is acceptable because it provides reasonable assurance that equipment within the scope of 10 CFR 50.49 has been identified.

With regard to 10 CFR 50.49(b)(3), TVA evaluated existing system arrangements and identified equipment for the variables defined in Regulatory Guide (RG) 1.97, Revision 2. TVA has submitted a report outlining the results of the review and Because the review is not complete, some of the schedules for modifications.

equipment items jointly within the scope of NUREG-0737 and RG 1.97 have not been included in the 10 CFR 50.49 scope. When the RG 1.97 report and equipment lists contained therein are in final form and have been accepted by the staff, appropriate equipment not already in the 10 CFR 50.49 scope will be added in accordance with the RG 1.97 implementation schedule.

TVA completed environmental qualification of the applicable final safety analy-sis report (FSAR) Class 1E-designed instrumentation and the FSAR postaccident monitoring (PAM) instrumentation before Unit 1 restart. For those instruments already added to the plant because of a commitment to meet post-TMI requirements (NUREG-0578 and -0737), TVA will complete its environmental qualification in NUREG-1232, Vol. 2, Supp. 1 3-5

accordance with its responses to those NUREG reports or any extension granted with respect to those responses.

For instrumentation that is not considered operable or not installed but that will be completed by startup from the Unit 1, Cycle 4 refueling outage in accord-ance with the implementation schedule for RG 1.97 or post-TMI NUREG reports, environmental qualification will be complete when the equipment is installed and operable. For instrumentation that exists at the plants but that was not included in the original PAM instrumentation set but that will be Category 1 or 2 RG 1.97 instrumentation, TVA will complete environmental qualification in ac-cordance with the implementation schedule for RG 1.97.

3.2.1.3 Conclusions On the basis of its evaluation in NUREG-1232, Volume 2, the staff has reached the following conclusions with regard to the qualification of electric equipment important to safety within the scope of 10 CFR 50.49:

(1) The Sequoyah electrical equipment environmental qualification program complies with the requirements of 10 CFR 50.49.

(2) TVA's proposed resolutions for each of the environmental qualification deficiencies identified in the staff's SER and the Franklin Research Center's technical evaluation report are acceptable.

The staff's findings regarding compliance with 10 CFR 50.49 relied on the completion of certain modifications and replacements that had to be completed in order for the affected equipment to be qualified. In letters dated March 24, 1987(b) and November 2,1988, TVA certified that the required modifications /

replacements were completed and that Sequoyah Unit I was in compliance with 10 CFR 50.49. On the Lests of h staff's evaluation and TVA's certification, the staff concludes ?. hat the issue of environmental qualification at Sequoyah Unit 1 is satisfactorily resolved.

1 3.2.2 Superheat Transient (Main Steam Temperature Issue) )

TVA designed Sequoyah to withstand an unisolable break in a main steam line either inside containment or in the main steam valve vaults (MSVVs) located outside the containment. As part of this design, the electrical equipment used i during this accident would be required to operate in the high temperatures i generated by such a line break. After the plant was completed, Westinghouse changed the information on which the design was based. This ;esulted in in-creased accident peak temperatures in the containment vessel and in the valve vaults. As a consequence, the design of the equipment located in these areas required reevaluation. This issue is discussed in Section III.6 of the SNPP and involves the main steam line break (MSLB) in the MSVVs and inside the containment.

3.2.2.1 Main Steam Line Break in Main Steam Valve Vaults This issue is evaluated by the staff in Section 3.2.2 of NUREG-1232, Volume 2.

The staff concluded for Sequoyah Unit 1 and Unit 2 that this issue for the MSLB in the MSVVs was resolved.

NUREG-1232, Vol. 2, Supp. 1 3-6

3.2.2.2. Main Steam Line. Break Inside the Containment The staff's conclusion that the containment temperature profile for the design-basis MSLB.inside the containment is acceptable contingent on the verification that the analysis contained:in Westinghouse reports WCAP-10986 and -10988 is accurate. The staff is reviewing these reports on a generic basis and'the .l results of the generic review will be addressed separately. TVA submitted in-1 E

formation to the staff in its letters dated November 20, 1987 and February 10(a),

June 1, August 31, and September 22, 1988.

~

3.3 Piece Parts Qualification (Procurement) 3.3.1 Introduction  !

TVA Nuclear Safety Review Staff (NSRS) reports R-84-17-NPS and R-85-07-NPS iden-tified deficiencies in TVA's practices for the procurement of safety-related replacement items. NRC Inspection Report 50-327, 328/86-61, dated November 14, ,

1986, cited related deficiencies which were classified as a potential enforce-  :

ment item (50-327, 328/86-61-01) for failure to take corrective action. Specifi-cally, the TVA program could allow previously qualified equipment to be degraded by purchasing replacement components and parts as commercial grade, without.docu- I mentation of its qualification and without adequate dedication of the items by TVA. This is discussed'in Section III.12.0 of the SNPP, Revision 1.

3.3.2 Evaluation TVA has established the Sequoyah Replacement Items Project (RIP). Through its RIP, TVA will establish a maintenance history of. plant replacement activities by reviewing maintenance requests, preventive maintenance activities, surveil-lance instructions, and work plans. TVA's Division of Nuclear Engineering will perform a documented engineering review and evaluation to establish the suitability of replacement items for the intended application.

TVA responded to the staff's concern by letters dated April 1(b) and December 8, 1987 and provided a long-term program plan by letter dated February 10,1988(b).

The staff evaluated the RIP in Section 3.3 of NUREG-1232, Volume 2 and concluded that this process was sufficient to support plant restart of Unit 2. i The staff has reviewed TVA's supplemental program plan to the RIP which was submitted as an enclosure to TVA's letter to the NRC dated February 10, 1988(b).

This supplements the original RIP program plan which was submitted to the NRC on April 1, 1987(b) and addresses TVA's commitment to provide a supplemental RIP program plan in TVA's letter dated December 8,1987. TVA submitted the implementation schedule for the supplemental program plan in a letter to NRC i J

dated August 10, 1988.

The original program plan provided for TVA's review and evaluation for adequacy of qualification, all installed replacement items within the scope of 10 CFR 50.49 and seismically sensitive replacement items within the boundary of Sequoyah Unit 2 pre-restart phase of the design baseline and verification pro- ,

gram (DBVP). All other Unit 2 installed safety-related replacement items were to be reviewed and evaluated after restart. The original program further I

NUREG-1232, Vol. 2, Supp. 1 3-7

provided for similar reviews and evaluations to be performed on Unit 1 with the same pre-restart and post-restart scheduling restrictions. The pre-restart reviews and evaluations were performed for Unit 2 as required.

The supplemental program changes the original program to allow for the substitu-tion of a warehouse inventory review and evaluation of safety-related replace-ment items for adequacy of. qualification instead of performing the reviews 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 provides.for review of deficiencies identified during the Unit 2 '

pre-restart efforts and the warehouse inventory efforts relative to the need l for corrective action on replacement items installed in the plant. TVA provided justifications for the proposed changes in the supplemental program plan and the cover letter transmitting the plan.

i The staff reviewed and evaluated the supplemental program plan and its schedule i for the following: (1) differences between the original program plan and the.

supplemental plan; (2) adequacy of TVA's justifications for the program changes; 4 and (3) adequacy, relative to restart of Unit 1, of TVA's actions toward the resolution of Unresolved Items (URIs) 50-327/87-40-01 from NRC Inspection Report 50-327, 328/87-40 dated November 30, 1987. Additionally, the supplemental plan

, was evaluated to determine if it provided an adequate level of confidence that l Unit 1 could be operated safely.

3.3.3 Conclusion On the basis of the staff's reviews and evaluations, the staff finds that, with proper implementation'of the supplemental program plan, this special issue (including actions toward resolution of the URI) is satisfactorily resolved for the restart of Unit 1.

3.4 Sensing Line Issues Issues were raised through the employee concerns program concerning the instru-ment line slope, compression fittings, and teflon tape. The staff evaluated these issues in Section 3.4 of NUREG-1232, Volume 2. TVA did not identify any differences between the Unit 1 program and the Unit 2 program.

On the basis of its evaluation in NUREG-1232, Volume 2, the staff finds that these issues are adequateiy resolved for the restart of Sequoyah Unit 1 and Unit 2.

As a long-term action, corporate guidance on the use of teflon tape and a single-defined tape replacement plan will be issued.

3.5 Welding 3.5.1 Introduction In Section III.8 of the SNPP, TVA discusses the welding project program to evaluate the adequacy of the TVA welding program for all of the TVA plants and the suitability of welded structures and systems for service. In addition, approximately 30 percent of the safety-related employee concerns pertain to various aspects of the TVA welding program.

NUREG-1232, Vol. 2, Supp. 1 3-8

I By letter dated January 17, 1986, TVA formally submitted for staff review its program plan to address employee concerns related to welding. TVA formulated its program to evaluate the welding program at each TVA nuclear power plant in two separate work phases. The Phase I effort consisted of a review of the writ-ten TVA welding program (design documents, policies, and procedures) to ensure that the welding program correctly reflects TVA's licensing commitments and regu-latory requirements. The Phase II effort consisted of actual reinspection of selected welds and the inspection results were used to evaluate the implementa-tion of the written welding program. In both phases of the program plan, TVA was to identify and categorize any deficiencies in the existing program, correct the problems, and implement changes to prevent recurrence.

3.5.2 Evaluation The staff evaluated the TVA welding program for Sequoyah in Section 3.5 of NUREG-1232, Volume 2. TVA did not identify any differences between the Unit 1 program and the Unit 2 program.

TVA committed to standardize among all nuclear plant sites the means of main-taining welder qualifications. This will be done by having the quality control (QC) inspector or the welder foreman initial the welder's rod issue slip indi-cating that the welder has maintained qualification by using the process.

Section III.3 of TVA's revised SNPP provides an action plan that will improve the design control program for Sequoyah when implemented. This plan includes the reconciliation of "as constructed" and "as designed" drawings to achieve a single set of plant drawings. This plan should address the irregularities identified above to ensure that the welds and welding requirements stated on the as-designed drawings match the installed hardware.

3.5.3 Conclusions On the basis of its evaluation in NUREG-1232, Volume 2, the staff concluded the following for Unit 1 and Unit 2:

(1) During construction of both Sequoyah units, TVA's implementation of the QA/QC program in the area of welding, while generally etfective, was ineffective in certain instances. For example, a significant number of deficient welds were found that required engineering calculations to demonstrate their suitability for service. These calculations should have been performed during construction. In addition, discrepancies were identi-fied between the design drawings and the actual hardware installed. Not-withstanding these findings, the fact that no welds required repair to meet design code requirements indicates an overall effective implementation of the QA/QC program in the area of welding.

(2) The effectiveness of TVA's process for QC inspector training and qualification / certification to visually inspect welds during plant con-struction and after operation is questionable. The welding deficiencies discussed above should have been detected and corrective actions should have been taken.

NUREG-1232, Vol. 2, Supp. 1 3-9 L - - - - - - - - - - - - - - - - - - - - .

i (3) Despite the deficiencies found in the implementation of the QA/QC program for welding activities, including some that were of a programmatic nature, the staff finds that these deficiencies have not significantly affected the suitability of plant hardware for service.

(4) With the' exception of QC inspectors' training and qualification /certif-ication, the staff finds that other essential elements (i.e., welding- ,i procedures, welder qualification and training, weld design and configu-ration, and filler metal control) of a sound welding program were func-l tioning and the resultant hardware is suitable for service.

Therefore, the staff concludes that TVA's welding reevaluation program has l been carried out adequately and that TVA has demonstrated that the hardware as constructed is suitable for service; that is, the design load limits for welded connections have been met. The staff further concludes that restart of both ,

Sequoyah units will not endanger the public health and safety.

l t

For an overall improvement of the welding program at Sequoyah, the staff endorses 1 the following changes that TVA has proposed in its internal control documents 4 contained in the SNPP:

(1) Combine the requirements of General Construction Document G-29 and Process Specification N73M2 into a single document.

4 (2) Replace the general construction specification for each unit with specific specifications.

(3) Maintain indirect quality control of fitup inspection by monitoring proc-esses as provided in 10 CFR Part 50, Appendix B: (1) by having the welder l and his foreman document that fitup is suitable for the QC inspector to l verify weld size during final inspection and (2) by having the QC inspector

selectively inspect a sample of fitups to verify this documentation.

(4) Consolidate inspector training and certification into one program under the control of a certified Level III non-destructive examination (NDE) examiner.

l l (5) Provide training or orientation to engineers, designers, technical super-visors, and engineering managers of the content and use of the internal control documents.

(6) Standardize the process of maintaining welder's certification by having the QC inspector or welder foreman initial the rod issue slip indicating that the specific welder has used the process.

In a letter dated January 30, 1987, TVA committed to an augmented and acceler-ated inservice inspection as recommended by NRC staff. The inspection program will include the elements listed below.

(1) A 100 percent examination of the American Society of Mechanical Engineers (ASME) Class 1 and 2 piping field welds will be completed in the first 10 year in-service interval. Those welds that remain to be examined will be scheduled for examination in the next two consecutive refueling outages following the submittal of the revised plan and the restart of any unit.

NUREG-1232, Vol. 2, Supp. 1 3-10 l

l (2) A 100 percent examination of the ASME Class 1 and 2 pipe support field welds will be completed in the first 10 year in-service interval. Those welds that remain to be examined will be scheduled for examination in the next two consecutive refueling outages following the submittal of the revised plan and the restart of any unit.

(3) Major component support welds made in the field on the reactor vessel, steam generator, pressurizer, and reactor coolant pumps that have been identified to be examined in the first 10 year program will be examined.

Those welds that remain to be examined will be scheduled for examination in the next two consecutive refueling outages following the submittal of the revised program and the restart of any unit.

(4) Where possible, the percentage of welds examined during the program will be maintained as required by the ASME Code in Tables IWB-2412-1 and IWC-2412-1 (Inspection Program B). Note that the required percentages may at be met for all categories of specific systems or item numbers, because cer-tain systems contain a large number of socket welds that are field welds and the majority of pipe support welds are also field welds. Where con-flicts arise with the percentage requirements, the revised augmented /

accelerated program will identify specific requirements for relief.

Credit for program examination will be taken for all examinations performed and no additional Class 1 and 2 field welds will have to be reexamined in the re-maining time of the first 10 year interval, with the exception of the ASME Code-l- required additional examinations resulting from unacceptable indications in the l initial or required successive examinations. Future 10 year interval examina-tions will follow their original schedule and will not be required to meet the l accelerated program. I Because the first refueling outage is scheduled to occur approximately 4 to 6 months after restart of Unit 2, the short duration of the operating time may not provide the needed time for the increased planning and scheduling staffing and craft support required to perform the increased inspections of items (1), l (2), and (3) above. In this case, the implementation of any accelerated program l would be deferred to the second and third outages following restart of Unit 2.

Scheduling parts of the actual inservice inspection for Unit 2 for the second and third refueling outage after restart rather than the first and second '

refueling outage after restart is acceptable to staff.

Further, the staff recommends that TVA consider the following:

(1) using industry generated standards where possible, particularly using American Welding Society (AWS) standards for certifying the AWS scopt weld inspectors (2) amending relevant FSAR sections to reflect changes in commitments and to formalize the intent as stated above (3) training personnel in the application of the standards adopted The augmented and accelerated inservice inspection program for Unit 2 was submitted by TVA in its letter dated November 9, 1988. TVA committed to submit NUREG-1232, Vol. 2, Supp. 1 3-11

the accelerated field weld program for Unit 1 within six months after the  ;

restart of Unit 1.

3.6 Containment Isolation i 3.6.1 Containment Isolation System Design General Design Criteria (GDC) 54 through 57 of Appendix A to 10 CFR Part 50 contain NRC design requirements for isolation of piping systems that penetrate the containment. In particular, GDC 54 contains general provisions for leak detection, redundancy, and reliability. GDC 55 requires each line that is part of the reactor coolant pressure boundary (RCPB) and that penetrates the contain-ment to have isolation valves as listed below, unless it can be demonstrated that the provisions for a specific class of lines are acceptable on some other defined basis.

The staff identified apparent discrepancies in system compliance with contain-ment isolation requirements during an inspection conducted at Sequoyah on March 3-14, 1986. Specifically, Inspection Report 50-327, 328/86-20 documents five containment penetrations of the chemical and volume control system (CVCS) that did not appear to meet 10 CFR Part 50, Appendix A general design criteria for containment isolation. >

TVA. submitted, by letters dated January 23 and February 3, 1987, requests for exemption to the requirements of GDC 55 and 56 for the penetrations in question.

TVA submitted supplemental information to these requests on April 8, 1987(b).

In its evaluation in Section 3.6.1 of NUREG-1232, Volume 2, the staff discusses each penetration not meeting the explicit GDC requirements as identified by TVA l in Table 2.2 of its submittal of January 2,1987. The discussion includes the I exemptions requested by TVA and granted by the staff for the Sequoyah contain-ment isolation design from the requirements in GDC 54 through 57 of Appendix A to 10 CFR Part 50.

The staff normally requires that all power-operated containment isolation valves have position indication in the main control room. TVA recently con-firmed that with the exception of 22 valves, all other power-operated valves have position indication in the main control room. Position indication for the 22 exceptions are provided in either the auxiliary building or the hot sample room. Installation of position indication for the 22 containment isolation valves in the main control room is planned for the Cycle 4 refueling outage. l t

On the basis of its evaluation, the staff concludes that, with the approved '

exemptions, the Sequoyah containment isolation design is in accordance with Appendix A to 10 CFR Part 50 and, therefore, it is acceptable. {

3.6.2 Containment Isolation Leakage Testing Program i Inspection Report 50-327, 328/86-20 contained open items regarding the contain-ment isolation design for certain containment penetrations. By letters dated  !

September 24, 1986 and January 2,1987, TVA proposed to partly resolve these open items by redesignating certain valves as containment isolation valves. i NUREG-1232, Vol. 2, Supp. 1 3-12

The acceptability of these proposals is addressed above. TVA also has evaluated the redesignated containment isolation valves in regard to the requirements of Appendix J to 10 CFR Part 50 concerning local leakage rate testing. The staff's review of this issue _is documented in Section 3.6.2 of NUREG-1232, Volume 2.

By letters dated July 11 and August 8, 1988, TVA requested an exemption to Appen-dix J for leak rate testing the check valves of the containment spray system (CSS) and residual heat removal spray system (RHRSS) for Sequoyah Unit 1 and Unit 2, which are containment isolation valves. Definition H in Appendix J pro-vides the criteria for a containment isolation valve to be type-C tested. The CSS and RHRSS meet criteriop 3 where the system is required to operate intermit-tently under post-accident conditions. The Sequoyah design for the CSS and RHRSS relied on a check valve inside the containment and a manual valve with seal water system outside the containment to satisfy the requirements of GDC 56. This design is such that TVA has stated that it is impractical to test the inboard check valves; therefore, TVA has requested an exemption from the Appendix J leak rate testing requirements for these check valves. TVA proposed to rely on the remote manual valve and seal water system and the closed CSS and RHRSS outside the con-tainment vessel as the basis for not testing the leak rate of the check valves to Appendix J requirements. The staff issued this exemption in its letter dated September 22, 1988.

On the basis of the evaluation in NUREG-1232, Volume 2, the staff finds that with the above exemption, the proposed local leakage rate testing program for penetrations is in accordance with the requirements of Appendix J to 10 CFR Part 50, and is, therefore, acceptable for Unit i and Unit 2.

3.6.3 Containment Leakage Testing The staff requested that TVA visually inspect the Sequoyah Unit 1 containment vessel before restart of the unit. The purpose of the visual inspection is to demonstrate that the containment vessel was not accidentally damaged during the extended outage since the last integrated leak rate test of the containment vessel in December 1985.

TVA has reported that since the plant shut down approximately 3 years ago, there has been no additional loading on the containment vessel. Although there has been no containment loading during the shutdown period, major modifications have been performed inside the containment vessel which increase the likelihood of accidental damage to the containment vessel. Actual experience with other util-ities has demonstrated that containment liners have been accidentally damaged during shutdown intervals much shorter than 3 years.

TVA has audited the work orders performed during the shutdown interval to demon-strate that proper controls were in effect to prevent damage to the containment vessel. However, such audits would only reveal accidental damage to the contain-ment if it was reported. Unreported damage to the containment vessel would not be identified by such audit.

A visual inspection of the containment vessel should identify any accidental damage, both reported and unreported, that may have occurred during the 3 year shutdown interval. By letter dated August 19, 1988, TVA committed to visually inspect the containment vessel under Surveillance Instruction (SI) 254, before restart.

NUREG-1232, Vol. 2, Supp. 1 3-13

3.7 Containment Coatings TVA identified deficiencies found during a review of maintenance records relating to its programs for coatings inside the containment vessel. These deficiencies are listed in Section 3.7 of NUREG-1232, Volume 2. TVA did not identify any differences between the Unit 1 program and the Unit 2 program.

After a LOCA or an MSLB, water from the containment sump is used for makeup to the core and for containment spray. The sump has a 6-inch trash curb around the base with 1/4-inch wire mesh screens that slope upward and outward from the sump to prevent debris from entering. Failure of coatings during a LOCA or an MSLB could lead to blockage of sump screens, thus an inadequate recirculation flow to the core or blockage of spray systems.

TVA's corrective actions were evaluated in Section 3.7 of NUREG-1232, Volume 2.

The staff concluded that a sufficient area of the sump screen would remain unblocked following an MSLB or a LOCA to allow the containment spray and RHR pumps to operate safely. Therefore, the containment coatings issue is con-sidered resolved for both Sequoyah Unit 1 and Unit 2.

3.8 Moderate-Energy Line Breaks In Section III.15.2 of the SNPP, TVA identified the actions it would take before restart of Sequoyah Unit 1 and Unit 2 to correct the moderate-energy line break (MELB) flooding issue. The staff's evaluation is documented in Section 3.8 of NUREG-1232, Volume 2. TVA did not identify any differences between the Unit 1 program and the Unit 2 program.

On the basis of its evaluation in NUREG-1232, Volume 2, the staff accepted TVA's procedures and assumptions for evaluating MELB flooding. The staff further ac-capted TVA's commitment to complete the actions listed below before restart of Unit 1.

(1) Ensure adequate sealing between the turbine building, the control building, and the auxiliary building.

(2) Provide administrative control for possible flooding in the annulus.

(3) Verify that the electrical equipment and electrical boards on the 734-foot and 749-foot level are above MELB flood levels.

(4) Update the previous review of unimplemented engineering change notices (ECNs) to determine if subsequent ECNs affect the flooding evaluation.

The staff concludes that completion of these actions will be sufficient for restart of Unit 1. However as a post-restart action, the staff recommends that TVA be able to demonstrate quick response to MELBs in safety-related areas.

3.9 ECCS Water loss Outside Crane Wall / Air Return Fan Operability By letter dated July 8, 1987, and as supplemented August 4, 1987, TVA identi-fied a condition involving the collection of water from the containment and residual heat removal sprays following a design-basis accident (DBA). Spray NUREG-1232, Vol. 2, Supp. 1 3-14

water collecting on the operating deck floor could drain directly into areas outside the crane wall through the opening for the containment air return fan <

A-A. The concerns.were that this drainage could result in undesirable low water levels above the sump and in flooding of the air return fan A-A.

The staff's evaluation of TVA's actions, including modifications, to resolve this issue are in Section'3.9 of NUREG-1232, Volume 2.

All efforts associated with the curb and drain modifications have been completed on Unit 2; those modifications for Unit I will be completed before restart.

On the basis of its evaluation in NUREG-1232, Volume 2, the staff concluded that the redesign of the containment drainage system will ensure that spray water will not damage the air return fans or bypass the sump; therefore, the design is acceptable for Unit 1 and Unit 2.

3.10 Platform Thermal Growth In its preliminary evaluation dated March 25, 1988, the staff approved TVA's j plan for the resolution of the structural thermal growth issue as described in l Section III.15.5 of the SNPP. The staff has completed a review of the details of TVA's resolution of the issues that include better calculations, generic implications, and other effects of the corrective action. The staff's evalua-  ;

tion is in Section 3.10 of NUREG-1232, Volume 2. TVA did not identify any dif-ferences between the Unit 1 program and the Unit 2 program.

TVA contracted with Bechtel North American Power Corporation to review the  ;

corrective action plan; Bechtel recommended several additional items. TVA l provided supplemental information on this issue in its letter of February 29, 1988. The recommendations consisted of additional calculations for design justification and modification of come structures and their supports. Examples of reviews the staff will perform include structures within the main steamline valve vault rooms as well as snubbers within the reactor building. Using the '

staff-approved restart criteria, TVA has determined that these modifications may be completed after restart of Sequoyah Unit 1 and Unit 2.

On the basis of the discussion in Section 3.10 of NUREG-1232, Volume 2, as well l as its previous review of SNPP Section III.15.5, the staff concludes that the i issue of the structural thermal growth has been adequately addressed by TVA for Unit 1 and Unit 2. i 3.11 Pipe Wall Thinning Assessment 3.11.1 Introduction On December 9,1986, Unit 2 at the Surry Power Station experienced a catastro- l phic failure of a main feedwater pipe, caused by wall thinning due to erosion /

corrosion in a carbon steel pipe elbow. Erosion / corrosion is a form of flow-assisted corrosion. Although pipe failures due to erosion / corrosion have oc-curred in piping containing a water-steam (two phase) mixture and pipe failures due to erosion have occurred in water systems containing solids, there have been few, if any, previously reported failures in large-diameter carbon steel piping l

systems containing high purity water (single phase); thus, TVA and the industry i

l NUREG-1232, Vol. 2, Supp. 1 3-15 l . _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

.in general had not established a program for the systematic examination of the thickness of.the walls of the feedwater and condensate piping.

3.11.2 Evaluation The staff's evaluation of TVA's response to the Surry 2 incident is based on the SNPP and the TVA's response of September 18, 1987, to NRC Bulletin 87-01, " Thin-ning of Pipe Walls in Nuclear Power Plants," which is being evaluated separately.

TVA's response included the results of its tests and inspections of piping. TVA selected areas susceptible to erosion / corrosion based on base metal composition, flow velocity, pressure differentials, unusual flowpath or geometry, and operat-ing temperature. Inspection was by visual and ultrasonic testing (UT) methods.

.The five susceptible systems are listed below.

I

• condensate (single phase)-

!

• feedwater (single phase)

• extraction steam (two phase)

• heater drains and vent lines (two phase) l

• turbine drain and vent lines (two phase)

TVA did not identify any differences between this program for Unit 1 and that for Unit 2.

The staff's evaluation is in Section 3.11 of NUREG-1232, Volume 2.

3.11.3 Conclusion TVA plans to inspect susceptible areas and trend the results. The NRC staff concludes that TVA's inspection and surveillance program is acceptable. The staff also concludes that the staff need not monitor TVA's implementation of the surveillance program at this time.

3.12 Cable Installation 3.12.1 Program Evaluation )

A number of employee concerns were received relating to construction practices at Watts Bar, particularly with respect to cable installation. The evaluaMon of these concerns was extended to Unit 1 and Unit 2 of the Sequoyah plants.

The staff's evaluation of TVA's cable installation practices at Sequoyah is provided in Section 3.12 of NUREG-1232, Volume 2 for Unit 1 and Unit 2. The staff has concluded that the cable installation practices were acceptable, but there was a question about the silicone rubber-insulated cable installed in the containment vessel. For Unit 2, the American Insulated Wire (AIW) cable was removed and the TVA test data on the Anaconda and Rockbestos cable, a partial qualification of the silicone rubber-insulated cable for a period of 10 years, l provided sufficient margin for the startup of Unit 2. TVA would qualify these cables for the expected life of Unit 1 and Unit 2 before the return of Unit 2 to power from the next refueling outage. TVA's test program to extend the qualified life of the Anaconda and Rockbestos cable is evaluated in Section i 3.12.2 which follows.

NUREG-1232, Vol. 2, Supp. 1 3-16

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3.12.2 Silicone Rubber-Insulated Cable Environmental Qualification By letter dated, November 24, 1987, TVA submitted the results of tests conducted by the Wyle Laboratories on silicone rubber-insulated cables (cables) installed ,

inside the containment vessel at Sequoyah. By letter dated December 28, 1987, '

l

'TVA documented its basis for concluding that the cables installed in the containment vessel at Sequoyah are environmentally qualified to perform their i intended function for a 10 year period following the original cable installation. l The staff reviewed the TVA data and concluded that the environmental qualifi-  !

cation tests performed by the Wyle Laboratory on Anaconda and Rockbestos cablec l and the replacement of AIW cables inside the Unit 2 containment vessel offered i adequate assurance that the functional integrity of the cables at Sequoyah Unit  !

2 is adequate to allow restart of that unit.  ;

1 By letter dated May 25, 1988, the staff requested that TVA submit details of a j cable test program for extending the qualified life of the Rockbestos and 1 Anaconda cables to 40 years. The staff accepted TVA's schedule for completing 1

this testing before the Unit 2 return to power from the Cycle 3 refueling outage. In that letter the staff outlined the basic requirements for an >

acceptable cable test program and by letter dated July 6, 1988, TVA submitted the details of its cable test program.

The staff, in its letter dated May 25, 1988, requested that TVA submit a cable test program for testing silicone rubber-insulated cables installed in the i containment vessel at Sequoyah Unit 1 and supplied by all three manufacturers (Anaconda, AIW, and Rockbestos) unless TVA decided to remove AIW cables from the Unit I containment vessel. TVA has elected to remove all the AIW silicone rubber-insulated cables, that are important to safety and must be qualified in accordance with 10 CFR 50.49, from the Unit 1 containment vessel and has proposed a test program for cables supplied by the other two manufacturers.

This cable test program is the test program to extend the qualified life of the Rockbestos and Anaconda cables for 40 years as discussed e ove.

The cable test program requires removal of installed cables for testing, five from each manufacturer, selected from the worst-case conduit configurations i located in the containment vessel at the Watts Bar Nuclear Plant. TVA has identified criteria used to determine the worst-case conduit configuration.

These criteria are similar to the criteria identified in TVA's letter of July 31, 1987, and include the length of cable pull, sidewall pressure, and 90-degree condulets. The test program also includes thermal aging, radiation aging, LOCA test (steam / chemical environment), as well as post-LOCA high pot test. The only exception is that the post-LOCA high pot test will be performed at twice the cables' rated voltage plus 1000 volts instead of 240 V dc/ mil.

Aging and LOCA tests are sufficient to demonstrate the functional operability of the cables. The post-LOCA high pot test will be used to demonstrate the margin available to account for test uncertainties. Hence, the staff finds the proposed test program acceptable.

The staff has reviewed TVA's proposed test program and has determined that the test program meets the requirements outlined in the staff's letter of May 25, 1988 with the following clarifications:

(1) TVA has defined the scope of the test program to include only the cables that are covered by 10 CFR 50.49, Category A and B. The staff requires NUREG-1232, Vol. 2, Supp. 1 3-17

i m j that all 10 CFR 50.49 cables be included in the program. TVA has informed the staff that all 10 CFR 50.49 cables are' covered by Category A and B.

However, to clarify the matter, TVA will delete the reference to Category A and B.

(2) Enclosure'2,;" Sample Selection,. Size and Removal Process": TVA should add a step between steps (4) and (5) of the licensee's submittal to state that the cable sample will be selected from a conduit with no less than three cables, unless justified. .TVA has informed the staff that its selection

' criteria already include this item and will add the criteria to the test

. program.

(3) Enclosure 3, " Resolution of Test Anomalies and Test Failures,". third para-graph: TVA should add a requirement that as soon as the determination'is made that a test anomaly is in fact an actual test failure, NRC will be promptly notified of such determination. TVA has agreed to add this requirement to the test program.

On the basis of its evaluation, the staff concludes that the proposed cable test" program is acceptable provided TVA revises the program as discussed in

' items (1) through (3) above. By letter dated October 31, 1988, TVA agreed to revise the program as discussed above. TVA's removal of AIW cables from Sequoyah Unit 1 and the previous qualification test of Anaconda and Rockbestos cables at the Wyle Laboratories provide adequate assurance of the integrity of.

cables installed at Sequoyah Unit 1 to allow restart of Unit 1. This is adequate for_the restart of Unit 1. Successful completion of the proposed test

, program will extend the environmentally qualified life of these cables to 40 years.

3.13. F_use Replacement TVA has experienced problems with fuses at Sequoyah. This is discussed in Section 3.13 of NUREG-1232, Volume 2. TVA did not identify any differences in this program between Unit 1 and Unit 2.

On the basis of the test results and experience with the FLAS-5 cadmium solder fuses from lots 4 and higher, the staff finds the replacement fuses acceptable.

However, because the analysis performed by TVA on the service life of the solder junction is predicted to be 80 months on the average and 25 months at a minimum, TVA either should replace these fuses every 25 months or should extend the life of these fuses with further testing and analysis based on the ambient conditions and failure rates of these fuses. ]

i i

I l

NUREG-1232, Vol. 2, Supp. 1 3-18 a

4 4 RESTART READINESS A number of programs necessary for safe conduct of nuclear activities at Sequoyah are discussed in the Sequoyah Nuclear Performance Plan (SNPP). The programs related to restart readiness are: operational readiness, management, quality assurance, operating experience improvement, post-modification testing, surveillance instruction review, operability "look back," maintenance, restart test program, training, security, emergency preparedness, radiological controls, and restart activities list. Three of the programs (management controls, ini-tiatives, and procedures) related to these activities were evaluated for the restart of Sequoyah Unit 2 in Chapter 4 of NUREG-1232, Volume 2, which NRC issued by a letter to TVA dated May 18, 1988. The same activities will be evaluated in Chapter 4 of this supplement for the restart of Unit 1.

In its letters dated March 31 and May 9,1988, TVA identified Unit 1 SNPP pro-grams that were different from Unit 2 programs. Those different Unit 1 programs that will be evaluated in this chapter are the following: operational readiness (Section 4.1) and the Sequoyah restart activities list (Section 4.14). Where the Unit 1 program does not differ from the Unit 2 program, the reader will be referred to NUREG-1232, Volume ?.. Any commitments that TVA made to NRC in re-solving issues identified during the staff's evaluation of these programs will be referenced in the material that follows.

The NRC staff has inspected the effectiveness of these programs and will continue to inspect them.

4.1 Operational Readiness 4.1.1 Introduction TVA has historically demonstrated weaknesses in performance of nuclear activ-ities as has been. discussed in previous systematic assessment of licensee performance (SALP) reports. On September 17, 1985, on the basis of continued poor performance as described in the fifth TVA SALP report, the NRC issued a letter delineating its concerns pursuant to 10 CFR 50.54(f). This TVA SALP report is contained within the staff's letter dated September 17, 1985.

Enclosure 2 to the staff's 10 CFR 50.54(f) letter posed certain questions to TVA regarding (1) equipment qualification (questions 1 and 2)

(2) operational readiness (question 3)

(3) cable tray support (question 4)

(4) design control (question 5)

Items (1), (3), and (4) are discussed in Sections 3.2, 2.5, and 2.1, respec-tively, of this supplement. Operational readiness will be discussed in this section.

NUREG-1232, Vol. 2, Supp. 1 4-1

l l

l l TVA has undertaken a significant effort to address and correct operational readiness issues. A special Sequoyah Task Force was established by the Manager

, of Nuclear' Power on March 19, 1986, to identify problems and initiate those l actions necessary to resolve the problems before restart of either Sequoyah i

unit. The SNPP, Revision 1, provides the assessment and plans for resuming i- operation of the Sequoyah units and those topics related specifically to operational readiness are discussed in Section V of the SNPP.

TVA has stated that the overall purpose of operational readiness is to provide the Site Director with verification that activities, programs, and commitments required for restart are completed. This is to be accomplished by designating an Operational Readiness Manager who reports to the Senior Vice President,.

Nuclear Power and an Operational Readiness Manager who reports to the Site Director. The Operational Readiness Manager provides independent oversight of the development and implementation of the operational readiness program and assists at the site by ensuring the program adequacy while also providing inde-pendent assessments and evaluations to the Senior Vice President, Nuclear Power. The Site Director will use the results of the operational readiness program and other status reviews to make his recommendation for Unit 1 restart to the Senior Vice President, Nuclear Power. The Senior Vice President, Nuclear Power will not approve restart of Unit 1 until he is satisfied that all preparations for restart have been satisfactorily completed.

The Operational Readiness Manager assesses whether corrective action plans have been established to address the underlying causes of deficiencies or problem areas, evaluates the adequacy _of corrective action, reviews the closecut practices, and provides comments to improve the process and program content.

The Operational Readiness Manager is responsible for working with the site and line organizations to obtain verification of program implementation, to obtain verification of organizational readiness through the evaluation of performance objectives, and to develop the restart prerequisite checklist. The checklist will be used to verify that hardware issues directly affecting system operability are closed before the applicable mode changes.

4.1.2 Evaluation Success of the operational readiness program is contingent upon the successful implementation of the three program elements: the SNPP completion of Volume 2 programs, the establishment and assessment of performance objectives, and the i restart prerequisite verification (Restart Test Instruction 9--Unit 1 Master Test Sequence).

Implementation of the first element will be to verify that (1) restart activities as defined in the TVA tracking and reporting open items (TROI) computer list have been completed, (2) SNPP Volume 2 text statements of intention have been l completed, and (3) major projects, having broad effect on other plant activities, have been completed before restart. Some long-term program improvements will i I

be open at restart and will be tracked through routine NRC observations of the TVA corporate commitment tracking system.

The purpose of the performance objectives evaluation is to ensure that site organizations function effectively and are prepared for plant restart and operation. Generic performance objectives and criteria have been established NUREG-1232, Vol. 2, Supp. 4-2 i i

_ _ _ _ _ _ . . _ _ _ _ _ _ __J

and assigned to site organizations so that they may address the areas of pro-cedures, staffing, supervisory involvement, internally and externally identi-fied findings, housekeeping, and readiness of support organizations during restart. Additional performance objectives and criteria have been developed for the functional areas of organization and administration, document control, maintenance, training, licensing, engineering, and configuration control.

Performance objectives in these functional areas also have been assigned to the appropriate site organizations.

TVA's performance objectives are based on the guidance provided by Institute for Nuclear Power Operations document INP0 85-001, " Performance Objectives and Criteria for Operating and Near Term Operating License Plants," January 1985.

This operational readiness evaluation will include the following:

• establishing appropriate objectives and criteria e evaluating readiness against established criteria 1

• assessing effect of deficiencies identified l

• developing and implementing additional corrective actions for identified deficiencies l l

• verifying that performance objectives have been met and readiness is assured l

TVA has established plant instructions and tracking systems to ensure that j hardware issues directly affecting system operability are closed before the l mode changes. To ensure that these hardware issues are complete, a restart j prequisite checklist has been developed. This checklist was developed by the I Sequoyah operational readiness staff and serves to consolidate hardware operability issues, including those listed below:

o maintenance or work request backlog o outstanding clearances o modification status o outstanding temporary alteration control forms (TACFs) o outstanding preventive maintenance packages o instrumentation availability o outstanding hardware-related potentially reportable occurrences (PR0s) and condition adverse to quality reports (CAQRs) l The restart prerequisite checklist will be provided to the Sequoyah Restart Test Manager for inclusion in the plant restart test sequencing instruction.

This instruction will provide for plant operation review committee (PORC) review and plant manager approval of results before leaving specified hold points. In addition to incorporating the restart prerequisite requirements, this instruc-tion will address the completion of required special testing during the restart of Unit 1.

A parallel independent assessment of operational readiness was performed by TVA's Office of Nuclear Power (0NP) Operational Readiness Manager. This review NUREG-1232, Vol. 2, Supp. 1 4-3 L-- -- _ _ _ _ _ - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ . - _ _

was conducted by a team of senior personnel who had plant experience from both inside and outside TVA. The TVA team provided its findings and recommendations to the Senior Vice President, Nuclear Power in a letter dated August 23, 1988.

Further, the Senior Vice President, Nuclear Power has requested that the Sequoyah Nuclear Safety' Review Board (NSRB) review the SNPP Volumes 1 and 2 and the actual ,

' status of preparation for restart of Sequoyah units from a safety perspective. l The NSRB has reviewed and accepted the overall approach outlined in the SNPP.

The board also has reviewed the special programs and certain secondary hardware j

' issues and the onsite safety review process, maintenance planning, and procedure  !

development.

The staff has reviewed the Independent Readiness Review as part of its ongoing ,

evaluation of the implementation of the Operational Readiness Review Program. In j addition, the staff has conducted an operational readiness inspection at Unit 1. '

4.1.3 Conclusions Initially, the staff believed that TVA needed to clarify the meaning of hardware  ;

issues in the paragraph describing the restart prerequisite verification element.  ;

Provisions have been included to ensure that TVA assesses hardware operability for the cumulative effect on system performance. Overall, the staff has con-cluded that the implementation portion of the operational readiness program rep-resents a realistic and systematic format to ensure that plant activities, pro-grams, and commitments required for restart are completed. After conducting its inspection, the staff concluded that Unit 1 was ready for operation. Subse-

.quent inspections during the restart of Unit 1 are documented in NRC Inspection Reports 50-327, 328/88-40 (October 20, 1988), 88-44 (October 28,1988),88-46 (November 8, 1988), 88-47 (November 28, 1988), 88-48 (to be issued), 88-49 (December 13, 1988), 88-51 (December 23, 1988), 88-52 (January 3, 1989), and '

88-55 (December 28,1988).

On the basis of its review, the staff finds that this program is acceptable. As designed, the program should provide the Site Director and Senior Vice President, Nuclear Power verification that activities, programs, and commitments required for restart of Unit 1 and Unit 2 are completed.

4.2 Management 4.2.1 Introduction In its SNPP, TVA staff states that, in the past, responsibility and authority have not been clearly assigned to managers and their organizations. To correct this weakness, TVA has reorganized the Sequoyah site organization. TVA also has taken specific actions to clarify each manager's authority and area of responsibility and to establish accountability. In addition, TVA has programs under way to improve the level of plant knowledge of plant managers and super-visors. The NRC staff evaluated TVA's efforts to improve the management and organization at Sequoyah in Section 4.2, " Management," of NUREG-1232, Volume 2.

4.2.2 Evaluation 4.2.2.6 Procedures Long-term and short-term actions are under way to improve the plant procedures.

The short-term effort consists of the development or revision of those procedures NUREG-1232, Vol. 2, Supp. 1 4-4

r,ccary to support plant restart. Work for Unit 2 was completed before the restart of Unit 2. Changes that need not be made before plant restart will be hand 1Ed as part of the long-term program to upgrade procedures. This long-term procedures improvement program is a corporate-wide effort that will extend be-yond restart of a Sequoyah unit. As part of this program, the Sequoyah plant procedures will be incorporated into an overall five-tiered package of policies, directives, standards, procedures, and instructions that will govern the opera-tions of TVA's entire Office of Nuclear Power. A site procedures group has been established on a permanent basis at Sequoyah to participate in this long-range program.

4.2.3 Conclusion On the basis of its evaluation, the NRC staff concludes that TVA has acceptably addressed the Sequoyah-specific management concerns and weaknesses for the restart of Unit 1 4.3 Quality Assurance 4.3.1 Conditions Adverse to Quality i TVA did not identify any differences between the program for Unit 1 and that for Unit 2. The Conditions Adverse to Quality (CAQ) Program is evaluated in Section 4.3.1 of NUREG-1232, Volume 2. The staff concluded that the measures described in the SNPP for handling CAQs are acceptable. NRC inspections (see Inspection Report 50-327, 328/87-55 [ November 14,1987]) have shown that prob-lems still exist at Sequoyah that will take time to fully resolve. These prob-lems include additional employee training, accurate tracking of problems, and general compliance with procedures.

NRCOrderEA85j9 By letter dated June 14, 1985, NRC issued Order EA 85-49 modifying the licenses for Sequoyah. The basis for the order was the circumstances surrounding the preparation of a nonconformance report (NCR) related to the Sequoyah contain-ment pressure transmitters. As a result of the special review conducted between March 27 and 29, 1985, NRC identified a breakdown in the management controls for evaluating and reporting potentially significant safety concerns.

TVA concluded in its letter dated March 2, 1987 that, with the implementation of its revised CAQ Program, it had met the requirements of the order. The staff reviewed these letters and the revised CAQ Program as described in the TVA Corporate and Sequoyah Nuclear Performance Plans. The staff also reviewed the implementation of the program at Sequoyah in several NRC inspections.

As discussed in the safety evaluation enclosed in its letter dated March 31, 1988, the staff concluded that TVA had acceptably addressed the order for Sequoyah. Therefore, the order was considered satisfied for Sequoyah. The NRC staff stated that it would continue, however, to monitor the implementation of the CAQ Program at Sequoyah as part of its normal inspection program for the two units.

NUREG-1232, Vol. 2, Supp. 1 4-5

l i

Changes to the CAQ program TVA has recently revised its CAQ Program. After the staff evaluated the earlier program and.found it acceptable (before the restart of Unit 2), the sta',^f con-cluded that NRC Order EA 85-49 was closed for Sequoyah. These evaluations are discussed here in Sections 4.3.1 and 4.3.2 and in Section 4.3 of NUREG-1232, Volume 2.

4.3.2 Quality Assurance Program The NRC staff evaluated TVA's program for resolving conditions adverse to qual-ity in its nuclear activities and in its quality assurance (QA) program in Sec-tion 4.3 NUREG-1232, Volume 2. TVA did not identify any differences between the program for Unit 1 and that for Unit 2.

The TVA organization for QA is described in Topical Report TVA-TR75-1 entitled, "QA Program Description for Design, Construction, and Operation of TVA Nuclear Power Plants." The staff evaluation of TVA's Sequoyah Quality Assurance Program is based on a review of SNPP Section 2.6, " Quality Assurance" and the topical report.

The staff concluded in NUREG-1232 Volume 2 that the overall revisions to the TVA nuclear quality assurance progra,m as gener, ally described in the re-vised SNPP represented QA programmatic improvements and, if properly implemented, were acceptable.

It is important to note that the staff's review and acceptance of the QA topical report means only that TVA's commitments satisfy the programmatic requirements of 10 CFR Part 50, Appendix B, as described in Chapter 17 of the NRC Standard Review Plan (NUREG-0800). The staff will assess whether these commitments are fully and effectively met in its ongoing oversight and inspection of TVA's tech-  !

nical and QA programs. Because of TVA's past problems in the QA area, NRC's Re-gion II staff approved this revision (Revision 9) to the QA topical report on January 30, 1987, for a period of 2 years. The staff's decision on extending its ,

approval of the topical report will depend on how effectively TVA implements the program.

On May 4, 1988, TVA submitted Revision 10 to its QA topical report to the NRC.

Staff review of Revision 10 determined that it reflected changes made in TVA's organizational structure since the issuance of Revision 9 to the topical report (TVA-TR75-1, "QA Program Description for Design Construction"). Revision 10 also clarified TVA's position relative to TVA s compliance with certain NRC regulatory guides. On the basis of its review, the staff concluded that Revi-sion 10 to the topical report is acceptable.

Staff reviews and audits of the TVA condition adverse to quality report (CAQR) process identified technical and administrative programmatic weaknesses. To address these weaknesses, the licensee undertook a detailed and comprehensive program to improve the TVA CAQR (problem identification and resolution) process.

The staff evaluated the QA program, the QA topical report, and the CAQR process as described in the licensee's SNPP.

l The staff assessme'nt of the QA program and the QA topical report was that the Sequoyah programs were acceptable and the Unit 2 implementation was adequate.

The staff also conducted inspections in this area as discussed in Inspection Reports 50-327, 328/88-15 (March 30, 1988) and 88-19 (May 27, 1988).

NUREG-1232, Vol. 2, Supp. 1 4-6

. Inspections 50-327,: 328/88-15 and 88-19 found that CAQR implementation was adequate and that the licensee had addressed identified weaknesses. These findings were applicable to both Unit 1 and Unit 2.

On the basis of its reviews and the NRC inspections, the staff concludes that the CAQR process is acceptable and that it is being adequately implemented with .

respect to both Unit 1 and Unit 2. The staff also finds that the quality assurance program is acceptable for the restart of Unit 1.

Representatives of NRC and TVA met at NRC headquarters in Rockville, Maryland

-on September 8, 1988, to discuss the changes.to the-CAQ Program. The staff concluded that the changes evolved from the program itself and do not affect the staff's conclusions in its safety evaluation on Order EA 85-49 dated ,

March 31, 1988. In its normal inspection activity at Sequoyah, the staff will J continue to monitor how TVA implements the CAQ Program to determine the effec-tiveness of the changes that TVA has made to the program. The summary of.the September 8, 1988, meeting was' issued on September 16, 1988.

4.4 Operating Experience Improvement Item C.3 of Enclosure 2 to the 10 CFR 50.54(f) letter requested a detailed ,

description of the Sequoyah Operational Readiness Plan. In response to this request, TVA described operating experience actions (in terms of improvements made through reactor trip reduction, limitation of spurious engineered safety features actuations, review of the Davis-Besse event for lessons learned, and review of nuclear operations experiences) in the SNPP. Each of these improve-ments was evaluated.by the staff in-Section 4.4 of NUREG-1232, Volume 2. The staff concluded that the actions taken by TVA to improve operational readiness were acceptable for the restart of Sequoyah Unit 1 and Unit 2.

4.5 Post-Modification Testing In past inspections NRC staff identified problems with respect to the adequacy of testing of systems and components following modification. TVA instituted programs to address the deficiencies in its post-modification testing. These programs were evaluated by the staff in Section 4.5 of NUREG-1232, Volume 2.

The staff concluded that the programs to address post-modification testing were acceptable for the restart of Unit 1 and Unit 2. TVA did not identify any differences between the Unit 1 program and the Unit 2 program.

4.6 Surveillance Instruction Review 4.6.1 Introduction By means of reviews and audits, the staff identified technical and administra-tive weaknesses in Sequoyah's surveillance instructions (sis). To remedy these weaknesses, TVA has undertaken a comprehensive and disciplined program to review and revise the sis. The program has been changed several times since it was initiated in the summer of 1986. These changes have resulted in increasing the technical and administrative depth of reviews, the scope of reviews, the independent evaluations of the process and its products, the field verification of sis and their supporting instructions, and the technical content and specificity of sis.

NUREG-1232, Vol. 2, Supp. 1  ?'

4.6.2 Evaluation The staff assessment of the descriptive material providing the basis for the TVA program to review and revise before restart certain Sequoyah Unit 2 sis that implement technical specification surveillance requirements included the scope, methodology, and organization of TVA's surveillance review and revision program.

The staff also conducted inspections in this area as discussed in Inspection Reports 50-327, 328/87-36 and 87-50.

The basic objectives of the SI program are to ensure all technical specification requirements are addressed and that the sis and their supporting instructions covered by the program scope are technically adequate to fulfill the surveil-lance requirements of the technical specifications, have an appropriate level of dependence on the skill of the performer of the instruction, and comply with basic administrative requirements that make performance of the SI reliable.

This Unit 2 program was completed before Unit 2 restart.

Although the staff concurs with TVA's objectives, TVA should define the skill level required to write, revise, and review the sis and supporting procedures and TVA should describe, including starting and completion dates, the long-term program which will be undertaken to ensure complete administrative consistency, achieve standard format and organization, and make other improvements as are determined to be needed.

The staff evaluated the Unit 2 program in Section 4.6 of NUREG-1232, Volume 2.

The scope of TVA's Unit 1 phase of the SI review program includes those technical specification sis and supporting instructions that are required for startup, operation, and safe shutdown of Sequoyah Unit 1 to the point of the next refueling. The staff discussed the program methodology and the governing organization, required training and qualification, and instruction verification in the Unit 2 SER (NUREG-1232, Volume 2) and found the program acceptable. The program for Unit 1 is essentially the same as the program for Unit 2.

The program for Unit 1 is currently under the control of the Site Director, and it is implemented by the established plant organization under the day-to-day direction of the SI review project manager.

Both the Unit 1 and Unit 2 phases of the SI review program call for a detailed checklist to be used during the technical review of an instruction to identify technical deficiencies. Part I of this checklist focuses on the technical ade-quacy of the instruction, with an operability evaluation being performed only if the instruction is found to be technically inadequate. Part II of the checklist focuses on the administrative adequacy of the instruction, but not all items within this section need to be fulfilled to ensure instruction adequacy. Part II of the checklist does not have to be completed for this program. Certain items in Part II of the checklist, such as senior reactor operator (SRO) approval to perform the test and verification or double verification signoffs, stem from other documents and are checked to ensure necessary compliance.

TVA has adopted a progressive SI verification approach that obtains the best verification permitted by plant conditions and the approval status of the in-struction. During the latter stages of instruction preparation, the responsible NUREG-1232, Vol. 2, Supp. 1 4-8

section performs nonmanipulative walkdowns to confirm that the instruction is correct.

4.6.3 Conclusions On the basis of its review and the NRC inspections, the staff concludes that the Surveillance Instruction Review and Revision Program is producing adequate procedures to support Unit 1 startup. However, the staff believes that the program for long-term control of SI improvements, including resolution of the issues of temporary changes, qualification of reviewers, and schedule, needs to be provided to completely resolve this issue.

The staff reviews of the Sequoyah procedure enhancement program indicated that this program is not unit specific and that the process being employed by the licensee is essentially the same for Unit 1. No additional inspection activi-ties are necessary.

4.7 Operability "Look Back" As a result of violations regarding the adequacy and timeliness of corrective i

actions for repetitive equipment failures and out-of-tolerance conditions, the licensee implemented a trending and tracking program at Sequoyah. . Because this program was geared toward identifying future deficiencies, the staff raised concerns regarding potential operability questions resulting from past, undetected, repetitive failures.

TVA conducted an operability "look back" program that was designed to identify adverse conditions associated with equipment operability, to evaluate the safety significance of these conditions, to document the effectiveness of corrective actions, and to propose further corrective actions where necessary.

This program was evaluated in Section 4.7 of NUREG-1232, Volume 2. The staff concluded that the scope, guidelines, and implementation of the Sequoyah operability look-back review program satisfactorily accomplished its intended purpose for Unit 1 and Unit 2.

4.8 Maintenance 4.8.1 Introduction Previous NRC inspections at TVA nuclear units indicated programmatic deficien-cies in the site maintenance programs. In the SNPP, TVA discusses specific problems identified by the NRC and TVA that have existed at Sequoyah. These deficiencies include failure to implement appropriate preventive maintenance programs, failure to provide adequate planning of maintenance activities, and inadequacies in the training programs for the corporate and site personnel involved in maintenance activities.

4.8.2 Evaluation The NRC staff evaluated the scope, organization, and meth 'gy of TVA's main-tenance program in Section 4.8 of NUREG-1232, Volume 2. Le taff concluded that the maintenance program is acceptable. TVA did not fa,a that the Unit 1 program differed from the Unit 2 program.

NUREG-1232, Vol. 2, Supp. 1 4-9

=

4.8.3 Conclusions In its evaluation in NUREG-1232, Volume 2, the staff noted that managers do not adequately address long-term program development and that improvements are needed in time management, interaction with support groups, and stabilization of the corporate organization. It also stated that interviews have indicated that TVA has taken the first steps toward resolving these problems as evidenced by the following activities: )

(1) TVA conducted-a time study of managers at the plant and identified problem {

areas. The staff understands that this study involved evaluations of man- ,

agement skills, work processes, climate and stress factors, facilities, and tools, and that a report with recommendations on improving the utilization of management talent has been provided to TVA.

I (2) The staff noted that maintenance managers appear to be working with support i groups to establish effective work relationships as evidenced by management i planning meetings with QA and utilization of SR0s in the work planning i process.

(3) The staff noted that the permanent corporate organization is beginning to take shape with the hiring of several very capable managers. The staff feels that the corporate organizations can have a significant effect on l the establishment of a strong program, but believes that the stabilization of the corporate staff is essential to making this a positive, not a nega-tive, impact.

Although it concluded in NUREG-1232, Volume 2, that TVA's maintenance program

was acceptable, the NRC staff will review the effect of these three steps on TVA's maintenance program in a future inspection. 4 4.9 Restart Test Program 4.9.1 Introduction In response to employee concerns, TVA reassessed operational safety at its plants. A major new review of the Sequoyah Unit 2 initial design, construction, and operating practices was conducted and a restart test program (RTP) was in-stituted to ascertain the functional integrity of the accident mitigation and safe-shutdown systems. The principal objective of the RTP is to instill con-fidence that certain preoperational tests conducted during initial plant licens-ing and surveillance inspections routinely conducted following plant licensing and during the long plant shutdown are valid tests that can ensure the current functional integrity of safety systems and components. This assurance is re-quired because the functional integrity might have been jeopardized by plant modifications, maintenance practices, or the like. This assurance is obtained by reviewing post-modification and maintenance tests and any other tests or pro-grams that might affect the validity of the subject tests.

The staff evaluated the RTP for Unit 2 in Section 4.9 of NUREG-1232, Volume 2.

The staff concluded that the RTP will ensure the functional integrity of safety systems at Unit 2 and is acceptable.

NUREG-1232, Vol. 2, Supp. 1 4-10

i TVA identified minor differences between the Unit 1 restart test program and the Unit 2 RTP. .These differences.are discussed in TVA's letters dated March 31 and May 9, 1988. The staff reviewed these differences in NRC Inspection Report 50-327, 328/88-29 (October 20,1988) on the containment spray system (CSS).

4.9.2 Evaluation In Inspection Report 50-327, 328/88-29, the staff reviewed the Unit 2 CSS RTP test matrix as it specifically applied to the Unit 1 CSS; the staff also compared the Unit 1 general program with the Unit 2 completed program. The details of the inspection objectives for this review and inspection finding are given in Inspection Report 50-327, 328/88-29 that was issued October 20, 1988. These details are summarized below.

(1) Unit 1 CSS Restart Test Program Review The inspection effort included a review of the CSS.to verify that the restart test group (RTG) functional review process is being adequately impleented, to verify that components / systems functions that are identified as requiring testing are properly dispositioned, to provide a sample assessment of the technical adequacy of several portions of previously completed preoperational tests that are being used to satisfy the functional testing requirements, and to verify that the functional analysis report. (FAR) matrix package complied with the applicable documents (including the FSAR and TS) and contained the necessary information.

It was determined that, for the CSS, the requirements of the Unit 1 restart test program were either properly implemented or TVA would correct the issue before Unit I restart.

(2) Comparison of Unit 1 RTP to the Unit 2 Completed Program This comparison was made to determine if the Unit 1 modified RTP was as accept-able as the Unit 2 completed program that was accepted by the staff and docu-mented in Section 4.9 of NUREG-1232, Volume 2. TVA provided the details of the differences between the Unit 1 RTP and the Unit 2 RTP in the enclosure to its May 9, 1988 letter. The RTP for Unit 1 is essentially the same as that for Unit 2 and the evaluation and conclusions discussed in NUREG-1232, Volume 2, are considered valid for both units. However, the Unit 1 program scope was reduced from that applied to Unit 2 on the basis of experience and as a result of modi-fication to other programs that were process inputs to the RTP. These differ-ences along with the team's comments are provided below:

• Once the design functions were established, the RTP, utilizing SIL-9B to generate the modification review report, reviewed the impact of previous modifications. This was different from the Unit 2 program which utilized the design baseline and verification program (DBVP) output for the list of modifications that may affect the system. The team identified a possible ,

weakness with this approach. Specifically, the Unit 2 program had also (

used red-line drawing to depict the "as constructed" system at the time the preoperational tests were performed. Combining the DBVP output (i.e.,

modifications since time of licensing) with the red-line drawing, the Unit 2 program could evaluate the adequacy of post-modification testing of all NUREG-1232, Vol. 2, Supp. 1 4-11

l modifications subsequent to successful preoperational testing. In compari-son, the Unit 1 program (which did not include the red-line drawing process) creates a gap involving the adequacy of post-modification testing between the time the preoperational test was performed and the time the operating licensing (0L) was issued. i q

This problem only affected those functions for which the licensee was tak-ing credit for preoperational tests to validate adequate testing of the I specified function. TVA has determined that 274 modifications fall into the post preoperational testing and pre-OL category. Of these, 190 modifi-cations were reviewed as part of the modifications review for Unit 1 and 16 were reviewed for Unit 2 only, leaving 68 modifications to be reviewed.

Two of the 68 modifications were determined to have a potential effect on previously tested equipment and both of these modifications were determined to be adequately tested and to have no effect on the function involved.

• The Unit 2 program requirement to review the results of the post-maintenance test survey was not included in the Unit 1 program. This decision was based i on TVA experience gained from the Unit 2 program which indicated that only approximately 6 percent of the maintenance requests reviewed indicated either a lack of adequate test documentation or a lack of adequate testing.

Additionally, the postmaintenance test survey was not conducted for Unit 1 as part of the DBVP; therefore, the RTP could not incorporate the survey data into its process. Also, the team was informed that the additional testing controls put in place at Sequoyah as a result of the Unit 2 main-tenance program improvements should reduce the effect of possible inade-quate postmaintenance testing on the validity of previous functional tests. i

• The Unit 2 requirement to review the effect of the piece parts review was also deleted from the Unit 1 program. TVA described the reduction in the Unit 1 piece parts program in its letter dated February 10,1988(b). The staff evaluated this reduction in Section 3.3 of this supplement. TVA stated that the RTP, therefore, did not identify a need to review the out-put of the piece parts program for its effect on functional test validation.

Additionally, as stated above, the licensee feels that the improved main- - '

tenance program would ensure that any part replaced as a result of the piece parts review would be adequately tested.

4.9.3 Conclusion As stated earlier, on the basis of these minor program implementation changes, the team concludes that the evaluation and conclusion for the Unit 2 program as stated in Section 4.9 of NUREG-1232, Volume 2, adequately bounds the Unit 1 program, ensuring the functional integrity of safety systems at Sequoyah Unit 1.  ;

4.10 Training Because of the programmatic concerns arising from licensed operator requalifi-cation deficiencies identified at Browns Ferry and deficiencies identified in operator and shift technical advisor (STA) knowledge of the safety parameter display system (SPDS), the staff determined that the Sequoyah training program would have to be reviewed for adequacy before startup.

NUREG-1232, Vol. 2, Supp. 1 4-12

1 Section II.2.3 of the SNPP documents TVA's review and evaluation of training and staffing. In the SNPP, TVA committed to increase the reactor operator certifi-cation program to 16 weeks and to increase the requalification period to 6 weeks.

TVA also noted that training for assistant unit operators was increased from I week to 2 weeks in 1986, and to 6 weeks in 1987 and 1988.

The staff evaluated the training programs instituted by TVA in Section 4.10 of NUREG-1232, Volume 2. TVA did not identify any differences between the Unit 1 program and the Unit 2 program. The staff concluded that these programs were sufficiently acceptable to permit restart of Sequoyah Unit 1 and Unit 2.

However, the staff will continue to monitor these programs to ensure proper implementation.

4.11 Security In the 10 CFR 50.54(f) letter (September 17,1985), the staff noted that TVA had not been performing adequately in several areas. These areas were identified from their low ratings within their respective SALP categories. As a result of these concerns, TVA has initiated several actions intended to improve performance.

In the most recent SALP report, the staff noted an improving trend in the area of security, compared to the low ratings previously noted. However, to ensure that this improvement would continue, TVA took several actions. These actions, which are dfscussed in Item 4 of Appendix 2 to the SNPP, are evaluated below.

TVA identified in the SNPP those measures it will take to increase how much supervisors and employees know about their responsibilities for complying with '

security requirements. TVA will trend all low security ratings to identify areas for improvement and will revise the training program for public safety to include experience from previous security incidents. To ensure the planned improvements were being properly implemented, the staff conducted physical security inspec-tions at the Sequoyah plant as documented in Inspection Reports 50-327, 328/

86-30 (June 3, 1986), and 86-47 (September 19,1986).

The staff has reviewed the information provided in the SNPP and has inspected physical security several times as part of its evaluation of the improvements to plant security at Sequoyah. On the basis of of its evaluation, the staff l concludes that the actions taken by TVA to improve security address the staff's l concerns. In addition, the staff finds that with the implementation of these actions, TVA will have an acceptable security program for restart of either Sequoyah unit.

4.12 Emergency Preparedness 4.12.1 Introduction SNPP Appendix 2, Section 6, Revision 1, documents TVA's actions taken in the Sequoyah emergency preparedness program to resolve problems identified in NRC SALP reports. TVA has reorganized its Emergency Preparedness Branch and has identified additional staff to provide increased resources in the areas of emer-gency planning and procedures, joint State and local government activities, development and conduct of exercises and drills, and onsite and offsite facili-ties. TVA has also identified additional staff needed at the sites for program implementation.

NUREG-1232, Vol. 2, Supp. 1 4-13 L_-- - _ - - _ _ - _ _ - .

r 4.12.2 Evaluation l

TVA has installed sirens and strobe lights in accordance with approved engineer-ing change notices issued to meet the requirements of IE Bulletin 79-18, "Audi-bility Problems Encountered on Evacuation of Personnel From High Noise Areas."

Tests to verify the system's effectiveness given the added sirens and strobe lights will be completed after restart of both units, when the equipment operat-ing noise levels are normal.

The staff evaluated emergency preparedness for Sequoyah in Section 4.12 of NUREG-1232, Volume 2. In this supplement, the improvements made by TVA to its Radiological Emergency Plan for Sequoyah are covered.

4.12.3 Conclusion The staff concludes that, with proper implementation, past problem areas in emergency preparedness should be satisfactorily resolved.

4.13 Radiological Controls In Section II.1.2.3 of the SNPP, TVA discusses its improvements to the radio-logical controls organization. In Section 4.13 of NUREG-1232, Volume 2, the staff evaluated improvements that TVA had made to its radiological controls organization. TVA did not identify any differences between the Unit 1 program and the Unit 2 program. Therefore, the staff concluded that: (1) These measures will strengthen the radiological controls program at Sequoyah and (2) The actions taken by the licensee are sufficient to. support plant restart for both Unit 1 and Unit 2.

4.14 Restart Activities List 4.14.1 Introduction For Sequoyah Unit 2, TVA established a Sequoyah Task Force on March 19, 1986, to review implementation of the corrective actions applicable to Sequoyah, to initiate specific actions to address Sequoyah problems, to monitor and ensure that a list has been compiled of all items known to need attention, and to re-view the process and identification of those items required to be completed before restart of Sequoyah Unit 1 and Unit 2.

To complete its assignment, the Sequoyah Task Force developed a list of Sequoyah plant activities (except for those of a routine nature) to be completed before restart. The Sequoyah Activities List (SAL) was based on issues identified in NRC inspections, TVA QA audits, American Nuclear Insurers audits, Institute of Nuclear Power Operations inspection reports, Sequoyah corrective action reports and discrepancy reports, TVA Nuclear Safety Review staff and Nuclear Safety Re-view Board reports, employee concerns, Sequoyah reactor trip reports, licensee event reports, and technical issues identified by TVA's Division of Nuclear Engineering.

The Sequoyah Task Force had established criteria (Section IV.2.0 of the SNPP) to determine which items had to be resolved for restart. The staff reviewed and accepted these criteria by letter dated June 9, 1987. The Sequoyah Task Force NUREG-1232, Vol. 2, Supp. 1 4-14

reviewed the process the line organization used to identify, evaluate, disposi-tion, and close out items, and also reviewed the adequacy of planned actions taken before Sequoyah Unit 2 restart. As new issues arose and work activities were developed, they were reviewed by Sequoyah managers to determine their import-ance to restart. The Site Director had to approve all new items added to the restart list; however, only the Manager of the Office of Nuclear Power, presently the Senior Vice President, Nuclear Power, could delete items that had been desig-nated for restart.

4.14.2 Evaluation The identification, tracking, and closure of restart items for Unit 1 are dis-cussed in Section IV of Revision 3 of the SNPP. TVA submitted this plan in its letter dated May 9, 1988.

Restart items for Unit 1 are being identified and tracked by TVA's permanent tracking and reporting open items (TROI) computer program rather than by the 5AL used for Unit 2. This program lists the restart and non-restart items for Sequoyah in a database. The status and organization responsible for each item are accessible through computer terminals by means of computer printouts provided to plant personnel. This capability was not available with the SAL. The staff has reviewed the data available from TROI and finds them acceptable.

TVA stated that the Unit 1 restart list was developed by an item-by-item review of completed and open Unit 2 and common restart activities and of open Unit 1 issues. TVA issued Standard Practice SQA203, "Use of TROI for Unit 1 Restart Action List," to specify the requirements for maintaining and controlling the Unit 1 restart list. The criteria used by TVA to determine if issues must be completed before restart are the same restart criteria used for Unit 2. Stan-dard Practice SQA203 requires each Sequoyah Unit 1 potential restart item to be evaluated against these criteria to determine whether associated corrective action is required to be completed before restart. TVA stated that the Site Director has designated either the Restart Director or Assistant to the Site Director to evaluate proposed new activities and ascertain that these activities satisfy the restart criteria.

In describing its process to close out restart items, TVA stated that Standard Practice SQA203 specifies that existing site procedures will be used to ensure that Unit I restart items are dispositioned and closed in a verifiable manner.

Each site manager is responsible for n,aintaining the status of his/her restart items through closure, adding new actions as necessary to resolve an open re-start item as the issue evolves and ensuring that a specific discipline and man-ager within his/her organization is assigned responsibility for obtaining timely closure of open restart items. TVA considers an item closed for restart when all corrective actions that have been specified to be completed before restart are field completed, documented, and verified in an appropriate manner.

To coordinate the effort to designate new activities as restart items, TVA explained that the Site Director has identified a Unit 1 Restart Director who is responsible for coordinating the Unit 1 restart effort. The Unit 1 Restart Director reports directly to the Site Director and has responsibility and auth-ority to establish specific schedule priorities, to ensure that line managers NUREG-1232, Vol. 2, Supp. 1 4-15

are coordinating their' activities to complete all restart actions, to establish.

, . site. goals as appropriate to achieve a safe and timely restart, to call and con-duct restart schedule status meetings, and to ensure performance of the.individ-ual. groups-and integrated work activities. TVA stated that this position has

~ been established in order to ensure that all restart requirements are properly.

completed in.an integrated fashion and in~a reasonable period of time.

T4;14.3- Conclusion' On the basis of'its evaluation,'the staff concludes that the use of the TROI computer system to identify, track the status of, and indicate closure of

. Unit I restart items is acceptable.

L L

]

i 1

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1 NUREG-1232, Vol. 2, Supp. 1 4-16

5 EMPLOYEE CONCERNS During the spring of 1985, a number of TVA employees informed the NRC and selected members of Congress of safety concerns, primarily related to the Watts Bar Nuclear Plant. In addition, TVA learned of many employee concerns through its own organization. The concerns indicated that many TVA employees had lost confidence in TVA's nuclear management and its ability to properly conduct nuclear activities. In addition, some of these employees xpressed fear of reprisal from TVA management if they raised their concerns directly. Two pro-grams relating to employee concerns have resulted; they are referred to as the "new" program and the "special" program. These two programs are discussed in detail in the staff's " Safety Evaluation Report on Tennessee Valley Authority:

Revised Corporate Nuclear Performance Plan," NUREG-1232, Volume 1, dated July 1987.

The new employee concerns program (ECP) was implemented at Sequoyah on February 1,1986, as described in a TVA submittal of February 3,1986. The key element of the program is the ECP Site Representative at Sequoyah. The ECP staff receives and investigates concerns from employees who feel that normal channels of resolution have failed. The program is further described in other TVA submittals including the Sequoyah Nuclear Performance Plan (SNPP). The staff issued its safety evaluation accepting TVA's new ECP on September 30, 1987.

In May 1985, TVA awarded the Quality Technology Company (QTC) a contract to develop and implement a program for conducting confidential interviews with TVA employees performing assignments for the Watts Bar Nuclear Plant. Concerns also were collected from TVA employees at the Sequoyah and Browns Ferry plants.

This program, which emphasized the identification of employee concerns dealing with nuclear safety at all TVA facilities, identified more than 5000 employee concerns. In February 1986, TVA initiated a program to evaluate and resolve these employee concerns. The employee concerns special program (ECSP) was developed to review the concerns received through the QTC or from TVA's Nuclear Safety Review Staff (NSRS) for applicability to Sequoyah. This work was per-formed by the Watts Bar employee concerns task group (ECTG). The staff evalua-tion of the ECSP was issued to TVA by letter dated October 6, 1987.

Employee concerns were grouped into nine categories for evaluation and resolution.

The categories are construction; engineering; industrial material control; oper-ations; quality assurance / quality control; welding; management and personnel; industrial safety; and intimidation, harassment, wrongdoing, or misconduct.

Because Sequoyah, Units 1 and 2, were scheduled to be the first TVA plants restarted, the concerns applicable to Sequoyah only, within each employee con-cern subcategory, were divided into individual element reports that addressed related concerns. For Sequoyah, element reports were prepared covering six of the categories. TVA has submitted more than 300 element reports to address the resolution of employee concerns for Sequoyah. These element reports have been divided into those that need to be resolved and evaluated before the restart of the Sequoyah units and those that may be resolved after restart. The criteria used were the staff-approved restart criteria.

NUREG-1232, Vol. 2, Supp. 1 5-1

1 The NRC staff has issued, by letter dated March 11, 1988, its " Preliminary Safety Evaluations on the Tennessee Valley Authority Employee Concern Element Reports" for the restart of Unit 2. This preliminary safety evaluation addressed.those element reports that the staff considered had to be resolved before the restart' of Unit 2. The NRC staff also issued, by letter dated November 4,1988(a), its

" Safety Evaluations on the Tennessee Valley Authority Employee Concern Element Reports" for the restart of Unit 1. This latter report contained the remainder of the evaluations needed for restart as well as the evaluations of the non-restart element reports. The staff preferred this method to issuing evaluations as part of NUREG-1232, Volume 2.

i Subcategory and category reports will address the resolution of employee con-cerns for the other TVA nuclear plants. TVA will not submit any element report 1

for the management and personnel and industrial safety categories because TVA has concluded these'do not contain safety-related concerns. The staff has concluded that. employee concerns in these two categories have been adequately 3 addressed as discussed in letters to TVA (December 14, 1987, and August 24, 1987,respectively). Concerns in the ninth category, relating to intimidation, harassment, wrongdoing, or misconduct, will be investigated and the results will be reported separately by the'TVA Office of General Counsel or the TVA Office of Inspector General. The staff's review of TVA's handling of these concerns'is l

discussed in an October 8, 1987 letter to TVA.

On the basis of its review of the TVA employee concerns program, the NRC staff concluded in Volume 1 of NUREG-1232 that TVA now has a policy that p,romotes quality and safety, and that TVA has taken steps to ensure that this policy is understood by TVA employees and is strictly enforced. The actions taken by TVA to improve employee confidence define an acceptable program for dealing with l employee concerns. In combination with the other improvements in the nuclear program that TVA is implementing, these steps should improve the confidence of I employees in TVA's management. The staff considers effective and continuing implementation of the new employee concerns program necessary if TVA is to sig-nificantly change its performance record. The employee concerns special program completed its activities and was merged into the permanent employee concerns. ,

program on October 1, 1988.

The staff will continue to monitor program implementation and the effectiveness of actions taken by TVA to deter intimidation and har.assment.

l l

NUREG-1232, Vol. 2, Supp. 1 5-2

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6 ALLEGATIONS Many concerns about nuclear safety problems were voiced to TVA'and investigated under its employee concerns program; many concerns about nuclear safety and other issues were voiced directly to the NRC staff. In a number of instances, the technical content of these allegations was provided to TVA for inclusion into the employee concerns program. The NRC staff used TVA's. responses as well as independent reviews to evaluate the issues and corrective actions. The re-maining allegations will be handled by the staff in'accordance with established NRC policies for handling allegations. All potential nuclear safety-significant Sequoyah-related allegations were evaluated and resolved to the satisfaction of the NRC staff before the restart of Unit 1.

I NUREG-1232, Vol. 2, Supp. 1 6-1

g- - --

, c ug

'/Ob t

1

- , -n APPENdIXA.

LIST OF NRC CONTRIBUTORS M. Branch . Office'of Nuclear. Reactor Regulation Office of Nuclear Reactor Regulation "4 .P.'Cortland. ,

J. Donohew- ' Office ~of Nuclear Reactor Regulation i LJ.: Fair Office:of Nuclear Reactor Regulation i H. Garg: Office of. Nuclear Reactor Regulation j E.tGoodwin- :0ffice of Nuclear. Reactor Regulation- i P. Hearn" Office of Nuclear Reactor Regulation

.G. Hubbard- Office.of Nuclear ReactorLRegulation K. Jenison Office of' Nuclear Reactor Regulation '

1 E.- Marinos Office of Nuclear Reactor Regulation: ,

F. Paulitz Office of NuclearfReactor Regulation ^

i

'R. Pierson Office of Nuclear Reactor. Regulation T. Rote 11ai Office of Nuclear Reactor _ Regulation D. Smith .

Office of Nuclear Reactor Regulation R..Westcott- Office;of Nuclear Reactor Regulation- 1 c

.I i

-NUREG-1231,.Vol. 2, Supp. 1 1

APPENDIX B

' REFERENCES Industry Standards American Institute of Steel Construction (AISC),' Manual of Steel Construction, Seventh Edison, 1973.

American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessel Code.

-- ,Section III,'" Rules for Construction of Nuclear Power Plant-Components,"

~ Subsection NF, " Component Supports."

l Institute of Electrical and Electronics Engineers, Std 323-1974, Qualifying

' Class 1E Equipment for Nuclear Power Generating Station.

Institute of Nuclear Power Operations (INP0), Report 85-001, " Performance Objectives and Criteria for Operating and Near Term Operating License Plants" (Proprietary), January 1985.

H Technical Evaluation Report Franklin Research Center, " Review of Licensees' Resolution of Outstanding Issues From NRC Equipment Environmental Qualification Safety Evaluation Reports (F-11 and B-60), Tennessee Valley Authority, Sequoyah Nuclear Plant Unit 2," March 31, 1983.

TVA Letters Tennessee Valley Authority, November 1, 1985, letter from C. H. Dean to W. J.

Dircks (NRC), transmitting TVA Nuclear Performance Plan, Volumes 1 and 2.

-- , January 17, 1986, letter from J. A. Domer to H. Denton (NRC),

Subject:

" Welding Review Program Description."

-- , February 3,1986, letter from R. Shell to H. Denton (NRC),

Subject:

" Employee Concerns Program."

-- , March 10, 1986, letter from S. White to L. W. Zech (NRC), transmitting Revised Corporate Nuclear Performance Plan.

-- , July 17, 1986, letter from S. A. White to L. W. Zech (NRC), transmitting Sequoyah Nuclear Performance Plan and Revision 1 to Revised Corporate Nuclear Performance Plan.

-- , July 31, 1986, letter from S. A. White to L. W. Zech (NRC), transmitting Revision 2 of Revised Corporate Nuclear Performance Plan.

NUREG-1232, Vol. 2, Supp. 1 1 Appendix B

-- , August 18, 1986, letter from R. Gridley to B. J. Youngblood (NRC),

Subject:

" Interim Acceptance Criteria, Civil Engineering Programs."

-- , September 24, 1986, letter from R. Gridley to B. J. Youngblood (NRC),

Subject:

" Response to Inspection Report Item 86-20-09."

-- , December 4,1986, letter to L. W. Zech (NRC), transmitting Revision 3 to the Revised Corporate Nuclear Performance Plan.

-- , December 11, 1986, letter from R. Gridley to B. J. Youngblood (NRC),

Subject:

" Additional Information on Sequoyah Design Baseline and Verification Program."

-- , January 2,1987, letter from R. Gridley to B. J. Youngblood (NRC),

Subject:

" Containment Isolation Design Pertaining to Chemical and Volume Control System."

-- , January 14, 1987, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Interim Acceptance Criteria for Cable Tray Supports."

-- , January 23, 1987, letter from J. A. Domer to Document Control Desk (NRC),

Subject:

" Exemption From 10 CFR 50, Appendix A, General Design Criteria 55."

-- , January 28, 1987, letter from R. Gridley to B. J. Youngblood (NRC), Sub-ject: " Interim Acceptance Criteria for Small Bore Piping."

-- , January 30, 1987, letter from R. Gridley to Document Control Desk (NRC),

forwarding response to open items in welding review.

-- , February 3, 1987 letter from J. A. Domer to Document Control Desk (NRC),

Subject:

" Exemption From 10 CFR 50, Appendix A, General Design Criteria 55 and 56."

-- , February 4,1987, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Supplemental Items Interim Acceptance Criteria for Cable Tray Supports."

-- , March 2,1987, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Order Modifying Licenses (EA 85-49)."

-- , March 24,1987(a), letter from R. Gridley to S. Ebneter (NRC),

Subject:

" Surveillance Instruction Review Program."

-- , March 24,1987(b), letter from R. Gridley to S. Ebneter (NRC),

Subject:

" Compliance With 10 CFR 50.49, Environmental Qualification of Electrical Equip-ment Important To Safety For Nuclear Power Plants."

-- , March 26, 1987, letter from S. White to S. Ebneter (NRC), transmitting Revision 4 to Revised Corporate Nuclear Performance Plan.

-- , April 1,1987(a), letter from S. White to Document Control Desk (NRC),

transmitting Revision 1 to the Sequoyah Nuclear Performance Plan.

NUREG-1232, Vol. 2, Supp. 1 2 Appendix B

-- , April 8, 1987(a), letter from R. Gridley to Document Control Desk (NRC),

Subject:

"Sequoyah - Alternate Analysis Program Phase II."

-- , April 8,1987(b), letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Exemption From 10 CFR 50, Appendix A, General Design Criteria 55 and 56."

12, 1987, letter from R. Gridley to Document Control Desk (NRC), Sub-ject: MayPost-restart Scope and Schedule for the Design Baseline and Verification Program."

-- , May 15, 1987, letter from R. Gridley to Document Control Desk (NRC) forward-ing " Engineering Assurance Oversight Review Report - DBVP."

-- , July 2, 1987, letter from S. A. White to Document Control Desk (NRC), trans-mitting Revision 2 to the Sequoyah Nuclear Performance Plan.

-- , July 8, 1987, letter from R. Gridley to Document Control Desk (NRC), Sub-ject: " Leakage of Spray Behind the Crane Wall Following a Postulated Design Basis Accident."

-- , July 21, 1987, letter from L. M. Nobles to Document Control Desk (NRC),

transmitting Licensee Event Report 37-30, " Notification on FLAS-5 Fuses."

-- , July 31, 1987, letter from R. Gridley to Document Control Desk (NRC), Sub-ject: " Revised Cable Test Program."

-- , August 4, 1987, letter from R. Gridley to Document Contro' Desk (NRC),

Subject:

" Leakage of Spray Water Behind the Crane Wall Following a Design Basis Accident."

-- , August 10, 1987, letter from R. Gridiey to Document Control Desk (NRC),

Subject:

" Comments on Safety Evaluation Report (SER) - Short-Circuit Study, Medium Voltage (6.9 kV) System."

-- , August 18, 1987, letter from L. M. Nobles to Document Control Desk (NRC),

Subject:

" Reportable Occurrence Report SQR0 50-327/874."

-- , September 18, 1987, letter from R. Gridley to Document Control Desk (NRC) transmitting response to IE Bulletin 87-01.

-- , October 23, 1987, letter from R. Gridley to Document Control Desk (NRC) transmitting Supplemental EA Oversight Review Report for DBVP.

-- , November 20, 1987, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Main Steam Line Break Inside Ice Condenser Containments."

-- , November 24, 1987, letter from R. Gridley to Document Control Desk (NRC) transmitting Wyle test results.

-- , December 8, 1987, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Replacement Items Project (RIP) Seismic Adequacy Verification."

NUREG-1232, Vol. 2, Supp. 1 3 Appendix B

1

-- , December 10,.-1987, letter from S. A. White to Document Control Desk (NRC) transmitting Revision 5 to Revised Nuclear Performance Plan. l

. -- , December 15, 1987, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Design Control Program."

-- , December 28, 1987, letter from S.-A. White to S. Ebneter (NRC),

Subject:

"Silcone Rubber Insulated Cable Issue Resolution."

-- , February 10,.1988(a), letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Main Steam Line Break (MSLB) Inside Ice-Condenser Containment."

-- , February 10, 1988(b), letter.from R. Gridley to Document Control' Desk (NRC),

Subject:

" Replacement Items Project Program Plan."

-- , February 29, 1988, letter.from R. Gridley to Document Control Desk (NRC),

Subject:

" Revised Instrumentation Accuracy Calculations."'

-- , March.-1, 1988, letter from R. Gridley to Document Control' Desk (NRC), Sub-ject: " Technical Specification Change 87-44."

-- , March 3,1988, letter from R. Gridley to Document Control Desk (NRC), Sub-ject: " Diesel Generators (DGs) - Operability Analysis."

-- , March 10, 1988, letter from R. Gridley to Document Control Desk (NRC), Sub-ject: " Diesel Generator Voltage and Margin Analysis Revisions."

-- , March 31, 1988, letter from R. Gridley to Document Control Desk (NRC), Sub-ject: " Unit 1 Restart Plan."

-- ,.May 4,1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

"TVA Topical Report, TVA-TR75-1A."

-- , May' Revision 3 to the Sequoyah Nuclear Performance Plan (SNPP)."9, 19 ject:

-- , June 1,1988, letter from R. Gridley to Document Control Desk (NRC), Sub-ject: " Request for Additional Information Regarding Main Steam Line Break in Ice. Condenser Plants."

-- , June 10, 1988, letter from R. Gridley to Document Control Desk (NRC), Sub-ject: " Appendix R - Response to Request for Information."

-- , June 13, 1988, letter from R. Gridley to Document Control Desk (NRC), Sub- .

ject: " Staffing of Fire Brigade."  !

1

-- , July 6,1988, letter from R. Gridley to Document Control Desk (NRC), Sub-  !

ject: "40 year Qualification Testing of Silicone Rubber Insulated Cables."

l -- , July 11, 1988, letter from M. J. Ray to Document Control Desk (NRC), Sub-l ject: " Exemption From Appendix J, T pe C Leak Testing - Residual Heat Removal Spray and Containment Spray Systems.y'

)

NUREG-1232, Vol. 2, Supp. 1 4 Appendix B

-- , July 28, 1988, letter from R. Gridley to Document Control Desk (NRC), Sub-ject: " Engineering Assurance (EA) Oversight Review for the Design Baseline ,

and Verification Program." l

-- , August 4, 1988(a), letter frcm R. Gridley to Document Control Desk (NRC),

Subject:

" Electrical Calculation Program Status."

-- , August 4,1988(b), letter from R. Gridley to Document Control Desk (NRC),

Subject:

Final Report on NRC Bulletin 79-14 for TVA Sequoyah Nuclear Plant Unit 1 and Common Piping."

-- , August 8, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Exemption from Appendix J, Type C, Leak Testing - Residual Heat Removal Spray and Containment Spray Systems."

-- , August 10, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Replacement Items Program Supplemental Program Plan."

-- , August 11, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Diesel Generator Load Analysis Results."

-- , August 19, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Visual Inspection of Containment."

-- , August 31, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Main Steam Line Break Inside Ice Condenser Containment."

-- , Septemer 15, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Electrical Calculation Program Final Status (Unit 1)."

\

-- , September 19, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Supplemental Engineering Assurance Oversight Review Report for the

( Design Baseline and Verification Program."

-- , September 22, 1988, letter from R. Gridley to Document Control Desk (NRC), i

Subject:

" Request for Additional Information Regarding Main Steam Break in l Ice Condenser Plants."

-- , September 28, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Comparison of the Sequoyah Diesel Generator Load Analysis Results."

-- , September 30, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Clarification of the July 21, 1988 TVA/NRC Meeting on Phase II of the Design Baseline and Verification Program."

-- , October 13, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Temporary Deviation Request From Requirements of 10 CFR 50, Appendix R, Section III.G.2."

-- , October 20, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Temporary Deviation Request From Requirements of 10 CFR 50, Appendix R, Section III.G.2."

NUREG-1232, Vol. 2, Supp. 1 5 Appendix B L

-- , October 26, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Clarification of Design Baseline and Verification Pro With the Equipment [ Environmental] Qualification (EQ) Program." gram Interface

-- , October 31, 1988 letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Clarification of the 40-Year Qualification Testing of Silicone Rubber Insulated Cable."

-- , November 2,1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Compliance With 10 CFR 50.49 Environmental Qualification of Elec-trical Equipment Important to Safety."

-- , November 9,1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

" Augmented and Accelerated In-Service Inspection Program for Unit 2."

-- , November 21, 1988, letter from R. Gridley to Document Control Desk (NRC),

Subject:

"NRC Inspection Report 50-327, 328/88-44."

NRC Letters U.S. Nuclear Regulatory Commission, August 10, 1984, letter from J. P. O'Reilly to H. Parris (TVA),

Subject:

" Confirmatory Action Letter on Appendix R Compliance."

-- , September 17, 1985, letter from W. Dircks to C. Dean (TVA) transmitting staff concerns and 10 CFR 50.54(f) issues.

-- , May 29, 1986, letter from B. Youngblood to S. White (TVA) regarding deviation requests from Appendix R.

-- , October 6, 1986, letter from B. Youngblood letter to S. A. White (TVA) regarding deviation requests from Appendix R.

-- , June 9,1987, letter from J. A. Zwolinski to S. A. White (TVA),

Subject:

" Restart Criteria."

-- , August 24, 1987, letter from J. A. Zwolinski to S. A. White (TVA),

Subject:

" Industrial Safety Element Report Safety Evaluation."

-- , September 30, 1987, letter from J. A. Zwolinski to S. A. White (TVA),

Subject:

" Employee Concern Program Safety Evaluation."

-- , October 6,1987, letter from J. A. Zwolinski to S. A. White (TVA),

Subject:

" Employee Concerns Special Program."

-- , October 8,1987, letter from S. Ebneter to S. A. White (TVA),

Subject:

" Employee Concerns Related to Harassment and Intimidation (H&I), Wrongdoing and Misconduct."

-- , December 14, 1987, letter from G. G. Zech to S. A. White (TVA),

Subject:

" Safety Evaluation for Management and Personnel of the Employee Concern Program for Sequoyah."

NUREG-1232, Vol. 2, Supp. 1 6 Appendix B

-- , February 23, 1988, letter from S. D. Ebneter to S.A. White (TVA), "Non-Nuclear Heatup for Sequoyah Unit 2 Prior to Restart."

-- , March 11, 1988, letter from G. G. Zech to S. A. White (TVA),

Subject:

" Preliminary Safety Evaluation on the Tennessee Valley Authority Employee  !

Concern Element Reports." i

-- , March 25, 1988, letter from S. D. Ebneter to S. A. White (TVA),

Subject:

" Revised Safety Evaluation on the Tennessee Valley Authority Sequoyah Nuclear Performance Plan." j

-- , March 31, 1988, letter from S. D. Ebneter to S. A. White (TVA),

Subject:

l

" Modification of Order EA 85-49." l

-- , May 18, 1988 letter from S. D. Ebneter to S. A. White (TVA),

Subject:

" Safety Evaluation Report on the Tennessee Valley Authority Sequoyah Nuclear Performance Plan."

-- , May 25, 1988, letter from S. D. Ebneter to S. A. White (TVA),

Subject:

)

" Qualification Testing of Installed Silicone Rubber Insulated Cable in j Containment."

-- , June 30, 1988, letter from S. Black to S. A. White (TVA),

Subject:

" Administrative Controls Technical Specification Changes."

-- , September 21, 1988, letter from S. D. Richardson to S. A. White (TVA),

Subject:

Preliminary Safety Evaluation on the Tennessee Valley Authority Sequoyah Nuclear Performance Plan."

-- , September 22, 1988, letter from J. G. Partlow to S. A. White (TVA),

Subject:

" Definition of Operable and Exemption from Appendix J Type C Testing for the -

Containment and Residual Heat Removal Spray System Check Valves."

-- , November 3, 1988, letter from S. D. Richardson to S. A. White (TVA),

Subject:

" Revision 1 of the Preliminary Safety Evaluation on the Tennesssee Valley Authority Sequoyah Nuclear Performance Plan."

-- , November 4,1988(a), letter from S. Black to S. A. White (TVA)

Subject:

" Safety Evaluations on the Tennessee Valley Authority Employee Concern Element Reports."

-- , November 4,1988(b), letter from S. D. Richardson to S. A. White (TVA),

Subject:

" Deviation From 10 CFR Part 50, Appendix R."

-- , November 7,1988, letter from S. Black to S. A. White (TVA),

Subject:

" Diesel Generator Improvement Plan."

-- , November 17, 1988, letter from J. G. Partlow to S. A. White (TVA),

Subject:

1

" Qualification Testing of Installed Silicone Rubber Insulated Cables in Containment."

i NUREG-1232, Vol. 2, Supp. 1 7 Appendix B j

I

NRC Meeting Summaries

-- , July 24, 1986, NRC summary of July 17 and 18,1986 meeting,

Subject:

" Design Baseline and Verification Program and the TVA Systems and' Support Acceptance Criteria."

-- , May 4,1988, NRC summary of April 14, 1988 meeting at NRC headquarters, Rockville, Maryland,

Subject:

" Discuss Differences Between Sequoyah Units 1 and 2 in the Sequoyah Nuclear Performance Plan."

-- , July 1, 1988, NRC summary of June 22, 1988 meeting at NRC headquarters, Rockville, Maryland,

Subject:

"TVA Commitments for Sequoyah Unit 2."

-- , August 4,1988, NRC summary of July 21, 1988 meeting at NRC headquarters, l Rockville, Maryland,

Subject:

" Phase II of the Design Baseline and Verification Program."

t

- , September 16, 1988, NRC summary of September 8, 1988 meeting at NRC sieadquarters, Rockville, Maryland,

Subject:

" Changes to the TVA Conditions Adverse to Quality Program at Sequoyah."

NRC Reports i

-- , NUREG-0011, " Safety Evaluation Report of the Sequoyah Nuclear Plant Units 1 and 2," January 1976.

l

-- . M EG-0578, "TMI-2 Lessons Learned Task Force: Status Report and Short- I Term Recommendations," July 1979.

-- , NUREG-0588, " Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment," November 1979.

-- , NUREG-0737, "ClarificatM of TMI Action Plan Requirements," November 1980.

-- , NUREG-0800, " Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," LWR Edition, July 1981.

-- , NUREG-1232, Vol. 1, " Safety Evaluation Report on Tennessee Valley Authority:

Revised Corporate Nuclear Performance Plan," July 28, 1987.

-- , NUREG-1232, Vol. 2, " Safety Evaluation Report on Tennessee Valley Authority:

Sequoyah Nuclear Performance Plan," May 13, 1988.

Westinghouse Reports l

Westinghouse Electric Corporation, WCAP-10986, " Ice Condenser Drain Test Results, Data Analysis and Development of Drain Flow Models for LOTIC-III Ice Condenser Code" (Proprietary), November 1985.

-- , WCAP-10988, " COBRA-NC, Analysis for Main Steamline Break in Catawba Unit 1 Ice Condenser Containment" (Proprietary), November 1985.

NUREG-1232, Vol. 2, Supp. 3 8 Appendix B

_ _ _ _ _ _ _ O

I

• 4+ 0a f NUM8 t

• fa *Fm'a er rioC. eaa vos nr s , s a.y/ -

NRC PORM 238 . U S. r uCLEM L81UL1 TORY COMMisBION

" NUREG-1232 2o 3E2 ' BIBLIOGRAPHIC DATA SHEET Vol. 2, Supp. 1 see mer:UcticN oN t i aevias, 3 LEAvgeLANn

2. TITLS iND SUSTITLE I SOfety Evaluation Report on Tennessee Valley Authority: Sequoyah Nuclear Performance Plan . OAT ..,0 YCO ,L.Teo Sequoyah Unit 1 Restart MONY-l ViAa

.uT ,.O. ,,,

January 1989 6 DATE atPORT ISSUED MONTH vtAR January 1989

~

8 PROJECT /T A5KMORE UNIT NUM86R 7 P4JORMeNG OmGANrI ATION NAME AND MAILtNG ADDRES$ (#wde,se te Coses Ar ociate Director for Special Projects ,,, ,,,,,,,,,,,

Office of Nuclear Reactor Regulation q U.S. Nuclear Regulatory Commission

/

Wn::hington, D.C. 20555 f ii. TvrtO,ae, oaf io .,0N.O..No Oac,ANa ATiON AM *No MA,L No Aoonass ,,,,,,. i. Co.,

Regulatory Same as 7 above . n a,Oo cove neo ,,-, .. . ,

12 SUPPLEMENT Anv NOTES Docket Nos. 50-327/328 13 ASST ACT (20D worss on ,ess/

The Safety Evaluation Report (SER) on the Sequoyah Nuclear Performance Plan, NUREG-1232, Volume 2, was based on the information submitted by the Tennessee Valley Authority (TVA) in its Sequoyah Nuclear Performance Plan (SNPP), through Revision 2, and on supporting documents. It was issued on May 18, 1988 by the U.S. Nuclear Regulatory Commission staff for the restart of Sequoyah Unit 2. The SNPP addresses the plant-specific concerns requiring resolution before startup of either of the Sequoyah units. In particular, the SER addressed required actions for Unit 2 restart.

l In most cases, the programmatic aspects for Unit I are identical to those for Unit 2.

TVA described the differences in programs between Unit 1 and Unit 2 in Revision 3 of th SNPP. This was stbmitted by TVA in its letter dated May 9, 1988. Where the Unit A program is different, the staff's evaluation is provided in this supplement to the staff's SER in NUREG-1232, Volume 2.

On the basis of its review, the staff concludes the Sequoyah-specific issues have been resolved to the extent that would support the restart of Sequoyah Unit 1.

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