ML20149D628

Safety Evaluation Report Related to the Operation of Vogtle Electric Generating Plant,Units 1 and 2.Docket Nos. 50-424 and 50-425.(Georgia Power Co,Et Al)

ML20149D628
Person / Time
Site:	Vogtle
Issue date:	01/31/1988
From:	Office of Nuclear Reactor Regulation
To:
References
NUREG-1137, NUREG-1137-S07, NUREG-1137-S7, NUDOCS 8802090570
Download: ML20149D628 (94)

Text

__ . . -. -

_s .-

NUREG-1137.

Supplement No. 7 Safety Evaluation Report related to the operation of Vogtle Electric Generating Plant, Units 1 and 2 Docket Nos. 50-424 and 50-425 Georgia Power Company, et al.

UcS. Nuclear Regulatory Commission .

l Office of Nuclear Reactor Regulation January 1988

,p'"%

f .....

g

[B82 X8i@8886l@  !

m pg m . . . 1, I

. NOTICE -

. ' 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,1717 H Street, N.W. ' ,

Washington, DC 20555

2. The Superintendent of Documents; U.S. Government Printing Office, Post Office Box 37082,-

Washington, DC 20013 7082 .

~

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

Referenced documents avahable for inspection and copying for a fee from the NRC Public Docu-ment Room include NRC correspondence and internal NRC memoranda; NRC Office of Inspection and Enforcement bulletins, circulars, info'rmation notices, inspection and investigation notices; Licensee Event Reports; vendor reports and correspondence; Commission papers; and applicant and licensee documents and correspondence.

The following documents in the NUREG series are available for purchase from the GPO Sales Program: formal NRC staff and contractor reports, NRC-sponsored conference proceedings, and NRC booklets and brochures. Also available are Regulatory Guides, NRC regulations in the. Code of Federal Regulations, and Nuclear Regulatory Commission issuances.

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

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

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 Division of information Support Services, Distribution Section, U.S. Nuclear Regulatory Commission, Washington, DC 20555.

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

NUREG-1137 Supplement No. 7 l

Safety Evaluation Report related to the operation of Vogtle Electric Generating Plant, Units 1 and 2 Docket Nos. 50-424 and 50-425 Georgia Power Company, et al.

U.S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation January 1988 g"%,,

s #

4 l

ABSTRACT l In June 1985, the staff of the Nuclear Regulatory Commission issued its Safety '

Evaluation Report (NUREG-1137) regarding the application of Georgia Power Company, Municipal Electric Authority of Georgia, Oglethorpe Power Corporation, and the City of Dalton, Georgia, for licenses to operate the  !

Vogtle Electric Generating Plant, Units 1 and 2 (Docket Nos. 50-424 and 50-425). Supplement 1 to NUREG-0737 was issued by the staff in October 1985, Supplement 2 was issued in May 1986, Supplement 3 was issued in August 1986, Supplement 4 was issued in December 1986, Supplement 5 was issued in January 1987, and Supplement 6 was issued in March 1987. The facility is located in Burke County, Georgia, approximately 26 miles south-southeast of Augusta, i Georgia, and on the Savannah River.

This seventh supplement to NUREG-1137 provides recent information regarding resolution of some of the open and confirmatory items that remained unresolved following issuance of Supplement 6, and documents completion of several Unit 1 license conditions.

I l

i i

I f

Vogtle SSER 7 iii

TABLE OF CONTENTS I

Page AB,STRACT........................................................... iii 1

INTRODUCTION AND GENERAL PLANT DESCRIPTION.................... 1-1 1.1 Introduction............................................. 1-1 1.7 .0 pen Items............................................... 1-2 1.8 Confirmatory Items....................................... 1-3 1.9 License Condition Items.................................. 1-3 2 SITE CHARACTERISTICS.......................................... 2-1 2.5 Geology and Seismology................................... 2-1 2.5.4 Stability of Subsurface Materials and Foundations................................... 2-1 2.5.4.5 Instrumentation and Monitoring........... 2-1 3 DESIGN OF STRUCTURES, COMPONENTS, EQUIPMENT, AND SYSTEMS...... 3-1 3.6 Protection Against Dynamic Effects Associated With the Postulated Rupture of Piping......................... 3-1 i 3.6.1 Plant Design for Protection Against Postulated i Failures in Fluid Systems Outside Containment..... 3-1 3.6.3. Leak-Before-Break Evaluation...................... 3-2 3.8 Design of Seismic Category I Structures. . . . . . . . . . . . . . . . . . 3-10 3.8.4 Other Seismic Category I Structures............... 3-10

, 3.9 Mechanical Systems and Components........................ 3-15 3.9.3 ASME Code Class 1, 2, and S Comoonents,. Component Supports, and Core Support Structures............. 3-15 3.9.3.3 Component Supports....................... 3-15 3.9.6 Inservice Testing of Pumps and Valves............. 3-17 4 REACT 0R....................................................... 4-1 4.4 Thermal-Hydraulic 0esign...............-................. 4-1 4.4.8 Instrumentation for netection of Inade Core Cooling..........................quate ............ 4-1 Vogtle SSER 7 v

TABLE OF CONTENTS (Continued)

Page 5-1 5- REACTOR COOLANT SYSTEM........................................ 1 5-1 5.4 Component and Subsystem Design...........................

System...................... 5-1 5.4.7 Residual Heat Removal 5.4.7.5 Tests, Operational Procedures, and Support Systems....................... 5-1 6-1 6 ENGINEERED SAFETY FEATURES....................................

6.5 Engineered Safety Feature Atmosphere Cleanup 6-1 Systems..................................................

6-1 6.5.1 System Description and Evaluation.................

7-1 7 INSTRUMENTATION AND CONTR0LS..................................

7-1 7.3 Engineered Safety Features Systems.......................

7.3.3 Specific Findings................................. 7-1 7.3.3.3 Undetectable Failure in On-Line Testing Circuitry for Engineered Safeguards Relays................................... 7-1 7.5 Information Systems important to Safety.................. 7-1  ;

7.5.2 Specific Findings................................. 7-1 7.5.2.1 Emergency Response Capability--

RG 1.97, Revision 2 Requirements......... 7-1

7. 5. 7. 4 Bypass and Inoperable Status Panel....... 7-4 9-1 9 AUXILIARY SYSTEMS.............................................

9.5 Other Auxiliary Systems.................................. 9-1 9-1 9.5.1 Fire Protection...................................

9.5.1.5 Fire Detection and Suppression........... 9-1 9.5.1.6 Fire Protection of Specific Plant Areas.. 9-3 9.5.4 Emergency Diesel Engine Fuel Oil Storage and Transfer System............................... 9-4 9.5.4.2 Emergency Diesel Engine Fuel Oil Storage 9-4 and Transfer System (Specific)...........

1 Vogtle SSER 7 vi  !

TABLE OF CONTENTS (Continued) 11 RADI0 ACTIVE WASTE l

MANAGEMENT.................................. 11-1 11.4 Solid Waste Management System...........................

11-1 1 11.4.3 Evaluation Findings............................. 11-1 11.5 Process and Effluent Radiological Monitorin and Sampling Systems.......................g............. 11-2 i

i i

11.5.3 TMI-2 Action Plan Requirements.................. 11-2 !

14 INITIAL TEST PR0 GRAM.~......................................... 14-1 15 ACCIDENT ANALYSES............................................. 15-1 1

15.8 Anticipated Transients Without Scram.................... 15-1 FIGURES 3.1 Structural model of typical fuel rack......................... 3-13 l

3.2 Nonlinear seismic model of typical fuel rack.................. 3-13 i

5.1 Vogtle low pressure safety-injection system normal ECCS  !

alignment..................................................... 5-2 i

TABLES 1.4 Listing of open items......................................... 1-4

1. 5 Listing of confirmatory items....................... 1-7

1. 6 Listing of license conditions. ..................... .........

......... 1-12 3.1 Summary of Vogtle Unit 1 Inservice Testing Program, Revision 2, changes and relief requests....................... 3-19 APPENDICES l

j A

Continuation of Chronology of Radiological Review of Vogtle Units 1 and 2 Operating License Review l i

B References l

0 Acronyms and Initialisms E

NRC Staff Contributors end Consultants X Errata to Safety Evaluation Report and Its Supplements O

Letter Report, Technical Evaluation of Revision 2 Changes for Pump and Valve Inservice Testing Program,' Vogtle Electric Generating Plant, Unit 1

, Vogtle SSER 7 vil

l 1 INTRODUCTION AND GENERAL DESCRIPTION OF PLANT 1.1 Introduction l

l In June 1985, the Nuclear Regulatory Commission staff (NRC or staff) issued a Safety Evaluation Report (SER), NUREG-1137, on the application of the Georgia Power Company (hereinafter referred to as the applicant or licensee) for licenses to operate the Vogtle Electric Generating Plant, Units 1 and 2. Supplement I to NUREG-1137 was issued in October 1985, Supplement 2 was issued in May 1986, Supplement 3 was issued in August 1986, Supplement 4 was issued in December 1986, Supplement 5 was issued in January 1987, and Supplement 6 was issued in March 1987 in conjunction with the Unit 1 full power license. This document, the a seventh supplement to that SER (SSER 7), provides the staff evaluation of open and confirmatory items that have been resolved since SSER 6 was issued and docu-ments the resolution of certain Unit 1 license conditions.

In this supplement, the term "licensee" refers only to Georgia Power Company as the license holder for Unit 1, as of January 16, 1987. The term "applicant" refers to Georgia Power Company as the applicant for an operating license for Unit 1 (before January 16, 1987) and for Unit 2.

Each of the sections and appendices of this supplement is designated the same as the related portion of the SER. Each section is supplementary to and not in lieu of the discussion in the SER, unless otherwise noted. Appendix A is a con-tinuation of the chronology of this safety review and Appendix B lists refer-ence materials cited in this document.* Appendix 0 lists acronyms and initialisms used in this supplement, Appendix E lists the principal contributors, and Appen-dix K is a continuation of errata to the SER and its supplements. Appendices C, F, G, H, I, J, L, H, N, 0, P, Q, R. S, T, U, and V have not been changed by this supplement. Appendix W is new as a result of this supplement. Appendix W evaluates Revision 2 to the Unit 1 Pump and Valve Inservice Testing Program.

In addition to updating the status of unresolved items as identified in SSER 6, this supplement

)

discusses the licensee's request to decrease the frequency of settlement monitoring (see Section 2.5.4.5) discusses the applicant's request to not calculate pipe stresses for  ;

2-inch and smaller non-seismic Category I moderate energy piping for i Unit 2 (see Section 3.6.1) ,

l discusses the applicant's request to apply leak-before-break technology I to certain auxiliary lines for Unit 2 (see Section 3.6.3) discusses the Unit 2 steam generator snubber reduction (see Section 3.9.3.3)

• Availability of all material cited is described on the inside front cover of this report.

Vogtle SSER 7 1-1

discusses Revision 2 to the Unit 1 Inservice Testing Program (see Section 3.9.6 and Appendix W) discusses test and operational procedures for the residual heat removal system (see Section 5.4.7.5) discusses the deletion of the Unit 2 electrical penetration filter and exhaust system (see Section 6.5.1) discusses Technical Specifications for testing of Unit 2 slave relays (see  !

Section 7.3.3.3) l 1

discusses the Plant Safety Monitoring System Verification and Validation Program for Units 1 and 2 (see Section 7.5.2.1) discusses three fire suppression system changes for Unit 2 (see Section 9.5.1) updates the resolution of the lov power license condition regarding potential leakage outside of containment (see Section 11.5.3) discusses the licensee's request to delay certain Unit 1 inital startup tests (see Section 14)

The NRC Project Manager for the operating license review through this supplement is Melanie A. Miller. The current Project Manager is Jon B. Hopkins. Each may be reached by telephone at (301) 492-7000 or by mail at the following address:

Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 2C555 Copies of this SER supplement are available for inspection at the NRC Public Document Room, 1717 H Street N.W., Washington, D.C. 20555, and at the local ,

Public Document Room at the Burke County Library, 4th Street, Waynesboro, l Georgia 30830.

1.7 Open Items The SER identified 14 items in the staff review that had not been resolved with the applicant at the time that report was issued. SSER 1 fully resolved open items 3, 9, 10, and 12 and partially resolved open item 2. SSER 2 fully re- i solved open items 4 and 6; partially resolved open items 5, 7a, and 13; expanded I open item 7a; and identified five new open items (7c and 15 through 18). SSER 3 fully resolved open items 7b and 18; partially resolved open items 1, 5, 7a, 11, and 13; expanded open item 1; and identified four new open items (7d and 19 through 21). SSER 4 fully rosolved open items 7, 8, 11, 13, 15, 17, and 19; partially resolved open items 5 and 16; resolved open item 2 for Unit 1; par-tially resolved open item 1 for Unit 1; changed open item 20 to a license condi-tion; and identified three new open items. SSER 5 fully resolved open items 1, 21, 23, and 24; partially resolved open items 5, 14a, 14b, and 22; changed the remaining portion of open item 14a to a license condition; and changed the re-  ;

maining portion of open item 16 to a schedular exemption. SSER 6 partially

, resolved open item 14b and changed the remaining portion to a license condition.

Vogtle SSER 7 1-2 l

1 l

l l

This supplement fully resolves open item 22 for both units and partially re-solves open item 5 for both units.

The complete list of open items is reproduced in updated Table 1.4; the current I status of each item is given. For those items addressed in this supplement, the I relevant section is noted. j l

1.8 Confirmatory Items

]

The SER identified 50 items that required confirmatory information and hence were not fully resolved at the time that report was issued. SSER 1 fully i resolved confirmatory items 6, 8, 11, 20, 32, 45, 46, and 47. SSER 2 fully i resolved confirmatory items 2, 3, 5, 16, 17, 21, 31, 34, 37, 38, 44, and 50 ,

and added confirmatory item 51. SSER 3 fully resolved confirmatory items 4, j 33, 39, 41, and 51; resoived confirmatory items 18 and 23 for Unit 1 only; added items 52 and 53; and partially resolved and expanded item 14. SSER 3 ,

also changed ennfirmatory item 22 to open item 19 and confirmatory items 43, 1 48, and 49 to license conditions. SSER 4 fully resolved confirmatory items 1, 7, 9,10,12,15, 35, 42, and 53; partially resolved confirmatory ite:n 14; partially resolved confirmatory item 36 for Unit 1; resolved confirmatory items 24, 26, and 52 for Unit 1 and confirmatory item 27 for Unit 2; changed confirmatory item 19 to a license condition; and opened confirmatory items 54 (Unit 2 only) and 55. SSER 5 fully resolved confirmatory items 14 and 29; re-solved confirmatory items 25, 28, and 36 for Unit 1; and reopened confirmatory item 27 for Unit 2. SSER 6 fully resolved confirmatory item 55 and resolved confirmatory items 13 and 30 for Unit 1. This supplement fully resolves confir-matory item 27 for Unit 2.

The complete list of confirmatory items and their status is provided in updated Table 1.5. If the confirmatory item is discussed in this supplement, the section in which it is discussed is identified.

1.9 License Condition Items .

In the SER, the staff identified 11 license conditions. These issues will be cited in the operating license or Technical Specifications to ensure that NRC requirements are met during plant operation unless these conditions have sub- '

sequently been resolved. SSER 1 added license condition 12. SSER 2 added license condition 13 on fire protection. SSER 3 added license conditions 14 and 15 based on previous confirmatory items (items 43, 48, and 49) and deleted license conditions 4 and 11 because the applicant had fulfilled those require-ments by including them in the Technical Specifications. SSER 4 resolved license conditions 1, 5 (Unit 1), and 6 because the applicant had fulfilled the requirements of the license conditions. SSER 4 also added license conditions 16 through 19. SSER 5 resolved license conditions 2 (Unit 1), 3, 9, and 16; added license condition 20; and added as a license condition a schedular exemption for spent fuel pool racks. SSER 6 resolved license condition 14 and added license condition 22. This supplement discusses the licensee's compliance with license conditions 12, 17, and 21. License condition 12 will need to be in-cluded in the Unit 2 license. The issue associated with license condition 17 (zinc coating -f diesel fuel oil storage tanks) has also been resolved for Unit 2. License condition 21 applies to Unit 1 only. Table 1.6 is updated in this report to reflect these changes.

Vogtle SSER 7 1-3

Table 1.4 Listing _of open items-(revised from SSER 6)

Item Status Section*

(1) Equipment qualification (a) Seismic equipment quali- Partially resolved  !

fication and expanded (SSER 3), i resolved for Unit 1 l (SSER 4)

(b) Environmental equipment Resolved for Unit 1 qualification (SSER 5)

(c) Pump and valve opera- Partially resolved bility assurance (SSER 3), resolved for Unit 1 (SSER 4)

(i) Aging and sequence Resolved (SSER 4) of environmental conditions in main-tenance program (ii) Pumps affected by Resolved (SSER 3) static shaft analysis (iii) Onsite audit Resolved (SSER 4) t (iv) Safety injection pump Opened (SSER 3),

operation '

resolved (SSER 4)

(v) Demonstrate operability Opened (SSER 3),

of check valves resolved (SSER 4)

(vi) Uniform thread Opened (SSER 3), ,

engagement resolved (SSER 4)

(2) Preservice inspection program Partially resolved (SSER 1), resolved for Unit 1 (SSER 4)

(3) Containment sump Resolved (SSER 1)

(4) Toxic gas evaluation of chemicals Resolved (SSER 2)

(5) Generic Letter 83-28 Partially resolved 15.8 (SSERs 2, 3, 4, 5, and 7), awaiting information, and under staff review (6) Emergency response capability-- Resolved (SSER 2)

RG 1.97, Rev. 2

• Section of this supplement in which item is discussed.

Vogtle SSER 7 1-4

I

i. <

l l

! . Table 1.4 (Continued) l-Item Status Section*

(7) Fire. protection items (a) Fire doors and dampers Partially resolved (SSERs 2 and 3),

resolved (SSER 4)

(b) Power supplies for ven- Resolved (SSER 3) tilation (c) Sprinkler system Opened (SSER 2),

flushing deviation resolved (SSER 4)

(d) Fire hazards analysis Opened (SSER 3),

resolved (SSER 4)

(8) Safe and alternate shutdown Resolved (SSER 4) capability (9) Training of emergency diesel Resolved (SSER 1) generator personnel (10) Diesel fuel oil storage tank Resolved (SSER 1) cathodic protection .

(11) Licensee qualifications for Partially resolved '

operation (SSER 3), resolved (SSER 4)

(12) Retesting of simulator response Resolved (SSER 1)

(NUREG-0737, Item 1.A.2.1)

(13) Emergency preparedness Partially resolved (SSERs 2 and 3),

resolved (SSER 4)

(14) Human factors engineering items (a) Detailed control room de- Partially resolved sign review and changed to li-cense condition (SSER 5)

(b) Safety parameter display Partially resolved system (SSERs 5 and 6),

changed to license condition (SSER 6)

• Section of this supplement in which item is discussed.

Vogtle SSER 7 1-5

Table 1.4 (Continued)

Item- Status Section*

(15) Arbitrary intermediate Opened (SSER 2),

pipe break criteria resolved (SSER 4)

(16) Spent fuel pool rack design Opened (SSER 2),

partially. resolved (SSER 4), schedular exemption (SSER 5)

(17) Training program Opened (SSER 2), ,

resolved (SSER 4)

(a) Mitigating core damage (NUREG-0737, Item I.A.2.1) 1 (b) Instructor qualification and requalification l l

(c) Licensed operator training (d) Nonlicensed personnel tt-aining (e) Records of plant personnel training (18) Compliance with RG 1.94 Opened (SSER 2),

resolved (SSER 3)

(19) LOCA mitigation in Modes 3 and 4 Opened (SSER 3),

resolved (SSER 4)

(20) Alternate radwaste facility Opened (SSER 3), j changed to license '!

condition (SSER 4)  !

l (21) Physical security Opened (SSER 3),

resolved (SSER 5)

(22) Seis:nic adequacy of plastic tie Opened (SSER 4), 3.8.4 wraps partially resolved (SSER 5), resolved (SSER 7) l (23) Verification of computer codes Opened (SSER 4),  ;

used to analyze ASME components resolved (SSER 5) l (24) Multiple response spectrum Opened (SSER 4), i methodology resolved (SSER 5) l

• Section of this supplement in which item is discussed.

Vogtle SSER 7 1-6

l l Table 1.5 Listing of confirmatory items (revised from SSER 6) i I

1 j Item Status Section*

(1)~ Correlation and analysis of data Resolved (SSER 4) from old and new meteorological towers ,

(2) Upgrade of operational meteoro- Resolved (SSER 2) logical measurements program (3) Atmospheric dispersion model Resolved (SSER 2) for dose assessments (4) NSCW cooling tower seepage Resolved (SSER 3) analysis i

(5) Details of groundwater Resolved (SSER 2) i monitoring program (6) Verification of FSAR commitments Resolved (SSER 1) i on compaction of Category 1 backfill (a) Audit of compaction control records (b) Submittal and evaluation of supplemental test results (7) Submittal and' evaluation of Resolved (SSER 4) settlement records and settle-ment monitoring program (8) Foundation competency of clay Resolved (SSER 1) l marl stratum (9) Steamline break analysis out- Resolved (SSER 4) side of containment (10) Final pipewhip and jet impinge- Resolved (SSER 4) ment evaluation for high-energy PiPing (11) Design documents review Resolved (SSER 1)

(12) Compliance with NUREG-0737, Resolved (SSER 4)

Item II.D.1 (13) Program submittal for inservice Resolved for Unit 1 testing of pumps and valves (SSER 6)

• Section of this supplement in which item is discussed.

Vogtle SSER 7 1-7

1 1

l

.]

1 l a Table 1.5 (Continued) l Item Status Section" (14) Pump and valve operability as-- Partially resolved 1 surance (SSERs 3 and 4),

resolved (SSER 5)-

(a) Compliance with RG 1.148 Resolved (SSER 4)

(b) Methods'and standards for Resolved (SSER 3) 1 qualification-(c) Qualification of pump and Resolved (SSER 4) motor (d) Generic testing criteria for Resolved (SSER 4) qualifying check valves (e) Administrative control of Resolved (SSER 4) component qualification (f) Dependability of containment Resolved (SSER 5)'

isolation (purge valves)

(g) Long-term operability of Resolved (SSER 4) deep draft pumps (IE Bulletin 79-15)

(h) Issues regarding AFW Opened (SSER 3),

turbine resolved (SSER 4)

(i) Operability of the feedwater Opened (SSER 3),

check valve resolved (SSER 4)

(j) FSAR list of active pumps Opened (SSER 3),

and valves resolved (SSER 4)

(k) Preservice tests prior Opened (SSER 3),

to fuel Inad resolved (SSER 4)

('l ) Complete qualification Opened (SSER 3),

prior to fuel load resolved (SSER 4)'

(15) Compliance with NUREG-0737, Resolved (SSER 4)

Item II.F.2 (16) Conformance to 10 CFR 50, Resolved (SSER 2)

Appendix G, criteria (PORV setpoint curve)

(17) Discrepancy between WCAP-10529 Resolved (SSER 2) and FSAR (18) Examination of steam generator Resolved for Unit 1 tubes (SSER 3)

• Section of this supplement in which item is discussed.

Vogtle SSER 7 1-8 f

i Table 1.5 (Continued)'

Item . Status Section*

(19) Natural circulation boration and Changed.to license  !

cooldown tests condition (SSER 4) l (20) Target Rock valves in RVHVS- Deleted as errata (SSER 1).

(21) Containment responses following Resolved (SSER 2)' t an MSLB (22) Operator action in event of a Changed to open item small-break LOCA 19 (SSER 3) i 4

(23) Volumetric examination of Resolved for Unit 1 engineered safety features (SSER 3)  !

systems (24) Test of engineered safeguards Resolved for Unit 1 P-4 interlock (SSER 4) t 1

) (25) IE Bulletin 80-06 concerns Resolved for Unit 1 (SSER 5)

(26) Override of isolation signals Resolved for Unit 1 I (SSER 4)

)

(27) Bypass and inoperable status Resolved (SSER 4), 7.5.2.4 panel reopened (SSER 5),

resolved (SSER 7)

(28) Compliance with NUREG-0737, Resolved for Unit 1 Item II.K.3.1 (SSER 5)

. (29) Capacity of each reserve Resolved (SSER 5)

, auxiliary transformer to start and run the loads of both Class 1E trains 4

(30) Verification test results for Resolved for Unit 1

!_ the adequacy of plant electric (SSER 6)

, distribution system voltages i i (31) Coordination and testing of Resolved (SSER 2) circuit breakers located in the primary circuit of regulated transformers used as isolation devices l

• Section of this supplement in which item is discussed, j Vogtle SSER 7 1-9 1

Table 1.5 (Continued)

Item Status Section*

(32) Plant-specific procedure for Resolved (SSER 1) es;' mating core damage (NUREG-0737, Item II.B.3)

(33) Demonstrate effective commu- Resolved (SSER 3) nications (34) Offsite communications Resolved (SSER 2)

(35) Procedures for load following Resolved (SSER 4) test and/or maintenance (36) Incorporation of generic and Partially resolved plant-specific recommendations for Unit 1 (SSER 4),

for TDI diesel generators resolved for Unit 1 (SSER 5)

(37) Procedures for ordering fuel Resolved (SSER 2) after 5 days (38) Procedures for general house- Resolved (SSER 2) keeping and maintenance (39) Process control program Resolved (SSER 3)

(40) Volume reduction system (VRS) Resolved (SSER 7) 11.4.3 (a) VRS topical report (b) Potential accidents in-volving the VRS (c) VRS bputs (d) VRS filter testing (41) Compliance with NUREG-0737, Resolved (SSER 3)

Item II.K.3.31 (42) Compliance with NUREG-0737, Resolved (SSER 4)

Item II.F.1 (43) Compliance with NUREG-0737, Changed to license Item III.D.1.1 condition (SSER 3)

(44) Procedures generation package Resolved (SSER 2)

• Section of this supplement in which item is discussed.

Vogtle SSER 7 1-10

Table 1.5 (Continued) ,

Item Status Section*

(45) Program.to minimize post-LOCA Deleted as errata leakage from ESF system out- (SSER 1) side' containment (46) Analysis of dropped control Resolved (SSER 1) rod event for DNB limits t

(47) Inadvertent boron dilution Resolved (SSER 1) during Modes 3, 4, and 5 (48) Operator action in event of Changed to license an SGTR condition-(SSER 3)

(49) Radiological consequences of Changed to license an SGTR condition (SSER 3) i (50) Program to minimize ECCS Resolved (SSER 2) l

. equipment leakage

{

(51) Generic Letter 85-12 Opened (SSER 2), i resolved (SSER 3) l (52) Seismic equipment qualification Opened (SSER 3),

resolved for Unit 1 (SSER 4)

(a) Stress criteria for i emergency and faulted conditions 4

(b) Completion of seismic qualification program l

(c) Verification of as-built l loads 1 (d) FSAR revisions

, (53) Emergency preparedness Opened (SSER 3),

resolved (SSER 4)

(54) Implementation of seismic Opened (SSER 4),

separation program for Unit 2 awaiting information (55) Annunciator for high-flow signal Opened (SSER 4),

to isolate electric steam boiler resolved (SSER 6) line

• Section of this supplement in which item is discussed.

1

Vogtle SSER 7 1-11 i

, , .-- , , - = _ _ . _ . _ _ . _ _ , , _ _ _ . -

l l

Table 1.6 Listing of license conditions (revised'from SSER 6) l Item Status

• Section**

(1) Long-term groundwater and settlement Resolved (SSER 4) ,

monitoring requirements  !

(2) -Inservice testing of pumps and valves Resolved for Unit 1 (SSER 5)

(3) Final baseline report for the loose Resolved (SSER 5) parts monitoring system .

(4) Technical Specification for maximum Resolved (SSER 3) permissible temperature mismatch (5) Inservico inspection program Resolved fer Unit 1 (SSER 4) ,

(6) Operability requirements for vent Resolved (SSER 4) system in 'echnical Specifications (7) Exemption from 10 CFR 50, Appendix J, .

Paragraph III.D.2(b)(ii) i i (8) Exemption from 10 CFR 70.24 (9) Operating expesience on' shift Resolved (SSER 5)  :

(10) Implementation and maintenance of physical security plan i 3

(11) Technical Specification to require four Resolved (SSER 3) valves'to be closed during refueling (12) Reactor vessel level instrumentation Completed _for 4.4.8  ;

system implementation report Unit 1 (SSER 7)

(13) Fire protection (14) Receipt of leak rate test results Resolved (SSER b)  ;

i (15) Steam generator tube rupture 1 4

(16) Natural circulation boration and Resolved (SSER 5) l cooldown tests l (17) Replacement of zinc coating of Unit 1 Completed 9.5.4.2 '

diesel fuel oil storage tanks (SSER 7)

(18) TDI maintenance and surveillance items 4

i See footnotes at end of table.

l,

' Vogtle SSER 7 1-12 '

i l

_ ___ ,= _ . _ _ - . _, , . _ . _ .

)

i Table 1.6 (Continued)

Item Status

• Section**

l (19) Monitoring o' alternate radwaste l facility exhaust (20) Detailed control room design review (21) Schedular exemption for spent Completed 3.8.4 fuel pool racks (SSER 7)

(22) Safety parameter display system

• "Resolved" indicates resolution before licensing; thus the issue was never identified as a condition in the license; "Completed" indicates that the licensee has fulfilled the requirements of a conditon in the license.

• • Section of this supplement in which item is discussed.

l l

l i

i Vogtle SSER 7 1-13 I

i 2 SITE CHARACTERISTICS 2.5 Geology and Seismology 2.5.4 Stability of Subsurface Materials and Foundations 2.5.4.5 Instrumentation and Monitoring *  !

As stated in the Vogtle Safety Evaluation Report (SER) (NUREG-1137), the appli-cant (now licensee) monitors the settlement of safety-related structures at 60-day in't ervals. The SER further stated that monitoring should continue through completion of construction and the first year of startup of both Units

! I and 2. The SER also contemplated some addition, subtraction, and relocation '

of settlement markers during that period. After the startup operation of Unit 1, but before the startup of Unit 2, the licensee has reviewed the settlement moni- ,

toring program and propoced certain modifications to that program because of the increasingly expensive and time-consuming nature of this program caused by oper-ational . interferences and installation of security barriers as discussed in its 1 letter dated May 22, 1987. <

The main modification relates to changing the measurement frequency on 62 markers on the Unit 1 side, and six markers on the Unit 2 side from the current 60-day interval to a 6-month interval. The licensee also proposes to relocate 4'l markers on the Unit 2 side and 52 markers on the Unit 1 side to improve  !

their accessibility as described in its letters dated May 22 and August 3,1997. l Finally, the licensee wants to discontinue the monitoring of two out of three i markers that were installed in the Category I backfill in the power block area after heavy rains and erosion in 1979. l These markers were intended to monitor I

any unanticipated settlement that might occur near eroded areas.

The licensee had originally committed to monitor the settlement of Category I

( structures by reading about 175 markers at 60-day intervals throt.gh the first t l year following startup of both Units 1 and 2. Although Unit 2 is not yet i

licensed, the licensee proposes to read 62 Unit 1 markers and 6 Unit 2 markers i at 6-month intervals. The licensee has, however, justified the reduced fre-l l uency of reading the markers by referring to the time settlement plots that j show that settlement of these markers has essentially stabilized. The staff has examined tne settlement graphs submitted with the licensee's May 22, 1987, l

l letter and finds that the licensee's proposal to reduce the reading frequency

! is acceptable for all but 11 of the 68 markers.

1 The staff requires that the licensee continue reading these 11 markers at 60-day intervals because they are in or near areas in which additional loading is expected to be placed before Unit 2 is licensed for operation, as discussed ,

in the licensee's letter dated September 22, 1937. The numbers of the affected -

i markers are 126, 127, 133, 136, 162, 223, 229, 230, 234, 268, and 269. j l

• This evaluation was previously provided to Georgia Power Company by letter 4

-dated October 20, 1987. '

Vogtle SSER 7 2-1 i

, _ _ . -, - -- J

The staf f agrees with the licensee's proposal to discontinue reading two (nos.

423-1 and 423-18) of the three markers installed in 1979 in order to monitor unanticipated settlement in the backfill after heavy rains, because they are no longer needed. However, the licensee will continue to read the remaining marker (no. 423-1A) at 6-month intervals; it will also retain the two discontinued markers so that they will be available for any future reading, if needed.

The licensee's proposal to relocate 44 Unit 2 markers and 52 Unit 1 markers is acceptable to the staff on the basis that the licensee will properly correlate the new settlement readings with the readings in the previous locations and have this work checked and certified to be correct by qualified engineers as discussed in its letter dated September 22, 1987. Tne licensee has also committed not to '

l destroy or disturb the original markers so that they are available for any future correlation. In view of the large number of markers that are proposed to be velocated (96 out of the total number of about 175 markers), the staff plans to inspect these markers and audit the correlation of the new settlement readings at a future date, preferably after some of the additional loadings are imposed on Unit 2.

On the basis of a review of the licensee's submittals, the staff approves the licensee's request to change the frequency of settlement measurements from 60-day to 6-month intervals on all but 11 of the 68 markers. The staff also  ;

, approves discontinuation of the reading of markers 423-1 and 423-18 and a 6-month monitoring frequency of marker 423-1A. The staff also agrees to the relocation of 96 markers on the basis that the licensee will properly correlate the new readings with the old and have them checked by qualified engineers.

l t

L i

e 4

i I

i Voglie SSER 7 2-2 l

l

3 DESIGN OF STRUCTURES, COMPONENTS, EQUIPMENT, AND SYSTEMS 3.6 Protection Against Dynamic Effects Associated With the Postulated

?upture of Piping 3.6.1 Plant Design for Protection Against Postulated Failures in Fluid Systems Outside Containment

• In Section 3.6.1 of the SER, the staff stipulated that based on the applicant's statement that all non-seismic Category I piping systems in safety-related areas were seismically supported, only cracks rather than full ruptures needed to be assumed in those moderate energy systems for flooding analyses assumptions.

By letter dated June 1,1987, the applicant submitted a revision to the Final Safety Analysis Report (FSAR) that revised its response to FSAR Question 410.15.

In Question 410.15, the staff stated its position that for flooding analysis purposes, the complete failure of non-seismic Category,I moderate energy piping systems should be considered in lieu of cracks in determining the worst case flooding. The applicant's original response in Amendment 9 to the FSAR indicated that all non-seismic Category I piping in safety-related structures has been supported to withstand safe shutdown earthquake (SSE) loads. It was also indicated in Amendment 9 that for SSE loading, piping stresses are calculated to consider that they are maintained within faulted allowables with certain specified exceptions. Faulted allowables are the calculated piping stress limits including the SSE contribution, identified by Section III of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code, that if the stresses are not exceeded, the piping is expected to maintain its integrit The June 1, 1987, submittal revised the specified exceptions (for Unit 2 only)y.

to include moderate energy non-seismic Category I piping, 2 inches and smaller.

However, these lines will be supported to seismic Category I criteria.

The flooding analysis will continue to rostulate through-wall leakage cracks in the Unit 2 non-seismic Category I 2-inch and smaller pipes. The applicant contends that justification for postulating cracks in these small pipes in lieu of pipe ruptures is such that crack postulation satisfies the requirements of Standard Review Plan (SRP) Section 3.6.1 and Branch Technical Postion (BTP) MEB 3-1 which states that through-wall leakage cracks should be postulated in fluid system p' ping designed to non-seismic standards and through-wall leakage cracks should be postulated in moderate energy fluid system piping.

The staff agrees with the applicant regarding postulating only through-wall leakage cracks in these small lines; however, it does not agree with the justi-fication referer ced. The referenced portion of BTP MEB 3-1 which discusses cracks in moderate energy non-seismic Category I piping systems of any size is meant to ensure all types of postulated pipe failures have been considered in these pipes. In soma instances, a pipe crack may result in more damage due to

• This evaluation was previously provided to Georgia Power Company by letter dated August 14, 1987.

Vogtle SSER 7 3-1

flooding than would a complete pipe rupture of th- same pipe. This may occur in the case in which the full pipe rupture is immi.diately detectable; the leak-age from the pipe crack, however, could continue for some time before it was detected.

As stated in the :taff's SER for Vogtle, a complete failure (rupture) of non-seismic Catego;y I piping systems need not be postulated because such systems are seismically supported. Because these lines continue to be seismically supported, the staff's conclusion as set forth in Section 3.6.1 of the SER remains valid and only through-wall leakage cracks need be postulated in moderate energy piping that is not designed to seismic Category I requirements. The staff, therefore, concludes that the additional exception of not calculating pipe stresses to ensure they are maintained within faulted allowables is acceptable for 2-inches and smaller non-seismic Category I moderate energy piping, and the requirements of General Design Criterion (GDC) 4, "Environmental and Missile Design Bases," are still satisfied for Vogtle Unit 2.

3.6.3 Leak-Before-Break Evaluation By letter dated April 29, 1987, the applicant informed the staff of its inten-tion to request a partial exemption from the requirements of Appendix A to 10 CFR 50 for Vogtle Unit 2. The exemption to be requested would permit the elimination of the dynamic effects of postulated pipe ruptures in auxiliary lines from the design basis, using fracture mechanics "leak before break" (LBB) technology. The application of LBB technology would be an alternative to pro-  !

viding protective devices against the dynamic loads resulting from postulated ruptures of LBB candidate lines at Vogtle Unit 2. The LBB candidate lines at Vogtle Unit 2 are the pressurizer surge line, accumulator injection line, and residual heat removal (RHR) suction line.

By letter dated July 15, 1987, the applicant submitted the technical basis for ,

the elimination of the dynamic effects of postulated pipe ruptures in the pres- '

surizer surge line of Vogtle Unit 2 in Westinghouse report WCAP-11531. By letters dated August 19 and September 17, 1987, the applicant submitted Addenda 1 and 2 to WCAP-11531, respectively, in response to the staff's requests for additional information in letters dated August 6 and September 9, 1987. The pressurizer surge line at Vogtle Unit 2 consists of 16-inch and 14-inch-diam-eter piping connected via a reducer (see Figure 4-1 in WCAP-11531).

4 By two letters dated October 16, 1987, the applicant submitted the technical ,

bases for the elimination of the dynamic effects of postulated pipe ruptures in the accumulator and RHR lines of Vogtle Unit 2 in Westinghouse reports WCAP-11583 and WCAP-11599, respectively. The accumulator line at Vogtle Unit 2 consists of 10-inch-diameter piping between the accumulator tank and the re-actor coolant system (RCS) cold leg (see Figures 5-1 through 5-4 in WCAP-11583 i (proprietary), WCAP-11584 (non proprietary)). The RHR line within the scope of i application of LBB is the high-energy portion of the RHR line. The high-energy portion of the RHR line consists of 12-inch-diameter piping between the RCS hot leg and the first isolation valve (see Figures 5-1 and 5-2 in WCAP-11599 (pro-prietary), WCAP-11600 (non proprietary)).

4 By means of deterministic fracture mechanics analyses, the applicant contends that postulated double-ended guillotine breaks (DEGBs) of the pressurizer surge

, line, the accumulator line, and RHR piping will not occur at Vogtle Unit 2, and therefore, need not be considered as a design basis for installi~ 'otective 1

Vogtle SSER 7 3-2

devices such as pipe whip restraints and jet impingement barriers to guard against the dynamic effects associated with such postulated breaks. Nn other changes in design requirements are addressed within the scope of the referenced reports; i.e. , no changes to the definition of a loss-of-coolant accident (LOCA) nor its relationship to the regulations addressing design requirements for the emergency core cooling system (ECCS) (10 CFR 50.46), containment (GDC 16 and 50), other engineered safety features, and the conditions fer environ-mental qualification of equipment (10 CFR 50.49).

Background on Leak-Before-Break Applications l The Commission's regulations until recently required that protective measures I

be provided against the dynamic effects of postulated pipe breaks in high-energy fluid system piping. Protective measures include physical isolation from postulated pipe rupture locations if feasible, or the installation of pipe whip restr'aints, jet impingement shields, or compartments. However, recent research performed by the NRC and industry, coupled with operating experience, has indicated that safety can be decreased by the placement of protective devices such as pipe whip restraints. Studies completed by Lawrence Livermore National Laboratory under contract to the NRC indicate that safety can be decreased by requiring protective devices to resist the dynamic effects associ-sted with postulated pipe rupture. These studies are discussed in NUREG/ l CR-4263,."Reliability Analysis of Stiff Versus Flexible Piping, Final Project  !

Report," dated May 1985. The placement of pipe whip restraints degrades plant safety if thermal growth is inadvertently restricted, reduces the accessibility l

for and effectiveness of inservice inspections, increases inservice inspection i 1

radiation dosages, and increases the cost of construction and maintenance.

An alternative to providing protective devices against the dynamic loads resulting from postulated pipe ruptures is made possible by the development of advanced fracture mechanics technology. These advanced fracture mechanics techniques deal with relatively small flaws in piping components (either pos-tulated or real) and examine their behavior under various pipe loads. The objective is to demonstrate, by deterministic analyses, that the detection of small flaws by either inservice inspection or leakage monitoring systems is assured long before the flaws can grow to critical or unstable sizes which could lead to large break areas such as the DEGB or its equivalent. The con-cept underlying such analyses is referred to as LBB. There is no implication that piping failures cannot occur, but rather that improved knowledge of the failure modes of piping systems and the application of appropriate leakage detection can reduce the probability of catastrophic failure to an insignificant value.

On April 11, 1986, a final rule was published in the Federal Register (51 FR 12502), effective May 12, 1986, amending GDC 4 of Appendix A to 10 CFR 50 to allow the use of analyses to eliminate from the design basis the dynamic effects of postulated pipe ruptures of primary coolant loop piping for pres-surized water reactors (PWRs). Acceptable technical proceduras and criteria for the LBB technology are defined in NUREG-1061, Volume 3, "Report of the U.S.

Nuclear Regulatory Commission Piping Review Committee, Evaluation of Potential for Pipe Breaks," dated November 1984. This limited scope modification to GDC 4 was made by the Commission because safety and economic benefits could be quickly realized without extensive and time-consuming review and discussion if the scope was initially limited to the primary main loop piping of PWRs. Sub-stantial evidence had already been developed to show that the LBB concept was Vogtle SSER 7 3-3

valid for primary main coolant loops "f PWRs. The Commission decided not to defer the limited application of LBB technology while the detailed provisions of the proposed acceptance criteria were being reviewed and approved. Many near-term operating license (NT0L) nuclear power plant units and operating nuclear power plant units had requested and received exemptions for eliminating the dynamic effects of postulated pipe rupture from the requirements of GDC 4.

On July 23, 1986, a proposed rule was published in the Federal Register (51 F_R 26393) to further amend GDC 4 to broaden the scope to cover all high-energy piping in all nuclear power plants, l'he proposed amendment to GDC 4 allows exclusion from the design basis of dynamic effects associated with high-energy pipe rupture by application of LBB technology Only high-energy piping that meets rigorous acceptance criteria in nuclear power units is covered. High-energy piping is defined as those systems having pressures exceeding 275 psig or temperatures exceeding 200 F. The proposed general acceptance criteria are based on NUREG-1061, Volume 3.

On October 27, 1987, a final rule was published in the Federal Register (52 F3 41288), effectivs November 27, 1987, amending GDC 4 of Appendix A to 10 CFR 50.

The revised GDC 4 allows the use of analyses to eliminate from the design basis the dynamic effects of postulated pipe ruptures in high-energy piping in nu-clear power units. The new technology reflects an engineering advance which allows simultaneously an increase in safety, reduced worker radiation exposures, and loser construction and maintenance costs. Implementation permits the re-moval of pipe whip restraints and jet impingement barriers as well as other related changes in operating plants, plants under construction, and future plant designs. Containment design and emergency core cooling requirements are not influenced by this modification. The acceptable technical procedures and criteria are defined in NUREG-1061, Volume 3.

Leak-Before-Break Evaluation parameters In its review of WCAP-11531 and its addenda, WCAP-11583 and WCAP-11599, the staff evaluated the applicant's analyses and materials data with regard to:

the limiting location (s) determined by stresses in the piping, associated with the combined loads from normal operation and the SSE and the fracture toughness properties of austenitic steel piping and associated weld materials potential loss of load-bearing capacity by mechanisms such as crack formation (by fatigue or strest corrosion) or wall thinning (by erosion or erosion-corrosion) size of postulated through-wall flaws that would leak a detectable amount under normal loads and pressure 3

stability of a "leakage-size flaw" under normal plJs SSE loads and margin in terms of loid and margin based on flaw size Leak-Before-Break Evaluation Criteria

, The NRC staff's criteria for evaluation of the above parameters are delineated in NUREG-1061, Volume 3. These criteria are identical to those accepted in the

! Vogtle SSER 7 3-4

limited scope and broad scope modifications of GDC 4. These criteria are listed in Chapter 5.0 of NUREG-1061, Volume 3 and are as follows:

(1) The loading conditions should include the static forces and moments (pressure, deadweight, and thermal expansion) due to normal operation, and the forces and moments associated with SSE. These forces and moments and the base metal and weld tensile and toughness properites are to be used to define the locations that have the smallest margins against pipe rupture in the pipe run (anchor to anchor).

(2) For the piping run/ systems under evaluation, all pertinent information should be provided which demonstrates that degradation or failure of the piping resulting from creep, corrosion, erosion-corrosion, stress-corrosion, fatigue, waterhammer, or other environmental conditions is not likely.

Relevant operating history should be cited, which includes system operational procedures; system or component modification; water chemistry parameters, limits, and control; and resistance of material to various forms of stress corrosion and performance under cyclic loadings.

(3) Pipe lines are evaluated to determine whether there is a high probability of degradation or failure from indirect causes such as fires, missiles, and equipment failures, and failures of systems or components in close proximity to the pipe.

(4) 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; long-term effects such as thermal aging; and other limitations to valid data (e.g.,

J maximum and maximum crack growth). The piping materials must be free from brittle cleavage-type failure over the full range of the system operating temperature.

(5) A through-wall flaw should be postulated at the limiting locations determined from criterion (1) above. The size of the flaw should be large enough so that detection of leakage is assured using the installed leak-detection capability when the pipe is subjected to normal opera-tional loads. NUREG-1061, Volume 3 recommends the margin on the magni-tude of leakage to be no less than a factor of 10 greater than the capability of the leakage detection system.

(6) It should be demonstrated that the postulated leakage flaw is stable under normal plus SSE loads for long periods of time; that is, crack growth, if any, is minimal.

The margin, in terms of applied loads, should be deter-mined by a flaw stability analysis, i.e., that the leakage-size flaw will not experience unstable crack growth even if larger loads (larger than design loads) are applied. This analysis should demonstrate that crack growth is stable and the final flaw size is limited that a double-ended pipe break will not occur.

(7) The stability analysis should compare 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.

Vogtle SSER 7 3-5

Staff Evaluation The staff had evaluated the information pre;ented in the submitted topical reports. The staff finds that the applicant has presented an acceptable tech-nical justification to eliminate, as a design basis, the dynamic effects of large ruptures in the pressurizer surge line and the accumulator and RHR pip-ing of Vogtle Unit 2.

(1) Loads and Load Combinations Normal operating loads, including pressure, deadweight, and thermal expansion, were used to determine leak rate and leakage-size flaws. The stability anal-yses performed to assess margin against pipe rupture at postulated faulted load  !

conditions were based on normal plus SSE loads.

In the leak rate' analysis, the individual normal (pressure, deadweight, and thermal expansion) load components were summed algebraically. In the stability analysis of the accumulator line, the individual normal and seismic (pressure, deadweight, thern.al, and SSE including seismic anchor motion) loads were summed absolutely. In the stability analysis of the pressurizer surge line and the RHR line, the individual normal (pressure, deadweight, and thermal expansion) load components were summed algebraically and the seismic (SSE including seis-mic anchor motion) loads were then added absolutely. The bending moments in the two principal coordinate directions and the total axial force were ob-tained. Then, the resultant bending moment was obtained from the square root of the sum of the squares of the principal coordinate moments.

Leak-before-break evaluations were performed for the limiting location within each of the lines between anchor points. The limiting location was determined

, using the recommendations in NUREG-1061, Volume 3, and is the location pre-dicted to have the smallest margin against pipe rupture based on the material resistance to ductile flaw instability under the combined normal plus SSE loads.

On the basis of its review, the staff finds that the load definition, method of load combination, and the location for which the LBB evaluations was performed are consistent with the recommendations in NUREG-1061, Volume 3, and provide a basis acceptable to the staff for LBB evaluation at Vogtle Unit 2.

(2) Pipe Degradation Mechanisms The applicant assessed each line to determine if there is significant potential for degradation of piping integrity during service. The degradation mechanisms evaluated were: intergranular stress corrosi.on cracking (IGSCC) of austenitic steel, potential for dynamic loads (e.g. , waterhammer), vibratory

fatigue, low-cycle thermal fatigue due to flow stratification, thermal aging effects on austenitic steel, wall thinning from erosion, creep damage, and fatigue from design transients.

1

, For Westinghouse facilities, there is no history of service cracking or wall thinning in the reactor coolant system primary loop and connecting Class 1 lines. This operating history totals more than 400 reactor years, including i five plants each having more than 15 years of operation and 15 other plants each with more than 10 years of operation. Also, evaluation of the plant-specific design, fluid, and operating conditions indicates: (a) IGSCC in Vogtle SSER 7 3-6

l austenitic steel is not likely because the lines were constructed usir,g tech-niques that produce an acceptable level of resistance to IGSCC, the fluid chemistry will be controlled during operation to minimize contaminants, and the dissolved oxygen is at a level that would normally preclude IGSCC; (b) water-hammer is unlikely because of appropriate design and operating procedures; (c) l crack initiation from viuratory fatigue is unlikely because there are no '

identified vibration sources and there are no socket welds, which may act as crack initiators, in the lines; (d) there is little temperature difference, which minimizes flow stratification and associated low-cycle thermal fatigue; (e) degradation of austenitic steel from thermal aging is not likely because there is no cast pipe or fitting in the lines, except for a cast stainless i

! steel nozzle on the accumulator line for which degradation from thermal aging  !

! was accounted for in the evaluation; (f) fluid conditions and use of erosion-resistant materials in the lines preclude the likelihood of wall thinning by erosion; and (g) the relatively low temperatures (less than 650 F) of the lines preclude any significant creep damage.

An assessment was also made to predict the inservice flaw growth in the lines from anticipated and postulated transient loads. The initial flaw size was determined from the Section XI (ASME Code) preservice acceptance standards and was assumed to be present in the evaluated lines before service. The tran-sients, stress and fracture mechanics analysis methods, a.nd the material crack-growth rel.ationship used in the fatigue crack growth evaluation were reviewed and accepted by the staff. The results indicate that the postulated flaw in each of the lines would remain within the end-of-design-life size criteria established by the staff.

On the basis of comparison of the design, material, operational, and fluid conditions anticipated for the pressurizer surge line, the accumulator line, and the RHR piping at Vogtle Unit 2 with prior service experience and conditions that may produce degradation in nuclear piping, the staff concludes that inser-vice cracking and significant degradation are unlikely. Consequently, the staff concludes that LBB analysis is an appropriate basis to demonstrate that the probability of pipe rupture for these lines is acceptably low and to jus-tify not installing protective devices against the dynamic effects of postulated pipe breaks in these lines.

(3) Indirect Sources of Pipe Rupture Pipe degradation or failure from indirect causes such as fires, missiles, and component support failure is prevented by designing, fabricating, and inspec-ting reactor compartments, components, and supports to staff criteria that reduce to a low probability the likelihood of the events or their inpacting safety-related components. The applicant's compliance with the criteria in the Standard Review Plan is discussed in the Vogtle FSAR, Sections 3.4.1 (flood protection), 3.5 (missile protection), 9.5.1 (fire protection), 3.9.B.3 and 5.4 (design and fabrication requirements), 5.2.4 (inservice inspection and j testing), and 17.1.14 and 17.2.10 (general inspection). '

(4) Materials Data The pressurizer surge line at Vogtle Unit 2 was constructed of SA-376 TP316 wrought austenitic steel. There is no cast pipe or fitting in the surgo line system. The accumulator line at Vogtle Unit 2 was constructed of SA-376 TP316 i Vogtle SSER 7 3-7

wrought austenitic steel. The accumulator line nozzle at the RCS cold leg was constructed of SA-351 CF8A cast stainless steel. The RHR line was constructed of SA-376 TP316 wrought austenitic steel. There is no cast pipe or fitting in the RHR line. The welding processes used for the three lines were gas tungsten arc weld (GTAW), submerged arc weld (SAW), and shielded metal arc weld (SMAW).

The plant-specific materials data were obtained from the certified material test reports (CMTRs) for the three lines at Vogtle Unit 2. The limiting loca-tions for the accumulator line are at welds fabricated with the SAW process.

The limiting conditions for the pressurizer surge line and RHR line are at welds f abricated with the SMAW process. The accumulator line cast stainless steel nozzle was also considered. Because the limiting locations for LBB analyses are welds in the base materials from evaluations based on item 1 of this section, "Loads and Load Combinations," the applicant estimated the elastic moduli and stress-strain relationships for the base materials and the fracture toughness properties of welds required for the LBB analyses.

For the three lines, the applicant selected the minimum room temperature yield strength from the CMTRs and then estimated the yield strength at the operating temperature based on typical yield struigth versus temperature data. Then, the elastic moduli and stress-strain relationships for the base materials were estimated based on generic procedures. For the fracture toughness properties of welds, the applicant selected J-R curves from the literature. However, the applicant provided insufficient justification that the selected weld J-R curves were lower-bound estimates for Vogtle Unit 2 welds. Furthermore, the applicant used a "modified J" parameter to describe the weld J-R curve. The staff con-siders the "modified J" not acceptable for licensing applications without further research. The staff's requests for additional information dated August 6 and September 9, 1987 discuss this issue.

For the fracture toughness properties of thermally aged, cast stainless steel, the applicant used estimation procedures described in Westinghouse reports WCAP-10456 and WCAP-10931, Revision 1, which have been reviewed previously by the staff as discussed in letters from B. J. Youngblood, NRC, to M. D. Spence, Texas Utilities Generating Company, dated August 28, 1984 and from D. C. Dilanni, NRC, to D. M. Musolf, Northern States Power Company, dated December 22, 1986, respectively.

The staff finds that the applicant's procedures in estimating the plant-specific, lower-bound, base metal, stress-strain relationship acceptable for the LBB flaw stability analysis, Also, the staff finds the applicant's use of the average, base metal, stress-strain relationship in the LBB leak rate analy-sis appropriate in obtaining realistic estimates of leakage-size flaws. Although the applicant provided inadequate lower-bound weld toughness properties, the applicant also performed flaw stability analyses using a procedure that is based on industry lower-bound weld toughness properties (see item 6 below, "Margins on Load and Flaw Size").

(5) Leak Rate Criteria and Computations The three lines at Vogtle Unit 2 are inside the containment. The applicant has proposed a leakage detection criterion that includes a detected leak rate of 1 gallon per minute (gpm) and, in accordance with the recommendation in Vogtle SSER 7 3-8

NUREG-1061, Volume 3, a margin of 10 was applied to this leak rate to define the leakage-size flaw used in the fracture stability analyses. The basis for the 1 gpm leak is the presence inside containment of diverse and redundant leakage-detection equipment and methods that are in compliance with Regulatory Guide (RG) 1.45, and operating experience at other Westinghouse plants.

Detected leaks will be repaired within the system limiting conditions for l'

operation established in either Technical Specifications or administrative procedures. When leakage is detected in reactor coolant pressure boundary piping, Technical Specification 3.4.6.2 requires that the plant be in hot standby within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown within the next 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Repairs would be required before restart.

The relationship between the flaw size and leak rate was estimated using com-puter software that includes an elastic plastic fracture mechanics routine for determining crack opening area and a thermal hydraulics routine to compute mass flow through the postulated through-wall flaw. In Supplement 4 to NUREG-0781, "Safety Evaluation Report Related to the Operation of South Texas Project, Units 1 and 2," dated July 1987, the staff concluded that the software used to estimate leak rate is acceptable for application to LBB analysis when used with the appropriate margin on predicted leak rate.

(6) Margins on Load and Flaw Size The applicant has performed stability analyses to determine if the leakage-size flaw is stable at 1.4 times the combination of normal plus SSE loads and if the critical-size flaw at normal plus SSE loads is at least twice as long as the leakage-size flaw. The stability analyses were performed using elastic plastic, fracture-mechanics analysis methods, the load combination method described in item 1 of this section ("Loads and Load Combinations"), the lower-bound stress-strain relationship discussed in item 4 of this section ("Materials Data"), and the leakage-size flaw determined for each line using the leak detection crite-rion in item 5 of this section ("Leak Rate Criteria and Computations"). The elastic plastic, fracture-mechanics analyses were performed using a tearing modulus (J-T) methodology based on procedures which were benchmarked and found accaptable by the staff in NUREG-1061, Volume 3.

The applicant performed a J-T analysis using thermally aged, cast stainless .

steel toughness properties in WCAP-10456 and WCAP-10931, Revision 1 to demon-strate the flaw stability of the accumulator line nozzle at the RCS cold leg.

The results showed that there is a margin of at least 1.4 on the normal plus SSE loads for the leakage-size flaw and a margin of at least 2 between the critical through-wall flaw size and the leakage-size flaw. The staff used an elastic plastic, fracture-mechanics, computer code developed by the staff 4 (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) to verify the applicant's results and to ensure that the staff's upper bound on the applied J for a specific cast stainless steel was not exceeded, as discussed in the staff's letter to Texas Utilities Generating  !

I Company, dated August 28, 1984.

Flaw stability analyses were performed for the material conditions using the base metal, stress-strain relationship and the limiting weld, fracture tough-ness relationship. As discussed in item 4 of this section ("Materials Data"),

the applicant provided inadequate lower-bound weld toughness properties for I

Vogtle SSER 7 3-9

l flaw stability evaluations. However, based on staff recommendations, the app-licant also performed flaw stability analyses using a limit load analysis pro-cedure, which has been modified by J-T analyses based on industry, lower-bound, weld-toughness properties. This modified limit load, flaw stability analysis uses the "Z-factor" correction for flux welds, which is the basis for develop-ing allowable flaw sizes for austenitic steel piping in Article IWB-3640 of the Winter 1985 Addendum of Section XI of the ASME Code (Electric Power Research Institute Special Report NP-4690-SR, "Evaluation of Flaws in Austenitic Steel Piping," prepared by Section XI Task Group for Piping Flaw Evaluation, July 1986).

The applicant's results from the flaw stability analyses using the "Z-factor" showed that at the limiting locations of the lines, a margin against pipe rupture of at least 1.4 exists on the normal plus SSE loads for the leakage-size flaw, and the critical through-wall flaw size at normal plus SSE loads is at least twice the length of the leakage-size flaw. The staff verified the applicant's results and finds that the applicant has demonstrated margins on load and flaw size consistent with the recommendations in NUREG-1061, Volume 3.

Staff Conclusions On the basis of its review of the information submitted by the applicant, the staff finds the pressurizer surge, the accumulator, and the RHR lines at Vogtle Unit 2 in compliance with the revised GOC 4. Thus, the dynamic effects of postulated pipe ruptures in the pressurizer surge, accumulator, and RHR lines may be eliminated from the design basis of Vogtle Unit 2. Because the final rule became effective November 27, 1987, it is not necessary for the applicant to request an exemption from GDC 4.

3.8 Design of Seismic Category I Structures 3.8.4 Other S ismic Category I Structures

• Tie Wraps in Vertical Cable Trays In SER Supplement 4 (SSER 4), the staff identified an open item regarding the seismic adequacy of plastic cable ties used to support seismic Class 1E cables in vertical cable trays. The issues involved load capacity of the plastic cable ties and the effects of aging, embrittlement, plastic creep, etc. on the struc-tural behavior of the ties over the life of the facility. By letter dated December 22, 1986, the applicant (now licensee) provided justification for the use of plastic cable ties during the first fuel cycle and committed to address the long-term effects of plastic cable ties by June 1, 1987. The staff partially resolved this issue in SSER 5 by concluding, based on the licensee's December 22, 1986, submittal, that the use of plastic cable ties to support Class 1E cables in vertical raceways was acceptable for the first fuel cycle. However, the adequacy of the plastic cable ties for the period beyond the first fuel cycle was considered confirmatory pending staff review of the program to address long-term effects of the plastic ties.

By letter dated May 27, 1987, the licensee responded to the remaining issue regarding long-term effects. In its May 27, 1987, response, the licensee com-mitted to use stainless steel cable ties to support cables in vertical cable

• This evaluation was previously provided to Georgia Power Company by letter dated July 30, 1987.

Vogtle SSER 7 3-10

trays. The stainless steel ties to be used at Vogtle Units 1 and 2 are fabri-cated from American Iron and Steel Institute (AISI) Type 302/304 steel which has superior corrosion resistance and mechanical properties at elevated tempera-tures. This material will not experience plastic creep, embrittlement, or re-duction in structural strength as a result of aging or environmental conditions as might the plastic ties. The licensee has conducted static pull tests on the stainless steel ties to establish the load capacity of the tie. The test methad l used to establish the load capacity of cable ties for various configurations of cable bundles was previously reviewed and accepted by the staff in SSER 5. The data from these tests, together with seismic and dead loads for the cables. and cable tie spacings were used to maintain a minimum safety factor of 1.3. The safety factor of 1.3 was accepted by the staff in SSER 5.

On the basis of the licensee's May 27, 1987, submittal, the staff concludes that with the~use of stainless steel cable ties to support seismic Class IE cables in vertical cable trays, the integrity of the cables will be assured over the life of the facility. The staff further concludes that the requirements of GDC 2 of Appendix A to 10 CFR 50 are satisfied by the use of the stainless steel tie wraps. These ties will be installed in Unit 1 before restart after the first refueling outage and will be installed in Unit 2 before fuel load.

Therefore, open item 22 is fully resolved for both units.

Spent Fuel Pool Racks

• By Amendment 22 to the FSAR, the applicant (now licensee) indicated that a different spent fuel rack design would be used at Vogtle Unit 1. The appli-cant proposed to replace the original Unit 1 spent fuel pool racks having 938 fuel assembly storage locations on a center-to-center spacing of 13.0 inches with two new high-density freestanding racks having 283 fuel assembly storage locations, or approximately 1.43 cores. Each rack consists of 144 fuel assem-bly cells arranged in a 12-by-12 configuration, with a center-to-center spacing of 10.6 inches between fuel assemblies. Additional fuel racks with different configurations may be added to the Unit 1 spent fuel pool in the future. Any additions would have to be approved by the staff.

In SSER 2, the staff noted that the spent fuel storage facility would be an open item until the applicant provided more detailed design information. In particular, the staff stated that the applicant would have to provide the de-tails of the rack design, including a criticality analysis, seismic analysis, materials compatibility analysis, and fuel handling accident analysis.

The applicant provided most of the requested information in Amendment 5 to the FSAR; this allowed the staff to resolve all issues regarding the design of the racks except for the seismic analysis in SSER 4. By letter dated November 28, 1986, the staff requested that the applicant provide additional information regarding the seismic analysis of the racks. By letter dated December 29, 1986, the applicant requested a schedular exemption to regulations that apply to spent fuel pool racks. In SSER 5, the staff determined that pursuant to 10 CFR 50.12(a)(1), the schedular exemption to 10 CFR 50.34(b)(2)i as it pertains to GDC 2, 61, and 62 of Appendix A to 10 CFR 50 is authorized by law, will not present an undue risk to the public health and safety, and is consistent with the common defense and security. Accordingly, this schedular exemption was

• This evaluation was previously provided to Georgia Power Company by letter dated July 30, 1987.

Vogtle SSER 7 3-11

a- included in Vogtle Unit 1 license nos. NPF-61 dated January 16, 1987, and NPF-68 dated March 16, 1987 (low power and full power, respectively) for the time period before the racks contain irradiated fuel.

) The licensee responded to the staff's November 28, 1986, request for additional i information by letter dated January 21, 1987. On the basis of the staff's re-view of this submittal, the staff requested additional information by letter -

dated April 7, 1987. The licensee responded to this request by letter dated  !

May 22, 1987, as supplemented by letter dated July 20, 1987. The licensee I further provided the spent fuel rack design report by letter dated September 29, 1987. The discussion that follows is the staff's evaluation of the licensee's ~

submittals dated January 21, May 22, July 20, and September 29, 1987.

The spent f el pool is constructed of reinforced concrete and lined with 1/4-inch stainless steel to ensure against leakage. The spent fuel pool is located within the seismic Category I fuel handling building. The pool is.approximately 50 feet long, 33.5 feet wide, and 41 feet deep.

~

The spent fuel will be stored in two high-density racks. Each rack consists of 144 fuel assembly cells arranged in a 12-by-12 configuration. The cell is made from 14 gauge (0.075-inch-thick) type 304 stainless steel. The nominal inside dimension of the cell is 8.8 inches square, and the length from the top of the fuel seating surface to the top of the cell funnel is approximately 168.25 inches.

> Storage cells are fastened and supported by two grid assemblies, also made from type 304 stainless steel, which are located at the top and bottom elevations of the racks. The racks are assembled in a checkerboard pattern with a 10.6-inch l center-to-center spacing. The racks are free standing, neither anchored to the f floor nor braced to the pool wall. Because the racks rest freely on the pool floor, it is necessary to determine that during seismic events the racks do not impact each other nor the walls, and are capable of maintaining their integrity.

Thus, displacement and stress calculations of the racks are required. Analyses of the racks were performed on the Westinghouse Electric Computer Analysis (WECAN) Code. It is a general purpose finite element code with capabilities of performing static, dynamic, linear, and nonlinear analyses. The WECAN Code has been audited and no errors or discrepancies were found by the NRC Vendor Program Branch as discuued in a report from G. Zech to J. Gallagher (Westing-house) dated January 7, 1985.

Effective structural properties of an average fuel cell within the rack assembly were obtained using a three-dimensional linear structural model that represents the rack assembly. The ma19ematical model is shown in Figure 3.1. These struc-tural properties were then used in a two-dimensional nonlinear seismic mode to perform seismic calculations. The mathematical model is shown in Figure 3.2.

Hydrodynamic mass of the fuel, the gap between the fuel and cell, the support pad boundary condition of the freestanding rack, and the assumed coefficient of friction between the support pad and pool floor were input to the WECAN Code in i addition to the structural properties. A coefficient of friction equal to 0.2 i

was assumed to obtain the maximum sliding distance of the base of a rack, A '

coefficient of friction equal to 0.8 was assumed to obtain the maximum load in the rack and maximum structural deflection of the rack. On the basis of experi-mental test data on water-lubricated stainless steels, E. Rabinowicz concluded i in "Friction Coefficients of Water-Lubricated Stainless Steels for a Spent Fuel Rack Facility," dated November 5, 1976, that a design based on friction coeffi-cient values between 0.2 and 0.8 should cover all eventualities. Therefore, the range of coefficients of friction between 0.2 and 0.8 used by the licensee Vogtle SSER 7 3-12 1

l l

l l

/  % TOP CELL TO- f i

,/ \,

's s

s

-5 s'/ CELL WELD ,

i l  %

I d q-.

.rE , ['] . 1

-t , , ,

.n *l- --

-#E ' '

. a-5 3

,- =

_ CELL TO4 ELL

% WELD

,, t-. _

1. E

_, .a.E

, {lb l %

4 8

l -. _

,,# E

s,

- i-I i .. . l g

.p ' l ==

', _ t

• -d' i 1M IMg ' -3 -

BASE PLATE 1 i

sTaucTunt l

Figure 3.1 Structural model of typical fuel rack {

i CELL Amanue(y

~ ~ ' x e. r2W' e Vj: L,!, i i

_ _L- 1 .

NEC f N.uu. vu -- _- - L,.1,

r. ,

<- b mW /

'/

O w -

's l

.u.a.mau.,

i- b A%' '

f

<- & 4'-- /

,,-- & cq' /

mm

& 4'.. /

/

, D. 4, ->

.t b W . /

O b

Figure 3.2 Nonlinear seismic model of typical fuel rack Vogtle SSER 7 3-13

i i

is reasonable. The maximum loads thus obtained were then' input to a three-dimensional structural model to obtain local stresses in the rack.

The licensee indicated that the maximum single rack sliding displacement was 0.036 inch, and the aaximum lateral deflection at the top of the rack was 0.1

. inch. Because the alearance between the two racks is approximately 4 inches and the minimum clearance between the racks and pool walls is 4.25 inches, it is apparent that the racks will not impact each other and the walls, because the actual clearances between the rack-to-rack and rack-to-wall are much greater than the distance due to rack sliding or deflection calculated for the safe shutdown earthquake (SSE) condition.

The licensee has provided analysis results of stresses due to the interactions j between the rack and pool floor and between the fuel and cell within a rack for '

both cperating basis earthquake (OBE) and SSE conditions. The results indicated that the maximum stresses in the liner plate and concrete floor are less than allowable stress values for the rack and pool floor interaction and that the maximum acceleration on the fuel assembly was 3.0 g. In response to the staff request as to what g levels the fuel assembly had been qualified for, the ,

licensee stated in the submittal of July 20, 1987, that the actual maximum. test )

j load was 20 g. Therefore, the integrity of the fuel assembly will be maintained j during earthquakes.

i

' The licensee has calculated the maximum thermal stress in the rack as 4000 psi  :

by assuming that one cell was loaded with hot fuel while the surrounding cells remained empty. When this maximum thermal stress combined with stresses assoc- i-iated with seismic and dead weight, the licensee stated that the total stress  !

was still below the allowable stress value. Therefore, the integrity of the t j rack will be maintained during thermal and' seismic conditions. During a July 15, t*

1987, telephone conference call, the staff questioned the validity of using 25%

of critical damping for the fuel grid and asked for documentation. The lit:ensee i responded in the July 20, 1987, submittal that the grid damping value of 2E%

had been developed from data presented in Westinghouse document WCAP-9401-P-A, ,

which was approved by the staff by letter dated May 7, 1981. The staff considers  !

l that the damping question has been answered and resolved. f; The licensee has also performed an analysis of dropping a fuel assembly straight through a storage location, and the results indicated that the pool liner would

• not be perforated. The licensee did not perform the first and second types of

fuel assembly accident analyses as specified in the NRC position paper, "Opere.ti90 i Technology Position for Review and Acceptance of Spent Fuel Storage and Har# ing

Applications," dated April 14, 1978, as modified on January 18, 1979. HowCVPr, j

the licensee stated that, with the 2000 ppm boron in the pool water, there would i 3

be no deformation that could reasonably be achieved by the drop of a fuel assembly that would cause the criticality acceptance criterion of 0.95 to be '

exceeded. The staff has reviewed this issue and agrees with the licensee.

l l Therefore, the staff considers that the licensee has adequately addressed the  !

fuel assembly accident analysis requirements.  !

The licensee stated that the cask crane was designed in such a way that it i could not pass over the spent fuel pools and, therefore, this would preclude l the movement of heavy loads over the spent fuel pools. The staff considers that this design is acceptable. l 1 l

! Vogtle SSER 7 3-14 I l

4  !'

The licensee stated that the metho'd ology used for the Vogtle Unit 1 spent fuel pool analysis is the same as that which had been used for McGuire, Turkey Point,  ;

Peach Dottom, and Palisades and that the models used in the analysis are similar i to those that had been used for these four plants, and that the methodology and l model had been reviewed and found acceptable by the staff for the referenced  !

plants. On October 8 and 9, 1986, the staff performed an audit at the Westing-house, Pensacola, Florida facility for the spent fuel rack design of Palisades  ;

and was satisfied with the general methodology and mathematical models used in  !

the analysis. The staff approval of the general methodology and analysis models l l was documented in the Palisades SER included in the issuance of Amendment 105,  ;

dated July 24, 1987 (Wambach, 1987; Zech, 1985). +

i l On the basis of the review of the licensee's submittals, the staff has concluded that the licensee has adequately and satisfactorily addressed all the issues related to the seismic adequacy of the spent fuel pool rack design at Vogtle Unit 1.

l- The to'.al weight of 288 spent fuel assemblies, as currently proposed, is less than the total weight of 938 spent fuel assemblies, which was previously licensed. Therefore, the capability of the spent fuel pool structure, which j has been designed and licensed for supporting 938 spent fuel assemblies, is i more than adequate for supporting 288 spent fuel assemblies. The capability of  :

the spent fuel pool structure should be reanalyzed when the total weight of {

] spent. fuel assemblies and racks exceeds the total weight of its previous design.

On the basis of the staff's acceptance of the spent fuel pool rack design sub- i mitted by the licensee, the staff has concluded that the schedular exemption ,

, included in the Unit 1 full power license is no longer required. l

[ 3.9 Mechanical Systems and Components i

3.9.3 ASME Code Class 1, 2, and 3 Components, Component Supports, and Core l Support Structures 3.9.3.3 Component Supports

• 4 i By letters dated July 1 and A ;ust 6, 1987, the applicant submitted a discussion of a proposed rdesign of the steam generator upper support of the reactor

. coolant loop system for Vogtle Unit 2. The applicant enclosed an evaluation to l verify the adequacy of the redesign and a proposed revision of the FSAR.

l The support redesign and FSAR revision will permit Vogtle Unit 2 to reduce the l number of large hydraulic snubbers in the steam generator support systems from J

five to two for all four steam generators. The technical basis for the FSAR

) revision is the use of the "leak-before-break" principle which would eliminate

the dynamP effects of postulated pipe ruptures from the primary piping design

! basis. The evaluation showed that the configuration of the redesign will be

able to withstand all remaining loadings, including those caused by the safe

! shutdown earthquake and the limiting high-energy-line breaks at branch nozzles.

i Specifically, the evaluation indicated that stresses in the reactor coolant

] loop piping are within the FSAR allowables with adequate margins of safety.

I l I

i *This evaluation was previously provided to Georgia Power Company by letter  !

) dated October 7, 1987. l

[ i j Vogtle 55ER 7 3-15 I l

-- .-_I

The Vogtle Unit 2 reactor coolant system consists of four reactor coolant loops (RCLs) with one steam generator per loop. An identical design was used for the supporting system of all four steam generators. The upper support is an octagonal ring girder with curved bearing surfaces placed around the steam generator shell and hung from the steam generator trunnions by four tie rods.

These tie rods support the dead weight of the ring assembly and position the ring girder vertically. Three rigid struts carrying loads from the steam generator through the ring girder are anchored to the secondary shield wall to restrict the movement of the steam generator. One strut is located on each of the three sides of the steam generator not facing the reactor. Five hydraulic snubbers located parallel to the hot leg are connected to the ring girder on the reactor side of the steam generator. The snubbers will permit the unrestrained thermal loop movement to the final hot operating position. The

~

proposed redesign effort is limited to the upper support and will reduce the i number of snubbers from five to two in each support.

In Volume 3, "Guillotine Break Indirectly Induced by Earthquakes," of NUREG/CR-3660, "Probability of Pipe Failure in Reactor Coolant Loops of l Westinghouse PWR Plants," the Lawrence Livermore National Laboratory performed an independent review on Westinghouse topical reports WCAP-10551 and WCAP-10552.

The results indicated that the design and construction practices used in 1 Westinghouse PWR plants will not significantly affect the probability of a double-ended guillotine break; thus the elimination of large primary loop pipe rupture as a structural design for Westinghouse PWRs can be permitted. This l l

change results in a reduced loading level, which in turn, requires less upper support rigidity for dynamic events considered in the plant design.

L Loadings considered in the redesign are those caused by deadweight, internal '

pressure, thermal movement, seismic events (operating basis earthquake and safe shutdown earthquake), and postulated pipe ruptures at nozzles.

The staff's evaluation of the RCL leak-before-break analysis for the original support configuration is attached to the staff's exemption to GDC 4 for Vogtle, dated February 5, 1985. A comparison has been made between the original loads and the revised loads from the steam generator upper lateral support redesign.

On the basis of this comparison, it was verified that the staff's original conclusions regarding the RCL leak-before-break analysis remain valid.

2 The WESTDYN computer code was used as the analytic tool. This code was discussed  !

in Westinghouse topical report WCAP-8252, Revision 1, "Documentation of Selected Westinghouse Structural Analysis Computer Codes." The staff approved this report by letter dated April 7, 1981, from R. L. Tedesco to T. M. Anderson of ,

Westinghouse. The mathematical models used consisted of mass and stiffness representations for all four RCLs and the reactor vessel. Three-directional seismic analyses were performed using envelope response spectra with damping j

values of 2% and 4% for operating basis earthquake and safe shutdown earthquake,

respectively. The three-directional seismic responses were combined by the i

square-root-sum-of-squares (SRSS) method. Combination of closely spaced modes i was conducted according to the approved FSAR method. Time-history forcing functions for the postulated breaks at five nozzles (the pressure surge, the l accumulator, the residual heat removal, the main steam, and the feedwater line '

nozzles) were used to determine the most severe pipe rupture loading, and the q

SRSS method was used to combine seismic and pipe rupture loads.

i i

i Vogtle SSER 7 3-16 1

l The adequacy of the redesign was verified by comparing the analytic results with the'Americce Society of Mechanical Engineers Boiler and Pressure Vessel ,

Code Section III (Code) requirements. Vogtle Unit 2 has adopted the l requirements of the 1977 Code Edition up to and including the Summer 1979 l addendum (Subsection NB) and the Summer 1977 addendum (Subsection NF).  ;

The applicant's submittal confirmed that piping stresses did not' exceed Code stress limits and loadings on nozzles did not exceed the allowables loading provided by the manufacturer in the equipment specifications.  !

! Paul Munroe hydraulic snubbers were used for the upper supports. The service ,

record of these snubbers showed that no service-oriented failures have been i l reported. Because Vogtle Unit 2 will follow all maintenance requirements i recommended by the manufacturer, high reliability of snubber performance is expected. .

The applicant redesigned the steam generator upper supports for Vogtle Unit 2 by applying approved piping analysis methods and using qualified equipment.

On the basis of its review, the staff concludes that the results are acceptable.

< Therefore, the staff approves the redesign and the proposed revised FSAR. i i

3.9.6 Inservice Testing of Pumps and Valves * -

In accordance with the requirements of 10 CFR 50.55a, the licensee submitted the Inservice Testing (IST) Program for Vogtle Unit 1 by letter dated July l 30, 1986. As a result of staff review and comments, the licensee revised its IST Program for Vogtle Unit 1 ar.d by letter dated October 31, 1986, submitted

+

Revision 1 of the Vogtle Unit 1 IST Program for final staff review and approval.

The staff found Revision 1 of the Vogtle Unit 1 IST Program acceptable as dis-cussed in SSER 6.

2

By letters dated June 25 and August 27, 1987, the licensee submitted Revision 2 of the Vogtle Unit 1 program for staff review and approval. -Revision 2 l contains mostiy program changes resulting from operating experiences and '

additional requests for relief from the ASME Code Section XI, Subsections IWP, e "Inservice Testing of Pumps in Nuclear Power Plants," and IWV, "Inservice

! Testing of Valves in Nuclear Power Plants," requirements. The staff's evaluation and conclusions regarding Revision 2 of the Vogtle Unit 1 IST Program are ,

l provided below.

l The staff's contractor, EG&G Idaho, Inc., has reviewed the licensee's submittals

pertaining to Revision 2 and has prepared an evaluation of the proposed revision 1 to the Vogtle Unit 1 IST Frogram (see Appendix W). The staff has reviewed j the contractor's evaluation and concurs in its findings. A summary of the  ;

i staff's evaluation and conclusions is presented in Table 3.1, Where appropriate, a remark is provided to clarify the conclusions.

1 On the basis of its review of the licensee's revised IST Program and relief re-quests, the staff concludes that the IST Program will provide reasonable assur-

ance uf the operational readiness of the pumps and valves covered by the IST j Program to perform their safety-related functions. The staff has determined I *This evaluation was previously provided to Georgia Power Company by letter dated October 7, 1987, i

Vogtle SSER 7 3-17 i

that pursuant to 10 CFR 50.55a(g)(6)(1) granting relief from the ASME Code if its requirements are impractical, is authorized by law, and such relief will not endanger life, property, or the common defense and security. The staff also concluded that granting relief is in the public interest considering the burden that could result if the requirements were imposed on the facility.

During the review of the licensee's IST Program, the staff has not identified any significant misinterpretation or omissions of Code requirements. Thus, the IST Program, Revision 2, dated June 25, 1987, as supplemented by letter dated August 27, 1987, is acceptable for implementation.

T I

i i

I i

l I

Vogtle SSER 7 3-18 ,

4 i

j Table 3.1 Summary of Vogtle Unit 1 Inservice Testing Program  ;

Revision 2, changes and relief requests l

l  :

i Description of changes NRC evaluation 1 and/or relief requests and conclusions Remarks '

i Relief Request PR-4 was added to the Relief is Alternative i j Program. PR-4 requests relief to mea- granted. method is '

i sure pump vibration at different loca- found acceptable.

1 tions than those required by the Code.  :

A note was added to Relief Request PR-2 Acceptable Change was

to indicate that instruments to measure made tt. comply the Code-required flow rate will be in- with the Code stalled before restart following the requirement.

, first refueling outage.

t Therangeonthepressuregaugeswas Acceptable  ;

changed from "O psi to 15 psi to "-15 psi to 15 psi" to indicate the ranges on the installed instruments, j

j Deleted reference to RR-3 on valves Acceptable PV-0455A and PV-0456A. On Relief Request  ;

RR-3, the reference to valves 1201-PV-

, 0455A and 1201<V-0456 was deleted in ,

! order to make RR-3 generic, j Cold Shutdown Justification CS-35 was Acceptable Necasoitated by  ;

l written to allow testing of valves IE information 1

1205-HV-8716A and 1205-HV-8716B to be Notice 87-01.  !

i performed on a cold shutdown frequency, i

! Cold Shutdown Justification CS-36 was Acceptable Necessitated by written to allow testing of valves IE Information 1205-U6-001 and 1205-06-002 to be p u- Notice 87-01.

formed on a cold shutdown frequency.

l l Cold Shutdown Justification CS-37 was Acceptable Necessitated by written to allow quarterly partial-stroke IE Information testing and full-stroke testing during Notice 87-01, cold shutdown of valves 1205-U6-009 and 1205-U6-010.

The program was changed to delete the Acceptable closed safety position for valves 1205-U6-009 and 1205-U6-010. These valves are not required to close to perform a safety function.

Relief Request RR-26 was written to re- Relief Request quest relief from using mechanical exer- withdrawal is I cisers to test the spray additive tank acceptable.

vacuum breaker valves and as subsequently withdrawn by letter dated August 27, 1987.

Vogtle SSER 7 3-19

Table 3.1 (Continued)

Description of changes NRC evaluation and/or relief requests and conclusions Remarks Cold Shutdown Justification CS-38 was Acceptable written to allow testing of valves HV-8508A and HV-8508B during cold shutdown.

The program was changed to indicate quar- Acceptable terly forward-flow-operability testing for valve 1208-U6-032.

Cold Shutdown Justification CS-34 was Acceptable written to allow full-stroke testihg of valves 1208-U4*284 and 1208-U4-299 during cold shutdown and partial-stroke testing during the quarterly pump tests.

The program was changed to indicate the Acceptable quarterly reverse-flow-closure testing of valves 1302-U4-113, 1302-U4-114, 1302-U4-115, and 1302-U4-116.

Cold Shutdown Justification CS-33 was Acceptable written to allow testing of valves 1302-U4-125, 1302-U4-126, 1302-U4-127, and 1302-U4-128 to be performed on a cold shutdown frequency.

The program was changed to indicate that Acceptable valves 1592-U4-186 and 1592-U4-187 are normally closed and that their safety position is open.

An editorial change indicated a piping Acceptable Editorial and instrumentation diagram (P&ID) revi- change.

sion that relocated valves HV-9378 and 2420-U4-049 to P&ID 1X4DB186-4.

The program was changed to indicate that Acceptable valves HV-8208, HV-8209, HV-8211, and HV-8212 are normally closed instead of nor-mally open. Valves HV-8211 and HV-8212 have been replaced with 1.00-inch valves.

Relief Request RR-1 was withdrawn. Acceptable Changes were References to RR-1 were deleted from made to comply the valve tables where appropriate. with SSER 6.

Vogtle SSER 7 3-20

l 4 REACTOR 4.4 Thermal-HydraulicDesign l 4.4.8 Instrumentation for Detection of Inadequate Core Cooling

• License Condition 2.C(7)a of the Vogtle Unit 1 full power license (NPF-68) required that the licensee submit the reactor vessel level instrumentation

system (RVLIS) implementation report by June 1, 1987. By letter dated May 29,  !

1987, the licensee provided the RVLIS implementation report. The staff has  !

reviewed the report and the supplemental information provided by the licensee's letter dated July 20, 1987, and concludes that the license condition has been ,

satisfied. Further, based on the acceptable RVLIS implementation report which  ;

i completes Vogtle Unit 1 compliance with NUREG-0737, Item II.F.2, the staff l

( approves the Vogtle Unit 1 RVLIS installation.  ;

l l I l

l i

i 3 i

\

i i I

! l i

i l

i i

i i I

• This evaluation was previously provided to Georgia Power Company by letter j dated August 12, 1987, i

u 3

Vogtle SSER 7 4-1

l 1

l 5 REACTOR COOLANT SYSTEM l

5.4 Component and Subsystem Desian

'5.4.7 Residual Heat Removal System 5.4.7.5 Tests, Operational Procedures, and Support Systems

• l On January 6, 1987, the staff issued Information Notice (IN) 87-01, "RHR Valve  !

Misalignment Causes Degradation of ECCS in PWRs," which discussed a poten- i tially significant problem pertaining to residual heat removal (RHR) valve  ;

alignment in the low pressure emergency core cooling system (ECCS). Specif-  :

ically, closure of the RHR crossover valves or of the pump discharge valves (valves 1HV-8716A and B and 1HV-8809A and B in the simplified Vogtle flow diagram of Figure 5.1) could potentially incapacitate the RHR system by-

! l i preventing injection into all four reactor coolant system (RCS) cold legs.  :

) i An enforcement conference was held with the licensee on October 21, 1987, in i 1 the Region II offices to discuss seven instances in which one of valves

, 1HV-8716A and B and 1HV-8809A and B had been closed at Vogtle Unit 1 between February and August 1987. In order to preclude closure of these valves in i Modes 1, 2, and 3, the licensee had submitted revisions to the Unit 1 Inservice l l Testing (IST) Program providing cold shutdown justification for closure of -

1 these valves.** However, at the enforcement conference, based on its addi-l tional review of closure of these RHR system valves, the licensee ijdicated its <

4 I

belief that closure of the valves was technically supported and the best sur- j veillance techniques necessitated closure of valves 1HV-8716A and B in Mode 1 l and of valves 1HV-8809A and B in Mode 3. The staff informed the licensee that  !

! it could not thus manipulate these valves until the staff had reviewed and '

l approved the analysis indicating that safety considerations continue to be met, l l

and thereby addressing the issue raised in IN 87-01.

Subsequently, the licensee submitted its technical basis for closure of these RHR valves by letter dated October 27, 1987. The staff's evaluation of the l closure of each valve follows.

l *This evaluatit,n was previously provided to Georgia Power Company by letter t dated November 5, 1987.

I i **IST Program, Revision 1, submitted by letter dated October 31, 1986, pro-l vided the cold shutdown justification for valves 1HV-8809A and B. IST

! Program, Revision 2, submitted by letter dated August 27, 1987, provided the i cold shutdown justification for valves 1HV-8716A and B, and was provided in a response to IN 87-01. The staff approved Revision 1 in SSER 6 dated March 1987 l and approved Revision 2 by letter dated September 22, 1987, and Section 3.9.6 and Appendix W of this report.

l

{ Vogtle SSER 7 5-1 l

4

< F.O.

o -8 H "Y"A C PUMP A HXA fD q q 4, COLDLEO LOOP 1 m .T. .Tm ' t f -

L o.

~ ~

m m -

m Hvs7018 HV8701A

• _ FV9518 N.C.

F.C.

RWST 2 COLDLEG LOOP 2 O ,

TANK I O 5N Z

w a wa MT , i r, r,

HOT LEO RECIRCULATION e

F.C. - FeNo closed T

N N.C. NormeNy cleoed F.O. - Fede open N O. - Normany open LO. - Locked open kI.

PUMP 5 HXS O *

, 4p, , COLDLEG LOOP 3 a

LO.

MVS7029 HV5702A rvests

N C.

l F C.

l Rwsv m , %_

cototrotooP4 TAMM V

Figure 5.1 Vogtle low pressure safety-injection system normal ECCS alignment

l l

Closure of Valves 1HV-8716A and B in Mode 1  ;

In its October 27, 1987, letter, the licensee described two surveillances which would require closure of valves 1HV-8716A and B. These valves are i required to operate following a loss-of-coolant accident (LOCA) in order to allow initiation of hot-leg recirculation, and therefore, stroke testing of 1 these valves at power allows detection of any valve degradation. For stroke testing, the valves would be individually closed for approximately three minute; every 90 days. In other respects, the configuration would be the same as that shown in Figure 5.1. During surveillance, additional single failures are not required to be assumed. Therefore, flow would continue to be available  !

from two RHR pumps into all four RCS cold legs. This configuration has no impact on the capability of the RHR system to perform its function.

Closure of valves 1HV-8716A and B would also be required during Mode 1 for quarterly flow testing of the RHR pumps. During this test, the opposite RHR cross-tie valve from the pumps being tested is closed for less than two hours, and the flow path of the refueling water storage tank is opened. This config-l uration allows essentially full-flow testing of the pump (approximately 3000

! gpm). Again, being in the surveillance mode does not require assumption of an  ;

additional single failure. Therefore, should a LOCA occur, partial flow is available into two cold legs from the pump being tested, and full flow into the remaining two cold legs is available from the RHR pump not being tested. l 1 Further, flow is available from the two intermediate-head safety-injection

pumps and the two high-head charging pumps, and the operater can take action to close the open cross-tie valve in order to obtain full flow into the RCS

from'the pump being tested. Even if assuming that during a LOCA one of the cold legs receiving flow from the RHR pump not being tested is spilling to the I broken reactor coolant loop, the total ECCS flow without operator action to close the cross-tie valve still exceeds minimum cooling requirements described

in the Vogtle FSAR. The FSAR analysis assumes loss of one RHR pump, one inter-mediate-head safety-injection pump, and one high-head charging pump. The li-

, censee has committed to test the RHR pumps at partial flow through the recir-culation line (see Figure 5.1) if the redundant RHR pump or its associated

, components are inoperable.

On the basis that the period of closure of valves 1HV-8716A and B is short and that in both surveillances described above, minimum ECCS flow requirements would continue to be met, the staff concludes that closure of these valves during Mode 1 operation is acceptable.

! The licensee has also committed to revise its IST Program to reflect its intent regarding RHR pump testing and thereby withdraw its cold shutdown justification associated with valves 1HV-816A and B. The staff requires that the IST revision be submitted in a timely manner.  !

Closure of Valves 1HV-8809A and B in Mode 3 1

The licensee has proposed to close valves 1HV-8809A and B (one at a time) in Mode 3 in order to perform leak tests of the check valves downstream of valves  !

, 1HV-8809A and B on each of the RCS cold legs. In submittals dated December 9, l l 1985, and June 13, 1986, the licensee described an analysis for a LOCA in Mode 3 '

l with portions of the ECCS disabled. The ECCS configuration in the analysis is Vogtle SSER 7 5-3 l

more conservative than that during check valve leak testing with one 1HV-8809 valve closed. The analysis assumed that flow was available from only one RHR pump, one intermediate-head safety-injection pump, and one high-head charging pump. The analysis also assumed that automatic safety-injection actuation on low pressurizer pressure was blocked and that only automatic safety injection on containment high pressure was available. In actuality, during check valve leak testing all ECCS pumps and accumulators (above 1000 psig) are available.

Also, automatic safety-injection actuation on pressurizer low pressure is avail-able above approximately 1900 psig when the operator unblocks this signal.

The December 9, 1985, and June 13, 1986, submittals were evaluated by the staff in its review of open item 19 (derived from confirmatory item 22), "LOCA miti-gation in Modes 3 and 4." In Section 6.3.5 of SSER 4 dated December 1986, the staff concluded that the Vogtle ECCS design is adequate for LOCA in Mode 3.

On the basis that the minimum ECCS flow requirements would continue to be met should a LOCA occur in Mode 3 with one 1HV-8809 valve closed, the staff con-cludes that closure of valves 1HV-8809A and B during Mode 3 operation is acceptable.

The licensee has shown, and the staff agrees, that based on analysis, closure I of one of the valves in question would not render the RHR system inoperable.

Rather, the minimum ECCS flow requirement would continue to be met. Therefore, the licensee can perform the surveillances discussed above in accordance with the current Technical Specification (T;, ' 5.2 without requiring any TS modif-ication. However, the licensee is required to include a discussion of the supporting analysis for LOCA in Mode 3 in the next FSAR amendment.

i l

i j

i i

i 1

1 Vogtle SSER 7 5-4 i i

\

1 I

6 ENGINEERED SAFETY FEATURES 6.5 Engineered Safety Feature Atmosphere Cleanup Systems ,

P i

6.5.1 System Description and Evaluation

• By letter dated June 1, 1987, the applicant transmitted a proposed revision to Sections 1.3, 3.2, and 9.4 of the Vogtle Units 1 and 2 FSAR. The proposed re-vision deletes the electrical penetration filter and exhaust (EPFE) system from

Vogtle Unit 2. The Vogtle Unit 1 EPFE system is not affected.

l The EPFE system is designed to maintain a minimum negative pressure on the elec-trical penetration area of the control building and minimize release of airborne radioactivity following postulated post-loss-of-coolant accident (LOCA) contain-ment leakage by filtering potentially contaminated air from the electrical pene-tration area. The system consists of two 100% capacity filtration trains each designed to filter up to 6000 cfm.

Section 6.5.1 of the SER described the EPFE system as an engineered safety fea-1 ture (ESF) system, and credited its charcoal adsorbers with 99% removal effi-l ciency for all forms of radioiodine. However, in a subsequent meeting with the applicant on November 17, 198E. the staff was informed that the indicated removal 4

efficiency for the charcoal adsorbtrs in the EPFE system was not used in the calculations of either post-accident (LOCA) offsite radiation dose exposures per

! 10 CFR Part 100, or radiation exposures to operating personnel in the control i room per the dose guidelines of GDC 19. On this basis, the staff accepted the applicant's proposal to delete the 1/8-inch negative pressure requirement from the Vogtle Unit 1 Technical Specifications and to reclassify the EPFE system to j a non-ESF system from an ESF system. As discussed in a telephone conference call  ;

on June 18, 1987, the applicarit agreed to clarify FSAR Section 9.4.5 to clearly t indicate that the Vogtle EPFE is a non-ESF system.  ;

The electrical penetration area is normally served by the control building levels A and B normal heating, ventilation, and air conditioning (HVAC) system which I has no connections to either the control room normal or emergency HVAC systems,  !

or the Technical Support Center (TSC) HVAC system. The Vogtle control room and l

] TSC are located on level 1 in the control building above levels A and B.

Following a design-basis LOCA, potential contaminated outside air is introduced l

, into the control room through the control room emergency filtration system to 1 remove radioactivity and to pressurize the control room. The outside air is

, also drawn into the control building levels A and B normal HVAC system for makeup air but it is not filtered. Deletion of the Unit 2 EPFE system could potentially increase airborne radioactivity concentrations at control building levels A and B because of leakage through the electrical penetrations.

• This evaluation was previously provided to Georgia Power Company by letter dated August 19, 1987.

4

'I

, Vogtle SSER 7 6-1

As indicated above, the staff previously did not use the airborne radioactivity removal efficiencies assigned to the EPFE system in the calculations of post-LOCA offsite radiation consequences or radiation exposure to operating personnei in the control room. To evaluate the effects of deletion of the Unit 2 EPFE system, the staff assumed inleakage of unfiltered contaminated air into the control room envelope from control building levels A and B through doorways on

, ingress and egress, and from the control room emergency HVAC recirculation ductwork. The staff assumed 10 cfm unfiltered infiltration of contaminated air from control building levels A and B into the control room through doorway

, ingress and egress as delineated in the guidelines of SRP Section 6.4. This assumption is conservative because the Vogtle control room is provided with a l two-door vestibule-type entry into the control room. This type of entry design

! significantly reduces contaminated air backflow into the pressurized control ,

room. l l

The applicant provided a calculation comparison of airborne radioactivity concen-  !

tration outside the control building to that inside the control building on levels A and B with a maximum total design leakage of 43.2 cubic centimeters per minute from 72 electrical penetrations. The results of this calculation indi-cated that the concentration inside the control building on levels A and B will l be approximately 15% higher than outside the control building levels A and B l bec n e the potential leaks from the electrical penetrations will reduce the iodine protection factor for control room doses by 1.06 (6%) based on the assumed

, 10-cfm unfiltered air infiltration. Using this factor, the staff calculated  ;

l thyroid and whole-body doses to the control room operators to still be within I the guidelines of GDC 19.

I The control room emergency filtration system contains two 100% capacity air  !

filtration units each designed to filter 25,000 cfm. Each unit includes a  ;

4-inch-deep charcoal adsorber, a control room return-air fan, and a control ~

room air-filter-unit fan. Upon receipt of a control room isolation signal, '

3 the control room emergency filtration system will be actuated, and the normal air handling unit will be automatically tripped. Outside air required for con-trol room pressurization is mixed with return air upstream of tne filtration

, unit. Air within the control room envelope is recirculated continuoutly through

the emergency filtration unit. The system design provides no potential bypass pathways around the emergency filtration units. The staff has credited the system with 99% removal efficiency for all forms of radioiodine.

l The control room return-air fan takes air from the control room envelope and the outside makeup-air line and delivers it to the filtration unit. The con-trol room filter unit fan is located adjacent to the filter housing and blows air directly into the control room envelope. Any air inleakage into the system

! ductwork will be filtered through the 4-inch-deep charcoal adsorber before it 2

enters the control room envelope. The staff, therefore, assumed no unfiltered infiltration of contaminated air from control building levels A and B into the control room through the control room emergency HVAC recirculation ductwork. ,

Thus, the staff finds that the slightly higher (15% increase) airborne radio- '

activity at control building levels A and B due to post-LOCA electrical penetra- ,

tion leaks will not exceed the control room operator dose guidelines of GDC 19 '

as indicated in the guidelines of SRP Section 6.4.

j

-i Vogtle SSER 7 6-2 f

i i

On this basis, the staff concludes that the applicant's request to delete the EPFE system from Vogtle Unit 2 is acceptable because the staff's previous conclusions stated in SER Sections 6.4 and 15.6.5 are not affected, and the requirements of GDC 19 continue to be satisfied.

Vogtle SSER 7 6-3

l l

l l

l 7 INSTRUMENTATION AND CONTROLS 7.3 Engineered Safety Features Systems 7.3.3 Specific Findings 7.3.3.3 Undetectable Failure in On-Line Testing Circuitry for Engineered Safeguards Relays In SSER 4, the staff stated that Vogtle Unit 2 Technical Specifications, when developed and reviewed, will contain test requirements (monthly.or quarterly) l that reflect the status of the pending wiring modification to the engineered

! safeguards relay circuitry. By letter dated March 16, 1987, the applicant stated that a wiring modification per Westinghouse Field Change Notice GBEM-10554 was completed on Vogtle Unit 2 on January 30, 1987. The staff finds this change acceptable and the unique testing requirements (monthly testing of slave relays in lieu of quarterly) will not be included in the Vogtle Unit 2 Technical Specifications.

7.5 Information Systems Important to Safety 7.5.2 Specific Findings 7.5.2.1 Emergency Pesponse Capability--PG '.97, Revision 2, Requirements

• In Section 7.5.2.1 of SSER 5, the staff required the applicant (now licensee) to augment certain surveillances and procedures associated with accident-monitoring instrumentation (Regulatory Guide (RG) 1.97, Revision 2) at Vogtle  !

Unit 1, pending completion of the verification and validat,'on (V&V) effort for the plant safety monitoring system (PSMS). By-letter dated June 1, 1987, the licensee provided details of the PSMS V&V Program. On June 29-30, 1987, the staff met with the licensee and its representatives at the Westinghouse facili-ties located in Monroeville, PA. The meeting was held to audit the Vogtle PSMS V&V Program. A consultant from SoHar Inc. assisted the staff during the

a. Jit.

The licensee has a microprocessor-based display system that performs post-accident monitoring at Vogtle. This display system is the PSMS, and it was manufactured by Westinghouse. The system processes plant sensor signals and outputs many of the RG 1.97, Revision 2 variables to plasma displays and external indicators, displays, cabinets, and other equipment. The PSMS con- i sists of three types of modular components: the remote processing units, the display processing units, and the plasma displays. Th7 system is seismically and environmentally qualified and configured to meet single-failure criteria.

The Vogtle PSMS is a functional derivative of the display developed by Westing-house for Housten Power and Light as part of the Qualified Display Processing

• This evaluation was previously provided to Georgia Power Company by letters dated August 25 and September 17, 1987.

Vogtle SSER 7 7-1

System (QDPS) for the South Texas Project. The development of the Vogtle PSMS occurred after the completion of the QDPS in order that all common software could be used without repeating the entire V&V process on those units. The staff's safety evaluation of the QDPS, which was found acceptable, appears in Supplement 4 to the South Texas SER (NUREG-0781) dated July 1987.

The staff evaluated the design differences between the Vogtle PSMS and the equivalent display designed and qualified for South Texas. The staff's review found hardware and software differences. In hardware, the Vogtle PSMS has a plant-specific display selection keyboard, and one output display per train as opposed to six displays for South Texas. In software, the difference consists of the plant-specific sensor inputs and variables, the display formats,.and the addition of data from a reactor vessel water level nstrumentation system. The Vogtle PSMS has a total of 1018 software units of which 136 units are unique to the ri nt. About 87% of the software units are the same as the software units in the South Texas display.

The design of the plasma display pages consists of an upper level plant status summary and four lower level displays for nuclear power, reactor ves;el water level, core exit thermocouples, and pressure-temperature limits. In addition, the system provides for the display of process variable time trend histories i and detailed data listings.

During its audit, the staff evaluated the organizational structure of the V&V l staff and the content of the V&V Program. The vendor as well as the Vogtle V&V team made presentations on the display's design organization. The data in these presentations described the V&V activities and identified responsible personnel. The staff's review of the data concluded the organizational struc-ture and the level of independence of the V&V team from the design team was acceptable.

The audit also evaluated the V&V Program. Westinghouse personnel made presenta-tions to the staff on the V&V Program. The object of this program is to elimi-nate errors in design. The method used to verify the software modules was the same method used in the South Texas Project, which the staff found acceptable.

However, the absence of verification of the software design also exists in the Vogtle program. On the other hand, this is overcome with an extensive verifica-tion of the software modules.

The method used by the validators to identify the tests for the display system was discussed by the vendor. This discussion identified the sctpe o' the tests consisting of functional, abnormal, and prudence evaluations. Tee functional evaluation of the display system contained static as well as dynamic tests.

Also, the validation effort focused upon the differences between the Vogtle and South Texas desigas with thorough testing to validate that each sensor input algorithm had been met. For Vogtle algorithms common with those at South Texas, validation testing was performed to demonstrate that all algorithms were properly installed. This was accamplished by performing a selected subset of the South Texas tests using Vogtle plant-specific sensor inputs and variables.

The staff's review of the Vogtle V&V Program confirms it is identical to the one used in the South Texas Project and that it is acceptable.

The staff evaluated the products from the V&V Program. The method used to evaluate products consisted of a walkthrough of the code for two sensor signals and an analysis of the trouble reports identified by V&V.

Vogtle SSER 7 7-2

The walkthrough of the code used two sensor signals: auxiliary feedwater flow and cold-leg coolant temperature. The analog sensor signals were traced through the signal conditioning circuits to the multiplexers. The multiplexer converts the analog signal to a digital signal. The digital signal is then processed by the microprocessors using stored algorithms. The processed signal is then displayed on the surface of the gas plasma display. . The staff's walk-through traced the signals through the algorithms and evaluated the associated V&V activities. The staff found the V&V activities responsive to the V&V plan.

The staff analyzed the trouble reports identified by the V&V Program during verification for the type and quantity of softwarc errors reported. The staff found the percentage of the major types of error to be consistent with published error patterns for this type of activity as discussed in IBM Technical Report TR 00.2763, dated June 10, 1974 (IBM, 1974). From this result, the staff con-cludes that the vendor performed an effective verification of the software.

The staff also analyzed the trouble reports identified during validation activi-ties and found a small number of trouble reports. The staff also found no gen-eric problems or types of errors that should have been detected during earlier verification activities. From these results, the staff concludes that the vendor performed an effective va;idation of the software.

During the audit, the licensee presented and discussed physical security measures and maintenance for the display system. Security measures were discussed for the remote processing units, the data processing units, and the displays. Also, security measures for the spare programmable read only memories (PROMS) were discussed.

The staff's review concludes that the physical security, maintenance, and modifications procedures for Vogtle are essentially identical to those for South Texas. These include the following:

(1) No data input devices are connected to the system in normal operation.

(2) The input keyboard used to change setpoints and limits is physically removed requiring keys, passwords, and authorization before use.

(3) All maintenance and code modifications will be performed by Westing-house to the same standards of V&V used in the design of the display.

The staff finds the physical security, maintenance, and modification procedJres for the Vogtle PSMS acceptable.

On the basis of its review of the V&V Program used to design and develop the PSMS, the staff concludes that:

(1) The Vogtle PSMS is very similar to the monitoring system developed and licensed for South Texas.

(2) An acceptable level of independence existed between the V&V team and the design team.

(3) The V&V plan used for the Vogtle PSMS is irentical to the one used for the monitoring system in South Texas.

Vogtle SSER 7 7-3 l ,

(4) The analysis of trouble reports generated from V&V activities con-cludes that the vendor met the goals of the V&V plan.

(5) The physical security, maintenance, and modification procedures for the system are adequate.

In terms of its evaluation of the V&V Program, the staff concludes that the Vogtle PSMS is acceptable.

By letter dated September 1, 1987, the licensee submitted information regarding the software and hardware differences between the PSMS of Vogtle Unit 1 and the PSMS of Vogtle Unit 2. In its' submittal, the licensee stated that only five units of code related to the Unit 2 plasma displays were affected by minor software changes. In addition, no trouble or clarification reports were generated in eitbar the verification or validation process for these Unit 2 changes. On the basis of its review of this information, the staff concludes that its acceptance of the Vogtle PSMS V&V effort as discussed in its letter of August 25, 1987, remains unchanged.

7.5.2.4 Bypass and Inoperable Status Panel In the SER, the staff indicated that the applicant had committed to have by- l passed and inoperable status indicate in both control rooms for the fuel hand-ling building engineered safety features heating, ventilation, and air condi-tioning system which is sharea between both units. Installation of the modifi- ,

cation was identified as a confirmatory item. After the staff resolved this issue in SSER 4 for Unit 2, the applicant informed the staff that the modifi-cation for Unit 2 was not yet. complete, thereby revising an earlier letter indicating installation was complete. Therefore, in SSER 5 the staff reopened this confirca*.ory item.

By letter dated October 15, 1987, the applicant informed the staff that the required modification for Unit 2 has been completed. On this basis, the staff concludes that confirmatory item 27 is satisfactorily resolved for Unit 2.

Vogtle SSER 7 7-4

9 AUXILIARY SYSTEMS 9.5 Other Auxiliary Systems 9.5.1 Fire Protection

• By letter dated July 7,1987, the applicant proposed three changes to the Vogtle Unit 2 fire suppression system. The three proposed changes are:

(1) Revise sprinkler hanger design based on the results of seismic testing for qualification purposes rather than analytical means as done previously.

(2) Revise the criteria for placement of in-tray sprinkler protection to include them only in the cable spreading rooms.

(3) Revise the fire suppression flushing procedures, which provides an alter-nate to flushing of the sprinkler system piping.

The applicant's position is that the proposed changes will not compromise the ability of the fire protection systems to perform their intended function during a fire.

9. 5.1. 5 Fire Detection and Suppression Sprinkler and Standpipe Systems Fire protection guidance furnished by the staff does not require a licensee to postulate a fire and earthquake simultaneously. However, in many areas, fire suppression systems are classified as seismic two-over-one (2/1) systems. This means that their integrity during and after a seismic event should be ensured so as not to jeopardize the integrity of adjacent equipmeiit and structures that may be essential for safe shutdown of the plant. Automatic sprinkler systems installed in areas containing safety-related equipment or components, therefore, must be designed and installed so that they-will not fail during an earthquake and damage the safety-related equipment or components. The automatic sprinkler systems of Unit 1 were designed and installed to meet strict support. stiffness and piping deflection criteria. However, the "Standard for the Installation of Sprinkler Systems," NFPA-13, published by the National Fire Protection Associa-tion, permits use of more flexible supports, including sway bracing, for sprinkler systems that may be subject tJ seismically induced vibratory loadings.

A recent experimental offort performed by ANCO Engineers, Inc. (ANCO) for Bechtel Western Power Corporation successfully demonstrated that the rod-suspended sprinkler systems at the South Texas Project were capable of withstanding simulated seismic events in excess of predicted design criteria without collapse.

• This evaluation was previously provided to Georgia Power Company by letter dated October 26, 1987.

Vogtle SSER 7 9-1

b l

'In order-to verify the adequacy of the more flexible sprinkler hanger design

_ proposed for Unit 2, the applicant contracted with ANCO to test three segments of actual Unit 1 sprinkler systems. The three test assemblies chosen were representative of actual installed systems, and each consisted of approximately 40 feet of feed main with several branch lines and a simulated deluge valve connection. Supports and sway braces for each test assembly were designed and installed using NFPA-13 recommendations. All' supports incorporated standard off-the-shelf. hardware, including swivel connections to act as pins at the top of the supports.

The assemblies were tested on the ANC0 R-4 shake table. Each was. subjected to dynamic loadings equivalent to five operating basis earthquakes (08Es), af ter several scaling earthquakes to include the effects of fatigue, and one safe shutdown earthquake (SSE). Each test assembly was hydrostatically tested before

, and after the first OBE test to demonstrate functionality. _ Finally, each of the test. assemblies was subjected to dynamic loadings equivalent to.l.2 x SSE and 1.4 x SSE to demonstrate survivability and to establish a design margin. Test results indicated that the fragility limits of the test assemblies exceeded.the capacity of the shake table and far exceeded the seismic design criteria of the site. The staff finds the above test procedure and test results to be acceptable.

The staff also agrees with the applicant's proposed FSAR changes related to the above. The proposed changes are contained in Inserts B, C, E, ar.d F to Attach-ment 4 of the applicant's letter dated July 7, 1987.

On the basis of the above evaluation, the staff finds that these tests demon-strated that automatic sprinkler fire suppression systems designed and installed in accordance with NFPA-13, using rod type hangers and sway bracing, will be able to withstand the design seismic loadings and, therefore, are acceptable..

Section 1-11.1.1 of NFPA-13, "Standard for the Installation of Sprinkler Systems,"

reads as follows:

1-11.1.1 Underground mains and lead-in connections to system risers shall be flushed before connection is made to sprinkler piping in order to remove foreign materials which may have entered the underground piping during the course of the installation.

For all systems,.the flushing operation shall be continued until water is clear.

The purpose of this flushing is to ensure that foreign materials that may have entered the underground piping during construction do not enter the sprinkler system piping.

The applicant performed the flushing operations of the underground mains and lead-in connections at Unit I while they were connected to the sprinkler systems. This deviation from the provisions of NFPA-13 resulted in an open item being added in SSER 2 that was later closed in SSER 4. For Unit 2, the applicant is proposing a different method of ensuring that the underground mains and lead-in piping to fire suppression systems are properly flushed, and that foreign material does not enter the suppression system piping. The proposal for Unit 2 provides for the use of test blanks, as follows:

Vogtle SSER 7 9-2

(1) A test blank will be installed between the system isolation valve and preaction sprinkler valve before the system is installed.

(2) The test blanks will be visible when installed and controlled through the use of drawings, procedures, and inspections.

(3) Test blanks will be removed after header piping is verified clean.

By telephone conference call on. September 2,1987, the staff was assured by the applicant that the test blanks will be so installed as to permit flushing of all portions of the underground main and system lead-in piping utilizing flushing flow rates in accordance with Section 1-11.1.2 of NFPA-13. Consider-ing that information, the staff agrees with the applicant's proposed approach to use test blanks to prevent introduction of foreign materials into sprinkler system piping during flushing operations of the underground mains and lead-in piping to the sprinkler systems.

The staff also agrees with the FSAR changes proposed by the applicant as contained in Attachment 4 of its letter of July 7,1987, and applicable to flushing of underground mains and system lead-in piping. The applicable proposed changes are contained in Insert D to FSAR Table 9.5.1-9 (sheet 2 of 16).

On the basis of the above evaluation, the staff finds that the proposed changes in procedures for flushing underground mains and lead-in piping to system users will satisfy BTP CME 8 9.5-1 (NUREG-0800), Section C.6.b.(1) and the referenced NFPA-24, "Standard for the Installation of Private Firc Service Mains and Their Appurtenances," Section 8-8 and are, therefore, acceptable.

9.5.1.6 Fire Protection of Specific Plant Areas Cable Spreading Rooms FSAR Section 9.5.1.2.1.4 addresses fire suppression design criteria for cable trays containing safe shutdown cables and specifies in-tray directional spray nozzles above each tray.

On the basis of additional staff guidance, and as a result of more refined methods of evaluating cable tray fire hazards and protection required (including test results from industry and NRC-sponsored research programs), the applicant realized that the protection provided for Unit 1 safe shutdown cables was un-necessarily conservative. Therefore, the applicant has proposed alternative design criteria for protecting cable trays throughout Unit 2. The applicant proposes that design of automatic sprinkler protection for cable trays in Unit 2 be based upon the following criteria:

(1) The area coverage boundaries for suppression systems will be in accordance with that identified on fire area drawings (FSAR Figures 9A-1 through 9A-46).

(2) In the cable spreading rooms, in-tray directional spray nozzles will be provided. Area protection at the ceiling will provide coverage for the first three safety-related trays in a vertical stack, and in-tray protec-tion will be provided for the remaining safety-related trays starting with the fourth tray in the stack and ending with the last tray in the stack (typical Unit 1 design).

Vogtle SSER 7 9-3

(3) For electrical cable chases and tunnels, sprinklers will be provided at the ceiling designed to discharge 0.3 gpm per square foot over the most remote 3000 square feet or area within the cutof f fire boundaries, whichever is less.

(4) 'For other areas containing three safety-related cable trays or less in a vertical stack, sprinklers will be provided at the ceiling design to discharge 0.21 gpm per square foot over the most remote

~

1500 square feet or area within the cutoff fire boundary, whichever is less (typical Unit 1 design).

(5) For other areas containing more than three safety-related cable trays in a vertical stack, sprinklers will be provided at the ceiling designed to discharge 0.3 gpm per square foot over the most remote 3000 square feet or area within the cutoff fire boundaries, whichever is less.

Except for cable spreading rooms, cable tray installations generally are con-sidered to have low to moderate fuel loads (80,000 Btu /f t2 of floor area being equivalent to a 1-hour fire). Based upon the low to moderate fuel loading in the cable trays throughout the plant, and an increased water density discharge i design criteria for ceiling sprinklers in Unit 2 compared to the lower water  ;

density discharge design criteria used for ceiling sprinklers in Unit 1, the staff agrees with the applicant that in-tray sprinkler protection does not have to be provided in areas other than the cable spreading room.

The staff also agrees with the FSAR changes proposed by the applicant as they relate to these changes in automatic sprinkler protection. The proposed FSAR changes accepted by the staff are shown as Insert A to Attachment 4 of the applicant's letter of July 7, 1987.

On the basis of the above evaluation, the staff finds that the proposed changes in design criteria for sprinkler protection for cable trays containing safe shutdown cables meets the guidelines of BTP CMEB 9.5-1 (NUREG-0800), Section C.5.e, is consistent with protection designs that have been accepted at other nuclear power plants, will provide adequate fire suppression protection for safe shutdown cables, and is, therefore, acceptable.

9.5.4 Emergency Diesel Engine Fuel Oil Storage and Transfer System 9.5.4.2 Emergency Diesel Engine Fuel Oil Storage and Transfer System (Specific)*

License Condition 2.C(8) was included in the Vogtle Unit 1 full power license (Facility Operating License NPF-68), dated March 16, 1987, because of staff concern that the reaction products of the acidic impurities in diesel fuel oil with the zinc inorganic coating of the storage tanks might cause plugging of lines and fuel injectors in diesel generators. The license condition states:

• This evaluation was previously provided to Georgia Power Company by letter dated October 15., 1987.

Vogtle SSER 7 9-4 r

=. -- _.

Prior to restart following the first refueling, GPC shall (1) replace the zinc coating in the diesel generator fuel oil storage tanks with a coating which does not contain zinc or (2) by March 1, 1988 provide an acceptable justification to the staff that the present fuel oil storage tank zinc-based coating will not affect the operability and reliability of the diesel generators over the life of the plant as specified in IE Circular 77-15.

Also, Technical Specification Surveillance Requirement 4.8.1.1.2f requires sampling and analysis of new fuel oil and oil in the storage tanks to verify that the neutralization number is less than 0.2 and the mercaptan content is less than 0.01%.

By letters dated July 13, September 30, and October 15, 1987, the licensee provided information justifying the continued use of the inorganic zinc coating on the fuel tanks. This information included the following items:

(1) The inorganic zinc coating substantially extends the life of steel storage tanks by delaying the onset of corrosion and by reducing the corrosion rate. The lowered corrosion rate results in less particulate contamination in the fuel oil.

(2) The staff concern arose in part because of the discussion in IE Circular 77-15 of a clogged strainer in the fuel line to the diesel generator at the Cooper Station. The circular states that fuel oils are degraded by contact with metal such as zinc, which "has a tendency to form soluble soaps in the fuel oil which are deposited on the diesel engine's injector nozzles. A buildup of this deposit will eventually degrade the engine's performance." The circular also states that "[t]he presence of water in the fuel oil promotes the growth of fungi or slime that also degrades the fuel and has the potential for clogging filters."

The licensee's letter of July 13, 1987, noted that the Cooper Station event could not have been caused by zinc because the steel Cooper tanks are not coated internally. According to the licensee, the diesel engine manufacturer makes no recommendations regarding the use of zinc coatings on storage tanks; it only specifies the use of No. 2 diesel fuel oil. The inorganic zinc coating manufacturer has stated that the "coating can be used with diesel fuel as long as the neutralization number is no greater than 0.4 and the mercaptan content is no greater than 0.01%." Analyses by the licensee of ten samples of fuel oil in Vogtle Unit 1 storage tanks A and B ranged from 0.06 to 0.10 for the neutralization number, with an average of 0.08.

The average mercaptan content in ten samples was 0.0005%.

No water was visible in 13 of 15 fuel oil samples. Only a trace of water was visually detectable in the remaining two samples. The Technical Specifications require sampling of the fuel oil in the storage tanks at least once every 31 days to verify that the particulate contamination is less than 10 mg/ liter.

Vogtle SSER 7 9-5

(3) Duplex fuel oil filters are installed in the fuel line with provisions to measure the differential pressure across the filter in use. A high differ-ential pressure would be annunciated in the control room, and an operator would switch from one filter element to the other.

(4) Diesel generator "pop" tests are performed on the fuel injectors every 18 months to check the spray pattern from the fuel injectors. As part of this test, all injectors are disassembled, cleaned, and inspected. Any damaged or worn parts are replaced. The inspection procedure.will include provisions for the analysis of any significant deposits of zinc.

(5) In accordance with the Technical Specifications, the tank is checked for the presence of water at least once every 31 days and, if found, the water is removed from the storage tank sumps.

The staff has reviewed the information provided in the licensee's letter of July 13, 1987, and found it to be consistent with information from other industry and literature sources. Protective coating experts consulted by the staff agree that the preferred coating to protect against the corrosion of steel storage tanks by fuel oil is inorganic zine without a top coat. The staff's research has not uncovered any problems of plugging of diesel generator fuel injectors. j Filter Clogging by Insolubles With regard to the sta.'f's original concern about clogging lines and filters with corrosion products or metallic soaps, the licensee's provision of a duplex filter with control room annunciation of excessive differential pressure across the filter element in operation is adequate to protect against a line clogging incident of the type that occurred at the Cooper Station. The Technical Specification requirements to monitor and control the neutralization number and concentrations of particulates, mercaptans, and water in fuel oil provide assurance that the rate of accumulation of filter-clogging corrosion products or oil degradation products will be slow.

Fuel Injector Plugging by Soluble Zinc Compounds With regard to the concern about soluble zinc soaps (principally zinc naphthe-nates), the chemical literature indicates that they have beneficial effects as combustion improvers and fungicides (Kirk-Othmer, 1978).

To provide a quantitative basis for considering the problem of soluble zinc naphthenates, the staff requested that the licensee take samples of the fuel oil in the storage tanks and have them analyzed for soluble zinc. By letter dated September 30, 1987, the licensee reported the following results:

Date Tank Zinc (ppm) 8/22/87 A 7.2 8/22/87 8 6.6 9/11/87 A 7.2 9/11/87 8 5.6 There are no specific standards for allowable limits on zinc concentration in fuel oil. The American Society for Testing and Materials (ASTM) speci-fication for allowable total concentration of inorganic constituents in Vogtle SSER 7 9-6

'No.:2 diesel fuel is.10 ppm. The licensee's letter of September 30, 1987, stated that the total inorganic material, includirig the zinc, in the fuel 01.1: tested was less than 10 ppm.

?seferences.to the use of naphthenates as "combustion improvers" that reduce the concentrations of soot, smoke, .3nd incompletely burned fuel, indicate that concentrations of metallic ,naphthenaMs (usually mixtures) in the range of 5 to 40 ppm are effective (ASME, 1975; Ocswa, 1974; and Ivanov, 1973). Higher con-centrations of up to 1300 ppm are med for high sulfur fuels (0.9%). Unfor-tunately, these studies do not provide any specific information on the long-term plating or deposition behavior of these additives on injector nozzles. It is likely, however, that more complete combustion with less soot and smoke would correspond to a lesser tendency toward deposition and plugging. In a conference telephone. call on October 6,1987, the licensee stated that an inspection of the injection nozzles after several hundred hours of diesel operation detected no signs of deposition or plugg'ing of the nozzles.

From the measured neutr'alization numbers, the equivalent concentration of zinc, dissolved as zine napht henate, can be calculated. For a neutralization number of 0.08, the correspond.ing di.ssolved zinc concentration would be approximately 47 ppm.

The fact that t.he zinc concentration in the fuel oil after storage in the Vogtle Unit 1 zinc-1 ined tanks for approximately two years is only 6 to 7 ppm indicates either a very slow reaction or a self-limiting one. It may be that naphthenic acids react at appreciable rates only with oxidized zinc com-pounds such as Zn0 and Zn (OH)2. but not with zinc metal. Another possibility is that the outer silicat.e layers 'of the coating protect the zinc in the inner coating layers from contact with naphthenic acids.

In summarizing the conside rations about dissolved zinc naphthenates, no evidence has been found that dissolved concentrations of 6 to 7 ppm zinc would tend to deposit on and plug diesel generator fuel injectors. To the contrary, some studies indicate that these concentrations of zinc naphthenate would act as combustion improvers with more complete combustion and less formation of soot and smoke. The Technical Sp'ecification limits placed on the allowable concen-trations of acidic constitue.nts and water in fuel oil serve to lessen the likelihood of the buildup of excessive concentrations of dissolved zinc.

The ASTM standard of less than 10 ppm total inorganic material in No. 2 diesel fuel oil reflects industrial experience that this level of inorganic content is acceptable. In view of the high solubility of zinc napnthenate in fuel oil and its special property of improving combustion, the ASTM limit of 10 ppm inorganic material may be unduly conserva tive in the case of zinc naphthenate.

On the basis of the new information on dissolved zinc available since the issuance of IE Circular 77-15, the staff concludes that the current levels of dissolved zinc in the diesel fuel storage tanks are acceptable.

Corrosion With regard to the effects of inorganic zine coating on the corrosion of the steel storage tanks, the staff agrees with the analysis provided by the licensee.

In industrial practice, inorganic zinc protective coatings are widely accepted as the most satisfactory way to provide long-term protection of underground steel tanks against corrosive attack by the acidic constituents of fuel oil.

The Technical Specification limits on the allowable concentrations of acidic l

Vogtle SSER 7 9-7 1

-constituents and of water prevent the accumulation of high concentrations of these corrosion-enhancing materials in the fuel oil.

The corrosion product zinc naphthenate is itself a corrosion inhibitor. It also has fungicidal activity and thus helps to control microbiological corrosion in any water phase that may collect in the storage tank sumps. These anticorrosion activities are further advantages deriving from the_ presence of the inorganic zinc tank lining.

Conclusion On the basis'of the considerations discussed above, the staff has concluded that the licensee has provided an acceptable justification that the inorganic zinc coating on the fuel storage tanks will not cdversely affect the operability and reliability of the diesel generators over the life of the plant. These con-siderations include:

new information on industrial experience with fuel oil tanks coated with inorganic zinc and on the combustion-improving properties of zinc naphthenate the addition of duplex fuel line filters to remove corrosion products or degradation products that could plug the fuel line surveillance procedures tc check the quality of the fuel oil, to monitor the differential pressure across the fuel line filter, and to inspect the diesel generator fuel injectors for zinc deposits Accordingly, License Condition 2.C(8) to Operating License NPF-68 is considered resolved. This evaluation also applies to Vogtle Unit 2.

To ensure that the fuel oil storage and delivery systems remain operable and reliable, the Technical Specifications related to fuel oil quality, including the limits on neutralization number and mercaptan content, should remain in effect. In addition, the licensee should continue to monitor the differential pressure across the filter element in the fuel line as stated in its July 13, 1987, letter. The proposed Vogtle Unit 2 Technical Specifications should include the same specifications regarding fuel _ oil quality, and Unit 2 should also monitor the differential pressure across the fuel line filter.

l' I

Vogtle SSER 7 9-8

J 11 RADIOACTIVE WASTE inNAGEMENT 11.4 Solid Waste Management System l 11.4.3 Evaluation Findings In the SER (NUREG-1137), the staff noted that it had not completed its review of the Aerojet Energy Conversion Company's (AECC's) Topical Report No. AECC-3-NP concerning the radioactive waste volume reduction system (VRS) employed at Vogtle. The staff tentatively concluded, however, based on the extent of the review of the topical report at that time, that the VRS at Vogtle was acceptable.

This, therefore, was stated to be a confirmatory item pending more detailed staff review of the topical report.

The confirmatory item associated with the VRS involved four issues. The first issue concerned completing the review of the topical report. By letter dated August 28, 1986, the staff provided its evaluation to the vendor, AECC, stating that the staff finds the report acceptable for referencing in license applica-ions. The vendor issued the approved report, Topical Report No. AECC-3-P-A, in November 1986.

The second issue dealt with potential accidents involving the VRS. By letter dated April 4, 1985, the applicant (now licensee) discussed two accidents: a .

small leak or malfunction resulting in the airborne release of a portion of the r dry product inventory of the VRS and the complete rupture of the recycle holdup tank which contains the largest inventory of significant isotopes. The appli-cant's calculation indicates that the calculated offsite doses from these acci-dents are small fractions of the numerical guide provided to meet the criterion "as low as is reasonably achievable" in Appendix I to 10 CFR Part 50. The staff finds acceptable, therefore, the resultant doses to an individual in an unrestricted area resulting from the VRS accidents.

The third issue concerned the applicant's proposal to not limit sulfur input to the VRS to 0.3% as suggested by the staff in its review of an earlier AECC re-port, Topical Report AECC-2-NP. There are no similar restrictions on the sul-fur content of feed materials in AECC-3-NP. The applicant stated that the limit is not applicable to its system because it is not constructed of stainless steel which is susceptible to acidic corrosion, active pH control was added to the Vogtle VRS to neutralize acid gases, and the vendor confirmed that for all Vogtle proposed feed rates and composition there is no acid gas problem. The staff finds the licensee's pH control provision to be acceptable to overcome potential acid gas generation.

The final issue concerned initial installation testing of the high-efficiency particulate air (HEPA) filters and charcoal adsorber as discussed in Regulatory Guide (RG) 1.140 in accordance with American National Standards Institute Stand-ard N510-1975. The applicant indicated that it would perform a visual inspec-tion before installation but that neither an accurate airflow distribution test nor dioctyl phthalate and tracer tests can be performed. AECC-3-NP stated Vogtle SSER 7 11-1

- that, based on the configuration of the cylindrical filter housing, the loca-tion of the air inlet above the first HEPA filter, and the straight-through flow configuration through single elements in series, the air flow distribution should be nearly uniform. The staff finds, therefore, that based on the filter configuration and the insignificant dose to an individual in an unrestricted area due to a VRS accident, the licensee's exceptions to RG 1.140 are acceptable.

The staff has completed its review of this confirmatory item based on the review of the accepted tc.pical report and finds that the VRS at Vogtle is acceptable in accordance with the criteria of Standard Review Plan (SRP) Section 11.4.

Therefore, this item is closed.

11.5 Process and Effluent Radiological Monitoring and Sampling Systems 11.5.3 TMI-2 Action Plan Requirements

• By letter dated March 9, 1987, the licensee submitted the results of an exami-nation for potential leakage outside containment to fulfill the requirements of NUREG-0737, Item III.D.1.1 as stipulated in license condition 2.C(8)a of the Vogtle Unit 1 low power license (NPF-61) dated January 16, 1987. In that letter, the licensee stated that a supplemental report would be submitted following completion of testing of the positive displacement pump and valve 1HV-3258 of the post-accident sampling system. In Section 11.5.3 of SSER 6, the staff concluded that a subsequent submittal on the above items would be acceptable and that the low power license condition was satisfied.

By letter dated April 20, 1987, the licensee submitted its supplemental report 1

eakage measurement of the positive displacement pump and valve 1HV-3258.

The licensee indicated that no leakage was detected from either the pump or the valve. On the basis of its review of the licensee's April 20 submittal, the staff concludes that the requirements of NUREG-0737, Item III.D.1.1 are fully satisfied.

QThis evaluation was previously provided to Georgia Power Company by letter dated May 19, 1987.

Vogtle SSER 7 11-2

l

)

l l

14 INITIAL TEST PROGRAM

• In the SER dated June 1985, the staff concluded that the applicant's (now licensee) Initial Test Program was acceptable. In SSER 5 dated January 1987, the staff concluded that certain changes to the Initial Test Program were acceptable. Since that SSER, the licensee has made further changes to the Vogtle Unit 1 Initial Test Program described in letters dated May 21, June 5, June 19 (2 letters), September 4, and' October 2, 1987 which were submitted in accordance.with license condition 2.C(3).

By letter dated May 21, 1987, the licensee modified the Process and Effluent Radiation Monitoring System Test (FSAR Section 14.2.8.2.28) to specifically address those monitors that either perform safety-related functions or provide safety-related diagnostic indications. Because the substance of this test has not changed, the staff finds this modification acceptable.

The remainder of the changes described in the May 21, 1987, letter, as well as the changes discussed in the June 5 letter and both June 19 letters,. are minor in nature and acceptable to the staff. ,

The changes to the Initial Test Program discussed in the September 4 and October 2 submittals are each addressed below.

(1) FSAR Section 14.2.8.2.25, "Automatic Steam Generator Level Control Test" By letter dated October 2, 1987, the licensee has stated that further testing of the automatic steam generator level control system, in addition to that demonstrated during various transients conducted at 30% and 75% power, is not l planned. However, the staff requires that the automatic steam generator level J control test be conducted during the load swing test at 100% power (see Item 2 l below) in accordance with RG 1.68, Appendix A.S.s.

(2) FSAR Section 14.2.8.2.27, "Load Swing Test" RG 1.68, Appendix A.5.h.h provides an acceptable approach for each facility to demonstrate that "the dynamic response of the plant to the design load swings I for the facility...is in accordance with design." In FSAR Sections 14.2.8.2.27, Load Swing Test, and 14.2.1, the licensee adequately described and committed to perform such tests before commercial operation. By letter dated October 2, 1987, the licensee has deleted the load swing from 100% power test. The staff finds no basis for deleting this test. This test provides an acceptable approach for

{

demonstrating the acceptable plant response in accordance with RG 1.68, Appen-dix A.5.h.h and further was used as a basis by the staff to allow the licensee exemption from demonstrating acceptable plant response to the most severe credible feedwater temperature reduction in accordance with RG 1.68, Appen-dix A.S.k.k (FSAR Section 1.9.68.2). It is the staf f's position that the

• This evaluation was previously provided to Georgia Power Company by letter dated October 8, 1987.

Vogtle SSER 7 14-1

licensee conduct a -10% load swing from 100% power test and a subsequent +10%

load swing test from 90% power as soon as practicable but not later than October 31, 1987, in accordance with FSAR Sections 1.9.68.2 and 14.2.8.2.27 and RG 1.68, Appendix A.5.h.h and A.S.k.k.

(3) FSAR Section 14.2.8.2.52, "Large Load Reduction Test" FSAR Section 14.2.12.2.18, "Large Load Reduction Test," describes 50% load re-ductions from various power levels. By letter dated October 2, 1987, the li-censee deleted the 50% load reduction from 100% power test. The 50% load reduc-tion test from full power is not a specifically required test, and therefore, the staff finds this acceptable.

(4) FSAR Section 14.2.8.2.54, "Steam Generator Moisture Carryover Test" By letter dated September 4, 1987, the licensee stated that the referenced test cannot be completed without placing the secondary plant polishing system out of service for 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, which the secondary plant chemistry is unable to support at this time. The steam generator moisture carryover test is not a specifically required test and, therefore, does not have to be conducted during the initial test program. The staff finds modification of this test acceptable.

(5) FSAR 3ection 14.2.8.2.48, "Thermal Expansion Test" By letter dated October 2, 1987, the licensee deferred the verification that dur-ing cooldown, plant components return to their approximate baseline cold position until entering cold shutdown on October 12, 1987, as part of the planned main-tenance outage. Although this test could have been performed during conduct of the Remote Shutdown Preoperational Test (FSAR Section 14.2.8.1.105) performed during the initial plant test program, deferral of this portion of the test does not impact the health and safety of the public. The staff finds this change acceptable.

(6) FSAR Section 14.2.8.2.43, "Dynamic Response Test" By letter dated September 4, 1987, the licensee deferred the verification of main steam system piping dynamic response to the rapid closure of the turbine stop valves from 100% povar. In its October 2, 1987, letter, the licensee in-dicated that it plans to conduct this verification during a plant trip from full power on October 9, 1987, to be conducted in conjunction with the planned maintenance outage. Although this test could have been performed during conduct of the Plant Trip From 100% Power Test (FSAR Section 14.2.8.2.53) performed dur-ing the initial plant test program, deferral of this test does not impact the health and safety of the public. The staff finds this change acceptable.

(7) FSAR Section 14.2.8.2.50, "Power Ascension Test Sequence" By letters dated September 4 and October 2, 1987, the licensee deferred comple-tion of the power ascension test sequence documentation pending completion of the power ascension testing. This is acceptable to the staff contingent upon resolution of the items in this evaluation.

Vogtle SSER 7 14-2

(8) FSAR Section 14.2.8.2.55, "Plant Performance Test" By letter dated October 2, 1987, the licensee stated that adjustments will continue to be made to plant systems to improve plant efficiency but that no further testing as part of the power ascension _ test program is planned.

Continued conduct of this test does not impact the health and safety of the public, and the staff finds this change acceptable.

By letter dated October 8, 1987, the staff directed the licensee to conduct the tests identified in Items 1, 2, 5, and 6 as soon as practicable but nut later than October 31, 1987.

By letter dated October 27, 1987,. the licensee informed the staff that a failed reactor coolant pump motor would prevent the unit from starting up after the  :

planned maintenance outage until about October 30, 1987, rather than the original schedule of October 22, 1987. Because of the delay, the licensee indicated that it would not be able to complete the remaining startup tests (load swing test at 100% power and automatic steam generator level control test) by October 31, 1987, as directed in the staff's letter of October 8,1987. The licensee committed to complete the tests within 3 to 5 days of reaching 100% power after the outage.

The staff concludes this schedule is acceptable. Subsequently, the resident inspectors indicated that the licensee initiated the test on November 9, 1987, and completed it early on November 10, 1987.

Vogtle SSER 7 14-3 l

/

l 15 ACCIDENT ANALYSES  ;

15.8 Anticipated Transients Without Scram i

Generic Letter 83-28 was issued by the staff on July 8, 1983. It describes l intermediate-tera actions to be_taken by licensees and applicants to address i the generic issue raised by the two anticipated transients without scram that 1 occurred at Unit 1 of Salem Nuclear Power Plant. l Generic Let ter 83-28, Item 2.1*

Item 2.1 requires the licensee to confirm that all reactor trip system (RTS) components are identifiea, classified, and treated as safety, related and that an effective vendor interface program is established ~for these components as indicated in the following statement:

Licensees and applicants shall confirm that all. components whose functioning is required to trip the reactor are identified as safety-related on documents, procedures, and information handling systems used in the plant to control safety-related activities, including maintenance, work orders, aid parts replacement. In addition, for these components, licensees and applicants shall establish, implement and maintain a continuing program to ensure I that the vendor information is comple te, current and controlled l throughout the life of the plant, ano appropriately referenced or incorporated in plant instructions and procedures.

The applicant (now licensee) responded tc the requirements of Item 2.1 by letters dated November 8, 1983, and May 20, 1985. The May 20 submittal was in response to the staff's request.for additional in"ormation dated March 18, 1985.

In the initial submittal, the applicant :ommitted to meeting the staff position regarding equipment classification and tie vendor interface program. In the latter submittal, the applicant stated t1at the RTS components are indicated as safety related in the Vogtle FSAR and had been identified as safety related on the applicable electrical diagrams and in the equipment index, that mainte-nance activities and work orders involvirg safety-related components were desig-nated as such on associated documents, and that procedural controls were estab-lished to ensure that maintenance and procurement activities associated with safety-related components would be treated as safety-related activities.

For the vendor interface program, the applicant stated that a Vogtle ope, rating experience program had established controls to ensure that Westinghouse (nuclear steam supply system (NSSS)) technical bulletins used to communicate technical-

• This evaluation was previously provided to Georgia Power Company by letter dated July 29, 1987.

Vogtle SSER 7 15-1

l l

l information and recommendations are reviewed and controlled for the life of the plant, and that these controls contain provisions to ensure positive feedback to Westinghouse. .

1 On the basis of its review of these responses, the staff finds that the licensee's statements confirm that a program exists for identifying, classify-ing, and treating components that are required for performance of the reactor trip function as safety related. Further, a program exists to ensure that Westinghouse (NSSS) technical bulletins are reviewed and controlled for the life of the plant, and that these controls.contain provisions to ensure posi-tive feedback to Westinghouse. This program meets the requirements of Item 2.1 of Generic. Letter 83-28, and is therefore acceptable. Thus,-Item 2.1 is resolved for both Units 1 and 2.

Generic Letter 83-23, Items 3.1.1, 3.1.2, 3.2.1, 3.2.2, and 4.5.1 By letters dated November 8, 1983 and August 26, 1986, the applicant provided information regarding compliance with Items 3.1.1, 3.1.2, 3.2.1, 3.2.2, and 4.5.1 of Generic Letter 83-28. The staff evaluated the licensee's responses against the NRC positions described in the generic letter for completeness and adequacy. The staff found the applicant's responses incomplete and required additional information to determine acceptability. These deficiencies were transmitted to the applicant by letter dated December 31, 1986, and in SSER 5.

The licensee's supplemental responses to Items 3.1.1, 3.1.2, 3.2.1, 3.2.2, and 4.5.1, submitted by letters dated January 15 and June 9, 1987, were reviewed and found acceptable.

Delineated below are the results of the staff's evaluations and a brief summary of the licensee's supplemental responses:*

Item 3.1.1 Item 3.1.1 requires licensees and applicants to submit the results of their re-view of test procedures, maintenance procedures, and Technical Specifications to ensure that postmaintenance operability testing of safety-related components in the reactor trip system is required to be conducted and that the testing

demonstrates that the equipment is capable of performing its safety functions before being returned to service.

The licensee (then applicant) stated in its final responso dated January 15, 1987, that procedures had been established which require postmaintenance testing of the reactor trip switchgear. The response also stated that test procedures had been developed to utilize the solid-state protection system panel or the main control board trip handswitch to demonstrate operability of the reactor trip switchgear. During its review, the staff did not interpret the licensee's trip switchgear statement to encompass all safety related components in the reactor trip system. The licensee's use of "reactor trip switchgear" instead of reactor trip system components was discussed during a telephone conversation

• These evaluations were previously provided to Georgia Power Company by letter dated July 7, 1987.

Vogtle SSER 7 15-2

- _ - _ _ _ _ . - . ._ ,-->~.-w m w-. -- , , . . - - . , - ,

i between the licensee and the staff on June 1, 1987. The licensee's representa-tive stated that the term "reactor trip switchgear" meant all safety-related components in the reactor trip system. This was confirmed by letter dated June 9, 1987. On this basis, the licensee's response is acceptable.

Item 3.1.2 Item 3.1.2 requires licensees and applicants to submit the results of their check of vendor and engineering recommendations to ensure that any appropriate test guidance is included in the test and maintenance procedures or the Technical Specifications, where required.

Tht. licensee's (then applicant) supplemental response to Item 3.1.2, dated January 15, 1987, stated that procedures are written referencing vendor manuals, if applicable, and when procedures are reviewed, the review criteria requires that the procedure be reviewed against applicable vendor manuals. The licensee also indicated that engineering and vendor recommendations were checked to ensure that appropriate test guidance has been included in the test and mainten-ance procedures or the Technical-Specifications. The licensee's response to Item 3.1.2 is acceptable.

Item 3.2.1 Item 3.2.1 requires licensees and applicants to submit a report documenting the extending of test and maintenance procedures and Technical Specifications review to ensure that postmaintenance operability testing of all safety-related equipment is required to be conducted and that the testing demonstrates that the equipment is capable of performing its safety functions before being returned to service.

The licensee's (then applicant) supplemental response to Item 3.2.1, dated January 15, 1987, stated that maintenance of safety-related systems / components is con-trolled and processed via Maintenance Work Order procedures. These proce-dures provide controls that require postmaintenance testing of safety-related systems / components to prove their operability. The licensee also stated that it has completed a review of test and maintenance proceaures and appropriate Technical Specifications to ensure that the testing demonstrates that the equip-ment is capable of performing its safety function. The licensee's response to Item 3.2.1 is acceptable.

Item 3.2.2 Item 3.2.2 requires licensees and applicants to submit the results of their check of vendor and engineering recommendations to ensure that any appropriate test guidance is included in the test and maintenance procedures or the Technical Specifications, where required.

The licensee's response to Item 3.2.2, dated January 15, 1987, states that procedures are written referencing vendor manuals and when procedures are reviewed they are checked against the applicable manual. The licensee indi-cated that vendor manuals are controlled by Administrative Procedure 00108-C and that vendor and engineering recommendations are reviewed and are included in the test and maintenance procedures or the Technical Specifications. The licensee's response to Item 3.2.1 is acceptable.

Vogtle SSER 7 15-3

Item-4.5.1 Item 4.5.1-requires that online functional testing of the reactor trip system including _ independent testing of the diverse trip features be. performed. The breaker undervoltage and' shunt trip features in. Westinghouse plants should be included.

The licensee's (then applicant) supplemental response to Item 4.5.1, dated-January 15, 1987, states that a surveillance procedure has been developed which verifies the capability-of the undervoltage and shunt trip feature, to indepen-dently t;'ip the reactor trip breakers. The surveillance test is performed each month, and each train.is-tested at least once every 62 days on a staggered test basis. The response stated that a Westinghouse automatic ~ shunt trip panel had been added to the reactor trip switchgear cabinets-and provides the capability to independently test the undervoltage and shunt trip devices. The licensee's response to Item 4.5.1 is acceptable.

l 1 L r

Vogtle SSER 7 15-4

I APPENDIX A.

CONTINUATION OF CHRONOLOGY OF HADI0 LOGICAL REVIEW 0F V0GTLE UNITS 1 AND 2 OPERATING LICENSE REVIEW FGbruary 26, 1987 Letter from Georgia Power Company (GPC) concerning defer-ral of Technical Specification requirements - extended range neutron flux monitors.

March 2, 198/ Letter from GPC responding to miscellaneous electrical and instrumentation concerns.

March 4. 1987 Letter #rorn GPC esponding to request for additional l informa".Ich 1914 Llye to IE Bulletin 85-03. l March 6, 1987 Letter from GPC concerning Ordt 2 piping penetration  !

area filtration and exhaust system. i i March 10, 1987 Letter from GPC forwarding suppiement to response to l miscellaneous electrical and instrumentation issues.

March 13, 1987 Letter from GPC forwarding revision to Emergency Plan i irrelementing procedures.

March 16, 1987 Letter from GPC concerning slave relay testing.

March 16, 1987 Letter to GPC forwarding Facility Operating License NPF-68 authorizing full power operation.

March 17, 1987 Letter from GPC forwarding outstanding submittals list.

March 18, 1987 Letter from GPC concerning confirmatory measurements program.

March 18, 1987 Letter from GPC designating points of contact for implementation of 10 CFR 73.57.

March 20, 1987 Letter from GPC notifying staff that Unit 2 fuel load .

date has been changed to February 1989.

March 24, 1987 Letter to GPC forwarding Supplement 6 to SER. i March 27, 1987 Letter from GPC concerning Nuclear Training and )

Qualification Plan.

March 27, 1987 Letter from GPC concerning rod withdrawal limits. l Vogtle SSER 7 1 Appendix A

March 27, 1987 Letter from GPC forwarding Amendment 7 to Physical Security and Contingency Plan.

March 27, 1987 Letter from GPC concerning Security Plan revisions.

March 30, 1987 Letter from GPC concerning Physical Security Plan.

April 2, 1987 Letter from GPC concerning changes in Initial Startup Test Program.

April 6,.1987 Letter from GPC concerning security program enhancements.

-April 7, 1987 Letter to GPC requesting additional information on spent fuel pool rack seismic design (open item 16, "Spent fuel pool rack design").

April 10, 1987 Letter from GPC concerning control room preliminary environmental survey (license condition 2.C(7)c).

April 14, 1987 Letter from GPC forwarding 1987 annual financial reports.

April 17, 1987 Meeting with GPC to discuss potential proposal to apply leak-before-break technology to branch lines in Unit 2 and to remove certain Unit 2 steam generator snubbers. (Summary issued April 22, 1987.)

April 27, 1987 Letter to GPC notifying it of NRC reorganization.

April 27, 1987 Letter from GPC forwarding outstanding submittals list. j April 28, 1987 Meeting with GPC at site to discuss-the Unit 1 startup history. (Summary issued May 4, 1987.)

April 28, 1987 Letter from GPC forwarding Revision 3 of the Offsite Dose Calculation Manual.

April 29, 1987 Letter from GPC concerning Unit 2 auxiliary line pipe break elimination program.

May 4, 1987 Letter to GPC concerning control room preliminary environmental survey (license condition 2.C(7)c).

May 5, 1987 Letter from GPC forwarding revision to Emergency Plan implementing procedures.

May 6, 1987 Letter from GPC forwarding FSAR Amendment 33.

May 11, 1987 Generic Letter 87-08, "Implementation of 10 CFR 73.55 Miscellaneous Amendments and Search Requirements."

May 14, 1987 Letter from GPC forwarding outstanding submittals list.

May 21, 1987 Letter from GPC concerning changes in Initial Startup l

Test Program, I

Vogtle SSER 7 2 Appendix A

May 22, 1987 Letter to GPC concerning Unit 2 steam generator snubber reduction and auxiliary'line break elimination program.

May 22, 1987 Letter from GPC concerning SER open iten 16, "Spent fuel pool rack design."

May 22, 1987 Letter from GPC concerning settlement monitoring program.

May 22, 1987 Meeting with GPC to discuss outstanding licensing actions. (Summary issued June 5, 1987.)

May 27, 1987 Letter from GPC concerning support of cables in vertical cable trays (open item 22, "Seismic adequacy of plastic tie wraps").

May 28, 1987 Letter from GPC concerning support of cable in vertical raceways (open item 22, "Seismic adequacy of plastic tie wraps").

May 29, 1987 Letter from GPC responding to license condition 2.C(7)a regarding reactor vessel level instrumentation system for Unit 1.

June 1, 1987 Letter from GPC concerning plant safety monitoring system verification and validation.

June 1, 1987 Letter from GPC concerning pipe break criteria for flooding analyses for Unit 2.

June 1, 1987 Letter from GPC concerning Unit 2 electrical penetration filter and exhaust system.

June 2, 1987 Letter from GPC forwarding revision to Emergency Plar.

implementing procedures.

June 3, 1987 Letter from GPC concerning Generic Letter 87-06, "Periodic Verification of Leak Tight Integrity of Pressure Isolation Valves."

June 4, 198" Meeting with GPC to discuss t.he Unit 2 analysis of the steam generator snubber reduction and the leak-before-break methodology on the surge line. (Summary issued June 25, 1987.)

June 4, 1987 Generic Letter 87-09, "Sections 3.0 and 4.0 of the Standard Technical Specifications (STS) on the applicability of limiting conditions for operation and surveillance requirements."

June 4, 1987 Letter to GPC requesting additional information regarding offsite medical services.

June 5, 1987 Letter from GPC concerning changes in Initial Startup Test Program.

June 8, 1987 Letter from GPC forwarding Security Plan revision.

Vogtle SSER 7 3 Appendix A

. June _9, 1987 !LetterifromtGPC concerning.SER open item 5, "Generic Letter 183-28."

June'9, 1987 ' Letter from 'GPCiconcerning ~1987 < emergency preparedness

-exercise.

June 9, 1987 Letter fromtGPC moncerning-leak rate test final report.

June 10, 1987 , Letter from GPC concerning 1987. emergency preparedness exerc'i se.

June 12, 1987 Generic Letter.87 '10, '"Implementation of :10 CFR 73.57, Requirements for FBI Criminal; History.Checksi" June 16, 1987 Letter to GPC concerning Unit 1 operating. history.

June 17, 1987 Letter from GPC forwarding outstanding submittals list.

June 17, 1987 Letter from license forwarding Security Plan amendment.

June 19, 1987 Generic Letter 87-11, "Relaxation in Arbitrary Intermediate Pipe Rupture Requirements."

June 19, 1987 Letter from GPC concerning changes in Initial Startup Test Program, regarding flux map test.

June 19, 1987 Letter from GPC concerning changes in Initial Startup Test Program, regarding at power intercomparison of reactor protection systen inputs and plant computer outputs test.

June 23, 1987 Letter to GPC forwarding Amendment 1 to NPF-68. Amerdment 1 modifies-Technical Specifications to increase the shutdown margin requirements shown in Figure 3.1-2 and changes the title of that figure.

June 24, 1987 Letter from GPC concerning offsite medical services for Unit 2.

June 25, 1987 Letter from GPC forwarding revision to Inservice Testing Program.

June 25, 1987 Letter from GPC concerning preservice inspection summary report.

June 26, 1987 Letter from GPC concerning Unit 2 auxiliary line pipe break elimination programs.

June 29-July 1, Meeting with GPC to audit the Plant Ssfety Monitoring Sys-1987 tem Verification and Validation Program. (Summary issued July 20, 1987.)

July 1, 1987 Letter from GPC concerning Unit 2 steam generator upper support design.

Vogtle SSER 7 4 Appendix A

July 7, 1987 Letter from GPC concerning Unit 2 fire suppression system changes.

July 7, 1987 Letter to GPC concerning resolution of Generic Letter 83-28, Items 3.1.1, 3.1.2, 3.2.1, 3.2.2, and 4.5.1.

July 8, 1987 Letter from GPC concerning Unit 2 auxiliary line pipe break elimination programs.

July 9, 1987 Generic Letter 87-12, "Loss of Residual Heat Removal (RHR),

While the Reactor Coolant System (RCS) Is Partially Filled."

July 10, 1987 Letter from GPC concerning temporary Technical Speci-fication relief.

July 13, 1987 Letter from GPC concerning diesel fuel oil storage tanks coating (License Condition 2.C(8)).

July 13, 1987 Letter to GPC concerning report to the Commission on Unit 1 Readiness Review Pilot Program.

July 14, 1987 Letter to GPC concerning staff review of Offsite Dose  !

Calculation Manual, Revision 3.

July 15, 1987 Letter from GPC concerning radiological consequences of Unit 2 electrical penetration filter and exhaust system deletion.

July 15, 1987 Letter from GPC concerning program to eliminate pipe breaks in auxiliary lines at Unit 2.

July 20, 1987 Letter from GPC concerning SER open item 16, "Spent fuel pool rack design."

July 20, 1987 Letter from GPC concerning reactor vessel level instru-mentation system (license condition 2.C(7)a).

July 22, 1987 Letter from GPC forwarding "Special Report on the Unit 1 Initial Operating History."

July 23, 1987 Letter from GPC concerning radiological consequences of Unit 2 electrical penetration filter and exhaust system deletion.

July 24, 1987 Letter from GPC forwarding outstanding submittals list.

July 24, 1987 Letter to GPC forwarding emergency Amendment 2 to NPF-68.

Amendment modifies the Technical Specifications to delete references to phase "A" containment isolation on a contain-ment area high-range radiation signal from Specification 3/4.3.2 and also to correct references which are no longer applicable because of that deletion.

July 27, 1987 Letter from GPC concerning Unit 2 pipe break criteria e for flooding analyses.

Vogtle SSER 7 5 Appendix A

July 28, 1987 Letter from GPC concerning reorganization.

July 29, 1987 Letter to GPC concerning staff acceptance of response to Generic Letter 83-28, Item 2.1.

July 30, 1987 Letter from GPC concerning anticipated transients without scram modifications.

July 30, 1987 Letter to GPC concerning staff acceptance of stainless steel ties for the use in vertical cable trays (open item 22, "Seismic adequacy of plastic tie wraps").

August 3, 1987 Letter from GPC concerning settlement monitoring program.

August 4, 1987 Generic Letter 87-14, "Operator Licensing Examinations."

August 6, 1987 Letter to GPC requesting additional information on elimination of dynamic effects of postulated pressurizer surge line pipe ruptures from design basis for Unit 2.

August 6, 1987 Letter from GPC concerning Unit 2 steam generator upper support design.

Augu'st 6, 1987 Letter to GPC concerning request for withholding infor-mation from public disclosure.

l August 10, 1987 Letter from GPC concerning outstanding submittals list.

l August 12, 1987 Letter to GPC concerning conformance to Unit 1 license l condition 2.C(7)a, "Compliance with NUREG-0737, Item II.F.2." l August 14, 1987 Letter to GPC requesting additional information on the Inservice Inspection Prograin for Unit 1.

August 14, 1987 Letter to GPC concerning acceptance of revised pipe break  ;

criteria for flooding analyses for Unit 2.

August 17, 1987 Five letters to GPC concerning request for withholding information from public disclosure.

August 19, 1987 Letter to GPC concerning staff acceptance of Unit 2 electrical penetration filter and exhaust system deletion.

August 20, 1987 Letter to GPC requesting additional information on settlement monitoring program.

August 21, 1987 Letter from GPC concerning Offsite Dose Calculation Manual.

August 25, 1987 Letter to GPC requesting status of implementation of approved regulatory initiatives.

August 25, 1987 Letter to GPC concerning staff acceptance of verification and validation of plant safety monitoring system.

Vogtle SSER 7 6 Appendix A

)

August 27, 1987 Letter from GPC modifying Revision 2 to Unit 1 Inservice Testing Program.

August 31, 1987 Letter from GPC forwarding summary report of Initial Startup Test Program.

August 31, 1987 Letter from GPC forwarding Amendment 34 to FSAR.

September 1, 1987 Letter from GPC concerning plant safety monitoring system verification and validation.

September 4,1987 Letter from GPC concerning digital metal impact monitoring system.

September 4, 1987 Letter from GPC concerning status of Initial Startup Test Program.

September 8, 1987 Letter from GPC responding to NRC Bulletin 87-01, "Thinning of Pipe Walls in Nuclear Power Plants."

September 9, 1987 Letter to GPC requesting additional information on dynamic effects of postulated pressurizer surge line pipe ruptures from design basis for Unit 2.

September 14, 1987 Letter from GPC forwarding outstanding submittals list.

September 15, 1987 ASLAB issues Decision affirming LBP-86-28 and LBP-86-41.

September 15, 1987 Meeting with GPC at GPC's offices to discuss status of Vogtle and Hatch licensing actions. (Summary issued September 25, 1987.)

September 17, 1987 Letter to GPC concerning staff acceptance of PSMS V&V Program for Unit 2.

September 17, 1987 Letter from GPC forwarding correction to Offsite Dose Calculation Manual.

September 17, 1987 Letter from GPC concerning program to eliminate pipe breaks in auxiliary lines at Unit 2.

September 18, 1987 Letter from GPC responding to Generic Letter 87-12 "Loss of Residual Heat Removal (RHR) While the Reactor Coolant System (RCS) Is Partially Filled."

September 22, 1987 Letter from GPC concerning program to monitor settlement.

September 22, 1987 Letter to GPC concerning staff acceptance of the Inservice Testing Program, Revision 2, for Unit 1.

September 22, 1987 Letter to GPC concerning staff acceptance of Units 1 and 2 Offsite Dose Calculation Manual, Revision 4.

September 23, 1987 Letter to GPC concerning Special Report on the Initial Operating History of Unit 1.

Vogtle SSER 7 7 Appendix A

1 September 23, 1987 Letter to GPC granting request for withhciding information from public disclosure.

September 23, 1987 Letter to GPC concerning request for withholding infor-mation from public disclosure.

September 25, 1987 Letter from GPC concerning Corporate Emergency Plan Implementing Instruction Revision.

Septt:mber 28, 1987 Letter from GPC forwarding revision to Emergency Plan Implementing Procedures.

September 30, 1987 Letter from GPC responding to request for implementation status.

September 30, 1987 Letter from GPC concerning diesel fuel oil storage tank coating (license condition 2.C(8)).

October 2, 1987 Letter from GPC concerning status of Initial Startup Test Program.

October 6, 1987 Letter from GPC.concerning cable separation within paw:

October 7, 1987 Letter to GPC concerning staff acceptance of Unit 2 steam generator snubber reduction.

October 8, 1987 Letter to GPC concerning Unit 1 Initial Startup Test Program. ,

October 13, 1987 Letter from GPC concerning management change. [

October 15, 1987 Letter from GPC concerning diesel fuel oil storage tank coating (license condition 2.C(8)).

October 15, 1987  !

Letter to GPC concerning staff acceptance of technical "

justification regarding the adequacy of diesel fuel oil storage tank zinc coating (license condition 2.C(8)).

October 15, 1987 Letter from GPC concerning confirmatory item 27, "Bypass '

and inoperable status panel."

October 1F., 3987 Letter from GPC concerning Unit 2 auxiliary line pipe I break elimination program and forwarding WCAP-11583 s.1 e WCAP-11584. t October 16, 1987 Letter from GPC concerning Unit 2 auxiliary line pipe [

break elimination program and forwarding WCAP-11599 and .

WCAP-11600.

October 20, 1987 Letter to GPC concerning staff review of proposed modifications to' settlement monitoring ,7rogram, j October 21, 1987 Letter from GPC providing additional information on the .

Inservice Inspection Program, i

Vogtle SSER 7 8 Appendix A  !

October 26, 1987 Letter to GPC concerning staff acceptance of Unit 2 fire suppression systen changes. ,

October 27, 1987 Letter from GPC concerning reclassification of reference l' letter GN-1205, dated December 4,1986.

l October 27, 1987 Letter from GPC forwarding affidavit for reference letter l GN-429, dated October 12, 1984. 1 October 27, 1987 Letter from GPC concerning status of Initial Startup Test  ;

Program.

October 27, 1987 Letter from_GPC concerning ECCS surveillance testing - -

valve manipulations.

October 27, 1987 Letter from GPC forwarding emergency plan procedure revision.

October 29, 1987 Letter from GPC concerning steam line break outside

. containment.

November 2, 1987 Letter from GPC concerning Unit 1 Inservice Inspection Program.

November 4, 1987 Letter from GPC concerning Preservice Inspection Program, Revision 2.

i November 5, 1987 Letter to GPC concerning residual heat removal system surveillance testing.

November 6, 1987 Letter to GPC requesting additional 17 formation on Generic Letter 83-28, Item 2 2.2.

November 10, 1987 Letter from GPC concerning Unit 2 Readiness Review Program.

November 10, 1987 Letter from GPC forwarding Security Plan revisions.

November 11, 1987 Letter from GPC concerning battery room spray.

November 17, 1987 Letter to GPC granting request for withholding information from public disclosure.

November 18, 1987 Letter from GPC concerning anticipated transients without scram modifications.

November 18, 1987 Letter from GPC forwarding outstancing submittals list.

November 19, 1987 Letter from GPC forwarding Security Plan revision.

November 20, 1987 Letter to GPC forwarding Amendment 3 to NPF-68. Amendment ciodified the Technical Specifications to revise the action requirements for inoperable fuel handling building post-accident ventilation system actuation instrumentation.

Vogtle SSER 7 9 Appendix A

November 23, 1987 Letter _from GPC concerning communication system.

November 24, 1987 Letter from GPC responding to request for information on-miscellaneous amendments / search requirements.

November 30, 1987 Letter fron GPC forwarding Supplement 1 to Summary Report of Startup Test Program.

December 4,1987 Letter from GPC concerning ECCS surveillance testing -

proposed FSAR revisions.

December 7, 1987 Letter from GPC concerning correspondence service list.

December 21, 1987 Letter from GPC concerning removal of control room temporary gypsum board fire wall.

December 21, 1987 Letter from GPC concerning clarification of FSAR Section 9.5.3 - Emergency Lighting.

December 21, 1987 Letter from GPC concerning derated embed plates.

December 22, 1987 Letter from GPC forwarding revisions to Emergency Plan Procedure.

December 23, 1987 Letter from GPC concerning spent fuel racks.

December 28, 1987 Letter from GPC forwarding outstanding submittals list.

d Vogtle SSER 7 10 Appendix A

APPENDIX B REFERENCES LSME, 1975 American Society of Mechanical Engineers, Paper No. 75-WA/CD-7, R. D. Giammar et al., "The Effect of Additives in Reducing Particulate Emissions From Residual Oil Com-bustion," for meeting Nov. 30 - Dec. 4, 1975, pp. 75-86.

Generic Letter 83-28 U.S. Nuclear Regulatory Commission, "Required Actions Based on Generic Implications of Salem ATWS Events,"

Generic Letter 83-28, July 8, 1983.

Generic Letter 85-12 U.S. Nuclear Regulatory Conmission, "Implementation of TMI Action Item II.K.3.5, ' Automatic Trip of Reactor Coolant Pumps'," Generic Letter 85-12, June 28, 1985.

IBM, 1974 IBM, "Design and Code Inspections and Process Control in the Development of Programs," Technical Report 00.2763, June 10, 1974.

IE Bulletin 79-15 U.S. Nuclear Regulatory Commission, Office of Inspection and Enforcement, "Deep Draft Pump Deficiencies," Bulle-tin 79-15, July 11, 1979.

IE Bulletin 80-06 U.S. Nuclear Regulatory Commission, Office of Inspection and Enforcement, "Engineered Safety Fecture (ESF) Reset Controls,"Bulletin 80-06, March 13, 1980.

IE Circular 77-15 U.S. Nuclear Regulatory Commission, Office of Inspection and Enforcement, "Degradation of Fuel Oil Flow to the Emergency Diesel Generator," Circular 77-15, November 23, 1977.

Ivanov, 1573 K. I. Ivanov et al., "Effect of metal-containing addi-tives on the concentration of sulfur trioxide in products of the combustion of liquid sulfur-containing fuels,"

Teploenergetika, 1973, pp. 85-87.

Ki rk-Othmer,1978 R. E. Kirk and D. F. Othmer, Kirk-Othmer Encyclopedia of Chemical Technology, Third Edition, Vol. 15, pp. 749-752; Vol. 8, pp. 44-48, John Wiley and Sons, New York, 1978.

NRC, 1979 U.S. Nuclear Regulatory Commission, "Operatir.0 Technology Position for Review and Acceptance of Spent Fuel Storage and Handling Applications," Position paper (April 14, 1978), modified on January 18, 1979.

Vogtle SSER 7 1 Appendix B

NUREG-0737 U.S. Nuclear Regulatory Commission, "Clarification of THI Action Plan Requirements, NUREG-0737," November 1980.

NUREG-0781 U.S. Nuclear Regulatory Commission, "Safety Evaluation Report Related to the Operation of South Texas Project, Units 1 and 2," Supplement 4, July 1987.

NUREG-0800 U.S. Nuclear Regulatory Commission, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants," LWR Edition, July 1981.

NUREG-1061 U.S. Nuclear Regulatory Commission, "Report of the U.S.

Nuclear Regulatory Commission Piping Review Committee, Evaluation of Potential for Pipe Breaks," Vol. 3, Novem-ber 1984.

I NUREG/CR-3660 U.S. Nuclear Regulatory Commission, "Probability of Pipe Failure in Reactor Coolant Loops of Westinghouse PWR Plants," Vol. 3, "Guillotine Break Indirectly Induced by I Earthquakes," February 1985.

NUREG/CR-4263 U.S. Nuclear Regulatory Commission, "Reliability Analysis of Stiff Versus Flexible Piping, Final Project Report,"

May 1985.

NUREG/CR-4572 U.S. Nuclear Regulatory Commission, "NRC Leak-Before-Break (LBB.NRC) Analysis Method for Circumferentially Through-Wall Cracked Pipes Under Axial Plus Bending Loads," May 1966.

Ogawa, 1974 H. Ogawa, "Mineral oil, especially heavy oil, additive--

containing heavy metal naphthenates catalytically accelerating combustion," Japanese Patent 74042886, November 18, 1974.

Rabinowicz, 1976 E. Rabinowicz, "Friction Coefficients of Water-Lubricated Stainless Steels for a Spent Fuel Rack Facility," Novem-ber 5, 1976 (available in NRC Public Document Room).

WCAP-8252 Westinghouse Electric Corp., "Documentation of Selected Westinghouse Structural Analysis Computer Codes," Revi-sion 1, May 1977.

WCAP-9401-P-A Westinghouse Electric Corp., "Verification Testing and Analyses of the 17x17 Optimized Fuel Assembly," August 1981.

WCAP-10529 Westinghouse Electric Corp., "COMS, Cold Overpressure Mitigating Systems," February 1984.

WCAP-10551 Westinghouse Electric Corp. , "Technical Bases for Elini-nating Large Primary Loop Pipe Rupture as the Struct al Design Basis for Alvin W. Vogtle Units 1 and 2," May 1984.

(See WCAP-10552 for a nonproprietary version of this report.)

Vogtle SSER 7 2 Appendix B

WCAP-10552 Westinghouse Electric Corp., "Technical Bases for Elimi-nating Large Primary Loop Pipe Rupture as the Structural Design Basis for Alvin W. Vogtle Units 1 and 2," May 1984.

WCAP-11531 Westinghouse Electric Corp., "Technical Bases for Elimi-nating Pressurizer Surge Line Rupture.as the Structural Design Basis for Vogtle Unit 2," July 1987.

WCAP-11583 Westinghouse Electric Corp., "Technical Bases for Elimi-nating Accumulator Line Rupture as the Structural Design Basis for Vogtle Unit 2," October 1987 (proprietary).

WCAP-11584 Westinghouse Electric Corp. , "Technical Bases for Eliminat-ing Accumulator Line Rupture as the Structural Design Basis for Vogtle Unit 2," October 1987 (nonproprietary).

WCAP-11599 Westinghouse Electric Corp., "Technical Bases for Elimi-nating RHR Line Rupture From the Structural Design Basis for Vogtle Unit 2," October 1987 (proprietary).

WCAP-11600 Westinghouse Electric Corp., "Technical Bases for Elimi-nating RHR Line Rupture From the Structural Design Basis for Vogtle Unit 2," October 1987 (nonproprietary).

Wambach, 1987 U.S. Nuclear Regulatory Commission, Letter from T. V.

Wambach to K. W. Berry (Consumers Power Co.),

Subject:

Amendment to Provisional Operating License No. DPR-20 (TAC No. 60844), July 24, 1987.

Zech, 1985 U.S. Nuclear Regulatory Commission, Letter from G. Zech to J. Gallagher (Westinghouse), January 7, 1985.

I l

t l

i I

l Vogtle SSER 7 3 Appendix B >

l

i APPENDIX D ACs0NYMS AND INITIALISMS AECC Aerojet Energy Conversion Company AFW auxiliary feedwater AISI American Iron and Steel Institute ANCO ANC0 Engineers, Inc.

ANSI American National Standards Institute ASLAB Atomic Safety and Licensing Appeal Board ASME American Society of Mechanical Engineers ASTM American Society for Testing and Materials BTP branch technical position CFR Code of Federal Regulations CMTR certified material test report DEGB double-ended guillotine break DNB departure from nucleate boiling ECCS emergency core cooling system EPFE electrical penetration filter and exhaust ESF engineered safety feature FSAR Final Safety Analysis Report GDC general design criterion (a)

GPC Georgia Power Company GTAW gas tungsten arc weld HEPA high efficiency particulate air HVAC heating, ventilation, and air conditioning IE Office of Inspection and Enforcement IGSCC intergranular stress corrosion cracking IN Information Notice IST inservice testing LBB leak before break LOCA loss-of-coolant accident .

MSLB main steam line break NFPA National Fire Protection Association NRC U.S. Nuclear Regulatory Commission NSCW nuclear service cooling water NSSS nuclear steam supply system NTOL near-term operating license Vogtle SSER 7 1 Appendix 0

OBE operating basis earthquake P&ID piping and instrumentatterv diagram PORY pcwer-operated relief valve h

PROM programmable read only memory PSMS plant safety monitoring system PWR pressurized water reactor QDPS qualified display processing system RCL reactor coolant loop RCS reactor coolant system RG regulatory guide-RHR residual heat removal RTS reactor trip system RVHVS reactor vessel head vent system RVLIS reactor vessel level instrumentation system RWST refueling water storage tank SAW submerged arc weld SER Safety Evaluation Report SGTR steam generator tube rupture SMAW shielded metal arc weld SPDS safety parameter display system SRP Standard Review Plan SRSS square-root-sum-of-squares SSE safe shutdown earthquake SSER Supplement to Safety Evaluation Report STS Standard Technical Specifications TDI Transamerica Delaval, Inc.

TER Technical Evaluation Report TMI-2 Three Mile Island, Unit 2 TS technical specification TSC Technical Support Center VRS volume reduction system V&V verification and validation WECAN Westinghouse Electric Computer Analysis Vogtle SSER 7 2 Appendix 0

APPENDIX E NRC STAFF CONTRIBUTORS AND CONSULTANTS This supplement to the Vogtle Safety Evaluation Report is a product of the NRC staff and its consultants. The NRC staff members and consultants listed below were principal contributors to this report.

Name Title Unit D. Notley Fire Protection Engineer Chemical Engineering Branch N. Merriweather Reactor Inspector Engineering Branch, Division of Reactor Safety, Region II F. Burrows Electrical Engineer Instrumentation and Control Systems Branch D. Lasher Electrical Engineer Instrumentation and Control Systems Branch R. Ramirez Senior Human Factors Human Factors Assessment Engineer Branch S. Lee Materials Engineer Materials Engineering Branch Y. Huang Senior Mechanical Engineer Mechanical Engineering Branch H. Shaw Mechanical Engineer Mechanical Engineering Branch J. Lee Reactor Engineer (Nuclear) Plant Systems Branch W. LeFave Senior Reactor Engineer Plant Systems Branch (Nuclear)

S. Kirslis Project Engineer Project Directorate 11-3 M. Miller Project Manager Project Directorate 11-3 C. Willis Senior Health Physicist Radiation Protection (Reactor) Branch T. Huang Reactor Engineer (Nuclear) Reactor Systems Branch Vogtle SSER 7 1 Appendix E

Name Title Unit S. Sun Nuclear Engineer Reactor Systems Branch L. Beltracchi Senior Human Factors Reliability and Human Engineeer Factors Branch, RES J. Ma Structural Engineer Structural and Geotech-nical Engineering Branch R. Pichumani Civil Engineer Structural and Geotech-nical-Engineering Branch N. Romney Civil Engineer Structural and Geotech-nical Engineering Branch Consultants R. Gruel, Battelle Pacific Northwest Laboratories F. Farmer, Idaho National Engineering Laboratory H. Rockhold, Idaho National Engineering Laboratory J. Frawley, SoHaR, Inc.

l i

r I

, Vogtle SSER 7 2 Appendix E

APPENDIX K ERRATA TO THE SAFETY EVALUATION REPORT AND ITS SUPPLEMENTS Page Paragraph

• Line Change SER 1-13 --

17 Change "12.3.4.2" to "12.5.2" 13-11 3 6 Change "appliant's" to "applicant's" Supplement 5 1-2 -- --

After-Item (8) add "(9) discusses a schedular exemption regarding the spent fuel pool (see Section 9.1.2)"

and renumber the items that follow accordingly Supplement 6 iii 1 2 Change "Georigia" to "Georgia"

• Full paragraph Vogtle SSER 7 1 Appendix K

APPENDIX W LETTER REPORT,.

TECHNICAL EVALUATION OF REVISION 2 CHANGES FOR PUMP AND VALVE INSERVICE TESTING PROGRAM, V0GTLE ELECTRIC GENERATING PLANT, UNIT 1 Pump Relief Request The licensee has requested relief from the Section XI (1983 Edition through Summer 1983 Addenda), IWP-4510 requirement that the direction of vibration mea-surements be in the horizontal or vertical direction for component cooling water pumps P4-001, P4-002, P4-003, P4-004, P4-005, and P4-006; safety _ injection pumps P6-003 and P6-004; centrifugal charging pumps P6-002 and P6-003; and auxiliary feedwater pumps P4-001,-P4-002, and P4-003, and has proposed _that two permanently mounted vibration transducers on each pump installed 45 degrees from the vertical and 90 degrees from each other be utilized for vibration measurements.

Licensee's Basis for Requesting Relief. Each of these pumps has two per-manently mounted vibration transducers (or pickups) installed 45 degrees from the vertical and 90 degrees from each other. Both transducers are used in the quarterly pump testing. Any increase in pump vibration in either the horizontal or vertical direction is detected by both transducers.

Evaluation. Utilizing two permanently mounted vibration transducers.in-stalled 45 degrees from the vertical and 90 degrees from each other to measure vibration for these pumps will give infurmation equivalent to or better than the information obtained from the utilization of one measurement point in the horizontal or vertical direction as required by the Code. Based on the deter-mination that it would be burdensome to the licensee if the Code requirement were imposed and that the licensee's proposed alternative testing will detect vibration changes in a manner equal to or better than the Code requirement, relief may be granted as requested.

(pages 2-4, 2-5, 2-8, 2-10, and 3-4 in the Vogtle IST Program Manual)

NOTE: The parenthesized page numbers are those of the Vogtle IST Program Manual that have been changed.

Additional Cold Shutdown Justifications for Valves Charging pump alternate miniflow isolation valves HV-8508A and HV-8508B (category B) cannot be exercised during power operation since the valves are interlocked with the volume control tank discharge valves LV-01128 and LV-0112C and these valves cannot be exercised during power operation due to interruption of pressurizer level control and possible subsequent plant shutdown. These valves will be full-stroke exercised during cold shutdowns and refueling outages (pages 4-27 and 6-38).

Vogtle SSER 7 1 Appendix W

Boric acid transfer pump discharge check valves U4-284 and U4-299 (cate-gory C) cannot be full-stroke exercised during power operation as full flow would adversely affect RCS boron concentration which could result in plant shut-down. These valves will be partial-stroke exercised quarterly and full-stroke exercised during cold shutdowns and refueling outages (pages 4-29 and 6-34).

Residual heat removal (RHR) pump discharge check valves U6-009 and V6-010 (category C) cannot be exercised during power operation as the RHR pumps cannot overcome RCS operating pressure. These valves cannot be exercised with full flow to the refueling water storage tank as the required valve lineup would place the plant in an unanalyzed condition outside its established design basis.

These valves will be partial-stroke exercised quarterly and full-stroke exercised during cold shutdowns and refueling outages (pages 4-23 and 6-37).

RHR pump suction from the refueling water storage tank (RWST) check valves06-001 and U6-002 (category C) cannot be exercised during power operation as the required valve lineup would place the plant in an unanalyzed condition outside its established design basis (see IE Information Notice No. 87-01). These valves will be full-stroke exercised during cold shutdowns and refueling outages (pages 4-23 and 6-36).

RHR pump discharge cross-connect isolation valves HV-8716A and HV-8716B (category B) cannot be exercised during power operation as failure in the closed position would place the plant in an unanalyzed condition outside its estab-lished design basis (see IE Information Notice No. 87-01). These valves will be full-stroke exercised during cold shutdowns and refueling outages (pages 4-22 and 6-35).

Auxiliary feedwater system teedwater bypass check valves V4-125, U4-126, U4-127, and U4-128 (category C) cannot be exercised during power operation as flow verification can only be verified during injection of auxiliary feedwater into the steam generators during cold shutdown. These valves will be full-stroke exercised during cold shutdowns and refueling outages (pages 4-44 and 6-33).

Other Program Revisions Not Addressed in TER Concerning pump relief request 3, the boric acid pump suction pressure gages were identified in revision 1 to have a range of 0 to 15 psig. The actual range of these gages is -15 to 15 psig and the pump reli=l request was changed to reflect this. This change has no programmatic effect upon pump relief request 3 and this relief request will not have to be re evaluated (page 3-3).

A note was added to pump relief request 2 to indicate that Supplement No. 6 of the Safety Evaluation Report requires that instruments to measure i

the Code required flow rate be installed before restart following the first refueling outage. This change has no programmatic effect upon pump relief request 2 and this relief request will not have to be re evaluated (page 3-2).

The specific reference to the PORVs for valve relief request 3 has been deleted in order to make this relief request for rapid acting valves generic.

This change has no programmatic effect upon valve relief request 3 and this 1

relief request will not have to be re-evaluated (pages 4-7 and 5-3).

Vogtle 5:;ER 7 2 Appendix W

i The closed safety position was deleted for RHR pump discharge check valves U6-009 and U6-010 as these valves are not required to close to perform a safety '

function. RHR pump miniflow valves FV-0610 and FV-0611 are normally open and allow flow to the suction side of the pumps regardless of the position of valves U6-009 and U6-010 (page 4-23).

The quarterly reverse flow closure testing of auxiliary feedwater to steam generator check valves V4-113, U4-114, U4-115, and U4-116 has been added (page 4-43).

The quarterly forward flow operability testing for chemical and volu e control to regenerative heat exchanger check valve V6-032 has been added (pages 4-28 and 5-16).

The program was changed to indicate that safety-related chillers chilled water cooler pump check valves U4-186 and U4-187 are normally closed and that their safety position is open (page 4-54).

A P&ID revision which relocated valves HV-9378 and U4-049 to P&ID 1X4DB186-4 necessitated an editorial change (page 4-60).

l The program was changed to indicate that sample valves HV-8208, HV-8209, HV-8211, and HV-8212 are normally closed instead of normally open. Sample valves HV-8211 and HV-8212 have been replaced with one inch valves (page 4-61).

Valve relief request 1 was withdrawn as per Supplement No. 6 of the Safety Evaluation Report. References to this relief request were deleted from the valve tables and valve relief request section where appropriate (pages 4-5, 4-6, 4-7, 4-11, 4-12, 4-13, 4-24, 4-26, 4-27, 4-28, 4-33, 4-34, 4-35, 4-36, 4-41, 4-45, 4-49, 4-50, 4-57, 4-60, and 5-1).

1 I

Vogtle SSER 7 3 Appendix W

f ga;ecau ns v s. vett7.m E vu. von, cou .u.o= , xiaca r *vwn m v rioc. n o a.. . 7 E"3NE BIBUOCRAPHIC DATA SHEET -1137 Supplement No. 7 .

sit th TavCir0Ns talgtest 3 Tifle AND 5vef aTLE 3LeavtSLA%s [

Safcty Evaluat Report related to the Operation of j Vogtle Electric nerating Plant, Units 1 and 2 **

4 OATt atecgcowettTto wo,,- ,t.a

. 4.vT o ,s, January f?p j 1988

.pttaeroas,uvto wo~ rf vs.a g

et .oawi~o o s.~ir.:.cw 4=t =o umis oalu<, e,c ,

Janua[ 1988 e eaoacrpn= weas v~.1 =vona Division of Reactor Proje I/II fca*=r~vuota Office of Nuclear Reactor R lation **is U.S. Nuclear Regulatory Comm:. ion Wschington, D. C. 20555 '

10 S*o%$0mi%s oacagigatsom gawl 4%D w A:Ls4G Aoomass ti te ceser it. i,PtO.mLPo#T Same as 7 above ,

e PlaioO CovimED f,ac4sw ses.s, y

13 $UPPLt ut%f am y 4CTil -

Portains to Docket Nos. 50-424 and 50-42 13 L8 5 7 m a C f #200 eere, or e, In June 1985, the staff of the Nuclear Reg ory Commission issued its Safety Evaluation R: port (NUREG-1137) regarding the applicati of Georgia Power Company, Municipal Electric Authority of Georgia, Oglethorpe Pc,wer Cor tion, and the City of Dalton, Georgia, for licenses to operate Vogtle Electric Gene ti Plant, Units 1 and 2 (Docket Nos. 50-424 and 50-425). Supplement 1 to NUREG- 073 as 1 'ued by the staff in October 1985, Supple-ment 2 was issued in May 1986, Supplem t 3 wa ssued in August 1986, Supplement 4 was iacued in December 1986, Supplement *

.*as issue k n January 1987, and Supplement 6 was issued in March 1987. The facility .i located i urke County, Georgia, approximately 26 miles south-southeast of Augusta, orgia, and on e Savannah River.

This seventh supplement to NUREG 137 provides rece information regarding resolution of some of the open and confirmato items that remaine~ unresolved following issuance of Supplement 6, and documents c lotion of several Un. .1 license conditions, s

4. ooc - s t . s . L .s . . . t . . . , sc a ,,v o.:

Vogtle Electric Generating Plant settlement ,'la'g,',';"

monitoring, pipe str s, leak-before-break technoloqv, steam g era tor snubber reduction, nservice Testing Program, residual heat ren, al system, Unlimited electrical penetr ion filter and exhaust system, slave relays, lant safety system, fire suo ession system, ootential leakage, and delay of nitial '

% W A V P.s W 4 . w, Unc [Ta',ssified 3

II44 empert, Unclassified o una o. .. cts il EA (t

7-ax-

r. ~

, .c c... . .w . o. 1 a ti, m -

y,< a

s

;;splf?q:. , *  ; _ f* .G.pyg; - ,'~ ,

~

. 4 s

,w_

. ?,m. . ,

. x

,,n: ,

~

, 3:['- e l)f 4.

a

.4 s

+

ts, 73..>_~ ','^

-1 vi;' . UNITED STATESb W- ?.'. L >

u..

> ~'

4~ riast cuss uAe s :2- 1 t NU' CLEAR REGULATORY COMMISSION - - . - ?Il

. Postmor * *iss eu6 ~ -c4 c if' 'I

> i. WASHINGTON,- D.C. 205559' t'* -

u.

""C"

.j::D -

, ~ . . ,m a

.. g s

% 4. 5, r s. /

+

.. PERMIT h 047, ' t

'O.

,:)q;e

,. . . . + n

~

.e: "': ~

. 4 OFFICIAL BUSINESS : -

M -' ~ 4 2LF

' * "PENALTY FOR PRIVATE USFl$300 --

• F r ,

^?5 3 A r c:

,R

{+ k-p 4 ,.

N -

, , .' (a ,

,q -

. ~

,7 77 1 13, . - 2 a_. 4 2 -'

' ,' , '_ ,f

_j t

3 , p , o '. i a p . ;: R -

W- J

<4 ~- ,y , .; , a.

• '- T .g g . .. ,

g ob Co

', m ; '

I e .' T l

+

'25

.m.

2

.." j J 1 m, y

,Cl

.4-0- {*

.: -4 ? 3

.z:

'm. ",

O?

m -

m 'I 33 3 4

O C Z-

- go' l n 3

'i. -4 m

- Co < : 4 a0 _

s >O z4r ~ i -

. Om.

~

- t4 m f~ '

m-

.O.

' -4  ;

33. =

. 5

'O m-2'

. m-2'

..4. . .

2 g-

~'T r* 7

> '3

-2 m

-4 m E

c- i 2

C-

D a (D >

. CO

- CQ a

'E R

m

.. -