Text

Safety Evaluation Report Related to the Operation of Comanche Peak Steam Electric Station,Units 1 and 2.Docket Nos. 50-445 and 50-446.(Texas Utilities Electric Company,Et Al.)
	ML20055C362
Person / Time
Site:	Comanche Peak
Issue date:	02/28/1990
From:	; Office of Nuclear Reactor Regulation
To:	;
References
	NUREG-0797, NUREG-0797-S23, NUREG-797, NUREG-797-S23, NUDOCS 9003070170
	Download: ML20055C362 (102)
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NUREG-0797 Supplement No. 23

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Safety Evaluation Report related to the operation of Comanche Peak Steam Electric Station, Units 1 and 2 Docket Nos. 50-445 and 50-446 i

Texas Utilities Electric Company, et al.

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U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation February 1990 s

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l AVAILABILITY NOTICE jl Availability of Reference Materials Cited in NRC Publications Most documents cited in NRC publications will be available from one of the following sources:

1.

The NRC Public Document Room 2120 L Street, NW, Lower Level, Washington, DC r

20555 2.

The Superintendent of Documents, U.S. Government Printing Office, P.O. 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 publica--

tions, it is not intended to be exhaustive.

Referenced documents available for inspection and copying for'a fee from the NRC Public Document Room include NRC correspondence and internal NRC memoranda; NRC Office of Inspection and Enforcement bulletins, circulars, information notices, inspection and investi-gation notices: Licensee Event Reports; vendor reports and correspondence; Commission papers; and applicant and licensee documents and correspondence, j

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

Program: formal NRC staff and contractor reports, NRC-sponsored conference proceed-ings, and NRC booklets and brochures. Also available are Regulatory Guides, NRC regula-tions in the Code of Federal Regulations, and Nuclear Regulatory Commission issuances.

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

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from these libraries, j

Documents such as theses, dissertations, foreign reports and translations, and non-NRC conference proceedings are available for purchase from the organization sponsoring the publication cited.

Single copies of NRC draft reports are available free, to the extent of supply, upon written request to the Office of information Resources Management, Distribution Section, U.S.

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National Standards, from the American National Standards institute,1430 Broadway, New York, NY 10018.

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O NUREG-0797 Supplement No. 23 Safety Evaluation Report l-related to the operation of Comanche Peak Steam Electric Station, I

Units 1 and 2 Docket Nos. 50-445 and 50-446 Texas Utilities Electric Company, et al.

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U.S. Nuclear Regulatory Commission i

Omce of Nuclear Reactor Regulation February 1990

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ABSTRACT Supplement 23 to the Safety Evaluation Report' related to the operation of' the Comanche Peak Steam Electric Station (CPSES), Units 1 and 2 (NUREG-0797), has been prepared by the Office of Nuclear Reactor Regulation of the U.S. Nuclear Regulatory Commission (NRC).

The facility is located in Somervell County, Texas, approximately 40 miles southwest of Fort Worth, Texas.

This supplement reports the status of certain issues that had not been resolved when the Safety Evaluation Report and supplements 1, 2, 3, 4, 6, 12, 21, and 22 to that report were published.

This supplement also includes the evaluations for licensing items resolved since Supplement 22 was issued.

Supplement.5 has not been issued.

Supplements 7, 8, 9, 10, and 11 were limited to the staff evaluation of allegations investigated by the NRC Technical Review Team.

Supplement 13 presented the staff's evaluation of the Comanche Peak Re-i sponse Team (CPRT) Program Plan, which was formulated by the applicant to resolve various construction and design issues raised by sources external to TV Electric.

Supplements 14 through 19 presented the staff's evaluation of the CPSES Correc-tive Action Program:

large-and small-bore piping and pipe supports (Supple-ment 14); cable trays an! cable tray hangers (Supplement 15); conduit supports (Supplement 16); mechanical, civil / structural, electrical, instrumentation and controls, and systems portions of the heating, ventilation, and air conditioning (HVAC) system workscopes (Supplement 17); HVAC structural design (Supplement 18);

and equipment qualification (Supplement 19).

Supplement 20 presented the staff's evaluation of the Comanche Peak Response Team implementation of the CPRT Program

'a Plan and the issue specific action plans, as well as the CPRT's investigations to determine the adequacy of various types of programs and hardware at CPSES.

l Items identified in Supplements 7, 8, 9, 10, 11, and 13 through 20 are not in-cluded in this supplement, except to the extent that they affect the applicant's Final Safety Analysis Report.

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b TABLE OF CONTENTS I

PaSe ABSTRACT...............................................................-... iii 1 INTRODUCTION AND GENERAL DESCRIPTION OF PLANT.......................

1-1 1.1 Introauction.................................................... 1 1.4 Identification of Agents and Contractors.........................

1-4 1.7 Summa ry o f Ou ts tandi ng I s s ue s...................................

1-4 1.8 Confirmatory Issues.............................................

1-4 1.9 License Conditions...............................................

1-5 2 SITE CHARACTERISTICS.................................................

2-1 2.5 Geology and Seismology.........................................

2-3 2.5.1 Geologic Information.....................................

2-1 3 DESIGN OF STRUCTURES, COMPONENTS, EQUIPMENT, AND SYSTEMS.............

3-1 3.3 Wind and Tornado Loadings.......................................

'3-1 3.3.2 Tornado Design Criteria..................................

3-1 3.6 Protection Against Dynamic Effects Associated With the Postulated Rupture of Piping....................................

3-1 3.6.1 Inside Containment.......................................

3-1 3.6.1.2 Systems Other Than RCS Main Loop.................

3-1 3.6.1.3 Thermal Stratification of Pressurizer Surge 1

Line (NRC Bulletin 88-11)........................

3-5 1

3.7 Seismic Design..................................................

3-10 3.7.1 Seismic Input............................................

3-10 3.8 Design of Seismic Category I Structures.........................

3-11 3.8.1 Concrete Containment.....................................

3-11 3.8.3 Other Seismic Category I Structures......................

3-12 3.9 Mechanical Systems and Components...............................

3-12 3.9.1 Special Topics for Mechanical Components.................

3-12 3.9.2 Dynamic. Testing and Analysis.............................

3-14 3.9.3 ASME Code Classes 1, 2, and 3 Components, Component Supports, and Core Support Structures....................

3-15 3.9.6 Inservice Testing of Pumps and Valves....................

3-18 Co,manche Peak SSER 23 v

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.'I TABLE OF CONTEKIS (Continued)-

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-i P_ge 4 -REACTOR.......................................................-........

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4 4,2 Fuel Design....................-..................................

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4. '.1 Description..................................-..........-..

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4.E 3 Mechanical Performance................................... 1 1

d, 4.3. Nuclear Design..................................................' i4-2

-4.3.2. Design Description....................................... 2-1 3

4.3.2.7 Vessel-Irradiation..............................-

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a 4.4. Thermal-Hydraulic' Design......................................

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'4.4.3 Thermal-Hydraulic Design Comparison......................

4-2' 5 REACTOR COOLANT SYSTEM..........................-......................

5-1 5.4 Component and Subsystem Design...................................

25-1 5.4.3 Residual Heat RemovalLSystem..............................

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5.4.3.3 Loss of Decay Heat Removal (Generic Letter 88-17)_..........................

~5-l' 6 ENGINEERED SAFETY FEATURES.............................................

_6-1 6.2 Containment System............................................... 1-6.2.3 Contai nment I sol ati on System..............................

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6. 4 Control Room Habitability.....................................-... 1:

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6.5 Engineered

Safety Features Materials........................;....

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6.5.1 System Description and Evaluation ~........................

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6.5.1.1 Fuel Handling Building Ventilation System.......--

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6.5.2 Containment Spray System'.................................

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7 INSTRUMENTATION AND CONTROLS..........................................

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7. 2 R e a c to r T r i p Sy s t em.............................................

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7.2.1 Description............................................-..

7 7.2.6 Generic. Implications of-ATWS Events at-the Salem Nuclear Power Plant (Generic Letter 83-28)...............

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TABLE OF CONTENTS (Continued)

.Page 7.5 -Information Systems Important to Safety..........................

7-5.

7.5.2 Po s tacci de nt Moni tori ng......_.............................

7 7.5.4 ~ Conclusions.......................-..........-.............

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AUXILIARY SYSTEMS.....................................................

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9.2 Water Systems....................................................

9-1 9.2;1 Station Service Water System...............................

9-1 9.2.2 Reactor Auxiliaries Cooling Water. System-(Component Cooling Water System)......................................

9-1; 9.2.6 Condensate Storage Facility...............................-i9-1 9.3 Process Auxiliaries..............................................:

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9. 3.1. Compres s ed Ai r Sy s tem..................................... 1 9.4 Heating, Ventilation, and Air Conditioning (HVAC) Systems........

9-2 9.4.5 Miscellaneous Building Ventilation Systemsc...............

9-2 9.5 Other Auxiliary Systems........-.................................

9-2 9.5.1 F i re P ro te c t i o n........................................... ; 9-2 9.5.1.2 Administrative Controls......................... 2' 9.5.1.4 General Plant Guidelines........................

9 9.5.1.5 Fire Detection and= Suppression..................

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9.5.3 Lighting System..........................................

9-3 11 RADI0 ACTIVE WASTE MANAGEMENT..........................................

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11.3 Process and Effluent Radiological Monitoring Systems............

11-1 13 CONDUCT OF 0PERATIONS............................................._....

13-1 13.1 Organizational Structure and Qualifications'....................

13-1 13.1.2 Operating Organization................................. ~13-1 13.1.2.1 Plant Staff ~..................................

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14 INITIAL TEST PROGRAM................................................. 1 i

15 ACCIDENT ANALYSIS.....................................................15-1 i

15.2 Moderate Frequency Transients.................................. 1 15.2.1 Increased Cooling Transients...........................

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TABLE OF CONTENTS (Continued)

.Page 15.2.3 Increased Core Reactivity Events.......................

15-1 15.2.3.1 Boron Dil ution Events.........................

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15.3 Infrequent Transients and Postulated Accidents.................

15-1 15.3.7 Reactor Coolant Pump Locked Rotor Accident.............

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15.3.8 Loss-of-Coolant Accident...............................

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15.4 Radiological Consequences of Design-Basis Accidents............

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15.4.4 Steam Generator Tube Rupture Accident...................

15-2 16 TECHNICAL SPECIFICATIONS.............................................

16-l' 22 THI-2 REQUIREMENTS...................................................

22-1 22.1 Introduction...................................................

22-1 22.2 Discussion of Requirements.....................................

22-1 I.A.1.1 Shi f t Technical Advi sor.............................

22-1 1.A.2.3 Administration of Training Programs for Licensed.

Operators...........................................

22-1 I.C.5 Procedures for Feedback of Operating Experience to Plant Staff......................................

22-2 I.C.7 NSSS Vendor Review of Procedures....................

22-2 II.B.3 Postaccident Sampling Capability'....................

22-2 II.B.4 Training for Mitigating Core Damage.................

22-2 II.E.4.2 Containment Isolation Dependability.................

22-3 II.F.2 Instrumentation for the Detection of Inade i

Core Cooling.............................quate-22-4 II.K.1 IE Bulletins on Measures To Mitigate Small-Break LOCAs and Loss-of-Feedwater Accidents................

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III.D.1.1 Integrity of Systems Outside Containment Likely-To Contain Radioactive Materia 1......................

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i TABLES 4.1 R e a c tor de s i g n comp a ri s o n...........................................

4-3 11.6 Process and e f fl uent moni tors.......................................

11-2 APPENDICES i

A CONTINUATION OF CHRON0 LOGICAL LISTING 0F CORRESPONDENCE B BIBLIOGRAPHY D LIST OF PRINCIPAL CONTRIBUTORS E ERRATA TO COMANCHE PEAK SAFETY EVALUATION REPORT AND SUPPLEMENTS 3

Comanche Peak SSER 23 viii

1 INTRODUCTION AND GENERAL DESCRIPTION OF PLANT 1.1 Introduction The Nuclear Regulatory Commission (NRC) Safety Evaluation Report (SER), NUREG-0797, on the application of the Texas Utilities Generating Company (TUGCO)*-(the applicant) for a license to operate the Comanche Peak Steam Electric Station (CPSES), Units 1 and 2, was issued in July 1981.

Since then the following sup-plements have been issued:

Supplement 1 (SSER 1) was issued in October 1981.

It described the resolu-tion of a large portion of the outstanding and confirmatory issues identi-I fied in the SER.

Supplement 2 (SSER 2) was issued in January 1982.

It included the report' of the Advisory Committee on Reactor Safeguards (ACRS) to the NRC Chair-man by letter dated November 17, 1981, which was appended as Appendix F.

Applicant and staff responses to comments by the ACRS were also included.

Supplement 3 (SSER 3) was issued in March 1983.

It addressed outstanding and confirmatory issues resolved since SSER 2.was issued. The staff's evaluation of the applicant's emtrgency plans was also described.

Supplement 4 (SSER 4) was issued in.Novemb'er 1983.

It included the staff's evaluation report on design modifications made to the Westinghouse model 04 and D5 steam generators installed at CPSES.

Supplement 5 (SSER 5) has been cancelled.

It was to 'have been limited ex-clusively to the CYGNA Independent Assessment Program.

The issues from the 1

CYGNA Independent Assessment Program-have been addressed in the applicant's Corrective Action Program.

The staff's evaluations of-the CYGNA-issues are provided in the respective SSERs (14-19) for each Corrective Action Program 1

design workscope.

Therefore, the planned supplement was never issued.

l Supplement 6 (SSER 6) was issued in November 1984.

It addressed outstand-1 ing and confirmatory issues resolved since SSER 4 was issued.

Noteworthy

. l in this supplement was a partial exemption to General Design Criterion i

(GDC) 4 of Appendix A to Part 50 of Title 10 of the Code of Federal Regula--

i' tion,s (10 CFR Part 50) deleting the requirement for installing jet impinge-ment shields for the Unit 1 primary coolant loop piping at postulated break 1

locations.

t Supplement 7 (SSER 7) was issued in January 1985..It was limited exclu-i sively to the staff's evaluation of allegations investigated by the NRC's Technical Review Team (TRT) pertaining to plant electrical / instrumentation systems and testing programs.

0n January 16, 1987, TUGC0 informed the NRC that it had adopted a new corporate i

signature and would be known as TV Electric'(Texas Utilities Electric Company).

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Supplement 8 (SSER 8) was issued in February 1985.

It was limited exclu-sively to the staf f's evaluation of allegations investigated by the TRT pertaining to the plant's civil / structural and other miscellaneous con-struction and plant-readiness testing items Supplement 9 (SSER 9) was issued in March 1985.

It was limited exclusively to the staff's evaluation of coating requirements inside cort 41nment and allegations of coating deficiencies investigated by the TRT.

Supplement 10 (SSER 10) was issued in April 1985.

It was limited exclu-sively to the staff's evaluation of allegations investigated by the TRT pertaining to the mechanical and piping areas.

Supplement 11 (SSER 11) was issued in May 1985.

It was limited exclusively to the staff's evaluation of allegations investigated by the TRT pertaining to quality assurance / quality control (QA/QC) practices in the design and construction of CPSES.

Supplement 12 (SSER 12) was issued in October 1985.

It updated the SER further by providing the results of the staff's review of information sub-mitted by the applicant by letter and in Final Safety Analysis Report (FSAR) amendments -ddressing several of the issues and license conditions listed in Sections 1.7, 1.8, and 1.9 of the SER that were unresolved at the time SSER 6 was issued.

SSER 12 also identified several new issues that had been identified since SSER 6 was issued and that were unresolved.

Supplement 13 (SSER 13) was issued in May 1986.

It presented the staff's evaluation of the Comanche Peak Response Team (CPRT) Program Plan, which was formulated by the applicant to resolve various design and construction issven raised by the Atomic Safety and Licensing Board, allegers, the Cit-izens Association for Sound Energy (CASE), and NRC inspections, as well as those raised by CYGNA Energy Services during its independent design assessment.

Supplement 14 (SSER 14) was issued in March 1988.

It presented the staff's evaluation of the applicant's Corrective Action Program related to large-and small-bore piping and pipe supports.

Supplements 15 and 16 (SSERs'15 and 16) were issued in July 1988; Supple-ments 17 through 19 (SSEks 17-19) were issued in November 1988.

They pre-liented the staf f's evaluation of t.he Corrective Action Program as related to cable trays and cable tray ha wers (SSER 15); conduit supports (SSER d);

the mechanical, civil / structural, electrical, and instrumentation and con-trols workscopes, and systems portions of the heating, ventilation, and C c conditioning (HVAC) system workscope (SSER 17); HVAC structural design (SSER 18); and equipment qualification (SSER 19).

Supplement 20 (SSER 20) was issued in November 1988.

It presented the staff's evaluation of the CPRT implementation of the CPRT Program Plan and the isste specific action plans, as well as the CPRT's investigations to determine the adequacy of various types of programs and hardware at CPSES.

Supplement 21 (SSER 21) was issued in April 1989.

It updated the SER fur-ther by providing the results of the staff's review of information that the Comanche Peak SSER 23 1-2

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applicant submitted by letter and in FSAR amendments.

It addressed several of the issues and license conditions listed in Sections 1.7, 1.8, and 1.9 1

of the SER that were unresolved at the time SSER 12 was issued.

Of note i

from an administrative standpoint SSER 21 renumbered items appearing in Sections 1.7, 1.8, and 1.9, and deleted all items that were previously re-solved but listed in SSER 12.

Supplement 22 was issued in January 1990.

It updated the SER by presenting the results of the staff's review of information that the applicant submit-ted by lotter and in FSAR amendments.

The staff review addressed several of the issues and license conditions listed in Sections 1.7, 3.8, and 1.9 of the SER that were unresolved at the time SSER 21 was issued.

The purpose of SSER 23 is to..spport issuance of the low power operating license for CPSES Unit 1 and to document resolution of the outstanding issues remaining from SSER 22 as indicated in Section 1.7.

Confirmatory issues remaining at the time of license issuance,~as well as proposed license conditions, are listed in Sections 1.8 and 1.9, respectively.

During the review of the amendments to the FSAR, the staff has developed additional conclusions and findings which do-not affect previous outstanding issues and confirmatory issues, and which will-be reported in a future supplement to the SER.

Each section or appendix of this supplement is numbered and titled so that it corresponds to the section or appendix of the SER that has been affected by the i

staff's additional evaluations and, except where specifically noted, does not replace the corresponding SER section or appendix.

A new section (3.6.1.3),

whien was not part of the original SER or its supplements, has been added.

Ap-pendix A is a continuation of the chronology of correspondence between the NRC and the applicant that updates the correspondence listed in the SER and in SSERs 1 through 22.

Appendix B includes references other than NRC documents and correspondence cited in this supplement.* Appendix 0 contains'a list of principal contributors to this supplement.

Apprndix E contains a list of er-rata identit wd in the SER and subsequent supplements.

No changes were made to SER Appendices C, F, G, H, I, J, K, L, M, N, 0, P, Q, R, S, T, U. V, W, X, Y, Z, AA, BB, CC, or DD in this supplement.

Management and coordination of all the outstanding regulatory actions for CPSES are under the overall direction of Mr. Christopher I. Grimes, the NRC Comanche Peak Project Division Director.

Mr. Grimes may be contacted by calling (301) 492-3299 or by writing to the following address:

Mr. Christopher I. Grimes Comanche Peak Project Division Office of Nuclear Reactor Regulation Mail Stop 7H-17 U.S. Nuclear Regulatory Commission Washington, D.C.

20555 Copies of this supplement are available for public inspection at (1) the NRC's Public Document Room at 2120 L Street, N.W., Washington, D.C. 20555; (2) the

Availability of all material cited is described on the inside front' cover of this document.

Comanche Peak SSEo 23 1-3 i

Local Public Document Room, located at the Somervell County Public Library on the Square, P.O. Box 1417 Glen Rose Texas 76043; and (3) the mini Local Public Document Room at the University of Texas at Arlington Library, 701 South Cooper, P.O. Box 19447, Arlington, Texas 76019.

1.4 Identification of Agents and Contractors As discussed in SSER 22, in March 1989, TV Electric entered into an agreement with Tex-La Electric Cooperative of Texas, Inc. (Tex-La) under which TV Elec-tric would purchase Tex-La's 2.17 percent ownership interest in the Comanche Peak Steam Electric Station (CPSES).

The staff ist.ued amendments to the con-struction permits on August 29, 1989* authorizing the transfer.

The transfer of Tex-La's ownership interest to TU Electric was completed on February 1,1990 and Tex-La is no longer listed as an owner of the CPSES.

Until the completion of the 6.2 percent ownership interest transfer from Texas Municipal Power Agency (TMPA) to TV Electric, as discusse( in SSER 22**, TMPA is still listed as an applicant.

With the completion of the TMPA transfer, TV Electric's aggregate interest in CPSES will be 100 percent.

N 1.7 Summary of Outstanding Issues Section 1.7 of the SER, as supplemented, identified a total of three outstanding issues at the time SSER 22 was issued.

Those issues that were resolved in pre-vious supplements were not listed in SSER 22.

As outstanding issues are re-solved, they will be dropped from the list in this section.

The following outstandit0 issues from SSER 22 are resolved in this supplement and will be dropped from the list of outstanding issues:

(1) Application of leak-before-break methodology to reactor coolant system (RCS) branch lines (Section 3.6.1.2)

(2) Accident monitoring design--comparison to Regulatory Guide 1.97, Revi-sion 2 (Section 7.5.2)

(3) Generic implication of ATWS events, Generic Letter 83-28 (Section 7.2.6)

There are no outstanding issues remaining at this time.

1.8 Cont irmatory Issues Section 1.8 of the SER, as supplemented, identified a total of four confirmatory issues at the time SSER 22 was issued.

Those issues that were resolved in pre-vious supplements were not listed in SSER 22.

As confirmatory issues are re-solved, they will be dropped from the list in this section.

The following confirmatory issue from SSER 22 is resolved in this supplement and will be dropped from the list of confirmatory issues:

The amendment for Unit 2 (CPPR-127) was reissued on September 14, 1989 to correct an administrative error.

- This transfer is taking place in 10 installments.

Comanche Peak SSER 23 1-4

(1) Containment isolation dependability-purge valve operability analysis LOCA-related dynamic loads (Section 22.2, II.E.4.2)

Confirmatory issues that are currently outstanding are listed below.

The staff will address resolution of these issues in a future supplement to the SER.

l (1) Inservice inspection program for compliance with 10 CFR 50.55a(g) to be submitted within six months of fullipower license (Sections 5.2.4.1 and l

6.6.1) l (2) Submittal of first-cycle N-16 transit time flow meter performance data to NRC for review (Section 7.2.1) r l

(3) Performance of boiling-water reactor and pressurized-water reactor relief and safety valves for Unit 2 (Section 22.2, 11.D.1) i (4) If necessary, TV Electric must docket a new plant-specific worst-case scenario after completion of the Westinghouse Owner's Group generic analy-sis of the uncovered steam generator tube rupture event (Section 15.4.4).

1. 9 License Conditions i

In Section 1.9 of SSER 22, the staff identified four proposed license conditions.

Those license conditions that were resolved in previous supplements were not l

listed in SSER 22.

As proposed license conditions are resolved, they will be dropped from the list in this section.

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The following proposed license condition from SSER 22 is resolved in this sup-plement and will be dropped from the list of proposed license conditions:

(1) The licensee is required to provide for staff acceptance a report on the result of the Westinghouse Owner's Group study of the steam generator tube l

rupture event, including plant-specific application of these results to CPSES, before startup of the second operating cycle (Section 15.4.4).

License conditions discussed in previous SERs that are currently under consid-eration are listed below.

(1) The licensee must continue to control mineral exploration within the ex-clusion area; that is, at distances beyond 2250 feet from safety-related structures per General Design Criterion 4,10 CFR Part 50, Appendix A (Sections 2.1.2, 2.2, and 2.3),

(2) The licensee shall implement and maintain in effect all provisions of the approved fire protection program, as described in the Final Safety Analy-sis Report (as amended) and as approved in the SER and its supplements, subject to the following provision:

The licensee may make changes to the approved fire protection l

program without prior approval of the Commission only if those changes would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire (Section 9.5 1).

(3) The licensee shall fully implement and maintain in effect all provisions of the physical security, guard training and qualification, and safeguards Comanche Peak SSER 23 1-5

contingency plans, previously approved by the Commission, and all amend-l ments made pursuant to the authority of 10 CFR 50.90 and 10 CFR 50.54(p).

The plans, which contain safeguards information protected under 10 CFR 73.21, are entitled:

" Comanche Peak Steam Electric Station Physical Secu-rity Plan" with revisions Submitted through November 28, 1988; " Comanche Peak Steam Electric Station Security Training and Qualification Plan" with revisions submitted through November 28, 1988; and " Comanche Peak Steam Electric Station Safeguards Contingency Plan" with revisions submitted through January 9,1989 (Section 13.6.11).

Comanche Peak SSER 23 1-6

2 SITE CHARACTERISTICS

2. 5 Geoloay and Seismoloay 2.5.1 Geologic Information Ongoing research identified a possible capable fault, the Criner Fault, about 200 kilometers (km) from the Comanche Peak Steam Electric Station (CPSES) site.

The staff has investigated this fault and its possible impact on the CPSES.

The NRC has been funding research on the Meers Fault since 1983.

This fault is part of the northwest-trending Wichita Frontal Fault System, which extends more than 700 km across southern Oklahoma and the Texas Panhandle.

The Meers Fault is exprested at ground surface by a 26-km-long, southwest-facing escarpment whose maximum height is 5 meters (m), and an 11-km lineament which extends southeastward beyond the escarpment.

Although apparently aseismic in historic times, geologic evidence along the Meers Fault indicates two and possibly three displacements within the past 5000 years, the youngest being about 1500 years ago.

It is considered capable and one of the few faults in the central and east-ern United States known to exhibit evidence of late Quaternary tectonic surface displacement.

As part of the current NRC-funded research contract being performed by Geoma-trix Consultants, Inc. (GC), the contractor was to conduct a brief regional re-connaissance to determine whether or not other faults of the Wichita Frontal Fault System had similar evidence for recent activity like the Meers Fault.

On Juiy 19, 1989, GC reported by telephone, and later by letter, that the Criner Fault could be a capable fault based on an aerial and brief field reconnaissance.

Because of the proximity of the fault to the site, the staff was concerned that it might be of safety significance to CPSES.

The Criner Fault is described as being downdropped to the southwest, striking N 45'W, having a 12-km-long,1-m-high, southwest-facing escarpment, and being located about 80 km southeast and along strike of the Meers Fault.

Ordovician limestene is juxtaposed against more easily erodible Pennsylvanian sandstones and shales across the fault.

The scarp ends to the northwest where sandstones and shales of equal erodibility are present on both sides of the fault.

The l

scarp terminates to the southeast where the Criner Fault separates into several splays and where it converges with the more northerly striking Kirby Fault.

The Kirby Fault is down to the northeast and forms a northeast facing scarp.

The block of Ordovician limestone between the two faults is uplifted relative to toe blocks to the north and to the south.

GC cited morphologic evidence as indicating young displacement; this is based on observations that the upper face of the scarp is strongly pitted due to weathering, but the lower 10 to 20 centimeters (cm) are relatively smooth.

At one location, mullions were observed suggesting dip-slip' displacement.

The smooth lower free face was interpreted by GC as suggesting late Quaternary (less than 20,000 years old) tectonic offset.

Comanche Peak SSER 23 2-1 1

In a telephone conference held on August 21, 1989, the staff informed Texas Utilities Electric (TV Electric, the applicant) of the Criner Fault findings, and asked TU Electric to address this issue with respect to its significance to the CPSES, which lies about 200 km south of the fault.

On September 5, 1989, the applicant, its consultants, and the NRC met.

At the meeting, the applicant presented evidence, based on a field reconnaissance at the Criner Fault and a literature search, that argues for an erosional origin for the escarpment.

The applicant also presented the results of an analysis that concluded that the oc-currence of a magnitude 7.0 earthquake on the Criner Fault would not affect the seismic design basis of the CPSES. As a result of this meeting, the NRC re-quested documentation of the information presented, particularly the basis sup-porting the ground-motion estimation.

A geological reconnaissance of the Criner Fault was conducted on September 28 and 29, 1989 by the applicant and its consultants, and the NRC and its research contractors (GC, EPRI, and the Oklahoma State Geological Survey).

As a result of observations made during this field trip, two possible hypotheses regarding the origin of the Criner Escarpment were formulated:

(1) The upper badly weathered and backwasted part of the 1-m scarp is a fault i

line scarp, but the lower 10 to 20 cm smooth, free face represents a fault f ace formed by tectonic displacement on the fault.

The freshness of the face suggests late Quaternary offset.

(2) The entire escarpment is a fault line scarp formed by the erosion and back-wasting of an ancient fault, probably late Paleozoic.

The fresh lower face was preserved by soil cover which has recently been removed by accelerated erosion along the base of the scarp or removal of the soil away from the rock face by downhill creep, brought about indirectly by agricultural practices, j

If the Criner Fault is capable, it has not moved within the last 10,000 years.

This is based on the lack of evidence for offset of alluvial terrace deposits overlying its trace at several locations.

The ages of these terrace sediments are not known, but because of the similarity between the soil of one of the older fans and the soil of dated material offset by the Meers Fault, it is es-timated to be at least 10,000 years old.

The strongest evidence cited by GC for fault capability is an offset stream alluvial terrace deposit along Hickory Creek near the southeast end of the Criner Escarpment.

The landowner denied the geological reconnaissance team access to this area.

GC described the outcrop as being located along a pre-viously unmapped strand of the Criner Fault.

Three late Quaternary fluvial I

terrace deposits (QAl, QAL, and QAL ) were identified with estimated ages i

2 3

ranging from Holocene Epoch (10,000 years ago to present) to more than'20,000 years old, with QAL3 being the oldest.

The estimated ages are based on simi-larities to soils studied in detail along the Meers Fault.

This exposure is described as being on the south bank of Hickory Creek where a bedrock fault along the southeast extension of the Criner Fault juxtaposes an older Pennsylvanian sandstone and shale over a younger Pennsylvanian sandstone i

and shale.

The fault is overlain by recent alluvium.

Adjacent to the bedrock fault as faulted QAla terrace alluvium.

The upper part of the fault zone is fi",ed with deformed QAla alluvium.

GC estimates that displacement of the Comanche Peak SSER 23 2-2

alluvium occurred between 10,000 and 20,000 years ago.

This is considerably older than the youngest two displacements on the Meers Fault (approximately 1500 and 1000 years ago).

There is also the possibility that the disrupted alluvium could have been caused by slumping or landsliding.

If the displace-ment displacement did occur within the last 20,000 years, then the fault is considered to be capable as defined in 10 CFR Part 100, Appendix A.

Presently there is insufficient evidence to prove or disprove the capability of the Criner Fault.

The Meers Fault, however, is considered to be capable of generating a large dam-aging earthquake somewhere in the magnitude range of 6-3/4 to 7-1/2.

Although the length of the Criner fault and the height of its scarp are less than those of the Meers Fault, because of its proximity and orientation, the staff conser-vatively estimated an earthquake magnitude of 7 on the Criner Fault for the eval-uation of the ground motion effect on the CPSES.

Although the applicant's posi-tion is that the Criner Fault is not capable, ground-motion estimates for CPSES were performed using attenuation equations developed for the central and eastern United States under two programs to characterize seismic hazard, one by the Electric Power Research Institute (EPRI) and the other by Lawrence Livermore National Laboratory (LLNL) under NRC sponsorthip.

The applicant estimates that the ground motion at the-CPSES site from a magnitude 7 earthquake on the Criner Fault, at a distance of 200 km, would be below the plant's safe shutdown earth-quake (SSE).

In its own evaluation, the staff used two representative ground-motion attentua-tion equations developed for the EPRI and LLNL studies, one by O. W. Nuttli and the other by R. K. McGuire and others, to estimate the 84th percentile spectral level for a magnitude 7 earthquake at a distance of 200 km.

These two ground response spectral estimates were compared to the CPSES 5." response spectrum.

The estimate using the Nuttli equation is approximately equal to the SSE response spectrum with slight nonsignificant exceedances at some frequencies and lower values at other frequencies.

The estimate using the McGuire equation is well below the SSE response spectrum at all frequencies.

In view of this, the staff concludes that a conservatively postulated magnitude 7 earthquake on the Criner Fault does not pose a safety concern for the CPSES.

The staff has evaluated the significance of the Criner Fault with respect to the safety of the CPSES and reached the following conclusions:

(1) The Criner Fault is~possibly capable but the present evidence is equivocal.

(2) If the fault is capable, its length and surface displacement are less than those of the Meers Fault.

(3) The ground-motion estimate at the CPSES from a conservatively assumed magnitude 7 earthquake on the Criner Fault has no safety impact on the plant.

The applicant has committed to update the FSAR to include assessments of the Meers and Criner Fa.ilts as part of the first annual FSAR update.

The staff concludes that the seismic design bases presented 1r the FSAR remain valid.

Comanche Peak SSER 23 2-3 s

w

(

l 3 DESIGN OF STRUCTURES, COMPONENTS, EQUIPMENT, AND SYSTEMS l

j 3.3 Wind and Tornado Loadings 3.3.2 Tornado Design Criteria The applicant has revised the Comanche Peak Steam Electric Station (CPSES) Final Safety Analysis Report (FSAR) commitment on tornado venting doon to allow the interior compartments to vent to the exterior by means of two blow-out doors which replace the original roll-up doors.

The staff finds blow out doors to be equally effective as the original roll-up doors in venting differential pressure l

from interior compartments.

Therefore, the staff concludes that this design change does not affect the conclusion reached in the SER regarding the ability of Category I structures to withstand a design-basis tornado.

In Section 3.3.2 of the FSAR, the applicant has taken an exception to Regulatory Guide (RG) 1.76 with regard to the rate of pressure drop due to the tornado loading.

The applicant utilizes 1 psi /s instead of 2 psi /s. The staff agrees that this difference in pressure drop has no effect on the safety of structures because the structural response is not sensitive to this small drop in pressure.

Therefore, the exception is acceptable.

l 3.6 Protection Against Dynamic Effects Associated With the Postulated Rupture of Piping 3.6.1 I n ide Containment The applicant provided criteria for the design of pipe whip restraints in Sec-tion 3.6B.2.3.3 of the FSAR.

These criteria include provisions for limiting the permanent strain in metallic ductile materials to 50 percent of the minimum ultimate uniform strain.

The ultimate strain was to be based on restraint material tests.

In Amendment 68 to the FSAR, the applicant clarified that in addition or as an alternative to restraint material tests, the ultimate strain was to be based on the American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code).

Specifying the ASME Code as an additional or alternate basis for the ultimate strain in the design of pipe whip restraints is acceptable.

Typically, ASME Code values for limiting stresses and strains are lower, and hence more conserv-ative, than corresponding values obtained from material test data.

3.6.1.2 Systems Other Than RCS Main Loop By letter dated April 15, 1988, the applicant requested the elimination of the dynamic effects of certain postulated high-energy pipe ruptures from the design basis of CPSES Unit I using " leak-before-break" (LBB) technology as permitted'by the revised General Design Criterion 4 (GDC 4) of Appendix A to 10 CFR Part 50.

Comanche Peak SSER 23 3-1 R

Specif 0 ally, the request applied to the accumulator, pressurizer surge, and residual heat removal (RHR) piping.

j The applicant supplemented its request by letters dated July 8,1988 and May 1, I

May 9 May 12, August 9, September 15, September 18, October 24, and December 12, 1989.

The technical basis for the elimination of the subject high energy pipe i

ruptures for CPSES Unit 1 was provided in seven reports: five by Westinghouse (WCAP-12248, WCAP-12248 Supp. 1, WCAP-12258, WCAP-12258 Supp. 2, WCAP-12267) and two by Robert L. Cloud & Associates on the CPSES-1 WHIPJET Program Report, dated April 1988 and May 1989.

The applicant also referenced Westinghouse re-ports WCAP-10456 and WCAP-10931, Revision 1, which the staff reviewed previously.

The revised GDC 4 is based on the development of advanced fracture mechanics technology using the LBB concept.

On October 27, 1987, a final rule was pub-i lished (52 FR 41288), effective November 27, 1987, amending GDC 4.

The revised i

GDC 4 allow's the use of analyses to eliminate from the design basis the-dynamic effects of postulated pipe ruptures in high-energy piping in nuclear power units.

Implementation permits the removal of pipe whip restraints and jet im-pingement barriers as well as other related changes in operating plants, plants under construction, and future plant designs.

Although functinnal and perform-ance requirements for containments, emergency core cooling systems, and environ-mental qualification of equipment remain unchanged, local dynamic effects uniquely associated with_ postulated ruptures in piping which qualified for LBB may be excluded from the design basis (53 FR 11311).

The acceptable technical procedures and criteria are defined in NURT5-1061, Volume 3.

s Using the criteria in NUREG-1061, the staff has reviewed and evaluated the' ap-plicant's submittals for compliance with the revised GDC 4.

The staff's find-ings are documented below.

, Piping at CPSES Within the LBB Scope i

The CPSES Unit 1 branch piping within the LBB scope are the accumulator, pres--

surizer surge, and RHR suction lines having nominal diameters of 10.75, 14, and 12.73 in., respectively.

The piping mr heials are austenitic wrought stainless steel for the accumulator (SA-376 TP316), pressurizer surge (SA-376 TP316), and RHR (SA 376 TP304) piping.

However, the material is austenitic cast stainless steel for the accumulator injection nozzles (SA-3~ t CF8A).

The staff's criteria for evaluating compliance with the revised GDC 4 are dis-cussed in Chapter 5.0 of NUREG-1061 and are as follows:

(1) The leading conditions should include the static forces and moments (pres-7 sure, deadweight, and thermal expansion) due to normal operation and the l

forces and moments associated with the safe shutdown earthquake (SSE).

These forces and moments should be located where the highest stresses.

coincident with the poorest material properties, are induced for base materials, weldments, and safe ends.

L (2) For the piping run/ systems under evaluation, all certinent information I

which demonstrates that degradation or failure of the piping resulting l

from stress corrosion cracking, fatigue, or water hammer is not likely, should be provided.

Relevant operating history should be cited, which I

l Comanche Peak SSER 23 3-2

?

e includes system operational procedures; system or component modification; water chemistry parameters, limits,- and controls; and resistance of mate-rial to various forms of stress corrosion and performance under cyclic loadings.

(3) The materials data provided should include types of materials and materials specifications used for base metal, weldments, and safe ends; the materials properties including the fracture mechanics parameter "J-integral" (J) resistance (J-R) curve used in the analyses; and long-term effects such as i

thermal aging and other limitations to valid data (esg., J maximum, and maximum crack growth).

(4) A through-wall flaw should be postulated at the highest stressed locations determined from criterion 1 above.

The size of the flaw-should be large enough so that the leakage is assured of detection with at least a factor r

of 10 using the minimum installed leak-detection capability when the pipe i

is subjected to. normal operational loads.

1 (5) It should be demonstrated that the postulated leakage flaw is stable under normal plus SSE loads for long perhds of time; that is, crack growth, if j

any, is minimal during an earthquake.

The margin, in terms of applied loefs, should be at least 1.4 and should be determined by a flaw stability analysis, that is, the leakage-size flaw will not experience unstable i

crack growth even if larger loads (larger than design loads) are applied.

~

However, the final rule permits a reduction of the margin of 1.4 to 1.0 if the individual normal and seismic (pressure, deadweight, thermal expan-sion, SSE, and seismic anchor motion) loads are summed absolutely.

i I

(6) The flaw size should be determined by comparing the leakage-size flaw to the critical-size flaw.

Under normal plus SSE loads, it should be demon-strated that there is a margin of at least 2 between the leakage-size flaw and the critical-size flaw to account for the uncertainties inherent in the analyses and leakage detection capability.

The staff has evaluated the information submitted by the applicant for compliance with the revised GDC 4.

Furthermore, for the accumulator piping, the staff per--

i formed independent flaw stability computations using an elastic plastic fracture mechanics procedure developed by the staff and detailed in NUREG/CR-4572.

For i

the pressurizer surp and RHR piping, the staff performed flaw stability compu-tations using a moditied limit-load analysis method based on Article IWB-3640 of Section XI of the ASME Code and discussed in the proposed SRP,Section 3.6.3 (52 F_R, 32626).

On the basis-of its review, the staff finds the subject CPSES Unit 1 piping in compliance with the revised GDC 4.

The staff's. evaluation is presented below.

(1) Normal operating loads, including pressure, deadweight, and thermal expan-sion, were used a determine leak rate and leakage-size flaws.

The flaw stability analyses performed to assess margins against pipe rupture at postulated faulted load conditions were based on normal'plus SSE loads.

In the stability analysis, the individual normal and seismic loads-were summed absolutely for the accumulator and pressurizer surge piping.

In e

i Comanche Peak SSER 23 3-3

the stability analysis of the RHR piping, the normal loads were summed algebraically before adding to the seismic loads absolutely.

In the leak rate analysis, the individual normal load components were summed algebraic-ally.

Leak-before-break evaluations were performed for the limiting loca-tions in the piping.

(2) The Westinghouse reactor coolant system (RCS) primary loop and conne:t-ing ASME Code Class 1 lines have an operating history that demonstrates the inherent operating stability characteristics of the design.

This includes a low susceptibility to cracking failure from the effects of corrosion (e.g., intergranular stress corrosion cracking), water hammer, or fatigue (low and high cycle).

This operating history totals over 400 reactor years, including five plants each having over 15 years of opera-tion and 15 other plants each with over 10 years of operation.

For the pressurizer surge line, the staff issued NRC Bulletin 88-11 request-ing verification of compliance with the applicable design codes considering thermal stratification.

The staff has reviewed this issue for CPSES Unit 1 and this LBB safety evaluation takes credit for the favorable finding per NRC Bulletin 88-11 (see Section 3.6.1.3 of this report).

The staff identified a concern related to potential thermal stratification in the pressurizer surge line during a forced cooldown of the reactor coolant system to effect repairs of leakage discovered in the surge line during normal plant operations.

The concern is that the combined thermal stresses associated with the forced cooldown process and the thermal stratification phenomenon could overstress the potentially weakened surge line implied by the presence of leakage in the line.

By letter dated October 24, 1989, the applicant committed to revise the plant operating procedures to provide prompt depressurization in the event of a pressur-izer surge line leak.

The staff concludes that the combination of analytical methods and plant procedures b adequate to resolve this con-cern for CPSES Unit 1.

For the RHR suction line, the staff recently issued Supplement 3 to NRC Bulletin 88-08 requesting the evaluation of the potential for thermal fatigue.

By letter dated August 9, 1989, the applicant committed to monitor the temperature of the RHR lines.

Should thermal fatigue develop, the applicant would be alerted by fluctuating temperatures on the RHR lines.

The staff concludes that the results of this monitoring program will be adequate to confirm the staff's conclusion that the RHR suction lines will not fail as a result of thermal fatigue and this issue is, therefore, resolved for CPSES Unit 1.

The monitoring program is to be continued until sufficient data are developed, either through industry generic or plant-specific programs, to permanently resolve this issue.

In its August 9, 1989 letter, the applicant agreed to obtain staff approval before terminating the monitoring program (3) The material tensile and fracture toughness properties were provided in the two Robert L. C%ud & Associates reports and in Westinghouse reports WCAP-12248, WCAP-12258, and WCAP-12267.

Because the CPSES Unit 1 Comanche Peak SSER 23 3-4

accumulator piping consists of cast stainless steel, the thermal aging toughness properties of cast stainless steel cateriais were estimated ac-cording to procedures in Westinghouse reports WCA9-10446 and WCAP-10931.

The material tensile properties were estimated using plant-specific mate-rial certifications and generic procedures for the acu mulator and pres-surizer surge piping.

The material tensile properties were based on ASME i

Code minimum values for the RHR piping.

For flaw stability evaluations, the lower-bound stress-strain properties were used.

For leakage rate evaluations, the average stress-strain properties were used.

(4) CPSES Unit I has systems to detect leakage in the RCS pressure boundary, which are consistent with the guidelines of RG 1.45, su that a leakage of I gallon per minute (gpm) can be detected in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

The calculated leak rate through the postulated flaw is large relative to the staff's required sensitivity to the plant's leak-detection systems; the margin is a factor of 10 on leakage and is consistent with the guidelines of NUREG-1061.

(5) In the flaw stability analyses, the staff evaluated the margin in terms of load for the leakage-size flaw under normal plus SSE loads.

The staff's calculations indicated the margin exceeded 1.0 for the accumulator and pressurizer surge piping where the individual normal and seismic loads were summed absolutely.

The margin is consistent with the guidelines of the final GDC 4 broad scope rule.

The staff's calculations also indicated that the margin exceeded 1.4 #or the RHR piping where the individual normal and seismic loads were not summed absolutely.

The margin is consistent with the guidelines of NUREG-1061.

(6) Similar to item 5 above, the margin between the leakage-size flaw and the critical-size flaw was also evaluated in the flaw stability analyses.

The staff's calculations indicated the margin in terms of flaw size ex-ceeded 2 for the load comb! nation method considered.

The margin is consistent with the guidelines of NUREG-1061.

The staff has reviewed the information submitted by the applicant and has per-formed independent flaw stability computations.

On the basis of its review, the staff cor.cludes that the CPSES Unit 1 ccumulator, pressuri ter surge, and RHR piping comply with the revised GDC 4 according to the criteria in NURES-1061,-

Volume 3.

Thus, the probability or likelinood cf large pipe breaks cccurring in the subject piping of CPSES Unit 1 (without the prior occurrence of detect-able leakage) is sufficiently low that dynamic effects associated with pcstulated pipe breaks need not be a design basis.

This conclusion is based on the appli-cant's commitments to (1) monitor the Ri:R line for the potential of thermat fatigue and (2) revise plant operating procedures to provice prompt deprassur-ization in the event of a pressurizer surge line leak.

Outstanding Issue 1 in SSER 22 is, therefore, resolved.

3.6.1.3 Thermal Stratification of Pressurizer Sur0e Line (NRC Bulletin 88-11)

The pressurizer surge line (PSL) in CPSES Unit 1 is a 14-in. sche M e 160 stainless steel pipe, connecting the bottom of the pressurizer vessel to the hot leg of one of the coolant loops.

The outflow of the pressurizer water is I

Comanche Peak SSER 23 3-5

generally warmer than the hot-leg flow.

Such temperature differential (AT) varies with plant operation activities and can be as high as 320 F during the initial CPSES Unit 1 plant heatup.

Thermal stratification is the separation of cold flow stream in the horizontal portion of the PSL, resulting in one tempera-t ture at the top of the pipe and another temperature at the bottom of the pipe.

Since thermal stratification is the direct result of the differences in densities between the pressurizer water and the generally cooler and heavier hot-leg water, the potential for stratification is increased as AT increases and as the insurge or outsurge flow decreases. Stratification in PSL was found recently at other pressurized-water reactor (PWR) plants and confirmed by data from several PWR plents.

The CPSES Unit 1 original design analysis did not include any stratified flow loading conditions.

Instead, it assumed complete sweep of the fluid along the line during insurges or outsurges, resulting in uniform thermal loading at any particular piping location.

Such analysis did not reflect PSL actual thermal

~

condition.

It potentially may overlook undesirable line deflection, and its actual high stresses may exceed design limits.

In addition, the striping phe-nomenon, which induces high cycle fatigue to the inner pipe wall, needs to be analyzed.

Thus, assessment of stratification effects on the PSL is necessary to ensure piping integrity and Code conformance.

Since stratification in the PSL is a generic concern to all PWRs, NRC Information Notice 88-80 was issued on October 7,1988, and then the NRC issued Bulletin 88-11 for the same concern on December 20, 1988.

The applicant has submitted a bounding evaluation report, WCAP-12248, which consists of presentation mate-rial and explanatory text.

The following is the staff's. evaluation of the applicant's ef forts and information provided in the report:

i The surge line stratification program for CPSES Unit I consists of the following majorparts:

update of design transients ASME Code Section III compliance for stress and fatigue participation in the Westinghouse Owners Group.(WOG) activities and confirm-atory monitoring l

UpdagofDesignTransients The sbrge line fluid temperature distribution was modified from the~ original uniform ten erature to a stratified profile.

Surge line stratification data were obtained from five other Westinghouse plants and thermal fluid conditions.

were developed.

4 On the basis of the monitoring data obtained, the design transients for heatup/cooldown, normal, and upset operating conditions were redefined to consider the stratification effects.

To determine the maximum top-to-bottom temperaturs differences, the system AT (maximum pressurizer and minimum bot-leg temperature) was considered.

The monitoring data obtained from the other five Westinghouse-designed PWRs-indicate that during critical operating transients, and heatup/cooldown-Comanche Peak SSER 23 3-6 4

operations, the pipe movements are consistent with analysis results.

Heat-transfer analysis and test data available to date show that a-stratified flow with a sharp fluid temperature gradient at the stratification interface, will provide a conservative condition at the inside face of the pipe.

The normal and upset thermal transients were developed based on:

The maximum pressurizer-to-hot-leg AT, which occurs in the pipe during a '

given transient, although the maximum pressurizer temperature and the minimum hot-leg temperature may not occur at the same time.

Full stratification cycles for all transients except for. steady-state fluctuations, unit loading and unloading, and reduced temperature return to power.

The maximum top-to-bottom pipe temperature to be AT-= 320 F, although none of the measured top-to-bottom pipe temperatures, in any plant, exceeded AT = 270 F even when system AT reached close to 320 F.

The envelope from measured transients in all plants was applied to define the analysis transients.

The staff concluded that the use of envelope transients, based on available data from five similar PWRs, are conservative and acceptable.

Confirmatory monitoring during the first refueling cycle will be conducted.to verify that the design transients used in CPSES Unit 1 are indeed bounding.:

ASME Code Section III Compliance for Stress and Fatigue Code compliance in stress The applicant performed a reanalysis on the PSL piping and supports-to account for thermal stratification effects.

The analysis consisted of three parts:

(1) global e fects on stresses, moments, displacements, and support reaction loads, based on both axial and radial variations in the pipe metal-temperature, (2) local stresses due to thermal gradient, and (3) local stresses and effects to fatigue due to thermal striping.

The total thermal stratification-stress, l-in the pipe is the result of global (structural) bending stress effects and l

the local stress effects due to thermal gradient, which means stress in items I

1 and 2 above were superimposed.

The staff agrees with the licensee's-l efforts and methodology for updating and assessing PSL for the stratification condition.

Structural analysis of the surge line using stratification-induced loads deter -

l mined the pipe displacements, support reaction loads, moments, and forces in-l the piping system using the ANSYS computer code.

Although a 320 F step temper-ature change was assumed for stratification throughout the surge line, the changes were linearized in ANSYS using conventional pipe element model.

~

Finite element models were used to calculate local stresses due to top-to-bottom nonlinear thermal gradients in the PSL.

Five hot-to-cold interface locations were analyzed using eleven cases of the'rmal stratification, to:calcu -

late piping response under all required loading conditions, reflecting temper--

ature differences up to 320 F.

Other cases were obtained by interpolation.

Comanche Peak SSER 23 3-7

Nozzle loads at locations connecting the surge line to the pressurizer and the hot leg to the main coolant loop were also evaluated.

Loads were found to be acceptable for all design conditions.

The applicant reported that its best-estimate analytical results compared favorably with measured displacements data observed during CPSES Unit 1 hot functional testing.

Furthermore, no discernible distress was observed in the entire PSL including supports, during visual examinations conducted after pre-operation testing.

The calculated displacement value of 1.46 in, at an approximately mid-span loca-tion was found acceptable when compared to the measured value of 1.1 in. in the vertical direction for a stratification case of pipe AT = 260'F.

Local axial stresses were developed due to restraint of axial expansion or con-traction.

The worst case, a step change in fluid temperature from hot to cold, occurs at the stratified interface.

This causes higher metal temperature gradients at the inside face rather than the outside surface of the pipe.

A two-dimensional finite element model was developed and the analysis considered unit loads of pressure and bending.

The resulting stresses were scaled using actual pressure transients and moments from the global structural analysis.

Results of global and local stresses were combined at any point in the pipe cross-section using superimposition methods.

The primary plus-secondary stress intensity range of equation 12 of AStft Code Section Ill Subsection NB-3600, was calculated to be 52.1 ksi and occurs at the hot nozzle safe end.

This is less than the code-allowable value of 3.05, or 57.9 ksi.

Stresses were intensified by "C" factors, to account for the worst-case concentration for all piping elements in the PSL, except for the RCL nozzle which used the results of the finite element, analysis (C2 = 1.37) in lieu of the code stress index (C2 = 1.7).

The stress index approach is a simple way to determine in an approximate manner the maximum elastic stress intensity in a component for a particular loading.

The indices in the code are established from analytical and experimental results, as well as engineering judgment.

In general, the indices are conservatively defined to envelop different possible geometric features and therefore the use of C2 = 1.37 value as derived by finite element analysis is considered acceptable.

The staff agrees with the approaches used by the applicant for performing PSL reanalyses.

Code compliance in fatigue The total fatigue to PSL is the result of stratification-induced global and local cyclic stress effects and striping-induced local cyclic stress effects.

To account for the thermal striping effects to PSL, flow model test results performed for the liquid metal fast breeder reactor primary loop and for the Mitsubishi heavy industries feedwater line cracking, were reviewed to establish the boundary condition.

These test results were used to define striping oscil-lation data, amplitude, and frequencies for evaluating high-cycle fatigue.

Por-tions of the PSL which experience stratification and striping were defined on the basis of measured results.

A frequency of 0.30 Hz with attenuating amplitude from 100 percent AT were selected for the analysis.

Comanche Peak SSER 23 3-8

Thermal striping stresses result from differences between temperatures at the inside surface wall of the pipe and the average through-wall temperatures which occur with time due to the oscillation of the hot and cold stratified boundary.

This stress is defined as a thermal discontinuity peak stress and is required by the ASME Code for the calculation of the fatigue usage factor.

The peak stress range and stress intensity values were calculated from two-dimensional finite i

element analysis stresses and were intensified by K to account for the worst-3 l

stress concentration for all piping elements.

The maximum fatigue usage factor obtained is 0.74 and occurs at the RCL nozzle safe end.

The applicant reported that considering AT attenuation with time, and a frequency of 0.30 Hz, a usage factor of less than 0.20 was determined as the worst case due to striping alone, even when the stresses were intensified by K factors.

Furthermore, the total calculated usage factor for striping alone was increased by 50 percent to account for any uncertainty in the selection of frequency and other variations.

A surface film coefficient cf 500 Btu /hr-ft2 *F was used and it was based on a flow rate of 9 gpm which was assumed to be constant throughout all striping analysis.

The data used in the assessment were obtained from a l

1/5-scale test model which showed that the frequency can range from 0.10 to l

0.50 Hz.

The frequency corresponding to the flow rates which closely approximate j

the Richardson's number for the pressurizer surge line was used.

The staff agrees that the stresses will be higher with the lower frequency and a 0.30 Hz frequency is justified.

However, the thermal striping potential due to l

a film coefficient of 500 Btu /hr-ft2 *F and attenuation of AT is questionable, I

but at this time no other better number exists and therefore this represents a l

best-judgment estimate.

If other information becomes available, perhaps from the efforts by the Electric Power Research Institute (EPRI) or possible future NRC research work, it will be utilized and further assessments will be marie for the striping ef fects of the PSL.

With the thermal transients updated to reflect stratification effects, new fatigue usage factors were calculated.

To determine the new fatigue usage I

factors by stratification alone, the more detailed tecnniques of ASME Code Section III Subsection NB-3200 were employed.

Because of the non-axisymmetric nature of stratification loading, stresses due to all loadings were obtained from finite element analysis and then combined on a stress component basis.

Five levels of thermal stratification at five worst-case points were calculated using the WECEVAL program.

Except in nozzle locations, for most components in the surge line (girth butt welds, elbows) no gross structural discontinuity is present and, therefore, the contribution of this code-defined "Q" secondary stress is zero.

As a result, the equation 10 (from ASME Code Section III Sutdection NB-3600) stress value for these components is due to pressure and moment only. For the RCL hot-leg nozzle, the results of the three-dimensional finite element WECAN analysis was l

used to determine the secondary gross structural discontinuity contribution for.

transients with stratification in the nozzle.

When the appropriate stress indices were used, the following maxiinum values were obtained by the use of i

equations 12 and 13 from ASME Code Section III Subsection NB-3600:

l Comancht Peak SSER 23 3-9

Location Stress value (ksi)

Allowable (ksi)

RCL nozzle Eq 12 = 52.1 35,= 57.9 RCL nozzle Eq 13 = 46.7 35,= 50.1 Usage factors at the inside and outside pipe wall were evaluated at il sections through the pipe wall.

For the cases in which equation 10 exceeded the 3 S, limit, a simplified elastic-plastic analysis was performed as per ASME Code Section III Subsection NB-3653.6.

Values of equations 12 and 13, K,, and ther-mal stress ratchet were checked.

Equation 13 is not affected by thermal strati-fication in the pipe where no gross structural discontinuities exist; therefore, it was only calculated at the nozzles.

A worst-case cumulative usage factor at the RCL nozzle of 0.74-is established when the striping effects are included.

The staf f agrees with the approaches used by the applicant for calculating the usage factor.

Conclusion The staff concludes that the applicant has made acceptable efforts to meet the actions delineated in the NRC Bulletin 88-11.

The applicant's analyses have demonstrated that, based on enveloping temperature profiles defined by available stratification data of other five Westinghouse-designed PWRs, the PSL meets the ASME Code Section III acceptance criteria.

By letter dated December 12, 1989, the applicant committed to conduct a monitoring program during the first fuel cycle to collect data to verify acceptability of the design transients used.

The applicant may request staff approval to terminate the monitoring program earlier if sufficient data are developed, either through industry generic or plant-specific programs to permanently resolve this issue.

3.7 Seismic Design 3.7.1 Seismic Input In FSAR Section 3.78.1, " Seismic Input," and in Appendix 1A(B) to the FSAR, tSe applicant stated that the design response spectra for the seismic design of CPSES are in conformance with RG 1.60, Revision 1, except in the high-frequency region greater 'han 33 Hz.

RG 1.60 indicates that such a reduction to the maxi-mum vertical ground acceleration occurs at 33 Hz.

Similarly, the frequency at the starting control point of the acceleration region is 3.5 Hz in RG 1.60; the corresponding point in the design vertical spectra is 4.0 Hz.

The applicant has stated that the vertical response spectra described above were changed on the basis of the recommendations made by Newmark, Blume, and Kapur in a paper (" Design Response Spectra for Nuclear Power Plants,") presented at the American Societies of Civil Engineers (ASCE) Structural Engineering Meeting in San Francisco in April 1973, and are in accordance with Standard Review Plan (SRP) Section 3.7.1 (NUREG-0800).

The applicant further stated that the effect of the deviations in design response spectra from RG 1.60 provisions is insignificant.

Comanche Peak SSER 23 3-10

The staff has verified that the above differences between the applicant's de-sign vertical response spectra and RG 1.60 spectra are indeed based on the recommendations referenced above.

Although RG 1.60 is also based on the rec-ommendations referenced above, the two documents differ slightly.

The staff agrees with the applicant's statement that the effect of the deviations (in the control points relating to 3.5 Hz and 33 Hz) is insignificant.

These deviations will not impair the safety of the structures, systems, and components that have been designed using the design vertical response spectra given in the FSAR.

t 3.8 Desion of Seismic Category I Structures 3.8.1 Concrete Containment t

The evaluation of the concrete containment is based on a linear elastic analysis of the shell.

The shell is modeled as a fixed-based, two-dimensional, axisym-metric shell of revolution.

The local discontinuities in the metal liner and associated penetrations were not analyzed as part of this model. However, a comparison was made between the CPSES containment structure, including penetra-tions, with those of similar PWR plants (Maine Yankee, Seabrook, Millstone, and Beaver Valley) for which ultimate pressure capacities (UPCs) have been estimated by the respective utilities and reviewed and approved by the staff. The appli-cant's estimate of the UPC of the containment is 150 psig; the reported capaci-ties of the similar plants vary between 96 and 150 psig.

Another recent source of comparison to the estimated CPSES containment capacity is the concrete containment model testing performed at Sandia National Lab-oratory (SNL).

The pressurized 1/6th-scale model leaked significantly at 135-145 psig, which is about three times the design pressure. The estimated capacity of the CPSES containment is also three times its design pressure.

Thus, the SNL test results tends to support the CPSES estimated capacity.-

There is a difference between the failure mode observed at the SNL' testing and that assumed in the CPSES analysis.

The CPSES analysis assumed that.the UPC is limited by the capacity of the reinforced-concrete containment, and not by the strain concentrations at insert plates around the penetrations.

It was judged in the analysis that at these strain levels, the liner is not expected to frac-e ture since the material of the liner is very ductile.

Contrary to this.judg-ment, the SNL test model failed when the liner tore as a result of excessive strain concentrations at insert plates around the penetrations.

The test model failed before reaching the failure mechanism assumed in the CPSES analysis.

These comments may be equally applicable to the past analyses performed for other plants.

The predictions of the UPC for the SNL test containment were in the range of 120 to 170 psig.

These predictions considered various theoretical failure modes.

Although the failure mode experienced in the SNL test was not the fail-ure mode predicted most likely to occur, the pressure at which the test con-tainment failed was enveloped by the analytical predictions.

On the basis of the uncertainty in potential failure modes that could occur at these high pressures (i.e., well above design pressure), the staff recommends that the ultimate containment pressure limit for the CPSES containment be expressed as a pressure range rather than as a eirgle pressure value.

The upper range limit is the. applicant's predicted value M :50 psig and the low range limit is 100 psig which reflects the uncertainties in failure modes and the variations observed in the analytical predictions performed at other plants.

Comanche Peak SSER 23 3-11

In summary, by comparison with other containment analyses and test results, the staff concludes that the ultimate pressure capacity of the CPSES containment is expected to be in the range of 100-150 psig and it is acceptable.

2 In Amendment 77 to the FSAR, the applicant indicated that the equipment hatch and sleeves for the transfer tube and electrical and process piping penetrations, which are subject to code stamping considerations, are not code stamped.

However, the lack of code stamping for the ferritic materials for these penetrations is compensated by the pressure testing that is required for the reinforced-concrete containment structure, as stated in FSAR Section 3.8.1.7.

This is acceptable.

The applicant identified in the FSAR an exception to American Institute of Steel Construction (AISC) recommendations for the tightening of high-strength bolts. For situations in which thermal expansion must be accommodated, the applicant hand-tightened the high-strength bolts rather than tightening the bolts i

to the AISC recommendations.

The staff has reviewed the FSAR with respect to the AISC requirements and the applicability of the exception to the AISC recom-mendation proposed by the applicant in item 2 of its December 7,1989 submittal.

The staff finds this exception acceptable for the specific application and installation criteria indicated in the applicant's letter of December 7,1989, since the applications include instances in which thermal movements must be accommodated and the actual load is well below the allowable AISC values.

3.8.3 Other Seismic Category I Structures The staff has reviewed Sections 3.7 and 3.8 of FSAR Amendment 77.

During the site audit of September 6-8, 1989, the actual stresses for many Category I structural compor.ents were found either to be the same as or to be very close to the allowable values (Table 3.8-1).

A sample review conducted at the audit revealed that for an exterior tank, the seismic acceleration was unconservatively calculated but the mass was conservatively estimated.

The staff recognized that the sample calculation was based on conservative assumption of the total load; however, conservativeness of individual asts;tions also should be verified and requested that the applicant verify the arpsis especially for those components having low margins.

By letter dated Decemcee 7,1989, the applicant stated that the calculations related to the tank have been revised and the revised stress is well below the allowable value because the overall load and the governing load i

combination were assumed conservatively.

The overall seismic design adequacy verification for seismic Category I structures has been completed by the appli-cant and verified by NRC inspectors.

3.9 Mechanical Systems and Components 3.9.1 Special Topics for Mechanical Components l

l Safety Evaluation Report (SER) Supplement 14 (SSER 14) presented the staff's evaluation of the applicant's Corrective Action P*ogram (CAP) pertaining to ASME Code Classes 1, 2, and 3 pipe supports and ASME Code Classes 2 and 3 piping systems as provided in Amendment 61 to the CPSES FSAR.

The workscope and methodologies developed for these piping systems and pipe supports during the l

CAP were summarized in CAP-related project status reports (PSRs) on the large-and small-bore piping and pipe supports.

1 l

l l

Comanche Peak SSER 23 3-12

The staff evaluation was provided in Section 4.1.2.2 of SSER 14.

However, SSER 14 was not prepared in the standard SER format.

Accordingly, SSER 14 and subsequent evaluations of the applicant's CAP relating to ASME Code Classes 1, 2, and 3 pipe supports and ASME Code Classes 2 and 3 piping are appropriately incorporated here and further clarified as necessary.

In FSAR Section 3.9N.I.4, the applicant described the method of analysis to be used relating to the ASME Code faulted condition service limits specified for ASME Code Class I components and component supports supplied by the nuclear steam supply system vendor.

As part of this description, FSAR Section 3.9N.1.4.5 detailed the method of analysis to be used to calculate the faulted condition stresses and deformations.

This description was provided to demonstrate that the applicant's method of analysis was in compliance with the method of analysis for faulted conditions outlined in Appendix F of the ASME Code.

The description of the faulted condition analysis for the primary components was revised in FSAR Section 3.9N.1.4.5 by Amendment 68.

The values of the percentage damping in the seismic analysis of the reactor coolant pump were reduced from 4 percent for the operating basis earthquake (OBE) and 7 percent for the safe shutdown earthquake (SSE) to 2 percent for the OBE and 4 percent for the SSE to be consistent with the values used in the reactor coolant loop and the reactor internals.

The use of the lower percentage damping values in the seismic analysis of the reactor coolant pump is acceptable.

The use of lower percentage damping values is more conservative since the response, hence the seismic stresses and displace-ments, will be increased.

In addition, consistency of percentage damping values in the seismic analysis of the primary components will ensure uniformity in the results of the analyses.

In FSAR Section 3.9B.1.4, the applicant specified the methods to be used relating to faulted condition service limits for the following balance-of plant-related items:

(1) ASME Code Classes 2 and 3 components, (2) bolting for ASME Code Classes 2 and 3 components, and (3) non-ASME Code components.

Specifically, the applicant has provided:

(1) a description of the type of analyses to be performed in the event that the design stress limits exceed the yield strength of the materials in the ASME Code Classes 2 and 3 components, (2) bolting design criteria, and (3) design or testing requirements for non-ASME Cude components.

For ASME Code Classes 2 and 3 components, the applicant removed, by Amendment 61 to the FSAR, a statemcot in FSAR Section 3.9B.1.4 which precluded the use of plastic analysis for the resign of all such components.

In a letter dated October 7,1986, the applicant stated that this removal of the previous FSAR restriction on the use of plastic analysis was not a commit-

+

ment to use plastic analysis for ASME Code Classes 2 and 3 components.

This change was implemented during the early stages of the applicant's CAP when the use of plastic analysis was under consideration to validate particular design and installation configurations.

These configurations were modified or elimi-nated during the CAP and validated without the use of plastic analysis.

The applicant further stated in the October 7, 1986, letter that specific usage of plastic analysis will be in accordance with the ASME Code and will be submitted to the staff for approval as required.

For ASME Code Classes 2 and 3 components, Comanche Peak SSER 23 3-13

t I

the staff finds that use of plastic analysis methods may be acceptable provided that, before its use, its application and justification be submitted to the staff for approval.

In addition, for bolts, the applicant removed by Amendment 66 to the FSAR the previous item of FSAR Section 3.9B.I.4 relating to anchor bolts for components and component supports.

This item referenced various subsections of Section 3.8 of the FSAR.

After reviewing this item, the staff finds that the removal of the discussion of anchor bolts from FSAR Section 3.9B.1.4 relating to bolts to bolts for ASME Code Classes 2 and 3 components is appropriate.

Design cri-teria for anchor bolts are included in FSAR Section 3.8.

3.9.2 Dynamic Testing and Analysis In FSAR Section 3.9B.2.1, the applicant provided details of the preoperational vibration and dynamic effects testing to be performed on piping systems and supports.

This testing is intended to confirm that the piping systems, re-straints, components, and supports have been adequately designed to accommo-date thermal motion and to withstand flow-induced dynamic loadings under steady-state and operational transient conditions anticipated during the life of the plant.

The applicant clarified this testing program in Amendments 57 through 74 to the FSAR.

By Amendment 66, the applicant clarified in FSAR Sections 3.9B.2.1.2 and 3.9B.2.1.4 the dynamic transient response testing to be performed.

Piping systems and transient flow modes to be monitored were identified.

In addition, clarifications of how the tests were to be conducted a id acceptance criteria for the test data were also provided.

Similar clarifications were provided by Amendments 66, 68, and 74 in FSAR Sections 3.6B.2.1.3 and 3.6B.2.1.4 of the steady-state vibration testing program.

The clarifications provided to the dynamic testing and analysis programs by Amendments 57 through 74 are acceptable.

These amendments provided clarifica-tion of the piping systems and involved testing procedures and acceptance cri-teria for test data. The programs, as clarified, provide assurance that the piping systems, restraints, components, and supports have been adequately designed to accommodate thermal motion and to withstand flow-induced dynamic loadings under steady-state and operational transient conditions anticipated during the life of the plant.

In addition, as part of NRC inspections, reviews will be performed to assure that the applicant's dynamic testing and analysis programs are implemented adequately.

These reviews will include assessments of (1) the test program prerequisites which assure that all piping hangers and restraints are installed and adjusted for the as-designed configuration and that each system will be tested under normal and upset conditions that could reasonably be expected to occur during the plant lifetime; (2) the manner in which the cognizant design personnel from organizations responsible for the piping systems will partici-pate in the development, conduct, ovaluation, and approval of the test results; and (3) the manner in which the data obtained from the separate vibration, thermal expansion, and dynamic response test programs will be combined and evaluated to assure that total system response is in accordance with the design.

I Comanche Peak SSER 23 3-14

c 3.9.3 ASME Code Classes 1, 2, and 3 Components, Component Supports, and Core Support Structures As documented in Section 4.1.2.2 of SSER 14, based on its review of changes made by Amendment 61 to the CPSES FSAR, the staff determined that the changes did not significantly alter the staff findings in the CPSES SER and in SSERs 1 through 4 and 6 through 13, except in areas related to (1) the combination of loss-of-coolant accident and SSE loads (Section 3.9.2.3 of the SER) and (2) the piping system damping values (Section 3.7.1 of the SER).

A similar determination was made following staff evaluations of subsequent changes made by later amendments through Amendment 76.

The results of staff evaluations of the Amendment 61 and subsequent changes through Amendment 76 are as follows:

(1) In FSAR Section 3.9B.3, the applicant specified the code of record for the piping systems and pipe supports.

FSAR Section 3.98.3 provides that piping systems will be designed and fabricated in accordance with the ASME Code,Section III,1974 edition, including the summer 1974 addenda, Subsections NC and ND, and piping supports will be designed and fabricated in accordance with the ASME Code Section III Subsection NF, 1974 edition, including the winter 1974 addenda.

In addition, FSAR Section 3.98.3 invoked paragraph NA-1140 of the 1974 edition of the ASME Code for the use of later code provisions and referenced the plant specifications for the location of details relating to the code editions, addenda, and cases utilized for the qualification of ASME Code Classes 2 and 3 piping systems and pipe supports.

The code of record specified for the ASME Code Classes 2 and 3 piping sys-tems and pipe supports was acceptable.

The ASME Code editions and addenda specified reflected the dates of issuance of the procurement specifications for the piping systems and supports.

In addition, as documented in Section 4.1.2.2 of SSER 14. on the basis of its review of the technical justifications provided in the applicant's report entitled " Documentation of ASME III NA-1140 Review for Piping and Supports," Revision 2, September 30, 1987, the staff determined that the applicant's use of later ASME Code provisions was acceptable.

All related requirements associated with the use of specific provisions of a code edition or addenda had been met.

Specific provisions from later code editions and addenda reviewed and approved by the staff for CPSES were listed in Section 4.1.2.2 of SSER 14.

However, as detailed in SSER 14, acceptance of some of the code editions and addenda listed in Section 4.1.2.2 was contingent on final acceptance by the staff for their incor-poration in an update to 10 CFR 50.55a.

On May 5, 1988, 10 CFR 50.55(a) was revised to incorporate Section III of the ASME Code through the 1985 addenda and the 1986 edition (53 F_R 16051).

(2) In Amendment 78 to FSAR Section 3.9B.3, the applicant provided details regarding the application and usages of ASME Code Cases N-318 and N-397.

Code Case N-397 is not utilized for piping stress analysis at CPSES, but Comanche Peak SSER 23 3-15 l

I any subsequent usage will be detailed in the FSAR and will be in compli-ance with the NRC letter to the applicant on the use of ASNE Code Cases N-397 and N-411, dated March 13, 1986.

The application and usages of Code Case N-318 to date at CPSES are listed in Table 3.9B-1F in the FSAR.

Any additional applications of Code Case N-318 will be included in a future FSAR amendment at the final reconciliation of the pipe support.

FSAR Sec-tion 3.78.1.3 was revised in Amendment 78 to discuss the applicati0n and usages of Code Case N-411. With the exception of one piping stress analysis problem, Code Case N-411 was used to determine the critical damping values for safety-related piping at CPSES.

In the one case for which Code Case N-411 was not utilized, the recommendations of RG 1.61 were used.

The staff approved limited use of ASME Code Case N-327 in Section 2.1 of Appendix A to SSER 14, and approved limited use of Code Cases N-318 and N-411 in Section 3.7.1 of SSER 21.

The additional description of the usages of these three code cases in Amendment 78 to the FSAR conforms to the staff's acceptance criteria detailed in SSER 14 and SSER 21.

Therefore, the appli-cation and usages of ASME Code Cases N-318, N-397, and N-411 for the CPSES piping and pipe supports are acceptable.

(3) In FSAR Section 3.98.1.1.1, the SSE was removed from the list of emergency condition transients (but was retained in the list of faulted condition transients).

The transients listed piping systems and Code Classes 1, 2, and 3 supports.

In addition, the SSE was deleted from the emergency con-dition, but was retained in the faulted condition load combinations in FSAR Tables 3.9B-1A through 3.9B-10 relating to ASME Code Classes 2 and 3 com-ponents and Classes 1, 2, and 3 pipe supports.

As documented in Section 4.1.2.2 of SSER 14, the change was in conformance with the service conditions specified in Appendix A to Section 3.9.3 of the NRC Standard Review Plan (NUREG-0800) and thus is acceptable.

(4)

In FSAR Section 3.9B.3.1.1, the applicant stated that peak dynamic responses from loadings shown in Tables 3.9B-1A and 3.9B-1B relating to ASME Code Classes 2 and 3 components and piping systems were to be combined using the square-root-of-the-sum-of-the-squares (SRSS) method.

Previously, the appli-cant had committed to combine the peak dynamic responses by the absolute sum method.

Previously, as documented in Section 4.1.2.2 of SSER 14, the staff had de-termined that the change from the absolute sum method to the SRSS method for combining peak dynamic responses for piping systems was consistent with the guidelines of NUREG-0484, " Methodology for Combining Dynamic Responses,"

Revision 1, May 1980, and thus is acceptable.

Subsequently, the applicant extended the scope of the change to include all ASME Code Classes 2 and 3 components, including piping and pipe supports.

The staff has determined that this SRSS methodology is also consistent with the guidelines of NUREG-0484 and therefore, is acceptable.

Comanche Peak SSER 23 3-16

i (5) In FSAR Section 3.9B.3.1.1, the applicant established functional capability stress limits in addition to those established by the ASME Code to ensure that during and after a design-basis accident condition, essential piping systems will maintain their capability to deliver the rated flow and re-tain their dimensional stability.

In addition, in FSAR Section 3.9B.3.1.1, the applicant specified that the stress limits for functional capability which had been previously given for CPSES in Section 3.9.3.1 of SSER 1 and SSER 3 were to provide ai alternate basis for assuring the functional cap-ability of stainless steel elbows and bends.

i As documented in Section 4.1.2.2 of SSER 14, the staff determined that (1) the functional capability stress limits established in FSAR Sec-tion 3.9B.3.1.1 were acceptable on the basis that these limits had been approved by the staff for all nuclear facilities and (2) the alternate criteria for stainless steel elbows and bends have been previously approved by the staff and are therefore, acceptable.

(6) In FSAR Section 3.9B.3.3, item 1.b, the applicant detailed the fluid tran-sient analysis methods used to establish the associated forcing functions necessary to perform the structural analyses of affected piping systems.

Of particular concern in closed relief systems were the large forces that could occur in piping subject to slug and two-phase flows or if water col-umns are present in the discharge piping.

As documented in Section 4.1.2.2 of SSER 14, based on the results of its review and audits of the fluid transient analysis method, the staff deter-mined that the method of analysis was technically adequate and consistent with the analysis methods used for other nuclear facilities and thus, is acceptable.

(7)

In FSAR Section 3.98.3.4.3, the applicant added item h by Amendment 66 to allow the AISC " Specification for the Design. Fabrication and Erection of Structural Steel for Buildings," dated November 1, 1978, including Supplement I dated March 11, 1986, to be utilized in the analysis of struc-tural tubing used in instrument impulse tubing supports for ASME Code,Section III, Classes 2 and 3 safety-related applications.

The use of the 1986 AISC specification for the analysis of structural tubing in instrument impulse tubing supports for ASME Code,Section III, Classes 2 and 3 safety-related applications was acceptable.

Use of the 1986 AISC specification for these instrument tubing supports is consistent with the use of this edition of the AISC specification for the design and analysis of ASME Code,Section III, Classes 1, 2, and 3 pipe supports.

(8) In FSAR Table 3.9B-1B, the loading combinations and stress limits are pro-vided for ASME Code Classes 2 and 3 piping systems.

The normal condition was revised to include testing conditions and thermal anchor movements; the upset condition was revised to include thermal anchor movements; the emergency condition was revised to delete the SSE as previously described; and the faulted condition was revised to include temperature, thermal anchor movements, containment displacements, and SSE anchor movements.

l Comanche Peak SSER 23 3-17

As documented in Section 4.1.2.2 of SSER 14, the staff determined that (with the exception of the deletion of the SSE from the emergency condition) the revised load combinations are more conservative than those which were previously considered and are thus acceptable.

Moreover, the revised load combinations envelop those specified in Appendix A of Section 3.9.3 of the Standard Review Plan (NUREG-0800).

(9) In FSAR Table 3.9B-10, the loading combinations are provided for ASME Code Classes 1, 2, and 3 pipe supports. The testing condition was revised to include thermal and containment pressurization loads; the emergency con-dition was revised to delete the SSE as previously described; and the faulted condition was revised to include the SSE and containment anchor movement.

The revisions to Tables 3.9B-1B and 3.9B-10 resulted in con-sistency in load combinations specified for ASME Code Classes 2 and 3 piping systems and ASME Code Classes 1, 2 and 3 pipe supports.

The load combinations for the ASME Code Classes 1, 2, and 3 pipe supports specified in FSAR Table 3.9B-1C are in accordance with Appendix A to Section 3.9.3 of the Standard Review Plan (NUREG-0800) and RGs 1.124 and 1.130 and are, therefore, acceptable.

(10) In FSAR Appendix 3B, the applicant described the computer codes and veri-fication mettods used by the Stone & Webster Engineering Corporation in the piping and pipe support design validation.

As documented in Section 4.1.2.2 of SSER 14, these computer codes have been approved and used for other nuclear facilities and are thus acceptable for use at CPSES.

3.9.6 Inservice Testing of Pumps and Valves The design of safety-related pumps and valves in the CPSES units is intended to demonstrate that they will be capable of performing their intended safety func-tion at any time during the plant life. To provide added assurance of the re-liability of these components, the applicant will periodically test all safety-related pumps and valves.

These tests will be performed in general accordance with the rules of Sedion XI of the ASME Code and will verify that these pumps and valves operate successfully when called upon.

Additionally, periodic measurements of various parameters will be compared with baseline measurements to detect any long-term degradation of the pump or valve performance.

The staff review under SRP Section 3.9.6 covers the applicant's program for preservice and inservice testing of pumps and valves.

The staff gives particular attention to these areas of the test program for which the applicant requests relief from the requirements of Section XI of the ASME Code.

The staff's previous evaluation of the applicant's inservice test program (IST),

as reported in the SER and in S3ERs 1 and 12, is invalid because the applicant has changed the CPSES IST program.

The staff's reevaluation of the applicant's IST program follows.

Comanche Peak SSER 23 3-18

f The NRC staff and its consultant, EG&G Idaho, have performed an initial review of the " Comanche Peak Unit 1 Pump and Valve Inservice Testing (IST) Program,"

Revision 3, for the first 10 year interval, which the applicant submitted by letters dated August 21 and November 15, 1989.

The staff concludes that the IST program is complete with respect to all components required to be in the program.

On this basis, the staff has determined that an interim period of relief is appropriate until the staff can complete the safety evaluation of the program.

This preliminary evaluation is intended to provide an assessment of the CPSES Unit 1 IST program until a final safety evaluation is completed.

Since this interim approval does not represent the results of the final program review, the final safety evaluation could contain relief request denials or identify components that should be added to the CPSES Unit 1 IST program.

The staff's final safety evaluation of the applicant's IST program will be reported in a future supplement to the SER.

The staff concludes that granting this interim approval for the reliefs requested.

in the CPSES Unit 1 IST program pursuant to 10 CFR 50.55a for the first 10 year interval, will not endanger life or property or the common defense and security.

Granting the approval is otherwise in the public interest considering the burden that could result if the requirements were imposed on the facility.

This interim relief will terminate on final action on the items covered.

Comanche Peak SSER 23 3-19

4 REACTOR 4.2 Fuel Desian 4.2.1 Description The FSAR indicates that absorber materials used in the control rods can be either: (1) all hafnium (primary design), (2) all silver-indium-cadmium alloy (alternate design), or (3) boron carbide pellets with silver-indium-cadmium alloy tips.

On the basis of discussions with the applicant, the staff-under-stands that the applicant intends to use silver-indium-cadmium control rods in the Comanche Peak Steam Electric Station (CPSES) Units 1 and 2.

If it becomes necessary to use Westinghouse-supplied full-length hafnium control rods in either Unit 1 or 2, the applicant will incorporate West '...whouse-recommended sur-veillance guidelines into a surveillance program for the hafnium control rods.

The Westinghouse guidelines are documented in a letter dated March 30, 1989 from W. J. Johnson to C. H. Berlinger of the NRC titled " Revised Hafnium RCCA Exami-nation Guidelines."

In Supplement I to the Safety Evaluation Report (SSER 1), the staff concluded thdt there is reasonable assurance that the substitution of hafnium for the silver-indium-cadmium absorber in CPSES control rods will not result in reduced safety margins or reliability and is, therefore, acceptable.

This conclusion is still valid, subject to implementation of the Westinghouse surveillance guidelines noted above, if full-length hafnium control rods are used.

4.2.3 Mechanical Performance The margin to departure from nucleate boiling (DNB) is expressed in terms of the DNB ratio (DNBR), which is defined as the ratio of the heat flux required to produce DNB at the calculated local coolant conditions to the actual local heat flux.

The applicant has proposed a minimum DNBR of 1.30 to ensure that there is a 95 percent probability at a 95 percent confidence level that the critical heat flux for DNB will not occur on the limiting fuel rod.

Fuel rod bowing reduces the value of the DNBR.

The maximum rod bow penalties accounted for in the design safety analysis are based on an assembly average burnup of 33,000 megawatt-days per metric ton uranium (MWD /MTU).

Applicable generic credits used to of fset the effect of rod bow are based upon conserva-tivism in the evaluation of DNBR and/or margin obtained from measured plant operating parameters which are less limiting than those required by the plant safety analysis.

For the safety analysis of CPSES Units 1 and 2, sufficient margin (9.1%) was maintained to accommodate full-and low-flow DNBR penalties.

The basis for this margin is indicated in the Final Safety Analysis Report (FSAR) and Technical Specifications bases on power distribution limits and in-cludes design-limit DNBR, grid spacing, thermal diffusion coefficient, DNBR multiplier, and pitch reduction.

The staff considers the basis to be accept-able for the generic margin used to offset the reduction in DNBR caused by rod bowing.

Comanche Peak SSER 23 4-1

4.3 Noclear Desian 4.3.2 Design Description Two additional primary neutron sources will be installed in two symmetric fuel assemblies, as indicated in Amendment 74 to the FSAR, because the currently installed primary sources are no longer adequate.

In addition, Amendment A indicates that the FSAR has been modified to reflect that the secondary sc e e assemblies do not contain burnable poison rods. The staff considers thest changes to be acceptable since the design changes have no adverse impact on the ability of the plant to meet all operating limits.

4.3.2.7 Vessel Irradiation Values are oresented for neutron flux in various energy ranges at mid-height of the pressure vesul inner boundary.

Core flux shapes calculated by stand-

)

ard design methods are input to a transport theory calculation which results in a neutron flux (indicated in the SER) of 2.8 x 1010 neutrons /cm2/sec having energy greater than 108 electron-volts at the inner vessel boundary.

This re-suits in a fluence of 2.8 x 1018 neutrons /cm2 for a 40 year vessel life with an 80 percent factor.

The SER states that the :nethods used for these calculations -

are stete of the art, and the staff concludes that acceptable analytical pro-cedures were used to calculate the vessel fluence.

Although Table 4.3-6 of the FSAR indicates that the above neutron flux at the inner boundary is 2.08 x 1010 (vs. 2.8 x 1010) neutrons /cm2/sec, this does not alter the above original staff conclusion concerning the analytical procedures for calculating vessel fluence.

4.4 Thermal-Hydraulic Desian m

4.4.3 Thermal-Hydraulic Design Comparison The thermai-hydraulic design parameters for CDSES Units 1 and 2 are listed in Tabic 4.1.

A comparison of these parameters with those of the Trojan and W. B. McGuire plants is included.

Table 4.1 differs-from that table in the SER because of revisions to CPSES parameters that are reflected in Table 4.4-1 of the FSAR (Amendment 46).

The major differences between Trojan and CPSES are an increase in the flow rate and a decrease in the maximum heat flux for CPSES.

These changes result in a greater safety margin. The CPSES units' thermal-hydraulic design is comparable to that of Trojan and W. B. McGuire, which have been pteviously reviewed and approved by the staff.

The comparability of the CPSES thermal-hydraulic design with the Trojan and W. B. McGuire plants and the fact that the CPSES units will have an increased safety margin over the Trojan design support the original SER conclusion that the CPSES thermal-hydraulic design is acceptable.

Comancho Peak SSER 23 62

Table 4.1 Reactor design comparison Trojan W. B. McGuire CPSES Comparison basis Unit 1 Units 1 and 2 Units 1 and 2 Performance characteristics Reactor core heat output (MWt) 3411 3411 3411 System pressure (psia) 2250 2250 2250 Minimum DNBR 1.30 1.30 1.30 Typical cell 2.04 2.08 2.04 Thimble cell 1.71 1.74 1.70 Critical heat flux correlation W-3 W-3 W-3 Coolant flow j

Total flow rate (100 lb/hr) 132.7 140.3 142.0 Effective flow rate for heat i

transfer (106 lb/hr) 126.7 134.0 133.7 Average velocity along fuel rods (ft/sec) 15.7 16.7 16.6 Coolant temperature, *F Nominal reactor inlet 552.7 558.1 559.6 Average rise in core 66.9 62.7 62.5 Heat transfer, 100% power i

Active heat transfer surface 59,700 59,700

.59,700 2

(ft )

Average heat flux (ETU/hr-ft )

189,800 189,800 180,800 2

Maximum heat flux (BTU /hr-ft )

574,500 440,300 440,300 2

Average-linear heat rate (kW/ft) 5.44 5.44 5.44 Maximum thersal output (kW/ft) 13.6 12.6 12.6 i

I Comanche Peak SSER 23 4-3 j

4 TD'

5 REACTOR COOLANT SYSTEM 5.4 Component and Subsystem Design 5.4.3 Residual Heat Removal System 5.4.3.3 1.oss of Decay Heat Removal (Generic Letter 88-17)

The staff has reviewed the applicant's February 10 and June 1, 1989 responses to Generic Letter (GL) 88-17 for programmed enhancements for loss of decay heat removal for CPSES Units 1 and 2.

The letter of February 10, 1989 included re-1 sponses to expeditious actions and programmed enhancements.

The staff review of the expeditious actions is documented in Section 5.4.3.3 of SSER 22.

Further staff review of the applicant's submittals has concluded that the re-sponses appear to meet the intent of the generic letter with respect to pro-l grammed enhancements.

Responses were provided for each of the six programmed-enhancement recommendations identified in the generic letter.

In a number of-instances, the applicant stated that revisions or analyses have not yet been a

completed.

The applicant has also stated, however, that all Unit 1 activities 1

related to the generic letter will be completed prior to entry into the first 1

reduced-inventory condition (mid-loop operation) following the achievement of 5 percent power in Unit 1.

Unit 2 activities are to be completed before Unit 2

~

fuel load.

These schedules are in accordance with those specified'in the ge-neric letter.

1 Temporary Instruction (TI) 2515/103 was written to verify that the applicant's preparation for non power operation is in accordance with.the programmed en-hancement phase of loss of decay beat removal (Generic Letter 88-17). The audit J

to be performed under TI 2515/103 will ensure that the applicant has adequately

'ssed the guidelines of GL 88-17 for operation' while in a-reduced inventory

-s condition.

l The staff considers this issue resolved upon satisfactory audit findings under l

TI 2515/103.

I i

k i

a i

Comanche Peak SSER 23 5-1 a

6 ENGINEERED SAFETY FEATURES 6.2 Containment Systems 6.2.3 Containment Isolation System In Sections 6.2.3 and 22.2 (II.E.4.2) of the Safety. Evaluation Report (SER)',

the staff concluded that the 18-inch containment penetration for the contain-ment pressure relief system was acceptable based on the applicant's commitment to limit its usage to less than 90 hours0.00104 days 0.025 hours 1.488095e-4 weeks 3.4245e-5 months per year during plant operating Modes 1 through 4.

In Amendment 78 to the Final Safe.y Analysis Report (FSAR).-the i

applicant identified a design change which added an orifice plate that changes the effective diameter of the penetration to 3 inches.

On the basis of;this design change, the time restriction on usage of the relief system-is no longer required. The staff concludes that the revised design is in accordance.with the guidelines of Branch Technical Position (BTP) CSB 6-4 as it relates to con-tainment penetrations of 3 inches or less and is, therefore, acceptable.

6.4 Control Room Habitability In SSER 22, the staff reported on its review of the applicant's new calculated doses to control room operators following a loss-of-coolant accident (LOCA) _

l addressed in various FSAR amendments since the SER was issued.

The staff con -

cluded that the new calculated doses of 26 rem (thyroid) and 1.7 rem (whole-body) were within the requirements of General Design' Criterion (GDC) 19.(10 CFR 4

Part 50, Appendix A) and the guidelines of Standard Review Plan'Section 6.4.

FSAR Amendment 78 provided additional changes resulting from the applicant's l

reanalysis of the dose to control room occupants due to post-LOCA leakage from engineered-safety-features equipment located outside the containment.

The re-

)

sultant radiation doses are 30 rem (thyroid) and 1.7 rem (whole body).

These doses are within the requirements of GDC 19 and are, therefore, acceptable.'

6.5 Engineered Safety Features Materials 6.5.1 System Description and Evaluation 6.5.1.1 Fuel Handling Building Ventilation System l

.In SER Section 6.5.1.1, the staff indicated that an efficiency of 99 percent

-was assumed for the-high-efficiency particulate air (HEPA) filters and charcoal adsorbers of the primary plant filtration units.

In FSAR Amendments 76 and 78, the applicant provided clarification to identify that the charcoal adsorber-efficiency for the primary plant filtration units is assumed-to be 95 percent which corresponds to an acceptance criterion of less than'l percent for in place penetration and bypass leakage at rated flow.

The staff concludes that this change is acceptable because both the FSAR Chapter 15 accident analyses' dose calculations and the f's confirmatory calculations presented in Section 15 of this supplement are ;.unsistent with this filter efficiency assumption.

The 1

i 1

Comanche Peak SSER 23 6-1 -.

i fuel handling accident assumes no filtration of the accident releases and the LOCA analysis assumes 95 percent efficiency for releases of activity due to leakage from systems outside containment.

6.5.2 Containment Spray System The staff's evaluation of the spray coverage reported in the SER was based on 6 ft3 and a spray coverage of approxi-a containment free volume of 2.985 x 10 mately 58 percent.

The SER concluded that the atmosphere-in the containment volume not directly covered by the spray would be adequately mixed due to the convection process.

The analysis conservatively assumed an air turnover rate of two turnovers per hour.

The applicant has slightly revised the FSAR values-of spray coverage and containment free volume to 56.7 percent and 3.031 x 108 ft, respectively.

These small changes will not change the spray effectiveness 3

because of the large conservatisms inherent in the air turnover rate used by the applicant. The staff's conclusion of the acceptability of the containment spray effectiveness that was reached in the SER is, therefore, still valid.

Comanche Peak SSER 23 6-2

=

7 INSTRUMENTATION AND CONTROLS 7.2 Reactor Trip System 7.2.1 Description Section 7.2.1 of Safety Evaluation Report (SER) Supplement 22 (SSER 22) de-scribed the power-range high positive-neutron-flux-rate. trip, based on.infor-mation contained in the Comanche Peak Steam Electric Station (CPSES) Final Safety Analysis Report (FSAR).

In Amendment 78 to the FSAR, the applicant.

revised the description 'of the trip's function by removing reference to the phenomenon of departure from nucleate boiling (DNB).

The.FSAR now states that this reactor trip provides protection against rod-ejection accidents of low.

worth from midpower and is always active.

The previous reference in the FSAR to DNB was an error and the staff agrees that the FSAR description of this re-actor trip function is the correct one.

1 7.2.6 Generic Implications of ATWS Events at the Salem Nuclear. Power Plant (Generic Letter 83-28)'

j On July 8,1983, the NRC staff issued Generic Letter-(GL) 83-28, which indicated acT, ions to be taken by licensees and applicants based on the generic implica-tions of the anticipated transient without scram (ATWS) events at~the Salem nu-clear power plant that occurred on February 22 and 25, 1983.

The staff's.evalu-ation of the responses submitted by the applicant for CPSES Units 1 and 2.to i

GL 83-28 Action Items 2.2.2, 4.2.1, 4.2.2, 4.2.3, 4.2.4, and 4.5.3 are provided l

below.

]

(2) Equipment Classification and Vendor Interface Item 2.2.2: Vendor Interface Program for All. Safety-Related Components This aspect of GL 83-28 requires licensees and applicants to describe their programs to ensure that vendor information for safety-related components is complete, current, and controlled throughout the life of the plant. ~The appli-cant responded in letters dated November 3, 1983; November 21, 1983; April 30, 1984; June 7, 1985; and April 11, 1988.

The applicant was an active partici-i pant in the Nuclear Utility Task Action Committee (NUTAC) which developed.the Vendor Equipment Technical Information Program (VETIP) Report; the VETIP Report i

has.been reviewed generically by the staff.

The. applicant is committed.-to im-l plementation of the NUTAC-VETIP and has established programs with Westinghouse-and the diesel generator vendor.

Contacts with other.vondors are established during the procurement process for spare and replacement parts.

As a require-nient of each purchase, the vendor must supply updated technical manuals and other current related technical information. '.The staff is preparing l additional l"

generic guidance for the industry which will clarify the scope.and details of vendor interface programs, the staff's understanding of VETIP, and; associated staff reviews.

On the basis of its review of the applicant's description.of its vendor interface programs and continuing generic efforts, the staff con-y cludes that the response to item 2.2.2 is acceptable.

l 4

Comanche Peak SSER 23 7-1 i

i

(4) Reactor Trip System Reliability Item 4.2:

Reactor Trip System Reliability (Preventive Maintenance and Surveillance Program for Reactor Trip Breakers)

Item 4.2.1:

Requires licensees and applicants to describe their program of periodic maintenance, including lubrication, housekeeping, and other items l

recommended by the equipment supplier to ensure reliable reactor trip breaker operation.

i The applicant responded to item 4.2.1 by letters dated November 3, 1983; June 7, 1985; June 2, 1986; and June 5, 1989.

In a safety evaluation dated December 5, J

I 1985, the staff found the applicant's program of periodic maintenance for the reactor trip breakers to be acceptable with one exception.

The applicant did not consider the UVTA trip force measurement to be of any significant value.

Subsequently, by correspondence dated June 2, 1986, the applicant stated that the UVTA trip force and breaker load check would be incorporated into the CPSES maintenance or surveillance program. -The staff finds this to be acceptable.

By letter dated June 5, 1989, the applicant advised the NRC that Westinghouse had issued a revised maintenance manual, dated November 1986.

On the basis.of this revised manual, the licensee stated that type A maintenance woutd be per-formed every 500 cycles or each refueling outage (instead of every six months),

whichever comes first, and meggering of breaker. Insulation resistance was no longer required.

The staff finds this to be consistent with the equipment sup-plier's recommendations as specified by item 4.2.1.

Also, the staff concludes that these changes will not significantly decrease the reliability of the re-actor trip breakers, and may actually improve safety because the train associ-ated with the breaker being maintained will not be made inoperable during re-actor operation.

The staff, therefore, finds the revised maintenance proce-dures to be acceptable.

Item 4.2.2:

Requires licensees and applicants to trend parameters'affecting operation and measured during testing to forecast degradation of operability of reactor trip breakers (RTBs).

The applicant submitted responses to item 4.2.2 by letters dated November 3, 1983; June 7, 1985; and June 5, 1989.

In a safety evaluation of December 5, 1985, the staff found the applicant's program of trending the parameters of the reactor trip breakers to be acceptable.

i By letter dated June 5, 1989, the applicant advised the NRC that Westinghouse had issued a revised maintenance manual, dated November 1986.

On the basis of this revised manual, the applicant stated that RTB insulation resistance and breaker response time-for RTB undervoltage trip are no longer trended.

How-ever, breaker response times are measured in conjunction with the CPSES' reactor protection system (RPS) response time procedures which are performed each re-fueling outage.

The staff finds this to be consistent with the equipment sup-plier's recommendations as specified by item 4.2.1.

Also, the staff concludes that trending of insulation is of negligible value in assessing the ability of the RTBs to perfc 6,

s' w v function.

Further, any significant degrada-tion of breaker -.; ne tiu Muld be disclosed by the RPS response time test-ing.

The '.taf f.

u-m,'

.s the trending procedures'to be acceptable.

Comanche Peak SSER 23 7-2

Item 4.2.3:

Requires licensees and applicants to life test (i.e., establish the life expectancy through testing) the breakers (including the trip attachments) on an acceptable sample size of reactor trip breakers (RTBs).

The applicant submitted responses to item 4.2.3 by letters dated November 3, 1983 and May 31, 1989.

The applicant contended that any further life testing of the RTBs than has already been done is unnecessary because the breakers are located in a mild environment and the current preventive maintenance and sur-veillance program is adequate to maintain the reliability of the RTBs.

The staff is reevaluating the desirability of performing life testing on the RTBs for all applicants and licensees and proposes to resolve this issue by generic action.

Nothing further need be done on a plant-specific basis at this time.

Item 4.2.4:

Requires applicants and licensees to periodically replace the re-actor trip breakers (RTBs) or components consistent with the demonstrated life cycles.

The applicant submitted responses to item 4.2.4 by letters dated November 3, 1983 and May 31, 1989.

As described under item 4.2.3 above, the applicant contended that any further life testing of the RTBs is unnecessary.

Since the replacement of the RTBs is to be based on the demonstrated life cycles, this issue cannot be resolved separately from item 4.2.3.

Therefore, this issue will also be resolved by the staff generically and nothing further need be done on a plant-specific basis at this time.

Item 4.5.3: On-Line Functional Testing of the Reactor Trip System Item 4.5.3 required confirmation from all licensees and applicants that on-line functional testing of the reactor trip system (RTS), including independent test-ing of the diverse trip feature was being performed.

Existing intervals for on-line functional testing required by Technical Speci-fications were to be reviewed to determine if the test intervals were adequate for achieving high RTS availability when accounting for considerations such as:

(1) uncertainties in component failure rates, (2) uncertainties in common-mode failure rates, (3) reduced redundancy during testing, (4) operator error during testing, and (5) component "wearout" caused by the testing.

By letter dated June 7, 1985 the applicant submitted its response to Generic Letter 83-28, item 4.5.3.

Therein the applicant indicated its endorsement of Westinghouse report WCAP-10271, " Evaluation of Surveillance Frequencies ar.d Out of Service Times for the Reactor Protection Instrumentation System", and its Supplement 1, as being applicable to CPSES.

The NRC staff, with the as-sistance of its contractor, Idaho National Engineering Laboratory (INEL), has reviewed the Westinghouse report and its supplement.

The results of INEL's review are reported in detail in EGG-NTA-8341, "A Review of Reactor Trip System Availability Analyses for Generic Letter 83-28, Item 4.5.3 Resolution," dated March 1989 and summarized below.

The Babcock & Wilcox, Combustion Engineering, General Electric, and Westinghouse Owners groups have submitted topical reports either in response to GL 83-28, item 4.5.3 or to provide a basis for requesting Technical Specification changes to extend RTS surveillance test intervals (STIs).

The owners groups' analyses addressed the adequacy of the existing intervals for on-line functional testing of the RTS, with the considerations required by item 4.5.3, by quantitatively estimating the unavailability of the RTS. ' These analyses found that the RTS was very reliable and that the unavailability was dominated by common-cause failure and human error.

Comanche Peak SSER 23 7-3

The ability to accurately estimate unavailability for very reliable systems was considered extensively in NUREG-0460, " Anticipated Transients Without Scram for Light Water Reactors," and the ATWS rulemaking.

The uncertainties of such estimates are large; because the systems are highly reliable, very little experience exists to support the estimates; and common-cause failure probabil-ities are difficult to estimate.

Therefore, the staff concludes that the RTS unavailability estimates in these studies, although useful for evaluating test intervals, must be used with caution.

NUREG-0460 also~ states that for systems with low f ailure probability, such as the RTS, common-mode failures tend to predominate, and, for a number of rea-sons, additional testing will not appreciably lower RTS unavailability.

First, testing more frequently than weekly is generally impractical, and even so the increased testing could at best-lower the failure probability by less than a factor of four compared to monthly testing.

Secondly, increased testing could possibly increase the probability of a common-mode failure through increased stress on the system.

Finally, not all potential failures can be detected by testing.

In summary, NUREG-0460 provides additional justification to demon-strate that the current test intervals are adequate to maintain high RTS avail-ability.

All four vendors' topical reports, including the Westinghouse report referenced by the applicant, have shown the currently configured RTS to be highly reliable, with the current test intervals.

INEL reviewed these analyses and performed independent estimates of its own which conclude-that the current test intervals provide high reliability.

In addition, the analyses in NUREG-0460 have shown i

that for a number of reasons, more frequent testing will not appreciably lower the estimates of failure probability.

On the basis of the staff's review of the owners groups' topical reports, the INEL independent analysis, and the findings noted in NUREG-0460, the staff con-cludes that the existing intervals, as recommended in the topical reports for on-line functional testing, are consistent with achieving high RTS availability at all operating reactors, and in particular, at CPSES.

Therefore, the staff considers item 4.5.3 to be complete.

Conclusion The status of the actions required by GL 83-28 is as follows:

Action Item Status Action Item Status 1.1 Closed in SSER 12 4.1 Closed in SSER 21 1.2 Closed in SSER 21 4.2.1 Closed in SSER 23 2.1 Closed in SSER 21 4.2.2 Closed in SSER 23 2.2.1 Closed in SSER 22 4.2.3 Generic action pending 2.2.2 Closed in SSER 23 4.2.4 Generic action pending-3.1.1 Closed in SSER 21 4.3 Closed in SSER 22 3.1.2 Closed in SSER 21 4.4 Not applicable 3.1.3 Closed in SSER 21 4.5.1 Closed in SSER 21 3.2.1 Closed in SSER 21 4.5.2 Closed in SSER 21 3.2.2 Closed in SSER 21 4.5.3 Closed in SSER'23-3.2.3 Closed in SSER 21 I

Comanche Peak SSER 23 7-4

T i

The resolution of the action items that are not closed (4.2.3 and 4.2.4) will be pursued on a generic basis and nothing further needs to be done on a plant-specific basis at this time.

These two action items arti classified as complete for the purpose of licensing CPSES.

The staff will report on the generic resolution of these two action items via an NRC bulletin or similar generic communication to the nuclear industry.

Outstanding Issue 3 in SSER 22 is, therefore, resolved.

7.5 Information Systems Important to Safety 7.5.2 Postaccident Monitoring On December 17, 1982, Generic Letter 82-33 was issued by D. G. Eisenhut, Director 1

of the Division of Licensing, Office of Nuclear Reactor Regulation, to all li-censees of operating reactors, applicants for operating licenses, and holders of construction permits. This letter included additional clarification regarding Regulatory Guide (RG) 1.97, Revision 2, relating to the requirements for emergency response capability.

These requirements have been published as Supplement 1 to e

NUREG-0737, " Clarification of TMI Action Plan Requirements."

The applicant's response to Section 6.2 of the generic letter is contained in Section 7.5 of the CPSES FSAR and in letters dated March 31, May 19, and i

June 16, 1989.

The staff's review was based on the recommendations of RG 1.97, Revision 2, and compares the instrumentation identified in Section 7.5 and Tables 032.110-1 through 032.110-6 of the FSAR (through Amendment 78) with these recommendations.

Unless otherwise noted, all future references to RG 1.97 are references to Revision 2 to RG 1.97.

Section 6.2 of NUREG-0737, Supplement 1, denotes the documentation to be submitted to the NRC which describes how the applicant complies with RG 1.97 in regard to emergency response facilities.

The applicant's submittals should include docu-mentation that provides the following information for each variable shown in the applicable table of RG 1.97.

instrument range environmental qualification seismic qualification quality assurance redundancy and sensor location power supply location of display schedule of installation or upgrade The applicant's submittals should identify any deviations from the recommenda-tions of RG 1.97 and should provide supporting justification or alternatives for the deviations identified.

Subsequent to the issuance of GL 82-33, the NRC held regional meetings in February and March of 1983 to answer licensee and applicant questions and con-cerns regarding the NRC policy on this subject.

At these meetings, it was noted that the NRC review would address only exceptions taken to RG 1.97.

It also noted that when licensees or applicants explicitly state that instrument i

Comanche Peak SSER 23 7-5

sys'tems conform to RG 1.97, no further staff review would be necessary.

There-fore, this report addresses only those exceptions to RG 1.97 that have been identified by the applicant.

The following evaluation of the submittals pro-vided by the applicant is based on the NRC review policy described in the regional meetings.

In FSAR Section 7.5, the applicant reviewed its postaccident monitoring instru-mentation, comparing the instrumentation characteristics with the recommenda-tions of R6 1.97; the applicant also submitted material on March 31, May 19, and June 16, 1989.

The applicant indicated in FSAR Section 7.5.3.6 that CPSES meets the intent of RG 1.97.

Therefore, the staff concludes that the applicant has provided a commitment on conformance to RG 1.97, with exceptions and devia-tions as noted below.

RG 1.97 does not specifically identify type A variables, that is, those vari-ables which provide information required to permit the control room operator to take specific manually controlled safety actions.

The applicant classified the following instrumentation as type A:.

(1) reactor coolant system (RCS) cold-leg water temperature (wide range)

(2) RCS hot-leg water temperature (wide range)

(3) RCS pressure (wide range)

(4) core exit temperature (5) degrees of subcooling (6) containment sump our level (wide range)

(7) containment pressure (intermediate range)

(8) refueling water storage tank level (9) pressurizer level I

(10) steam generator level (narrow range)

(11) steam generator pressure (12) auxiliary feedwater flow (13) condensate storage tank water level This instrumentation meets the Category 1 recommendations consistent with the requirements for type A variables with the exceptions discussed in the para-graphs that follow.

In addition, the. applicant identified deviations from and exceptions to RG 1.97 which, along with issues resolved during the course of the staff's review, are discussed below.

Reactor Coolant System Soluble Boron Concentration RG 1.97 recommends a control room display of zero to 6000 parts per million (ppm) for the instrumentation supplied for this variable.

The applicant has not provided on-line instrumentation for this variable and stated that this variable is monitored by the.postaccident sampling system using laboratory an-alysis.

The available range is 500 ppm to 6000 ppm.

This area-of design devi-ates from RG 1.97 with respect to postaccident sampling capability.

The staff addressed this deviation when it reviewed NUREG-0737, Item II.B.3, and found it acceptable.

Reactor Coolant System Cold-Leg Water-Temperature RG 1.97 recommends a control room display with a range from 50 F to 750 F for this variable.

The instrumentation provided by the applicant for this variable Comanche Peak SSER 23 7-6

has a range of 50 F to 700 F.

Revision 3 of RG 1.97 recommends a range of 50 F to 700*F for this instrumentation.

Therefore, the range supplied by the appli-cant for this instrumentation is acceptable.

4 Reactor Coolant System Hot-Leg Water Temperature RG 1.97 recommends a control room display with a range from 50 F to 750 F for this variable.

The instrumentation provided by the applicant for this variable has a range of 50 F to 700 F.

Revision 3 of RG 1.97 recommends a range of 50 F to 700 F for this instrumentation. Therefore, the range supplied by the appli-i cant for this instrumentation is acceptable.

Reactor Coolant Level RG 1.97 recommends reactor coolant level instrumentaticn with a range from the bottom of the core to the top of the reactor vessel.

The instrumentation pro-vided by the applicant has a range covering from the upper core plate to the top of the reactor vessel.

Revision 3 of RG 1.97 recommends a range from the bottom of the hot leg to the top of the reactor vessel for this instrumentation.

The instrumentation provided by the applicant m'eets this range.

Therefore, the range supplied by the applicant for this instrumentation is acceptable.

Containment Sump Water Level RG 1.97 recommends both narrow-range and wide-range (up to 600,000 gal) instru-mentation for containment sump water level.

The acplicant has provided wide-range instrumentation that has indication from 806 ft to 817 ft 6 in.

There is no separate narrow-range instrumentation for this variable. The applicant sta-ted that the wide-range instrumentation displays the entire range of expected postaccident levels in the containment and includes the information that the recommended narrow-range instruments would display.

Because the wide-range instruments are inclusive of the narrow range recemmendations, the staff finds the instrumentation supplied for this variable acceptable.

Containment Isolation Valve Position The applicant identified an exception to RG 1.97 fo" thi

..c dale in that the manually operated containment isolation valves do not he.c l'e "0 commended valve position-indication instrumentation. Those containment. isolation valves that are operated automatically have the recommended position-indication instrumen-tation for each valve.

The applicant provided documentation which states _that all manually operated containment isolation valves are administratively control-led and locked in the closed position.

Thus, the operator is aware of the posi-tion of these valves in a postaccident situation.

Because the operator is aware that these valves are locked closed and has indication for the automatically operated isolation valves, the staff finds the instrumentation provided for containment isolation valve position acceptable.

Additionally, the applicant's containment isolation valve position-indication instrumentation deviates from a strict interpretation of the Category 1 recom-4 mendation for redundant instrumentation.

There is one open/ closed limit switch per automatic valve with indication at the control switch and at monitor light boxes.

Since redonnant isolation valves are provided, the staff finds that the regulatory guide coes not intend redundant indication per valve.

There is re-dundant indication of the isolation function.

The containment isolation valve I

Comanche Peak SSER 23 7-7

l position-indication instrumentation meets the Category 1 criteria.

Therefore, the staff finds that the instrumentation P>vided is acceptable.

Residual Heat Removal Exchanger Outlet Temperature RG 1.97 recommends instrumentation with a range from 32 F to 350*F for this variable.

The instrumentation provided by the applicant for this variable has a range of 50 F to 400 F, an 18' deviation in the lower limit of the range.

The applicant provided documentation which states that the 50 F-to-400'F range covers the anticipated requirements for normal operation, anticipated operational occurrences, and accident conditions.

On the basis of this statement, the staff finds the provided range acceptable.

Accumulator Tank Level and Pressure J

RG 1.97 recommends instrumentation with ranges from 10 percent to 90 percent of the accumulator tank volume for level and from zero to 750 psig for the accumu-i lator tank pressure.

The applicant has designated pressure as the key instru-mentation for this variable and has supplied Category 2 pressure instrumentation.

Category 3 level instrumentation is acceptable as backup instrumentation to the Category 2 pressure instrumentation.

The supplied instrumentation has ranges from zero to 100 percent (level) and zero to 700 psig (pressure).

The applicant provided documentation which states that both ranges cover the anticipated re-quirements for normal operation, anticipated operational occurrences, and ac.:i-dent conditions.

On the basis of this-statemer.t, the staff finds the provided ranges acceptable.

Flow in Low-Pressure Injection System RG 1.97 recoenends Category 2 instrumentation for this variable.

Section 7.5 of the FSAR does not address this variable; however, from previously submitted material for the CPSES design, low pressure injection is a residual heat removal (RHR) system function. The RHR flow is monitored by Category 2 instrumentation in accordance with kG Guide 1.97.

Therefore, the staff finds the instrumentation provided for this safety-injection function acceptable'.

Boric Acid Charging Flow RG 1.97 recommends Category 2 instrumentation for this variable to monitor safety-injection flow.

Section 7.5 of the FSAR states that in the CPSES design, this safety-injection flow is established by the centrifugal charging pump.

The centrifugal charging pump flow is monitored by Category 2 instrumentation in accordance with RG 1.97.

Therefore, the staff finds the instrumentation provided for this safety-injection function acceptable.

Quench Tank Temperature RG 1.97 recommends instrumentation with a range from 50*F to 750 F for this variable.

The instrumentation provided by the applicant for this variable has a range from 50 F to 350 F.

The applicant provided documentEtion which states that the 50 F-to-350 F range covers the anticipated requirements-for normal operation, anticipated operational occurrences, and' accident conditions.

This is related to the design pressure (100 psig) of the tank and the corresponding saturated steam temperature at this pressure.

On the basis-of this statement, the staff finds the provided range acceptable.

j Comanche Peak SSER 23 7-8 l

s

Steam Generator Level Wide-Range RG 1.97 recommends Category 1 instrumentation for this variable.

The applicant stated that this instrumentation was Category 2 backup instrumentation; however, no deviations from Category 1 requirements were identified.

Subsequently, the applicant verified that this instrumentation satisfied Category 1 requirements and the RG 1.97 recommendations.

The staff finds this to be acceptable.

Steam Generator Pressure RG 1.97 recommends that instrumentation for this variable have a range from atmospheric pressure to 20 percent above the lowest safety valve. setting.

Sec-tion 10.3.2.1 of the CPSES FSAR stetes that the safety valve with the lowest set point is set at 1200 psig; therefore, the upper limit of the range should be 1440 psig.

The range provided by the applicant is zero to 1300 psig.

The applicant provided documentation which describes the tap location in order to justify the instrument range.

The tap is located between the steam flow re-strictors and the main steam isolation valves.

Because the tap is located close to the main steam safety-relief valves,.both the tap and the valves ex-perience essentially the same pressure.

The safety-relief valve with the high-est set point is set at 1225 psig il percent.

The applicant stated that a steam pressure transient analysis that included the effects of the flow re-strictors, the set point tolerance, and the accumulation of steam in the steam lines showed that all safety-relief valves will be wide open at 1285 psig.

Be-cause the pressure seen by the transmitter would be within the range supplied, the staff finds the zero-to-1300 psig range acceptable.

Heat Removal by the Containment Fan Heat Removal System RG 1.97 recommends plant-specific instrumentation for this variable.

Sec-tion 7.5 of the FSAR does not discuss this variable.

The applicant provided documentation which states there is not a containment fan heat removal system at CPSES that is designed to operate in a postaccident situation.

On the basis of this statement, the staff finds this exception to RG 1.97 acceptable.

Containment Sump Water Temperature RG 1.97 recommends Category 2 instrumentation with a range from 50 F to 250 F for this variable.. Section 7.5 of the FSAR does not discuss this variable.

The applicant provided documentation which reports that an analysis shows the emergency core cooling system pumps will have adequate net positive suction head regardless of the sump water temperature.

The applicant established that alter-native instrumentation can be used to confirm that containment cooling is taking -

place.

This alternative instrumentation includes Category 3 RHR heat-exchanger inlet tenperature, Category 2 RHR heat exchanger outlet temperature, and Cate-gory 2 containment atmosphere temperature.

With adequate net positive suction head provided and suitable alternative in-strumentation to show the effectiveness of containment cooling, the staff finds.

this exception to RG 1.97 acceptable.

Component Cooling Water Temperature to ESF System RG 1.97 recommends that the instrument range be 32 F to 200 F to monitor the Comanche Peak SSER 23 7-9 l

m m -

L temperature of the component cooling water to engineered safety features sys-tems. The applicant has provided component cooling water header temperature instrumentation that covers a range of 30 F to 150 F.

The applicant's justifi-cation for this deviation is based on a p N t-specific analysis and is substan-tiated in Table 032.110-5 of the FSAR.

W plant-specific analysis demonstrated that the given range is adequn e to cover the maximum anticipated component cool-ing water temperature.

The staff finds the justification acceptable and the range adequate.

Makeup Flow-In

[

RG 1.97 recornmends Category 2 instrumentation for this variable.

The applicant i

T has provided Category 3 instrumentation, stating that this instrumentation is used for a normal safe shutdown, but it is not required during or following an accident.

The applicant stated that these instrunients are so located such that a mild environment is present when procedures require the use of the instrumen-f tation. On the basis of these statements, ehe staff finds this deviation'from RG 1.97 acceptable, Letdown Flow-Out RG 1.97 recommends Category 2 instrumentation for this variable.

The applicant has provided Category 3 instrumentation, stating that this instrumentation is used for a normal safe shutdown, but it is not required during or following an accident.

The opplicant stated that these instruments are so located that a

,i mild environment is present when procedures require the use of the instrumenta-tion.

On the basis of these statements, the staff finds this deviation from RG 1.97 acceptable.

Volume Control Tank Level RG 1.97 recommends Category 2 instrumentation for this variable.

The applicant has provided Category 3 instrumentation, stating that this instrumentation is used for a normal safe shutdown, but it is not required during or following an accident.

The applicant reviewed the location of these instruments and has determined that they are so located that a mild environment is present when procedures require the use of the instrumentation.

The staff concludes that Category 2 instrumentation for this variable is not required based on the location and lack of required function of this instrument during or following an accident.

Therefore, the staff finds this. deviation from RG 1.97 acceptable.

High-Level Radioactive Liquid Tank Level RG 1.97 recommends that the instrument range for this variable cover from the top to the bottom of the tank.

The applicant has a high-level alarm in the con-trol room and instrumentation that covers the recommended range in the local waste processing panels.

The applicant provided documentation which states that the control room alarm is an aid to prevent the overfilling of the three tanks, and that a display in the control room is not needed.

Section 6.2(g) of NUREG-0737, Supplement 1, allows displays in locations other than the control room control panels.

Because of this allowance, the staff finds the provided i

instrumentation acceptable.

l I

Comanche Peak SSER 23 7-10

l Radioactive Gas Holdup Tank Pressure RG 1.97 recommends instrumentation for this variable that can monitor tank pressure with a range of zero to 150 percent of the tank design pressure.

The applicant has a high pressure alarm in the control room and instruoentation with a range from zero to 150 psig in the, local waste processing panels.

The applicant provided documentation which states that the control room alarm is an aid to keep these tanks from overfilling, and that a display in the control room is not needed.

Section 6.2(g) of NUREG-0737, Supplement 1, allows dis-plays in locations other than the control room control panels.

Because of this allowance, the staff finds the provided instrumentation location acceptable.

2 Tables 11.3-1 and 11.3-2 of the FSAR state that these tanks have a design pressure of 150 psig, and that the high pressure alarm is set at 100 psig.

The design output (maximum) pressure of the waste gas compressors is 150 psig.

Section 11.3.2.1.1 of the FSAR states that there are relief valves that can relieve the full flow from both waste gas compressors.

These relief valves are l

set to relieve pressure at less than the system design pressure.

Because of the pressure relief capacity of the system, the staff finds the zero to 150 psig range acceptable.

Vent From Steam Generator Safety-Relief Valves RG 1.97 recommends Category 2, environmentally qualified instrumentation for this variable to monitor noble gases, the duration of the release, and the mass of steam per unit of time.

Section 7.5 of the FSAR states that this instrumen-tation is qualified for the period of time needed to detect a tube rupture l

event.

This instrumentation is needed only during a steam generator tube rup-ture event.

or this event, these monitors are located in a mild environment.

On the bas' sf this information, the staff concludes that the instrumentation provided tv. this variable is acceptable.

Condenser Air Removal System Exhaust--Noble Gas and Vent Flow RG 1.97 recommends a display with a range from 10 6 pCi/cc to 105 pCi/cc.

The instrumentation identified in Section 7.5 of the FSAR has a range of 10 5 pCi/cc to 10 1 pCi/cc.

The regulatory guide makes allowance for a common plant vent that monitors this discharge.

The applicant provided documentation which states that tnis system discharges through a common plant vent.

The range of the common plant vent instrumentation meets the recommended range.

Because of this flow routing, the instrumentation supplied for this variable is-acceptable.

All Othen Identified Release Points--Noble Gas and Vent Flow RG 1.97 recommends Category 2 instrumentation for this variable with a display range from 10 6 pCi/cc to 102 pCi/cc.

Section 7.5 of the FSAR does not discuss this n riable. The applicant provided documentation which stated that all identified release points are monitored in accordance with RG 1.97 recommenda-tions, utilizing a common plant vent.

The range of the common plant vent in-strumentation meets the recommended range.

Because of this flow routing, the instrumentation supplied for this variable is acceptable.

Comanche Peak SSER 23 7-11

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Particulates and Halogens RG 1.97 recommends sampling with onsite analysis with a capability from 10 3 pCi/cc to 102 pCi/cc.

Section 7.5 of the FSAR states that a grab sample is used with an "as required" capability.

The applicant verified that the range supplied meets the recommended range.

Therefore, the staff finds the instru-mentation provided for this variable acceptable.

Airborne Radiohalogens and Particulates RG 1.97 recommends portable sampling with onsite analysis with a capability from 10 8 pCi/cc to 10 3 pCi/cc for this variable.

The applicant provided documentation which lists the portable sampling equipment and the onsite an-alysis equipment available for this capability.

The applicant stated that this equipment meets the capabilities recommended by RG 1.97.

On the bas of this statement, the staff finds the instrumentation provided for this veiable ac-ceptable.

Plant and Environs Radiation RG 1.97 recommends portable instrumentation for this variable for isotopic analysis. The range recommended is from 10 3R/hr to 104R/hr for' photons and from 10 3 rad /hr to 104 rad /hr beta and lower energy photons.

The applicant provided documentation which states that the portable instruments used for this variable meet these recommendations.

On the basis of this' statement, the staff finds the instrumentation provided for this variable acceptable.

Plant and Environs Radioactivity RG 1.97 recommends a portable multichannel gamma-ray spectrometer for analyzing this variable.

Section 7.5 of the FSAR does not discuss this variable.

The applicant does not have the capability to send a multichannel gamma-ray spec-trometer into the field to perform an isotopic analysis.

However, the appli-cant has portable sampling equipment and germanium detector and multichannel analyzers at two onsite locations:

the nuclear operations support facility and the plant hot lab.

The' laboratory equipment at CPSES can provide isotopic analysis and a timely assessment of radioactive releases.

Therefore, this is an acceptable deviatwn from RG 1.97.

Estimation of Atmospheric Stability RG 1.97 recommends instrumentation for this variable to have either a range of

-5 C to +10 C (-9 F to 18 F) or an analogous range for alternative stability analysis.

The instrumentation provided by the applicant has a range of -5 F to '15 F.

The applicant justified this range by stating that the range is wiJer than the range specified in RG 1.23, Revision 1, Table 1, " Classification-cf Atmospheric Stability by Temperature Change with Height." The applicant stated that the -5 F to +15 F range is equivalent to -5.56*C to +5.56 C for an equivalent of a 100-m span.

Table 1 of RG 1.23 provides seven atmospheric sta-bility classifications based on the difference in temperature per 100-m eleva-tion change.

These classifications cover from extremely unstable to extremely stable.

A temperature difference with height greater than +4 C/100m-(extremely stable classification) or less than -2 C/100m (extremely unstable classifica-tion) has no impact, on the stability classification.

The instrumentation pro-vided by the applicant includes this range.

Therefore, the staff finds that this instrumentation is acceptable for determining atmospheric stability.

Comanche Peak SSER 23 7-12

Accident Sampling (Primary Coolant, Containment Air, and Sump)

The postaccident sampling system provided by the applicant includes sampling and analysis as recommended by RG 1.97 except for the following deviations:

(1) Boron content--The minimum observable concentration is 500 ppm.

(2) Chloride content--The minimum observable concentration is 25 ppb.

--The maximum observable concentration is 5 ppm.

(3) Dissolved hydrogen--The minimum observable concentration is 0.5 cc/kg.

(4) Dissolved oxygen--The minimum observable concentration is 0.1 ppm.

(5) Hydrogen coatent--The minimum observable concentration is 0.1 percent.

(6) 0xygen content--The minimum observable concentration is 0.1 percent.

i Additionally, there is no display in the control room.

The applicant deviates from RG 1.97 with respect to postaccident sampling capability.

The staff addressed this deviation in its review of NUREG-0737, Item II.B.3, and finds it acceptable.

Environmental Qualification, Indication, and Recording Table 7.5.-1 of the FSAR states that environmental qualification will be pro-vided "as appropriate" for Category 2 variables.- The applicant provided clari-fying documentation which indicated that the instrumentation supplied for Cate-gory 2 variables is either environmentally qualified (per 10 CFR 50.49) or is located in a mild environment for the length of time that the instrumentation was designed to function.

The applicant also indicated that Category 2 instru-ments are either environmentally qualified or located in a mild environment in accordance with the recommendations of RG 1.97.

This is in accordance with RG 1.97 and is acceptable.

Table 7.5.1 of the FSAR states that the indication for Category 1 variables is "immediately accessible." RG 1.97 recommends continuous-indication for Category 1 variables.

The applicant provided documentation stating that as a minimum, all Category 1 variables are continuously displayed or are available for display on demand.

The applicant also provided documentation stating that-each channel of Category 1 instrumentation has a dedicated indicator, recorder, or display device satisfying this recommendation.

With this clarification, the staff finds the Category 1 indicators, recorders, and display devices acceptable.

Table 7.5-1 and Section 7.5.1.3.1.4 of the FSAR state that the emergency re-sponse facility (ERF) computer is the device used for recording the Category l' variables.

The applicant provided documentation describing this capability.

Instrumentation / computer isolation is provided by qualified Class 1E optical isolation devices for Class 1E equipment.

The ERF computer was designed to meet the requirements of Supplement 1 of NUREG-0737.

On tha basis of this de-scription of the recording capability of the ERF computer and the described isolation betwen Category 1 and Category 2 instrumentation and the ERF-compu-ter, the staff finds the recording capability provided acceptable.

Comanche Peak SSER 23 7-13

RMjy,: Sn Exposure Rate RG 1.97 recommends Category 2 instrumentation for this variable with a range of 10 1 R/hr to 104 R/hr.

The instrumentation (designed as Category 3 instru-mentation) provided by the applicant for the control room area, the postac-cident sampling system room area, the plant vent stack area, and the hot lab area, the RHR pump room, and the fuel building area instrumentation have ranges of from 10 1 mR/hr to 104 mR/hr.

The ranges chosen were specific to the re-quirements of their locations.

The range was chosen for these areas to provide personnel protection during normal and accident conditions.

These area monitors are supplemental to portable monitors used before any entry into potentially contaminated areas.

The applicant uses the portable instrumentation as the key means of assessing area environments.

From a radiological standpoint, if the radia' ion levels reach or exceed the upper limit of the provided range (10 R/hr), personnel would not be permitted into the areas except for a lifesaving act'vity.

The staff, therefore, finds the documented range for the radiation exrosure rate instrumentation acceptable.

The Category 3 instrumentation is accepti. ole as backup instrumentation.

Pressurizer Level RG 1.97 recommends instrumentation fer this variable with a range from the bot-tom to tne top of the pressurizer o ssel.

The instrumentation provided by the applicant does not monitor this full range.

The applicant stated that the level instrumentation monitors tne entire length of the cylindrical portion of the pressurizer vessel, plus approximately 3 in. of each of the two hemispherical ends.

The applicant stated that all automatic and manual operator actions occur within the provided range.

The volume to level ratio in the hemispherical ends of the pressurizer vessel is not linear.

To monitor outside of the provided range would require either accepting greater inaccuracies or greater circuit complexity.

The existing range is adequate to monitor this variable during accident and postaccident conditions.

Therefore, the staff finds this deviation acceptable.

l Instrument Identification RG 1.97 recommends that all type A, B, and C and Category 1 and 2 instrumeets be specifically identified on control panels so the operator can easily discern that they are intended for use under accident conditions.

The applicant stated that its labeling complies with this position, with the following exceptions:

steam generator blowdown radiation monitor condensor off gas radiation monitor plant vent stack radiation monitor containment isolation valve (CIV) status indication l

The applicant stated that the radiation monitors are part of a computer-based system that displays the variable on demand on a cathode-ray tube.

This method l

l of display is endorsed by RG 1.97 for these monitors; therefore, these display-on-demand variables do not need additional labeling.

Comanche Peak SSER 23 7-14

1 The CIV status indication is provided by unique monitor light boxes located on i

the main control board and by indicator lights that are part of each CIV con-trol switch essembly.

Pattern recognition (all monitor light boxes lit or unlit) quickly alerts the operator to the valve position.

The CIV control switches are siready color coded in accordance with the associated safety train and power source.

Additional color coding is deemed by the applicant to be potentially confusing.

On the basis of this justification, the staff finds the identified deviations in instrument identification acceptable.

Isolation of Cateoory 2 Instrumentation The applicant provided documentation stating that those Category 2 instrument l

loops that are powered by Class IE power and feed signals to other systems have l

approved isolation devices.

Those Category 2 instrument loops that are powered by other Category 2 (but not Class 1E) power sources either do not feed signals I

to other systems or have similar isolation devices.

On the basis of the de-scribed isolation devices where signals cross from Category 2 instrumentation to other systems, the staff finds the isolation provided for these Category 2 instrument channels accoptable.

Containment Atmosphere Temperature RG 1.97 recommends instrumentation for this variable with a range from 40*F to 1

400 F.

The instrumentation provided by the applicant has a range from zero to l

360 F.

The applicant provided documentation stating that the peak postaccident containment temperature is 345 F.

On this basis, the staff finds the provided zero to 360 F range acceptable.

Containment Pressure RG 1.97 recommends instrumentation for this variable with a range of 10 psig to 3 times the design pressure of 50 psig.

The applicant provided documenta-tion stating that this range is covered by two sets of instruments--the inter-mediate-range instruments that have a range of -5 to 60 psig and the= wide-range instruments that have a range of zero to 150 psig.

With the use of these two sets of instruments, the staff finds the ranges provided for this variable ac-ceptable.

Radiation Level in Circulating Primary Coolant The applicant stated in its March 31, 1989 letter that radiation level measure-ments to indicate fuel cladding failure are provided by the postaccident samp-ling system, which has been reviewed by the NRC as part of the staff's review of NUREG-0737, Item II.B.3.

The staff finds this alternative instrumentation acceptable for meeting the recommendations of RG 1.97.

7.5.4 Conclusions On the basis of its review of the submittals provided by the applicant, the staff concludes that the CPSES Units 1 and 2 design is acceptable with respect to conformance to RG 1.97, Revision 2.

Outstanding Issue 2 in SSER 22 is, therefore, resolved.

4 Comanche Peak SSER 23 7-15

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9 AUXILIARY SYSTEMS 9.2 Water Systems 9.2.1 Station Service Water Systems:

In Safety Evaluation Report (SER) Section 9.2.1, the staff stated that the p

recirculation loops around the station service water pumps would be used for-testing purposes.

In Amendment 78 to the Final Safety Analysis Report (FSAR),

the applicant identified a design change which includes blind flanges to pro--

hibit flow through these recirulation lines.

The reason for the design change was a concern that the plasite coating in the recirculation line could flake off.and be returned to the pump suction, possibly causing blockage.

The staff concludes that because testing can still be done through the normal flow paths, the requirements of General Design Criterion 46 (10 CFR Part 50, Appendix A) related to cooling water system functional testing are met, and the design change is acceptable.

9.2.2 Reactor Auxiliaries Cooling Water System (Component-Cooling Water System)

In Section 9.2.2 of the SER, the staff indicated that the reactor makeup water system provided automatic makeup to the component cooling water surge tank upon receipt of a tank low-low level alarm.

In FSAR Amendment 78, the applicant stated that the reactor makeup water system could also be used manually to' pro-vide normal makeup to the surge tank.

As indicated in the SER, normal makeup can also be provided by the demineralized water system.

This manual makeup-from the reactor makeup water system provides added flexibility and has been identified here for completeness.

This change does not' alter the staff's pre-vious conclusions for acceptability in Section 9.2.2 of the SER.

9.2.6 Condensate Storage Facility In Sections 9.2.6 and 10.4.9 of SSER 22, the staff clarified the usable volume of water-reserved in the condensate storage tank for use by the auxiliary feed-water system.

It should be noted that the clarification also applies to Sec-tion 5.4.3 of the SER which provides a brief discussion of the condensate stor-age tank volume.

9.3 Process Auxiliaries 9.3.1 Compressed Air System I

In SER Section 9.3.1, the staff stated that air accumulators are provided for -

the auxiliary feedwater flow control valves, steam supply valves to'the turbine-driven auxiliary feedwater pump, and the control room airfdampers. _In FSAR Amendments 66 and 78, the applicant also stated that an air accumulator would be provided for the component cooling water system regulator valve. associated with the safeguards chilled water system.

This is a matter of clarification to indicate that the valves identified in Section 9.3.1 of the SER are not the i

-1 a

Comanche Peak SSER 23 9-l' i'

only ones equipped with accumulators, as the SER infers.

The staff, therefore, finds that the conclusions reached in Section 9.4.5 of the SER and in SER Supplement 22 (SSER 22) related to the acceptability of the compressed air sys-tem remain unchanged by this revision.

9.4 Heating, Ventilation, and Air Conditioning (HVAC) Systems 9.4.5 Miscellaneous Building Ventilation Systems In SER Section 9.4.5, the staff indicated that the diesel generator building ventilation system included one 100 percent-capacity exhaust fan.

In FSAR Amendments 76 and 78, the applicant provided a more detailed description of the diesel generator building ventilation system.

There is one 100 percent-capacity exhaust fan for each of the day tank rooms and four 25-percent-capacity' exhaust fans (a total of eight fans) for each diesel generator room.

This de-sign provides adequate redundancy and more operational flexibility during the winter months'when all four exhaust fans may not be required.

The staff, therefore, finds that the conclusions reached in Section 9.4.5 of the SER and SSER 22 related to the acceptability of the diesel generator building ventila-tion system are still valid.

9.5 Other Auxiliary Systems 9.5.1 Fire Protection SSER 21 contained a review of the applicant's fire protection program described in the FSAR through Amendment 71 and in Revision 1 of the Fire Protection Report (FPR) submitted by the applicant in a letter dated April 29, 1988. The appli-cant has since revised its fire protection program in Amendments 75, 76, and 78 to the FSAR and by submitting Revisions 2 and 3 to the FPR in letters dated July 19, 1989 and September 22, 1989, respectively.

9.5.1.2 Administrative Controls In SSER 21, the staff identified a concern relative to the possibility that two adjacent manholes containing redundant shutdown cables could be subjected to a flamable liquid since the manholes are in close proximity to the diesel fuel unloading area.

During a site audit conducted on October 2-6, 1989 (NRC Inspec-tion Report 50-445/89-69; 50-446/89-69),.the applicant presented the modified procedures which cover the unloading of diesel fuel. The modified procedures ensure that both manhole covers would be in place before diesel fuel unloading.

The procedures were reviewed and found to adequately address the concern raised in SSER 21.

Therefore, this concern is considered resolved.

9.5.1.4 General Plant Guidelines Electrical Cable Construction, Cable Trays, and Cable Penetrations In FSAR Amendment 78, the applicant identified an additional small amount of cable did not meet the specifications of Institute of Electrical and Electronics Engineers (IEEE) Standard 383-1974.

This cable has been installed in the con-trol room / cable spreading room for the data acquisition system.

In SSER 12, Section 9.5.1.4, the staff specified the amount of cabling not in compliance Comanche Peak SSER 23 9-2

with IEEE Standard 383-1974 that was installed in these areas.

The staff con-cludes that the additional small amount of cabling identified by the applicant in FSAR Amendment 78 has a negligible impact on the area fire loading, and therefore, does not affect the staff's conclusions on acceptability reached in SSER 12.

4 9.5.1.5 Fire Detection and Suppression Fire Protection Water Supply System In SSER 21, Section 9.5.1.5, the staff evaluated the addition of redundant fire-water storage tanks.

In that SSER, the staff noted that each tank had a capacity of 504,000 gallons.

In FSAR Amendment 78, the applicant revised the capacity of the tanks to indicate j

that each tank contained 524,500 gallons of water.

This is an increase over the previously evaluated capacity and is, therefore, acceptable.

The staff, there-fore, finds that the conclusions reached in Section 9.5.1.5 of SSER 21 remain unchanged.

9.5.3 Lighting System

)-

The lighting system for CPSES is designed to provide adequate lighting in all areas of the station, indoors and outdoors, and consists of normal, ac essential, i

and de emergency lighting systems.

This lighting system design is equal to or exceeds the recommendations contained in the Illuminating Engineering Society Lighting Handbook.

Normal lighting for the plant is supplied by a grounded 208/120-V ac, three phase, four-wire distribution system.

Dry-type transformers that feed lighting panels are connected to motor control centers throughout the plant.

The transformers and lighting panels which they feed are conveniently located throughout the' plant to permit efficient distribution of the lighting load.

The non-Class 1E ac essential and non-Class 1E de emergency lighting systems are provided in those locations where safety-related functions are performed.

These lighting systems are designed to provide adequate illumination in areas con-taining equipment necessary for the safe shutdown of the plant.

These areas include the control room, the diesel generator room, remote shutdown panel 4

locations, areas required for control of safety-related equipment, primary interior access routes to and from specific plant areas, and primary exits.

The primary plant ac essential lighting is provided by ac systems having con-nections to the onsite standby diesel generators.

During all operating condi-tions or a loss-of coolant accident (LOCA), and in the event of the loss of all i

offsite ac power, onsite standby diesel generator power is available to the ac' essential lighting system.

The non-Class 1E de emergency lighting system con-sists of lights connected to dedicated batteries or individual battery packs.

The de emergency lights in the control room are normally deenergized.

The con-tactor in the de emergency lighting panels is normally held open by a feed from the ac lighting system.

The dc emergency lights are activated by the loss of power to the ac lighting systems.

Individual battery packs are normally i

under a float charge from the ac lighting power supplies for their respective areas.

If an ac lighting power supply is lost, the respective de lights are activated from their individual battery packs by their respective relays.

1 i

Comanche Peak SSER 23 9-3 1

_ _J

1 The ac and de lighting in the control room, in the primary plant essential con-trol areas, and in the primary interior access routes between them, is arranged in a staggered pattern and alternately fed from the redundant trains and/or from self-contained battery packs energized from either train A, train B, or normal ac sources.

As an alternative, where the engineered safety features equipment is energized from a particular train, at essential and de emergency lighting from the same train is provided in that area and in the primary access route to it.

These practices ensure adequate lighting in these areas for expected possible electrical single-failure conditions.

The at essential and de emergency lighting systems are independent of each other.

An electrical failure in one system does not cause the other system to be in-operable.

Furthermore, in critical control areas, the lighting is either redun-dant (that is, overlapping from adjacent areas) or energized from the same train as the equipment in that area and/or provided by self-contained battery packs energized from either train A, train B, or normal ac sources.

The integrated design of these lighting systems provides adequate lighting in plant areas re-quired for control of safety-related equipment and in the major interior access routes to and from these areas.

The normal, ac essential, and de emergency lighting systems are tested and in-spected after their installation is complete.

The ac essential lighting is used on a day-to-day basis to provide a part of the ordinary operational light-ing and, as such, periodic testing is.not required.

The de emergency lights connected to the dedicated batteries can be tested periodically by tripping the circuits fed from the ac lighting system, thereby closing the feeder circuits to the de emergency lights.

For battery packs, the test circuit contained in each individual unit can be used for test purposes.

Battery pack batteries are replaced periodically.

The review of the lighting system included assessment of the number and type of lighting systems provided, assessment of the adequacy of the power sources for the normal and emergency lighting systems, and verification of functional capa-bility of the lighting system under all conditions of operation.

The basis for acceptance was conformance of the design bases and criteria, and design of the lighting systems and necessary auxiliary supporting systems to the acceptance criteria in Section II of Standard Review Plan (SRP) Section 9.5.3.

Other bases for acceptance were conformance to industry standards and the abil-ity to provide effective lighting in all areas of the CPSES under all conditions of operation.

On the basis of its review, the staff concludes that the.various lighting systems provided at the CPSES are in conformance with the above standards, criteria, and design bases; that they are capable of performing their design function; and that they are, therefore, acceptable.

Special requirements needed for the emergency lighting system to satisfy Appen-dix A to Branch Technical Position ASB 9.5-1 were reviewed separately during the fire protection review, as documented in Section 9.5.1 of the SER and subse-quent SER supplemente Comanche Peak SSER 23 9-4

11 RADIOACTIVE WASTE MANAGEMENT 11.3 Process and Effluent Radiological Monitoring Systems Safety Evaluation Report (SER) Supplement 22 (SSER 22) di.scussed the applicant's deletion of process monitors on the laundry and hot shower recycle stream and the waste monitor tank input recycle stream, since the plant design no longer recycles processed liquid to the condensate storage and laundry tanks.* Since the streams no longer exist, the staff. concludes that the deletions do not af-fect the conclusions reached in Supplement 22 to the SER with regard to the applicant's conformance to the monitoring and sampling provisions of General Design Criteria 60, 63, and 64 (10 CFR Part 50, Appendix A) and Regulatory Guide 1.21.

In Amendment 78 to the Final Safety Analysis Report (FSAR), the applicant deleted the specific radiation monitoring instruments from Table IL 2-5 to. reflect the current design (evaluated by the staff in SSER 22.)

In this supplement, the a

staff has revised Table 11.6 of the SER to reflect these changes, i

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Apperidix E to this supplement contains errata to correct the' discussion in SSER 22.

r Comanche Peak SSER 23 11-1 j

l Table 11.6 Process and effluent monitors

Stream monitored Detector ** Number Monitor sensitivity Liquids:

Component cooling water y

3/ reactor 1x10 5 pCi/cm3 (Co-60)

Service water effluent y

2/ reactor 1x10 5 pCi/cm3 (Co-60)

Liquid waste effluentt y

1 shared 1x10 5 pCi/cm3 (Co-60)

Boron recovery system distillate y

1 shared 1x10 5 pCi/cm3 (Co-60)

Letdown system GM 1~ reactor 1 pCi/cm3 (Co-60)

Condensate demineralizer input y

1/ reactor 1x10 5 pCi/cm3 (Co-60)

Condensate demineralizer output y

1/ reactor 1x10 5 pCi/cm3 (Co-60)

Auxiliary steam condensate y

1 shared 1x10 5 pCi/cm3 (Co-60)

Turbine b1dg drain inputt y

1/ reactor 1x10 5 pCi/cm3 (Co-60)

Gases:

Plant vent stack monitoring system--auxiliary buildingtt 3

Gaseous isotopes p

1 shared 1x10 6 pCi/cm3 (Xe-133)

Particulate p

1 shared 5x10 12 pCi/cm (Cs-137) lodine y

1 shared 4x10 4 cpm /pCi (1-131)

Containment monitoring system--safeguards buildingtt Gaseous isotopes p

1/ reactor 1x10 6 pCi/cm3 (Xe-133)

Particulate p

1/ reactor 5x10 11 pCi/cm3 (Cs-137)

Iodine y

1/ reactor 4x10 4 cpm /pCi (I-131)

Plant vent duct monitor (gas)tt p

1 shared 1x10 4 pCi/cm3 (Xe-133)

Auxiliary b1dg vent duct (gas) p 1 shared 1x10 4 pCi/cm3 (Xe-133)

Condenser vacuum pump vent (gas) p 1/ reactor 1x10 5 pCi/cm3 (Xe-133)

GWPS monitor (gas) inlet p

1 shared 1x10 1 pCi/cm3 (Xe-133)

HVAC room vent duct (gas) p 1 shared 1x10 4 pCi/cm3 (Xe-133)

Fuel b1dg vent duct (gas) p 1 shared 1x10 4 pCi/cm3 (Xe-133)~

Safeguards bldg vent duct (gas) p 1/ reactor 1x10 4 pCi/cm3 (Xe-133)

All liquid and gaseous effluent streams will be monitored in accordance with the guidelines of Regulatory Guide 1.21

- Type of scintillation detector (y or p) or a Geiger-Mueller (GM) detector tTerminates discharge by closing isolation valve when the radioactivity level exceeds a predetermined value, itTerminates discharges from the gaseous waste processing system (GWPS), control room ventilation exhaust, and containment purge ventilation when the radio-activity level exceeds a predetermined value.

Comanche Peak SSER 23 11-2

1 13 CONDUCT OF OPERATIONS 13.1 Organizational Structure end Qualifications 13.1.2 Operating Organization 13.1.2.1 Plant Staff (1) Operations Department In a letter dated March 19, 1986, the applicant committed to meeting the guide-lines of Generic Letter (GL) 84-16 for providing adequate on-shif t operating ex-perience for near-term operating license applicants.-

In letters dated October 26, and December 28, 1989, the applicant provided information to the staff describing the hot operating experience of its shift supervisors and unit supervisors.

The staff has reviewed this information and concludes that the applicant has ade-quate personnel on each shift to meet the hot operating experience guidelines of GL 84-16.

However, it should be noted that one of the shift supervisors had I

not yet met the specific experience guideline for participating in a shutdown, although he has experienced more than one scram from power.

The staff consid-ered the lack of shutdown experience and concludes that it is not a safety con-cern.

This is because two-unit supervisors on shift with the shift supervisor in question have experience levels which are sufficient to compensate for the shift supervisor's lack of a single shutdown experience. ' More specifically, one-unit supervisor has had the six-months' hot operating experience and the startup and shutdown experience.

In addition, a second unit supervisor on that shift has had six weeks' hot operating experience and meets the guidelines for startup and shutdown experience.

Comanche Peak SSER 23 13-1

14 INITIAL TEST PROGRAM The testing activities to be performed on safety-related systems at Comanche Peak Steam Electric Station (CPSES) are divided into three major phases:

pre-requisite testing, preoperational testing, and initial startup testing.

Prerequisite testing will be conducted to verify the integrity, proper-installa-i I

tion, cleanliness, and functional operability of the system components.

Preoperational testing will be performed to demonstrate the' capability of sys-tems, structures, and components to meet safety-related performance requirements.

These tests will be performed on plant systems, structures, and components that are designed to perform a nuclear safety-related' function.

Preoperational test-ing will be completed before fuel loading with certain limited exceptions where tests or parts of tests will be deferred until the core has been loaded.

In such cases, sufficient testing will be performed before fuel loading to provide reasonable assurance that the postloading tests will be successful.

Initial startup tests will be performed beginning with fuel loading and ending

.I with commercial operation.

The. intent of these tests is to ensure that fuel i

loading is effected in a safe manner; that the plant is safely brought to. rated l

capacity; that plant performance is satisfactory in terms of established design i

criteria; and to demonstrate, where practical, that the plant is capable ~ of l

withstanding anticipated transients and postulated accidents.

The staff review concentrated on the administration of the test program and the completeness of the prerequisite, preoperational, and startup tests.

For example, the staff's l

Safety Evaluation Report (issued at completion of the construction permit review i

[CP SER]) was reexamined to determine the principal design criteria for.the plant l

and to identify any specific concerns or unique design features that would war-I rant special test consideration.

Chapters 1 through 12 of the Final Safety.

Analysis Report (FSAR) were reviewed to familiarize the staff with the facility

[

design and nomenclature.

Chapters 13 and 17 were reviewed to familiarize the staff with the applicant's organizational structure, qualifications, administra-tive controls, and quality assurance program as they apply to or impact the initial test program.

Chapter 15 was reviewed to identify assumptions pertain-ing to performance characteristics that should be verified by testing and to identify all structures, systems, components, and design features that were j

assumed to function (either explicitly or implicitly) in the accident analysis.

Licensee event reports for operating, reactors of similar design were reviewed to identify potentially serious events and chronic or generic problems that might warrant special test consideration.

Standard Technical Specifications for West-inghouse pressurized-water reactors (PWRs) were reviewed to identify all struc-tures, systems, and components that would be relied upon for establishing con-formance with safety limits or limiting conditions for operations.

Finally, the startup test reports for other PWR plants were reviewed to identify problem areas that should be emphasized in the CPSES initial test program (ITP).

Comanche Peak SSER 23 14-1

The objective of the staff review of FSAR Chapter 14 is to determine whether the acceptance criteria stated in the Standard Review Plan (SRP, NUREG-0800) are met.

The staff reviewed several aspects of the initial test program including the fol-lowing major considerations:

(1) The applicant's organization and staff for performing the ITP were reviewed.

The staff concludes that an adequate number of appropriately qualified per-sonnel are assigned to develop test procedures, conduct the tests, and re-view the results of the tests.

Plant staff personnel are utilized to maxi-mize the training benefits of the test program.

(2) The applicant stated that the test procedures were developed using input from the nuclear steam supply system (NSSS) vendor, the architect-engineer, the applicant's engineering staff, and other equipment suppliers and con-tractors as needed.

The applicant also stated that a review of operating experiences at similar plants was factored into the development of the test procedures.

(3) The applicant stated that the tests are being conducted using approved test procedures and that administrative controls cover (a) the completion of test prerequisites, (b) the completion of necessary data sheets and other documentation, and (c) the review and approval of modifications to test procedures.

The applicant stated that administrative procedures also cover implementation of modifications or repair requirements identified as being -

required by the tests and any necessary retesting.

(4) The applicant stated that the results of each test are reviewed for tech-nical adequacy and completeness by qualified personnel, including NSSS vendor and architect-engineer personnel as appropriate.

Preoperational test results are reviewed before fuel loading, and the startup test results from each activity or power level will be reviewed before the next activity or power level.

(5) The applicant stated that normal plant operating and. emergency procedures are used in performing the initial test program, thereby_ verifying the correctness of the procedures to the extent practical.

(6) The applicant has requested that certain preoperational tests be deferred until after fuel load.

These tests are described in letters dated I

December 6, 1989 and January 12, 1990.

The letters also identify which tests will be conducted before entering the next specified operating mode.

The staff finds the applicant's justification for deferral and subsequent schedule for conducting these tests to be acceptable.

Therefore, the pro-posed license condition on this issue described in Safety Eavluation Report-(SER) Supplement 6 (SSER 6) is no longer valid and is hereby deleted.

The sequential schedule for performing the startup tests established that:

(a) systems required to prevent, limit, or mitigate the consequences of postulated accidents will be tested before 25 percent of rated power is exceeded and (b) the safety of the plant will not be dependent on the per-formance of untested systems, structures, and components.

The applicant has committed in the FSAR to make preoperational test procedures available for staff review at least 30 days before the expected performance of the test, and startup test procedures will be available at least 60 days before fuel loading.

By letter dated October 12, 1989, the applicant has further Comanche Peak SSER 23 14-2

I committed that any changes to the initial startup test program as' described j

in Chapter 14 of the FSAR will be niade in accordance with the provisions of 10 CFR 50.59 and reported to the staff within one month of the applicant's approval of such change.

The staff finds these commitments acceptable.

(7) The abstract of each test procedure presented in' Chapter 14 of the FSAR was reviewed.

The staff verified that there are test abstracts for those structures, systems, components, and design features that:

(a) will be used for shutdown and cooldown of.the reactor under normal plant conditions and for maintaining the reactor in a safe condition for an extended shutdown period; (b) will be used for shutdown and cooldown of the reactor under transient (infrequent or moderately frequent events) conditions and postu-lated accident conditions and for maintaining the reactor.in a safe condi-tion for an extended shutdown period following such conditions; (c) will be used for establishing conformance with the limits of limiting conditions for operation that will be included in the facility Technical Specifications; (d) are classified as engineered safety features or will be relied on to support or ensure the operations of engineered safety features within design limits; (e) are assumed to function or for which credit is taken in the accident analysis of the facility, as described in the FSAR; and (f) will be used to process, store, control, or limit the release of radioactive materials.

(8) The test objective, prerequisites, methods, and acceptance criteria for each test abstract were reviewed in sufficient detail to establish that the functional adequacy of the structures, systems, components, and design features will be demonstrated.

(9) The test program's conformance with applicable regulatory guides (RGs) was reviewed.

The review included RGs 1.20, 1.41, 1.52, 1.68, 1.68.2, 1.79, 1.80, 1.108, and 1.68.3.

The applicant made a number of changes to the'ITP in response to staff comments.

Examples of these changes include:

(1) Administrative controls were added to ensure that all test procedure modifi-cations that alter the acceptance criteria or test intent would be appro-priately reviewed.

(2) Additional (five consecutive cold quick starts) testing of the steam-driven auxiliary feedwater pumps was added to further demonstrate system reliability.

(3) Testing to verify that the reactor cooled pipe penetration cooling system will maintain the pipe tunnel concrete temperature within design limits was added.

(4) The acceptance criteria for certain preoperational and startup. tests involv-ing reactor protection system hardware instrumentation delay time, remote plant shutdown validation, diesel generator starting requirements, snubber inspection, battery charger capacity, containment spray flowpath verifica-tion, sampling system flowpath and holdup, and power-operated relief valve capacities were modified.

Modified acceptance criteria were required to more accurately reflect the actual test conditions and to provide assurance that systems will perform in conformance with design predictions.

Comanche Peak SSER 23 14-3

(5) The minimum qualifications for personnel who direct or supervise the con-duct of testing were upgraded to conform with acceptable industry standards.

(6) Certain system tests were expanded to ensure that comprehensive system and component testing was scheduled.

Sample systems included station service.

water, component cooling water, vent and drain, spent fuel pool cooling, residual heat removal, chemical and volume control, safety injection, con-tainment ventilation, diesel generator compartment ventilation, ac and de power distribution, reactor protection, rod control, steam generator safety' and relief valves, main steam and feedwater' isolation valves, auxiliary feedwater, pressurizer safety and relief valves, and engineered safety features.

The applicant made additional changes to the initial test program which are discussed below:

(1) The applicant deleted the flux distribution measurement test which is used to demonstrate the ability to detect rod misalignments equal to or less than technical specifications at 50 percent and 100 percent power by use of incore flux maps without providing substantive justification.

The applicant subsequently provided adequate justification by proposing to use the digital rod position indication system in~ lieu of the incore traversing probe system to detect rod misalignment.

The digital rod position indica-tion system is a diverse, independent, and more accurate method of detecting control rod positions; therefore, this is acceptable to the staff.

(2) The applicant has withdrawn its original commitment to test instrument air systems following the guidance of RG 1.80.

In April 1982, RG 1,68.3, "Preoperational Testing of Instrument and Control Air Systems," was issued, superseding RG 1.80 for plants whose application for an operating license was docketed after May 24, 1982.

The applicant has committed to conduct the instrument and control air systems test adhering to the guidance in RG 1.68.3.

The staff finds this acceptable, l

(3) The applicant originally committed to perform a de power system test to demonstrate the operability of de loads at minimum voltages, and to support its design profile calculations.

Subsequently, the applicant deleted the preoperational test and stated that its analytical calculations were ade-quate to demonstrate that acceptable minimum voltage is available to operate Class 1E dc equipment.

This staff did not accept thic deletion.

The appli-cant resolved the issue by reinstating the test to demonstrate Class 1E de equipment operability with minimum de voltage available.

(4) With respect to implementing RG 1.68, Revision 2, dated August 1978,

~

" Initial Test Programs for Water-Cooled-Nuclear Power Plants," the FSAR states that hot no-flow, cold no-flow, and cold full-flow rod drops do not provide any additional useful data.

By Technical Specifications, critical operations are only permitted when the plant is hot and reactor-coolant pumps are operating, and thus scram _ testing is not required for hot no-flow, cold no-flow, and cold full-flow conditions.

Consistent with this intent not to perform rod drops for these conditions, FSAR Table 14.2-3 (sheet 19) addresses rod drop tests only for hot full-flow reactor coolant system conditions.

The Table 14.2-3 test summary includes performing at least three additional rod drop tests for each rod whose measured drop time deviates from the mean for all rods by more than-two Comanche Peak SSER 23 14-4

standard deviations.

The staff concludes that-the rod drop test summary meets the intent of RG 1.68, subject to the above exceptions which were; justified by the applicant.

On the basis of its review, including the' items discussed above, the staff con-cludes that the ITP described in the applic-tden meets the' acceptance criteria of SRP Section 14.2 and that the' successful cur;. _'on of the; program will demon-strate the functional adequacy of plant structures, systems, and components..The staf f also concludes that the -ITP described. meets the test requirements of Gen-eral Design Criterion 1 of-Appendix A to 10 CFR Part 50 and Section XI of.Appen-dix B to 10 CFR Part 50.

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-Comanche Peak SSER 23 14-5 1

i 15 ACCIDENT ANALYSIS 15.2 Moderate Frequency Transients 15.2.1 Increased Cooling Transients The' applicant has analyzed the following events which produced increased primary.

system cooling:

(1) decrease in feedwater temperature,-(2) increase in feedwater flow, (3) excessive load increase, and (4) opening of system generator' relief or safety valve.

None of these transients are limiting.-

Since the' Technical Spe-cifications for the Comanche Peak Steam Electric Station (CPSES) require'all four:

reactor coolant loops to be operational in Modes 1 and 2,-the applicant stated-i that there is no need to analyze the event of startup of an inactive reactor i

coolant pump at an incorrect temperature.

Therefore, the staff concludes that'-

'j the analytical results are acceptable because the specified acceptable fuel de-sign limits are not violated.

15.2.3 Increased Core Reactivity. Transients l

15.2.3.1 Boron Dilution Events The principal means of causing an inadvertent boron dilution are the' opening of the primary water makeup control valve and' failure of the blend system.

The chemical volume and control system (CVCS) is designed.to limit the dilution rate.

to values which will allow sufficient time for automatic or operator response.

to terminate the dilution'before the shutdown margin is exhausted.

Amendment 74 to the FSAR makes changes to reflect the plant as-built conditions such as a-dilution flow rate of 167 gallons per minute (gpm) for all' modes of operation-and 4169 ft3 minimum reactor coolant system volume for dilution-during hot ' shut-j down and hot standby.

j The staff concludes that the applicant's analyses of inadvertent boron dilution for all modes of operation. demonstrate that sufficient time exists for automatic 4

or operator action to terminate the dilution before. shutdown margin is exhausted.

15.3 Infrequent Transients and Postulated Accidents 15.3.7 Reactor Coolant Pump Locked Rotor Accident The locked rotor accident was analyzed by postulating an instantaneous seizure

.I of one reactor coolant system pump rotor.

The reactor flow would decrease. rap-'

i idly and the reactor would shut down as a result of a low-flow signal. The aaplicant reanalyzed this accident considering certain modified core values'.

T1e results showed a maximum cladding temperature of 1795 F and a peak coolant' system pressure of 2648 psia, which indicates that the coolant. system pressure boundary still maintains its integrity.' The staff, therefore, concludes that-the reanalysis of locked rotor accident is. acceptable.

Comanche Peak SSER 23 15-1 l

Because the reanalysis shows that the differences between past and'present re -

sults are very small, the staff concludes that the staff's previous conclusion is still valid, that is, a fuel failure of 7 percent is conservative for the locked rotor accident.

15.3.8 Loss-of-Coolant Accident Large-Break The applicant has reanalyzed the large-break loss-of-coolant accident (LOCA) based on some limiting conditions.

The result showed a peak cladding _ tempera-ture (PCT) penalty of 47.8F.

The final PCT for the large-break LOCA is thus 2058.5 F, which is below the 10 CFR 50.46 acceptance criterion of 2200 F.

The staff, therefore, concludes that the applicant's reanalysis of'the large-break-LOCA meets the acceptance criterion and is acceptable.

Small-Break The applicant has reanalyzed the small-break LOCA based on some limiting condi-tions.

The result showed a PCT penalty of 108F,

The final PCT for the small-break LOCA is thus 1895.5 F, which is below the~10 CFR 50.46 acceptance criterion-of 2200 F.

The staf f, therefore, concludes that the applicant's reanalysis of the small-break LOCA meets the ccceptance criterion and is acceptable. '

15.4 Radiological Consequences of Design-Basis Accidents 15.4.4 Steam Generator Tube Rupture Accident Following the Ginna steam generator tube rupture (SGTR) event on January 25, 1982, the SGTR Subgroup of the Westinghouse Owners Group (WOG) submitted.

o WCAP-10698, "SGTR Analysis Methodology To Determine the Margin to Steam Generator 4

Overfill," dated December 1984, for NRC staff review, which also references WCAP-10698, Supplement 1, " Evaluation of Offsite Radiation Doses for a Steam Generator Tube Rupture Accident."

In its evaluation of these Westinghouse reports (NRCletter, March 30, 1987), the staff concluded that the WOG provided an~ac-ceptable and conservative methodology for the generic SGTR analysis,'but that five specific and crucial values and assumptions used in the analysis may vary i

significantly from plant to plant, altering the steam generator overfill and radiological dose results.

The staff concluded that each member of'the SGTR subgroup and all near-term operating license (NT0L) applicants of Westinghouse plants were required to submit plant-specific.information as follows before the methodology from WCAP-10698 could be applied on a plant-specific basis:

1 (1) Confirmation that the plant has in place simulators and training programs which provide' the required assurance that the necessary actions and times l

can be taken consistent with those assumed ~for the WCAP-10698 design-basis analysis.

Demonstration runs should be performed to show that the-accident =

can be mitigated within a period of time compatible with overall prevention,-

L i

using design-basis assumptions regarding available equipment, and to-demon-strate that the operator action times assumed in the analysis are realistic.

(2) A site-specific SGTR radiation offsite consequence analysis which assumes.

the most severe failure identified in WCAP-10698, Supplement 1.

The analy-sis should be performed using the methodology'in Standard Review Plan (SRP)

Comanche Peak SSER 23 15-2

Section 15.6.3 (NUREG-0800), as supplemented by the guidance in a_ letter the NRC sent to the WOG SGTR subgroup in December 1985.

(3) An evaluation of the structural adequacy of the main steam lines and assoc-iated supports under water-filled conditions as a result of SGTR overfill.

(4) A list of systems, components, and instrumentation which are credited for accident. mitigation in the plant-specific SGTR emergency operating proce-dures (EOPs)..Specify whether each system and component specified is safety grade.

For primary and secondary power-operated _ relief valves (PORVs) and control valves, specify the valve motive power and state whether the motive power and valve controls are safety grade.

For non-safety grade systems and components, state whether safety grade backups are available which can be expected to function, or provide the desired information within a time period compatible with prevention of SGTR overfill, or justify that non safety grade components can be utilized for the design-basis event.

Provide a list of all radiation monitors that could be utilized for iden-tification of the accident and the ruptured steam generator and specify the quality and reliability of this instrumentation if possible.

If the E0Ps specify steam generator (SG) sampling as a means of identifying the ruptured SG, provide the expected time period for obtaining the sample results and discuss the effect on the duration of the accident.

(5) A survey of plant primary and " balance of plant" systems design to determine the compatibility with the bounding plant analysis in WCAP-10698.

Major design differences should be noted.

The worst single failure should be identified if different from the WCAP-10698 analysis and the effect of the difference on the margin of overfill should be provided.

TU Electric is a member of the SGTR subgroup and has provided by letters.to NRC (March 15 and December 20, 1988), the plant-specific information (listed above) as required by the staff for CPSES.

The staff's review of the SGTR' accident-analysis for the CPSES FSAR follows, consistent with the just-listed five re-quirements as necessary for application of the WOG generic methodology in a plant-specific basis, lhe applicant examined two different scenarios for the CPSES Unit 1 SGTR acci-dent analysis.

The scenarios are (1) the SGTR scenario conducive to steam gen-erator (SG) overfill and (2) the SGTR scenario resulting in a maximized offsite dose.

Each scenario includes a limiting single failure.

The significance of the SG overfill scenario is the possibility for an offsite radioactive release through the SG safety valves and the' possibility of creating a main steam line break.

For the maximum offsite dose scenario, the concern is assuring compliance with regulatory offsite dose limits as specified in 10 CFR 100.11.

Both scen-arios have been analyzed under design-basis conditions using the SGTR methodology in WCAP-10698 and WCAP-10698, Supplement 1.

i (1) Evaluation of Steam Generator Overfill Scenario i

Single-Failure Assumption CPSES Unit 1 is a four-loop Westinghouse ~-designed plant with a Model D-4 type SG of 5954 ft3 total volume capacity.

For the design-basis SGTR scenario most conducive toward overfill, the licensee has identified the Comanche Peak SSER 23 15-3

4I i

worst-case single failure to be a failed-open auxiliary feedwater (AFW) throttling valve on the faulted SG loop.

Because the inventory of the' faulted SG should be maximized for conservatism in the SG overfill analy-sis, the tube break is modeled as the double-ended, guillotine break of a single tube, consistent with SRP Section 15.6.3.

Primary flow out the break is maximized with the break location ~ assumed above the tube sheet, at the SG tube bundle exit.

Other Assumptions The licensee assumed that all three AFW pumps initiated at full-flow capa-

city, subsequent to the reactor trip.

The inventory in the faulted SG is conservatively assumed to increase at this rate until the operator isolates AFW flow to the faulted SG about 15 minutet after the onset of the design-basis tube rupture.

The reactor trip time was assumed on low pressure, at its maximum allowable-set point, to begin AFW injection as soon as possible after the SGTR.

This trip time is conservative for the SG overfill scenario.

Other assumptions include a loss of offsite power (LOOP) 5 minutes after the SGTR, a conservative initial SG mass, and the consideration of an SGTR-at zero power.

The applicant has determined that a LOOP occurring subse-quent to a reactor / turbine trip is conservative due to the higher primary pressure before LOOP which results in an increased break flow rate, and the turbine runback which results in increased inventory in the faulted SG.

Although the applicant assumes 100 percent power conditions elsewhere in the event, it assumes an SG mass corresponding-to 40 percent power for an increased initial inventory in the SGs.

Also, the applicant has evaluated i

the effects of an SGTR at zero power and has found them to be bounded by the 100 percent power scenario, partially due to the reduced break flow at lower power levels.

Margin to Overfill Overfill of the faulted SG in an SGTR is of concern because of the increased load on steam lines, which were not designed to serve as water lines, and because of the possible release of primary coolant to the atmosphere via-l safety valves, which were not designed to have water pass through them.

The design-basis tube rupture, as modeled, adds an estimated 163 ft3 of primary water during the first 40 minutes of the event.

AFW continues to

[

contribute to the SG inventory, adding to the increasing level in the faulted SG, until manual isolation occurs.

According to the analysis and on the basis of emergency response guidelines l

(ERGS) and emergency operating procedures (EOPs), the tube rupture event can be identified within 10 minutes from the onset of the event, and the faulted SG can be isolated.

Design-basis SGTR simulator runs were done at CPSES, as close to design-basis conditions as the-simulator would allow, exploring the validity of the operator action times assumed in the analysis.

l The results of the simulator tests.are discussed below.

Assuming 11.5 minutes to cool down the primary system and 3.5 minutes to depressurize the reactor coolant system (RCS), the total time to terminate' Comanche Peak SSER 23 15-4

flow through the ruptured tube from the onset of the event is 37 minutes.

At this point, the faulted SG level ceases to rise and indicates the maxi-mum SG 1evel during the event to be 5634 ft3 Therefore, the applicant concluded that the faulted SG, with a volume of 5954 ft3, does not overfill for the design-basis SGTR.

(2) Evaluation of Scenario for Maximum Offsite Radiological Consequences The applicant has performed a site-specific SGTR radiation offsite conse-quence analysis which considers atmospheric relief valve failure to'close on the faulted SG as a worst single failure.

The results of this analysis are well within the limits set by 10 CFR 100.11.

However, the staff is not convinced that the applicant has analyzed the worst-case scenario similar to the North Anna SGTR event.

The North Anna event demonstrated that the-worst-case SGTR location from a radiological standpoint could be at the top.

of the tube bundle.

This new analysis dose calculations would increase in comparison to the current analysis.

However, the staff concludes that the doses would remain within the 10 CFR 100.11 requirements.

The WOG is currently evaluating the offsite consequences from a postulated top break accident.

In a letter dated January 17, 1990, the applicant has committed to provide the staff with a schedule to implement any required plant-specific analysis (once the staff has accepted the analysis proposed by the WOG), if the results of the WOG-sponsored study show that a plant-specific analysis is indeed required.

RETRAN Computer Code The applicant used RETRAN02/M0D04 to analyze the SGTR event for CPSES Unit 1.

This version of RETRAN has not previously been approved for generic licensing applications.

Therefore, the NRC staff has evaluated the appropriateness of RETRAN02/ MOD 04 for the SGTR scenario presented by the applicant.

The staff's consultant compared RETRAN02/ MOD 04 with RETRAN02/M002 (letter from H. Kamariya and P. B. Abramson [ International Technical Services, Inc.] to A. P. Gilbert

[NRC] dated May 4, 1988)-and found that the staff safety evaluation report writ-ten on M0002 (see letter from C. O. Thomas [NRC] to T. W. Schnatz [ Utility Group for Regulatory Application], dated September 2, 1984) was applicable to MOD 04.

l In the evaluation of the CPSES SGTR analysis, the staff found nothing that vio-lated the restrictions imposed by the September 12, 1984 safety evaluation.

The applicant addressed each limitation in a letter dated December 20, 1988, and the staff concluded that there is reasonable assurance that MOD 04 is adequate for use in this SGTR analysis.

Therefore, the staff concludes that RETRAN02/

MOD 04 is acceptable as applied to this licensing application.

Evaluation of the Applicability of WCAP-10698 (WOG Generic SGTR Analysis) to CPSES The applicant addressed the five issues that the staff identified as requiring plant-specific submittals before use of methodology of WCAP-10698. The staff has evaluated the applicant's responses to these issues as discussed below:

i (1) The applicant has confirmed that CPSES Unit 1 is establishing the simulator and training programs necessary to assure that operator actions and opera-tor action times can be conducted under design-basis conditions consistent Comanche Peak SSER 23 15-5

i with those actions and times assumed in the CPSES SGTR accident analysis.

The applicant has performed demonstration runs to show that the accident can be mitigated within a period of time compatible with SG overfill pre-vention using design-basis assumptions.

Further, the results of those demonstration runs were bounded by those operator action times assumed in the plant-specific SGTR analysis and are, therefore, acceptable.

7 (2) The applicant has provided a site-specific SGTR radiation offsite conseq-uence analysis.

The WOG is evaluating the offsite consequences due to a postulated top break accident to determine whether the worst-case SGTR scenario has been analyzed.

In a letter dated January 17, 1990, the appli-cant has committed to provide the staff with a schedule to implement any required plant-specific actions (once the staff has approved the actions proposed by the WOG), if the results of the WOG-sponsored study show that a plant-specific response is indeed required.

(3) The staff has reviewed the structu*al adequacy of the CPSES Unit 1 steam lines under water-filled conditions.

On the basis of a review of the pipe support calculations to assess the effects of the SGTR event the staff finds that the structural integrity of the affected supports is maintained per American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),Section III, Subsection NF requirements, as a result of loads imposed by this event.

The staff finds this acceptable.

(4) The applicant has provided a list of systems, components, and instrumenta-tion which are credited for accident mitigation in the plant-specific SGTR E0Ps.

Further categorization of the above equipment was done with added descriptions of their use in the design-basis and non-design-basis SGTR scenarios.

This request by the staff was aimed toward determining whether safety grade equipment, exclusively, was credited in'the accident analysis for mitigation of the event.

Of particular interest is identification of the SGTR using only safety grade control room monitors, which excludes the use of condenser air ejector monitors.

The staff has reviewed this information and concludes that the applicant does in fact credit only safety grade equipment for identification and mitigation of the SGTR event.

Verification of the ability to mitigate the event in accordance with the assumptions in the accident analysis is incor-I porated into the procedures for the SGTR simulator runs.

Because the re-l sults of the simulator runs will be consistent with the accident analysis, with only safety grade equipment available to the operator from the time of accident initiation, the staff is reasonably assured in the analysis (con-sistent with item 1) without the availability of_ condenser air ejector moni-tors.

The staff finds the list of equipment used for SGTR mitigation to be acceptable, (5) The compatibility of the CPSES SGTR analysis with the bounding plant analy-i sis (NRC letter to WOG SGTR subgroup, March 30, 1987) has been determined by the applicant and incorporated into the plant-specific analysis.

The staff has reviewed, discussed, and evaluated the results'of the comparison and finds them acceptable.

Comanche Peak SSER 23 15-6

Conclusions-On the basis of the.information provided, the staff concludes that the applicant' has met the staff requirements of the NRC letter of March 30,t 1987, and that the methodology and analysis for the CPSES SGTR accident analysis are acceptable, and the proposed license condition is-no longer necessary.

Further, because the applicant has provided reasonable assurance:that CPSES-Unit-1 can withstand the effects of a design-basis SGTR event, the reassessment of the radiological con-sequences due to an SGTR at the top of the tube sheet, currently being investi-gated by the WOG, will be treated as a confirmatory issue.

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16 TECHNICAL SPECIFICATIONS Relocation of Technical Specifications Requirements

]

On February 6, 1987, the Commission issued an Interim Policy Statement on Tech-nical Specification Improvements (52 FR 3788).

The policy statement encouraged

.J the development of new Standard TechnTeal Specifications (STS) to be used as guides for' licensees in preparing improved Technical Specifications (TS) for their facilities.

The policy statement contained criteria for determining which regulatory requirements and operating restrictions should be retained in TS.

It-also identified four additional systems that are to be retained on the basis of operating experience and probabilistic risk assessment (PRA).

The policy state-i ant indicated that risk evaluations are an appropriate tool for defining re-quirements that should be retained in the TS, where including such requirements is consistent with the purpose of TS.

Finally, it indicated that current TS requirements not retained in the STS would be relocated to other licensee-controlled documents.

On the basis of the policy statement criteria, Texas Utilities Electric Company (TV Electric, the applicant) proposed in the October 30, 1987 TS markup for CPSES Unit 1 to relocate a number of technical specifications and TS tables to licensee-controlled documents.

At a meeting with TV Electric in January 1988, the staff informed the applicant that some of the proposed changes were being considered by the staff as line-item improvements-to the STS and that these improvements could be factored into the CPSES Unit 1 TS when the staff's posi-tion was finalized.

Except for the turbine overspeed reliability program (TORP),

the staff considered the balance of the proposed TS changes as generic changes to the STS.

The staff informed the applicant that these generic items did not have sufficient safety significance to warrant their consideration ahead of the development of the new STS which was being prepared by the Westinghouse Owners Group (WOG).

By January 1989, the staff had issued generic letters (GLs) on three of the line-item improvements discussed at the January 1988 meeting and incorporated them into the CPSES Unit 1 TS.

These technical specifications and TS tables were relocated to the following documents:

The fire protection TS were relocated to the fire protection program per GL 88-12.

The organizational charts were relocated to the FSAR per GL 88-06.

The radiological effluent = technical specifications were relocated to the Offsite Dose Calculation Manual (0DCM) and the process control program per GL 89-01.

In addition, four tables were relocated to the Comanche Peak Technical Require-ments Manual (TRM).

The staff was developing generic letters alerting people Comanche Peak SSER 23 16-1

I J

to the relocation of these tables and the staff position was far enough along to approve these changes on a lead plant basis for CPSES Unit 1.

The four relocated tables are:

Table 3.3-2, " Reactor Trip System Instrumentation Response Times" Table 3.3-5, " Engineered Safety Features Response Times" Table 3.6-1, " Containment Isolation Valves" Table 3.8-1, " Containment Penetration Conductor Overcurrent Protective Devices" i

The relocation of the turbine overspeed trip system surveillance requirements to a TORP has only been approved for certain Westinghouse-manufactured turbine-generator (TG) units based on a Westinghouse topical report approved by the staff.

Since the TG unit and its associated overspeed trip system at CPSES were manufactured by Allis-Chalmers Power Systems Inc., the applicant was informed that relocation of the turbine overspeed TS to a TORP would not be considered until a t"rbine missile study similar to the Westinghouse submittals was provided by Allis-cnalmers.

In a letter dated August 5, 1988, the applicant submitted a list of 64 generic TS changes, of which 23 involved the relocation of some technical specifications, in a meeting on September 22, 1988, the staff informed the applicant that 15 of the 23 proposed TS relocations had been discussed previously as items being con-sidered as line-item improvements by the staff.

Of the eight remaining proposed TS relocations, the staff would only consider the relocation of seven technical specifications as a limited trial use of the criteria specified in the "NRC Staff Review of Nuclear Steam Supply System Vendor Owners Groups' Application of the Commission's Interim Policy Statement Criteria to Standard Technical Specifica-tions" (transmitted by letter from T. E. Murley [NRC], to R.-A. Newton [WOG),

dated May 9, 1988).

The seven-specifications proposed for relocation were:

3/4.3.3.2 Moveable Incore Detectors 3/4.3.3.3 Seismic Instrumentation 3/4.3.3.4 Meteorological Instrumentation 3/4.3.3.9 Loose-Part Detection System 3/4.4.5 Steam Generators 3/4.7.9 Snubbers (Surveillance Requirements only) 3/4.7.10 Sealed Source Contamination On November 17, 1988, the applicant submitted a risk survey.to show that these technical specifications could be relocated from the CPSES TS. The applicant concluded that for specifications 3/4.3.3.2, 3/4.3.3.3, 3/4.3.3.4, 3/4.3.3.9, and 3/4.7.10, the failure of the systems associated with those specifications would not affect any of the PRA-identified initiating events or critical systems listed in the November 17, 1988 letter. -Therefore, these items were not consid-ered to be significant risk contributors and could be relocated from the TS.

The staff has reviewed the risk survey for these specifications and concurs with the applicant's conclusions that the TS requirements for these. specifications can be relocated to a licensee-controlled document without affecting the plant's ri s k.

Comanche Peak SSER 23 16-2

The staff did not require a risk survey for specification 3/4.7.9, since the TS surveillance requirements were only being relocated, without changes, to the TRM, leaving the limiting condition for operation (LCO) in the TS.

Therefore, the staff concludes that the relocation of the following specifications to the cited documents is acceptable:

Specification 3/4.3.3.2 to the TRM

~

Specification 3/4.3.3.3 to the TRM Specification 3/4.3.3.4 to the ODCM Specification 3/4.3.3.9 to the TRM Specification 3/4.7.9 to the TRM Specification 3/4.7.10 to the ODCM Since the risk survey showed that the steam generators have a potential to impact the PRA-identified initiating events and the critical systems listed in the November 17, 1988 letter, the staff concluded that specification 3/4.4.5 could I

not be moved out of the CPSES TS.

However, the staff relocated the surveillance requirements for specification 3/4.4.5 to Section 3/4.0 of the CPSES TS and j

incorporated LC0 3.4.5 into the LCOs of specification 3/4.4.1.

The staff requested that a description of tne controls which would be used to maintain and change the TRM be submitted for review.

The applicant, in a letter dated December 21, 1988, submitted the requested description.

The staff has reviewed the proposed controls and finds that the program is consistent with the 10 CFR 50.59 guidel'oss being developed by the staff and the industry (Nuclear Management and Resora es Council [NUMARC)).

Therefore, the staff concludes that the controls on changes to the TRM are acceptable.

i 2

1 l

i 1

i Comanche Peak SSER 23 16-3

L I

fi 22 THI-2 REQUIREMENTS 22.1 Introduction The Comanche Peak Safety Evaluation Report (SER) (NUREG-0797, July 1981) indi-cates staff inspection requirements pertaining to various action items developed-in response to the 1979 nuclear accident at Three Mile Island, Unit 2 (TMI-2) and required by the staff to be implemented by the applicant.

The status of the staff's review, including inspections, is discussed below.

lL 22.2 Discussion of Requirements I.A.1.1 Shift Technical Advisor Generic Letter (GL) 86-04, " Policy Statement on Engineering Expertise on Shift,"

issued on February 13, 1986, transmitted-the Federal Recister notice (50 FR 43621, October 28,1985) of the Commission policy statement anc gave licensees a'id appli-cants an opportunity to transmit plans regarding modifications to their current programs.

The policy statement offered two options for meeting the current're-quirements for providing engineering expertise on shift in accordance with this TMI-2 item and meeting licensed operator staffing requirements [10 CFR 50.54(m)(2)].

Option 1 provided for elimination of the separate shift technical advisor (STA) position by allowing licensees and applicants to combine one of the required senior reactor operator (SRO) positions with the_ STA position into a dual role SR0/STA position.

Option 2 stated that licensees and applicants.could' continue to use an NRC-approved STA program while meeting the-licensed operator staffing requirements.

The applicant responded to GL 86-04 in a letter dated May 30, 1986, and stated that the program at CPSES for providing engineering expertise on shift would-comply with Option 2 of the generic letter._ Subsequently, in Final Safety Analy-sis Report (FSAR) Amendment 76 and as documented in SER Supplement 22 (SSER 22),

~

a Section 13.1.2.1, the applicant revised its commitment (to have an STA on each j

shift) to allow for the use of the dual role SR0/STA if the individual who per-l forms the dual-role function meets Option 1 of the Commission policy statement.

This meets the guidelines of GL 86-04 and the Commission Policy Statement on-1 Engineering Expertise on Shift and is, therefore, acceptable, j

I.A.2.3 Administration of Training Programs for Licensed Operators i

The SER states that the staff will verify that all-permanent members of-the sta-tion staff who teach systems, integrated responses, transients, and simulator courses are certified by either demonstrating their SR0 qualifications or by

. j successfully completing an instructor certification program.

The staff reviewed-the rssumss of the training staff and verified that this commitment has been met a

(Inspection Report 50-445/89-72; 50-446/89-72),

a Comanche Peak SSER 23 22-1 1

-q

)

t 1.C.5 Procedures for Feedback of Operating Experience to Plant Staff In accordance with the provisions and clarifications of NUREG-0660 and NUREG-0737, the applicant is required to prepare procedures to ensure that operating informa-tion pertinent to plant safety, originating both within and outside the utility organization, is continually supplied to operators and other personnel, and is incorporated into training and retraining programs.

SSER 6 stated that the staff concluded that the procedures to handle the evaluation and feedback of operating l

experience information to appropriate plant personnel are in conformance with i

the TMI Action Plan and are, therefore, acceptable.

In addition, Inspection Report 50-445/89-37; 50-446/89-37 reviewed the applicant's current procedures, which reflect changes (since SSER 6) in titles and reporting responsibilities l

within the applicant's organization, and determined that the current _ procedures adequately address-the provisions of this action item.

l I.C.7 NSSS Vendor Review of Procedures l

Operating license applicants are required to obtain reactor vendor review of their low power test, power-ascension, and emergency procedures as a further.,

j verification of the adequacy of the procedures.

The staff verified that Westinghouse reviewed the emergency procedures.

In addition, a Westinghouse representative is a member of the Joint Test Group and Test Review Group which review the low power test and power-ascension procedures (Inspection Report 50-446/89-72; 50-446/89-72).

On this basis, the staff concludes that the applicant has taken appropriate actions to ensure NSSS vendor review of these procedures.

II.B.3 Postaccident Sampling Capability In Chapter 22 of SSER 6, the staff reported that the applicant's postaccident sampling system (PASS) included the ability to perform in-line monitoring of l

the conductivitiy of the undiluted sample, which is not a regulatory require-l ment.

The applicant has deleted the conductivity cell because' experience has shown that the cell traps air during calibration and impairs the operation of the desired in-line pH monitor.

The conductivity cell was one of several indi-cations to confirm an adequate flush for.the sample.

However, the only measured value that is actually used to verify an effective flush is the radiation level at the panel.

The staff agrees that the conductivity cell is not needed to meet any of the criteria of item II.B.3 and that its removal will not impair the PASS's sampling capability.

l The staff concludes that the removal.of in-line conductivity monitoring capabil-ity from the PASS does not affect the staff's previous conclusion that the pro-posed PASS meets all of the criteria of item II.B.3 of NUREG-0737.

l II.B.4 Training for Mitigating Core Damage NUREG-0737 states, in part, that a training program is to be developed to teach shift technical advisors (STAS) and operating personnel, ranging from the plant manager through the operations chain to the licensed operators, to use installed equipment and systems to control or mitigate accidents in which the core is severely damaged.

This program is to be developed before fuel load and is to include the training indicated in Enclosure 3 to H. R. Denton's March 28, 1980, letter.

Comanche Paak SSER 23 22-2

i The staff (Inspection Report 50-445/89-67; 50-446/89-67) reviewed the applicant's letter dated August 7, 1989, cross-referencing the items in the Denton letter to the training sources-that implement the training.

The staff also reviewed the applicant's Quality Assurance (QA) Audit Report TUG-87-34, dated January 26, 1988, which identified five specific areas of severe-core-damage training which j

were not adequately addressed.

In a memorandum dated June 16, 1989, from i

J. McMahon to B. Wells, the applicant detailed the corrective action status of QA Audit TUG-87-34, stating that the Mitigating Core Damage Course will be revised to include all training criteria of the Denton letter.

The applicant informed the staff that the course has been revised, and that as of October 27, 1989, all currently licensed operators have completed the course.

The staff will verify the implementation of the training program before full power operation.

II.E.4.2 Containment Isolation Dependability I

In accordante with TMI Action Plan Item II.E.4.2(f), the applicant is required to demonstrate the operability of the containment purge and vent valves and, in particular, the ability of those valves to close during a design-basis accident /

loss-of-coolant-accident (DBA/LOCA) event to ensure containment isolation.

The purge / vent system for CPSES consists of two 18-in, and two 48-in, purge and vent lines.

SSER 12 reported that the issue of purge / vent valve operability remained a confirmatory issue [ item 10(j)] and that further information from the applicant would be required to resolve this item.

l The applicant responded to the staff's concerns in a letter dated December 16,-

1985, providing the requested operability analysis for the 18-in, purge valves.

The applicant is required by the plant Technical Specifications to maintain the 48-in, purge valves locked closed during operating modes 1, 2, 3, and 4.

j The staff's consultant on this issue, Brookhaven hational Laboratory (BNL), has reviewed the analysis contained in the applicant's December 16, 1985 letter, and has provided the staff with a technical evaluation report dated October 5, i

1989.

A summary of the consultant's evaluation, and the staff's conclusion, i

are provided below.

j The 18-in. purge valves installed in the CPSES units as PosiSeal International, j

Inc. butterfly valves have actuators set up to require air to open and spring

~

close upon receipt of an isolation signal or loss of power or. air.

The-appli-cant has evaluated the ability of these valves to close without damage'against the design pressure of the containment (50 psig).for different values of initial valve openings.

In order to ensure valve closure, the amount of valve opening is restricted to 65 degrees by bolting a stop to the intervals of the matrix piston cartridge which limits the stroke of the actuator.

BNL has reviewed the applicant's approach for determining the dynamic torques on the 18-in. purge valves resulting from a postulated LOCA-related pressure inside containment, the ability of critical valve parts to withstand the stresses associated with the postulated LOCA and seismic loads, and the valve closure times,.taking into account the various torques acting on the valves during closure.

BNL has concluded that the information submitted demonstrates the ability of the 18-in. purge valves to close from a maximum opening of 65 degrees against the rise in containment pressure following a postulated DBA/LOCA.

The staff has reviewed the evaluation performed by BNL and concurs with its conclusion.

4 l

Comanche Peak SSER 23 22-3

The staff concludes that the operability requirements of TMI Action Plan Item II.E.4.2(f) have been satisfied for the CPSES purge and vent system.

This completes the staff's review of II.E.4.2 for the CPSES units.

II.F.2 Instrumentation for the Detection of Inadequate Core Cooling Heated Junction Thermocouple System-Reactor Vessel Level Measurement By letter dated July 24, 1989, the applicant informed the NRC of a discrepancy between the design values and actual values of temperature difference for the heated junction thermocouple (HJTC) equipment, as discussed in SSER 6.

During the performance of the CPSES Unit 1 JHTC preoperational test, the temperature difference between the heated and unheated junction thermocougle at ambient temperature and atmospheric pressure ranged from 106 F to 171 F instead of the anticipated design temperature difference of much less than 100 F as was de-scribed in SSER 6.

A telephone conference was held on November 8, 1989 to discuss the increased HJTC ATs at CPSES.

On December 7, 1989, the applicant-submitted a letter to respond to the staff questions discussed in the telephone conference.

The dif ferential temperature (AT) between the unheated and heated HJTC junction isaninputrelatedtothepredeterminedsetpointfortheheatedjunction thermocouple signals.

This set point is a plant-specific item and determiries the presence or absence of liquid at each HJTC sensor location.- The differen-tial temperature set point is calculated (based on tests) to be low enough to obtain a good response time, but high enough to ensure liquid is not 3 resent.

The set point values are predetermined and are installed as part of tie level logic software.

The logic indicates that the liquid level has. dropped to a level lower than the sensor location when the AT sensed by the thermocouple exceeds the AT set point.

The Combustion Engineering (CE) testing results (CEN-185-P, Supplement 3-P) indicated that the observed values from CPSES are consistentwiththemeasuredvaluesatCEtestingfacilitiesdegFto171Ffor ending on the size of the heater power.

The observed values ranging from 106 CPSES Unit 1 during HJTC preoperational testing is equivalent to the measured values from CE testing facilities corresponding to either 20 watts or 30 watts heat power used.

The sensor is considered covered with liquid if AT is below 200 F.

The applicant has provided an HJTC AT comparison.

It indicates the covered AT is approximately 126 F or less and the average AT is approximately 100 F for the CPSES Unit 1 HJTC, which are within about the same range as those measured from the other plants with the HJTC system.

This provides adequate l

margin to avoid spurious indication of an uncovered HJTC sensor.

l l

The staff concludes that, although the AT observed during testing at CPSES was larger than the value predicted in SSER 6, the HJTC equipment will perform its intended function of providing the plant operators with an unambiguous reading of reactor vessel coolant level and is acceptable.

II.K.1 IF Bulletins on Measures To Mitigate Small-Break LOCAs and Loss-of-1 Feedwater Accidents I

Inspection Report 50-445/89-83; 50-446/89-83 provided NRC verification that the applicant has adequate controls in place to ensure proper engineered safety I

feature (ESF) functioning and to ensure that the operability status of safety-l related systems is always known.

Comanche Peak SSER 23 22-4

The staff reviewed Instruction 0WI-103, Revision 3. " Operations Department Locked Valve Control," which provides Operations Department personnel with a method for controlling, maintaining, and verifying locked-in position valves and breakers by means of chain or cable and padlocks or seals.

In general, the applicant uses this instruction as well as the valve lineups called for in the standard operat-ing procedures to ensure that valve, breaker, and switch i.neups are controlled to ensure proper ESF functioning.

The staff reviewed Operations Procedure ODA-308, Revision 0, "LC0 Tracking Log,"

to verify that the applicant has a method to remain aware of the operability status of safety-related systems.

This procedure provides Operations Department i

personnel with a method of documenting and tracking degraded Technical Specifi-cations limiting conditions for operations, required actions, reporting, and testing requirements.

The staff finds that the applicant has met the requirements of this-TMI-2 action item.

j III.D.1.1 Integrity of Systems Outside Containment Likely To Contain Radio-

__active Material i

In Section 22.2 of SSER 4, the staff concluded that the applicant's commitments to meet NUREG-0737, Item III.D.1.1 of the TMI Task Action Plan were acceptable.

In FSAR Amendments 76 and 78, the applicant specified that the leakage value for systems outside containment likely to contain radioactive material will be lim-ited to 1 gpm/ unit.

This is consistent with the leak rate assumed for engineered l

safety features equipment in calculating the LOCA doses and is more conservative i

than the limits which were evaluated and found acceptable in SSER 4.

The staff, i

therefore, concludes that the applicant's commitments are still in accordance with Item 111.D.1.1, and are acceptable.

l Comanche Peak SSER 23 22-5 l

_.___------_--------------N

l APPENDIX A CONTINUATION OF CHRONOLOGICAL LISTING OF CORRESPONDENCE This appendix continues the chronological listing of routine licensing corre-spondence between the U. S. Nuclear Regulatory Commission (NRC) staff and the applicant (Texas Utilities Electric Company) since Supp?ement 22 was issued.

January 5, 1990 Letter from applicant providing the rcsponse required prior to fuel load for NRC Bulletin 89-03 concerning shutdown mar-gin during refueling.

January 5, 1990 Letter from applicant identifying that Comahche Peak Steam Electric Station (CPSES) will be ready for the Operational Readiness Assessment Team to return on January-22, 1990.

January 12, 1990 Letter from applicant providing an advance submittal of a Final Safety Analysis Report (FSAR) change related to acci-dent monitoring and the instrument range for the parameter component cooling water header temperature.

January 12, 1990 Letter from applicant providing the schedule for.the comple-tion of two pre-operation tests, one of which is deferred until af ter fuel load since main condenser vacuum is required to complete the test.

January 15, 1990 Letter from applicant submitting recommended changes to the proposed Technical Specifications for CPSES Unit.1.

January 15, 1990 Letter from applicant transmitting Amendment 78 to the CPSES-FSAR.

January 15, 1990 Letter from applicant transmitting a description of Amend-ment 78 to the CPSES FSAR.

January 15, 1990 Letter from applicant transmitting Revision 2 to the Technical Requirements Manual.

January 17, 1990 Letter from applicant providing clarification and revision to the description of the negative pressure boundary established and maintained to control potential emergency core cooling system leakage.

January 17, 1990 Letter from app'icant providing commitment to submit CPSES implementation schedule for actions required to resolve steam generator tube rupture issue within 60 days following NRC staff's approval of the Westinghouse Owners Group proposal.

Comanche Peak SSER 23 1

Appendix A' l

January 17, 1990 Letter from applicant providing supplemental information regarding cable tray percent fill criteria, fill above the siderail criteria, and measures taken to comply with these criteria.

January 17, 1990 Letter from applicant transmitting proposed changes to the CPSES Physical Security Plan.

January 19, 1990 Letter to applicant providing NRC acceptance of the approach, methodology and schedule provided in the 60-day response to Generic Letter (GL) 88-20.

January 23, 1990 Letter from applicant providing TV Electric's concurrence with its consultant's (APTECH) report on the Borg-Warner check valve swing arm failures.

January 24, 1990 Letter from applicant transmitting supplement 4 of the CPSES Human Factors Control Room Design Review Final Report, in-cluding the results of the environmental surveys.

January 25, 1990 Letter to applicant transmitting a notice of violation and proposed imposition of a $30,000 civil penalty (Inspection Report 50-445/89-30 and 50-446/89-30).

January 26, 1990 Letter from applicant providing response to-GL 89-13 concern-ing problems with service water systems.

January 26, 1990 Letter from applicant providing additional information re-lated to the full penetration attachment welds for contain-ment liner insert plates.

January 26, 1990 Letter from applicant providing the results of the engineering report of the fracture toughness of the feedwater isolation valves.

January 26, 1990 Letter from applicant providing additional information for twelve non-conforming flanges, per NRC Bulletin 88-05, with low hardness.

January 26, 1990 Letter from applicant identifying the engineering evaluation performed on bolting materials used'at CPSES.

January 30, 1990 Letter from applicant certifying that all temporary badges have been removed from access points and deleted from the security computer.

January 30, 1990 Letter to applicant forwarding GL 90-01 concerning voluntary participation in regulatory impact survey.

January 31, 1990 Letter from applicant transmitting payment of civil penalty proposed by Enforcement Action (EA)-318 and responding to related Notice of Violation.

Comanche Peak SSER 23 2

Appendix A

i k

February 2,1990 Letter from applicant confirming the completion of the transfer of all Tex-La Electric Cooperative of Texas, Inc.

ownership of CPSES to the Texas Utilities Electric Company on February 1,1990.

February 2,1990 Letter from applicant confirming the completion of the mechanical and electrical equipment qualification program (environmental and seismic).

February 2,1990 Letter from applicant providing results and evaluation of chemical test data for twelve non-conforming flanges,~per NRC Bulletin 88-05, with low hardness.

February 2, 1990 Letter from applicant describing management action in the area of the identification and correction of problems.

The following correspondence was omitted from the chronologies in the preceding supplement and should be inserted in proper order.

September 19, 1989 Letter to applicant forwarding summary of September 5, 1989-meeting with utility regarding' significance of Criner Fault to grant.

September 21, 1989 Letter from applicant providing the annual report of changes in peak cladding temperature.

September 22, 1989 Letter from applicant forwarding the Unit 1 Inservice Test-ing Program Plan, " Inservice Testing of the Pumps and Valves",

Revision 3.

October 4, 1989 Letter to applicant forwarding notification of October 11, 1989 meeting with the applicant to discuss structural issues.

October 19, 1989 Letter to applicant forwarding GL 89-22 concerning changes in maximum probable precipitation.

October 24, 1989 Letter from applicant forwarding additional information con-cerning surge line stratification and leak-before-break evaluation.

October 24, 1989 Letter from applicant forwarding additional information in response to NRC Bulletin 88-08 concerning thermal stresses in piping connected to the reactor coolant system (RCS).

October 26, 1989 Letter from applicant forwarding proposed changes to the CPSES Emergency Plan.

October 27, 1989 Letter from applicant describing the status and completion plans for the engineering function evaluation.

October 27, 1989 Letter from applicant forwarding response to GL 89-07 con-cerning safeguards contingency planning.

Comanche Peak SSER 23 3

Appendix A

October 30, 1989 Letter from applicant forwarding a response to GL 88-20 on individual plant examinations for severe accidents vulnera-bilities.

October 31, 1989 Letter from applicant forwarding information related to the schedule for submitting core reload analysis topical reports.

November 1, 1989 Letter from applicant advising that changes and revisions to chemistry, environmental, and operations procedures will be issued before fuel load in response to Unresolved Item 445/8957-U-02.

November 2, 1989 Letter to applicant advising that financial information sub-mitted for 1989 in September 15, 1989 letter satisfies re-quirements of 10 CFR 140.21.

November 2, 1989 Letter from applicant forwarding proprietary WCAP-12248, Supp1 ament 2 and nonproprietary WCAP-12247, Supplement 2,

" Additional Information in Support of Evaluation of Thermal Stratification for Comanche Peak Unit...." per NRC Bulletin 88-11.

Proprietary report withheld (ref 10 CFR 2.790).

November 2, 1989 Letter from applicant responding to NRC Bulletin 88-09 regarding thimble tube thinning in Westinghouse reactors.

Utility developing procedure to include criteria for characterizing thimble tube wear and describes actions to' be performed should unacceptable wear be observed.

November 3, 1989 Letter to applicant forwarding notification of November 30, 1989 meeting with utility in Region IV to discuss recent changes in operator licensing program, including. generic fundamentals examination section and revisions to site-specific exam section.

November 6, 1989 Letter to applicant forwarding environmental assessment and finding of no significant impact regarding exemption from requirements of 10 CFR 70.24.

Exemption concerned criticality monitors in areas where fuel assemblies are stored and handled.

November 6, 1989 Letter to applicant forwarding environmental assessment and finding of no significant impact regarding January 20, 1986 request for exemption from 10 CFR 50, Appendix J, Section III.D.2(b)(ii), containment airlock leakage testing.

November 6, 1989 Letter to applicant forwarding environmental assessment and finding of no significant impact regarding schedular exemption from the requirements of the decommissioning planning rule (10 CFR 50.33(k) and 10 CFR 50.75).

November 9, 1989 Letter to applicant forwarding request for additional infor-mation (RAI) regarding Borg-Warner check valve swing arms, per October 26, 1989 public meeting concerning service water system check valve swing arm failure and realiability of other Borg-Warner arms installed at facility.

-Comanche Peak SSER 23 4

Appendix A

b November 10, 1989 Letter from applicant responding to NRC September 29, 1989 letter regarding allegations by previous employees.

Investi-gations of allegations revealed no supporting information.

Hardware complies with applicable requirements at plant.

November 10, 1989 Letter from applicant forwarding "1989 Accountability /

Evacuation Graded Exercise Scenario Manual" used in exercise-on October 27, 1989.

[

November 13, 1989 Letter from applicant forwarding changes to be included in future FSAR amendment regarding electrical separation between Class IE power conduits and non-Class 1E instrument control cable tray and cable.

November 15, 1989 Letter from applicant forwarding Interim Change Requests IST-R3-001:and IST-R3-002 to Revision 3 to inservice testing program plan.

Change requests clarify proposed auxiliary feedwater isolation check valve testing and cold shutdown testing.

November 17, 1989 Letter from applicant providing interim response to NRC Bul-1etin 88-08, " Thermal Stresses in Piping Connected-to RCS."

November 17, 1989 Letter from applicant providing advanced change to be in-cluded in future FSAR amendment dealing with criteria for loading cable trays above side rails.

November 21, 1989 Letter from applicant submitting a response to a request for additional information concerning the CPSES emergency organi-zation.

November 27, 1989 Letter from applicant submitting additional information re-garding fracture toughness of main' steam and feedwater sys-tem materials.

l l

November 27, 1989 Letter from applicant forwarding response to GL 89-21.

Sub-mittal concerns status of implementation of USI requirements.

November 27, 1989 Letter from applicant forwarding Revision 2 to the Offsite Dose Calculation Manual.

Revision incorporates requirement for resin sampling and radioactivity analysis, i

December 1, 1989 Letter from applicant responding to RAI regarding feedwater check valve qualification for severe loadings, per Amendment 76, Section 3.9B. 3.2 to plant FSAR.

.t I

December 6, 1989 Letter from applicant discussing deferral of preoperational testing of sampling system, primary plant ventilation, safe-guards building ventilation, auxiliary feedwater system, fuel pool cooling and cleanup system, safety injection and re-sponse time testing of main steam isolation valves.

.l l

I Comanche Peak SSER 23 5

Appendix A

I December 7, 1989 Letter from applicant forwarding response to RAI on FSAR Section 3.8 as followup from NRC structural audit at facil-ity during Septemt,er 6-7, 1989.

December 7,1989 Letter from applicant discussing increased aT for reactor vessel level instrumentation system.

Schematic cross-section of heat junction thermocouple sensor enclosed.

December 11, 1989 Letter from applicant submitting notification of the use of respiratory protective equipment per 10 CFR 20.103(g).

December 11, 1989 Letter from applicant responding to H. S. Phillips' June 21, 1989 memorandum regarding inaccurate information provided during November 9, 1989 enforcement conference regarding removal of coating from Unit I station service water system I

(EA 88-310).

1 December 11, 1989 Letter from applicant updating plant implementation of anti-cipated transient without scram mitigation systa actuation circuitry.

Final implementation of system comp,ete.

December 12, 1989 Letter from applicant responding to concerns raised by NRC during November 8, 1989 conversation with M. Fields; letter provides required affidavit per NRC Bulletin 88-11 " Pres-surizer Surge Line Thermal Stratification and Leak-Before-Break," as amended.

December 12, 1989 Letter from applicant responding to September 23, 1989 letter from Citizens Association for Sound Energy (CASE) to NRC re-questing reconsideration and reversal of January 9, 1989 i

EA-88-310 regarding station service water system coating removal activities.

December 12, 1989 Letter from applicant submitting a change notification for the process control program.

December 15, 1989 Letter to applicant requesting additional ir. formation regard-ing plant staff experience to determine if utility meets com-l mitment for hot operating experience described in March 16, 1986 letter.

Decemoer 15, 1989 Letter to applicant forwarding Federal Reaister notice of availability of supplement to NUREG-0775, "FES [ Final F.nvi--

ronmental Statement) Related to the Operation of Comanche Peak Steam Electric Station, Units 1 and 2."

December 15, 1989 Letter from applicant providing clarification of utility's July 21,1989 response to GL 89-08, " Erosion / Corrosion-Induced Pipe Wall Thinning." Erosion / corrosion monitoring program consistent with Nuclear Management and Resources Council recommendations.

Comanche Peak SSER 23 6

Appendix A

i December 15, 1989 letter from applicant requesting authorization for use of 12 I

American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code) cases listed on enclosed tables.

i December 15, 1989 Letter from applicant forwarding advance FSAR changes of Tables 6.1B-4 and 6.5.3 regarding revisions to boron concen-

)

tration of refueling water storage tank and RCS and quantity of borated water used for calculating containment sump solu-tion mixing.

December 18, 1989 Letter from applicant responding to November 20, 1989 letter j

raising concern regarding clarity of test packages for auxi-liary feedwater system noted during October 16-27, 1989 1

inspection.

December 20, 1989 Letter from applicant providing additional information re-j garding failure of Borg-Warner check valve swing arm in ser-vice water system, per November 9, 1989 RAI.

Services of APTECH procured to evaluate swing arm failure and develop i

and implement technique for judging acceptability of other swing arms.

December 21, 1989 Letter from applicant responding to GL 89-10, " Safety Related i

Motor-Operated Valve Testing and Surveillance." Schedule and recommendations delineated in GL will be met.

December 21, 1989 Letter from applicant requesting NRC issuance of decision denying CASE November 29, 1989 request for action regarding THERMO-LAG, per Joint Stipulation Paragraphs B.3-5.

December 21, 1989 Letter from applicant requesting denial of CASE December 6, 1989 rcQuest for action regarding scaling calculations.

December 21, 1989 Letter from applicant submitting a response to an RAI con-cerning the CPSES emergency organization.

December 21, 1989 Letter from applicant providing additional details related to efforts to comply with the schedular requirements of 10 CFR 50.33(k) on decommissioning.

December 28, 1989 Letter from applicant stating that testing activities for Unit 1 motor-operated valves are completed within scope of IE Bulletin 85-03.

December 29, 1989 Letter from applicant certifying that the fitness-for-duty program per 10 CFR 26 has been implemented.

December 29, 1989 Letter from applicant identifying actions required to complete the equipment qualification program (environmental and seismic).

Comanche Peak SSER 23 7

Appendix A

--~----------,..-----.,---,---_,,,-----,-,---_.-,._,..--,,._,-.-------_------.....------,--,.-....,.,.-.--- -..------.----..,- -

l l

I APPENDIX B l

BIBLIOGRAPHY NRC Bulletins and Information NoticesBulletin 88-08, " Thermal Stresses in Piping Connected to Reactor Coolant System,"

June 22, 1988; Supplement 1, June 24, 1988; Supplement 2, August 8, 1988; i

Supplement 3, April 22, 1989.

Bulletin 88-11 " Pressurizer Surge Line Thermal Stratification", December 20, 1988.

Information Notice 88-80, " Unexpected Piping Movement Attributed to Thermal Stratification," October 7, 1988.

NRC Generic letters GL 82-33, " Supplement 1 to NUREG-0737--Emergency Response Capabilities," Decem-ber 17, 1982.

GL 83-28, " Required Actions Based on Generic Implications of Salem ATWS Events,"

July 8, 1983.

GL 84-16, " Adequacy of On-Shift Operating Experience for Applicants," June 27, t

1984.

GL 86-04, " Policy Statement on Engineering Expertise On Shift", February 13, 1986.

GL 88-17, " Loss of Decay Heat Removal", October 17, 1988.

NRC Letters September 2, 1984 C. O. Thomas to T. W. Schnatz (Utility Group for Regulatory Application), " Acceptance for Referencing of Licensing Topi-cal Reports EPRI CCM-5, 'RETRAN-A Program for One Dimensional Transient Thermal Hydraulic Analysis of Complex Fluid Flow Systems,' and EPRI NP-1850-CCM, 'RETRAN-02-A Program for Transient Thermal-Hydraulic Analysis of Complex Fluid Flow Systems'."

December 17, 1985 H. Berkow to A. Landieu (Westinghouse Owners Group, SGTR Subgroup), " Acceptance for Referencing of Licensing Topical Report WCAP-10698, Supplement 1, Evaluation of Offsite Doses for a SGTR Accident."

December 22, 1986 D. C. Dilnni to D. M. Musolf (Northern States Power Company),

forwards " Safety Evaluation Granting Licensee Exemption Request to Allow Application of Leak-Before-Break Technology as Basis for Elimination of Protective Devices in Primary RCS at Plant."

Comanche Peak SSER 23 1

Appendix B.

March 30, 1987 H. 8erkow to A. Ladieu (Westinghouse Owners Group, SGTR Subgroup), " Acceptance for Referencing of License Topical Report WCAP-10698, 'SGTR Analysis Methodology to Determine the Margin to Steam Generator Overfill'," December 1984.

NRC NUREG-Series Reports NUREG-0460, " Anticipated Transients Without Scram for Light Water Reactors,"

March 1980.

NUREG-0484, " Methodology for Combining Dynamic Responses," Revision 1, May 1980.

NUREG-0660, "NRC Action Plan Developed as a Result of the TMI-2 Accident," May 1980.

NUREG-0737, " Clarification of TMI Action Plan Requirements," October 1980.

(Suppl.1, see NRC Generic Letter 82-33.)

NUREG-0800, " Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," July 1981.

NUREG-1061, Volume 3, " Report of the U.S. Nuclear Regulatory Commission Piping Review Committee, Evaluation of Potential for Pipe Breaks," November 1984.

NUREG/CR-4572, "NRC Leak-Before-Break (LBB.NRC) Analysis Method for Circum-ferentially Through-Wall Cracked Pipes Under Axial Plus Bending Loads," May 1986.

NUREG/CR-5250, " Seismic Hazard Characterization of 69 Nuclear Power Plant Sites East of the Rocky Mountains," prepared by Lawrence Livermore National Laboratory, January 1989.

Westinghouse Reports WCAP-10271, " Evaluation of Surveillance Frequencies and Out-of-Service Times for the Reactor Protection Information System," January 1983; Suppl. 1, July 1983.

I WCAP-10456, "The Effects of Thermal Aging on the Structural Integrity of Cast Stainless Steel Piping for Westinghouse Nuclear Steam Supply Systems," November 1983, Westinghouse Proprietary Class 2.

WCAP-10931, Revision 1, " Toughness Criteria for Thermally Aged Cast Stainless Steel," July 1986, Westinghouse Proprietary Class 2.

WCAP-12248 (Proprietary), " Evaluation of Thermal Stratification for the Comanche l

Peak Unit 1 Pressurization Surge Line," April 1989.

WCAP-12248, Supplement 1, " Additional Information in Support of the Evaluation-of Thermal Stratification for the Comanche Peak Unit 1 Pressurizer Surge Line,"

September 1989, Westinghouse Proprietary Class 2.

WCAP 12258, " Evaluation of Thermal Stratification for the Comanche Peak Unit 1 Residual Heat Removal Lines," April 1989, Westinghouse Proprietary Class 2..

Comanche Peak SSER 23 2

Appendix B

WCAP-12258, Supplement 2, " Evaluation of Thermal Stratification for the Comanche Peak Unit 1 Residual Heat Removal Lines," August 1989, Westinghouse Proprietary Class 2.

WCAP-12267, " Technical Bases for Eliminating Rupture of the Accumulator Injection Nozzles as a Structural Design Basis for Comanche Peak Unit 1," May 1989, Westinghouse Proprietary Class 2.

Letter from W. J. Johnson to C. H. Berlinger (NRC), " Revised Hafnium RCCA Examination Guidelines," March 30, 1989.

Miscellaneous Robert L. Cloud & Associates, "CPSES-1 WHIPJET Program Report," April 1988.

Robert L. Cloud & Associates, Report RLCA/P142/04-89/001, "CPSES-1 WHIPJET Program Report, 10-Inch Safety Injection System Accumulator Lines," May 1989.

EG&G Idaho, EGG-NTA-8341, "A Review of Reactor Trip System Availability Analyses fo.' Generic Letter 83-28, Item 4.5.3 Resolution," March 1989.

Electric Power Research Institute, Special Report No. NP-6395-0, "Probabilistic Seismic Hazard Evaluations at Nuclear Plant Sites in the Central and Eastern United States:

Resolution of Charleston Issue," April 1989.

Geometrix Consultants, Inc., "Paleoseismic History of the Meers Fault, South-western Oklahoma and Its Implications to Evauation of Earthquake Hazards in the Central and Eastern United States," San Francisco, California, August 1989.

Geometrix Consultants, Inc., letter to R. McMullen (NRC), discussing the Criner Fault regional reconnaissance, August 7, 1989.

Illuminating Engineering Society (IES), Lighting Handbook, " Applications," 1981.

International Technical Services, Inc., letter from H. Komoriya and P. B.

Abramson to A. P. Gilbert (NRC), comparing RETRAN02/ MOD 04 with RETRAN02/ MOD 02, with May 4, 1988.

Nuclear Utility Task Action Committee, " Vendor Equipment Technical Information Program Report," March 1984.

Newmark, N.M.; J. A. Blume, and K. K. Kapur," Design Response Spectra for Nuclear Power Plants," presented at American Society of Civil Engineers (ASCE) meeting in San Francisco, California, in April 1973.

Published as " Seismic Design Spectra for Nuclear Power Plants," Journal of Power Division, ASCE, Vol. 99, No. P02, pp. 287-303, November 1973.

Nuttli, O.

W., "The Mississip i Valley Earthquakes of 1811 and 1812:

Intensities, Ground Motion and Magnitudes,p' Bulletin of the Seismological Society of America, Vol. 63, pp. 227-248, 1973.

Westinghouse Owners Group, " Emergency Response Guidelines (ERG)," Revision 1A, l

July 1987.

Comanche Peak SSER 23 3

Appendix B

INDUSTRY CODES AND STANDARDS American Institute of Steel Construction, " Specification for the Design, Fabri-cation and Erection of Structural Steel for Buildings," November 1, 1978, Supplement 1, March 11, 1986.

American Society of Mechanical Engineers, Boiler and Pressure Vessel Code Section III, " Rules for Construction of Nuclear Power Plant Components";

Subsections NA-1140 (" Effective Dates of Code Editions, Addenda, and Cases),

NB-3200 (" Design Criteria"), NB-3600 (" Piping Design"), NB 3653.6 ("Simpli-fied Elastic-Plastic Discontinuity Analysis"), NF (" Component Supports").

Section XI, " Rules for Inservice Inspection of Nuclear Power Plant Components."

Institute of Electrical and Electronics Engineers, Standard 383, " Standard for Type Test of Class 1E Electric Cables, Field Splices, and Connections for Nuclear Power Generating Stations," 1974.

l l

Comanche Peak SSER 23 4

Appendix B

I i

APPENDIX D LIST OF PRINCIPAL CONTRIBUTORS Contributor Organization F. A11enspach Office of Nuclear Reactor Regulation Performance and Quality Evaluation Branch F. Ashe Office of Nuclear Reactor Regulation Comanche Peak Project Division H. Balukjian Office of Nuclear Reactor Regulation Reactor Systems Branch H. Brammer Office of Nuclear Reactor Regulation iechanical Engineering Branch K.' Desai Office of Nuclear Reactor Regulation Reactor Systems Branch R. Eckenrode Office of Nuclear Reactor Regulation Human Factors Assessment Branch M. Fields Office of Nuclear Reactor Regulation Comanche Peak Project Division S. Hou Office of Nuclear Reactor Regulation Mechanical Engineering Branch G. Hubbard Office of Nuclear Reactor Regulation TVA Projects Division J. Lee Office of Nuclear Reactor Regulation Radiation Protection Branch S. Lee Office of Nuclear Reactor Regulation Materials and Chemical Engineering Branch W. LeFave Office of Nuclear Reactor Regulation Plant Systems Branch C-Y. Li Office of Nuclear Reactor Regulation Plant Systems Branch J. Lyons Office of Nuclear Reactor Regulation Comanche Peak Project Division l-1 Comanche Peak SSER 23 1

Appendix D

Contributor Organization M. Malloy Office of Nuclear Reactor Regulation Comanche Peak Project Division B. Marcus Office of Nuclear Reactor Regulation Instrumentation and Control Systems Branch R. McMullen Office of Nuclear Regulatory Research Structural and Seismic Engineering Branch J. Moore Office of the General Counsel C. Nichols Office of Nuclear Reactor Regulation Plant Systems Branch D. Norkin Office of Nuclear Reactor Regulation Comanche Peak Project Division R. Pedersen Office of Nuclear Reactor Regulation Radiation Protection Branch R. Pelton Office of Nuclear Reactor Regulation Human Factors Assessment Branch J. Rajan Office of Nuclear Reactor Regulation Mechanical Engineering Branch F. Rinaldi Office of Nuclear Reactor Regulation Structural and Geosciences Branch D. Terao Office of Nuclear Reactor Regulation TVA Projects Division l

A. Toalston Office of Nuclear Reactor Regulation Electrical Systems Branch E. Tomlinson Office of Nuclear Reactor Regulation ProjectDirectorateIV N. Trehan Office of Nuclear Reactor Regulation Electrical Systems Branch J. Tsao Office of Nuclear Reactor Regulation Materials and Chemical Engineering Branch J. Wilson Office of Nuclear Reactor Regulation Comanche Peak Project Division F. Witt Office of Nuclear Reactor Regulation Plant Systems Branch S-L. Wu Office of Nuclear Reactor Regulation Reactor Systems Branch Comanche Peak SSER 23 2

Appendix D

APPENDIX E ERRATA TO COMANCHE PEAK SAFETY EVALUATION REPORT AND SUPPLEMENTS The following errata are applicable to the Comanche Peak SER and its supplements:

Supplement 22 Change Page 1-9, line 17 Change " August 22, 1988" to " November 28, 1988" Page 11-5, line 5 Add "and the waste monitor tank input recycle stream" after " stream" Page 11-5, line 6 Change "these" to "the condensate storage and laundry" Page 22-8, lines 8a9 Change "... January 4, 1990, the applicant committed to provide..." to read "... September 19, 1989, the appli-cant provided..."

Page 22-9, lines 3-4 Change " Amendment 76" to " Amendments 76 and 77" Page 22-9, line 4 Change "in a letter dated April 28, 1989" to "in letters dated April 28 and August 25, 1989" Comanche Peak SSER 23 1

Appendix E

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,*i NUREG-0797 2.uia ANo svenia Supplement No. 23 Safety Evaluation Report related to the operation of Comanche Peak Steam Electric Station, ff"""'"""',",',

Units 1 and 2 February 1990

4. F IN OR GR ANT NUMBE R b, Au1 HOR (Sp

6. TYPE OF REPORT regulatory

1. VL RlOD COVt R L D tinchor Vent January 1989-January 1990

e. Pt R f O,RMI.NG..D.RG.ANIZ Ah0N - N AW AND P DDnib$ fit NRC, pee O*ma. O#m W "W. VI %W*" A**'"? C8""% "#"8W '8#" # "'*""'"##

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o Division of Comanche Peak Project Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555

9. SP.ONSOR1N,G OR, GANIZATDON - N AML AND ADDR L55 ist NNC. trse '3*me m ahoe**;if to"t'w**!. Prouw knc Dawan. Otra er Me,6n. VK kumer R*euserorv Comm'euen.

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10. SUPPMMENT ARY NOTES Docket Nos. 50-445 and 50-446 H. ABST R ACi fm wore w smJ Supplement 23 to the Safety Evaluation Report related to the operation of the Comanche Peak Steam Electric Station, Units 1 and 2 (llVREG-0797), has been prepare <

by the Office of Nuclear Reactor Regulation of the U. S. Iluclear Regulatory Commission.

The facility is located in Somervell County, Texas, approximately 40 miles southwest of Fort Worth, Texas. This supplement reports the status of certain issues that had not beer resolved at the time of publication of the Safety Evaluation Report and Supplements 1, 2, 3, 4, 6, 12, 21, and 2? to that report. This supplement also includes the evaluations foi licensing items resolved since Supplement 22 was issued:

Supplement 5 has been cancelled. Supplements 7 through 11 were limited to the staff evaluation of allegations investigated by the NRC Technical Review Team.

Supplement 13 presented the staff's evaluation of the Comanche Peak Response Team (CPRT) Program Plan, which was fomulated by the applicant to resolve various construction and design issues raised by sources external to the applicant. Supplements 14 through 20 presented the staff's evaluation of the applicant's Corrective Action Program and CPRT activities.

Items identified in Supplements 7, 8, 9, 10, 11, 13, and 15 through 20 are not included in this supplement, except to the extent that they affect the applicant's Final Safety Analysis Report.

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