ML11364A031

Updated Final Safety Analysis Report Amendment 23

ML11364A031
Person / Time
Site:	Sequoyah
Issue date:	12/14/2011
From:	James Shea Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML11364A031 (197)

Text

Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402 December 14, 2011 10 CFR 50.4 10 CFR 50.71(e)

ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Sequoyah Nuclear Plant, Units 1 and 2 Facility Operating License Nos. DPR-77 and DPR-79 NRC Docket Nos. 50-327 and 50-328

Subject:

Updated Final Safety Analysis Report Amendment 23 In accordance with 10 CFR 50.71 (e), enclosed is Amendment 23 to the Sequoyah Nuclear Plant Updated Final Safety Analysis Report. Amendment 23 reflects changes and analyses made since the issuance of Amendment 22 on May 24, 2010.

This letter certifies that the information provided in the enclosed Amendment 23 accurately reflects the information and analyses from the changes made since the issuance of the previous amendment.

There are no regulatory commitments contained in this letter. If you have any questions concerning this submittal, please call G. M. Cook at (423) 843-7170.

I declare under penalty of perjury that the foregoing is true and correct. Executed on this 14t day of December 2011.

Resp 'lly, J J. hea M nager, Corporate Nuclear Licensing

Enclosure:

Updated Final Safety Analysis Report (UFSAR) Amendment 23 cc (Enclosure):

NRC Regional Administrator - Region II NRC Senior Resident Inspector - Sequoyah Nuclear Plant Printed on recycled paper

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE FILING INSTRUCTIONS FOR AMENDMENT 23 Remove Insert EPL pages 1 through 77 EPL pages 1 through 76 1.7-7/1.7-8 1.7-7/1.7-8 2.3-7/2.3-8 2.3-7/2.3-8 2.3-9/2.3-10 2.3-9/2.3-10 2.3-11/2.3-12 2.3-11/2.3-12 2.3-17/2.3-18 2.3-17/2.3-18 2.3-19/--- 2.3-19/---

2.4-33/2.4-34 2.4-33/2.4-34 2.4-39/2.4-40 2.4-39/2.4-40 2.4-41/2.4-42 2.4-41/2.4-42 2.4A-5/2.4A-6 2.4A-5/2.4A-6 Table 3.2.1-2 (Sheet 1)/(Sheet 2) Table 3.2.1-2 (Sheet 1)/(Sheet 2)

Table 3.2.1-2 (Sheet 3)/(Sheet 4) Table 3.2.1-2 (Sheet 3)/(Sheet 4) 3.3-3/3.3-4 3.3-3/3.3-4 3.5-23/3.5-24 3.5-23/3.5-24 3.7-23/3.7-24 3.7-23/3.7-24 3.7-41/3.7-42 3.7-41/3.7-42 3.8-1/3.8-2 3.8-1/3.8-2 3.8-3/3.8-4 3.8-3/3.8-4 3.8-77/3.8-78 3.8-77/3.8-78 3.8-79/3.8-80 3.8-79/3.8-80 3.8-107/3.8-108 3.8-107/3.8-108 5.2-1/5.2-2 5.2-1/5.2-2 5.2-25/5.2-26 5.2-25/5.2-26 6.2-5/6.2-6 6.2-5/6.2-6 6.2-57/6.2-58 6.2-57/6.2-58 6.2-75/6.2-76 6.2-75/6.2-76 6.2-85/6.2-86 6.2-85/6.2-86 Table 6.2.4-1/--- Table 6.2.4-1 (Sheet 1)/(Sheet 2)

Table 6.2.4-1 (Sheet 3)/(Sheet 4) 6.3-516.3-6 6.3-5/6.3-6 6.3-13/6.3-14 6.3-13/6.3-14 6.3-17/6.3-18 6.3-17/6.3-18 6.3-19/6.3-20 6.3-19/6.3-20 6.3-21/6.3-22 6.3-21/6.3-22 6.3-23/6.3-24 6.3-23/6.3-24 6.3-25/6.3-26 6.3-25/6.3-26 6.9-1/6.9-2 6.9-1/6.9-2 7.2-27/7.2-28 7.2-27/7.2-28 7.2-29/7.2-30 7.2-29/7.2-30 7.7-7/7.7-8 7.7-7/7.7-8 7.7-9/7.7-10 7.7-9/7.7-10 8.1-1/8.1-2 8.1-1/8.1-2 8.2-1/8.2-2 8.2-1/8.2-2 8.2-3/8.2-4 8.2-3/8.2-4 8.2-5/8.2-6 8.2-5/8.2-6 8.2-9/8.2-10 8.2-9/8.2-10 8.2-11/8.2-12 8.2-11/8.2-12 8.2-13/8.2-14 8.2-13/8.2-14 I

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE FILING INSTRUCTIONS FOR AMENDMENT 23 Remove Insert Table 8.2.1-1 (Sheet 1)/(Sheet 2) Table 8.2.1-1 (Sheet 1)/(Sheet 2)

Figure 8.3.1-17/--- Figure 8.3.1-17/---

9.1-1/9.1-2 9.1-1/9.1-2 9.3-3/9.3-4 9.3-3/9.3-4 10.4-17/10.4-18 10.4-17/10.4-18 11.4-1/11.4-2 11.4-1/11.4-2 11.4-5/11.4-6 11.4-5/11.4-6 Table 11.4.2-1 (Sheet 1)/(Sheet 2) Table 11.4.2-1 (Sheet 1)/(Sheet 2) 12.1-9/12.1-10 12.1-9/12.1-10 12.1-11/12.1-12 12.1-11/12.1-12 12.1-13/12.1-14 12.1-13/12.1-14 12.1-15/--- 12.1-15/---

15.4-13/15.4-14 15.4-13/15.4-14 FOLDOUT FIGURES Figure 1.2.3-12 Figure 1.2.3-12 Figure 2.1.2-1 Figure 2.1.2-1 Figure 2.5.1-12 Figure 2.5.1-12 Figure 3.8.4-1 Figure 3.8.4-1 Figure 7.2.1-1 Sheet 13 Figure 7.2.1-1 Sheet 13 Figure 7.2.1-1 Sheet 13A Figure 7.2.1-1 Sheet 14 Figure 7.2.1-1 Sheet 14 Figure 7.2.1-1 Sheet 14A Figure 7.2.1-1 Sheet 16 Figure 7.2.1-1 Sheet 16 Figure 8.1.2-1 Figure 8.1.2-1 Figure 8.2.1-1 Figure 8.2.1-1 Figure 8.2.1-2 Figure8.2.1-2 Figure 8.2.1-5 Figure 8.2.1-5 Figure 10.3.2-1 Figure 10.3.2-1 Figurel10.4.5-2 Figurel10.4.5-2 Figure 10.4.7-2 Figure 10.4.7-2 2

ENCLOSURE SEQUOYAH NUCLEAR PLANT UPDATED FINAL SAFETY ANALYSIS REPORT (UFSAR) AMENDMENT 23 UFSAR AMENDMENT 23 CHANGE PAGES

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 1 13 2 13 3 13 4 18 CHAPTER 1 1-1 19 1-2 17 1-3 17 1.1-1 17 1.1-2 19 1.2-1 13 1.2-2 17 1.2-3 18 1.2-4 19 1.2-5 16 1.2-6 17 1.2-7 21 1.2-8 13 1.2-9 16 1.2-10 13 1.2-11 19 Figure 1.2.3-1 13 Figure 1.2.3-2 18 Figure 1.2.3-3 13 Figure 1.2.3-4 13 Figure 1.2.3-5 13 Figure 1.2.3-6 13 Figure 1.2.3-7 13 Figure 1.2.3-8 13 Figure 1.2.3-9 13 Figure 1.2.3-10 13 Figure 1.2.3-11 18 Figure 1.2.3-12 23 Figure 1.2.3-13 18 Figure 1.2.3-14 13 Figure 1.2.3-15 13 Figure 1.2.3-16 13 Figure 1.2.3-17 13 Figure 1.2.3-18 13 Figure 1.2.3-19 18 1.3-1 13 Table 1.3.1-1 (Sheet 1) 13 Table 1.3.1-1 (Sheet 2) 13 Table 1.3.1-1 (Sheet 3) 13 Table 1.3.1-1 (Sheet 4) 13 Table 1.3.1-1 (Sheet 5) 13 Note: The Effective Amendment designation indicates the affected page was either changed as a result of the Amendment or the page number was altered as a result of the Amendment.

EPL-1

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Table 1.3.1-2 (Sheet 1) 13 Table 1.3.1-2 (Sheet 2) 13 Table 1.3.1-2 (Sheet 3) 13 Table 1.3.2-1 (Sheet 1) 18 Table 1.3.2-1 (Sheet 2) 13 Table 1.3.2-1 (Sheet 3) 13 Table 1.3.2-1 (Sheet 4) 17 Table 1.3.2-1 (Sheet 5) 13 Table 1.3.2-1 (Sheet 6) 13 Table 1.3.2-1 (Sheet 7) 13 Table 1.3.2-1 (Sheet 8) 13 Table 1.3.2-1 (Sheet 9) 18 1.4-1 18 1.5-1 13 1.5-2 13 1.5-3 13 1.5-4 13 1.5-5 13 1.5-6 13 1.5-7 13 1.5-8 13 1.5-9 13 1.5-10 13 1.5-11 13 1.5-12 13 1.5-13 13 1.5-14 13 1.6-1 17 Table 1.6.1-1 (Sheet 1) 13 Table 1.6.1-1 (Sheet 2) 13 Table 1.6.1-1 (Sheet 3) 13 Table 1.6.1-1 (Sheet 4) 13 Table 1.6.1-1 (Sheet 5) 13 Table 1.6.1-1 (Sheet 6) 13 Table 1.6.1-1 (Sheet 7) 13 Table 1.6.1-1 (Sheet 8) 13 Table 1.6.1-1 (Sheet 9) 13 Table 1.6.1-1 (Sheet 10) 13 Table 1.6.1-1 (Sheet 11) 13 Table 1.6.1-1 (Sheet 12) 17 Table 1.6.1-1 (Sheet 13) 17 1.7-1 17 1.7-2 13 1.7-3 13 1.7-4 19 1.7-5 13 1.7-6 19 1.7-7 19 1.7-8 23 1.7-9 18 1.7-10 13 EPL 2

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 1.8-1 13 CHAPTER 2 2-1 13 2-2 13 2-3 13 2-4 13 2-5 13 2-6 13 2-7 13 2-8 13 2-9 21 2-10 13 2-11 13 2-12 17 2-13 13 2-14 13 2-15 13 2-16 13 2-17 13 2-18 17 2-19 17 2-20 13 2-21 13 2.1-1 20 2.1-2 13 2.1-3 13 2.1-4 13 2.1-5 13 2.1-6 19 Table 2.1.1-1 1 Table 2.1.3-1 13 Table 2.1.3-2 13 Table 2.1.3-3 13 Table 2.1.3-4 13 Table 2.1.3-5 13 Table 2.1.3-6 13 Table 2.1.3-6a 13 Table 2.1.3-7 13 Table 2.1.3-8 13 Table 2.1.3-9 13 Table 2.1.3-10 13 Table 2.1.3-11 13 Table 2.1.3-12 13 Table 2.1.3-12a 13 Table 2.1.3-13 13 Table 2.1.3-14 13 Table 2.1.3-15 13 Table 2.1.3-16 13 Table 2.1.3-17 13 EPL 3

SEQUOYAH NUCLEAR PLANT FINAL SAFETYANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Table 2.1.3-18 13 Table 2.1.3-19 13 Table 2.1.3-20 21 Table 2.1.4-1 13 Table 2.1.4-2 13 Figure 2.1.1-1 13 Figure 2.1.1-2 20 Figure 2.1.1-3 Original Figure 2.1.2-1 23 Figure 2.1.2-2 20 Figure 2.1.3-1 Original Figure 2.1.4-1 Original Figure 2.1.4-2 Original 2.2-1 13 2.2-2 13 2.2-3 13 2.2-4 16 2.2-5 13 2.2-6 13 2.2-7 16 2.2-8 13 2.2-9 16 Table 2.2.2-1 13 Table 2.2.2-1a 13 Table 2.2.2-1b 13 Table 2.2.3-1 (Sheet 1) 13 Table 2.2.3-1 (Sheet 2) 13 Table 2.2.3-2 (Sheet 1) 13 Table 2.2.3-2 (Sheet 2) 13 Table 2.2.3-3 13 2.3-1 13 2.3-2 18 2.3-3 21 2.3-4 18 2.3-5 18 2.3-6 18 2.3-7 15 2.3-8 23 2.3-9 23 2.3-10 23 2.3-11 23 2.3-12 15 2.3-13 20 2.3-14 13 2.3-15 13 2.3-16 21 2.3-17 21 2.3-18 23 2.3-19 23 Table 2.3.2-1 13 Table 2.3.2-2 13 EPL 4

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment Table 2.3.2-3 13 Table 2.3.2-4 13 Table 2.3.2-5 13 Table 2.3.2-6 13 Table 2.3.2-7 13 Table 2.3.2-8 13 Table 2.3.2-9 13 Table 2.3.2-10 13 Table 2.3.2-11 13 Table 2.3.2-12 13 Table 2.3.2-13 13 Table 2.3.2-14 (Sheet 1) 13 Table 2.3.2-14 (Sheet 2) 13 Table 2.3.2-15 13 Table 2.3.2-16 18 Table 2.3.2-17 13 Table 2.3.2-18 13 Table 2.3.2-19 13 Table 2.3.2-20 18 Table 2.3.2-21 13 Table 2.3.2-22 13 Table 2.3.2-23 13 Table 2.3.2-24 13 Table 2.3.2-25 13 Table 2.3.2-26 13 Table 2.3.2-27 13 Table 2.3.2-28 13 Table 2.3.2-29 13 Table 2.3.2-30 13 Table 2.3.2-31 13 Table 2.3.2-32 13 Table 2.3.2-33 13 Table 2.3.2-34 13 Table 2.3.2-35 13 Table 2.3.2-36 13 Table 2.3.2-37 13 Table 2.3.2-38 13 Table 2.3.2-39 13 Table 2.3.2-40 13 Table 2.3.2-41 13 Table 2.3.2-42 13 Table 2.3.2-43 13 Table 2.3.2-44 13 Table 2.3.2-45 13 Table 2.3.2-46 13 Table 2.3.2-47 13 Table 2.3.2-48 13 Table 2.3.2-49 13 Table 2.3.2-50 13 Table 2.3.2-51 13 Table 2.3.2-52 13 EPL 5

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment Table 2.3.2-53 13 Table 2.3.2-54 13 Table 2.3.2-55 13 Table 2.3.2-56 13 Table 2.3.2-57 13 Table 2.3.2-58 13 Table 2.3.4-1 13 Table 2.3.4-2 13 Table 2.3.4-3 13 Table 2.3.4-4 13 Table 2.3.4-5 13 Table 2.3.4-6 13 Table 2.3.4-7 13 Table 2.3.4-8 13 Table 2.3.4-9 13 Table 2.3.4-10 13 Table 2.3.4-11 13 Table 2.3.4-12 13 Table 2.3.4-13 13 Table 2.3.4-14 13 Figure 2.3.1-1 Original Figure 2.3.1-2 Original Figure 2.3.2-1 Original Figure 2.3.2-2 Original Figure 2.3.2-3 1 Figure 2.3.2-4 1 Figure 2.3.2-5 1 Figure 2.3.2-6 1 Figure 2.3.2-7 1 Figure 2.3.2-8 1 Figure 2.3.2-9 1 Figure 2.3.2-10 1 Figure 2.3.2-11 1 Figure 2.3.2-12 1 Figure 2.3.2-13 1 Figure 2.3.2-14 1 Figure 2.3.2-15 1 Figure 2.3.2-16 1 Figure 2.3.2-17 1 Figure 2.3.2-18 1 Figure 2.3.2-19 1 Figure 2.3.2-20 1 Figure 2.3.2-21 1 Figure 2.3.2-22 1 Figure 2.3.2-23 (Sheet 1) Original Figure 2.3.2-23 (Sheet 2) Original Figure 2.3.2-23 (Sheet 3) Original Figure 2.3.2-23 (Sheet 4) Original Figure 2.3.2-23 (Sheet 5) Original Figure 2.3.2-23 (Sheet 6) Original Figure 2.3.2-23 (Sheet 7) Original EPL 6

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Pa_.e Amendment Figure 2.3.2-23 (Sheet 8) Original Figure 2.3.2-23 (Sheet 9) Original 2.4-1 17 2.4-2 17 2.4-3 17 2.4-4 17 2.4-5 17 2.4-6 17 2.4-7 17 2.4-8 17 2.4-9 17 2.4-10 17 2.4-11 17 2.4-12 17 2.4-13 17 2.4-14 17 2.4-15 17 2.4-16 17 2.4-17 17 2.4-18 17 2.4-19 17 2.4-20 17 2.4-21 17 2.4-22 17 2.4-23 17 2.4-24 17 2.4-25 17 2.4-26 17 2.4-27 17 2.4-28 17 2.4-29 17 2.4-30 17 2.4-31 17 2.4-32 21 2.4-33 21 2.4-34 23 2.4-35 21 2.4-36 21 2.4-37 21 2.4-38 21 2.4-39 21 2.4-40 23 2.4-41 23 2.4-42 17 2.4-43 21 Table 2.4.1-1 17 Table 2.4.1-2 17 Table 2.4.1-3 17 Table 2.4.1-4 17 Table 2.4.1-5 (Sheet 1) 17 Table 2.4.1-5 (Sheet 2) 17 EPL 7

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Table 2.4.3-1 (Sheet 1) 13 Table 2.4.3-1 (Sheet 2) 13 Table 2.4.3-2 13 Table 2.4.4-1 17 Table 2.4.4-2 13 Table 2.4.13-1 (Sheet 1) 17 Table 2.4.13-1 (Sheet 2) 17 Table 2.4.13-1 (Sheet 3) 17 Table 2.4.13-2 (Sheet 1) 17 Table 2.4.13-2 (Sheet 2) 17 Table 2.4.13-2 (Sheet 3) 17 Table 2.4.13-2 (Sheet 4) 17 Figure 2.4.1-1 Original Figure 2.4.1-2 17 Figure 2.4.1-3 (Sheet 1) 17 Figure 2.4.1-3 (Sheet 2) 17 Figure 2.4.1-3 (Sheet 3) 17 Figure 2.4.1-3 (Sheet 4) 17 Figure 2.4.1-3 (Sheet 5) 17 Figure 2.4.1-3 (Sheet 6) 17 Figure 2.4.1-3 (Sheet 7) 17 Figure 2.4.1-3 (Sheet 8) 17 Figure 2.4.1-3 (Sheet 9) 17 Figure 2.4.1-3 (Sheet 10) 17 Figure 2.4.1-3 (Sheet 11) 17 Figure 2.4.1-3 (Sheet 12) 17 Figure 2.4.1-3 (Sheet 13) 17 Figure 2.4.1-3 (Sheet 14) 17 Figure 2.4.2-1 17 Figure 2.4.3-1 17 Figure 2.4.3-2 17 Figure 2.4.3-3 17 Figure 2.4.3-4 17 Figure 2.4.3-5 17 Figure 2.4.3-6 (Sheet 1) 17 Figure 2.4.3-6 (Sheet 2) 17 Figure 2.4.3-6 (Sheet 3) 17 Figure 2.4.3-6 (Sheet 4) 17 Figure 2.4.3-6 (Sheet 5) 17 Figure 2.4.3-6 (Sheet 6) 17 Figure 2.4.3-6 (Sheet 7) 17 Figure 2.4.3-6 (Sheet 8) 17 Figure 2.4.3-6 (Sheet 9) 17 Figure 2.4.3-6 (Sheet 10) 17 Figure 2.4.3-6 (Sheet 11) 17 Figure 2.4.3-7 17 Figure 2.4.3-8 17 Figure 2.4.3-9 17 Figure 2.4.3-10 17 Figure 2.4.3-11 17 Figure 2.4.3-12 17 EPL 8

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Figure 2.4.3-13a 19 Figure 2.4.3-14 Original Figure 2.4.3-15 Original Figure 2.4.3-16 Original Figure 2.4.3-17 Original Figure 2.4.4-1 6 Figure 2.4.4-2 17 Figure 2.4.4-3 17 Figure 2.4.4-4 Original Figure 2.4.4-5 17 Figure 2.4.4-6 6 Figure 2.4.4-7 1 Figure 2.4.4-8 Original Figure 2.4.4-9 Original Figure 2.4.4-10 Original Figure 2.4.4-11 17 Figure 2.4.4-12 Original Figure 2.4.4-13 17 Figure 2.4.4-14 17 Figure 2.4.4-15 Original Figure 2.4.4-16 Original Figure 2.4.4-17 Original Figure 2.4.4-18 Original Figure 2.4.4-21 17 Figure 2.4.4-24 Original Figure 2.4.4-25 17 Figure 2.4.4-26 Original Figure 2.4.4-27 Original Figure 2.4.4-28 Original Figure 2.4.4-29 Original Figure 2.4.4-30 17 Figure 2.4.4-31 Original Figure 2.4.4-37 17 Figure 2.4.4-38 17 Figure 2.4.4-39 17 Figure 2.4.8-1 17 Figure 2.4.13-1 6 Figure 2.4.13-2 6 2.4A-i 13 2.4A-ii 13 2.4A-iii 13 2.4A-1 17 2.4A-2 17 2.4A-3 17 2.4A-4 21 2.4A-5 23 214A-6 17 2.4A-7 15 2.4A-8 13 2.4A-9 13 2.4A-10 17 EPL 9

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 2.4A-1 1 17 2.4A-12 17 2.4A-13 17 2.4A-14 17 2.4A-1 5 17 2.4A-16 17 Table 2.4A-2 17 Figure 2.4A-2 15 Figure 2.4A-3 15 Figure 2.4A-4 17 2.5-1 13 2.5-2 13 2.5-3 13 2.5-4 13 2.5-5 13 2.5-6 13 2.5-7 13 2.5-8 13 2.5-9 13 2.5-10 13 2.5-11 13 2.5-12 13 2.5-13 13 2.5-14 13 2.5-15 13 2.5-16 13 2.5-17 13 2.5-18 13 2.5-19 13 2.5-20 13 2.5-21 13 2.5-22 13 2.5-23 13 2.5-24 13 2.5-25 13 2.5-26 13 2.5-27 13 2.5-28 13 2.5-29 13 2.5-30 13 2.5-31 13 2.5-32 13 Table 2.5.1-1 13 Table 2.5.1-2 (Sheet 1) 13 Table 2.5.1-2 (Sheet 2) 13 Table 2.5.1-3 13 Table 2.5.1-4 13 Table 2.5.1-5 13 Table 2.5.1-6 13 Table 2.5.1-7 13 Table 2.5.1-8 13 EPL 10

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Table 2.5.1-9 13 Table 2.5.1-10 13 Table 2.5.1-11 (Sheet 1) 13 Table 2.5.1-11 (Sheet 2) 13 Table 2.5.1-12 13 Table 2.5.1-13 (Sheet 1) 13 Table 2.5.1-13 (Sheet 2) 13 Table 2.5.1-14 13 Table 2.5.2-1 (Sheet 1) 13 Table 2.5.2-1 (Sheet 2) 13 Table 2.5.2-1 (Sheet 3) 13 Table 2.5.2-1 (Sheet 4) 13 Table 2.5.2-1 (Sheet 5) 13 Table 2.5.2-1 (Sheet 6) 13 Figure 2.5.1-1 Original Figure 2.5.1-2 Original Figure 2.5.1-3 Original Figure 2.5.1-4 Original Figure 2.5.1-5 Original Figure 2.5.1-6 Original Figure 2.5.1-7 Original Figure 2.5.1-8 Original Figure 2.5.1-9 Original Figure 2.5.1-10 Original Figure 2.5.1-11 Original Figure 2.5.1-12 23 Figure 2.5.1-12a 13 Figure 2.5.1-12b 13 Figure 2.5.1-13 13 Figure 2.5.1-13a 13 Figure 2.5.1-14 Original Figure 2.5.1-15 Original Figure 2.5.2-1 Original Figure 2.5.2-2 Original Figure 2.5.2-3 Original Figure 2.5.2-4 Original Figure 2.5.2-5 Original Figure 2.5.2-6 Original Figure 2.5.2-7 Original Figure 2.5.2-8 Original Figure 2.5.2-9 Original Figure 2.5.2-10 Original Figure 2.5.2-11 Original Figure 2.5.2-12 Original Figure 2.5.2-13 Original Figure 2.5.2-14 Original Figure 2.5.5-1 Original Figure 2.5.6-1 6 Figure 2.5.6-2 Original 2.6-1 13 Table 2.6-1 13 EPL 11

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment CHAPTER 3 3-1 13 3-2 13 3-3 13 3-4 16 3-5 13 3-6 13 3-7 21 3-8 18 3-9 13 3-10 13 3-11 13 3-12 13 3-13 13 3-14 18 3-15 13 3-16 13 3-17 13 3-18 13 3-19 18 3-20 13 3-21 13 3.1-1 13 3.1-2 13 3.1-3 13 3.1-4 13 3.1-5 13 3.1-6 13 3.1-7 13 3.1-8 13 3.1-9 18 3.1-10 13 3.1-11 13 3.1-12 13 3.1-13 13 3.1-14 13 3.1-15 13 3.1-16 13 3.1-17 13 3.1-18 18 3.1-19 13 3.1-20 13 3.1-21 13 3.1-22 13 3.1-23 13 3.1-24 20 3.1-25 20 3.1-26 13 3.1-27 13 EPL 12

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 3.1-28 21 3.1-29 13 3.1-30 13 3.1-31 13 3.1-32 13 3.1-33 18 3.2-1 13 3.2-2 15 3.2-3 13 3.2-4 13 3.2-5 13 Table 3.2.1-1 16 Table 3.2.1-2 (Sheet 1) 23 Table 3.2.1-2 (Sheet 2) 13 Table 3.2.1-2 (Sheet 3) 13 Table 3.2.1-2 (Sheet 4) 23 Table 3.2.1-2 (Sheet 5) 13 Table 3.2.1-2 (Sheet 6) 13 Table 3.2.1-2 (Sheet 7) 13 Table 3.2.1-2 (Sheet 8) 13 Table 3.2.1-2 Notes (Sheet 9) 18 Table 3.2.1-2 Notes (Sheet 10) 19 Table 3.2.1-2 Notes (Sheet 11) 13 Table 3.2.1-3 (Sheet 1) 18 Table 3.2.1-3 (Sheet 2) 13 Table 3.2.1-3 (Sheet 3) 13 Table 3.2.1-3 (Sheet 4) 13 Table 3.2.1-3 (Sheet 5) 13 Table 3.2.2-1 13 Table 3.2.2-2 (Sheet 1) 13 Table 3.2.2-2 (Sheet 2) 13 Table 3.2.2-3 (Sheet 1) 13 Table 3.2.2-3 (Sheet 2) 13 Table 3.2.2-3 (Sheet 3) 19 3.3-1 21 3.3-2 13 3.3-3 23 3.3-4 13 Figure 3.3.2-1 Original 3.4-1 13 3.5-1 13 3.5-2 13 3.5-3 13 3.5-4 13 3.5-5 13 3.5-6 13 3.5-7 13 3.5-8 13 3.5-9 13 3.5-10 13 3.5-11 13 EPL 13

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment 3.5-12 13 3.5-13 13 3.5-14 13 3.5-15 13 3.5-16 21 3.5-17 13 3.5-18 13 3.5-19 13 3.5-20 13 3.5-21 19 3.5-22 13 3.5-23 23 3.5-24 13 Table 3.5.1-1 (Sheet 1) 13 Table 3.5.1-1 (Sheet 2) 13 Table 3.5.2-1 13 Table 3.5.5-1 13 Table 3.5.5-2 13 Table 3.5.5-3 (Sheet 1) 13 Table 3.5.5-3 (Sheet 2) 13 Table 3.5.5-3 (Sheet 3) 13 Table 3.5.5-4 13 Table 3.5.5-5 13 Figure 3.5.2-1 6 Figure 3.5.2-2 Original Figure 3.5.2-3 Original Figure 3.5.4-1 Original Figure 3.5.4-2 Original Figure 3.5.4-3 Original Figure 3.5.4-4 Original 3.6-1 18 3.6-2 13 3.6-3 13 3.6-4 13 3.6-5 13 3.6-6 13 3.6-7 13 3.6-8 13 3.6-9 18 3.6-10 13 3.6-11 13 3.6-12 13 3.6-13 13 3.6-14 13 3.6-15 13 3.6-16 13 3.6-17 13 3.6-18 18 3.6-19 18 3.6-20 13 3.6-21 13 EPL 14

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Pa e Amendment 3.6-22 13 3.6-23 13 3.6-24 13 3.6-25 18 Table 3.6.1-1 (Sheet 1) 21 Table 3.6.1-1 (Sheet 2) 21 Table 3.6.1-1 (Sheet 3) 21 Table 3.6.2-1 18 Table 3.6.7-1 18 Table 3.6.7-2 13 Table 3.6.7-3 13 Figure 3.6.1-1 13 Figure 3.6.2-1 18 Figure 3.6.4-2 Original Figure 3.6.7-1 18 Figure 3.6.7-2 18 3.7-1 13 3.7-2 17 3.7-3 13 3.7-4 13 3.7-5 13 3.7-6 13 3.7-7 13 3.7-8 13 3.7-9 13 3.7-10 18 3.7-1Oa 18 3.7-11 13 3.7-12 13 3.7-13 13 3.7-14 13 3.7-15 13 3.7-16 13 3.7-17 13 3.7-18 13 3.7-19 13 3.7-20 13 3.7-21 13 3.7-22 13 3.7-23 23 3.7-24 18 3.7-25 13 3.7-26 18 3.7-27 17 3.7-28 13 3.7-29 18 3.7-29a 18 3.7-30 13 3.7-31 13 3.7-32 13 3.7-33 13 EPL 15

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment 3.7-34 13 3.7-35 19 3.7-35a 19 3.7-36 16 3.7-37 16 3.7-38 16 3.7-39 16 3.7-40 22 3.7-41 13 3.7-42 23 Table 3.7.1-1 13 Table 3.7.1-2 13 Table 3.7.1-3 (Sheet 1) 13 Table 3.7.1-3 (Sheet 2) 13 Table 3.7.1-3A (Sheet 1) 13 Table 3.7.1-3A (Sheet 2) 13 Table 3.7.1-4 13 Table 3.7.1-5 13 Table 3.7.2-1 13 Table 3.7.2-2 (Sheet 1) 13 Table 3.7.2-2 (Sheet 2) 13 Table 3.7.2-6 13 Table 3.7.2-7 13 Table 3.7.2-10 13 Table 3.7.2-11 13 Table 3.7.2-12 13 Table 3.7.2-13 13 Table 3.7.2-14 13 Table 3.7.2-15 13 Table 3.7.2-16 13 Table 3.7.2-17 13 Table 3.7.2-18 13 Table 3.7.2-19 13 Table 3.7.2-20 13 Table 3.7.2-21 13 Table 3.7.2-22 13 Table 3.7.2-23 13 Table 3.7.2-24 13 Table 3.7.2-25 13 Table.3.7.2-26 13 Table 3.7.2-27 13 Table 3.7.2-28 13 Table 3.7.2-29 13 Table 3.7.2-30 13 Table 3.7.2-31 13 Table 3.7.2-32 13 Table 3.7.2-33 13 Table 3.7.2-34 13 Table 3.7.2-35 13 Table 3.7.2-36 13 Table 3.7.2-37 13 EPL 16

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment Table 3.7.2-38 13 Table 3.7.2-39 13 Table 3.7.2-40 13 Table 3.7.2-41 13 Table 3.7.2-42 13 Table 3.7.2-43 13 Table 3.7.2-44 13 Table 3.7.2-45 13 Figure 3.7.1-1 13 Figure 3.7.1-2 13 Figure 3.7.2-1 Original Figure 3.7.2-2 Original Figure 3.7.2-3 Original Figure 3.7.2-4 Original Figure 3.7.2-5 Original Figure 3.7.2-6 Original Figure 3.7,2-7 Original Figure 3.7.2-8 Original Figure 3.7.2-9 Original Figure 3.7,2-10 Original Figure 3.7.2-11 Original Figure 3.7.2-12 Original Figure 3.7.2-13 Original Figure 3.7.2-14 Original Figure 3.7.2-15 Original Figure 3.7.2-16 Original Figure 3.7.2-17 Original Figure 3.7.2-18 Original Figure 3.7.2-19 Original Figure 3.7.2-20 Original Figure 3.7.2-21 Original Figure 3.7.2-22 Original Figure 3.7.2-23 Original Figure 3.7.2-24 Original Figure 3.7.2-25 Original Figure 3.7.2-26 Original Figure 3.7.2-27 Original Figure 3.7.2-28 Original Figure 3.7.2-29 Original Figure 3.7.2-30 Original Figure 3.7.2-31 Original Figure 3.7.2-32 Original Figure 3.7.2-33 Original Figure 3.7.2-34 Original Figure 3.7.2-35 Original Figure 3.7.2-36 Original Figure 3.7.2-37 Original Figure 3.7.2-38 Original Figure 3.7.2-39 Original Figure 3.7.2-40 Original Figure 3.7.2-41 Original EPL 17

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Figure 3.7.2-42 Original Figure 3.7.2-43 Original Figure 3.7.2-44 Original Figure 3.7.2-45 Original Figure 3.7.2-46 Original Figure 3.7.2-47 Original Figure 3.7.2-48 6 Figure 3.7.2-49 Original Figure 3.7.2-50 Original Figure 3.7.2-51 Original Figure 3.7.2-52 Original Figure 3.7.2-53 Original Figure 3.7.2-54 6 Figure 3.7.2-55 6 Figure 3.7.2-56 6 Figure 3.7.2-57 6 Figure 3.7.2-58 6 Figure 3.7.2-59 6 Figure 3.7.2-60 6 Figure 3.7.2-61 6 Figure 3.7.2-62 6 Figure 3.7.2-63 6 Figure 3.7.2-64 6 Figure 3.7.2-65 6 Figure 3.7.2-66 6 Figure 3.7.2-67 6 Figure 3.7.2-68 6 Figure 3.7.2-69 6 Figure 3.7.2-70 6 Figure 3.7.2-71 6 Figure 3.7.2-72 6 Figure 3.7.2-73 6 Figure 3.7.2-74 6 Figure 3.7.2-75 6 Figure 3.7.2-76 6 Figure 3.7.2-77 Original Figure 3.7.2-78 Original Figure 3.7.2-79 18 3.8-1 20 3.8-2 23 3.8-3 23 3.8-4 13 3.8-5 17 3.8-6 13 3.8-7 13 3.8-8 13 3.8-9 13 3.8-10 13 3.8-11 13 3.8-12 18 3.8-13 18 EPL 18

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 3.8-14 13 3.8-15 20 3.8-16 13 3.8-17 21 3.8-18 13 3.8-19 13 3.8-20 13 3.8-21 13 3.8-22 13 3.8-23 13 3.8-24 20 3.8-25 13 3.8-26 13 3.8-27 13 3.8-28 13 3.8-29 13 3.8-30 13 3.8-31 21 3.8-32 13 3.8-33 13 3.8-34 13 3.8-35 13 3.8-36 13 3.8-37 13 3.8-38 13 3.8-39 21 3.8-40 13 3.8-41 13 3.8-42 13 3.8-43 13 3.8-44 13 3.8-45 21 3.8-46 13 3.8-47 13 3.8-48 13 3.8-49 18 3.8-50 18 3.8-51 17 3.8-52 13 3.8-53 13 3.8-54 13 3.8-55 13 3.8-56 13 3.8-57 13 3.8-58 18 3.8-58a 18 3.8-59 13 3.8-60 13 3.8-61 13 3.8-62 13 3.8-63 13 EPL 19

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 3.8-64 13 3.8-65 16 3.8-66 13 3.8-67 13 3.8-68 13 3.8-69 13 3.8-70 13 3.8-71 13 3.8-72 18 3.8-73 13 3.8-74 13 3.8-75 19 3.8-76 13 3.8-77 23 3.8-78 13 3.8-79 23 3.8-80 22 3.8-81 13 3.8-82 13 3.8-83 13 3.8-84 13 3.8-85 13 3.8-86 13 3.8-87 13 3.8-88 19 3.8-89 13 3.8-90 13 3.8-91 13 3.8-92 13 3.8-93 13 3.8-94 13 3.8-95 13 3.8-96 13 3.8-97 13 3.8-98 13 3.8-99 13 3.8-100 13 3.8-101 13 3.8-102 13 3.8-103 13 3.8-104 13 3.8-105 13 3.8-106 13 3.8-107 23 3.8-108 13 3.8-109 13 3.8-110 13 3.8-111 19 3.8-112 19 3.8-113 19 3.8-114 13 EPL 20

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Pacqe Amendment Table 3.8.1-1 13 Table 3.8.1-2 13 Table 3.8.2-1 (Sheet 1) 13 Table 3.8.2-1 (Sheet 2) 13 Table 3.8.2-2 (Sheet 1) 13 Table 3.8.2-2 (Sheet 2) 13 Table 3.8.2-2 (Sheet 3) 13 Table 3.8.3-1 13 Table 3.8.3-2 6 Table 3.8.3-2A 18 Table 3.8.3-3 13 Table 3.8.3-4 (Sheet 1) 13 Table 3.8.3-4 (Sheet 2) 13 Table 3.8.3-4 (Sheet 3) 13 Table 3.8.3-5 13 Table 3.8.3-6 13 Table 3.8.3-7 13 Table 3.8.3-8 21 Table 3.8.3-9 13 Table 3.8.3-10 (Sheet 1) 13 Table 3.8.3-10 (Sheet 2) 13 Table 3.8.3-11 13 Table 3.8.4.1 (Sheet 1) 13 Table 3.8.4-1 (Sheet 2) 21 Table 3.8.4-1 (Sheet 3) 21 Table 3.8.4-1 (Sheet 4) 13 Table 3.8.4-1 (Sheet 5) 13 Table 3.8.4-2 (Sheet 1) 13 Table 3.8.4-2 (Sheet 2) 13 Table 3.8.4-2 (Sheet 3) 13 Table 3.8.4-3 (Sheet 1) 13 Table 3.8.4-3 (Sheet 2) 13 Table 3.8.4-4 13 Table 3.8.4-5 13 Table 3.8.4-6 13 Table 3.8.4-7 13 Table 3.8.4-8 (Sheet 1) 13 Table 3.8.4-8 (Sheet 2) -13 Table 3.8.4-9 (Sheet 1) 13 Table 3.8.4-9 (Sheet 2) 13 Table 3.8.4-10 13 Table 3.8.4-11 13 Table 3.8.4-12 13 Table 3.8.4-13 13 Table 3.8.4-14 (Sheet 1) 13 Table 3.8.4-14 (Sheet 2) 13 Table 3.8.4-15 (Sheet 1) 13 Table 3.8.4-15 (Sheet 2) 13 Table 3.8.4-16 13 Table 3.8.4-17 (Sheet 1) 13 Table 3.8.4-17 (Sheet 2) 13 EPL 21

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Table 3.8.4-18 13 Table 3.8.6-1 (Sheet 1) 13 Table 3.8.6-1 (Sheet 2) 13 Table 3.8.6-2 (Sheet 1) 18 Table 3.8.6-2 (Sheet 2) 13 Figure 3.8.1-1 13 Figure 3.8.2-1 13 Figure 3.8.2-2 13 Figure 3.8.2-3 13 Figure 3.8.2-4 13 Figure 3.8.2-5 13 Figure 3.8.2-6 13 Figure 3.8.2-7 16 Figure 3.8.2-8 13 Figure 3.8.2-9 13 Figure 3.8.2-10 13 Figure 3.8.2-11 13 Figure 3.8.3-1 13 Figure 3.8.3-2 13 Figure 3.8.4-1 23 Figure 3.8.4-2 13 Figure 3.8.4-3 13 Figure 3.8.4-4 13 Figure 3.8.4-5 13 Figure 3.8.4-6 13 Figure 3.8.4-7 19 Figure 3.8.4-8 13 Figure 3.8.4-9 19 Figure 3.8.4-10 13 Figure 3.8.4-11 13 Figure 3.8.6-1 13 Figure 3.8.6-2 13 Figure 3.8.6-3 13 Figure 3.8.6-4 13 Figure 3.8.6-5 13 Figure 3.8.6-6 18 Figure 3.8.6-7 18 Figure 3.8.6-8 18 Figure 3.8.6-9 13 Figure 3.8.6-10 13 Figure 3.8.6-11 13 Figure 3.8.6-12 Original 3.8A-1 13 3.8A-2 13 Figure 3.8A-1 6 Figure 3.8A-2 6 3.8B-1 13 3.8B-2 13 3.8B-3 13 3.88-4 13 3.8B-5 13 EPL 22

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment 3.8B-6 13 3.8C-1 13 3.8C-2 13 Figure 3.8C-1 Original Figure 3.8C-2 6 Figure 3.8C-3 6 Figure 3.8C-4 6 3.8D-1 13 3.8D-2 13 3.8D-3 13 Table 3.8D-1 13 Table 3.8D-2 13 Table 3.8D-3 13 Table 3.8D-4 13 Table 3.8D-5 13 Table 3.8D-6 13 Table 3.8D-7 13 Table 3.8D-8 13 Figure 3.8D-1 Original Figure 3.8D-2 Original 3.8E-1 13 3.8E-2 13 3.8E-3 13 3.8E-4 13 3.8E-5 13 Figure 3.8E-1 Original 3.9-1 13 3.9-2 13 3.9-3 13 3.9-4 13 3.9-5 13 3.9-6 13 3.9-7 13 3.9-8 13 3.9-9 13 3.9-10 13 3.9-11 13 3.9-12 13 3.9-13 13 3.9-14 13 3.9-15 18 3.9-16 18 3.9-17 13 3.9-18 13 3.9-19 13 3.9-20 13 3.9-21 13 3.9-22 13 3.9-23 13 3.9-24 13 3.9-25 13 EPL 23

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment 3.9-26 13 3.9-27 13 3.9-28 13 3.9-29 13 3.9-30 13 3.9-31 13 3.9-32 13 3.9-33 13 3.9-34 21 3.9-35 13 3.9-36 13 3.9-37 13 3.9-38 13 3.9-39 13 3.9-40 13 3.9-41 13 3.9-42 14 Table 3.9.2-1 13 Table 3.9.2-2 13 Table 3.9.2-3 22 Table 3.9.2-3a 22 Table 3.9.2-4 (Sheet 1) 13 Table 3.9.2-4 (Sheet 2) 13 Table 3.9.2-5 (Sheet 1) 14 Table 3.9.2-5 (Sheet 2) 14 Table 3.9.3-1 13 Figure 3.9.1-1 Original Figure 3.9.1-2 Original Figure 3.9.1-3 Original Figure 3.9.1-4 Original Figure 3.9.1-5 (Sheet 1) Original Figure 3.9.1-5 (Sheet 2) Original Figure 3.9.1-6 6 Figure 3.9.1-7 Original Figure 3.9.1-8 18 Figure 3.9.2-1 10 3.10-1 13 3.10-2 13 3.10-3 13 3.10-4 13 3.10-5 13 3.10-6 13 3.10-7 13 3.10-8 13 3.10-9 13 Table 3.10.2-1 13 3.11-1 13 3.11-2 13 Table 3.11.1-1 (Sheet 1) 20 Table 3.11.1-1 (Sheet 2) 13 3.12-1 21 EPL 24

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 3.12-2 21 3.12-3 21 3.12-4 21 3.12-5 21 3.12-6 21 3.12-7 21 CHAPTER 4 4-1 13 4-2 13 4-3 13 4-4 17 4-5 13 4-6 13 4-7 13 4-8 13 4-9 16 4-10 16 4.1-1 17 4.1-2 18 4.1-3 13 Table 4.1-1 (Sheet 1) 13 Table 4.1-1 (Sheet 2) 13 Table 4.1-1 (Sheet 3) 17 Table 4.1-2 (Sheet 1) 13 Table 4.1-2 (Sheet 2) 13 Table 4.1-2 (Sheet 3) 13 Table 4.1-3 13 4.2-1 13 4.2-2 13 4.2-3 13 4.2-4 13 4.2-5 13 4.2-6 13 4.2-7 13 4.2-8 13 4.2-9 13 4.2-10 13 4.2-11 13 4.2-12 13 4.2-13 13 4.2-14 13 4.2-15 13 4.2-16 13 4.2-17 13 4.2-18 13 4.2-19 13 4.2-20 13 4.2-21 13 EPL 25

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment 4.2-22 13 4.2-23 13 4.2-24 13 4.2-25 13 4.2-26 13 4.2-27 13 4.2-28 13 4.2-29 13 4.2-30 18 4.2-31 18 4.2-32 13 4.2-33 13 4.2-34 17 4.2-35 13 4.2-36 18 4.2-37 18 4.2-38 18 4.2-39 13 4.2-40 13 4.2-41 13 4.2-42 17 4.2-43 17 4.2-44 17 4.2-45 17 4.2-46 13 4.2-47 13 4.2-48 13 4.2-49 13 4.2-50 13 4.2-51 13 4.2-52 17 4.2-53 17 Table 4.2.2-1 13 Figure 4.2.1-1 6 Figure 4.2.1-2 Original Figure 4.2.1-2A 8 Figure 4.2.1-3 Original Notes on Figure 4.2.1-3 13 Figure 4.2. 1-3A 8 Figure 4.2.1-4 Original Figure 4.2.1-5 Original Figure 4.2.1-6a Original Figure 4.2.1-6b Original Figure 4.2.1-7a 8 Figure 4.2.1-7B 8 Figure 4.2.1-7c Original Figure 4.2.1-8 Original Figure 4.2.1-9 13 Figure 4.2.1-10 13 Figure 4.2.1-11 13 Figure 4.2.1-12 13 EPL 26

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Figure 4.2.2-1 Original Figure 4.2.2-2 Original Figure 4.2.2-3 Original Figure 4.2.2-4 Original Figure 4.2.2-5 Original Figure 4.2.3-1 17 Figure 4.2.3-2 Original Figure 4.2.3-2A Original Figure 4.2.3-3 Original Figure 4.2.3-3A Original Figure 4.2.3-3B Original Figure 4.2.3-3C Original Figure 4.2.3-4 Original Figure 4.2.3-5a 10 Figure 4.2.3-5b 10 Figure 4.2.3-6 1 Figure 4.2.3-7 Original Figure 4.2.3-8 Original Figure 4.2.3-9 Original Figure 4.2.3-10 Original 4.3-1 13 4.3-2 13 4.3-3 17 4.3-4 13 4.3-5 13 4.3-6 13 4.3-7 13 4.3-8 13 4.3-9 13 4.3-10 13 4.3-11 13 4.3-12 13 4.3-13 13 4.3-14 13 4.3-15 17 4.3-16 13 4.3-17 13 4.3-18 13 4.3-19 15 4.3-20 13 4.3-21 13 4.3-22 13 4.3-23 13 4.3-24 13 4.3-25 17 4.3-26 17 4.3-27 14 4.3-28 16 4.3-29 16 4.3-30 16 4.3-31 13 EPL 27

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment 4.3-32 13 4.3-33 13 4.3-34 13 4.3-35 13 4.3-36 13 4.3-37 13 4.3-38 13 4.3-39 13 4.3-40 14 Table 4.3.2-1 (Sheet 1) 13 Table 4.3.2-1 (Sheet 2) 13 Table 4.3.2-2 13 Table 4.3.2-3 13 Table 4.3.2-4 13 Table 4.3.2-5 13 Table 4.3.2-6 13 Table 4.3.2-7 13 Table 4.3.2-8 13 Table 4.3.2-9 13 Table 4.3.2-10 13 Table 4.3.2-11 13 Figure 4.3.2-1 Original Figure 4.3.2-2 Original Figure 4.3.2-3 Original Figure 4.3.2-4 Original Figure 4.3.2-5 Original Figure 4.3.2-6 10 Figure 4.3.2-7 10 Figure 4.3.2-8 10 Figure 4.3.2-9 6 Figure 4.3.2-10 10 Figure 4.3.2-11 10 Figure 4.3.2-12 Original Figure 4.3.2-13 Original Figure 4.3.2-14 Original Figure 4.3.2-15 Original Figure 4.3.2-16 Original Figure 4.3.2-17 Original Figure 4.3.2-18 Original Figure 4.3.2-19 Original Figure 4.3.2-20 Original Figure 4.3.2-21 13 Figure 4.3.2-22 13 Figure 4.3.2-23 13 Figure 4.3.2-24 10 Figure 4.3.2-25 Original Figure 4.3.2-26 Original Figure 4.3.2-27 Original Figure 4.3.2-28 Original Figure 4.3.2-29 Original Figure 4.3.2-30 Original EPL 28

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment Figure 4.3.2-31 Original Figure 4.3.2-32 Original Figure 4.3.2-33 Original Figure 4.3.2-34 Original Figure 4.3.2-35 Original Figure 4.3.2-36 17 Figure 4.3.2-37 Original Figure 4.3.2-38 Original Figure 4.3.2-39 Original Figure 4.3.2-40 8 Figure 4.3.2-41 Original Figure 4.3.2-42 Original Figure 4.3.2-43 Original Figure 4.3.2-44 Original Figure 4.3.2-45 Original Figure 4.3.2-46 Original 4.4-1 13 4.4-2 13 4.4-3 18 4.4-4 16 4.4-5 13 4.4-6 13 4.4-7 17 4.4-8 13 4.4-9 13 4.4-10 13 4.4-11 13 4.4-12 13 4.4-13 13 4.4-14 13 4.4-15 13 4.4-16 18 4.4-17 13 4.4-18 18 4.4-19 13 4.4-20 13 4.4-21 13 4.4-22 13 4.4-23 13 4.4-24 13 4.4-25 13 4.4-26 13 4.4-27 13 4.4-28 13 4.4-29 13 4.4-30 13 4.4-31 13 4.4-32 13 4.4-33 13 4.4-34 13 4.4-35 13 EPL 29

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 4.4-36 13 Table 4.4.2-1 13 Table 4.4.2-2 13 Table 4.4.2-3 13 Figure 4.4.2-3 Original Figure 4.4.2-4 13 Figure 4.4.2-5 13 Figure 4.4.2-6 Original Figure 4.4.2-7 10 Figure 4.4.2-8 10 Figure 4.4.2-9 10 Figure 4.4.2-10 Original Figure 4.4.5-1 Original 4.5-1 18 4.5-2 18 4.5-3 17 4.5-4 17 4.5-5 13 4.5-6 17 4.5-7 21 4.5-7a 21 4.5-7b 21 4.5-8 19 4.5-9 19 4.5-10 17 4.5-11 17 4.5-12 13 4.5-13 17 4.5-14 17 4.5-15 20 4.5-16 20 4.5-17 20 4.5-18 13 4.5-19 20 4.5-20 13 4.5-21 13 4.5-22 13 4.5-23 17 4.5-24 17 4.5-25 17 4.5-26 18 4.5-27 13 4.5-28 21 4.5-29 17 4.5-30 17 4.5-31 21 4.5-32 17 4.5-33 17 4.5-34 13 4.5-35 17 4.5-36 13 EPL 30

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 4.5-37 17 4.5-38 17 4.5-39 17 4.5-40 17 4.5-41 13 4.5-42 17 4.5-43 17 4.5-44 17 4.5-45 17 4.5-46 17 4.5-47 17 4.5-48 17 4.5-49 17 4.5-50 20 4.5-51 13 4.5-52 20 4.5-53 17 4.5-54 17 4.5-55 17 4.5-56 17 4.5-57 13 4.5-58 17 4.5-59 20 Table 4.5.1-1 13 Table 4.5.1-2 17 Table 4.5.1-3 13 Table 4.5.2-1 13 Table 4.5.2-2 13 Table 4.5.3-1 17 Table 4.5.4.2-1 (Sheet 1) 18 Table 4.4.4.2-1 (Sheet 2) 18 Figure 4.5.2-1 16 Figure 4.5.2-2 13 Figure 4.5.2-3 13 Figure 4.5.2-4 13 Figure 4.5.2-5A 16 Figure 4.5.2-5B 16 Figure 4.5.2-6 16 Figure 4.5.2-7A 16 Figure 4.5.2-7B 16 Figure 4.5.2-8A 16 Figure 4.5.2-8B 16 Figure 4.5.2-9 13 Figure 4.5.2-10 13 Figure 4.5.2-11 13 Figure 4.5.2-12 13 Figure 4.5.2-13 13 Figure 4.5.2-14 13 Figure 4.5.2-15 16 Figure 4.5.4.2-7 13 Figure 4.5.4.2-8 13 EPL 31

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment Figure 4.5.4.2-9 13 CHAPTER 5 5-1 18 5-2 18 5-3 18 5-4 18 5-5 18 5-6 13 5-7 18 5-8 18 5-9 13 5.1-1 18 5.1-2 18 5.1-3 13 5.1-4 20 5.1-4a 20 5.1-5 13 5.1-6 15 5.1-7 15 5.1-8 20 Table 5.1-1 (Sheet 1) 20 Table 5.1-1 (Sheet 2) 18 Figure 5.1-1 15 Figure 5.1-2 13 Figure 5.1-3 13 5.2-1 18 5.2-2 23 5.2-3 18 5.2-4 18 5.2-5 18 5.2-6 18 5.2-7 18 5.2-8 18 5.2-9 18 5.2-10 18 5.2-11 18 5.2-12 18 5.2-13 18 5.2-14 18 5.2-15 18 5.2-16 18 5.2-17 18 5.2-18 18 5.2-19 18 5.2-20 18 5.2-21 18 5.2-22 18 5.2-23 18 5.2-24 18 EPL 32

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 5.2-25 23 5.2-26 18 5.2-27 18 5.2-28 18 5.2-29 18 5.2-30 18 5.2-31 19 5.2-32 19 5.2-33 22 5.2-34 18 5.2-35 18 5.2-36 18 5.2-37 18 5.2-38 19 5.2-39 18 5.2-40 18 5.2-41 18 5.2-42 18 5.2-43 18 5.2-44 18 5.2-45 18 5.2-46 18 5.2-47 18 5.2-48 20 5.2-49 18 5.2-50 18 5.2-51 18 5.2-52 18 5.2-53 18 5.2-54 18 5.2-55 18 5.2-56 18 5.2-57 18 5.2-58 18 5.2-59 22 5.2-60 22 5.2-61 22 5.2-62 19 Table 5.2-1 13 Table 5.2.1-1 20 Table 5.2.1-22 13 Table 5.2.1-23 13 Table 5.2.1-24 13 Table 5.2-2 13 Table 5.2.2-1 13 Table 5.2.2-2 13 Table 5.2-3 (Sheet 1) 13 Table 5.2-3 (Sheet 2) 13 Table 5.2.3-1 (Sheet 1) 18 Table 5.2.3-1 (Sheet 2) 21 Table 5.2.3-1 (Sheet 3) 18 EPL 33

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paoe Amendment Table 5.2.3-2 (Sheet 1) 13 Table 5.2.3-2 (Sheet 2) 13 Table 5.2.3-3 17 Table 5.2-4 18 Table 5.2.4-1 13 Table 5.2.4-2 13 Table 5.2.4-3 13 Table 5.2.4-4 13 Table 5.2.4-5 13 Table 5.2.4-6 13 Table 5.2.4-7 13 Table 5.2-5 18 Table 5.2.5-1 13 Figure 5.2.1-4 18 Figure 5.2.1-5 Original Figure 5.2.1-6 18 Figure 5.2.1-8 Original Figure 5.2.1-9 Original Figure 5.2.1-10 Original Figure 5.2.1-11 Original Figure 5.2.1-12 Original Figure 5.2.1-13 Original Figure 5.2.1-14 18 Figure 5.2.1-15 Original Figure 5.2.1-16 Original Figure 5.2.6-1 Original Figure 5.2.7-1 13 5.3-1 13 Figure 5.3.4-1 13 5.4-1 13 5.4-2 13 5.4-3 17 5.4-4 17 5.4-5 17 5.4-6 17 5.4-7 17 5.4-8 17 5.4-9 17 5.4-10 17 5.4-11 17 5.4-12 17 5.4-13 17 5.4-14 17 5.4-15 17 Table 5.4.2-1 13 Table 5.4.4-1 13 Figure 5.4.2-1 Original Figure 5.4.3-1 Original Figure 5.4.3-2 Original Figure 5.4.3-3 Original 5.5-1 18 EPL 34

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 5.5-2 18 5.5-3 18 5.5-4 18 5.5-5 18 5.5-6 18 5.5-7 18 5.5-8 18 5.5-9 18 5.5-10 18 5.5-11 18 5.5-12 18 5.5-13 18 5.5-14 18 5.5-15 18 5.5-16 18 5.5-17 18 5.5-18 18 5.5-19 18 5.5-20 18 5.5-21 18 5.5-22 18 5.5-23 18 5.5-24 18 5.5-25 19 5.5-25a 19 5.5-26 18 5.5-27 18 5.5-28 18 5.5-29 18 5.5-30 18 5.5-31 18 5.5-32 18 5.5-33 18 5.5-34 18 5.5-35 18 5.5-36 18 5.5-37 18 5.5-38 18 5.5-39 18 Table 5.5.1-1 16 Table 5.5.1-2 13 Table 5.5.2-1 18 Table 5.5.2-2 13 Table 5.5.3-1 13 Table 5.5.5-1 20 Table 5.5.7-1 17 Table 5.5.7-2 16 Table 5.5.10-1 21 Table 5.5.10-2 13 Table 5.5.11-1 13 Table 5.5.12-1 18 EPL 35

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment Table 5.5.13-1 13 Figure 5.5.1-1 Original Figure 5.5.1-2 Original Figure 5.5.1-3 Original Figure 5.5.2-1a 18 Figure 5.5.2-1b 18 Figure 5.5.7-1 13 Figure 5.5.7-2 22 Figure 5.5. 10-1 Original Figure 5.5.14-1 Original Figure 5.5.14-2 18 Figure 5.5.14-3 Original Figure 5.5.14-4 Original Figure 5.5.14-5 18 5.6-1 13 5.6-2 13 5.6-3 13 5.6-4 13 5.6-5 22 5.6-6 22 CHAPTER 6 6-1 20 6-2 20 6-3 13 6-4 15 6-5 13 6-6 18 6-7 21 6-8 20 6-9 13 6-10 13 6-11 13 6-12 14 6-13 14 6-14 14 6-15 20 6-16 13 6-17 13 6.1-1 13 6.1-2 13 6.2-1 17 6.2-2 13 6.2-3 13 6.2-4 13 6.2-5 23 6.2-6 14 6.2-7 13 6.2-8 13 6.2-9 13 EPL 36

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 6.2-10 13 6.2-11 13 6.2-12 13 6.2-13 13 6.2-14 13 6.2-15 13 6.2-16 13 6.2-17 13 6.2-18 18 6.2-19 18 6.2-20 18 6.2-21 21 6.2-22 14 6.2-22a 22 6.2-23 13 6.2-24 13 6.2-25 13 6.2-26 13 6.2-27 13 6.2-28 14 6.2-29 14 6.2-30 14 6.2-31 17 6.2-32 14 6.2-33 14 6.2-34 14 6.2-35 18 6.2-36 18 6.2-37 14 6.2-38 18 6.2-39 18 6.2-40 18 6.2-41 18 6.2-42 18 6.2-43 18 6.2-44 18 6.2-45 18 6.2-46 18 6.2-47 18 6.2-48 13 6.2-49 22 6.2-50 22 6.2-51 15 6.2-52 13 6.2-53 20 6.2-53a 21 6.2-54 13 6.2-55 13 6.2-56 13 6.2-57 21 6.2-58 23 EPL 37

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment 6.2-59 21 6.2-60 13 6.2-61 16 6.2-62 13 6.2-63 13 6.2-64 19 6.2-65 13 6.2-66 13 6.2-67 13 6.2-68 13 6.2-69 13 6.2-70 16 6.2-71 13 6.2-72 13 6.2-73 13 6.2-74 13 6.2-75 13 6.2-76 23 6.2-77 13 6.2-78 18 6.2-79 13 6.2-80 13 6.2-81 13 6.2-82 13 6.2-83 13 6.2-84 13 6.2-85 23 6.2-86 13 6.2-87 16 6.2-88 16 6.2-89 20 6.2-90 20 6.2-91 20 6.2-92 20 6.2-93 21 6.2-94 20 6.2-95 20 6.2-96 20 6.2-97 20 6.2-98 20 6.2-99 20 6.2-100 20 6.2-101 20 6.2-102 20 6.2-103 20 6.2-104 20 Table 6.2.1-1 (Sheet 1) 18 Table 6.2.1-1 (Sheet 2) 13 Table 6.2.1-1 (Sheet 3) 13 Table 6.2.1-1 (Sheet 4) 13 Table 6.2.1-1 (Sheet 5) 16 EPL 38

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment Table 6.2.1-1 (Sheet 6) 14 Table 6.2.1-1 (Sheet 7) 18 Table 6.2.1-1 (Sheet 8) 15 Table 6.2.1-2 13 Table 6.2.1-3 13 Table 6.2.1-4 13 Table 6.2.1-5 (Sheet 1) 13 Table 6.2.1-5 (Sheet 2) 13 Table 6.2.1-6 14 Table 6.2.1-7 14 Table 6.2.1-8 18 Table 6.2.1-8a 18 Table 6.2.1-9 18 Table 6.2.1-10 18 Table 6.2.1-12 13 Table 6.2.1-13 14 Table 6.2.1-15 13 Table 6.2.1-16 14 Table 6.2.1-18 14 Table 6.2.1-21 18 Table 6.2.1-22 14 Table 6.2.1-23 14 Table 6.2.1-24 18 Table 6.2.1-25 13 Table 6.2.1-26 (Sheet 1) 13 Table 6.2.1-26 (Sheet 2) 13 Table 6.2.1-27 18 Table 6.2.1-28 (Sheet 1) 13 Table 6.2.1-28 (Sheet 2) 13 Table 6.2.1-28 (Sheet 3) 13 Table 6.2.1-29 (Sheet 1) 13 Table 6.2.1-29 (Sheet 2) 13 Table 6.2.1-29 (Sheet 3) 13 Table 6.2.1-29 (Sheet 4) 13 Table 6.2.1-29 (Sheet 5) 13 Table 6.2-1-30 (Sheet 1) 13 Table 6.2.1-30 (Sheet 2) 13 Table 6.2.1-31 (Sheet 1) 17 Table 6.2.1-31 (Sheet 2) 17 Table 6.2.1-32 (Sheet 1) 18 Table 6.2.1-32 (Sheet 2) 18 Table 6.2.1-32 (Sheet 3) 21 Table 6.2.1-33 13 Table 6.2.1-34 13 Table 6.2.1-35 13 Table 6.2.1-36 17 Table 6.2.1-37 13 Table 6.2.1-38 13 Table 6.2.1-39 (Sheet 1) 13 Table 6.2.1-39 (Sheet 2) 13 Table 6.2.1-40 13 EPL 39

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment Table 6.2.1-41 (Sheet 1) 13 Table 6.2.1-41 (Sheet 2) 13 Table 6.2.1-42 (Sheet 1) 13 Table 6.2.1-42 (Sheet 2) 13 Table 6.2.1-43 13 Table 6.2.1-44 13 Table 6.2.2-1 15 Table 6.2.2-2 21 Table 6.2.2-3 13 Table 6.2.3-1 (Sheet 1) 19 Table 6.2.3-1 (Sheet 2) 19 Table 6.2.3-2 (Sheet 1) 16 Table 6.2.3-2 (Sheet 2) 16 Table 6.2.4-1 (Sheet 1) 23 Table 6.2.4-1 (Sheet 2) 23 Table 6.2.4-1 (Sheet 3) 23 Table 6.2.4-1 (Sheet 4) 23 Table 6.2.6-1 13 Figure 6.2.1-1 through 1J 13 Figure 6.2.1-2 Original Figure 6.2.1-3 13 Figure 6.2.1-4 12 Figure 6.2.1-5 12 Figure 6.2.1-6 1 Figure 6.2.1-7 1 Figure 6.2.1-8 Original Figure 6.2.1-9 Original Figure 6.2.1-10 Original Figure 6.2. 1-11 Original Figure 6.2.1-12 Original Figure 6.2.1-13 Original Figure 6.2.1-14 Original Figure 6.2.1-15 18 Figure 6.2.1-16 18 Figure 6.2.1-17 18 Figure 6.2.1-18 18 Figure 6.2.1-19 18 Figure 6.2.1-22 12 Figure 6.2.1-23 12 Figure 6.2.1-24 Original Figure 6.2.1-25 Original Figure 6.2.1-26 Original Figure 6.2.1-27 Original Figure 6.2.1-28 Original Figure 6.2.1-29 Original Figure 6.2.1-30 Original Figure 6.2.1-31 Original Figure 6.2.1-32 Original Figure 6.2.1-33 Original Figure 6.2.1-34 Original Figure 6.2.1-41 Original EPL 40

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment Figure 6.2.1-42 Original Figure 6.2.1-43 18 Figure 6.2.1-44 18 Figure 6.2.1-45 18 Figure 6.2.1-46 18 Figure 6.2.1-47 18 Figure 6.2.1-48 18 Figure 6.2.1-49 18 Figure 6.2.1-50 18 Figure 6.2.1-51 18 Figure 6.2.1-52 18 Figure 6.2.1-53 18 Figure 6.2.1-54 18 Figure 6.2.1-55 18 Figure 6.2.1-56 18 Figure 6.2.1-57 18 Figure 6.2.1-58 18 Figure 6.2.1-59 18 Figure 6.2.1-60 18 Figure 6.2.1-61 Original Figure 6.2.1-62 Original Figure 6.2.1-63 Original Figure 6.2.1-63A 13 Figure 6.2.1-63B 13 Figure 6.2.1-63C 13 Figure 6.2.1-63D 13 Figure 6.2.1-63E 13 Figure 6.2.1-63F 13 Figure 6.2.1-64 Original Figure 6.2.1-65 Original Figure 6.2.1-66 Original Figure 6.2.1-67 Original Figure 6.2.1-68 Original Figure 6.2.1-69 Original Figure 6.2.1-70 Original Figure 6.2.1-71 Original Figure 6.2.1-72 Original Figure 6.2.1-73 Original Figure 6.2.1-74 Original Figure 6.2.1-75 Original Figure 6.2.1-76 Original Figure 6.2.1-77 Original Figure 6.2.1-78 Original Figure 6.2.1-79 Original Figure 6.2.1-80 Original Figure 6.2.1-81 Original Figure 6.2.1-82 Original Figure 6.2.1-83 14 Figure 6.2.2-1 15 Figure 6.2.2-2 22 Figure 6.2.2-3 13 EPL 41

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment Figure 6.2.3-1 13 Figure 6.2.4-1 18 Figure 6.2.5A-1 1 Figure 6.2.5A-2 1 Figure 6.2.5A-3 1 Figure 6.2.5A-4 1 Figure 6.2.5A-5 1 Figure 6.2.5B-1 20 Figure 6.2.6-1 13 Figure 6.2.6-2 6 Figure 6.2.6-3 6 6.3-1 13 6.3-2 13 6.3-3 13 6.3-4 13 6.3-5 13 6.3-6 23 6.3-7 13 6.3-8 13 6.3-9 17 6.3-10 21 6.3-11 13 6.3-12 13 6.3-13 23 6.3-14 13 6.3-15 14 6.3-16 13 6.3-17 13 6.3-18 23 6.3-19 23 6.3-20 23 6.3-21 23 6.3-22 23 6.3-23 23 6.3-24 23 6.3-25 23 6.3-26 23 Table 6.3.2-1 (Sheet 1) 17 Table 6.3.2-1 (Sheet 2) 13 Table 6.3.2-1 (Sheet 3) 13 Table 6.3.2-2 16 Table 6.3.2-3 16 Table 6.3.2-4 (Sheet 1) 21 Table 6.3.2-4 (Sheet 2) 21 Table 6.3.2-4 (Sheet 3) 13 Table 6.3.2-5 13 Table 6.3.2-6 13 Table 6.3.2-7 (Sheet 1) 13 Table 6.3.2-7 (Sheet 2) 13 Table 6.3.2-7 (Sheet 3) 13 Table 6.3.2-8 13 EPL 42

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment Table 6.3.3-1 13 Figure 6.3.2-1 16 Figure 6.3.2-2 22 Figure 6.3.2-3 13 Figure 6.3.2-4 21 Figure 6.3.2-5 21 Figure 6.3.2-6 21 Figure 6.3.2-7 21 6.4-1 13 6.4-2 19 6.4-3 13 6.4-4 13 6.4-5 16 6.4-6 16 6.5-1 15 6.5-2 13 6.5-3 15 6.5-4 18 6.5-5 15 6.5-6 15 6.5-7 13 6.5-8 13 6.5-9 13 6.5-10 13 6.5-11 13 6.5-12 13 6.5-13 13 6.5-14 13 6.5-15 13 6.5-16 13 6.5-17 15 6.5-18 13 6.5-19 13 6.5-20 15 6.5-21 15 6.5-22 13 6.5-23 14 6.5-24 13 6.5-25 15 6.5-26 16 6.5-27 13 6.5-28 13 6.5-29 13 6.5-30 13 6.5-31 17 6.5-32 13 6.5-33 13 6.5-34 13 6.5-35 13 6.5-36 13 6.5-37 22 EPL 43

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment 6.5-38 22 6.5-39 13 6.5-40 13 6.5-41 13 6.5-42 13 6.5-43 13 6.5-44 13 6.5-45 13 6.5-46 13 6.5-47 13 6.5-48 13 6.5-49 13 6.5-50 13 6.5-51 13 6.5-52 13 6.5-53 13 6.5-54 13 6.5-55 13 6.5-56 17 6.5-57 13 6.5-58 13 6.5-59 13 6.5-60 13 6.5-61 13 6.5-62 13 6.5-63 21 6.5-64 13 6.5-65 13 6.5-66 21 6.5-67 21 6.5-68 13 6.5-69 21 6.5-70 13 6.5-71 15 6.5-72 13 6.5-73 17 Table 6.5.2-1 (Sheet 1) 13 Table 6.5.2-1 (Sheet 2) 13 Table 6.5.2-2 13 Table 6.5.2-3 13 Table 6.5.3-1 13 Table 6.5.3-2 13 Table 6.5.3-3 13 Table 6.5.3-4 13 Table 6.5.3-5 13 Table 6.5.3-6 13 Table 6.5.3-7 13 Table 6.5.4-1 13 Table 6.5.4-2 13 Table 6.5.4-3 13 Table 6.5.4-4 15 EPL 44

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Table 6.5.4-5 13 Table 6.5.4-6 13 Table 6.5.4-7 13 Table 6.5.4-8 13 Table 6.5.4-9 13 Table 6.5.4-10 13 Table 6.5.4-11 13 Table 6.5.4-12 13 Table 6.5.4-13 15 Table 6.5.4-14 15 Table 6.5.4-15 15 Table 6.5.4-16 15 Table 6.5.5-1 13 Table 6.5.6-1 (Sheet 1) 17 Table 6.5.6-1 (Sheet 2) 17 Table 6.5.9-1 13 Table 6.5.10-1 (Sheet 1) 13 Table 6.5.10-1 (Sheet 2) 13 Table 6.5.10-2 (Sheet 1) 13 Table 6.5.10-2 (Sheet 2) 13 Table 6.5.10-2 (Sheet 3) 13 Table 6.5.10-2 (Sheet 4) 13 Table 6.5.10-2 (Sheet 5) 13 Table 6.5.10-2 (Sheet 6) 13 Table 6.5.10-2 (Sheet 7) 13 Table 6.5.10-2 (Sheet 8) 13 Table 6.5.10-2 (Sheet 9) 13 Table 6.5.10-2 (Sheet 10) 13 Table 6.5.10-2 (Sheet 11) 13 Table 6.5.10-2 (Sheet 12) 13 Table 6.5.10-2 (Sheet 13) 13 Table 6.5.10-2 (Sheet 14) 13 Table 6.5.11-1 13 Table 6.5.11-2 13 Table 6.5.12-1 13 Table 6.5.15-1 15 Figure 6.5.1-1 Original Figure 6.5.1-2A 13 Figure 6.5.1-2B 13 Figure 6.5.1-3 Original Figure 6.5.2-1 Original Figure 6.5.2-2 Original Figure 6.5.2-3 Original Figure 6.5.3-1 6 Figure 6.5.3-2 Original Figure 6.5.3-3 Original Figure 6.5.3-4 Original Figure 6.5.3-5 Original Figure 6.5.4-1 Original Figure 6.5.4-2 Original Figure 6.5.6-1 13 EPL 45

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment Figure 6.5.7-1 Original Figure 6.5.9-1 Original Figure 6.5.9-2 13 Figure 6.5.9-3 Original Figure 6.5.9-4 Original Figure 6.5.9-5 Original Figure 6.5.9-6 Original Figure 6.5.9-7 6 Figure 6.5.10-1 Original Figure 6.5.10-2 Original Figure 6.5.10-3 Original Figure 6.5.10-4 Original Figure 6.5.10-5 Original Figure 6.5.10-6 Original Figure 6.5.10-7 Original Figure 6.5.10-8 Original Figure 6.5.10-9 Original Figure 6.5.10-10 Original Figure 6.5.10-11 Original Figure 6.5.10-12 Original Figure 6.5.10-13 Original Figure 6.5.10-14 Original Figure 6.5.10-15 Original Figure 6.5.10-16 Original Figure 6.5.11-1 6 Figure 6.5.12-1 Original Figure 6.5.12-2 6 Figure 6.5.13-1 Original Figure 6.5.15-1 Original Figure 6.5.15-2 Original Figure 6.5.15-3 Original Figure 6.5.15-4 Original 6A-1 13 6A-2 13 6A-3 13 6A-4 21 Figure 6A-1 13 6.6-1 13 6.6-2 13 6.6-3 13 6.7-1 13 6.8-1 20 6.9-1 23 6.9-2 16 CHAPTER 7 7-1 13 7-2 13 7-3 13 7-4 13 EPL 46

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Pa e Amendment 7-5 13 7-6 13 7.1-1 13 7.1-2 13 7.1-3 13 7.1-4 13 7.1-5 13 7.1-6 13 7.1-7 13 7.1-8 13 7.1-9 13 7.1-10 13 7.1-11 13 7.1-12 18 7.1-13 13 7.1-14 13 7.1-15 13 7.1-16 18 7.1-17 15 7.1-18 15 7.1-19 15 7.1-20 21 7.1-21 13 Figure 7.1.3-1 Original Figure 7.1.3-2 Original Figure 7.1.3-3 Original Figure 7.1.3-4 Original Figure 7.1.3-5 Original Figure 7.1.4-1 16 7.2-1 13 7.2-2 13 7.2-3 13 7.2-4 13 7.2-5 13 7.2-6 13 7.2-7 13 7.2-8 13 7.2-9 13 7.2-10 13 7.2-11 13 7.2-12 13 7.2-13 16 7.2-14 13 7.2-15 13 7.2-16 17 7.2-17 13 7.2-18 13 7.2-19 13 7.2-20 13 7.2-21 13 7.2-22 13 EPL 47

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment 7.2-23 16 7.2-24 13 7.2-25 13 7.2-26 13 7.2-27 23 7.2-28 22 7.2-29 16 7.2-30 23 7.2-31 22 7.2-32 22 Table 7.2.1-1 (Sheet 1) 13 Table 7.2.1-1 (Sheet 2) 13 Table 7.2.1-2 13 Table 7.2.1-3 (Sheet 1) 13 Table 7.2.1-3 (Sheet 2) 13 Table 7.2.1-3 (Sheet 3) 13 Table 7.2.1-4 13 Table 7.2.1-5 (Sheet 1) 13 Table 7.2.1-5 (Sheet 2) 13 Figure 7.2.1-1 (Sheet 1) 13 Figure 7.2.1-1 (Sheet 2) 13 Figure 7.2.1-1 (Sheet 3) 20 Figure 7.2.1-1 (Sheet4) 13 Figure 7.2.1-1 (Sheet 5) 13 Figure 7.2.1-1 (Sheet 6) 13 Figure 7.2.1-1 (Sheet 7) 13 Figure 7.2.1-1 (Sheet 8) 13 Figure 7.2.1-1 (Sheet 9) 13 Figure 7.2.1-1 (Sheet 10) 13 Figure 7.2.1-1 (Sheet 11) 13 Figure 7.2.1-1 (Sheet 12) 13 Figure 7.2.1-1 (Sheet 13) 23 Figure 7.2.1-1 (Sheet 14) 23 Figure 7.2.1-1 (Sheet 15) 13 Figure 7.2.1-1 (Sheet 16) 23 Figure 7.2.1-1 (Sheet 17) 13 Figure 7.2.1-1 (Sheet 18) 13 Figure 7.2.1-1 (Sheet 19) 13 Figure 7.2.1-1 (Sheet 20) 13 Figure 7.2.1-2 Original Figure 7.2.2-1 17 Figure 7.2.2-2 Original 7.3-1 13 7.3-2 13 7.3-3 13 7.3-4 13 7.3-5 13 7.3-6 13 7.3-7 13 7.3-8 13 7.3-9 13 EPL 48

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 7.3-10 13 7.3-11 13 7.3-12 13 7.3-13 13 7.3-14 13 7.3-15 21 7.3-16 13 Table 7.3.1-1 13 Table 7.3.1-2 13 Table 7.3.1-3 16 Table 7.3.1-4 (Sheet 1) 15 Table 7.3.1-4 (Sheet 2) 15 Table 7.3.1-4 (Sheet 3) 15 Table 7.3.1-4 (Sheet 4) 15 Table 7.3.1-4 (Sheet 5) 13 Table 7.3.2-1 13 7.4-1 13 7.4-2 20 7.4-3 13 7.4-4 13 7.4-5 13 7.5-1 13 7.5-2 13 7.5-3 13 7.5-4 15 7.5-5 15 7.5-6 15 7.5-7 21 7.5-8 13 Table 7.5-1 15 Table 7.5-2 (Sheet 1) 13 Table 7.5-2 (Sheet 2) 18 Table 7.5-2 (Sheet 3) 21 Table 7.5-2 (Sheet 4) 13 Table 7.5-2 (Sheet 5) 21 Table 7.5-2 (Sheet 6) 13 Table 7.5-2 (Sheet 7) 15 Table 7.5-2 (Sheet 8) 13 Table 7.5-2 (Sheet 9) 13 Table 7.5-2 (Sheet 10) 13 Table 7.5-2 (Sheet 11) 13 7.6-1 17 7.6-2 13 7.6-3 13 7.6-4 13 7.6-5 13 7.6-6 13 7.6-7 13 7.6-8 13 7.6-9 13 Figure 7.6.6-1 Original EPL 49

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Figure 7.6.7-1 13 Figure 7.6.9-1 (Sheet 1) 6 Figure 7.6.9-1 (Sheet 2) Original Figure 7.6.9-1 (Sheet 3) 6 7.7-1 13 7.7-2 13 7.7-3 13 7.7-4 13 7.7-5 13 7.7-6 20 7.7-7 20 7.7-8 23 7.7-9 23 7.7-10 23 7.7-10a 22 7.7-11 13 7.7-12 15 7.7-13 16 7.7-14 13 7.7-15 13 7.7-16 13 7.7-17 .13 7.7-18 13 7.7-19 13 7.7-20 13 7.7-21 16 Table 7.7.1-1 13 Figure 7.7.1-1 13 Figure 7.7.1-2 Original Figure 7.7.1-3 Original Figure 7.7.1-4 13 Figure 7.7.1-5 13 7A-1 13 7A-2 13 7A-3 13 7A-4 13 7A-5 13 Figure 7A-1 Original Figure 7A-2 13 Figure 7A-3 13 Figure 7A-4 13 Figure 7A-5 13 Figure 7A-6 13 CHAPTER 8 8-1 13 8-2 20 8-3 20 8-4 13 8-5 13 EPL 50

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 8.1-1 23 8.1-2 13 8.1-3 13 8.1-4 21 8.1-5 13 8.1-6 18 Table 8.1.2-1 (Sheet 1) 13 Table 8.1.2-1 (Sheet 2) 13 Figure 8.1.1-1 17 Figure 8.1.2-1 23 Figure 8.1.2-2 19 8.2-1 23 8.2-2 21 8.2-3 13 8.2-4 23 8.2-5 23 8.2-6 21 8.2-7 21 8.2-8 13 8.2-9 13 8.2-10 23 8.2-11 23 8.2-12 13 8.2-13 13 8.2-14 23 8.2-15 18 8.2-16 18 Table 8.2.1-1 (Sheet 1) 23 Table 8.2.1-1 (Sheet 2) 23 Table 8.2.1-1 (Sheet 3) 13 Table 8.2.1-1 (Sheet 4) 13 Table 8.2.1-1 (Sheet 5) 13 Figure 8.2.1-1 23 Figure 8.2.1-2 23 Figure 8.2.1-3 13 Figure 8.2.1-4 21 Figure 8.2.1-5 23 Figure 8.2.1-6 13 8.3-1 13 8.3-2 13 8.3-3 21 8.3-4 19 8.3-5 18 8.3-6 18 8.3-7 16 8.3-8 13 8.3-9 16 8.3-10 13 8.3-11 15 8.3-12 13 8.3-12a 18 EPL 51

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment 8.3-13 17 8.3-14 17 8.3-15 13 8.3-16 14 8.3-17 13 8.3-18 18 8.3-19 13 8.3-20 13 8.3-21 17 8.3-22 13 8.3-23 20 8.3-24 20 8.3-24a 20 8.3-25 13 8.3-26 21 8.3-27 13 8.3-28 13 8.3-29 13 8.3-30 13 8.3-31 13 8.3-32 13 8.3-33 13 8.3-34 13 8.3-35 13 8.3-36 13 8.3-37 13 8.3-38 19 8.3-39 16 8.3-40 13 8.3-41 21 8.3-42 13 8.3-43 16 8.3-44 13 8.3-45 13 8.3-46 13 8.3-47 20 Table 8.3.1-1 21 Table 8.3.1-2 16 Table 8.3.1-3 13 Table 8.3.1-4 13 Table 8.3.1-5 13 Table 8.3.1-6 13 Table 8.3.1-7 13 Table 8.3.1-8 13 Table 8.3.1-9 13 Table 8.3.1-11 13 Table 8.3.2-1 13 Figure 8.3.1-1 13 Figure 8.3.1-2 16 Figure 8.3.1-3 18 Figure 8.3.1-4 13 EPL 52

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Figure 8.3.1-5 13 Figure 8.3.1-6 22 Figure 8.3.1-7 17 Figure 8.3.1-8 19 Figure 8.3.1-9 13 Figure 8.3.1-10 17 Figure 8.3.1-11 19 Figure 8.3.1-12 20 Figure 8.3.1-13 19 Figure 8.3.1-14. 18 Figure 8.3.1-15 19 Figure 8.3.1-16 16 Figure 8.3.1-17 23 Figure 8.3.1-18 13 Figure 8.3.1-19 13 Figure 8.3.1-20 13 Figure 8.3.1-21 18 Figure 8.3.1-22 13 Figure 8.3.2-1 21 CHAPTER 9 9-1 19 9-2 19 9-3 19 9-4 19 9-5 19 9-6 19 9-7 19 9-8 16 9-9 13 9-10 21 9.1-1 18 9.1-2 23 9.1-3 18 9.1-4 18 9.1-5 18 9.1-6 18 9.1-7 18 9.1-8 20 9.1-9 18 9.1-10 18 9.1-11 18 9.1-12 18 9.1-13 18 9.1-14 19 9.1-15 19 9.1-16 19 9.1-17 19 9.1-18 18 9.1-19 18 EPL 53

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 9.1-20 18 9.1-21 18 9.1-22 19 9.1-23 19 9.1-24 19 9.1-25 19 Table 9.1.3-1 (Sheet 1) 13 Table 9.1.3-1 (Sheet 2) 13 Table 9.1.3-2 (Sheet 1) 20 Table 9.1.3-2 (Sheet 2) 13 Table 9.1.3-3 13 Table 9.1.3-4 18 Table 9.1.5-1 19 Table 9.1.5-2 19 Figure 9.1.1-1 13 Figure 9.1.1-2 21 Figure 9.1.2-1 Original Figure 9.1.2-2 13 Figure 9.1.3-1 13 Figure 9.1.3-2 13 Figure 9.1.4-1 15 Figure 9.1.4-3 Original Figure 9.1.4-4 Original Figure 9.1.4-5 13 Figure 9.1.4-6 13 Figure 9.1.4-7 18 Figure 9.1.4-8 Original 9.2-1 21 9.2-2 21 9.2-3 16 9.2-4 19 9.2-5 13 9.2-6 13 9.2-7 13 9.2-8 13 9.2-9 21 9.2-10 21 9.2-11 21 9.2-12 13 9.2-13 21 9.2-14 16 9.2-15 21 9.2-16 21 9.2-17 15 9.2-18 15 9.2-19 13 9.2-20 21 9.2-21 13 9.2-22 16 9.2-23 21 9.2-24 18 EPL 54

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment 9.2-25 21 9.2-26 21 9.2-27 16 Table 9.2.1-1 (Sheet 1) 13 Table 9.2.1-1 (Sheet 2) 13 Table 9.2.1-2 (Sheet 1) 13 Table 9.2.1-2 (Sheet 2) 13 Table 9.2.2-1 13 Table 9.2.2-2 13 Table 9.2.7-1 13 Figure 9.2.1-1 17 Figure 9.2.1-2 13 Figure 9.2.1-3 16 Figure 9.2.1-4 22 Figure 9.2.1-5 13 Figure 9.2.1-6 13 Figure 9.2.1-7 13 Figure 9.2.2-1 18 Figure 9.2.2-2 21 Figure 9.2.2-3 18 Figure 9.2.2-3a 16 Figure 9.2.2-4 21 Figure 9.2.2-4a 21 Figure 9.2.2-5 16 Figure 9.2.2-6 13 Figure 9.2.3-1 13 Figure 9.2.3-2 16 Figure 9.2.7-1 21 Figure 9.2.7-2 17 Figure 9.2.7-3 17 Figure 9.2.7-4 20 9.3-1 16 9.3-2 19 9.3-2a 19 9.3-3 23 9.3-4 16 9.3-5 16 9.3-6 16 9.3-7 19 9.3-8 13 9.3-9 13 9.3-10 19 9.3-11 17 9.3-12 13 9.3-13 18 9.3-14 19 9.3-15 13 9.3-16 15 9.3-17 18 9.3-18 13 9.3-19 13 EPL 55

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment 9.3-20 13 9.3-21 13 9.3-22 17 9.3-23 ° 13 9.3-24 13 9.3-25 13 9.3-26 13 9.3-27 13 9.3-28 13 9.3-29 17 9.3-30 13 9.3-31 17 9.3-32 13 9.3-33 13 9.3-34 13 Table 9.3.1-1 14 Table 9.3.2-1 (Sheet 1) 17 Table 9.3.2-1 (Sheet 2) 16 Table 9.3.2-1 (Sheet 3) 16 Table 9.3.2-1 (Sheet 4) 13 Table 9.3.4-1 19 Table 9.3.4-2 (Sheet 1) 13 Table 9.3.4-2 (Sheet 2) 13 Table 9.3.4-2 (Sheet 3) 13 Table 9.3.4-2 (Sheet 4) 19 Table 9.3.4-2 (Sheet 5) 19 Table 9.3.4-2 (Sheet 6) 13 Figure 9.3.1-1 17 Figure 9.3.1-2 13 Figure 9.3.1-3 17 Figure 9.3.3-1 13 Figure 9.3.3-2 13 Figure 9.3.4-1 18 Figure 9.3.4-2 17 Figure 9.3.4-3 17 Figure 9.3.4-4 15 Figure 9.3.4-5 22 Figure 9.3.4-6 13 Figure 9.3.6-1 13 9.4-1 16 9.4-2 13 9.4-3 16 9.4-4 13 9.4-5 13 9.4-6 16 9.4-7 13 9.4-8 13 9.4-9 16 9.4-10 15 9.4-11 13 9.4-12 14 EPL 56

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 9.4-12a 14 9.4-13 21 9.4-14 15 9.4-15 13 9.4-16 13 9.4-17 13 9.4-18 19 9.4-19 21 9.4-20 21 9.4-21 15 9.4-22 13 9.4-23 19 9.4-24 22 9.4-25 18 9.4-26 21 9.4-27 18 9.4-28 21 9.4-29 18 9.4-30 17 Table 9.4.1-1 (Sheet 1) 16 Table 9.4.1-1 (Sheet 2) 16 Table 9.4.7-1 13 Figure 9.4.1-1 16 Figure 9.4.2-1 13 Figure 9.4.2-2 13 Figure 9.4.2-2a 13 Figure 9.4.2-3 17 Figure 9.4.2-4 16 Figure 9.4.2-5 16 Figure 9.4.5-1 16 Figure 9.4.7-1 18 Figure 9.4.10-1 13 9.5-1 13 9.5-2 13 9.5-3 20 9.5-4 20 9.5-5 20 9.5-6 13 9.5-7 13 9.5-8 13 9.5-9 13 9.5-10 13 9.5-11 20 9.5-12 13 9.5-13 13 9.5-14 17 9.5-15 15 Table 9.5.2-1 17 Table 9.5.10-1 15 Figure 9.5.4-1 18 Figure 9.5.5-1 13 EPL 57

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Figure 9.5.6-1 20 CHAPTER 10 10-1 13 10-2 13 10-3 13 10-4 13 10-5 17 10.1-1 17 Table 10.1-1 (Sheet 1) 19 Table 10.1-1 (Sheet 2) 13 Table 10.1-1 (Sheet 3) 18 Table 10.1-1 (Sheet 4) 13 Table 10.1-1 (Sheet 5) 17 Figure 10.1-1 13 Figure 10.1-2 18 Figure 10.1-3 19 10.2-1 19 10.2-2 13 10.2-3 13 10.2-4 19 10.2-5 19 10.2-6 18 10.2-7 13 10.2-8 13 10.2-9 13 10.2-10 13 10.2-11 13 10.2-12 13 10.2-13 13 10.2-14 13 10.2-15 13 10.2-16 18 Table 10.2.3-1 13 Table 10.2.3-2 13 Table 10.2.3-3 (Sheet 1) 13 Table 10.2.3-3 (Sheet 2) 13 Table 10.2.3-4 13 Table 10.2.3-5 13 Figure 10.2.3-1 Original Figure 10.2.3-2 Original Figure 10.2.3-3 Original Figure 10.2.3-4 6 10.3-1 18 10.3-2 18 10.3-3 18 10.3-4 18 10.3-5 18 10.3-6 18 10.3-7 18 EPL 58

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment Table 10.3.2-1 14 Table 10.3.3-1 14 Figure 10.3.2-1 23 10.4-1 13 10.4-2 13 10.4-3 13 10.4-4 13 10.4-5 13 10.4-6 13 10.4-7 18 10.4-7a 16 10.4-8 13 10.4-9 21 10.4-10 13 10.4-11 13 10.4-12 13 10.4-13 16 10.4-14 15 10.4-15 17 10.4-16 13 10.4-17 23 10.4-18 22 10.4-19 22 10.4-20 22 10.4-21 13 10.4-22 19 10.4-23 14 10.4-24 13 10.4-25 13 10.4-26 19 10.4-27 18 10.4-28 14 10.4-29 14 10.4-30 14 10.4-31 18 10.4-32 22 10.4-33 13 10.4-34 17 10.4-35 13 10.4-36 14 10.4-37 19 10.4-38 13 10.4-39 20 10.4-40 13 10.4-41 20 10.4-42 20 10.4-43 13 10.4-44 13 10.4-45 20 10.4-46 15 10.4-47 13 EPL 59

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment 10.4-48 19 10.4-49 19 Table 10.4.1-1 13 Table 10.4.7-1 18 Table 10.4.7-2 14 Table 10.4.7-3 13 Table 10.4.7-4 (Sheet 1) 13 Table 10.4.7-4 (Sheet 2) 13 Table 10.4.7-5 13 Table 10.4.7-6 (Sheet 1) 14 Table 10.4.7-6 (Sheet 2) 14 Table 10.4.7-6 (Sheet 3) 14 Table 10.4.7-6 (Sheet 4) 14 Table 10.4.8-1 (Sheet 1) 14 Table 10.4.8-1 (Sheet 2) 14 Figure 10.4.2-1 17 Figure 10.4.5-1 13 Figure 10.4.5-2 23 Figure 10.4.7-1 13 Figure 10.4.7-2 23 Figure 10.4.7-3 22 Figure 10.4.7-4 19 Figure 10.4.7-5 19 Figure 10.4.7-6 13 Figure 10.4.7-7 13 Figure 10.4.8-1 15 Figure 10.4.8-2 13 Figure 10.4.8-3 13 Figure 10.4.9-1 15 Figure 10.4.9-2 17 CHAPTER 11 11-1 13 11-2 20 11-3 13 11-4 15 11-5 13 11.1-1 13 11.1-2 13 11.1-3 13 11.1-4 13 Table 11.1.1-1 (Sheet 1) 13 Table 11.1.1-1 (Sheet 2) 13 Table 11.1.1-2 (Sheet 1) 13 Table 11.1.1-2 (Sheet 2) 13 Table 11.1.1-3 13 Table 11.1.1-4 13 Table 11.1.1-5 13 Table 11.1.2-1 13 Table 11.1.2-2 (Sheet 1) 13 EPL 60

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Table 11.1.2-2 (Sheet 2) 13 Table 11.1.2-2 (Sheet 3) 13 Table 11.1.2-3 (Sheet 1) 13 Table 11.1.2-3 (Sheet 2) 13 Table 11.1.2-4 (Sheet 1) 13 Table 11.1.2-4 (Sheet 2) 13 Table 11.1.2-4 (Sheet 3) 13 11.2-1 17 11.2-2 22 11.2-3 17 11.2-4 17 11.2-5 17 11.2-6 17 11.2-7 19 11.2-8 17 11.2-9 22 11.2-10 18 11.2-11 19 11.2-12 13 11.2-13 17 11.2-14 20 11.2-15 20 11.2-16 17 11.2-17 16 11.2-18 16 11.2-19 13 11.2-20 13 Table 11.2.2-1 (Sheet 1) 17 Table 11.2.2-1 (Sheet 2) 13 Table 11.2.2-2 13 Table 11.2.3-1 (Sheet 1) 13 Table 11.2.3-1 (Sheet 2) 13 Table 11.2.3-1 (Sheet 3) 17 Table 11.2.3-1 (Sheet 4) 13 Table 11.2.3-1 (Sheet 5) 13 Table 11.2.4-1 13 Table 11.2.9-1 13 Table 11.2.9-2 13 Figure 11.2.2-1 18 Figure 11.2.2-2 20 11.3-1 13 11.3-2 14 11.3-3 14 11.3-4 13 11.3-5 13 11.3-6 19 11.3-7 17 11.3-8 13 11.3-9 13 11.3-10 15 Table 11.3.2-1 (Sheet 1) 13 EPL61

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment Table 11.3.2-1 (Sheet 2) 14 Table 11.3.2-1 (Sheet 3) 13 Table 11.3.2-1 (Sheet 4) 14 Table 11.3.2-2 15 Table 11.3.3-1 13 Table 11.3.6-1 15 Table 11.3.6-2 (Sheet 1) 15 Table 11.3.6-2 (Sheet 2) 15 Table 11.3.6-3 (Sheet 1) 13 Table 11.3.6-3 (Sheet 2) 13 Table 11.3.9-1 13 Table 11.3.9-2 13 Table 11.3.9-3 13 Table 11.3.9-4 15 Table 11.3.9-5 15 Figure 11.3.2-1 16 Figure 11.3.2-2 21 11.4-1 13 11.4-2 23 11.4-3 19 11.4-4 19 11.4-5 23 11.4-6 17 11.4-7 20 11.4-8 20 11.4-9 16 11.4-10 20 Table 11.4.2-1 (Sheet 1) 23 Table 11.4.2-1 (Sheet 2) 19 Table 11.4.2-2 (Sheet 1) 17 Table 11.4.2-2 (Sheet 2) 16 Table 11.4.2-2 (Sheet 3) 16 Table 11.4.2-3 (Sheet 1) 17 Table 11.4.2-3 (Sheet 2) 16 Table 11.4.2-3 (Sheet 3) 15 Table 11.4.2-3 (Sheet 4) 16 Table 11.4.2-3 (Sheet 5) 19 Table 11.4.2-3 (Sheet 6) 19 11.5-1 17 11.5-2 17 11.5-3 13 11.5-4 16 11.5-5 16 Table 11.5.2-1 13 11.6-1 13 11.6-2 13 11.6-3 13 11.6-4 13 11.6-5 17 Table 11.6.4-1 13 11A-1 13 EPL 62

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment 11A-2 17 11A-3 17 1 1A-4 17 Table 11A-1 21 Table 11A-2 21 CHAPTER 12 12-1 13 12-2 13 12-3 16 12.1-1 13 12.1-2 13 12.1-3 13 12.1-4 13 12.1-5 13 12.1-6 13 12.1-7 13 12.1-8 19 12.1-9 23 12.1-10 23 12.1-11 23 12.1-12 23 12.1-13 23 12.1-14 23 12.1-15 23 Table 12.1.2-1 13 Table 12.1.4-1 20 Table 12.1.6-1 13 12.2-1 13 12.2-2 13 12.2-3 13 12.2-4 16 12.2-5 13 12.2-6 13 Table 12.2.4-1 16 Table 12.2.4-2 13 Table 12.2.4-3 16 Table 12.2.6-1 13 12.3-1 13 12.3-2 13 12.4-1 13 Table 12.4.2-1 13 CHAPTER 13 13-1 13 13-2 15 13.1-1 13 13.1-2 17 13.1-3 17 EPL 63

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 13.2-1 13 13.3-1 13 13.4-1 15 13.5-1 22 13.5-2 16 13.5-3 13 13.5-4 13 13.5-5 13 Figure 13.5.1-1 13 13.6-1 19 13.6-2 19 13.7-1 17 13.8-1 15 CHAPTER 14 14-1 13 14.1-1 13 14.1-2 13 14.1-3 13 14.1-4 13 14.1-5 13 14.1-6 13 14.1-7 13 14.1-8 13 14.1-9 13 14.1-10 13 14.1-11 13 14.1-12 13 14.1-13 13 Table 14.1-1 (Sheet 1) 13 Table 14.1-1 (Sheet 2) 13 Table 14.1-1 (Sheet 3) 13 Table 14.1-1 (Sheet 4) 13 Table 14.1-1 (Sheet 5) 13 Table 14.1-1 (Sheet 6) 13 Table 14.1-1 (Sheet 7) 13 Table 14.1-1 (Sheet 8) .13 Table 14.1-1 (Sheet 9) 13 Table 14.1-1 (Sheet 10) 13 Table 14.1-1 (Sheet 11) 13 Table 14.1-1 (Sheet 12) 13 Table 14.1-1 (Sheet 13) 13 Table 14.1-1 (Sheet 14) 13 Table 14.1-1 (Sheet 15) 13 Table 14.1-1 (Sheet 16) 13 Table 14.1-1 (Sheet 17) 13 Table 14.1-1 (Sheet 18) 13 Table 14.1-1 (Sheet 19) 13 Table 14.1-1 (Sheet 20) 13 Table 14.1-1 (Sheet 21) 13 EPL 64

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Table 14.1-1 (Sheet 22) 13 Table 14.1-1 (Sheet 23) 13 Table 14.1-1 (Sheet 24) 13 Table 14.1-1 (Sheet 25) 13 Table 14.1-1 (Sheet 26) 13 Table 14.1-1 (Sheet 27) 13 Table 14.1-1 (Sheet 28) 13 Table 14.1-1 (Sheet 29) 13 Table 14.1-1 (Sheet 30) 13 Table 14.1-1 (Sheet 31) 13 Table 14.1-1 (Sheet 32) 13 Table 14.1-1 (Sheet 33) 13 Table 14.1-1 (Sheet 34) 13 Table 14.1-1 (Sheet 35) 13 Table 14.1-1 (Sheet 36) 13 Table 14.1-1 (Sheet 37) 13 Table 14.1-1 (Sheet 38) 13 Table 14.1-1 (Sheet 39) 13 Table 14.1-1 (Sheet 40) 13 Table 14.1-1 (Sheet4l) 13 Table 14.1-1 (Sheet 42) 13 Table 14.1-1 (Sheet 43) 13 Table 14.1-1 (Sheet 44) 13 Table 14.1-1 (Sheet 45) 13 Table 14.1-1 (Sheet46) 13 Table 14.1-1 (Sheet 47) 13 Table 14.1-1 (Sheet 48) 13 Table 14.1-1 (Sheet 49) 13 Table 14.1-1 (Sheet 50) 13 Table 14.1-1 (Sheet 51) 13 Table 14.1-1 (Sheet 52) 13 Table 14.1-1 (Sheet 53) 13 Table 14.1-1 (Sheet 54) 13 Table 14.1-1 (Sheet 55) 13 Table 14.1-1 (Sheet 56) 13 Table 14.1-1 (Sheet 57) 13 Table 14.1-1 (Sheet 58) 13 Table 14.1-1 (Sheet 59) 13 Table 14.1-1 (Sheet 60) 13 Table 14.1-1 (Sheet 61) 13 Table 14.1-1 (Sheet 62) 13 Table 14.1-1 (Sheet 63) 13 Table 14.1-1 (Sheet 64) 13 Table 14.1-1 (Sheet 65) 13 Table 14.1-1 (Sheet 66) 13 Table 14.1-1 (Sheet 67) 13 Table 14.1-1 (Sheet 68) 13 Table 14.1-1 (Sheet 69) 13 Table 14.1-1 (Sheet 70) 13 Table 14.1-1 (Sheet 71) 13 Table 14.1-1 (Sheet 72) 13 EPL 65

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment Table 14.1-1 (Sheet 73) 13 Table 14.1-1 (Sheet 74) 13 Table 14.1-1 (Sheet 75) 13 Table 14.1-1 (Sheet 76) 13 Table 14.1-1 (Sheet 77) 13 Table 14.1-1 (Sheet 78) 13 Table 14.1-1 (Sheet 79) 13 Table 14.1-1 (Sheet 80) 13 Table 14.1-1 (Sheet 81) 13 Table 14.1-1 (Sheet 82) 13 Table 14.1-1 (Sheet 83) 13 Table 14.1-1 (Sheet 84) 13 Table 14.1-1 (Sheet 85) 13 Table 14.1-1 (Sheet 86) 13 Table 14.1-1 (Sheet 87) 13 Table 14.1-1 (Sheet 88) 13 Table 14.1-1 (Sheet 89) 13 Table 14.1-1 (Sheet 90) 13 Table 14.1-1 (Sheet 91) 13 Table 14.1-1 (Sheet 92) 13 Table 14.1-2 (Sheet 1) 13 Table 14.1-2 (Sheet 2) 13 Table 14.1-2 (Sheet 3) 13 Table 14.1-2 (Sheet 4) 13 Table 14.1-2 (Sheet 5) 13 Table 14.1-2 (Sheet 6) 13 Table 14.1-2 (Sheet 7) 13 Table 14.1-2 (Sheet 8) 13 Table 14.1-2 (Sheet 9) 13 Table 14.1-2 (Sheet 10) 13 Table 14.1-2 (Sheet 11) 13 Table 14.1-2 (Sheet 12) 13 Table 14.1-2 (Sheet 13) 13 Table 14.1-2 (Sheet 14) 13 Table 14.1-2 (Sheet 15) 13 Table 14.1-3 (Sheet 1) 13 Table 14.1-3 (Sheet 2) 13 Table 14.1-3 (Sheet 3) 13 Table 14.1-3 (Sheet 4) 13 Table 14.1-3 (Sheet 5) 13 Table 14.1-3 (Sheet 6) 13 Table 14.1-3 (Sheet 7) 13 Table 14.1-3 (Sheet 8) 13 Table 14.1-3 (Sheet 9) 13 Table 14.1-3 (Sheet 10) 13 Table 14.1-3 (Sheet 11) 13 Table 14.1-3 (Sheet 12) 13 Table 14.1-3 (Sheet 13) 13 Table 14.1-3 (Sheet 14) 13 Figure 14.1-1 Original Figure 14.1-2 Original EPL 66

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment Figure 14.1-3 Original Figure 14.1-4 Original 14.2-1 13 14.2-2 13 14.2-3 13 Figure 14.2.2-1 13 Figure 14.2.2-2 13 CHAPTER 15 15-1 21 15-2 21 15-3 18 15-4 18 15-5 21 15-6 18 15-7 21 15-8 21 15-9 18 15-10 21 15-11 21 15-12 22 15-13 22 15-14 22 15-15 22 15-16 21 15-17 21 15-18 21 15.1-1 18 15.1-2 17 15.1-3 21 15.1-4 17 15.1-4a 17 15.1-5 17 15.1-6 13 15.1-7 13 15.1-8 13 15.1-9 13 15.1-10 21 15.1-11 21 15.1-12 13 15.1-13 21 15.1-14 21 15.1-15 21 15.1-16 21 15.1-17 21 Table 15.1.2-1 17 Table 15.1.2-2 (Sheet 1) 19 Table 15.1.2-2 (Sheet 2) 17 Table 15.1.2-2 (Sheet 3) 21 Table 15.1.3-1 (Sheet 1) 17 EPL 67

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Table 15.1.3-1 (Sheet 2) 17 Table 15.1.7-1 13 Table 15.1.7-2 13 Figure 15.1.3-1 17 Figure 15.1.5-1 13 Figure 15.1.5-2 13 Figure 15.1.5-3 13 Figure 15.1.6-1 1 Figure 15.1.8-1 1 Figure 15.1.9-1 13 15.2-1 18 15.2-2 18 15.2-3 18 15.2-4 18 15.2-5 18 15.2-6 18 15.2-7 18 15.2-8 18 15.2-9 18 15.2-10 18 15.2-11 18 15.2-12 18 15.2-13 18 15.2-14 18 15.2-15 18 15.2-16 18 15.2-17 18 15.2-18 18 15.2-19 18 15.2-20 18 15.2-21 18 15.2-22 18 15.2-23 18 15.2-24 18 15.2-25 18 15.2-26 19 15.2-27 18 15.2-28 18 15.2-29 18 15.2-30 22 15.2-31 22 15.2-32 22 15.2-33 22 15.2-34 22 15.2-35 22 15.2-36 22 15.2-37 22 15.2-38 22 15.2-39 21 15.2-40 21 15.2-41 21 EPL 68

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paae Amendment 15.2-42 21 Table 15.2-1 (Sheet 1) 18 Table 15.2-1 (Sheet 2) 13 Table 15.2-1 (Sheet 3) 13 Table 15.2-1 (Sheet 4) 21 Table 15.2-1 (Sheet 5) 15 Table 15.2-1 (Sheet 6) 15 Table 15.2-1 (Sheet 7) 22 Table 15.2-1 (Sheet 8) 22 Table 15.2-1 (Sheet 9) 22 Table 15.2.7-1 13 Table 15.2.7-2 13 Table 15.2.7-3 13 Figure 15.2.1-1 18 Figure 15.2.1-2 18 Figure 15.2.1-3 18 Figure 15.2.2-1 Original Figure 15.2.2-2 Original Figure 15.2.2-3 Original Figure 15.2.2-4 Original Figure 15.2.2-5 Original Figure 15.2.2-6 Original Figure 15.2.2-7 Original Figure 15.2.3-1 Original Figure 15.2.3-2 Original Figure 15.2.4-1 Original Figure 15.2.4-2 Original Figure 15.2.4-3 Original Figure 15.2.5-1 10 Figure 15.2.5-2a 10 Figure 15.2.5-2b 10 Figure 15.2.5-2c 10 Figure 15.2.5-3 10 Figure 15.2.6-1 10 Figure 15.2.6-2 10 Figure 15.2.6-3 10 Figure 15.2.6-4 10 Figure 15.2.7-1 13 Figure 15.2.7-2 13 Figure 15.2.7-3 13 Figure 15.2.7-4 13 Figure 15.2.7-5 13 Figure 15.2.7-6 13 Figure 15.2.7-9 Original Figure 15.2.7-10 Original Figure 15.2.7-11 Original Figure 15.2.7-12 Original Figure 15.2.7-13 1 Figure 15.2.7-14 1 Figure 15.2.7-15 1 Figure 15.2.7-16 1 EPL 69

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Figure 15.2.8-1a & Figure 15.2.8-1b 15 Figure 15.2.8-2a & Figure 15.2.8-2b 15 Figure 15.2.8-3a & Figure 15.2.8-3b 15 Figure 15.2.8-4a & Figure 15.2.8-4b 15 Figure 15.2.9-1a & Figure 15.2.9-1b 15 Figure 15.2.9-2a & Figure 15.2.9-2b 15 Figure 15.2.9-3a & Figure 15.2.9-3b 15 Figure 15.2.9-4a & Figure 15.2.9-4b 15 Figure 15.2.10-1 22 Figure 15.2.10-2 22 Figure 15.2.10-3 22 Figure 15.2.10-4 22 Figure 15.2.10-5 22 Figure 15.2.10-6 22 Figure 15.2.10-7 22 Figure 15.2.10-8 22 Figure 15.2.10-9 22 Figure 15.2.10-10 22 Figure 15.2.10-11 22 Figure 15.2.10-12 22 Figure 15.2.10-13 22 Figure 15.2.10-14 22 Figure 15.2.10-15 22 Figure 15.2.11-1 Original Figure 15.2.11-2 Original Figure 15.2.11-3 Original Figure 15.2.11-4 Original Figure 15.2.11-5 Original Figure 15.2.11-6 Original Figure 15.2.11-7 Original Figure 15.2.11-8 Original Figure 15.2.12-1 Original Figure 15.2.12-2 Original Figure 15.2.12-3 Original Figure 15.2.13-1 Original Figure 15.2.13-2 Original Figure 15.2.13-3 Original Figure 15.2.14-1 Original Figure 15.2.14-2 Original 15.3-1 18 15.3-2 21 15.3-3 21 15.3-4 18 15.3-5 18 15.3-6 18 15.3-7 21 15.3-8 18 15.3-9 18 15.3-10 18 15.3-11 21 15.3-12 21 EPL 70

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Table 15.3.1-1 21 Table 15.3.1-2 21 Table 15.3.4-1 13 Table 15.3.7-1 21 Figure 15.3.1-1 21 Figure 15.3.1-2 21 Figure 15.3.1-3 21 Figure 15.3.1-4 21 Figure 15.3.1-5 21 Figure 15.3.1-6 21 Figure 15.3.1-7 21 Figure 15.3.3-1 Original Figure 15.3.3-2 Original Figure 15.3.3-3 Original Figure 15.3.3-4 Original Figure 15.3.3-5 Original Figure 15.3.4-1 13 Figure 15.3.4-2 13 Figure 15.3.7-1 21 Figure 15.3.7-2 21 Figure 15.3.7-3 21 15.4-1 21 15.4-2 21 15.4-3 21 15.4-4 21 15.4-5 21 15.4-6 21 15.4-7 21 15.4-8 21 15.4-9 21 15.4-10 21 15.4-11 21 15.4-12 21 15.4-13 23 15.4-14 21 15.4-15 21 15.4-16 21 15.4-17 21 15.4-18 21 15.4-19 21 15.4-20 21 15.4-21 21 15.4-22 21 15.4-23 21 15.4-24 21 15.4-25 21 15.4-26 21 15.4-27 21 15.4-28 21 15.4-29 21 15.4-30 21 EPL 71

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paqe Amendment 15.4-31 21 15.4-32 21 15.4-33 21 15.4-34 21 15.4-35 21 15.4-36 21 Table 15.4.1-1 (Sheet 1) 21 Table 15.4.1-1 (Sheet 2) 21 Table 15.4.1-2 21 Table 15.4.1-2a 21 Table 15.4.1-3 21 Table 15.4.1-4 21 Table 15.4.1-5 21 Table 15.4.1-6 (Sheet 1) 13 Table 15.4.1-6 (Sheet 2) 13 Table 15.4.1-7 13 Table 15.4.1-9 (Sheet 1) 13 Table 15.4.1-9 (Sheet 2) 15 Table 15.4.1-9 (Sheet 3) 15 Table 15.4.1-12 (Sheet 1) 13 Table 15.4.1-12 (Sheet 2) 13 Table 15.4.2-1 13 Table 15.4.4-1 13 Table 15.4.6-1 13 Figure 15.4.1-1 21 Figure 15.4.1-2 21 Figure 15.4.1-3 21 Figure 15.4.1-4 21 Figure 15.4.1-6 21 Figure 15.4.1-7 21 Figure 15.4.1-9 21 Figure 15.4.1-10 21 Figure 15.4.1-11 21 Figure 15.4.1-14 21 Figure 15.4.1-15 21 Figure 15.4.1-16 21 Figure 15.4.1-17 21 Figure 15.4.1-18 21 Figure 15.4.2-1 13 Figure 15.4.2-2 13 Figure 15.4.2-3 13 Figure 15.4.2-4 13 Figure 15.4.2-5 13 Figure 15.4.2-6 13 Figure 15.4.2-7 13 Figure 15.4.2-8 13 Figure 15.4.2-9 13 Figure 15.4.2-10 13 Figure 15.4.2-11 13 Figure 15.4.2-12 13 Figure 15.4.2-13 13 EPL 72

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Paeg Amendment Figure 15.4.2-14 13 Figure 15.4.2-15 13 Figure 15.4.2-16 13 Figure 15.4.2-17 13 Figure 15.4.2-18 13 Figure 15.4.2-19 13 Figure 15.4.2-20 13 Figure 15.4.2-21 13 Figure 15.4.2-22 13 Figure 15.4.2-23 13 Figure 15.4.2-24 13 Figure 15.4.2-25 13 Figure 15.4.2-26 13 Figure 15.4.2-27 13 Figure 15.4.2-28 13 Figure 15.4.2-29 13 Figure 15.4.2-30 13 Figure 15.4.2-31 13 Figure 15.4.2-32 13 Figure 15.4.2-33 13 Figure 15.4.2-34 13 Figure 15.4.2-35a & 15.4.2-35b 15 Figure 15.4.2-36a & 15.4.2-36b 15 Figure 15.4.2-37a & 15.4.2-37b 15 Figure 15.4.2-38a & 15.4.2-38b 15 Figure 15.4.4-1 8 Figure 15.4.4-2 8 Figure 15.4.4-3 8 Figure 15.4.4-4 8 Figure 15.4.4-5 13 Figure 15.4.6-1 10 Figure 15.4.6-2 10 Figure 15.4.6-3 10 Figure 15.4.6-4 10 15.5-1 18 15.5-2 18 15.5-3 18 15.5-4 18 15.5-5 18 15.5-6 18 15.5-7 18 15.5-8 18 15.5-9 18 15.5-10 21 15.5-11 21 15.5-12 18 15.5-13 18 15.5-14 21 15.5-15 21 15.5-16 21 15.5-17 18 EPL 73

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment 15.5-18 18 15.5-19 18 15.5-20 18 15.5-21 18 15.5-22 18 15.5-23 18 15.5-24 20 15.5-25 20 15.5-26 18 15.5-27 18 15.5-28 18 Table 15.5.1-1 18 Table 15.5.2-1 18 Table 15.5.2-2 13 Table 15.5.3-1 (Sheet 1) 13 Table 15.5.3-1 (Sheet 2) 13 Table 15.5.3-2 13 Table 15.5.3-3 13 Table 15.5.3-4 18 Table 15.5.3-5 13 Table 15.5.3-6 18 Table 15.5.3-7 18 Table 15.5.3-8 (Sheet 1) 13 Table 15.5.3-8 (Sheet 2) 13 Table 15.5.4-1 18 Table 15.5.4-2 (Sheet 1) 13 Table 15.5.4-2 (Sheet 2) 13 Table 15.5.5-1 (Sheet 1) 20 Table 15.5.5-1 (Sheet 2) 18 Table 15.5.6-1 (Sheet 1) 18 Table 15.5.6-1 (Sheet 2) 18 Table 15.5.6-1 (Sheet 3) 18 Table 15.5.6-2 13 Table 15.5.6-3 15 Figure 15.5.1-1 10 Figure 15.5.1-2 10 Figure 15.5.1-3 10 Figure 15.5.3-1 Original 15A-1 18 15A-2 18 15A-3 18 15A-4 18 Table 15A-1 18 Table 15A-2 18 15B-1 13 15B-2 13 15B-3 13 151B-4 13 158-5 13 15B-6 13 15B-7 13 EPL 74

SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE EFFECTIVE PAGE LISTING Effective Page Amendment Table 15B-1 13 Table 15B-2 13 Table 15B-3 13 Figure 15B-1 10 Figure 15B-2 Original Figure 15B-3 10 Figure 15B-4 Original Figure 15B-5 10 Figure 15B-6 10 Figure 15B-7 10 Figure 15B-8 10 Figure 15B-9 10 Figure 15B-10 10 Figure 15B-11 10 15C-1 13 15C-2 13 15C-3 13 15C-4 13 15C-5 13 15C-6 13 15C-7 13 Figure 15C-1 11 15D-1 18 15D-2 18 15D-3 18 Table 15D-1 18 Table 15D-2 18 Table 15D-3 18 CHAPTER 17 17-1 13 17.1-1 13 17.2-1 19 EPL 75

SQN SEQUOYAH NUCLEAR PLANT FINAL SAFETY ANALYSIS REPORT UPDATE LIST OF AMENDMENTS Amendment Number Date Submitted to NRC Updated FSAR Submitted April 14, 1983 Amendment 1 April 16, 1984 Amendment 2 April 11, 1985 Amendment 3 April 11, 1986 Amendment 4 April 20, 1987 Amendment 5 April 20, 1988 Amendment 6 April 14, 1989 Amendment 7 April 27, 1990 Amendment 8 April 15, 1991 Amendment 9 April 15,1992 Amendment 10 April 14,1994 Amendment 11 May 12, 1995 Amendment 12 December 6, 1996 Amendment 13 March 25, 1998 Amendment 14 May 4, 1998 Amendment 15 November 9, 1999 Amendment 16 May 10, 2001 Amendment 17 November 8, 2002 Amendment 18 May 28, 2004 Amendment 19 October 13, 2005 Amendment 20 June 12, 2007 Amendment 21 December 5, 2008 Amendment 22 May 24, 2010 Amendment 23 December 14, 2011 EPL-76

SQN-19 ISOL Isolation JB Junction Box JCT Junction K Kip KIP 1000 Pounds kJ Kilojoules kV Kilovolt kVA Kilovolt Ampere kW Kilowatt kWH Kilowatt Hours LAB Laboratory LB Pounds LCO Limiting Conditions for Operation LCV Level Control Valves LHR Linear Heat Rate LOCA Loss of Coolant Accident LP Low Pressure LPT Low Profile Transporter LPZ Low Population Zone LS Limit Switch LSS Lower Support Structure LTDN Letdown LWPS Liquid Waste Processing System MAN Manual MAP Maximum Allowable Peak Mark-BW Mark-BW fuel MCC Motor Control Center MCR Main Control Room MECH Mechanical MFPT Main Feedwater Pump Turbine MFRR Manufacturer MISC Miscellaneous MK NO Mark Number MOV Motor Operated Valve MPC Multi-Purpose Canister mR Millirem MSR Moisture Separator Reheater MKUP Makeup MULT Multiple MV Millivolt MVA Megavoltamperes MW Megawatt MWH Megawatt-Hour MWT Megawatt Thermal N2 Nitrogen NDT Nondestructive Testing NDTT Nil Ductility Transition Temperature NIM Nuclear Instrumentation Module NIS Nuclear Instrumentation System NOM Nominal 1.7-7

SQN-23 NOR Normal NQAM Nuclear Quality Assurance Manual NPSH Net Positive Suction Head NSSS Nuclear Steam Supply System NUC Nuclear NVT Fast Neutron Exposure (No. x Velocity x Time) 02 Oxygen OD Outside Diameter OPER Operator ORF Orifice OSC Oscillograph OSGSF Old Steam Generator Storage Facility OSG Original Steam Generators (Unit 2 only)

P-AUTO Process-Automatic PAX Private Automatic Exchange PCB Power Circuit Breaker PCI Pellet Cladding Interaction PD Positive Displacement PDIS Pressure Differential Indicating Switch PDS Pressure Differential Switch PF Power Factor pH Measure of Acidity and Basicity PIE Post Irradiation Exam PLT Plant PMF Probable Maximum Flood PMP Pump PMWS Primary Makeup Water System PNEU Pneumatic PNL Panel POSN Position PPM Parts Per Million PRESS Pressure PRI Primary PROC Procedure PROP Proportional PROT Protection PRT Pressurizer Relief Tank PZR Pressurizer PS Pressure Switch PSAR Preliminary Safety Analysis Report PSCC Power System Control Center PSIA Pounds Per Square Inch, Absolute PSIG Pounds Per Square Inch, Gauge P Signal High Containment Pressure Signal PT Point PW Primary Water PWR Pressurized Water Reactor Px Power Supply PWR Sply Power Supply S1-7.doc 1.7-8

SQN Joint percentage frequencies of wind direction and wind speed for the Pasquill stability classes A through G are summarized in Tables 2.3.2-23 through 2.3.2-29 and Figures 2.3.2-16 through 2.3.2-22. The most critical conditions, class G and wind speeds less than 3.5 mph (Table 2.3.2-29, Figure 2.3.2-22), occurred less than six percent of the time. Stability category G is most often associated with downvalley winds (from the north-northeast and northeast), with a secondary maximum associated upvalley winds (from the southwest and south-southwest).

Annual frequencies for classes E and F (Tables 2.3.2-27 and 2.3.2-28) show respective frequencies of about 17 and 15 percent for wind speeds less than 3.5 mph.

Using the same type of instrumentation, the capability for calculating hourly average AT values (based on hourly-average temperature values) was established in January 1975. A special adjustment of the computer program developed for this purpose was made to also obtain instantaneous, end-of-hour AT values for comparison with the hourly-average values.

Table 2.3.2-30 provides the frequencies for hourly-average and end-of-hour stability classes (Pasquill A-G), and Tables 2.3.2-31 through 2.3.2-58 provide joint frequencies of wind direction and wind speed by stability class, each for hourly-average and end-of-hour AT values.

Summaries based on hourly-average and end-of-hour AT values are presented for 33- to 150-foot AT and 33-foot wind direction and wind speed data, and for 33- to 300-foot AT and 300-foot wind direction and wind speed data. The same wind direction and wind speed data were used with the hourly-average and the end-of-hour AT data.

2.3.2.3 Potential Influence of the Plant and its Facilities on Local Meteorology The presence and operation of the Sequoyah Nuclear Plant should have no noticeable effects on the local meteorology, with the exception of a slight increase in frequency, duration, and intensity of steam fogs forming at the river surface due to heated water releases through the diffusers. These fogs develop as a result of elevation of the dew point by the addition of moisture to the air from the water surface. Once this shallow fog moves on shore, the moisture source is cut off and the fog dissipates. Thus, the increased fogging should be confined within the boundaries of the Chickamauga Reservoir and should not affect long-term fog patterns in the surrounding area. This phenomenon has been observed frequently over the extended river and reservoir system within the Tennessee Valley Region.

Based on previous experience with natural-draft cooling tower operation at the TVA Paradise Steam Plant, no adverse impact on the local meteorology is expected from the operation of supplemental natural-draft cooling towers at the Sequoyah Plant. Some minor effects may include increased atmospheric moisture, decreased solar radiation, and increased concentrations of aerosols related to the drift. However, the significance of these effects would be very difficult or impossible to measure.

2.3.2.4 Topographical Description The principal effect of the topography in the Sequoyah area on the diffusion of effluent releases is one of confinement to the downwind sectors of predominant wind. Figure 2.3.2-23, sheets 1-9, shows the topographic features within five miles and topographic cross sections in the 16 compass sectors. Annually, the majority of the releases of radioactive effluent would be 2.3-7

SQN-23 dispersed within the northeasterly and southwesterly quadrants from the plant as a result of the upvalley-downvalley low-level wind. Therefore, relative ground-level concentrations would be expected to be higher in these sectors, particularly during periods of low wind and stable conditions.

Also, with the relatively flat and undulating valley floor, there should be minimal discontinuity of the general low-level wind pattern from terrain roughness or irregularity. Furthermore, differences in the ambient thermal or stability structure in the area from differential surface heating between land and water should not cause significant alterations to the wind and stability patterns in the plant area. On rare occasions, slight buildup of effluent concentration could occur in the Cumberland escarpment area, about 15 miles to the northwest, where some geographically induced impingement or entrapment of the effluent might be expected.

2.3.3 On-Site Meteorolo-gical Measurement Program 2.3.3.1 Siting and Description of Instruments The Sequoyah meteorological facility consists of a 91-meter (300 foot) instrumented tower for wind and temperature measurements, a separate 10-meter (33 foot) tower for dewpoint measurements, a ground-based instrument for rainfall measurements, and an Environmental Data Station (EDS), which houses the data collection and recording equipment. A system of lightning and surge protection circuitry with proper grounding is included in the facility design. This facility is located approximately 0.74 miles (1.2 kilometers) southwest of the Reactor Building and about 50 feet (15 meters) above plant grade (Figure 2.3.2-1).

Rainfall is monitored from a rain gauge located approximately 55 feet from the tower. Data collected include: (1) wind speed and direction at 10, 46, and 91 meters (33, 150, and 300 feet), (2) temperature at 10, 46, and 91 meters; (3) a separate 10 meter (33 foot) tower for dewpoint measurements; and (4) rainfall at 1 meter (3 feet). More exact measurements heights for wind and temperature sensors are given in EDS Manual [Reference 20]. Elsewhere in this document, temperature and wind sensor heights are given as 10, 46, and 91 meters. Collection of onsite meteorological data at the Sequoyah Nuclear Plant commenced in April 1971 with measurements of wind speed and wind direction at 10 meter and 91 meters, temperature at 1, 10, 46, and 91 meters; and dewpoint and rainfall at 1 meter. Measurements of 46 meter windspeed/direction and 10 meter dewpoint began on August 6, 1976. Measurement of 1 meter dewpoint ended on January 9, 1979.

Measurement of 1 meter temperature ended on January 10, 1979. The dewpoint sensor was moved to a separate tower on June 7, 1994.

Instrument Description A description of the meteorological sensors follows. More detailed sensor specifications are included in the EDS manual [Reference 20]. Replacement sensors, which may be of a different manufacturer or model, will satisfy Regulatory Guide 1.23 (Revision 1). [Reference 13]

SENSOR HEIGHT (feet) DESCRIPTION Wind Direction and 10, 46, and 91 Ultrasonic Wind Sensor.

Wind Speed

$2.3.doc 2.3-8

SQN-23 SENSOR HEIGHT (meters) DESCRIPTION Temperature 10, 46, and 91 Platinum wire resistance temperature detector (RTD) with aspirated radiation shield.

Dewpoint 10 Capacitive Humidity Sensor.

I Rainfall 1 Tipping bucket rain gauge.

I 2.3.3.2 Data Acquisition System The data acquisition system is located at the EDS and consists of meteorological sensors, a computer (with peripherals), and various interface devices. These devices send meteorological data to the plant, to the Central Emergency Control Center (CECC), and to enable callup for data validation and archiving offsite.

$2.3.doc 2.3-9

SQN-23 System Accuracies The meteorological data collection system is designed and replacement components are chosen to meet or exceed specifications for accuracy identified in NRC Regulatory Guide 1.23, Revision 1.

The meteorological data collection system (root-sum-squared [RSS] error) satisfies the R.G. 1.23 accuracy requirements. A detailed listing of error sources for each parameter is included in the EDS manual [Reference 20].

2.3.3.3 Data Recording and Display The data acquisition is under control of the computer program. The output of each meteorological sensor is scanned periodically, scaled, and the data values are stored.

Meteorological sensor outputs (except rainfall) are measured every five seconds (720 per hour).

Rainfall is measured continuously as it occurs. Software data processing routines within the computer accumulate output and perform data calculations to generate 15-minute and hourly averages of wind speed and temperature, 15-minute and hourly vector wind speed and direction, 15-minute and hourly total precipitation, hourly average of dewpoint, and hourly horizontal wind direction sigmas. Vector wind speed and direction are calculated along with arithmetic average wind speed.

Selected data each 15 minutes and all data each hour are stored for remote data access.

Data sent to the plant computer systems every minute includes 10, 46, and 91 meter values for wind speed, wind direction, and temperature.

$2.3.doc 2.3-10

SQN-23 Data sent to the Central Emergency Control Center (CECC) computer in Chattanooga every 15 minutes includes 91-, 46-, and 10-meter wind direction, wind speed, and temperature values. These data are available from the CECC computer to other TVA and State emergency centers in support of the Radiological Emergency Plan (REP), including the Technical Support Center at Sequoyah.

Remote access of meteorological data by the NRC is available through the CECC computer.

Data are sent from the EDS to an offsite computer for validation, reporting, and archiving.

2.3.3.4 Equipment Servicing, Maintenance, and Calibration The meteorological equipment at EDS is kept in proper operating condition by staff that are trained and qualified for necessary tasks.

Most equipment is calibrated or replaced at least every six months of service. The methods for maintaining a calibrated status for the components of the meteorological data collection system (sensors, recorders, electronics, DVM, data logger, etc.) include field checks, field calibration, and/or replacement by a laboratory calibrated component. More frequent calibration intervals for individual components may be conducted, on the basis of the operational history of the component type.

Detailed procedures are used and are referenced in the EDS Manual.

2.3.3.5 Operational Meteorological Program The operational phase of the meteorological program includes those procedures and responsibilities related to activities beginning with the initial fuel loading and continuing through the life of the plant.

This phase of the meteorological data collection program will be continuous without major interruptions. The meteorological program has been developed to be consistent with guidance given in NRC Regulatory Guide 1.23 (Revision 1) and the reporting procedure in Regulatory Guide 1.21 (Revision 1). [Reference 14] The basic objective is to maintain data collection performance to assure at least 90 percent joint recoverability and availability of data needed for assessing the relative concentrations and doses resulting from accidental or routine releases.

The restoration of the data collection capability of the meteorological facility in the event of equipment failure or malfunction will be accomplished by replacement or repair of affected equipment. A stock of spare parts and equipment is maintained to minimize and shorten the periods of outages. Equipment malfunctions or outages are detected by maintenance personnel during routine or special checks.

Equipment outages that affect the data transmitted to the plant can be detected by review of data displays in the reactor control room. Also, checks of data availability to the emergency centers are performed each work day. When an outage of one or more of the critical data items occurs, the appropriate maintenance personnel will be notified.

S2.3.doc 2.3-11

SQN In the event that the onsite meteorological facility is rendered inoperable, or there is an outage of communications or data access systems; there is no fully representative offsite source of meteorological data for identification of atmospheric dispersion conditions. Therefore; TVA has I:5 prepared objective backup procedures to provide estimates for missing or garbled data. These procedures incorporate available onsite data (for a partial loss of data), offsite data, and conditional climatology. The CECC meteorologist will apply the appropriate backup procedures. I 15 2.3.4 Short-Term (Accident) Diffusion Estimates 2.3.4.1 Obiective Two sets of atmospheric dilution factors (X/Q values) are currently used for accident releases modeled as ground level releases from the Sequoyah Nuclear Plant for specified time intervals and distances. The first set is based on one year (April 2, 1971 through March 31, 1972) of data from the Sequoyah permanent meteorological facility. Part of this set was used in the design accident dose calculations and is shown in Table 15A-2. The latest and most widely used set is based on four years (January 1972 through December 1975) of data (Tables 2.3.2-23 through 2.3.2-29). This data was used in Chapter 11.

2.3.4.2 Calculations Two mathematical models were used in estimating atmospheric dilution factors during postulated reactor accidents - one for the 1-hour and 8-hour (0-8 hours) averaging periods and the other for the 16-hour (8-24 hours), 3-day (1-4 days), and 26-day (4-30 days) averaging periods. Calculations with the two models utilize hourly values of wind direction, wind speed, and atmospheric stability (Pasquill classes A through G).

Nomenclature A = minimum cross-sectional area of the Reactor Building (m2 )

c = an empirical constant used in defining the magnitude of the building wake (dimensionless)

Q = source strength or effluent release rate (curies/sec) u = mean horizontal wind speed at 10 meters (m/sec) x = distance from effluent release point to point at which X/Q values are computed (m) 71 = 3.1416 S2-3.doc 2.3-12

SQN-21 In calculating the average annual atmospheric dispersion factors for the selected distances between 1 and 50 miles, it is assumed that gaseous effluents are released from a single point (the three release zones are not considered in these calculations). The distances to the unrestricted area boundary from this point are shown in Table 11.3.9-1.

Atmospheric dispersion calculations are based on a building wake model described by Davidson

[16,17]. The average annual atmospheric dispersion factor at any point of interest x is given by:

wind stability speeds types X (12)1/2w(Z)f

- = _L Z1Xi Ej U SEC/rM3 Q" 4r W (~~Ui where W = 2p x/1 6, the sector width at downwind distances x, m, u= wind speed i, m/s, fij- frequency with which wind speed ul occurs in the sector of interest during atmospheric stability class j,

( 2 ) () +j 1 the vertical standard deviation of the plume (modified for the effect of building wake dilution) at the distance x for stability class J, m, (o'=)j = Pasquill vertical standard deviation of the plume at the distance x for stability class j, m, c parameter that relates the cross-sectional area of a building to the size of the turbulent wake caused by the building, A = minimum Reactor Building cross-sectional area, m2 .

In the expression for (oa), c is assumed to be 0.5 and A is assumed to be 1,800 M2. Table 2.3.4-14 lists average annual atmospheric dispersion factors for the Sequoyah site.

2.3.6 References

1. U.S. Atomic Energy Commission, A Meteorological Survey of the Oak Ridge Area, ORO-99, Weather Bureau, Oak Ridge, Tennessee November 1953, page 377.

S2.3.doc 2.3-17

SQN-23

2. U.S. Atomic Energy Commission, A Meteorological Survey of the Oak Ridge Area, ORO-99, Weather Bureau, Oak Ridge, Tennessee, November 1953, page 192.

3. Local Climatological Data, "Annual Summary With Comparative Data," Chattanooga, Tennessee, U.S. Department of Commerce, NOAA, National Climatic Center, Asheville, North Carolina, 1979.

4. Severe Local Storm Occurrences, 1955-1967, ESSA Technical Memorandum WSTM FCST 12, U.S. Department of Commerce, Weather Bureau (now NWS), Silver Spring, Maryland, September 1969.

5. "Tornado Occurrences in Tennessee, 1916-1964," John V. Vaiksnoras, U.S. Department of Commerce, Weather Bureau, Nashville, Tennessee, May 5, 1965.

6. "Tornado Probabilities," H. C. S. Thom, Monthly Weather Review, Volume 91, Nos. 10-12, 1963, pp. 730-736.

7. Discussion with John Vaiksnoras, State Climatologist for Tennessee, Nashville, Tennessee, August 3, 1972.

8. "Tornadoes of the United States," Snowden D. Flora, University of Oklahoma Press, November 1953.

9. Mixing Heights, Wind Speeds, and Potential for Urban Air Pollution Throughout the Contiguous United States, George C. Holzworth, Division of Meteorology, Environmental Protection Agency, Preliminary Document, May 10, 1971.

10. Precipitation in the Tennessee River Basin, Tennessee Valley Authority, Division of Water Control Planning, Hydraulic Data Branch, period of record 35 Years (1935-1969).

11. Glaze - Its Meteorology and Climatology, Geographical Distribution, and Economic Effects, Technical Report EP-105, U.S. Army, Domestic Area Section, Quartermaster Research and Engineering Center, Environmental Protection Research Division, Natick, Massachusetts, March 1959.

12. Ostby, Frederick, employee of U.S. Department of Commerce, NOAA, NWS, National Severe Storms Forecast Center, Kansas City, Missouri, telephone conversation with TVA meteorologist, Norris Nielsen, September 14, 1973.

13. U.S. Nuclear Regulatory Commission, Regulatory Guide 1.23, Revision 1, "Meteorological Monitoring Programs for Nuclear Power Plants," Washington, D.C., March 2007.

14. Regulatory Guide 1.21, Revision 1, "Measuring, Evaluating, and Reporting Radioactivity in Solid Wastes and Releases of Radioactive Materials in Liquid and Gaseous Effluents from Light-Water-Cooled Nuclear Power Plants," U.S. Atomic Energy Commission, Washington, D.C.,

June 1974.

$2.3.doc 2.3-18

SQN-23

15. Regulatory Guide 1.4, Revision 2, "Assumptions Used for Evaluating the Potential Radiological Consequences of a Loss of Coolant Accident for Pressurized Water Reactors," U.S. Atomic Energy Commission, Washington, D.C., June 1974.

16. Meteorology and Atomic Energy, D. H. Slade, ed., USAEC Report, TID-24190, July 1968.

17. Atmospheric Diffusion Experiments with SF 6 Tracer Gas at Three Mile Island Nuclear Station Under Low Wind Speed Inversion Conditions, Pickard, Lowe, and Associates, Inc., The Research Corporation of New England, General Public Utilities Service Corporation, January 1972.

18. Tornado data for the Sequoyah Nuclear Plant site prepared by the National Severe Storms Forecast Center, Kansas City, Missouri, November 1987.

19. "Extremes of Snowfall: United States and Canada," Weatherwise, Published for American Meteorological Society by Weatherwise, Inc., December 1970.

20. Sequoyah Nuclear Plant Environmental Data Station Manual, Tennessee Valley Authority.

21. Deleted by Amend 15

22. Deleted by Amend 15

23. Deleted by Amend 23.

24. Storm Data, U.S. Department of Commerce, NOAA, National Climatic Data Center, Asheville, North Carolina, Volume 29, Number 1 through Volume 44, Number 10, January 1987 - October 2002.

25. Local Climatological Data, "Annual Summary with Comparative Data," Chattanooga, Tennessee, U.S. Department of Commerce, NOAA, National Climatic Data Center, Asheville, North Carolina, 2002.

26. Climatological Data, Tennessee, U.S. Department of Commerce, NOAA, National Climatic Data Center, Asheville, North Carolina, Volumes 101-107, July (Number 7) Issues, 1996 - 2002.

27. Lighting Strike Density for the Contiguous United States From Thunderstorm Duration Records, NUREG/CR-3759, prepared by NOAA's National Severe Storms Laboratory, Norman, Oklahoma, for Division of Health, Siting, and Waste Management, Office of Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission, Washington, D.C., May 1984.

28. Precipitation in the Tennessee River Basin, Tennessee Valley Authority, Division of Water Control Planning, Hydraulic Data Branch, 1968 - 1972.

S2.3.doc. 2.3-19

SQN-21 volume of water in storage is above the SMOG, the weekly average system minimum flow requirement will be increased each week from 14,000 cfs (cubic feet per second) the first week of June to 25,000 cfs the last week of July.

Beginning August 1 and continuing through Labor Day, the weekly average flow requirement will be 29,000 cfs. If the volume of water in storage is below the SMOG curve, 13,000 cfs weekly average minimum flows will be released from Chickamauga Dam between June 1 and July 31, and 25,000 cfs weekly average minimum flows will be released from August 1 through Labor Day.

Within these weekly averages, TVA has the flexibility to schedule daily and hourly flows to best meet all operating objectives, including water supply for TVA's thermal power generating plants. Flows may be higher than these stated minimums if additional releases are required at tributary or main river reservoirs to maintain allocated flood storage space or during critical power situations to maintain the integrity and reliability of the TVA power supply system.

In the assumed event of complete dam failure of the north embankment of Chickamauga Dam resulting in a breach width of 400 feet, with the Chickamauga pool at elevation 681, the water surface at SQN will begin to drop within one hour and will fall to elevation 641 about 60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br /> after failure.

TVA will begin providing steady releases of at least 14,000 cfs at Watts Bar within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of Chickamauga Dam failure to assure that the water level recession at SQN does not drop below elevation 641. The estimated minimum river flow requirement for the ERCW system is only 45 cfs.

Reference:

Programmatic Environmental Impact Statement, TVA Reservoir Operations Study, Record of Decision, May 2004.

2.4.11.2 Low Water Resultinq From Surges, Seiches, or Tsunamis Because of its inland location on a relatively small, narrow lake, low water levels resulting from surges, seiches, or tsunamis are not a potential problem.

2.4.11.3 Historical Low Water From the beginning of stream gauge records at Chattanooga in 1874 until the closure of Chickamauga Dam in January 1940, the lowest daily flow in the Tennessee River at SQN was 3,200 cfs on September 7 and 13, 1925. The next lowest daily flow of 4,600 cfs occurred in 1881 and also in 1883.

Since January 1942, low flows at the site have been regulated by TVA reservoirs, particularly by Watts Bar and Chickamauga Dams. Under normal operating conditions, there may be periods of several hours daily when there are no releases from either or both dams, but average daily flows at the site have been less than 5,000 cfs only 0.65 percent of the time and have been less than 10,000 cfs, 5.19 percent of the time.

On March 30 and 31, 1968, during special operations for the control of watermilfoil, there were no releases from either Watts Bar or Chickamauga Dams during the two-day period. The previous minimum daily flow was 700 cfs on November 1, 1953. TVA no longer conducts special operations for the control of water milfoil on Chickamauga Reservoir.

Since January 1940, water levels at the plant have been controlled by Chickamauga Reservoir. Since then,-the minimum level at the dam was 673.3 on January 21, 1942. TVA no longer routinely conducts pre-flood drawdowns below elevation 675 at Chickamauga Reservoir and the minimum elevation in the past 20 years (1987 - 2006) was 674.97 at Chickamauga head water.

2.4.11.4 Future Control Future added controls which could alter low flow conditions at the plant are not anticipated because no sites that would have a significant influence remain to be developed.

S2-4.doc 2.4-33

SQN-23 2.4.11.5 Plant Requirements 2.4.11.5.1 Two-Unit Operation The safety related water supply systems requiring river water are: the essential raw cooling water (ERCW) (Subsection 9.2.2), and that portion of the high-pressure fire-protection system (HPFP)

(Subsection 2.4A.4.1) supplying emergency feedwater to the steam generators. The fire/flood mode pumps are submersible pumps located in the CCW intake pumping station. The CCW intake pumping station sump is at elevation 648. The entrances to the suction pipes for the fire/flood mode pumps are at elevation 651 feet 0 inches which is 32 feet and 24 feet, respectively, below the maximum normal water elevation of 683.0 and the normal minimum elevation of 675.0 for the reservoir. Abnormal reservoir level is 670 feet with a technical specification limit of 674 ft. For flow requirements of the HPFP during engineering safety feature operation, see subsection 9.5.1. The ERCW pump sump in this independent station is at elevation 625.0, which is 58.0' below maximum normal water elevation, 50.0' below minimum normal water elevation, and 16' below the 641' minimum possible elevation of the river.

Since the ERCW pumping station has direct communication with the river for all water levels and is above probable maximum flood, the ERCW system for two-unit plant operation always operates in an open cooling cycle.

2.4.11.6 Heat Sink Dependability Requirements The ultimate heat sink, its design bases and its operation, under all normal and credible accident conditions is described in detail in Subsection 9.2.5. As discussed in Subsection 9.2.5, the sink was modified by a new essential raw cooling water (ERCW) pumping station before unit 2 began operation.

The design basis and operation of the ERCW system, both with the original ERCW intake station and with the new ERCW intake station, is presented in Subsection 9.2.2. As described in these sections, the new ERCW station is designed to guarantee a continued adequate supply of essential cooling water for all plant design basis conditions. This position is further assured since additional river water may be provided from TVA's upstream multiple-purpose reservoirs, as previously discussed during Low Flow in Rivers and Streams.

2.4.11.6.1 Loss of Downstream Dam The loss of downstream dam will not result in any adverse effects on the availability of water to the ERCW system or these portions of the original HPFP supplying emergency feedwater to the steam generator. Loss of downstream dam reduces ERCW flow about 7% to the component cooling and containment spray heat exchangers. ERCW flow does not decrease below that assumed in the analysis (analyzed as 670' to 639') until more than two hours after the peak containment temperature and pressure occurs. (See Section 6.2.1.3.4.)

2.4.11.6.2 Adequacy of Minimum Flow The cooling requirements for plant safety-related features are provided by the ERCW system. The required ERCW flow rates under the most demanding modes of operation (including loss of downstream dam) as given in Subsection 9.2.2 are contained in TVA calculations and flow diagrams.

Two other safety-related functions may require water from the ultimate heat sink; these are fire protection water (refer to Subparagraph 2.4.11.6.3) and emergency steam generator feedwater (refer to Subsection 10.4.7). These two functions have smaller flow requirements than the ERCW systems.

Consequently, the relative abundance of the river flow, even under the worst conditions, assures the availability of an adequate water supply for all safety-related plant cooling water requirements.

$2-4.doc 2.4-34

SQN-21

[4] TVA, Chickamauga Reservoir Sediment Investigations, Cross Sections, 1940-1961, Division of Water Control Planning, Hydraulic Data Branch.

[5] TVA, Measured Cross Sections of Chickamauga Reservoir, 1972, Flood Protection Branch.

[6] Fischer, H. B., List, E. J., Koh, R.C.Y., Imberger, J., Brooks, N. H. (1979), Mixing in Inland and Costal Waters, Academic Press, New York.

[7] Chow, V. T. (1959) Open-Channel Hydraulics, McGraw-Hill, New York.

[8] United States Nuclear Regulatory Commission, Office of Standards Development, Regulatory Guide 1.113 (April 1977), "Estimating Aquatic Dispersion of Effluents from Accidental and Routine Reactor Releases for the Purpose of Implementing Appendix I," Revision 1.

[9] McIntosh, D. A., Johnson, B. E. and Speaks, E. B. (October 1982), "A Field Verification of Sequoyah Nuclear Plant Diffuser Performance Model: One-Unit Operation," TVA, Office of Natural Resources, Division of Air and Water Resources, Water Systems Development Branch, Norris, TN, Report No. WR28-1-45-110.

[10] 10 CFR Part 20, Appendix B, Table II, Column 2.

[11] TVA SQN Calculation SQN-SQS2-0242, SQN Site Iodine-131 Release Concentration in Tennessee River.

2.4.13 Groundwater (HISTORICAL INFORMATION) 2.4.13.1 Description and Onsite Use The peninsula on which SQN is located is underlain by the Conasauga Shale, a poor water-bearing formation. About 2,000 feet northwest of the plant site, the trace of the Kingston Fault separates this outcrop area of the Conasauga Shale from a wide belt of Knox Dolomite. The Knox is the major water bearing formation of eastern Tennessee.

Groundwater in the Conasauga Shale occurs in small openings along fractures and bedding planes; these rapidly decrease in size with depth, and few openings exist below a depth of 300 feet.

Groundwater in the Knox Dolomite occurs in solutionally enlarged openings formed along fractures and bedding planes and also in locally thick cherty clay overburden.

There is no groundwater use at SQN.

2.4.13.2 Sources The source of groundwater at SQN.is recharged by local, onsite precipitation. Discharge occurs by movement mainly along strike of bedrock, to the northeast and southwest, into Chickamauga Lake.

Rises in the level of Chickamauga Lake result in corresponding rises in the water table and recharge along the periphery of the lake, extending inland for short distances. Lateral extent of this effect varies with local slope of the water table, but probably nowhere exceeds 500 feet. Lowering levels of Chickamauga Lake results in corresponding declines in the water table along the lake periphery, and short-term increase in groundwater discharge.

When SQN was initially evaluated in the early 1970s, it was in a rural area, and only a few houses within a two-mile radius of the plant site were supplied by individual wells in the Knox Dolomite (see Table 2.4.13-1, Figure 2.4.13-1). Because the average domestic use probably does

$2-4.doc 2.4-39

SQN-23 not exceed 500 gallons per day per house, groundwater withdrawal within a two-mile radius of the plant site was less than 50,000 gallons per day. Such a small volume withdrawal over the area would have essentially no effect on areal groundwater levels and gradients. Although development of the area has increased, public supplies are available and overall groundwater use is not expected to increase.

Public and industrial groundwater supplies within a 20 mile radius of the site in 1985 are listed in Table 2.4.13-2. The area groundwater gradient is towards Chickamauga Lake, under water table conditions, and at a gradient of less than 120 feet per mile. The water table system is shallow, the surface of which conforms in general to the topography of the land surface. Depth to water ranges from less than 10 feet in topographically low areas to more than 75 feet in higher areas underlain by Knox Dolomite. Figure 2.4.13-2 is a generalized water-table map of SQN, based on water level data from five onsite observation wells, and in private wells adjacent to the site in April 1973, and also based on surface resistivity measurements of depth to water table made in 1972.

Because permeability across strike in the Conasauga Shale is extremely low, and nearly all water movement is in a southwest-northeast direction, along strike, the Conasauga-Knox Dolomite Contact is a hydraulic barrier, across which only a very small volume of water could migrate in the event large groundwater withdrawals were made from the adjacent Knox.

Although some water can cross this boundary, the permeability normal to strike of the Conasauga is too low to allow development of an areally extensive cone of depression.

Groundwater recharge occurs to the Conasauga Shale at the plant site. Recharge water moves no more than 3,000 feet before being discharged to Chickamauga Lake.

2.4.13.3 Accident Effects Design features in SQN further protect groundwater from contamination.

Category I structures in the SQN facility are designed to assure that all system components perform their designed function, including maintenance of integrity during earthquake.

Buildings in which radioactive liquids could be released due to the equipment failure, overflow, or spillage are designed to retain such liquids even if subject to an earthquake equivalent to the safe shutdown earthquake. Outdoor tanks that contain radioactive liquids are designed so that if they overflow, the overflow liquid is redirected to the building where the liquid is collected in the radwaste system. Two outdoor tanks that contain low concentrations of radioactivity at times overflow to yard drains which discharge into the diffuser pond. Overflow liquid is discharged near the discharge diffuser.

The capacity for dispersion and dilution of contaminants by the groundwater system of the Conasauga Shale is low. Dispersion would occur slowly because water movement is limited to small openings along fractures and bedding planes in the shale. Clay minerals of the Conasauga Shale do, however, have a relatively high exchange capacity, and some of the radioactive ions would be absorbed by these minerals. Any ions moving through the groundwater system eventually would be discharged to Chickamauga Lake.

$2-4.doc 2.4-40

SQN-23 The Conasauga Shale is heterogeneous and anisotropic vertically and horizontally. Water-bearing characteristics change abruptly within short distances. Standard aquifer analyses cannot be applied, and meaningful values for permeability, time of travel, or dilution factors cannot be obtained.

Bedrock porosity is estimated to be less than 3 percent based on examination of results of exploratory core drilling. It is known from experience elsewhere in this region that water movement in the Conasauga Shale occurs almost entirely parallel to strike. Subsurface movement of a liquid radwaste release at the plant site would be about 1,000 feet to the northeast or about 2,000 feet to the southwest before discharge to Chickamauga Lake.

Time of travel can only be estimated as being a few weeks for first arrival, a few months for peak concentration arrival, and perhaps two or more years for total discharge. The computed mean time of travel of groundwater from SQN to Chickamauga Lake is 303 days.

No radwaste discharge would reach a groundwater user. At the nearest point, the reservation boundary lies 2,200 feet northwest of the plant site, across strike. Groundwater movement will not occur from the plant site in this direction across this distance.

During initial licensing, the radionuclide concentrations were determined for both groundwater and surface water movement to the nearest potable water intake (Savannah Valley Utility District, which is no longer in service) and found to be of no concern (see Safety Evaluation Report, March 1979, Section 2.4.4 Groundwater).

2.4.13.4 Monitorinq or Safe-guard Requirements SQN is on a peninsula of low-permeability rock; the groundwater system of the site is essentially hydraulically isolated and potential hazard to groundwater users of the area is minimal. The environmental radiological monitoring program is addressed in Section 11.6.

Monitor wells 1, 2, 3, and 4 were sampled and analyzed for radioactivity during the period from 1976 through 1978. Well 5 was not monitored because of insufficient flow. An additional well (Well 6) was drilled in late 1978 downgradient from the plant and a pump sampler installed.

Wells 1, 2, 4, and 5 are each 150 feet deep, Well 6 is 250 feet deep, and Wells L6 and L7 are 75-80 feet deep. All of the wells are cased in the residuum and open bore in the Conasauga Shale.

2.4.13.5 Conclusions SQN was designed to provide protection of groundwater resources by preventing the escape of the leaks of radionuclides. Site soils and underlying geology provide further protection in that they retard the movement of water and attenuate any contaminants that would be released. All groundwater movement is toward Chickamauga Lake. The Knox Dolomite is essentially hydraulically separated from the Conasauga Shale; therefore, offsite pumping, including future development, should have little effect upon the groundwater table in the Conasauga Shale at the plant.

Even though the potential for accidental contamination of the groundwater system is extremely low, the radiological monitoring program will provide ample lead times to mitigate any offsite contamination.

S2-4.doc 2.4-41

SQN-17 As a consequence of the geohydrologic conditions that remain unchanged from evaluations conducted in the 1970s, the information in Chapter 2.4.13 Groundwater is historical and should not be subject to updating revisions.

2.4.14 Technical Requirements and Emergency Operation Requirements Emergency flood protection plans, designed to minimize impact of floods above plant grade on safety-related facilities, are described in Appendix 2.4A. Procedures for predicting rainfall floods, arrangements to warn of upstream dam failure floods, and lead times available and types of action to be taken to meet related safety requirements for both sources of flooding are described therein. The Technical Requirements Manual specify the action to be taken to minimize the consequences of flccds.

2.4.15 References

1. U.S. Weather Bureau, "Probable Maximum and TVA Precipitation Over The Tennessee River Basin Above Chattanooga," Hydrometeorological Report No. 41, 1965.

2. U.S. Weather Bureau, "Probable Maximum and TVA Precipitation for Tennessee River Basins Up To 3,000 Square Miles in Area and Duration to 72 Hours," Hydrometeorological Report No.

45, 1969.

3. Garrison, J. M., Granju, J. P., and Price, J. T., "Unsteady Flow Simulation in Rivers and Reservoirs," Journal of the Hydraulics Division, ASCE, Vol. 95, No. HY5, Proceedings Paper 6771, September 1969, pp. 15559-1576.

4. PSAR, Phipps Bend Nuclear Plant, Docket Nos. 50-553, 50-554.

5. Tennessee Valley Authority, "Flood Insurance Study, Hamilton County, Tennessee, (Unincorporated Areas)," Division of Water Resources, February 1979.

6. U.S. Army Engineering, Corps of Engineers, Omaha, Nebraska, "Severe Windstorms of Record,"

Technical Bulletin No. 2, Civil Works Investigations Project CW-178 Freeboard Criteria for Dams and Levees, January 1960.

7. U.S. Army Corps of Engineers, "Computation of Freeboard Allowances for Waves in Reservoirs,"

Engineering Engineer Technical Letter No. 1110-2-8, August 1966.

8. U.S. Army Coastal Engineering Research Center, "Shore Protection, Planning, and Design," 3rd Edition, 1966.

9. Reference removed per Amendment 6.

10. Hinds, Julian, Creager, William P., and Justin, Joel D., "Engineering For Dams," Vol. II, Concrete Dams, John Wiley and Sons, Inc., 1944.

11. Bustamante, Jurge I., Flores, Arando, "Water Pressure in Dams Subject to Earthquakes," Journal of the Engineering Mechanics Division, ASCE Proceedings, October 1966.

12. Chopra, Anil K., "Hydrodynamic Pressures on Dams During Earthquakes," Journal of the Engineering Mechanics Division, ASCE Proceedings, December 1967.

S2-4.doc 2.4-42

SQN-23 The temperatures can be maintained at a value appreciably less than the fuel pit temperature calculated for the nonflood spent fuel cooling case when assuming the loss of one equipment train.

As further assurance, the open reactor cooling circuit was aligned and tested, during pre-operational testing, to confirm flow adequacy. Normal operation of the RHR System and SFPC System heat exchangers will confirm the heat removal capabilities of the heat exchangers.

High spent fuel pit temperature will cause an annunciation in the MCR, thus indicating equipment malfunction. Additionally, that portion of the cooling system above flood water will be frequently inspected to confirm continued proper operation.

For either mode of reactor cooling, leakage from the Reactor Coolant System will be collected, to the extent possible, in the reactor coolant drain tank; nonrecoverable leakage will be made up from supplies of clean water stored in the four cold leg accumulators, the pressurizer relief tank, the cask decontamination tank, and the demineralized water tank. If these sources prove insufficient, the FP System can be connected to the Auxiliary Charging System (subsection 9.3.5) as a backup. Whatever the source, makeup water will be filtered, demineralized, tested, and borated, as necessary, to the normal refueling concentration, and pumped by the Auxiliary Charging System into the reactor (see Figures 2.4A-2 and 2.4A-3).

Power Electric power will be supplied by the onsite diesel generators starting at the beginning of Stage II or when offsite power is lost, whichever occurs first (subsection 2.4A.5.3).

Cooling of Plant Loads Plant cooling requirements, with the exception of the FP System which must supply feedwater to the steam generators, will be met by the ERCW System (refer to subsection 9.2.2).

Plant Water SupIpl The plant water supply is thoroughly discussed in subsection 9.2.2. The following is a summary description of the water supply provided for use during flooded plant conditions. The ERCW station is designed to remain fully functional for all floods up to and including the DBF. The CCW intake forebay will provide a water supply for the fire/flood mode pumps. If the flood approaches DBF proportions, there is a remote possibility that Chickamauga Dam will fail. Such an event would leave the Sequoyah Plant CCW intake forebay isolated from the river as flood water recedes below EL 665. Should this event occur, the CCW forebay has the capacity of retained water to supply two steam generators in each unit and provide spent fuel pit with evaporation makeup flow until CCW forebay inventory makeup is established. The ERCW station is designed to be operable for all plant conditions and includes provisions for makeup to the forebay. Reference FSAR 2.4A.10-1.

2.4A.3 Warninq Plan Plant grade elevation 705 can be exceeded by both rainfall floods and seismic-caused dam failure floods. A warning plan is needed to assure plant safety from these floods.

S2-4app.doc 2.4A-5

SQN-17 2.4A.3.1 Rainfall Floods Protection of the Sequoyah Plant from the low probability rainfall floods that might exceed plant grade depends on a flood warning issued by TVA's River Operations as described in Section 2.4A.8. With TVA's extensive climate monitoring and flood predicting systems and flood control facilities, floods in the Sequoyah area can be reliably predicted well in advance. The Sequoyah Nuclear Plant flood warning plan will provide a minimum preparation time of 27 hours3.125e-4 days <br />0.0075 hours <br />4.464286e-5 weeks <br />1.02735e-5 months <br /> including a 3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> margin for operation in the flood mode. Four additional, preceding hours will provide time to gather data and produce the warning. The warning plan will be divided into two stages--the first a minimum of 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> long and the second of 17 hour1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />s--so that unnecessary economic penalty can be avoided while adequate time is ensured for preparing for operation in the flood mode.

The first stage, Stage I, of shutdown will begin when there is sufficient rainfall on the ground in the upstream watershed to yield a projected plant site water level of 697 in the winter months (October 1 through April 15) and 703 in the summer (April 16 through September 30). This assures that the additional time required is available when shutdown is initiated. The water level of 703 (two feet below plant grade) will allow margin so that waves due to high winds cannot disrupt the flood mode preparation. Stage I will allow preparation steps causing some damage to be sustained but will withhold major economic damage until the Stage II warning assures a forthcoming flood above grade.

The plant preparation status will be held at Stage I until either Stage II begins or TVA's River Operations determines that flood waters will not exceed elevation 703 at the plant. The Stage II warning will be issued only when enough rain has fallen to predict that elevation 703 is likely to be exceeded.

2.4A.3.2 Seismic Dam Failure Floods Protection of the Sequoyah plant from flood waves generated by seismically caused dam failures which exceed plant grade depends on TVA's River Operation organization to identify when a critical combination of dam failures and floods exist. There are nine upstream dams whose failure, in combination coincident with certain storm conditions, would cause a flood to exceed plant grade.

These dams are Norris, Cherokee, Douglas, Fort Loudoun, Fontana, Hiwassee, Apalachia, Blue Ridge, and Tellico.

2.4A.4 Preparation for Flood Mode At the time the initial flood warning is issued, the plant may be operating in any normal mode. This means that either or both units may be at power or either unit may be in any stage of refueling.

S2-4app.doc 2.4A-6

SQN-23 Table 3.2.1-2 (Sheet 1)

SUMMARY

OF CRITERIA - MECHANICAL SYSTEM COMPONENTS (EXCLUDING PIPING)

Scope Safety Class Code QA Reqd Location Rad Source Seismic.

Component (L (2) .3 (4)L (5) (6) Categorv( 7)

Reactor Coolant System Reactor Vessel W A III-A X C X I Reactor Coolant Pump Pressure Boundary W A III-A X C X Steam Generators (Tube) W, W-CE A III-A X C X (Shell) W, W-CE B Ill-A X C X I Pressurizer W A Ill-A X C X Pressurizer Relief Valves W A II a9 X C X I Pressurizer Safety Valves W A Ilia9 X C X Pressurizer Relief Tank W G VIII X C P I(L)

Safety Injection System Safety Injection Pumps W B P&V-II X AB X I Accumulator (9) W B III-C X C P I

• Injection Tank W B III-C X AB X I

• Refueling Water Storage Tank T C D100 X 0 P I

• Orifice W Ill-C AB P I Residual Heat Removal System

• RHR Pumps W B P&V-II X AB X I RHR Heat Exchangers (Tube) W B III-C X AB X I (Shell) W C VIII X AB P I Containment Spray System

• CS Pumps T B P&V-II X AB X I

• CS Heat Exchangers (Tube) T B III-C X AB X I (Shell) T C Vill X AB P I CS Nozzles T B 111-2 X C X I Primary Water Make-Up System

• Pump T G HI - AB I(L)

• Tank T G (14) X AB I T321-02.doc

SQN Table 3.2.1-2 (Sheet 2)

SUMMARY

OF CRITERIA- MECHANICAL SYSTEM COMPONENTS (EXCLUDING PIPING)

Component Scope Safety Class Code QA Reqd

(

Location

(

Red Source Seismic. 1)3 Category(

__(2) _)7jI3 Chemical and Volume Control System Pumps "Charging, Centrifugal W B P&V-II X AB X I "Boric Acid Transfer W C P&V-III X AB P I Heat Exchangers Regeneratve (Tube and Shell) W B III-C X C X

• Letdown (Tube) W B III-C X AB X I (Shell) W C VIII X AB P I Excess Letdown (Tube) W B Ill-C X C X I (Shell) W C VIII X C P

• Seal Water (Tube) W B Ill-C X AB X I (Shell) W C VIII X AB P Tanks

• Volume Control W B III-C X AB X I "Boric Acid W C VIII X AB P I

• Boric Acid Batching W G VIII AB I(L)

"Chemical Mixng W VIII AB I(L)

"Resin Fill W G VIII AB I(L)

Steam Generator Blowdown System SG Blowdown Isolaton Valves T B 111-2 X AB P Au*ilary Air Systems Compressor T C - X AB I Receivers T C VIII X AB I Air Dryers T C 111-3 X AB I Ice Condenser Ice Baskets W C - X C I Lower Inlet Doors W C X C I Lattice Frames W C X C I

SQN Table 3.2.1-2 (Sheet 3)

SUMMARY

OF CRITERIA - MECHANICAL SYSTEM COMPONENTS (EXCLUDING PIPING)

Scope Safety Class Code QA Reqd Location Rad Source Seismic.

Component (2) DL (4) -5) Category( 7)

Lattice Frame Columns W C X C Lower Support Structure W C X C Intermediate Deck Doors W C X C Wall Panels W C X C Floor Structures W,T C X C Top Deck Doors W C X C Air Handling Unit Supports W C X C Top Deck Beams W C X C Refrigeration System W CAB 1(L)

Ice Machine W AB 1(1)

Ice Condenser Bridge Crane W C 1(1)

Containment Isolation System

• Valves T B P&V-II X C,AB X.P I Air Return Fans T . (10) AMCA X C Component Cooling System

' Pumps - Main T C P&V-Ill X AB P

- Thermal Barrier T C P&V-III X C P

- Seal Leakage Return T G AB P

• Heat Exchangers T C Vill X AB P Surge Tank T C 111-3 X AB P Valves (Containment Isolation) T B P&V-II X C

' Valves T C P&V-lII X AB,C 1(L)

Radioactive Waste Disposal System Tanks W G VIII AB X Reactor Coolant Drain W G Ill-C C X 1(L)

Tritiated Drain Collector W G VIII AB X I(L)

Sump W G VIII AB X Spent Resin Storage W G VIII AB X Gas Decay W D 111-C X AB X T321-02.doc

SQN-23 Table 3.2.1-2 (Sheet 4)

SUMMARY

OF CRITERIA - MECHANICAL SYSTEM COMPONENTS (EXCLUDING PIPING)

Scope Safety Class Code QA Reqd Location Rad Source Seismic.

Component 1 (2) (3) (4) (5_ (6) Cateqorv( 7)

Pumps Reactor Coolant Drain Tank Pumps W G HI - C X(L)

Chemical Drain Tank Pump W G HI AB X I(L)

Sump Tank Pumps W G HI AB X I(L)

Miscellaneous

• Waste Gas Compressor Package W D (16) X AB X I Waste Gas Filter T G III-C AB X I(L)

• Automatic Gas Analyzer W AB P I

• Hydraulic Compactor W AB P Fire Protection System Fire/Flood Mode Pumps (submersible) T C P&V-III X 0 1 (Intake Pumping Station)

Station Ventilation Systems Containment Ventilation Containment Purge

• Fans Exhaust T 10 AMCA X AB

• Filters:

Charcoal T (10) AACC X AB P I HEPA T (10) MIL-F X AB P I Prefilter T (10) UL900 X AB P I Other Systems

• Fan/Coil Units (Supply) T - AMCA X AB X I(L)

" Supply Air Filters T - UL900 X AB X I(L)

Auxiliary Building Ventilation

• Fan/Coil Units T - AMCA X AB I(L)

• Filters:

Pre-Intake T - UL900 X AB P I(L)

Bag-Intake T - X AB P I(L)

• ESF Room Coolers T (10) X AB P I Air Conditioning Systems T - X AB I(L)

T321-02.doc

SQN-23 Analyses indicate that the effective tornado-generated pressure differential will not exceed 100 Ib/ft 2 acting on the roof and exterior walls of the Spent Fuel Pool Room and cask loading area. The roof is the limiting structural element in this condition and is designed to withstand an upward-acting pressure of 180 Ib/ft 2. Air velocity induced by venting is expected to be high at the vent opening, but decrease rapidly within a few feet of the opening. No hazard to equipment is foreseen since the vents are located in the Auxiliary Building roof, well away from any essential equipment.

Pressure differentials and assorted air velocities are expected in all areas which depressurize due to the venting of the building. Structures in these areas have been evaluated for the differential pressure from depressurization. In the room(s) where the differential pressure exceeds the wall design, administrative operating instructions will ensure that the doors will remain open during a tornado event to reduce the differential pressure to an acceptable value. No hazard to equipment in these areas is foreseen due to the small pressure differential and low air velocities. Walls, ceilings, and floors separating areas experiencing depressurization during a tornado from areas not experiencing depressurization are designed to withstand the effects of total tornado-generated pressure differential of 3 lb/in 2. The analytical model employed in determining the effective differential pressures utilizes isentropic, perfect gas relations in a step-wise, quasi-steady first law analysis. The analysis determined pressure and temperature variations within the structure induced by the tornado defined in Section 3.3.2.1.

3.3.2.3 Ability of Category I Structures to Perform Despite Failure of Structures Not Designed for Tornado Loads An investigation of the effect of tornado loading on the Turbine Building was made to determine the extent of failure of the structure as to collapse or to the possibility of generating missiles that could damage Category I structures and impair their ability to perform their intended design function.

The following information was determined:

1. The metal siding panels will fail at loads considefably below the design tornado loading and will become missiles that could impact the Control Building. The siding will fail before the main girts are overloaded enough to cau:e tailure. i ce failure of the parapet Li. is is iikeiy, resuiiing in 61C release, of 16WF15.5 in 4-foot lengths, 8WF 1.5 in 8-foot lengths, 18 by 3/8 plate in varying lengths, ST4WF8.5 in (-foot lengths The walls and roof of the Control Building were investigated for the above missiles and found to be adequately designed to resist the missiles.

2. Following the failure of the siding, the structural steel framing of the building will be exposed to tornado forces acting upon the steel structure, equipment, piping, and other items of wind resistance. At the maximum design tornado winds, the structure will have some points of local yielding in connections as forces are redistributed throughout the bracing and rigid frames. The resistance of the structure at this point will be sufficient to prevent collapse onto the Control Building.

$3-03.doc 3.3-3

SQN

3. The Turbine Room cranes, if not anchored, could possibly be blown from the crane girders, either falling on the operating floor or out the end of the building onto the Control Building roof.

To preclude the occurrence of this event, the cranes will be anchored to stops at one end of the runway at any time during tornado alerts, watches, and tornadoes.

4. The Potable Water Tanks and Gland Seal Water Tanks at Elevation 773 floor could be blown to the Control Building roof along with air intake hoods, auxiliary boiler stack, and heating and vent equipment on the Elevation 773 floor.

The Control Building roof was determined to be adequately designed to resist the described

ýýve.*,ts.

3.3.3 References

1. "Wind Forces on Structures," Final Report, Task Committee on Wind Forces, Committee on Loads and Stresses, Structural Division, Transactions, American Society of Civil Engineers Publication, Number 3269, Volume 126, Part 11 (1961).

2. Hoecker, W. H., "Wind Speed and Air Flow Patterns in the Dallas Tornado and Some Resultant Implications," Monthly Weather Review, May 1960.

3. Hoecker, W. H., "Three Dimensional Pressure Pattern of the Dallas Tornado and Some Resultant Implications," Monthly Weather Review, December 1961.

S3-03.doc 3.3-4

SQN-23 3-foot-high parapet wall around the roof of the Diesel Generator Building. The top of the parapet wall is 48.5 feet above plant grade. From spectrum A (Table 3.5.5-2) the only credible missile at that elevation is the 1-inch-diameter steel rod.

Buried Pipincq Tornado missile protection for all safety-related buried piping is provided by one of the five protective schemes described below.

1. 10 feet of compacted fine-grained soil.

2. 7 feet of compacted crushed stone.

3. 18 inches of conventional unreinforced concrete.

4. 18 inches of roller-compacted unreinforced concrete.

5. 7 feet of stone larger in size than 1032 for the dike area.

In each scheme, a 12-inch cushion of either compacted sand or fine-grained earthfill is required over the top of the pipe.

The acceptability of each scheme has been verified by a full-scale test program (Reference 13) in which missiles from the NRC spectrum were dropped from a helicopter into test pits of crushed stone or earthfill and onto concrete slabs. The missiles used in the testing were:

1. A 1500-pound utility pole,

2. A 12-inch-diameter schedule 40 steel pipe,

3. A 1-inch-diameter steel rod,

4. A 3-inch-diameter schedule 40 steel pipe, and

5. A 6-inch-diameter schedule 40 steel pipe.

Of these missiles, the 12-inch pipe and utility pole caused the greatest penetration depths. Impact velocities of 200-215 ft/s were achieved for both the utility pole and 12-inch pipe, which equals or exceeds the design velocities for those missiles. The protective thicknesses listed above are based on the maximum thicknesses observed in the test program and are, therefore, conservatively chosen.

S3-05.doc 3.5-23

SQN 3.5.6 References

1. J. Burnell, "The Flow of Boiling Water Through Nozzles, Orifices, and Pipes," The Institution of Engineers, Australia, March 1946.

2. A. Amirikian, "Design of Protective Structures," NP-3726, Bureau of Yards and Docks, Department of the Navy, Washington, D.C., August 1950.

3. C. V. Moore, 'The Design of Barricades for Hazardous Pressure Systems," Nuclear Engineering and Design, vol. 5, 1967, pp 85-86.

4. Letter from Paul R. Spencer, U.S. Department of Transportation, National Highway Safety Bureau, dated September 28, 1970, transmitting automobile impact time-history deceleration data to TVA.

5. Norman J. DeLeys, et al, Full Scale Crash Tests of Rigid Simulated Heavy Vehicle Underride, Guard, Cornell Aeronautical Laboratory, Inc., Buffalo, New York, March 1970. Report prepared for Department of Transportation, Federal Highway Administration, National Highway Safety Bureau, Washington, DC.

6. P. P. Bijlaard, "Stresses from Radial Loads on Cylindrical Pressure Vessels," Welding Research Supplement, December 1954. Report prepared for the Design Division of the Pressure Vessel Research Committee of the Welding Research Council.

7. Westinghouse Electric Corporation, Systems Standard Design Criteria, "Protection Criteria Against Dynamic Effects Resulting from Pipe Rupture," January 1970.

8. Electric Power Research Institute, "Full-Scale Tornado-Missile Impact Tests," Report No. EPRI NP-440, July 1977.

9. Civil Design Guide DG-C1.57, Rev. 1, "Design of Slabs for Missile Impact," 1979

10. ANSI/AISC N690-1984, "Nuclear Facilities-Steel Safety-Related Structures for Design Fabrication and Erection."

11. Bechtel Power Corporation, Topical Report BC-TOP-9, Rev. 1, "Design of Structures for Missile Impact," 1973.

12. Yura, J. A. Birkemoe, P. C. nd Ricles, J. M., "Beam Web Shear Connections: An Experimental study," Journal of Structural Division, ASCE, Vol. 108, No. ST2, Feb. 1982, pp. 311-325.

13. Testing of Protective Cover for Essential Buried Structures, CEB 81-2D, CEB 8106 16015.

$3-05.doc 3.5-24

SQN 3.7.6 References

1. "Dynamic Effect of Earthquake on Engineering Structures," Tennessee Valley Authority, Report No. 8-194, August 1939.

2. Newmark, N. M., "Design Criteria for Nuclear Reactors Subjected to Earthquake Hazards," paper presented at meeting of the International Atomic Energy Association, Tokyo, Japan, June 12-16, 1967.

3. Richart, F. E., Jr., J. R. Hall, Jr., R. D. Woods, Vibrations of Soils and Foundations, Prentice-Hall, Inc., 1970, New Jersey.

4. Parmelee, R. A., D. S. Perelman, et al., "Seismic Response of Structure-Foundation Systems,"

Proceedings of the American Society of Civil Engineers, December 1968 (EM6).

5. Whitman, R. V., "Analysis of Foundation Vibrations," Vibration in Civil Enqineering, 1966, Buttersworth, London.

6. Marley Company, "Earthquake and Wind Load Analysis Calculations," TVA Contract No. 71C53-92700.

7. Letter from Engineering Data Systems to TVA, March 6, 1972; Sequoyah Nuclear Plant Cooling Towers, Checking of Seismic Calculations.

8. Hayashi, Satoshi, "Analysis and Design of Earth Structures and Foundations," Syllabus for Earthquake Engineering Fundamentals, August 22 through September 2, 1966, Engineering Extension, Department of Engineering, University of California, Los Angeles.

9. Donald C. Cook Nuclear Plant Final Safety Analysis Report, American Electric Power Service Corporation, Docket Nos. 50-315 and 50-316.

10. Thomas, T. H., et al., Nuclear Reactors and Earthquakes, TID-7024, U.S. Atomic Energy Commission, Washington DC, August 1963.

11. Soroka, W. W., Analog Methods in Comnutation and Simulation, McGraw-Hill, New York, 1965.

12. Biggs, J. M., et al., Structural Design for Dynamic Loads, Chapter 8, McGraw-Hill, New York, 1959.

13. Harrington, R. L., and W. S. Vorus, "Dynamic Shock Analysis of Shipboard Equipment," Marine Technoloqy, October 1967. Published by the Society of Naval Architects and Marine Engineers.

14. WESTDYN, Westinghouse Structural Dynamic Analysis Computer Program, August 1970.

(Westinghouse Nuclear Energy Systems Proprietary.)

15. Bohm, G., "Seismic Analysis of Reactor Internals for Pressurized Water Reactors," First National Congress of Pressure Vessel and Piping Technology ASME Panel on Seismic Analysis & Design of Pressure Vessels and Piping Components, San Francisco, May 10-12, 1971.

16. Gesinski, L. T., "Fuel Assembly Safety Analysis for Combined Seismic and Loss-of-Coolant Accident," WCAP-7950, October 20,1972.

17. Broms, Bengt B., "Design of Laterally Loaded Piles," Journal of the Soil Mechanics and Foundation Division, ASCE, No. SM3, May 1965, pp 79-99.

S3-07.doc 3.7-41

SQN-23

18. Bechtel Power Corporation, Repair BC-TOP-4A, "Seismic Analysis of Structures and Components for Nuclear Power Plants" Revision 3, September 1974.

19. Hadjian, A. H., and Ellison, B., "Equivalent Properties for Layered Media," Soil Dynamics and Earthquake Engineering, Vol. 4, No. 4, pp 203-209.

20. Letter from NRC to TVA dated May 13, 1992, "Alternate Analysis Review Program Phase II -

Pipe Support Deflection Criteria, Sequoyah Nuclear Plant, Units 1 and 2 (TAC Nos. R00419 and R00420)," (A02 920519 008).

21. Letter from TVA to NRC dated January 28, 1993, "Sequoyah Nuclear Plant (SQN) - NRC Inspection Report Nos. 50-327/90-18 and 50-328/90 Unresolved Issue (URI) 88-12 Component Damping Values," (S64 930126 800)

22. BAW-10220P, "Mark-BW Fuel Assembly Application for Sequoyah Nuclear Units 1 and 2" March 1996.

23. BAW-10227P-A, "Evaluation of Advanced Cladding and Structural Material (M5) in PWR Reactor Fuel," February 2000.

24. BAW-2396, "Sequoyah Nuclear Plant M5 Design Report," May 2001.

25. Westinghouse Electric Company, Computer Code, WECAN (Westinghouse Electric Analysis), A Large General Purpose Finite Element Method Computer Program.

26. SCG-1 S-614, "Design of Old Steam Generator Storage Facility."

S3-07.doc 3.7-42

SQN-20 3.8 DESIGN OF CATEGORY I STRUCTURES 3.8.1 Concrete Containment The Reactor Building is a Category I structure in its entirety and is designed to remain functional in the event of a SSE, or tornado, or a flood.

3.8.1.1 Shield Building The Shield Building, shown in Figures 1.2.3-11, -12, and -13, is a reinforced concrete structure surrounding the steel containment structure and is designed to provide: radiation shielding from accident conditions, radiation shielding from parts of the Reactor Coolant System during operation, and protection of the steel containment vessel from low temperatures, adverse atmospheric conditions, external missiles, and flood. The Shield Building provides barrier for the annulus ventilation system which also serves as a redundant second containment barrier for control of leakage. The Shield Building is a reinforced concrete cylinder supported by a circular base slab and covered at the top with a spherical dome. It is located adjacent to the Auxiliary Building, Valve Room Buildings, and the Additional Equipment Building, as shown in Figure 1.2.3-1. It is physically separated from these buildings by a 1-inch expansion joint. Only the base slab resists the LOCA pressure load which is transmitted to it through a steel plate liner anchored to its top face and also through the anchors of the steel containment shell, interior structures and piping and equipment supports to the base slab. For further discussion of the base slab see Section 3.8.5.1.

The cylinder wall is approximately 150 feet in height from the liner on the base slab to the spring line of the dome. It has an inside diameter of 125 feet-1 inch and a thickness of 3 feet. The approximate inside height is 175 feet from the liner on the base slab to the dome apex. Conventional steel reinforcing bars were used throughout the structure and were placed in a horizontal and vertical pattern in each face of the cylinder wall. The area of reinforcement in each direction of each face is not less than 0.0015 times the gross concrete area.

The effects of penetrations through the wall were considered. Penetrations, 12 inches or less in diameter, do not significantly disturb the reinforcing pattern in the wall. Therefore, no special reinforcing considerations were made at these areas.

For penetrations larger than 12 inches, reinforcing is terminated at the opening. Supplemental reinforcing is added, both vertically and horizontally, to replace the reinforcing terminated. The amount of supplemental reinforcing added is equal to or greater than the amount of reinforcing removed and is placed adjacent to the penetration. In addition, rectangular and square box-outs in the wall have diagonal reinforcing across the comers. All reinforcing bars were lap spliced in accordance with ACI 318-63 requirements for Strength Design.

Reinforcing steel bars in the dome were arranged in a radial and circumferential pattern. A grid pattern was used at the crown of the dome.

A ring tension beam is provided at the dome-cylinder junction to resist the outward thrust from the dome roof. The tensile force in the ring beam is resisted by 24 No. 11 reinforcing bars. These bars are spliced by lapping 8 feet 6 inches. Laps are uniformly staggered around the S3-08.doc 3.8-1

SQN-23 circumference of the ring beam so that at any cross section only four bars are spliced out of the total 24 bars. That is, at any section, 20 bars are continuous and unspliced. These continuous, unspliced bars alone will carry the imposed load with only a 20 percent increase in stress. Stirrups enclosing the main reinforcement are spaced on 15-inch centers.

To facilitate removal of the old steam generators (OSGs) and installation of the replacement steam generators (RSGs) during the Unit 1 steam generator replacement (SGR), two construction openings were cut in the concrete shield building dome. These openings were restored by splicing new reinforcing bar to the existing reinforcing bar using Bar-Lock couplers and pouring new concrete to close the openings.

In preparation for the replacement of the Unit 2 steam generators, two approximately 18" diameter penetrations are core-drilled into the concrete Shield Building dome. Each penetration is closed using a lockable steel hatch assembly, and appropriate administrative measures are instituted for controlling the opening and closing of these hatches. As part of performing the Unit 2 SGR, the two larger construction openings in the Shield Building dome that are made to allow the removal of the OSGs from containment and placement of the RSGs into containment remove these 18-inches penetrations and their surrounding concrete. The penetrations will be eliminated as part of restoring the concrete of the construction openings at the conclusion of the Unit 2 SGR.

3.8.1.1.1 Equipment Hatch Doors and Sleeves An equipment hatch door and one sleeve are provided for each Reactor Unit. The steel sleeve forms an access through the Shield Building wall to the equipment hatch in the containment vessel for access to upper containment. Each sleeve extends from inside the Shield Building to the shielded passageway leading to the Auxiliary Building floor Elevation 734. Each door is of the hinged, double-leaf, marine type with seals for providing an airtight closure between the annulus surrounding the steel containment vessel and the inside of the Auxiliary Building. A door will normally be opened only when the reactor is in the shutdown, depressurized condition such that secondary containment is not required.

The sleeves, embedded in the Shield Building walls, are of welded steel construction, rectangular in cross section. The doors are hinged to the sleeves on the end toward the outside of the Shield Building wall and are of welded construction consisting of structural shapes with a steel skin plate.

Sealing of a door when closed is by means of solid, molded rubber seals mounted on the door. The seals contact the edge of the sleeve at the top and sides, a removable seal bar at the floor level, and a sealing bar at the meeting line of the two leaves.

The sealing bar at the meeting line is mounted on one of the leaves. Penetrations through the doors are sealed with solid rubber 0-ring type seals.

The doors are opened and closed manually. Latching of the doors in the closed position is accomplished by multiple hand-lever operated dogs acting on wedge surfaces around the perimeter and meeting edges of the door leaves. The doors are provided with concrete missile shield blocks on their Auxiliary Building side.

The doors and sleeves will maintain their structural and leak tight integrity and remain operational after being subjected to the environmental or accident conditions listed in Section 3.8.1.4.

S3-08.doc 3.8-2

SQN-23 3.8.1.2 Applicable Codes, Standards, and Specifications The structural design of the Reinforced Concrete Shield Building is in compliance with the American Concrete Institute 318-63 building code working stress design requirements. All reinforcing steel conforms to the requirements of ASTM Designation A 615, Grade 60. Construction was carried out under the requirements of TVA Construction Specification G-2.

Unless otherwise indicated, the design and construction of the Shield Building was based upon the appropriate sections of the following codes, standards, and specifications.

Modifications to these codes, standards, and specifications are made where necessary to meet the specific requirements of the structures. Where date of edition, copyright, or addendum is specified, earlier versions of the listed documents were not used. In some instances, later revisions of the listed documents were used where design safety was not compromised.

1. American Concrete Institute (ACI)

ACI 214-77 Recommended Practice for Evaluation of Strength Results of Concrete ACI 315-65 Manual of Standard Practice for Detailing Reinforced Concrete Structures ACI 318-63 Building Code Requirements for Reinforced Concrete ACI 318-71 Building Code Requirements for Reinforced Concrete ACI 318-77 Building Code Requirements for Reinforced Concrete ACI 347-68 Recommended Practice for Concrete Formwork ACI 305-72 Recommended Practice for Hot Weather Concreting ACI 211.1-70 Recommended Practice for Selecting Proportions for Normal Weight Concrete ACI 304-73 Recommended Practice for Measuring, Mixing, Transporting, and Placing Concrete

2. American Institute of Steel Construction (AISC):

"Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings,"

adopted February 12, 1969.

3. American Society for Testing and Materials, 1971 ASTM Standards. Specific standards are identified in Subsection 3.8.1.6.

4. American Welding Society (AWS):

"Code for Welding in Building Construction," AWS D1.0-69 as modified by TVA General Construction Specification G-29C.

"Structural Welding Code," AWS D1.1-72 as modified by TVA General Construction Specification G-29C.

"Recommended Practice for Welding Reinforcing Steel, Metal Inserts, and Connections in Reinforced Concrete Connections," AWS D12.1-61.

5. Uniform Building Code, International Conference of Building Officials, Los Angeles, 1970 edition.

6. Southern Standard Building Code, 1969 edition, 1971 revision.

7. "Nuclear Reactors and Earthquakes," USAEC Report TID-7024, August 1963.

$3-08.doc 3.8-3

SQN

8. American Society of Civil Engineers (ASCE) Transactions, Paper Number 3269, "Wind Forces on Structures," 1961.

9. Code of Federal Regulations, Title 29, Chapter XVII, Part 1910, "Occupational Safety and Health Standards."

10. NRC Regulatory Guides:

Number 1.12 Instrumentation for Earthquakes Number 1.31 Control of Stainless Steel Welding

11. TVA Construction Specifications:

G-2 - TVA General Construction Specification for Plain and Reinforced Concrete.

G-29 - TVA General Construction Specification - Process Specification for Welding and Heat Treatment.

G-30 - TVA General Construction Specification - Fly Ash for Use as an Admixture in Concrete.

G-32 - TVA General Construction Specification - Bolt Anchors Set in Hardened Concrete.

G-34 - TVA General Construction Specification - Repair of Concrete.

12. TVA Reports CEB 86-12 Study of Log-Term Concrete Strength at Sequoyah and Watts Bar Nuclear Plant.

CEB 86-19-C Concrete Quality Evaluation.

3.8.1.3 Loads and Loading Combinations The Shield Building dome and cylinder wall are subjected to the following loads:

Dead Load This includes weight of the concrete structure plus any other permanent load contributing to stress, such as equipment, piping, and cable trays suspended from the structure.

Earth Pressure The static soil pressure was computed using TVA General Earth Pressure Design Standards incorporating Coulomb's "Wedge of Pressure" theory. Standard soil properties for fine grained rolled fill are as follows:

Angle of internal friction = 32"

$3-08.doc 3.8-4

SQN-23

9. The double doors to the heating and ventilating spaces at Elevation 714.0 (one for each unit),

doors A123 and A132.

10. The door separating the Additional Equipment Building and the airlock at Elevation 714.0 (one for each unit, bidirectional pressure requirements), doors A214 and A215.

11. The door to the Cask Decontamination Room, Elevation 705.0, door Al 15.

12. The doors in the X-line wall of the cask loading area at Elevation 706.0 (one single door Al 13 and one double door Al 14).

13. The water tight doors leading to the instrument room at Elevation 685.0; one in N-line wall, C27, and one in C3-line wall, C14.

14. The doors to the Main Steam and Feedwater Valve Rooms at Elevation 706.0 (one for each unit), doors A101 and A105.

15. The water tight double doors at the main entrance from the Service Building, Elevation 690.0, door A57.

16. The water tight annulus access doors (one per unit, doors A65 and A78) and doors to the Reactor Building Access Rooms (one per unit, doors A64 and A77) at Elevation 690.0.

17. The water tight airlock door to the Radiochemical Laboratory at Elevation 690.0, door A55.

The doors are hinged, manually operated type metal doors, complete with frames and closers. The frames are either welded to plates, bolted to the concrete walls, embedded in concrete walls, or welded to embedded plates. Both single and double doors are involved. Double doors consist of an active and inactive leaf, with the active leaf being used for normal traffic. Doors C27, A55, A57, A65 and A78 have a single skin plate with horizontal stiffeners. All other doors are the flush type.

Securing for tornado, annulus pressure drop, or flood is done by a normal latching mechanism except for doors C27, A55, A57, A65 and A78 which are secured by the use of hand-operated dogs. All doors affected by tornadoes are secured during tornado warning and doors A65 and A78 are secured during external flood warnings. Doors A55, A57, C27, and C14 will protect essential safety equipment in the auxiliary and control buildings to elevation 706.0 from internal floodwaters in the turbine building caused by a rupture in the Condenser Circulating Water system (CCWS).

During normal operation the doors provide personnel and equipment access. Doors A55, A57, A64, A65, A77, A78, A101, A105, Al 13, Al14, A123, A132, A214, and 215 are also components of the building airlocks which serve to maintain a slight negative pressure in the Auxiliary and Reactor Buildings. These doors are equipped with electrical interlocks to assure that one of each pair of interlocked doors is always closed.

Spent Fuel Pool Gates The fuel transfer canal gate as shown in Figure 3.8.4-11, when in the installed position, forms the boundary between the fuel transfer canal and the spent fuel pool. This gate is used for S3-08.doc 3.8-77

SQN dewatering the fuel transfer canal for maintenance or after refueling operation. This gate is installed or removed under balanced head. The cask loading area gate is abandoned in the open 13 storage position. Both gates are of similar construction and are seismic Category I.

Waste Packaging Area The waste packaging area is a one-story reinforced concrete structure supported on H-bearing piles and is located on the east end of the Auxiliary Building as shown in Figure 1.2.3-7. The Ji3 roof of the structure slopes about 24' and consists of a series of precast beams tied together by a mat of reinforcing steel welded to plates embedded in the beams and topped by 4-inches of poured-in-place concrete. The structure is separated from the Auxiliary Building and the Condensate Demineralizer Waste Evaporator Building by a 2-inch expansion joint filled with fiberglass insulation which prevents interaction of the buildings when subjected to seismic motion.

Condensate Demineralizer Waste Evaporator Building Portion The Condensate Demineralizer Waste Evaporator Building portion is a two-story reinforced concrete structure which houses equipment necessary for processing condensate demineralizer wastes and for serving as a backup in processing floor drain wastes. The structure is supported on H-bearing piles and is located on the southeast side of the Auxiliary Building as shown in j 13 Figure 1.2.3-7. The building is separated from the waste packaging area and the Additional Equipment Building by a 2-inch expansion joint filled with fiberglass material which prevents interaction of the buildings if subjected to seismic motion.

Additional Equipment Building Portion The Additional Equipment Building portion consists of multistory reinforced concrete structures, one for each unit, which were added to accommodate additional accumulators for each unit and for the transfer of ice condenser equipment. The structures are located adjacent to the Reactor Buildings and near the east end of the Main Auxiliary Building as shown in Figures 1.2.3-1 1' through 1.2.3-6. Each building is founded on sound rock and is separated from the Condensate Demineralizer Waste Evaporator Building (Unit 2 structure only), the Reactor Building, and the Auxiliary Building by a 2-inch expansion joint filled with fiberglass insulation which prevents interaction of the buildings when subjected to seismic motion.

West Main Steam Valve Rooms The west steam valve rooms are the compartments of the auxiliary building which house the isolation valves for the main steam lines penetrating the west side of the reactor building. From these rooms the main steam lines exit the auxiliary building.

To protect the west steam valve rooms from over-pressurization due to postulated large high energy pipe breaks, the roofs of the west steam valve rooms at Elevation 779 and the pressure relief hatches at Elevation 729 are designed to initiate pressure relief at a maximum of .5 psi (72 psf) differential pressure.

S3-08.doc 3.8-78

SQN-23 Additionally, to maintain the Environmental Qualification of the components located inside the valve rooms, the roof and hatches are designed to blow-away and provide and maintain the necessary flow areas after pipe breaks required by the Superheat Analysis.

3.8.4.1.2 Condenser Cooling Water Pumping Station and Retaining Walls Pumping Station The building is a reinforced concrete box-type structure housing the condenser circulating water pumps, cooling tower makeup pumps, and fire protection / flood mode pumps. The structure is founded on rock and back-filled on three sides to approximately the elevation of the top deck.

The structure is built without contraction or expansion joints. In the northwest-southeast direction, it is stiffened by two full height walls and three partial height walls extending the full length of the structure.

In the northeast-southwest direction, the structure is stiffened by the many walls and piers making up the six pump bays. Refer to Figures 1.2.3-18 and 1.2.3-19 for details.

Retaining Walls The retaining walls are rock founded, reinforced concrete cantilever walls located at each end of the forebay side of the intake pumping station. These walls retain the earthfill adjacent to the intake pumping station.

3.8.4.1.3 Diesel Generator Building The building is a two-story rectangular reinforced concrete box-type structure which houses the diesel generators and their auxiliary equipment. Interior walls of reinforced concrete separate the diesel generators into four compartments. Diesel fuel storage tanks are embedded in the base slab. A concrete apron extending 13 feet from the edge of the structure is used to decrease the bearing on the subgrade to less than the allowable capacity. The entire structure is supported on soil. No connection of pipes or conduit were made until after completion of the structure and initial settlement stabilized.

For general layout and configuration of the structure, see Figure 1.2.3-17.

Diesel Generator Building Doors and Bulkheads The four doors shown in Figure 3.8.4-2 at Elevation 722.0 in the east wall of the Diesel Generator Building along with removable steel bulkheads above the doors provide closures for the 11 feet 10 inches high by 8 feet 8 inches wide access openings to the Diesel Generator Units. The access openings provide for passage of large tools and repair parts for the diesel generators. The doors are normally closed and latched. The bulkheads are bolted in position and are removed only for major repair of the diesel generators. The doors and bulkheads, in conjunction with the precast concrete barrier in front of them, protect the generators from damage by tornadoes, missiles, wind, snow, ice, and rain and form a part of the security system to prevent entry into the Diesel Generator Building by unauthorized persons.

S3-08.doc 3.8-79

SQN-22 Each steel bulkhead above the door is a structural steel frame 4 feet 4 inches high by 9 feet 6 inches wide. It is covered on both sides with a steel skin plate and provided with a crushable strip on the inner side along the top and sides. Turnbuckles support the steel bulkheads vertically and they are held horizontally by bolted clamps at the sides and top.

Each door is 7 feet 10 inches high and consists of two leaves which are manually operated and hinged at the outer sides to an embedded steel frame. The two leaves bear against steel bars at the outer sides and bottom, against each other at the center, and against a steel angle at the top. The bars are welded to the embedded frame and the angle to the bulkhead above the door.

Each door leaf is a structural steel frame covered on both sides with a steel skin plate and provided with a crushable strip around its periphery where it bears against lateral support. Both leaves are provided with latches which are operated from the inside only.

The crushable strip around the periphery of the doors and bulkheads is a latticework which is designed to absorb energy from missile impact. The doors and bulkheads may be deformed by the missiles but will remain in position.

The precast concrete bulkheads consist of several individual sections stacked into place and bolted in position to the concrete walls. They will be removed only for major repair of the diesel generators.

These bulkheads provide protection from missile spectrum D of Table 3.5.5-5, as discussed in Section 3.5.5, Part II(D).

3.8.4.1.4 Category I Water Tanks and Pipe Tunnels There is one refueling water storage tank (RWST) for each unit at Sequoyah Nuclear Plant. (The functional requirements for this tank are discussed in Chapter 6). Pipes extending from RWST to the Auxiliary Building are housed in reinforced concrete tunnels which vary in width and height.

Refueling Water Storage Tank (RWST)

The RWST is a seismic Category I structure but is not tornado Category I. A storage basin is provided around the tank to retain sufficient borated water in the event the tank is ruptured by a tornado missile or other initiating event. Details of the storage basin and the technical basis for it are discussed in Chapter 6. The minimum and maximum volume of contained water in the RWST are specified in the plant's Technical Specifications. RWST is a cylindrical vessel whose longitudinal axis is oriented in the vertical direction.

The end of the cylinder which forms the base or bottom of the tank is completely enclosed with a 5/16-inch-thick flat plate. The base of the tank sits on a concrete granular fill supported foundation to which the tank is attached at 60 lug points. The reinforced concrete foundation is described in Section 3.8.5.1.2. The tops of the cylindrical section of the tank is sealed at the side-wall/roof intersection using conical-shaped roofs whose apexes coincide with the tank's longitudinal axis. An internal inspection of the RWST will be performed on a periodic basis for structural integrity and degradation.

The tank is equipped with an atmospheric vent located at the peak or cone apex of the roof. The vent is designed to pass a volume flow rate of air that is at least equal to the maximum

$3-08.doc 3.8-80

SQN-23 Diesel Generator Building and Emergency Cooling Water Structures These structures are situated as described in Section 3.8.5.1.2. The Diesel Generator Building consists of a 9-foot 9-inch thick base slab which distributes superstructure loads to the supporting soil medium. A concrete apron extending 13 feet from the edge of the base slab is used to decrease the bearing on the subgrade to less than the allowable capacity.

3.8.5.6 Materials, Quality Control, and Special Construction Techniques 3.8.5.6.1 Materials Concrete and Reinforcing Steel See Section 3.8.1.6.1 and 3.8.4.6.1.

Backfill Materials Backfill material was taken only from areas designated by the soils investigation program (see Section 2.5) as suitable for backfill material.

3.8.5.6.2 Quality Control See Section 3.8.4.6.3 and 3.8.1.6.2.

Base Rock The base area of all rock supported structures was inspected by the principal Civil Design Engineer in conjunction with an experienced TVA Geologist during final cleanup of rock surfaces to determine its suitability as a foundation.

Backfill Quality control requirements for backfill material were as specified in Section 2.5.1.11.1.

3.8.5.6.3 Special Construction Techniques Normal construction procedures were used in the construction of all other Category I structures.

3.8.6 Category I (L) Cranes 3.8.6.1 Polar Cranes 3.8.6.1.1 Description See Figures 3.8.6-1 through 3.8.6-5.

$3-08.doc 3.8-107

SQN There are two polar cranes, one in each of the reactor buildings. Each crane is a single trolley, overhead, electric traveling type; operating on an 86-foot diameter rail at the top of the crane wall and above the reactor. Each crane has a main hoist capacity of 175 tons and an auxiliary hoist capacity of 35 tons.

The main and auxiliary hoist motions are driven by DC motors with a motor-generator type DC power supply and stepless regulated speed control. The bridge and trolley travel motions are driven by AC motors with static, stepless regulated speed control.

Structural portions of the crane bridges consist of welded box-type girders and welded, haunched, box-type end ties. Structural portions of the trolleys consist of welded box-type trucks and welded cross girts which are bolted to the trucks.

Control of each crane is from a cab located below the bridge walkway at one end of a girder.

3.8.6.1.2 Applicable Codes, Standards, and Specifications The following codes, standards, and specifications were used in the design of the cranes:

National Electric Code, 1970 edition National Electrical Manufacturers Association, Motor and Generator Standards, Standard MG-1, 1970 edition.

Electric Overhead Crane Institute Specification 61, "Specifications for Electric Overhead Traveling Cranes."

Federal Specification RR-W-410a, class 3.

American Society for Testing and Materials, "Material Standards," 1970 edition.

American Welding Society, D1.0, Code for Welding in Building Construction.

Section 1.23, Part I, "Specification for the Design, Fabrication, and Erection of Structural Steel for Buildings," Manual of Steel Construction, Part 5, American Institute for Steel Construction , 6th edition, 1963. Where date of edition, copyright, or addendum is specified, earlier versions of the listed documents were not used. In some instances, later revisions of the listed documents were used where safety was not compromised.

American Gear Manufacturers Association Standards for Spur, Helical, Herringbone, and Bevel Gears.

The cranes meet applicable requirements of the listed codes, standards, and specifications.

$3-08.doc 3.8-108

SQN-18 5.2 INTEGRITY OF THE REACTOR COOLANT SYSTEM BOUNDARY In adjusting the Sequoyah FSAR format to fit the NRC Format Guide it has been necessary in certain areas to use terminology which is basically inappropriate to plants of the Sequoyah era. However in using certain of the terminology which follows, we make the distinction that we are stating what the system is capable of being measured against; not the actual rules used in the original design.

The ASME Section III Nuclear Power Plant Components Code 1971 edition is inapplicable to the Sequoyah Plants. However, since the reactor coolant loop vessels (reactor vessel, pressurizer and steam generators) are basically standard components, analysis on these vessels with the more recent ASME Code conditions (normal, upset, emergency and faulted) have been performed with the load combinations and associated stress limits given in Tables 5.2-1 through 5.2-5. This analysis includes the dynamic effects of equipment operation as transmitted to various components by system piping.

Reactor Coolant System components have been designed, fabricated, inspected, tested, and procured in accordance with Tables 3.2.2-1 and 3.2.2-2.

The Reactor Coolant System boundary is designed to accommodate the system pressures and temperatures attained under all expected modes of plant operation including all anticipated transients, and to maintain the stresses within applicable stress limits. Design conditions are given in Paragraph 5.2.1.1. The system is protected from overpressure by means of pressure relieving devices as required by applicable codes. Materials of construction are specified to minimize corrosion and erosion and to provide a structural system boundary throughout the life of the plant. Fracture prevention measures are taken to prevent brittle fracture. Inspection in accordance with applicable codes and provisions (see Subsection 5.2.8) are made for surveillance of critical areas to enable periodic assessment of the boundary integrity.

5.2.1 Design of Reactor Coolant System Boundary Components The original design basis conditions as discussed in this section included the effects of postulated main reactor coolant loop pipe breaks. These breaks have been eliminated from the design basis through application of leak before break technology (see Section 3.6.1.1). The original design basis evaluation is described below. These results envelope the effects of the remaining postulated LOCAs.

5.2.1.1 Performance Obiectives and Design Conditions The performance objectives of the Reactor Coolant System (RCS) are described in Section 5.1.

Equipment Code and classification list for the components within the RCS boundary are given in Section 3.2.

The RCS in conjunction with the Reactor Control and Protection Systems is designed to maintain the reactor coolant at conditions of temperature, pressure and flow adequate to protect the core from damage. The design requirement for safety is to prevent conditions of high power, high reactor coolant temperature or low reactor coolant pressure or combinations of these which could result in a DNBR less than 1.3.

The RCS is designed to avoid uncontrolled reductions in boric acid concentration or reactor coolant temperature. The reactor coolant is the core moderator, reflector, and solvent for the chemical shim.

$5-2.doc 5.2-1

SQN-23 As a result, changes in coolant temperature or boric acid concentration affect the reactivity level in the core.

The following design bases have been selected to ensure that the uniform RCS boron concentration and temperature will be maintained:

1. Coolant flow is provided by either a reactor coolant pump or a residual heat removal pump to ensure uniform mixing of the boron.

2. The design arrangement of the Reactor Coolant System eliminates dead ended sections and other areas of low coolant flow in which nonhomogeneities in coolant temperature or boron concentration could develop.

3. The RCS is designed to operate within the operating parameters, particularly the coolant temperature change limitations.

The design pressure for the RCS is 2485 psig except for the pressurizer relief line from the safety valve to the pressurizer relief tank, which is 600 psig, and the pressurizer relief tank, which is 100 psig.

For components with design pressures of 2485 psig, the normal operating pressure is 2235 psig. The design temperature for the RCS is 650°F except for the pressurizer and its surge line which are designed for 680'F, and the pressurizer relief line from the safety valve to the pressurizer relief tank, which is designed for 340°F.

The following five ASME operating conditions are considered in the design of the RCS.

1. Normal Conditions Any condition in the course of startup, operation in the design power range, hot standby and system shutdown, other than upset, emergency, faulted or testing conditions.

2. Upset conditions Any deviations from normal conditions anticipated to occur often enough that design should include a capability to withstand the conditions without operational impairment. The upset conditions include those transients which result from any single operator error or control malfunction, transients caused by a fault in a system component requiring its isolation from the system and transients due to loss of load or power. Upset conditions include any abnormal incidents not resulting in a forced outage and also forced outages for which the corrective action does not include any repair of mechanical damage. The estimated duration of an upset condition is included in the design specifications.

3. Emergency conditions Those deviations from normal conditions which require shutdown for correction of the conditions or repair of damage in the system. The conditions have a low probability of occurrence but are included to provide assurance that no gross loss of structural integrity will result as a concomitant effect of any damage developed in the system. The total number of postulated occurrences for such events shall not cause more than twenty-five stress cycles having a Sa value greater than that for 106 cycles from the applicable fatigue design curves of the ASME code Section II1.

S5-2.doc 5.2-2

SQN-23

1. When the load coefficient method is used, the factor C' to be used in the analysis, for other conditions, should be C' = 0.60. (for design procedures see Part 1 of AISC-69).

2. When the load factor method is used, the load factor should be 1.1 (for design procedures as specified in Part 2 of AISC-69).

For core support structures the procedures of Subparagraph 5.2.1.6.1 are used.

5.2.1.7 Reactor Pressure Vessel Support Loads 5.2.1.7.1 Introduction This section presents the method of computing the reactor pressure vessel loss of coolant accident (LOCA) support loads and displacements. The structural analysis considers simultaneous application of the time-history loads on the reactor vessel resulting from the reactor coolant loop vessel nozzle mechanical loads, internal hydraulic pressure transients, and reactor cavity pressurization (for postulated breaks in the reactor coolant pipe at the vessel nozzles). The vessel is restrained by reactor vessel support pads and shoes beneath each nozzle (two inlet, two outlet) and the reactor coolant loops with the primary supports of the steam generators and the reactor coolant pumps. The objective of this analysis is to obtain reactor vessel displacements and the reactor vessel supports loads.

Pipe displacement restraints installed in the primary shield wall limit the break opening area of the vessel nozzle pipe breaks to less than 100 square inches. This 100 square inch area was determined to be an upper bound by using worst case vessel and pipe relative motions based on a preliminary analysis of this plant. Detailed studies have shown that pipe breaks at the hot or cold leg reactor vessel support loads and the highest vessel displacements, primarily due to the influence of reactor cavity pressurization. By considering these breaks, the most severe reactor vessel support loads are determined. For completeness, a break outside the shield wall, for which there is no cavity pressurization, is also analyzed; specifically, the pump outlet nozzle pipe break is considered. In summary, three loss of coolant accident conditions are analyzed:

1. Reactor vessel inlet nozzle pipe break

2. Reactor vessel outlet nozzle pipe break

3. Reactor coolant pump outlet nozzle pipe break 5.2.1.7.2 Interface Information The Tennessee Valley Authority is responsible for reactor containment design and analysis. Stiffness of the primary shield wall beneath the reactor vessel supports was provided by TVA to Westinghouse.

All other input information was developed within Westinghouse. These items are as follows: reactor internals properties, loop mechanical loads and loop stiffness, internal hydraulic pressure transients, asymmetric cavity pressure time history loads, and reactor support stiffness. These inputs allowed formulation of the mathematical models and performance of the analyses, as will be described.

5.2.1.7.3 Loadinq Conditions Following the postulated pipe rupture at the reactor vessel nozzle, the reactor vessel is excited by time-history forces. As described, these forces are the combined effect of three phenomena:

S5-2.doc 5.2-25

SQN-18 (1) reactor coolant loop mechanical loads, (2) reactor cavity pressurization forces and (3) reactor internal hydraulic forces.

The reactor coolant loop mechanical forces are derived from the elastic dynamic analyses of the loop piping for the postulated break. This analysis is described in Section 5.2.1.5. The dynamic reactions on the nozzles of all the unbroken piping legs are applied to the vessel in the RPV blowdown analysis.

Reactor cavity pressurization forces arise for the pipe breaks at the vessel nozzles for the steam and water which is released in the reactor cavity through the annulus around the broken pipe. The reactor cavity is pressurized asymmetrically with higher pressure on the side adjacent to the break. These differences in pressure horizontally across the reactor cavity result in horizontal forces applied to the reactor vessel. Smaller vertical forces arising from pressure on the bottom on the vessel and the vessel flanges are also applied to the reactor vessel. The cavity pressure analysis is described in Section 6.2.

The internals reaction forces develop from asymmetric pressure distributions inside the reactor vessel.

For a vessel inlet nozzle break and pump outlet nozzle break, the depressurization wave path is through the broken loop inlet nozzle and into the region between the core barrel and reactor vessel (see Figure 3.9.1-5). This region is called the downcomer annulus. The initial waves propagate up, down and around the downcomer annulus and up through the fuel. In the case of an RPV outlet nozzle break, the wave passes through the outlet nozzle and directly into the upper internals region, depressurizes the core, and enters the downcomer annulus from the bottom of the vessel. Thus, for an outlet nozzle break, the downcomer annulus is depressurized with much smaller differences in pressure horizontally across the core barrel than for the inlet break. For both the inlet and outlet nozzle breaks, the depressurization waves continue their propagation by reflection and transmission through the reactor vessel fluid but the initial depressurization wave has the greatest effect on the loads.

The reactor intemals hydraulic pressure transients were calculated including the assumption that the structural motion is coupled with the pressure transients. This phenomena has been referred to as hydroelastic coupling or fluid-structure interaction. The hydraulic analysis considers the fluid-structure interaction of the core barrel by accounting for the deflections of constraining boundaries which are represented by masses and springs. The dynamic response of the core barrel in its beam bending mode responding to blowdown forces compensates for internal pressure variation by increasing the volume of the more highly pressurized regions. The analytical methods used to develop the reactor internals hydraulics are described in Reference 13.

5.2.1.7.4 Reactor Vessel and Internals Modeling The reactor vessel and internals general assembly is shown in Figure 3.9.1-5. The reactor vessel is restrained by two mechanisms: (1) the four attached reactor coolant loops with the steam generator and reactor coolant pump primary supports and (2) four reactor vessel supports at alternate nozzles.

The reactor vessel supports are described in Section 5.5.14 and are shown in Figure 5.5.14-1. The support shoe provides restraint in the horizontal directions and for downward reactor vessel motion.

The reactor vessel model consists of two separate non-linear elastic models connected at a common node. One model represents the dynamic vertical characteristics of the vessel and its internals, and the other model represents the translational and rotational characteristics of the structure. These two S5-2.doc 5.2-26

SQN-23

2. Auxiliary Buildinq Secondary Containment Enclosure Structure The auxiliary building is a conventional reinforced concrete structure located between the reactor buildings and the control building as shown in Figures 1.2.3-1 through 1.2.3-9. Its basic functions are to house support and safety equipment for the primary system and to provide an isolation barrier during certain postulated accidents involving airborne radioactive contamination.

Certain parts of the building's interior and exterior walls, floor slabs, and roof form the isolation barrier. The enclosed volume is about 3.5 x 106 cubic feet. The only openings in the isolation barrier are sealed mechanical and electrical penetrations or airlocks. The building itself is by design and construction leak tight. Additional structural data on the auxiliary building is provided in Subsection 3.8.4.

The accident situations for which the auxiliary building isolation barrier will serve as a containment barrier are those involving irradiated fuel within the confines of the building and spills or leaks of radioactive materials from tanks and process lines inside the building. During a LOCA, any through-the-line leakage from primary containment into the auxiliary building will bypass the shield building annulus, in this case, the ABSCE will serve as part of the secondary containment enclosure.

Penetrations Mechanical and electrical penetration seals in the isolation barrier will be similar to those for the shield building. See Subsection 6.2.1 for design details. Other potential leakage paths into the auxiliary building will be ventilation openings and equipment and personnel access points.

Testing is performed in accordance with the Technical Specifications to ensure compliance with pressure limits.

All auxiliary building ventilation supply and exhaust ducts are provided with two low leakage isolation dampers in series. These two isolation dampers are heavy duty with resilient seals along the blade edges. Where practical, one damper in each pair is located inboard and one outboard of the containment barrier. The dampers fail in the closed position upon loss of power.

All normally used entrances and exits into the ABSCE for both equipment and personnel are through air locks during power operation. The air lock locations are shown in figures found in Section 1.2.3. The doors in each air lock are electrically interlocked such that only one side of the air lock can be opened at a time. As a safety precaution, an interlock defeat switch is provided to allow emergency egress should either side of the air lock be blocked open in an accident.

A special case is the interlock system for the large exterior door to the railway loading area. The large door is treated as one side of the air lock and either the two doors leading to the fuel handling area or the railway access hatch covers above can act as the other side of the lock.

When the large railroad door is open, neither of the doors to the fuel handling area nor the access hatches above can be opened, and when either of these two doors and either of the access hatches above are open, the large railway access door cannot be opened. The railway access doors and hatches are described in Subsection 3.8.4.

$6-2.doc 6.2-5

SQN 6.2.1.3 Design Evaluation The design basis for containment pressure transients has been revised for Sequoyah. This design basis is documented in WCAP 12455, Revision 1 (Reference 72). Since the pressure "

transient for Sequoyah is limited by the minimum safeguards condition, the documentation for the minimum safeguards cases presented in Section 6.2.1.3 are based on the above referenced WCAP. 14 6.2.1.3.A Sensitivity to Containment Spray Heat Exchanger Tube Plugging LOCA Containment Integrity containment pressure calculations have been completed to assess the effect of containment spray heat exchanger tube plugging on containment response. The limiting pressure transient for Sequoyah documented in WCAP 12455, the Double-ended Pump Suction Minimum Safeguards case, was addressed. Documentation of the minimum safeguards case is presented in Section e.2.1.3. This analyses supports a heat axchanger tube plugging limit of 13.3 percent.

6.2.1.3.1 Primary Containment Evaluation

1. The primary containment's leak tightness does not depend on the operation of any continuous monitoring or compressor system. The leak testing of the primary containment and its isolation system is discussed in Section 6.2.1.4.1 and 6.2.1.4.2.

2. The acceptance criteria for the leak tightness of the primary containment are such that at containment design pressure, there is a 25% margin between the acceptable maximum leakage rate and the maximum permissible leakage rate.

3. Reduced inventory/mid-loop requirements dictate to reasonably assure that containment closure can be achieved when core uncovery could result from a loss of RHR coupled with the inability to initiate alternate cooling or addition of water to RCS inventory.

6.2.1.3.2 Secondary Containment Evaluation The secondary containment enclosures were designed to provide a positive barrier to all potential primary containment leakage pathways during a LOCA and to radioactive contaminants released in accidental spills and fuel handling accidents that may occur in the auxiliary building.

In a LOCA, the shield building containment enclosure provides the barrier to airborne primary containment leakage from air-filled automatic isolating penetrations, and the auxiliary building provides a barrier to through-the-line leakage which can potentially become airborne.

1. Shield Building Structure The building construction employs monolithic pours of concrete. This approach for structures of this type produces a very low leakage barrier. The low leakage characteristics of this barrier help to reduce the rate at which filtered annulus air must be released to maintain the enclosed volume at a negative pressure. This factor contributes significantly to keeping the exclusion area boundary and the low population zone (LPZ) dosage levels within 10 CFR 100 guidelines.

S6-2.doc 6.2-6

SQN-21 The pump and motor design conforms as applicable to the following standards: Hydraulic Institute Section B - Centrifugal Pumps, NEMA MGI-1 963- Motors, ANSI B16.5 - Steel Pipe Flanges and Pipe Fittings, ASME Draft Code for Pumps and Valves for Nuclear Power, November 1968.

The Residual Heat Removal pumps which also provide flow to the Containment Spray Subsystems are .described in Section 6.3.

Heat Exchangers The Containment Spray heat exchangers are the vertical shell and U-tube (1B heat exchanger is a straight tube type) type with tubes welded to the tube sheet. Borated water from either the refueling water storage tank or the containment sump circulates through the tube side. Original design parameters are presented in Table 6.2.2-2. The heat exchangers conform to the following standards:

Tubular Exchanger Manufacture Association (TEMA), Class R, Tube Side-ASME III, shell side-ASME Boiler and Pressure Vessel Code,Section VIII. The heat exchangers are designed using a conservative fouling resistance for water for the inside and the outside of the tubes of 0.0003 and 0.001 hrft2°F/BTU respectively, from the TEMA Standards.

The RHR heat exchangers which also provide cooling to the Containment Spray Subsystems are described in Section 6.3.

All Containment Spray Subsystem piping in contact with borated water is austenitic stainless steel.

Piping joints are welded or flanged as necessary. The piping startup strainers are designed to meet the requirements of ANSI B31.1 with inspection and test requirements of ANSI B31.7 used in lieu of the applicable Nuclear Code Cases.

Spray Nozzles and Ring Headers Each containment spray ring header contains 312 hollow cone ramp bottom nozzles. These nozzles have an approximately 3/8 inch spray orifice and will not be subject to clogging by particles less than 1/4 inch in maximum dimension. The nozzles produce a mean drop size of approximately 700 microns in diameter at rated system conditions. The spray solution is completely stable and soluble at all temperatures of interest in the containment and therefore will not precipitate or otherwise interfere with nozzle performance. Each nozzle header is independently oriented to maximize coverage of the upper containment volume inside the crane wall. This arrangement will prohibit any flow into the ice condenser.

Using conventional analytical techniques, the pumps were shown to be capable of overcoming the system flow resistance. The resistance includes elevation difference between the spray header and pump, the nozzles, the heat exchanger, piping between the pump and spray header, and water supply piping to the pump suction.

The residual heat removal spray ring headers contain 147 nozzles per header. It has the same design characteristics as the Containment Spray trains.

$6-2.doc 6.2-57

SQN-23 Refueling Water Storage Tank During the injection phase immediately following a LOCA, the containment spray trains are supplied from the refueling water storage tank.

This tank is located in the yard. Sufficient water is provided to supply the Containment Spray trains and the ECCS trains for the injection mode at ambient temperature of 105°F maximum until switchover to the ECCS containment sump.

Material Compatibility All parts of the Containment Spray Subsystem that are in contact with borated water are austenitic stainless steel or equivalent corrosion-resistant material.

Design of Recirculation Piping The containment spray recirculation water supply is taken from the emergency sump inside the containment (see sections below).

NPSH The design head of the pumps is sufficient to continue at rated capacity with a minimum level in the refueling water storage tank against a head equivalent to the sum of the design pressures of the containment, the head to the uppermost nozzles, and the line and the nozzle pressure losses. System pressure ensures compliance with the pump net positive section head (NPSH) requirements of NRC Regulatory Guide No. 1.1 for Water Cooled Nuclear Power Plants. The pumped fluid will be a subcooled liquid for all modes in system operation. Therefore, the minimum NPSH available is determined from the following equation:

NPSH = Elevation head + (Containment pressure - liquid vapor pressure) - friction losses No credit is taken for containment overpressure (i.e., containment pressure used in calculating NPSH is one atmosphere or zero gage pressure). Adequate NPSH exists for all expected fluid temperatures without reliance on increased containment pressure. The flow characteristics of the pump are shown in Figure 6.2.2-3.

Containment Recirculation Sump The containment recirculation sump is designed to prevent trash and debris from entering that could affect the operation of the Containment Spray trains. In addition, the sump provides for adequate NPSH for the Containment Spray pumps and Residual Heat Removal pumps to operate in the recirculation mode.

Trash and debris are eliminated by an advanced design strainer that contains perforations of 0.095 inch diameter. The strainer is designed with sufficient flow area to maintain a low fluid velocity at the entrance. Therefore, the debris that is more dense than water will settle to the containment floor rather than block the strainer. Internal baffles are provided to allow the escape of air during initial filling and to prevent the formation of vortices. 1/4-inch mesh screens are provided inside the sump pit as a final barrier to prevent debris from jeopardizing Containment Spray and Residual Heat Removal pump operation.

S6-2.doc 6.2-58

SQN 6.2.3.6.2 Emergency Gas Treatment System HEPA filters and carbon adsorbers in the Emergency Gas Treatment System are designed for stability and dependability in accident environments discussed above. The HEPA filters have a fire-retardant glass fiber filter, aluminum separators, and carbon steel frame. This type of filter is capable of functioning at rated conditions at temperatures up to 250°F and gamma doses of up to 108 rads. The carbon adsorbers will be individually encased, flat-bed, tray-type units. Each tray will contain new, commercially pure, activated carbon treated with iodine or iodine compound to facilitate removal of organic and inorganic iodine compounds. The carbon ignition temperature after impregnation will be greater than 620 0 F. Adsorber material and gaskets will withstand gamma doses of 1 x 108 rads accumulated in a 1 month period.

6.2.3.6.3 Auxiliary Building Gas Treatment System Same as subsection 6.2.3.6.2 above.

6.2.4 Containment Isolation Systems The purpose of containment isolation is to provide positive closure methods in lines penetrating primary reactor containment in the event of a loss of coolant accident within containment or another event that creates one of the containment isolation signals. Primary reactor containment is the third of the three principle fission product barriers (fuel clad, RCPB, reactor containment) necessary for the protection of the public health and safety. The objective of containment isolation is to allow the normal or emergency passage of the following while preserving the integrity of the containment boundary:

1. Engineered Safety Feature system fluids, or

2. Fluid of systems which are not required to function following a LOCA but, if available, can be used to accomplish a function similar to an engineered safety feature system.

Other fluid systems shall be isolated upon the appropriate isolation signal. Penetrations through the containment boundary shall be leak rate tested as necessary. An integrated test is used to pressurize the entire containment and prove performance of all penetrations. Penetrations are also individually 3 tested unless specific requirements are met as detailed herein (e.g. closed systems).

The bases for containment isolation and containment integrity ensures that the release of radioactive materials from the containment atmosphere will be restricted to those leakage paths and associated leak rates assumed in the accident analysis and within the limits of 10CFR100. The limitation on containment leakage ensures that the total containment leakage volume will not exceed the value assumed in the accident analysis at the peak accident pressure.

The limitations on closure and leak rate for the containment airlocks are required to satisfy CONTAINMENT INTEGRITY. Surveillance testing of the airlock seals provide assurance that the overall airlock leakage will not become excessive during the intervals between overall airlock leakage tests. The structural integrity of the containment steel vessel will be maintained comparable to the original design standards for the life of the facility. Structural integrity is required to ensure the vessel will withstand the maximum pressure of 12 psig in the event of a LOCA. The visual inspection in conjunction with the Type A integrated test demonstrates this integrity. Containment isolation valves that must isolate on various signals are identified in Reference 73. The operability of these valves ensures that the containment atmosphere will be

$6-2.doc 6.2-75

SQN-23 isolated from the outside environment in the event of an accident that requires containment isolation.

Containment isolation valve closure within the time limits specified ensures that the release of radioactive materials to the environment will be consistent with the assumptions used in the accident analysis. Additional valves have been identified as barrier valves which are a part of the accident monitoring instrumentation in Tech Spec 3/4.3.3.7 and as designated as Category 1 in accordance with Reg Guide 1.97 R2. Containment Isolation valve position indication requirements are specified by Tech Spec 3/4.3.3.7.

A visual inspection which verifies that no loose debris (rags, trash, clothing, etc.) is present in the containment which could be transported to the containment sump and cause restriction of the pump suctions during LOCA conditions. This visual inspection shall be performed:

1. For all accessible areas of the containment prior to establishing CONTAINMENT INTEGRITY, and

2. Of the areas affected within containment at the action of each containment entry when "CONTAINMENT INTEGRITY" is established.

DEFINITIONS BYPASS LEAKAGE PATH is a potential path for leakage to escape from both the primary containment and annulus pressure boundary. Only one type of BYPASS LEAKAGE PATH is recognized:

a. BYPASS LEAKAGE PATHS TO THE AUXILIARY BUILDING are those paths that would potentially allow leakage from the primary containment to circumvent the annulus secondary containment enclosure and escape directly to the Auxiliary Building secondary containment enclosure.

CLOSED SYSTEM: A piping system that penetrates containment and is a closed loop either inside or outside the containment. Under normal operating conditions or LOCA conditions for closed systems inside containment, the fluid in the system does not communicate directly with either primary coolant or the containment atmosphere.

CONTAINMENT INTEGRITY shall exist when:

a. All penetrations required to be closed during accident conditions are either:

1) Capable of being closed by an OPERABLE containment automatic isolation valve system, or

2) Closed by manual valves, blind flanges, or deactivated automatic valves secured in their closed positions, except as provided by Technical Specification 3.6.3.

b. All equipment hatches are closed and sealed, and

c. Each air lock is in compliance with the requirements of Technical Specification 3.6.1.3, and

d. The containment leakage rates are within the limits of Technical Specification 4.6.1.1.c, and

e. The sealing mechanism associated with each penetration (e.g., welds, bellows, or O-rings) is OPERABLE, and

f. Secondary Containment Bypass Leakage Rates are within the limits of Technical Specification SR 4.6.3.8 and TS 6.8.4.h.

CONTAINMENT ISOLATION SIGNAL: A signal that automatically initiates the accident isolation function and establishes isolation barrier(s) in containment penetrations to mitigate the potential consequences of an accident. SQN has the following signals that will isolate valves in lines penetrating containment: Phase A, Phase B, Containment Ventilation Isolation, and Containment Pressure. Auxiliary Feedwater initiation, safety injection, main steam isolation, and feedwater isolation are other ESF actuation signals that are credited for isolating valves in lines penetrating containment.

ENGINEERED SAFETY FEATURE(S): Systems which are required to prevent, arrest, or mitigate the consequences of an accident.

$6-2.doc 6.2-76

SQN-23 Penetration Type XIV Equipment Hatch An equipment hatch, fabricated from welded steel and furnished with a double-gasketed flange and bolted dished door, is provided. A test connection to the space between the gaskets is provided to pressurize the space for leak rate testing, as shown on drawing 48W406.

Penetration Type XV Personnel Access Two personnel locks are provided. Each personnel lock, as shown on drawing 48W406, is a double door, welded steel assembly. Quick-acting type equalizing valves are provided to equalize pressure in the airlock when entering or leaving the containment vessel. The doors are sealed with double gaskets. A test connection to the space between the gaskets is provided to pressurize the space for leak rate testing. The emergency air supply connection to the space between the double doors serves as a test connection to pressurize this space for leak rate testing. A special holddown device is provided to secure the inner door in a sealed position during leak rate testing of the space between the doors.

The two doors in each personnel lock are interlocked to prevent both being opened simultaneously and to ensure that one door and its equalizing valve are completely closed before the opposite door can be opened. Remote indicating lights and annunciators, located in the control room, indicate the door is in operational status. Provision is made to permit bypassing the door interlocking system with a special tool to allow doors to be left open during plant cold shutdown. Each lock door hinge is designed to be capable of adjustment to assure proper seating.

Penetration Type XVI Fuel Transfer Tube A 20 inch outside diameter transfer tube penetration is provided for fuel movement between the refueling canal in the containment and spent fuel pit. The penetration consists of 20 inch stainless steel pipe installed inside a 24 inch carbon steel pipe, as shown on drawing 47W455-1. The inner pipe acts as the transfer tube and is fitted with a double-gasketed blind flange in the refueling canal and a standard gate valve in the spent fuel pit. The inner pipe is welded to the containment penetration sleeve. Expansion bellows are provided on the pipes to compensate for any differential movement between the two pipes or other structures.

Penetration Type XVII Thimble Renewal Incore instrumentation thimble renewal requires penetrations in both the steel containment and the Shield Building at the same elevation and azimuth. These are separate penetrations and are not connected in the annulus. The containment penetration is illustrated on drawing 48W406, a similar seal is used on the Shield Building. Double 0-ring gaskets and leak rate test connectors are provided for both the steel containment penetration.

Penetration Type XVIII Ice Blowinq The ice-blowing line penetrations have a blind flange with a double 0-ring gasket inside and outside the containment, as shown on drawing 48W406. Sealing between the Auxiliary Building and the annulus is provided by a blind flange, fitted with a gasket.

S6-2.doc 6.2-85

SQN Penetration Type XIX Containment Vacuum Relief The penetrations for the Containment Vacuum Relief System, as shown on drawing 47W331-2.

There are no bellows and no flued heads.

Penetration Type XX Electrical The electrical penetration assemblies will provide a means for the continuity of power, control, and signal circuits through the primary containment structure. The electrical penetration assemblies are designed to maintain containment integrity. Additional discussion of electrical penetrations is provided in Section 7.1.3.

Penetration Type XXI Cold Water Penetrations The penetration for cold water lines such as ERCW is shown on drawing 48W406. There are no bellows or flued heads.

Penetration Type XXII Maintenance Type The penetration for X-108 and X-109 are shown on drawing 48W406. This flued head is similar to the flued heads in penetration Types IV and V but with the difference that the Type XXII penetration does not use insulation.

LEAKAGE PATHS The possible leakage paths from primary containment are discussed below.

These leakage paths are defined on the basis that the annulus pressure is always less than outdoor ambient, the Auxiliary Building, and the containment pressures. Therefore, whenever containment is required, leakage is into the annulus. The possible leakage paths considered do not include containment leakage through the steel plates or through the full penetration welds in the containment vessels. Neither do the possible leakage paths include Shield Building embedments. This is acceptable, as any leakage through any of these paths will be into the annulus and the leakage will be processed by the Emergency Gas Treatment System.

The more probable sources of containment and Shield Building leakage, such as elastomer seals, bellows, and through line, are considered as possible leak path types. Each penetration that contains elastomer seals or a bellows has at least one leakage path defined in the PENETRATION TABLES. All penetrations not open to the annulus are considered as possible paths for through-line containment and have one or more isolation valves. Thus, every pipe penetration has at least one type of leak path listed. The five different types of possible leakage paths are discussed separately below.

Type A Leakage Path Leakage type A is leakage from the Auxiliary Building into the annulus.

Type B Leakage Path Type B leakage paths are from the containment to the annulus. -2, S6-2.doc 6.2-86

SQN-23 TABLE 6.2.4-1 (Sheet 1)

CONTAINMENT PENETRATIONS CONTAINMENT ISOLATION VALVF STR1KF TIMF RFCIJIRFME:NTS CONTAINMENT VALVE NUMBER FUNCTION MAXIMUM ISOLATION TIME (SECONDS)

A. PHASE "A" ISOLATION 1 FCV-1-7 SG Blow Dn 10 2 FCV-1-14 SG Blow Dn 10 3 FCV-1-25 SG Blow Dn 10 4 FCV-1 -32 SG Blow Dn 10 5 FCV-26-240 Fire Protection Isol. 20 6 FCV-26-243 Fire Protection Isol. 20 7 FSV-30-134 Cntment Bldg Press Trans Sense Line 4 8 FSV-30-135 Cntment Bldg Press Trans Sense Line 4 9 FCV-31 C-222 CW-Inst Room CIrs 10 10 FCV-31 C-223 CW-Inst Room Clrs 10 11 FCV-31 C-224 CW-Inst Room Cirs 10 12 FCV-31 C-225 CW-Inst Room CIrs 10 13 FCV-31 C-229 CW-Inst Room Clrs 10 14 FCV-31 C-230 CW-Inst Room CIrs 10 15 FCV-31 C-231 CW-Inst Room CIrs 10 16 FCV-31 C-232 CW-Inst Room CIrs 10 17 FSV-43-2 Sample Przr Steam Space 10 18 FCV-43-3* Sample Przr Steam Space 10 19 FV-43-11 Sample Przr Liquid 10 20 FCV-43-12* Sample Przr Liquid 10 21 FSV-43-22 Sample RC Outlet Hdrs 10 22 FCV-43-23* Sample RC Outlet Hdrs 10 23 FSV-43-34 Accum Sample 5 24 FCV-43-35* Accum Sample 5 25 FSV-43-55 SG Blown DN Sample Line 10 26 FSV-43-58 SG Blown DN Sample Line 10 27 FSV-43-61 SG Blown DN Sample Line 10 28 FSV-43-64 SG Blown DN Sample Line 10 29 FCV-61-96 Glycol Inlet to Floor Cooler 30 30 FCV-61-97 Glycol Inlet to Floor Cooler 30 31 FCV-61-110 Glycol Inlet to Floor Cooler 30 32 FCV-61 -122 Glycol Inlet to Floor Cooler 30 33 FCV-61-191 Ice Condenser- Glycol In 30 34 FCV-61-192 Ice Condenser- Glycol In 30 35 FCV-61-193 Ice Condenser- Glycol Out 30 36 FCV-61-194 Ice Condenser- Glycol Out 30

• (These valves are FSCV on Unit 1.)

T624-1.doc

SQN-23 TABLE 6.2.4-1 (Sheet 2)

CONTAINMENT PENETRATIONS CONTAINMENT ISOLATION VALVE STROKE TIME REQUIREMENTS VALVE NUMBER FUNCTION MAXIMUM ISOLATION TIME (SECONDS) 43 FCV-62-61 RCP Seals 10 44 FCV-62-63 RCP Seals 10 45 FCV-62-72 Letdown Line 10 46 FCV-62-73 Letdown Line 10 47 FCV-62-74 Letdown Line 20 48 FCV-62-77 Letdown Line 10 49 FCV-63-23 Accum to Hold Up Tank 10 50 FCV-63-64 WDS N2 to Accum 10 51 FCV-63-71 Accum to Hold Up Tank 10 52 FCV-63-84 Accum to Hold Up Tank 10 53 FCV-68-305 WDS N2 to PRT 10 54 FCV-68-307 PRT to Gas Analyzer 10 55 FCV-68-308 PRT to Gas Analyzer 10 56 FCV-70-85 CCS from Excess Lt Dn Hx 10 57 FCV-70-143 CCS to Excess Lt Dn Hx 60 58 FCV-77-9 RCDT Pump Disch 10 59 FCV-77-1 0 RCDT Pump Disch 10 60 FCV-77-18 RCDT and PRT to V H 10 61 FCV-77-19 RCDT and PRT to V H 10 62 FCV-77-20 N, to RCDT 10 63 FCV-77-127 Floor Sump Pump Disch 10 64 FCV-77-128 Floor Sump Pump Disch 10 65 FCV-81 -12 Primary Water Makeup 10 B. PHASE "B" ISOLATION 1 FCV-32-80 (U1), FCV-32-81 (U2) Control Air Supply 10 2 FCV-32-102 (U1), FCV-32-103 (U2) Control Air Supply 10 3 FCV-32-110 (U1), FCV-32-111 (U2) Control Air Supply 10 4 FCV-67-83 ERCW - LWR Cmpt Cirs 60 5 FCV-67-87 ERCW - LWR Cmpt Cirs 60 6 FCV-67-88 ERCW - LWR Cmpt Cirs 60 7 FCV-67-89 ERCW - LWR Cmpt Cirs 70 8 FCV-67-90 ERCW - LWR Cmpt Cirs 70 9 FCV-67-91 ERCW - LWR Cmpt Cirs 60 10 FCV-67-95 ERCW - LWR Cmpt Cirs 60 11 FCV-67-96 ERCW - LWR Cmpt Cirs 60 12 FCV-67-99 ERCW - LWR Cmpt Cirs 60 13 FCV-67-103 ERCW - LWR Cmpt Cirs 60 14 FCV-67-104 ERCW - LWR Cmpt Cirs 60 15 FCV-67-105 ERCW - LWR Cmpt Cirs 70 16 FCV-67-106 ERCW - LWR Cmpt Cirs 70 17 FCV-67-107 ERCW - LWR Cmpt Cirs 60 18 FCV-67-111 ERCW - LWR Cmpt Cirs 60 19 FCV-67-112 ERCW - LWR Cmpt Cirs 60 20 2-FCV-67-130 ERCW - Up Cmpt CIrs 60 21 2-FCV-67-131 ERCW - Up Cmpt Cirs 60 T624-1 .doc

SQN-23 TABLE 6.2.4-1 (Sheet 3)

CONTAINMENT PENETRATIONS CONTAINMENT ISOLATION VALVE STROKE TIME REQUIREMENTS VALVE NUMBER FUNCTION MAXIMUM ISOLATION TIME (SECONDS) 22 2-FCV-67-133 ERCW - Up Cmpt CIrs 60 23 2-FCV-67-134 ERCW - Up Cmpt Cirs 60 24 2-FCV-67-138 ERCW - Up Cmpt Cirs 60 25 2-FCV-67-139 ERCW - Up Cmpt Cirs 60 26 2-FCV-67-141 ERCW - Up Cmpt Cirs 60 27 2-FCV-67-142 ERCW - Up Cmpt Cirs 60 28 2-FCV-67-295 ERCW - Up Cmpt Cirs 60 29 2-FCV-67-296 ERCW - Up Cmpt Cirs 60 30 2-FCV-67-297 ERCW - Up Cmpt CIrs 60 31 2-FCV-67-298 ERCW - Up Cmpt CIrs 60 32 FCV-70-87 RCP Thermal Barrier Ret 60 33 FCV-70-89 CCS from RCP Oil Coolers 60 34 FCV-70-90 RCP Thermal Barrier Ret 60 35 FCV-70-92 CCS from RCP Oil Coolers 60 36 FCV-70-134 To RCP Thermal Barriers 60 37 FCV-70-140 CCS to RCP Oil Coolers 60 38 FCV-70-141 CCS to RCP Oil Coolers 65 C. PHASE "A" CONTAINMENT VENT ISOLATION 1 FCV-30-7 Upper Compt Purge Air Supply 2 FCV-30-8 Upper Compt Purge Air Supply 3 FCV-30-9 Upper Compt Purge Air Supply 4 FCV-30-1 0 Upper Compt Purge Air Supply 5 FCV-30-14 Lower Compt Purge Air Supply 6 FCV-30-15 Lower Compt Purge Air Supply 7 FCV-30-16 Lower Compt Purge Air Supply 8 FCV-30-17 Lower Compt Purge Air Supply 9 FCV-30-19 Inst Room Purge Air Supply 10 FCV-30-20 Inst Room Purge Air Supply 11 FCV-30-37 Lower Compt Pressure Relief 12 FCV-30-40 Lower Compt Pressure Relief 13 FCV-30-50 Upper Compt Purge Air Exh 14 FCV-30-51 Upper Compt Purge Air Exh 15 FCV-30-52 Upper Compt Purge Air Exh 16 FCV-30-53 Upper Compt Purge Air Exh 17 FCV-30-56 Lower Compt Purge Air Exh 18 FCV-30-57 Lower Compt Purge Air Exh 19 FCV-30-58 Inst Room Purge Air Exh 20 FCV-30-59 Inst Room Purge Air Exh 21 FCV-90-107 Cntmt Bldg LWR Compt Air Mon 22 FCV-90-108 Cntmt Bldg LWR Compt Air Mon 23 FCV-90-109 Cntmt Bldg LWR Compt Air Mon 24 FCV-90-110 Cntmt Bldg LWR Compt Air Mon 25 FCV-90-111 Cntmt Bldg LWR Compt Air Mon 26 FCV-90-113 Cntmt Bldg UPR Compt Air Mon 27 FCV-90-114 Cntmt Bldg UPR Compt Air Mon 28 FCV-90-115 Cntmt Bldg UPR Compt Air Mon T624-1 .doc

SQN-23 TABLE 6.2.4-1 (Sheet 4)

CONTAINMENT PENETRATIONS CONTAINMENT ISOLATION VALVE STROKE TIME REQUIREMENTS VALVE NUMBER FUNCTION MAXIMUM ISOLATION TIME (SECONDS) 29 FCV-90-116 Cntmt Bldg UPR Compt Air Mon 5 30 FCV-90-117 Cntmt Bldg UPR Compt Air Mon 5 D. OTHER 1 FCV-30-46 Vaccum Relief Isolation Valve 25 2 FCV-30-47 Vaccum Relief Isolation Valve 25 3 FCV-30-48 Vaccum Relief Isolation Valve 25 4 FCV-62-90 Normal Charging Isolation Valve 12 T624-1 .doc

SQN the lantern ring and a minimum of a one-half set of packing above the lantern ring. A full set of packing is defined as a depth of packing equal to 1-1/2 times the stem diameter. Some valves may have generic valve packing substitutions as recommended by EPRI Report NP-5697, Project 2233-3, Final Report, May 1988.

The motor operator incorporates a "hammer blow" feature that allows the motor to attain its I j:

operational speed prior to being subjected to operational loads.

Manual Globes, Gates, and Check Valves Gate valves are either wedge design or parallel disc and are straight through. The wedge is either split or solid. All gate valves have backseat and outside screw and yoke.

Globe valves, "T" and "Y" style are full ported with outside screw and yoke construction.

Check valves are spring loaded lift piston types for sizes 2 inches and smaller, and swing type 1 for size 3 inches and larger. Stainless steel check valves have no penetration welds other than 13 the inlet, outlet and bonnet. The check hinge is serviced through the bonnet.

The stem packing and gasket of the stainless steel manual globe and gate valves are similar to those described above for motor operated valves. Carbon steel manual valves are employed to pass non-radioactive fluids only and therefore do not contain the double packing and seal weld provision.

Diaphragm Valves The diaphragm valves use the diaphragm member for shutoff with even weir bodies. These valves are used throughout the ECCS where pressures and temperatures permit.

Accumulator Check Valves The low pressure accumulator check valves are designed with a low pressure drop configuration with all operating parts contained within the body.

Design considerations and analyses which assure that leakage across all the check valves located in each accumulator injection line will not impair accumulator availability are as follows:

1. During normal operation the differential pressure is approximately 1635 psid for the check valves in the cold leg lines. Since the valves remain in this position except when tested or I when called upon to function, they are not subject to the abuses of flow operation or impact loads caused by sudden flow reversal and seating. They do not experience significant wear of the moving parts and hence are expected to function with minimal leakage.

2. When the RCS is being pressurized during the normal plant heatup operation, the check valves are tested for leakage in accordance with Technical Specifications. This testI 3 confirms the seating of the disc.

3. The experience derived from the check valves employed in the emergency injection systems indicate that the system is reliable and workable. This is substantiated by the satisfactory experience from operation of the Ginna and subsequent plants where the usage of check valves is identical to this application.

Relief Valves The accumulator relief valves are sized to pass nitrogen gas at a rate in excess of the accumulator gas fill line delivery rate. The relief valves will also pass water in excess of the

$6-3.doc 6.3-5

SQN-23 expected accumulator in leakage rate, but this is not considered to be necessary, because the time required to fill the gas space gives the operator ample opportunity to correct the situation. Other relief valves are installed in various sections of the ECCS to protect lines which have a lower design pressure than the RCS. Some relief valves discharge to the pressurizer relief tank. The valve stem and spring adjustment assembly are isolated from the system fluids by a bellows seal between the valve disc and spindle.

Butterfly Valves Each main residual heat removal line has an air-operated butterfly valve which is normally open and is designed to fail in the open position. These valves are left in the full open position during normal operation to maximize flow from this system to the RCS during the injection mode of the ECCS operation.

Throttle Valves The correct position of each mechanical stop shall be verified within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> following action of each valve stroking operation or maintenance on the valve when the ECCS subsystems are required to be operable for the following ECCS throttle valves: Charging Pump Injection Throttle Valves (63-582,63-583,63-584, and 63-585) Safety Injection Cold Leg Throttle Valves (63-550,63-552, 63-554, and 63-556) and Safety Injection Hot Leg Throttle Valves (63-542,63-544, 63-546, and 63-548)

All piping joints are welded except for pump connections, butterfly valves, relief valves, orifice plate flange connections, and flanged connections for maintenance.

Weld connections for pipes sized 2-1/2 inches and larger are butt welded. Reducing tees are used where the branch size exceeds one-half of the header size. Branch connections of sizes that are equal to or less than one-half of the header size conform to the ANSI B31.1.0-1967 Edition Code.

Branch connections 1/2 through 2 inches are attached to the header by means of full penetration welds, using pre-engineered integrally reinforced branch connections.

Minimum piping and fitting wall thickness as determined by ANSI B31.1.0-1967 Edition formula are increased to account for the manufacturer's permissible tolerance of minus 12-1/2 percent on the nominal wall and an appropriate allowance for wall thinning on the external radius during any pipe bending operations in the shop fabrication of the subassemblies.

To assure that air pockets, which may cause disruptive water hammer and/or pump binding, are eliminated from the ECCS, vent valves have been located at high points throughout the system. The use of these valves when filling will ensure a solid system from the suction valves at the containment sump to the inlet valve to the containment spray header. The piping from the containment sump to the suction valve is normally maintained dry and have been designed to be self venting. The RHR spray header is maintained with a 30 day water seal for 10CFR50 Appendix J. The spray header is also self venting.

Once the system is filled, a positive static pressure provided by the RWST precludes the leaking of air into the system.

Leak detection is discussed in Sections 5.2.7 and 6.3.2.11.

System Operation The operation of the ECCS following a Loss of Coolant Accident, can be divided into two distinct modes:

1. The injection mode in which any reactivity increase following the postulated accidents is terminated, initial cooling of the core is accomplished, and coolant lost from the primary system in the case of a LOCA is replenished, and

2. The recirculation mode in which long term core cooling is provided during the accident recovery period.

A discussion of these modes follows.

S6-3.doc 6.3-6

SQN-23 Since the operation of the active components of the ECCS following a steam line rupture is identical to that following a loss of coolant accident, the same analysis is applicable and the ECCS can sustain the failure of any single active component and still meet the level of performance for the addition of shutdown reactivity. Passive failure is not considered for the short term.

Passive Failure Criteria The following philosophy provides for necessary redundancy in component and system arrangement to meet the intent of the NRC General Design Criteria on single failure as it specifically applies to failure of passive components, in the ECCS. Thus, for the long term, the system design is based on accepting either a passive or an active failure.

Redundancy of Flow Paths and Components for Long-Term Emergency Core Cooling In design of the Emergency Core Cooling System, Westinghouse utilized the following criteria.

1. During the long-term cooling period following a LOCA, the emergency core cooling flow paths are separable into two sub-systems, either of which can provide minimum core cooling functions and return spilled water from the floor of the containment back to the RCS.

2. Either of the two sub-systems can be isolated and removed from service in the event of a leak outside the containment.

3. Adequate redundancy of check valves is provided to tolerate failure of a check valve during the long-term as a passive component.

4. Should one of these two sub-systems be isolated in this long-term period, the other sub-system remains operable.

5. Provisions are also made in the design to detect leakage from components outside the containment, collect this leakage and to provide for maintenance of the affected equipment.

Thus, for the long-term emergency core cooling function, adequate core cooling capacity exists with one flow path removed from service whether isolated due to a leak, because of blocking of one flow path, or because failure in the containment results in a spill of the delivery of one injection flow path. It should be noted that closure of the A-Train Safety Injection Pump Suction Isolation Valve (FCV-63-47) during power operation will prevent B-Train Residual Heat Removal from supplying either Centrifugal Charging Pump in the cold leg recirculation mode. This results in the inoperability of both trains of ECCS because at least one complete independent train cannot be established in all ECCS modes; however, entry into LCO 3.0.3 is not required provided that at least 100 percent of the ECCS flow equivalent to a single operable ECCS train is available. The design intent of the ECCS piping layout is to maximize the number of options available to the control room operator for response to a passive failure. This is consistent with the defense in depth approach for ECCS design.

Subsequent Leakage from Components in Safeguards Systems With respect to piping and mechanical equipment outside the containment, considering the provisions for visual inspection and leak detection, leaks will be detected before they propagate to major proportions. A Westinghouse review of the equipment in the system indicates that the largest sudden leak potential would result from the sudden failure of an RHR or CS pump shaft seal. Evaluation of seal leakage assuming only the presence of a seal retention ring around the pump shaft showed flows less than 50 gpm would result. Piping leaks, valve packing leaks, or flange gasket leaks have been of a nature to build up slowly with time and are considered less severe than the pump seal failure.

$6-3.doc 6.3-13

SQN

1. The piping is classified in accordance with ANS Safety Class 2 and receives the ASME Class 2 quality assurance program associated with this safety class.

2. The piping, equipment and supports are designed to insure no loss of function for the Safe Shutdown Earthquake.

3. The system piping is located within a controlled area on the plant site.

4. The piping system receives periodic tests and is accessible for periodic visual inspection. 13

5. The piping is austenitic stainless steel which, due to its ductility, can withstand severe distortion without failure.

Based on this review, design of the Auxiliary Building and related equipment is based upon handling of ECCS !e.--ks up tc a maximum of 50 gppm. To assure adequatn core cooling, design features are provided to prevent this limiting passive failure from causing any loss of function in the other train of the ECCS equipment due to flooding of redundant components or loss of NPSH to the ECCS pumps. Independent means are available to provide information to the operator for 13 use in identifying ECCS leakage into certain locations in the Auxiliary Building. These means include the Auxiliary Building flood detection system, the instrumentation and alarms associated with the drainage and waste processing systems which normally handle drainage into these areas.

A flood detection system utilizing conductivity type water level detector devices is used to monitor and actuate alarms for ECCS and other leakage at specific locations in the Auxiliary 13 Building. Individual detectors are located in each ECCS pump compartment, in the ECCS heat exchanger rooms, in the pipe gallery for each unit, and in the pipe chase. A common alarm in the main control room will alert the operator when any of these flood detectors are tripped. A flood detector indicator panel, located immediately outside the control room, then identifies the exact location of the tripped detector. The detector panel is provided with a test switch which can be used to verify the availability of power to each individual detector. These flood detectors are to be tested to verify initial operability and will be periodically tested as a part of the plant instrument surveillance and maintenance program.

Since each ECCS pump and heat exchanger room is monitored by a level detection device, the operator may immediately identify leakage into one of these rooms and determine which subsystem must be shut down and secured to terminate the leak. The operator can readily accomplish this action from the main control room by stopping the appropriate subsystem pump and by closing the corresponding sump isolation valves and individual pump discharge valves.

The time necessary for the operator to detect leakage into one of these rooms is dependent on the leakage rate. A limiting 50 gpm leak in the largest ECCS pump room can be detected within 30 minutes. Slower leaks will require proportionally longer detection times.

Leakage into the SIS or CVCS pump rooms, the pipe chase, or the pipe gallery (all at elevation 669) is piped through the floor drain header to the floor drain collector tank at elevation 653.

ECCS leakage into the RHR or CS pump rooms or the pipe chase (all at elevation 653) is piped to the Auxiliary Building floor and equipment drain sump. The floor drain in each of these areas is provided with a standpipe which assures that the setpoint for the water level detector is reached prior to draining the leakage from the room. However, the standpipes each have drilled holes to allow minor normal leakage to drain from the room.

The Auxiliary Building floor and equipment drain sump is provided with redundant 50 gpm pumps which automatically start on high level. Pump flow can be directed to either the floor drain 3I 3

collector tank or to the tritiated drain collector tank. Operation of these pumps is indicated in the

$6-3.doc 6.3-14

SQN 6.3.2.14 Net Positive Suction Head The ECCS is designed so that adequate net positive suction head is provided to system pumps.

Adequate net positive suction head is shown to be available for all pumps as follows:

1. Residual Heat Removal Pumps The net positive suction head of the residual heat removal pumps is evaluated for normal plant shutdown operation, and for both the injection and recirculation modes of operation for the design basis accident. Recirculation operation gives the limiting net positive suction head requirement, and the net positive suction head available is determined from the containment pressure, vapor pressure of liquid in the sump, containment sump level relative to the pump elevation and the pressure drop in the suction piping from the sump to the pumps. The net positive suction head evaluation is based on all pumps operating at the maximum design flow rates. The residual heat removal pump head-capacity and net positive suction head curves are given in Figure 6.3.2-5.

2. Safety Injection and Centrifugal Charging Pumps The net positive suction head for the safety injection pumps and the centrifugal charging pumps is evaluated for both the injection and recirculation modes of operation for the design basis accident. The end of the injection mode of operation gives the limiting net positive suction head available. The net positive suction head available is determined from the elevation head and vapor pressure of the water in the refueling water storage tank, which is at atmospheric pressure, and the pressure drop in the suction piping from the tank to the pumps. At the end of the injection mode when suction from the refueling water storage tank is terminated (low refueling water storage tank level), adequate net positive suction head is supplied from the containment sump by the booster action of the RHR pumps. The net positive suction head I 3 evaluation is based on all pumps operating at the maximum design flow rates. The head-capacity, and net positive suction head curves for the safety injection pumps are given in Figure 6.3.2-6. The head-capacity and net positive suction head curves for the charging pumps are given in Figure 6.3.2-7.

6.3.2.15 Control of Motor-Operated Isolation Valves The design of the control circuit for the motor operated isolation valves in the lines connecting a cold leg accumulator to the RCS provides protection against inadvertent closure. The cold leg accumulator isolation valves are FCV-63-118, accumulator 1 (train A), FCV-63-98, accumulator 13 2 (train B), FCV-63-80, accumulator 3 (train A), and FCV-63-67, accumulator 4 (train B). During heatup and pressurization of the RCS, these valves are manually opened in accordance with technical specification requirements. After the valves are opened, electrical power is removed to prevent inadvertent valve closure. During cooldown, electrical power is restored so that the valves can be manually closed from the main control room when allowed by technical specifications. Control power and therefore position indication is retained when motor power is removed to provide for main control room indication of valve position. Although the valves are normally open during operation, they receive a safety injection signal to open. These valves are 13 also automatically opened when the system pressure exceeds the P-11 permissive level (1970 psig).

6.3.2.16 Motor Operated Valves and Controls Remotely operated valves for the injection mode which are under manual control (i.e., valves normally in the ready position not requiring an SIS signal) have their positions indicated on a common portion of the control board. If a component is out of its proper position, its status monitor light will indicate this on the status monitor control panel. At any time during operation S6-3.doc 6.3-17

SQN-23 when one of the valves is not in the ready position for injection, this condition is shown visually on the board, and an audible alarm is sounded in the main control room. The motor-operated isolation valves located between the high pressure RCS and the relatively low pressure RHRS are discussed in Subsections 5.5.7 and 7.6.2.

6.3.2.17 Manual Actions No manual actions are required during the injection phase except for the Shutdown LOCA (SDLOCA) where the operator must manually establish sufficient ECCS flow. Actions required by the operator for proper ECCS operation following injection are those required to realign the system for cold leg recirculation and hot leg recirculation mode of operation.

During a Shutdown LOCA initiated after the RHR is aligned for shutdown cooling, the RHR pump suction piping might have to be cooled prior to starting the RHR pumps using either the RWST or the Containment Sump as the suction source. The cooling might be necessary in order to ensure that the RHR pumps have adequate NPSH and to ensure that potential steam voids in RHR system piping cannot cause a waterhammer event or damage to the RHR pump. The cooling might also be necessary to ensure that the Containment Spray pumps have adequate NPSH when being realigned to the Containment Sump.

6.3.2.18 Process Instrumentation Process instrumentation available to the operator in the control room to assist in assessing post loss of coolant accident conditions are tabulated in Section 7.5.

6.3.2.19 Materials Materials employed for components of the ECCS are given in Table 6.3.2-6. These materials are chosen based upon their ability to resist radiolytic and pyrolitic decomposition. (See Subsection 6.3.2.4) Coatings specified for use on the ECCS components (mainly, the cold leg accumulators) are designated to meet the requirements of ANSI 101.2-1972; "Protective Coatings (Paints) For Light Water Nuclear Reactor Containment Facilities," as a minimum.

6.3.3 Performance Evaluation 6.3.3.1 Evaluation Model The following analyses are performed to ensure that the limits on core behavior following a RCS pipe rupture are met by the ECCS operating with minimum design equipment:

1. Large pipe break analysis

2. Small line break analysis

3. Main steam system line rupture

4. Recirculation cooling The flow delivered to the RCS by the ECCS as a function of reactor coolant pressure with the operation of minimum design equipment is analyzed in Section 15.4.

The design basis performance characteristic is derived from the specified performance characteristic for each pump with a conservative estimate of system piping resistance, based upon piping layout for the flow diagram illustrated in Figure 6.3.2-1.

The performance characteristic utilized in the accident analyses includes a 5 percent decrease in the design head for margin. When the initiating incident is assumed to be the severance of an injection line the injection curve utilized in the analysis accounts for the loss of injection water through the broken line.

6.3.3.2 ECCS Performance The large pipe break analysis is used to evaluate the initial core thermal transient for a spectrum of pipe ruptures from a break size of 0.5 ft2 up to the double ended rupture of the largest pipe in the Reactor Coolant System.

S6-3.doc 6.3-18

SQN-23 The injection flow from active components is required to control the cladding temperature subsequent to accumulator injection, complete reactor vessel refill, and eventually return the core to a subcooled state. The results indicate that the maximum cladding temperature attained at any point in the core is such that the limits on core behavior as specified in Section 15.4 are met.

A flow balance test shall be performed during shutdown following action of modifications to the ECCS subsystem that alter the subsystem flow characteristics and verifying the following flow rates:

1. For safety injection pump lines with a single pump running:

a. The sum of the injection line flow rates, excluding the highest flow rate is greater than or equal to 443 gpm, and

b. The total pump flow rate is less than or equal to 675 gpm.

2. For centrifugal charging pump lines with a single pump running:

a. The sum of the injection line flow rates, excluding the highest flow rate is greater than or equal to 309 gpm, and

b. The total pump flow rate is less than or equal to 555 gpm.

3. For all four cold leg injection lines with a single RHR pump running a flow rate greater than or equal to 3931 gpm.

6.3.3.3 Alternate Analysis Methods The small pipe break analysis is used to evaluate the initial core thermal transient for a spectrum of pipe rupture from 3/8 inch up to and including the rupture of a six inch diameter pipe. For breaks 3/8 inch or smaller (except those in the PRZ vapor space), the charging system can maintain the pressurizer level and the Reactor Coolant System operating pressure and the Emergency Core Cooling System would not be actuated.

The results of the small pipe break analysis indicate that the limits on core behavior are adequately met, as shown in Section 15.3.

Main Steam System Single Active Failure Analyses of reactor behavior following any single active failure in the main steam system which results in an uncontrolled release of steam are included in Section 15.2. The analyses assume that a single valve (largest of the safety, relief, or bypass valves) opens and fails to close, which results in an uncontrolled cooldown of the Reactor Coolant System.

Results indicate that if the incident is initiated at the hot shutdown condition, which results in the highest reactivity worth, the DNB criteria is satisfied. Thus, the Emergency Core Cooling System provides adequate protection for this incident.

Steam Line Rupture Following a steam line rupture the Emergency Core Cooling System is automatically actuated to deliver borated water from the RWST to the Reactor Coolant System. The response of the Emergency Core Cooling System following a steam line break is identical to its response during the injection mode of operation following a loss of coolant accident.

This accident is discussed in detail in Section 15.4 the limiting steam line rupture is a complete line severance.

$6-3.doc 6.3-19

SQN-23 In the case of a steam line rupture when offsite power is not assumed lost, credit is taken for the uninterrupted availability of power for the Emergency Core Cooling System components.

The results of the analysis in Section 15.4 indicate that the design basis criteria are met. Thus, the Emergency Core Cooling System adequately fulfills its shutdown reactivity addition function.

A technical specification is established to ensure the availability of the RWST which provides the shutdown reactivity.

The safety injection actuation signal initiates identical actions as described for the injection mode of the loss of coolant accident, even though not all of these actions are required following a steam line rupture, e.g., the residual heat removal pumps are not required since the Reactor Coolant System pressure will remain above their shutoff head.

The delivery of borated water from the RWST results in a negative reactivity change to counteract the increase in reactivity caused by the system cooldown. The charging pumps continue to deliver borated water from the refueling water storage tank, until enough water has been added to the Reactor Coolant System to make up for the shrinkage due to cooldown. The safety injection pumps also deliver borated water from the refueling water storage tank for the interval when the Reactor Coolant System pressure is less than the shutoff head of the safety injection pumps. After pressurizer water level has been restored, the injection is manually terminated. A high pressurizer water level alarm in the control room would warn the operator to terminate injection flow if this were not done previously.

The sequence of events following a postulated steam line break is described in Section 15.4.

6.3.3.4 Fuel Rod Perforations Discussions of peak clad temperature and metal-water reactions appear in Subsections 15.3.1 and 15.4.1. Analyses of the radiological consequences of RCS pipe ruptures also are presented in Subsection 15.5.

6.3.3.5 Evaluation Model Does not apply to this plant (BWRs only).

6.3.3.6 Fuel Clad Effects Does not apply to this plant (BWRs only).

6.3.3.7 ECCS Performance Does not apply to this plant (BWRs only).

6.3.3.8 Peak Factors Does not apply to this plant (BWRs only).

6.3.3.9 Fuel Rod Perforations Does not apply to this plant (BWRs only).

6.3.3.10 Conformance With Interim Acceptance Criteria Does not apply to this plant (BWRs only).

6.3.3.11 Effects of ECCS Operation on the Core The effects of the ECCS operation on the reactor core are discussed in Sections 15.3 and 15.4.

6.3.3.12 Use of Dual Function Components The Emergency Core Cooling System contains components which have no other operating function as well as components which are shared with other systems and perform normal operating functions.

Components in each category are as follows:

1. Components of the Emergency Core Cooling System which perform no other function are:

6.3-20

SQN-23

a. One accumulator for each loop which discharges borated water into its respective cold leg of the reactor coolant loop piping.

b. Two safety injection pumps which supply borated water for core cooling to the Reactor Coolant System. These pumps are also used for filling the accumulators.

c. Associated piping, valves and instrumentation.

2. Components which also have a normal operating function are as follows:

a. The residual heat removal pumps and the residual heat exchangers:

These components are normally used during the latter stages of normal reactor cooldown and when the reactor is held at cold shutdown or refueling for core decay heat removal. However, during all other plant operating periods, they are aligned to perform the low head injection function.

b. The centrifugal charging pumps: These pumps are normally aligned for RCP seal injection and charging service as part of the Chemical and Volume Control System. The normal operation of these pumps is discussed in Section 9.3.4.

c. The refueling water storage tank: This tank is used to fill the refueling canal for refueling operations. It is normally aligned to the suction of the safety injection pumps and the residual heat removal pumps for the ECCS function and to the suction of containment spray pumps. It is normally isolated from the RHR pump suction when the RHR pumps are aligned to the RCS for shutdown cooling. The RWST may be aligned to the RCS during RCS drain and fill operations. The charging pumps are aligned to the suction of the refueling water storage tank upon receipt of the safety signal.

An evaluation of all components required for operation of the Emergency Core Cooling System demonstrates that either:

1. The component is not shared with other systems, or

2. If the component is shared with other systems, it is aligned during normal plant operation to perform its accident function; or if not aligned to its accident function, two valves in parallel are provided to align the system for injection, and two valves in series are provided to isolate portions of the system not utilized for injection. These valves are automatically actuated by the safety injection signal.

Table 6.3.3-1 indicates the alignment of major components during normal operation, and the realignment required to perform the accident function.

Dependence on Other Systems Other principal systems which operate in conjunction with the Emergency Core Cooling System are as follows:

1. The Component Cooling System cools the residual heat exchangers during the recirculation mode of operation. It also supplies cooling water to the mechanical seal coolers for the centrifugal charging pumps and the safety injection pumps, and the seal water heat exchangers for the residual heat removal pumps.

2. The Essential Raw Cooling Water System provides cooling water to the component cooling heat exchangers, various coolers for the centrifugal charging pumps and the safety injection pumps, and the ESF equipment room coolers.

3. The electrical systems provide normal and emergency power sources for the Emergency Core Cooling System.

4. The Engineered Safety Features Actuation System generates the initiation signal for emergency core cooling.

6.3-21

SQN-23

5. The Auxiliary Feedwater System supplies feedwater to the steam generators.

Limiting Conditions for Operation The design philosophy with respect to active components in the high head/low head injection system is to provide backup equipment so that maintenance is possible during operation, in accordance with Technical Specification Action limitations, without impairment of the safety function of the system.

6.3.3.13 Laq Times The minimum active components will be capable of delivering full rated flow within a specified time interval after process parameters reach the setpoints for the safety injection signal. Response of the system is automatic, with appropriate allowances for delays in actuation of circuitry and active components. The active portions of the system are actuated by the safety injection signal. In analyses of system performance, delays in reaching the programmed trip points and in actuation of components are established on the basis that only emergency onsite power is available. A further discussion of the starting sequence is given in Subsection 8.3.1.

In the loss of coolant accident analysis presented in Sections 15.3 and 15.4 no credit is assumed for partial flow prior to the establishment of full flow and no credit is assumed for the availability of offsite power sources.

For smaller loss of coolant accidents, there are some additional delays before the process variables reach their respective programmed trip setpoints since this is a function of the severity imposed by the accident. Allowances are made for this in the analyses of the spectrum of reactor coolant pipe breaks.

6.3.3.14 Thermal Shock Considerations Thermal shock considerations are discussed in Section 5.2.

6.3.3.15 Limits on System Parameters A comprehensive testing program has been undertaken to demonstrate that the Emergency Core Cooling System components and associated instrumentation and electrical equipment which are located inside the containment will operate for the time period required in the combined post loss of coolant accident conditions of temperature, pressure, humidity, radiation, and chemistry (Reference 1).

Components such as remote motor operated valves and flow and pressure transmitters have been shown capable of operating for the required post-accident periods, when exposed to post loss of coolant environmental conditions.

The specification of individual parameters as given in Table 6.3.2-1 includes due consideration of allowances for margins over and above the required performance value (e.g., pump flow and net positive suction head), and the most severe conditions to which the component could be subjected (e.g., pressure, temperature, and flow).

This consideration ensures that the Emergency Core Cooling System is capable of meeting its minimum required level of functional performance.

6.3.4 Tests and Inspections Performance tests of the components are performed in the manufacturer's shop. An initial pre-operational system flow test is performed to demonstrate the proper functioning of all of the components. In order to demonstrate the readiness and operability of the Emergency Core Cooling System, components are subjected to periodic tests and inspections in accordance with the ASME Section Xl programs and the 10CFR50 Appendix J program as required. The Emergency Core Cooling System components are designed and fabricated to permit inspection and in-service tests in accordance with ASME Code Section XI.

6.3-22

SQN-23 Quality Control Tests and inspections are carried out during fabrication of each of the Emergency Core Cooling System components. These tests are conducted and documented in accordance with the Quality Assurance program discussed in Chapter 17.

Pre-Operational Tests These tests are intended to evaluate the hydraulic and mechanical performance of the passive and active components involved in the injection mode by demonstrating that they have been installed and adjusted so they will operate in accordance with the design intent. These tests are divided into three individual sections that may be performed as plant conditions allow without compromising the integrity of the tests.

One of these individual sections consists of system actuation tests to verify: The operability of all Emergency Core Cooling System valves initiated by the safety injection "S" signal, the phase A containment isolation "T"signal; the operability of all safeguard pump circuitry down through the pump breaker control circuits; and the proper operation of all valve interlocks.

Another of the individual sections is the accumulator injection test. The objective of this section is to check the accumulator injection line to verify that the lines are free from obstructions and that the accumulator check valves operate correctly. The test objectives will be met by a low pressure blowdown of each accumulator. The cold leg accumulator test was performed with the reactor head and internals removed.

The last of the individual sections consists of operational tests of all of the major pumps - i.e., the charging pumps, the residual heat removal pumps, and the safety injection pumps. The purpose of these tests is to evaluate the hydraulic and mechanical performance of the pumps delivering through the flow paths required for emergency core cooling. These tests will be divided into two parts: pump operation under mini flow conditions and pump operation at full flow conditions. The predicted system resistance will be verified by measuring the flow in each piping branch, as each pump delivers from the refueling water storage tank to the open reactor vessel, and adjustment made where necessary to assure that no one branch has an unacceptably low or high resistance. During this flow test, the system will also be checked to assure there is sufficient total line resistance to prevent excessive run out of the pump. At the completion of the flow test, the total pump flow and relative flow between the branch lines will be compared with the minimum acceptable flows as determined for the safety analysis.

The systems are accepted only after demonstration of proper actuation of all components and after demonstration of flow delivery of all components within design requirements.

Periodic Component Testing Routine periodic testing of the Emergency Core Cooling System components and necessary support systems is performed in accordance with plant Technical Specifications. Components not covered by Technical Specifications may also be periodically tested at power in accordance with approved plant maintenance program procedures.

Pumps and valves are periodically tested in accordance with Technical Specifications and ASME Section Xl. Ifsuch testing indicates a need for corrective maintenance, the redundancy of equipment in these systems permits such maintenance to be performed without shutting down or reducing load under certain conditions as permitted by Technical Specifications.

Test lines are provided for periodic measurement of the leakage of reactor coolant back through the accumulator discharge line check valves and to ascertain that these valves seat whenever the Reactor Coolant System pressure is raised. These tests are routinely performed in accordance with Technical Specifications and ASME Section Xl when the reactor is being returned to power after an outage and the reactor pressure is raised above the accumulator pressure. To implement the periodic component testing requirements, the SQN Technical Specifications have been established. During periodic system testing, a visual inspection of assessable pump seals, valve 6.3-23

SQN-23 packings, flanged connections, and relief valves can be made to detect leakage. Inservice inspection provides further confirmation that no significant deterioration is occurring in the Emergency Core Cooling System fluid boundary.

Design measures have been taken to assure that the following testing can be performed:

1. Active components may be tested periodically for operability (e.g., pumps on mini flow, certain valves, etc.).

2. An integrated system actuation test can be performed when the plant is cooled down and the Residual Heat Removal System is in operation. The Emergency Core Cooling System can be arranged so that no flow will be introduced into the Reactor Coolant System for this test. Details of the testing of the sensors and logic circuits associated with the generation of a safety injection signal together with the application of this signal to the operation of each active component are given in Section 7.2.

3. An initial flow test of the full operational sequence can be performed.

The design features which assure this test capability are specifically:

1. Power sources are provided to permit individual actuation of each active component of the Emergency Core Cooling System.

2. The safety injection pumps can be tested periodically during plant operation using the minimum flow recirculation lines provided.

3. The residual heat removal pumps are used every time the Residual Heat Removal System is put into operation. They can also be tested periodically using the miniflow recirculation lines.

4. The centrifugal charging pumps are either normally in use for charging service or can be tested periodically on miniflow or charging flow.

5. Remote operated valves can be exercised.

6. Level and pressure instrumentation are provided for each accumulator tank, for continuous monitoring of these parameters during plant operation.

7. Flow from each accumulator tank can be directed through a test line to determine check valve leakage.

8. A flow indicator is provided in the safety injection pump header, and in the residual heat removal pump headers. Pressure instrumentation is also provided in these lines.

9. An integrated system test can be performed during shutdown to demonstrate the operation of the valves, pump circuit breakers, and automatic loading of Emergency Core Cooling System components on the diesels (by simultaneously simulating a loss of offsite power to the vital electrical buses).

6.3.5 Instrumentation Application 6.3.5.1 Temperature Indication Residual Heat Exchanger Inlet and Outlet Temperature The fluid temperature at the inlet and outlet of each residual heat exchanger is recorded in the main control room.

6.3-24

SQN-23 Refuelingq Water Storage Tank (RWST) Temperature Two temperature channels are provided to monitor the RWST temperature. Both are indicated in the main control room. A high/low temperature alarm is provided in the main control room.

6.3.5.2 Pressure Indication CCP Iniection Tank Pressure CCP injection tank outlet pressure is indicated in the main control room. A high pressure alarm is provided.

Safety Iniection Header Pressure Safety injection pump discharge header pressure is indicated in the main control room.

Cold Leg Accumulator Pressure Duplicate pressure channels are installed on each cold leg accumulator. Pressure indication in the control room and high and low pressure alarms are provided by each channel.

Residual Heat Removal Pump Discharge Pressure Residual heat removal discharge pressure for each pump is indicated in the main control room. A high pressure alarm is actuated by each channel.

6.3.5.3 Flow Indication Charging Pump Iniection Header Flow The total centrifugal charging pump injection flow, which discharges to the cold leg injection header, is indicated in the main control room.

Residual Heat Removal Pump Iniection Flow Flow through each residual heat removal injection and recirculation header leading to the reactor cold or hot legs is indicated in the main control room.

Test Line Flow "Bucket testing" or an alternate flow measurement device can be used to determine test line flow to verify proper seating of the accumulator check valves between the injection lines and the reactor coolant system.

Residual Heat Removal Pump Minimum Flow Installed in each residual heat removal pump discharge header is a local flow meter and flow switches for miniflow valve control.

6.3.5.4 Level Indication Refueling Water Storaqe Tank Level Six water level indicator channels, which indicate in the main control room, are provided for the refueling water storage tank. Four wide range channels alarm on low and low-low water levels, 6.3-25

SQN-23 and are indicated on the main control board. Two narrow range channels are also provided with low and high-level alarms indicated on the main control board.

Accumulator Water Level Duplicate water level channels are provided for each accumulator. The channels monitoring the level in the cold leg accumulators do so directly. Both channels provide indication, for each accumulator, in the main control room and actuate high and low water level alarms.

Containment Sump Water Level Four containment sump water level indicator channels provide the main control room with water level indication.

6.3.5.5 Valve Position Indication Valve positions are indicated on the control board such that a valve not in its proper position will cause a white monitor light to illuminate and thereby give a highly visible indication to the. operator.

Valve position is also indicated by a second system employing a "red-green" light system on the control board. Thus should any bulb fail in service, the true position of the valve can still be determined.

Accumulator Isolation Valve Position Indication The accumulator isolation valves are provided with red (open) and green (closed) position indication lights located at the control switch for each valve. These lights are powered by valve control power and actuated by valve motor operator limit switches.

A monitor light that is on when the valve is not fully open is provided in an array of monitor lights that are all off when their respective valves are in proper position enabling safeguards operation. This light is energized from a separate monitor light supply and actuated by a valve motor operated limit switch.

An alarm annunciator point is activated by both a valve motor operator limit switch and by a valve position limit switch activated by stem travel whenever an accumulator valve is not fully open for any reason with the system at pressure (the pressure at which the safety injection block is unblocked). A separate annunciator point is used for each accumulator valve. This alarm will be recycled at approximately one hour intervals to remind the operator of the improper valve lineup.

Refuelinq Water Storage Tank Isolation Valve The control and indications provided for these valves are identical to those provided for the cold leg accumulator isolation valves, with the exception that a safety injection signal is not applied to the valves between the safety injection pumps, and residual heat removal pumps, and the refueling water storage tank.

6.3.6 References

1. Westinghouse Topical Report, "Environmental Testing of Engineered Safety Features Related Equipment (NSSS-Standard Scope)," NCAP-7774, Volume 1, August 1971.

2. ASME Section Xl Program Basis Documents for Sequoyah Nuclear Plant.

3. SQN Design Criteria SQN-DC-V-27.3, "Safety Injection System."

6.3-26

SQN-23 6.9 MOTOR-OPERATED VALVE PROGRAM - GENERIC LETTER 89-10 6.9.1 Program Description NRC Generic Letter (GL) 89-10, "Safety-Related Motor Operated Valve Testing and Surveillance," requests that holders of nuclear power plant operating licenses and construction permits establish a program to provide for testing, inspection, and maintenance of safety-related motor-operated valves (MOVs) and certain other MOVs in safety-related systems so as to provide the necessary assurance that they will function when subjected to the design basis conditions that are to be considered during both normal operation and abnormal events within the design basis of the plant.

GL 89-10, GL 95-07; Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves, and GL 96-05; Periodic Verification of Design-Basis Capability of Safety-Related MOVs, are described in the Motor-Operated Valve Program.

6.9.2 References

1. TVA letter to NRC dated December 21, 1989, Browns Ferry Nuclear Plant (BFN),

Sequoyah Nuclear Plant (SQN), and Watts Bar Nuclear Plant (WBN) - Response to Generic Letter (GL) 89 Safety-Related Motor-Operated Valve (MOV) Testing and Surveillance.

2. TVA letter to NRC dated October 28, 1991, Sequoyah Nuclear Plant - Supplemental Information for Compliance with Generic Letter (GL) 89-10.

3. TVA letter to NRC dated November 26, 1991, Sequoyah Nuclear Plant (SON) - TVA Response to NRC Inspection Report 91-18 Regarding Generic Letter (GL) 89-10.

4. TVA letter to NRC dated October 16, 1995, Browns Ferry Nuclear Plant (BFN), Sequoyah Nuclear Plant (SQN), and Watts Bar Nuclear Plant (WBN) - Initial response to (GL) 95-07, Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves.

5. TVA letter to NRC dated December 15, 1995, Browns Ferry Nuclear Plant (BFN),

Sequoyah Nuclear Plant (SON), and Watts Bar Nuclear Plant (WBN) - Revised response to (GL) 95-07, Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves.

6. TVA letter to NRC dated March 15, 1996, Browns Ferry Nuclear Plant (BFN), Sequoyah Nuclear Plant (SON), and Watts Bar Nuclear Plant (WBN) - Supplement response to (GL) 95-07, Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves.

7. TVA letter to NRC dated February 13, 1996, Browns Ferry Nuclear Plant (BFN),

Sequoyah Nuclear Plant (SON), and Watts Bar Nuclear Plant (WBN) - 180-day response to (GL) 95-07, Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves.

8. TVA letter to NRC dated August 6, 1996, Sequoyah Nuclear Plant units 1 and 2 -

Response to NRC requests for additional information - (GL) 95-07, Pressure Locking and Thermal Binding of Safety-Related Power-Operated Gate Valves.

$6-9.doc 6.9-1

SQN-16

9. TVA letter to NRC dated November 18, 1996, Browns Ferry Nuclear Plant (BFN),

Sequoyah Nuclear Plant (SQN), Watts Bar Nuclear Plant (WBN), and Bellefonte Nuclear Plant (BLN) - Response to (GL) 96-05, Periodic Verification of Design-Basis Capability of Safety-Related Motor-Operated Valves dated September 18, 1996.

10. TVA letter to NRC dated March 17, 1997, Browns Ferry Nuclear Plant (BFN),

Sequoyah Nuclear Plant (SQN), Watts Bar Nuclear Plant (WBN), and Bellefonte Nuclear Plant (BLN) - 180-day response to NRC (GL) 96-05, Periodic Verification of Design-Basis Capability of Safety-Related Motor-Operated Valves dated September 18, 1996.

11. NRC letter to TVA dated August 27, 1998, Completion of Action for Generic Letter 95-07 and Transmittal of Safety Evaluation of Licensee Response, Sequoyah Nuclear Plan, Units 1 and 2 (TAC Nos. M93519 and M93520).

12. TVA letter to NRC dated April 28, 1998, Brown's Ferry Nuclear Plant (BFN),

Sequoyah Nuclear Plant (SQN), Watts Bar Nuclear Plant (WBN), and Bellefonte Nuclear Plant (BLN) Response to NRC's Safety Evaluation dated October 30, 1997 on Joint Owner's Group (JOG) Program for Generic Letter (GL) 96-05, "Periodic Verification (PV) of Motor Operated Valves (MOV)" described in Topical Report MPR-1807 (Revision 2).

13. TVA letter to NRC dated April 23, 1999, Sequoyah Nuclear Plant (SQN) Units 1 and 2 - Docket Nos. 50-327 and 50-328 - Facility Operating License DPR-77 and DPR Response to NRC Questions Conceming Generic Letter (GL) 96-05.

14. NRC's letter to TVA dated January 3, 2000, Sequoyah Nuclear Plant, Units 1 and 2

- Closeout of Generic Letter (GL) 96-05, "Periodic Verification of Design Basis Capability of Safety-Related Motor Operated Valves."

S6-9.doc 6.9-2

SQN-23 7.2.2.3.5 Steam Generator Water Level The basic function of the reactor protection circuits associated with low steam generator water level is to preserve the steam generator heat sink for removal of long term residual heat. Should a complete loss of feedwater occur, the reactor would be tripped on low-low steam generator water level. In addition, redundant auxiliary feedwater pumps are provided to supply feedwater in order to maintain residual heat removal after trip preventing eventual thermal expansion and discharge of the reactor coolant through the pressurizer relief valves into the relief tank even when main feedwater pumps are incapacitated. This reactor trip acts before the steam generators are dry to reduce the required capacity and starting time requirements of these auxiliary feedwater pumps and to minimize the thermal transient on the Reactor Coolant System and steam generators. Therefore, a low-low steam generator water level reactor trip is provided for each steam generator to ensure that sufficient initial thermal capacity is available in the steam generator at the start of the transient. It is desirable to minimize thermal transients on a steam generator for a credible loss of feedwater accident.

It should be noted that a single protection system failure that potentially could cause a control system reaction is eliminated by the DCS (Distributed Control System) using a Median Signal Selection (MSS) function. The system checks the quality of the instrument signal inputs and if all are of a good quality, the median signal is then selected for control. Should one of the signal inputs fail, the remaining signals are then averaged to provide the control function. The prime reason for the MSS feature is to prevent a failed protection system instrument channel from causing a disturbance in the feedwater control system requiring subsequent protective system action. All three narrow range steam generator water level channels for each steam generator, which also provide a reactor protection system reactor trip, are applied to the DCS MSS circuitry for feedwater control for its respective feedwater regulating valve. Upon a failure of one steam generator level signal, the remaining level signals for that generator are averaged in the DCS for its feedwater regulating valve control. Since no adverse control system action may now result from a single failed protection instrument channel, a second random protection system failure (as would otherwise be required by IEEE 279-1971) need not be considered.

7.2.2.4 Additional Postulated Accidents Loss of plant auxiliary control air or loss of component cooling water is discussed in Paragraph 7.3.2.3.

Load rejection and turbine trip are discussed in further detail in Section 7.7.

The control interlocks, called rod stops, that are provided to prevent abnormal power conditions which could result from excessive control rod withdrawal are discussed in 7.7.1.4.1 and listed on Table 7.7.1-1. Excessively high power operation (which is prevented by blocking of automatic rod withdrawal), if allowed to continue, might lead to a safety limit (as given in the Technical Specifications) being reached. Before such a limit is reached, protection will be available from the Reactor Trip System. At the power levels of the rod block setpoints, safety limits have not been reached; and therefore these rod withdrawal stops do not come under the scope of safety related systems, and are considered as control systems.

$7-2.doc 7.2-27

SQN-22 7.2.3 Tests and Inspections The Reactor Trip System meets the testing requirements of Reference 9. The testability of the system is discussed in 7.2.2.2.3. The test intervals are specified in the Technical Specifications. Written test procedures and documentation, conforming to the requirements of Reference 9, are available for audit by responsible personnel.

Reference 15 documents a methodology to be used to justify revisions to the technical specifications.

The methodology consists of the deterministic and numerical evaluation of the effects of particular technical specification changes with consideration given to such things as safety, equipment requirements, human factors and operational impacts. The technical specification revisions evaluated were increased test and maintenance times, less frequent surveillance and testing in bypass.

7.2.3.1 Inservice Tests and Inspections Periodic surveillance of the Reactor Trip System is performed to ensure proper protective action. This surveillance consists of channel checks, channel calibrations, channel functional testing, and response time testing which are summarized as follows:

1. Channel Checks A channel check consists of a qualitative determination of acceptability by observation of channel behavior during operation. It includes comparison of the channel indication and/or status indications and/or status derived from independent channels measuring the same variable.

Failures such as blown instrument fuses, defective indicators, or faulted amplifiers which result in "upscale" or "downscale" indication can be easily recognized by simple observation of the functioning of the instrument or system. Furthermore, in many cases such failures are revealed by alarm or annunciator action, and a check supplements this type of surveillance.

2. Channel Calibration A channel calibration consists of adjustment of channel output such that it responds, within acceptable range and accuracy, to known values of the parameter which the channel measures.

Calibration encompasses the entire channel including the sensor, alarm and/or trip function, and includes the channel functional test discussed below. Thus, the calibration ensures the acquisition and presentation of accurate information,

3. Channel Functional Test A channel functional test consists of:

a. Analog channels - the injection of a simulated signal into the channel as close to the sensor as practicable to verify operability including alarm and/or trip functions.

b. Bistable channels - the injection of a simulated signal into the sensor to verify operability including alarm and/or trip functions.

c. Digital channels - the injection of a simulated signal into the channel as close to the sensor input to the process racks as practicable to verify operability including alarm and/or trip functions.

4. Response Time Test A response time verification demonstrates that the protective function associated with each applicable channel is completed within the required time limit. The response time verification may consist of any series of sequential, overlapping, or total channel measurements such that the total channel response time is verified to be within the acceptable limits (Table 7.2.1-5).

$7-2.doc 7.2-28

SQN-16 The minimum frequencies for the surveillance items listed above are defined in the plant technical specifications.

As a result of TS Change No. 99-08 and WCAP-13632 R1, the following requirements must be applied in order to eliminate sensor Response Time Test.

1. Pressure sensor response times must be verified by performance of an appropriate response time test prior to placing a new sensor in to operational service and reverified following maintenance that may adversely affect sensor response time.

2. Pressure sensors (transmitters and switches) utilizing capillary tubes must be subjected to response time testing after initial installation and following any maintenance or modification activity that could damage the transmitter capillary tubes.

3. Pressure transmitters equipped with variable damping capability in reactor trip system or engineered safety feature actuation system response time applications, which required periodic response time test, must be subjected to response time testing after initial installation or following any maintenance or modification activity. Administrative controls may include use of pressure transmitters that are factory set and hermetically sealed to prohibit tampering or in situ application of a tamper seal (or sealant) on the potentiometer to secure and give visual indication of the potentiometer position.

4. Periodic drift monitoring will be performed for all Model 1151, 1152, 1153, and 1154 Rosemount pressure and differential pressure transmitters for which periodic response time testing is required, in accordance with guidance contained in Rosemount Technical Bulletin No. 4 and will continue to remain in full compliance with any prior commitments to Bulletin 90-01, Supplement 1, "Loss of Fill-Oil in Transmitters Manufactured by Rosemount."

7.2.3.2 Periodic Testing of the Nuclear Instrumentation System The following periodic tests of the Nuclear Instrumentation System are performed:

1. Testing at plant shutdown

a. Source range testing

b. Intermediate range testing

c. Power range testing

2. Testing between P-6 and P-10 permissive power levels

a. Intermediate range testing

b. Power range testing

3. Testing above P-10 permissive power level

a. Intermediate range testing

b. Power range testing Any deviations noted during the performance of these tests are investigated and corrected in accordance with the established calibration and trouble shooting procedures provided in the manufacturer's technical manual for the Nuclear Instrumentation System. Control and protection trip settings are indicated in the plant Technical Specifications and the Precautions, Limitations and Setpoints documents.

$7-2.doc 7.2-29

SQN-23 7.2.3.3 Periodic Testing of the Process Channels of the Protection Circuits The following periodic tests of the process channels of the protection circuits are performed:

1. Tavg and AT protection channel testing

2. Pressurizer pressure protection channels

3. Pressurizer level protection channels

4. Environmental Allowance Modifier and Trip Time Delay Protection Channels

5. Steam generator level protection channels

6. Reactor coolant flow protection channels

7. Impulse chamber pressure channels The following conditions are incorporated into the procedures for these tests:

1. These tests may be performed at the required frequencies and for the required operational modes as defined in the plant technical specifications.

2. Before starting any of these tests with the plant at power, all redundant reactor trip channels associated with the function to be tested must be in the normal (untripped) mode in order to avoid spurious trips. In accordance with the provisions of the plant technical specifications, certain inoperable channels may be placed in the bypassed mode to accommodate testing of the remaining channels.

3. Setpoints are verified.

Median Signal Selector Testing The median signal selectors (MSS) that are used for feedwater control exist as software modules or blocks in the Feedwater Distributed Control System (DCS). Prior to maintenance or testing of an individual steam generator level channel, the MSS function can be validated that it is working properly.

The signals that are applied to the MSS can be compared to the resultant output by reviewing the various signal values in the DCS. The MSS function will then allow testing or maintenance of individual steam generator level channels while at power without causing a feedwater control system disturbance as long as the other two channels are functioning properly and their channels are not tripped or bypassed. The MSS would simply ignore the channel under test.

The DCS has the option to manually remove a channel to be tested from providing input into the DCS control, forcing the DCS logic to ignore the channel to be tested. If two input channels of the same parameter are removed for maintenance at the same time, the DCS will cause the control affected by those signals to shift to manual and initiate an alarm. If the DCS detects a hardware problem with two channels of the same parameter at the same time, the associated control is switched to manual, initiating an alarm to warn the operators.

$7-2.doc 7.2-30

SQN-20 Since the amount of shutdown reactivity required for the design shutdown margin following a reactor trip increases with increasing power, the allowable rod insertion limits must be decreased (the rods must be withdrawn further) with increasing power. Two parameters which are proportional to power are used as inputs to the insertion monitor. These are the AT between the hot leg and the cold leg, which is a direct function of reactor power, and Tavg, which is programmed as a function of power. The rod insertion monitor uses parameters for each control rod bank as follows:

ZLL = A (AT)a,,,t + B(Tag )a,,ct + C Where ZLL = Maximum permissible insertion limit for affected control bank (AT) auct = Highest AT of all loops (Tavg) auct Highest Tavg of all loops A,B,C = Constants chosen to maintain ZLL > actual limit based on physics calculations The control rod bank demand position (Z) is compared to ZLL as follows:

If Z - ZLL < D, a low alarm is actuated If Z - ZLL < E, a low - low alarms is actuated Since the highest values of Tavg and AT are chosen by auctioneering, a conservatively high representation of power is used in the insertion limit calculation.

Actuation of the low alarm alerts the operator of an approach to a reduced shutdown margin situation.

Administrative procedures require the operator to add boron through the Chemical and Volume Control System. Actuation of the low-low alarm requires the operator to initiate emergency boration procedures. The value for "E" is chosen such that the low-low alarm would normally be actuated before the insertion limit is reached. The value for "D" is chosen to allow the operator to follow normal boration procedures. Figure 7.7.1-2 shows a block diagram representation of the control rod bank insertion monitor. The monitor is shown in more detail on the functional diagrams shown in Figure 7.2.1-1, Sheet 9. In addition to the rod insertion monitor for the control banks, an alarm system is provided to warn the operator if any shutdown rod cluster control assembly leaves the fully withdrawn position.

Rod insertion limits are established by:

1. Establishing the allowed rod reactivity insertion at full power consistent with the purposes given above.

2. Establishing the differential reactivity worth of the control rods when moved in normal sequence.

3. Establishing the change in reactivity with power level by relating power level to rod position.

4. Linearizing the resultant limit curve. All key nuclear parameters in this procedure are measured as part of the initial and periodic physics testing program.

$7-7.doc 7.7-7

SQN-23 Any unexpected change in the position of the control bank under automatic control, or a change in coolant temperature under manual control, provides a direct and immediate indication of a change in the reactivity status of the reactor. In addition, samples are taken periodically of coolant boron concentration. Variations in concentration during core life provide an additional check on the reactivity status of the reactor, including core depletion.

7.7.1.3.4 Rod Deviation Alarm The demanded and measured rod position signals are displayed on the control board. They are also monitored by the plant computer which provides an audible alarm whenever an individual rod position signal deviates from the other rods in the bank by a preset limit. The alarm is set in accordance with plant technical specifications.

Figure 7.7.1-3 is a block diagram of the rod deviation comparator and alarm system.

7.7.1.3.5 Rod Bottom Alarm A rod bottom signal for the full-length rods bistable in the analog RPIS as described in Reference 4 generates the "ROD BOTTOM ROD DROP" alarm.

7.7.1.4 Plant Control System Interlocks The listing of the Plant Control System Interlocks, along with the description of their derivations and functions, is presented in Table 7.7.1-1. It is noted that the designation numbers for these interlocks are preceded by "C". The development of these logic functions is shown in the functional diagrams (Figure 7.2.1-1, Sheets 9 to 16).

7.7.1.4.1 Rod Stops Rod stops are provided to prevent abnormal power conditions which could result from excessive control rod withdrawal initiated by either a control system malfunction or operator violation of administrative procedures.

Rod stops are the C 1, C2 , C 3, C 4, and C 5 control interlocks identified in Table 7.7.1-1. The C 3 rod stop derived from over-temperature AT and the C 4 rod stop, derived from overpower AT are also used for turbine runback, which is discussed below.

7.7.1.4.2 Automatic Turbine Load Runback Automatic turbine load runback is initiated by an approach to an overpower or overtemperature condition. This will prevent high power operation that might lead to an undesirable condition which, if reached, will be protected by reactor trip.

Turbine load reduction is initiated by either an overtemperature or overpower AT signal. Two out of four coincidence logic is used.

Inhibit relays are included in the C 3 and C 4 interlock control circuits to prevent turbine runback in the event of a loss of 120V AC Vital Power to the Overtemperature Delta T or Overpower Delta T separation relays.

S7-7.doc 7.7-8

SQN-23 A rod stop and turbine runback are initiated when AT > ATrod stop for both the overtemperature and the overpower condition.

For either condition in general ATrod stop = ATsetpoint -Bp where Bp= a setpoint bias where AT setpoint refers to the overtemperature AT reactor trip value and the overpower AT reactor trip value for the two conditions.

The turbine runback is repeated until AT is equal to or less than ATrod stop.

This function serves to maintain an essentially constant margin to trip.

7.7.1.5 Pressurizer Pressure Control The Reactor Coolant System pressure is controlled by using either the heaters (in the water region) or the spray (in the steam region of the pressurizer) plus steam relief for large transients. The electrical immersion heaters are located near the bottom of the pressurizer. A portion of the heater group is proportionally controlled to correct small pressure variations. These variations are due to heat losses, including heat losses due to a small continuous spray. The remaining (backup) heaters are turned on when the pressurizer pressure-controlled signal demands approximately 100 percent proportional heater power.

The spray nozzles are located on the top of the pressurizer. Spray is initiated when the pressure-controlled spray demand signal is above a given setpoint. The spray rate increases proportionally with increasing spray demand signal until it reaches a maximum value.

Steam condensed by the spray reduces the pressurizer pressure. A small continuous spray is normally maintained to reduce thermal stresses and thermal shock and to help maintain uniform water chemistry and temperature in the pressurizer.

Power relief valves limit system pressure for large positive pressure transients. In the event of a large load reduction, not exceeding the design plant load rejection capability, the pressurizer power-operated relief valves might be actuated for the most adverse conditions, e.g., the most negative Doppler coefficient, and the minimum incremental rod worth. The relief capacity of the power-operated relief valves is sized large enough to limit the system pressure to prevent actuation of high pressure reactor trip for the above condition. See Figure 7.2.1-1 sheet 11.

7.7.1.6 Pressurizer Water Level Control The pressurizer operates by maintaining a steam cushion over the reactor coolant. As the density of the reactor coolant changes due to changes in reactor coolant temperature, the steam water interface moves to absorb the variations with relatively small pressure disturbances.

$7-7.doc 7.7-9

SQN-23 The water inventory in the Reactor Coolant System is maintained by the Chemical and Volume Control System. During normal plant operation, the charging flow varies to produce the flow demanded by the pressurizer water level controller. The pressurizer water level is programmed as a function of coolant average temperature, with the highest average temperature being used.

The pressurizer water level decreases as the load is reduced from full load. This is a result of coolant contraction following programmed coolant temperature reduction from full power to low power. The programmed level is designed to match as nearly as possible the level changes resulting from the coolant temperature changes. A block diagram of the Pressurizer Water Level Control System is shown on Figure 7.2.1-1 sheet 11.

To permit manual control of pressurizer water level during startup and shutdown operations, the charging flow can be manually regulated from the main control room.

7.7.1.7 Steam Generator Water Level Control Each steam generator is equipped with a three-element feedwater flow control system which maintains a programmed water level which is a function of turbine load. The three-element Feedwater Control (FWC) System regulates the feedwater valve by continuously comparing the feedwater flow signal, the water level signal, the programmed level, and the pressure compensated steam flow signal.

The steam generator water level signal provided to the feedwater control system is derived from a median signal selector in the Feedwater DCS (Distributed Control System) which accepts the three narrow range level signal inputs for each steam generator and selects the median signal. Upon failure of one level channel, the average of the remaining two is used for control.

For the feedwater flow input signals, the two feedwater flow channels for each feedwater line are used to develop an average to control its respective feedwater regulating valve. The average of the other feedwater flows to the other steam generators is used as a "voter" so that should one of the feedwater flow channels fail, the voter signal would cause the control system to select the remaining channel that is closest to the voter signal value for continued automatic control. The system will alarm indicating the channel had failed. The voter signal only helps in determining the signal health between the two individual feedwater flow channels for a particular steam generator and is not the control signal.

For the steam flow input signals, the two steam flow channels for each steam line are used to develop an average steam flow signal to control its respective feedwater control valve. The average of the other steam generator's feedwater flows (the same "voter" signal used for FW flows describe above) is also used as a voter so that should one steam flow channel signal fail outside a predetermined limit, that signal quality is set to BAD, and the remaining steam flow channel alone would be used in the FW regulating valve control. An alarm would annunciate indicating that the steam flow channel had failed.

The steam flow voter is not used as the controlling signal.

In the event that both feedwater flow signals or both steam flow signals from one steam generator fail while at power, three element flow control is no longer available for that steam generator FW flow control valve. The DCS will sense that either the validated feedwater flow or validated steam flow control signals have failed, and will cause that feedwater regulating valve to transfer control to single

$7-7.doc 7.7-10

SQN-23 8.0 ELECTRIC POWER

8.1 INTRODUCTION

8.1.1 Utility Grid and Interconnections The Tennessee Valley Authority (TVA) is a corporation of the United States Government serving the State of Tennessee and parts of six other states in the southeast on the boundaries of Tennessee.

TVA is interconnected with electric power companies to the north, west, south, and east of its service area. As shown in Figure 8.1.1-1, the TVA grid consists of interconnected hydro plants, fossil-fueled plants, combustion turbine plants, and nuclear plants supplying electric energy over a transmission system consisting of various voltages up to 500-kV.

The Sequoyah Nuclear Plant is located 18 miles northeast of Chattanooga, Tennessee, on the west bank of the Tennessee River, six miles east of Soddy-Daisy, Tennessee. The plant is connected into a strong transmission grid supplying large load centers. One of the two nuclear units is connected to the 500-kV transmission system and one is connected to the 161-kV transmission system. The two systems are interconnected at Sequoyah through a 1200 MVA, 500-161-kV transformer bank.

8.1.2 Plant Electrical Power System The plant electric power system consists of the main generators, the unit station service transformers, the common station service transformers, the diesel generators, the batteries, and the electric distribution system as shown on Figures 8.1.2-1 and 8.1.2-2. The main generators supply electrical power through isolated-phase buses to the main step-up transformers. During normal operation, startup, and shutdown, auxiliary power is supplied from the 161-kV system through the common station service transformers. The standby onsite power is supplied by four diesel generators. Station Auxiliary Power may alternately be taken from the unit station service transformers during certain special analyzed cases.

The safety objective for the power system is to furnish adequate electric -power to ensure that safety loads function in conformance with design criteria and bases.

The safety objective has been accomplished by: (1) establishing design criteria and bases that conform to regulatory documents and accepted design practice, and (2) implementation of these criteria and bases in a manner that assures a system design and a constructed plant which satisfies safety requirements. The applicable documents governing the design are shown in Subsection 8.1.5.

Figure 8.1.2-1 depicts the plant auxiliary power distribution system that provides AC power to the two nuclear power units, the two independent preferred (offsite) power circuits, and four diesel-generator standby (onsite) power sources and distributes it to both safety-related and nonsafety-related loads in the plant. The two preferred circuits have access to the TVA transmission network which in turn has multiple interties with other transmission networks.

S8-1 .doc 8.1-1

SQN The major safety-related loads for each nuclear unit are divided electrically into two redundant load groups. Each redundant load group of each unit has access to a standby (onsite) source and to each of the two preferred (offsite) sources. Due to a number of shared systems, two (must be the same train) out of four diesels and load groups are required to provide all safety and 13 functions for each unit. The offsite and onsite power systems are described in Sections 8.2 8.3.

Figure 8.1.2-2 depicts the vital AC and DC control power distribution systems that connect four 1 25V batteries, four battery chargers and eight 120V AC inverters with their respective safety-related loads. The 125V DC distribution system is a safety-related system which receives power from four independent battery chargers and four 125V DC batteries and distributes it to safety-related (and non-safety related) loads of both units. The 120V AC distribution system is also a safety-related system which receives power from eight independent inverters and distributes it to the safety-related (and non-safety related) loads of both units. These systems 13 are described in Sections 8.2 and 8.3.

8.1.3 Safety-Related Loads Major loads requiring electric power to perform their safety function are listed in Table 8.1.2-1.

8.1.4 Design Bases The design bases for the electric power system are listed below.

Offsite (Preferred) Power System (1) Each of the two offsite power circuits supplying electric power from the transmission network to the onsite electric distribution system shall have sufficient capability and capacity, and be available in sufficient time following a loss of all onsite alternating current power and the other offsite electric power circuit, to assure that specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded. One of the two circuits shall be available to supply the plant safety loads within a few seconds following a loss-of-coolant accident to assure that core cooling, 13 containment integrity, and other vital safety functions are maintained.

(2) The two offsite power circuits (not including the switchyard) shall be designed and located to be physically independent so as to minimize, to the extent practical, the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions.

Onsite (Standby) Power Systems (1) The onsite power systems shall be designed to provide sufficient capacity to assure that acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences and that the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents in one unit and to safely shutdown the other unit.

S8-1 .doc 8.1-2

SQN-23 8.2 OFFSITE POWER SYSTEM 8.2.1 Transmission Network Description The Sequoyah Nuclear Plant is connected into a strong existing transmission network supplying large load centers. One unit is connected into the 500-kV transmission network and the other unit is connected into the 161-kV transmission system. The two systems are interconnected at Sequoyah through a 1200-MVA, 500-161-kV intertie transformer bank. Preferred electric power (normal power supply) to the emergency buses and to start up and shut down the generating units at the Sequoyah Nuclear Plant is supplied by two physically and electrically independent circuits from the Sequoyah 161 -kV switchyard through three separate transformers to the onsite electrical distribution system, (refer to Figure 8.2.1-1).

Five 500-kV transmission lines connect one generating unit into the 500-kV system. Except in the vicinity of Sequoyah Nuclear Plant, the lines are on rights of way which are sufficiently wide to preclude the likelihood of failure of one line causing failure of another.

The 161-kV switchyard is the terminus for the second nuclear unit, the 500-kV intertie transformer bank and eight 161-kV transmission lines. Four 161-kV transmission lines terminate on each bus section. Two fuseless 84 MVAR 161-kV capacitor banks are tied to the 161-kV switchyard through double bus-tie breakers. Each bank is independently switched. These capacitors provide reactive voltage support for the 161-kV offsite system. Of the eight 161-kV transmission lines emanating from the Sequoyah 161-kV switchyard, one connects to TVA's Chickamauga Hydro Plant; one connects to TVA's Watts Bar Hydro Plant; and six connect to 161-kV substations that are an integral part of the 161-kV transmission network. Nine hydro plants, one fossil-fueled plant, and one nuclear plant are located within a sixty-mile radius from the Sequoyah Nuclear Plant. These plants are strongly connected through the 161-kV and 500-kV transmission networks to Sequoyah and have an installed capacity of more than 4000 MVA.

The transmission line structures of the 161-kV and 500-kV systems are designed to withstand medium loading conditions as specified in The Bureau of Standards Handbook No. 10 (National Electrical Safety Code Part 2).

To reduce the total number of acres of easement right of way required for the line connections to the Sequoyah Nuclear Plant, a number of the 161-kV lines are constructed on double circuit towers and, also, on common wide right of way. The 161-kV switchyard is designed with two main bus sections and is arranged so that the supply to the onsite power system, as well as the connections to the generator and 500-161-kV intertie transformer bank is maintained to one bus section for a failure of the other section. Four of the 161-kV lines terminate on one bus section and connect to Charleston, East Cleveland, VW Chattanooga, and Moccasin 161-kV substations. The other four 161-kV transmission lines terminate on the other bus section and connect to Charleston and Concord 161-kV substations and Chickamauga and Watts Bar Hydro Plants.

S8-2.doc 8.2-1

SQN-21 To make the thirteen line connections into Sequoyah, a number of lines must cross each other. When lines of different voltages cross, the higher voltage line crosses over the lower voltage line. Crossings similar to these are common throughout the TVA service area.

The Bradley 500-kV Line crosses over the Sequoyah-Moccasin 161-kV Transmission Line. Assuming the 500-kV line falls at the crossover point, this will result in the loss of both the 500-kV and 161-kV lines. The four remaining 500-kV connections at Sequoyah and the seven remaining 161-kV connections will stay in service.

The Sequoyah-Watts Bar No. 2 500-kV Transmission Line crosses under the Widows Creek 500-kV Line, the Franklin 500-kV Line, and the Watts Bar No. 1 Line. If one of the three physically higher lines fall, this will result in the loss of two 500-kV lines. Three 500-kV connections and eight 161-kV connections will stay in service.

The 161-kV transmission line crossover at Sequoyah in the 161-kV transmission grid system consists of the Concord No. 1 line crossing under the following five connections from Sequoyah. They are Charleston No. 1, Charleston No. 2, Chickamauga No. 1, Watts Bar Hydro, and East Cleveland. Only two of the 161-kV transmission lines would be involved if either of the five aforementioned lines were to fall. Those lines remaining in service will be five 500-kV connections and six 161-kV connections.

The Tennessee Valley Region is located in a high thunderstorm frequency area and interruptions due to lightning do occur. Most interruptions are momentary in duration and have no significant effect on the operation of TVA's network of lines. The lightening performance for the transmission lines connected to the 161- and 500-kV switchyards at Sequoyah indicates that for the period January 1, 1994, through December 31, 1998, there were twenty-one 500-kV line interruptions and twenty 161-kV line interruptions attributed to lightening. Of these interruptions, six 500 kV and no 161-kV interruptions resulted in outages in excess of one minute.

Localized heavy conductor icing has occurred on some of TVA's transmission lines in years past.

TVA's lines are designed to withstand these heavy icing conditions and no mechanical failures have occurred due to icing of any of the lines being connected into Sequoyah.

Several of the existing transmission lines that will be connected into Sequoyah do traverse fairly rugged terrain. Construction across this type terrain is not unusual for TVA transmission lines.

Conductor spans in excess of 2,000 feet are fairly common and construction of spans of this magnitude are handled routinely. The longest spans which normally require the tallest transmission towers are river crossing spans. The 3,400 foot river crossing span on the Watts Bar-Sequoyah 500-kV lines is the longest span in the lines being connected into Sequoyah. The overhead ground wire in this span is marked with aircraft hazard markers and the transmission line towers are lighted for aeronautical protection.

TVA's transmission lines are designed and constructed to eliminate damaging conductor vibrations.

Conductor galloping is a phenomenon which normally occurs on lines constructed of small conductors during conductor icing conditions in conjunction with a continuous low velocity wind. Since TVA's higher voltage lines utilize larger conductors, galloping on them is extremely rare and is no threat to the safe operation of the lines being connected into Sequoyah.

8.2.1.1 Preferred Power System The intent of GDC 17 has been implemented in the design of the Preferred Power System by providing two physically and functionally independent circuits for energizing safety related load groups.

This section identifies these two circuits and describes the general provisions made to achieve functional independence between them. Paragraphs 8.2.1.2 through 8.2.1.4 describe measures taken to provide physical independence between them. The Preferred Power System

$8-2.doc 8.2-2

SQN can be identified by reference to Figures 8.1.2-1, 8.2.1-1, and 8.2.1-2. The Preferred Power System consists of: three 161-6.9-kV common station service transformers (CSSTR's) (A, B, and C); a 6.9-kv start board; four 6.9-kV start buses; eight 6.9-kV unit boards; four 6.9-kV 13 shutdown boards; and all overhead conductors, buses, cable, and distribution equipment that interconnect the CSSTR's with the 6.9-kV shutdown boards. The Preferred Power System is supplied power by way of the plant 161-kV switchyard.

Figures 8.1.2-1 and 8.2.1-1 indicate the functional arrangement of the two independent circuits which derive power from the 161-kV switchyard and deliver it to the individual 6.9-kV Unit Boards. Power is then routed by two independent circuits from the 6.9-kV Unit Boards to the 3 6.9-kV Shutdown Boards within each unit.

The components comprising the Preferred Power System have been arranged to provide sufficient independence (both physical and functional) to minimize the likelihood of simultaneous outage of both preferred circuits.

Functional independence has been achieved by providing separate control circuits, powered by separate DC sources. The single line diagrams of these non-safety related 250V DC Systems are included as Figures 8.2.1-3 and 8.2.1-4.

8.2.1.2 Transmission Lines, Switchyard, and Transformers The eight 161-kV and the five 500-kV lines connecting the plant with the TVA transmission network are indicated functionally on Figure 8.2.1-1. The onsite transmission line arrangement is shown on Figure 8.2.1-2 and the offsite transmission line routing in the vicinity of the switchyard is shown on Figure 8.2.1-5. These lines are routed to minimize the likelihood of their simultaneous failure.

The physical separation of the most widely spaced transmission lines at a point on a circle with a radius of one mile from the plant center exceeds 1/4 mile as shown on Figure 8.2.1-5, which 13 meets the separation requirement from Regulatory Guide 1.155 (NU-MARC 87-00).

Physical arrangement of the equipment is shown on Figure 8.2.1-2. Normally, total functional independence is not maintained in the switchyard itself, due to the fact that all bus sections are electrically connected together. However, in the event of an electrical fault, electrical separation is established in a few cycles by circuit breaker operation. The fault isolation and bus transfer scheme is designed to permit automatic fault isolation while still maintaining multiple connections from the 161-kV switchyard to the grid. Thus, both independent circuits providing preferred power will remain energized. Switchyard control and functional independence is further discussed in Paragraph 8.2.1.5.

It is also possible to isolate the incoming circuit associated with a CSSTR from the other j '3 incoming transmission lines. This makes it possible to functionally isolate the transformer on a single hydro unit either at the Watts Bar or Chickamauga Hydro Station, which itself has been isolated from the grid.

Location of the CSSTRs and CCW cooling tower transformers is shown on Figure 8.2.1-2.

Physical separation between CSSTRs A, B, and C is a minimum of 65 feet, centerline-to-centerline and 35 feet between closest parts. No missile barrier is required between the CSSTRs to protect one transformer in the event of a failure of the other transformer. The j 3 physical arrangement is based on TVA's experience and the analysis of previous failures on transformers with similar construction. A fire is the major concern relative to a transformer failure. In addition to the physical separation, automatic fire protection has been provided as S8-2.doc 8.2-3

SQN-23 described in the Fire Protection Report (see 9.5.1). Also, the yard area is covered with a thick layer of loose limestone gravel which is designed to limit the spread of transformer oil should a transformer tank rupture. Therefore, these three design features provide the necessary protection to minimize to the extent practical the likelihood of the simultaneous failure of the Common Station Service Transformers under operating and postulated accident conditions. The primary voltage is 161-kV, rated 33/44/55MVA, OA/FA/FOA at 55°C.1 The secondary voltage is 6.9-kV, and each is rated 24/32/40MVA, OA/FA/FOA at 550C. CSSTR's A, B, and C are equipped with automatic high speed load tap changers.

1 Cooling modes associated with different ratings are as follows:

OA - Oil to air cooling FA - Oil to forced air cooling FOA - Forced oil to forced air cooling Common Station Service Transformer D and CCW Cooling Tower Transformers A and B are also connected to the 161-kV switchyard. These transformers supply power to non-essential non-safety-related balance-of-plant loads that provide no safety-related functions. The rest of this chapter discusses only the A, B, and C CSSTR's unless specifically noted otherwise.

8.2.1.3 Arrangement of the Start Buses, Start Board, and Unit Boards From the low-voltage side of each common station service transformer, two 6.9-kV buses supply the 6.9-kV start board. The 6.9-kV buses from CSSTR C are underground cable. The 6.9-kV buses from CSSTRs A and B maintain 65 feet center-to-centerline separation to their convergence at the start board. These buses then connect to the start bus normal or alternate breakers. The design of the start board conforms to ANSI C 37.20 "Standard for Switchgear Assemblies Including Metal-Enclosed Bus," (including Section 20-6.2.2 of this standard which defines the requirements for barriers) and is classified as outdoor metal-clad switchgear. The breakers at the 6.9-kV start board are electrically operated, horizontal drawout type, with stored energy mechanisms. The breakers supply the start buses which feeds the 6.9-kV Unit Boards and 6.9-kV Common Boards. These circuit breakers have a continuous rating of 3,750 amperes, an insulation system for 13.8-kV, and interrupting rating of 50,000 amperes, and a momentary rating of 80,000 amperes. The circuit breakers are utilized at 6.9-kV and there is sufficient margin between the application and the rating of these circuit breakers.

Each start bus is enclosed by a grounded bus housing. The start buses consist of two insulated 6 x 1/2 inch aluminum channels per phase for 4000A busduct section; two insulated 4 x 3/4 inch aluminum bars per phase for 3000A busduct sections; two insulated 4 inch by 3/4 inch aluminum bars per phase for the 2000A busduct section, and one insulated 4 inch by 1/4 inch copper bar per phase for the 1200A busduct section; and two 8 inch by 1/2 inch aluminum bars per phase for part of 4000A buses 1A, 1B, and 2B. The outdoor portion of 2A and 2B are one insulated 10 x 1/2 inch copper per phase.

4000A buses C1 and C2 (from CSSTR C to the start board) consist of 9-750MCM per phase underground cables. Each three-phase circuit is separately enclosed in a metal bus housing. The separation with two intervening grounded metal barriers, makes the start buses independent with respect to fault propagation. Protection from natural phenomena, other than GDC 2 events, vehicle collision, missile impact, and falling structures is best provided by minimizing the length of run and careful routing. The position of the bus relative to the turbine building wall, as shown in Figure 8.2.1-2, provides protection for almost 180 degrees from all such non-GDC 2 hazards. The turbine building structure is designed to withstand tornado wind loadings which are greater than that of the offsite power system.

$8-2.doc 8.2-4

SQN-23 There is no normal vehicular access (except for maintenance) to the vicinity of the start buses. The short length of the buses provides a minimum cross-section for missile impact, while the inherent strength of the bus housing, and supporting structure assures a high probability of surviving a non-GDC 2 missile impact in the unlikely event that it would occur.

The 6.9-kV start buses enter the turbine building spaced approximately 10 feet centerline-to-centerline and continue on this spacing across the building.

The 6.9-kV unit boards are indoor, metal-clad switchgear with electrically operated, horizontal drawout breakers with stored energy mechanisms and are mounted on floor El. 701'-2" between the two start buses. The 6.9-kV common boards are the same type switchgear as the 6.9-kV unit boards and are mounted on floor El. 732'-0" above the two start buses. The start buses are tapped at appropriate places to enter the unit boards supply breakers through the tops of the boards and the common boards supply breakers through the bottoms of the boards. The normal and alternate supply breakers for each board are separated along the length of the board by several load feeder breakers.

The four unit station service transformers are located in the transformer yard, west of the turbine building and directly under the delta section of the isolated-phase main generator bus. The unit station service buses are of indoor type construction. After entering the turbine building, the unit station service buses are routed to the appropriate supply breakers in the 6.9-kV unit and 6.9-kV common boards, entering through the tops of the 6.9-kV unit boards and the bottoms of the 6.9-kV common boards.

All of the station service buses (unit and common) are nonventilated, nonsegregated, metal-clad dripproof construction referenced in ANSI C37.20. In addition, the outdoor portions are weatherproof and equipped with 120V 1-phase heaters to prevent condensation inside the bus conductor insulation or supporting insulators. All buses are provided with gas-resistant seals at entry to a piece of switchgear. At the penetration of an outside building wall, the buses are provided with a 2 hour2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> rated firestop.

It is the TVA position that the offsite power system is not required to withstand the design basis phenomena of GDC 2. An onsite electrical power system is provided, consistent with the requirement of GDC 17, for this purpose.

8.2.1.4 Arrangement of Switchyard Control and Relaying Panels Figure 8.2.1-6 shows the physical arrangement of the relay and main control rooms where the relay, control, and 250V dc control power distribution panels are located.

The protective and auxiliary relays for CSSTR's A, B, and C are parts of two separate groups of duplex relay boards located in the relay room. The switchboard wire used for wiring in the relay and control boards is insulated with cross-linked polyethylene.

The control switches, indicating lights, and indicating instruments associated with the two offsite power circuits are located on panels 5, 4, and 2 of the control board in the. main control room. Circuit A controls are on panel 5, circuit C on panel 4, and circuit B on panel 2. The control board panels are of unitary construction with full side panels and rear doors.

S8-2.doc 8.2-5

SQN-21 The control switches for the 161-kV power circuit breakers and motor-operated disconnect switches are mounted together with the corresponding indicating lights on the benchboard part of each panel.

The control switches for the 6900V start bus feeders and associated indicating meters are located above the switches on the vertical part of the board.

Non-safety related control power for power circuit breakers and associated protective relays is provided from the 250V DC power systems as shown in Figures 8.2.1-3 and 8.2.1-4 via circuit breakers on panels 6, 7, and 8 of the control room DC distribution board. Physical isolation of control power supplies for control of the two preferred power circuits is achieved by metal barriers between adjacent panels.

Two separate 250V DC buses are provided in these three panels, bus 1 in panels 7 and 8 and bus 2 in panel 6. Each bus can be fed from one of the two 250V battery boards through manual, mechanically interlocked, nonautomatic circuit interrupters. Normally, bus 1 is fed from battery board 1 and bus 2 from battery board 2. The power circuit breaker and associated relay control circuits are allocated to these two DC buses on the basis of switchyard connections. Thus, circuits related to the 161-kV buses 1 and 2, section 2, are fed from the DC bus 2, and those related to 161-kV buses 1 and 2, sections 3 and 4 (with the exception of power circuit breaker No. 924) are connected to DC bus 1.

This allocation of control circuits ensures that the control and relay circuits of the three CSSTR's are fed from two independent DC distribution buses and that failure of one DC bus cannot cause the loss of all CSSTR's (A, B, and C). Each circuit is protected by a circuit breaker and supervised by an amber indicating.light located on recording and instrument board panel No. 5. These indicating lights are grouped on the panel on the basis of the DC buses they are connected to, and their wiring is physically separated on the panel on the same basis.

A 480V AC distribution system provides the power required for the 161-kV motor-operated disconnect switches (MODs) and air compressors associated with each airblast 161-kV power circuit breaker.

ABB 161-kV SF6 breakers have spring charging motors instead of air compressors. These motors are normally powered from the 480V AC distribution system. On loss of the 480V AC normal supply the SF6 breakers automatically transfer to a 250V DC altemate supply. Two separate 6900V feeders from the 6.9-kV common boards supply four 6900V-480V transformers. The 480V distribution systems are ungrounded and provided with a ground indicating light. Each of the four distribution cabinets, located in the 161-kV switchyard, can be supplied from either of two transformers via a normal or an alternate feeder. The selection, at each cabinet, between the two feeders is by means of manually-operated, mechanically-interlocked, nonautomatic circuit interupters. The two 6900V feeders are so arranged and rated that each one can feed all four transformers if required. The allocation of individual loads to the distribution cabinets is based on the arrangement of 161-kV connections. Two cabinets, fed from different 6900V sources, supply loadsassociated with 161-kV bus 2, section 2, and bus 1, section 4.

The two other cabinets supply loads associated with 161-kV bus 1, section 2, and bus 2, section 4.

This corresponds to the allocation of the 250V DC control supplies described above. CSSTR A & B have a further division of load arrangement with respect to the two 161-kV circuit breakers (air blast types) and motor operated disconnect switches. The air compressor for each air-blast breaker is supplied power from a different AC distribution cabinet. The two motor-operated disconnect switches associated with each of the two power circuit breakers are also connected to separate AC supplies.

In addition to the indicating lamps and instruments, the control room operator is provided with an annunciation system which, for the switchyard and the common station service transformers, monitors the following:

Operation of any 161 -kV power circuit breaker.

Abnormal air pressure in the LP System for each airblast 161-kV power circuit breaker.

Abnormal air pressure in the HP System for each airblast 161-kV power circuit breaker.

$8-2.doc 8.2-6

SQN fail to trip within the time setting of its timing relay, the associated breaker failure trip relay will trip and lock out both breakers in that particular switchyard bay. The relay will also trip and lock out all breakers connected to the bus associated with the failed breaker. In addition, the breaker failure relays protecting generator 2 power circuit breakers, when operated, will trip turbine steam valves, exciter field breakers, and the associated 6.9-kV breakers on unit station service transformers. Any of the breaker failure relays associated with the intertie transformer bank 5 PCB's will trip and lock out all PCB's connecting it to both the 161-kV and 500-kV switchyards.

The five power transformers (CSSTR's A, B, and C, main transformer bank No. 2, and intertie transformer bank No. 5) are protected as follows: 13 with harmonic restraint, a sudden Each CSSTR is protected by a percentage differential relay pressure relay, and a neutral overcurrent relay in the 6.9-kV winding neutral.

The operation of the transformer protection relays will trip and lock out the power circuit breakers connecting it to the switchyard, trip and lock out associated 6.9-kV circuit breakers, and starts a high-pressure sprinkler system to prevent or extinguish any possible fire.

The intertie transformer bank No. 5 is protected by a percentage differential relay with harmonic restraint, nondirectional, torque-controlled overcurrent relays and sudden pressure relays. The sudden pressure relays on this transformer will operate to isolate the transformer from both the 161-kV and 500-kV switchyards and the transformer high-pressure fire protection sprinkler system will be started by thermal devices or a sudden pressure device on the transformer.

The main transformer bank No. 2 is protected by differential and sudden pressure relays whose operation trip and lock out the 161-kV breakers connecting it to the switchyard, and the associated 6.9-kV breakers on unit station service transformers and trip the turbine steam valves and exciter field breaker.

The supply to the CSSTR's possesses a high degree of reliability even under electrical fault conditions. The following discussion describes the sequence of events following postulated faults:

13

1. Transmission line fault.

If the instantaneous element of the line protective relays is actuated the line breaker is tripped and a high speed reclosure occurs. If after the high speed reclosure the fault has not cleared, the breaker will trip again and a standard speed (synchronism check-voltage check) reclosure occurs. In the majority of the cases these reclosures will restore the line back to service. However, a trip after this will lock out the breaker isolating the faulted line. There is no appreciable disturbance on the feeders to the CSSTR's. 1 13

2. Transmission line fault and failure of the line circuit breaker to clear the fault.

The corresponding main bus breakup relay is automatically initiated, starting a timer. If the fault is not cleared within the time setting of the timer, all circuit breakers connected to that bus will be tripped and locked out. With normal position of circuit breakers and MOD's described previously, all CSSTR's (A, B, and C) continue to receive power without interruption.

3. Main bus fault.

This type of fault is detected by the bus differential protection. When initiated, it trips and locks out the circuit breakers connected to the faulted bus. The effects of this action are similar to those described under 2 above.

S8-2.doc 8.2-9

SQN-23

4. Transformer or transformer feeder faults.

These faults cause tripping of all the transformer circuit breakers on the high and low voltage side of the transformer. In addition, the trip relay initiates the transformer fire protection sprinkler and starts the fire pump if the fault is in the transformer.

5. Common transformer or transformer feeder fault and failure of one HV circuit breaker to operate properly.

These events cause the operation of protection described under 4 above, followed by the operation of the breaker failure relay which trips all breakers connected to the bus at the time of failure. The event results in the loss of one transformer; the other transformers continue to receive power from their main or alternate bus.

The allocation of the 250V DC control power circuits for relays, circuit breaker, and MOD operation (the description of which is included in the preceding section) is coordinated with the switching requirements of the zig zag main and transfer bus arrangement and the requirement for the optimum availability of the CSSTR's.

8.2.1.6 6.9-kV Start Board Control and Relayinq The secondaries of the CSSTRs A, B, and C feed into a 6.9-kV start board containing eight circuit breakers. These breakers are the normal and alternate supply breakers for the four start buses. Start buses 1A and 2A are normally fed from CSSTR A, and start buses 1B and 2B are normally fed from CSSTR C. Transfer to CSSTR B may be automatic or manual but transfer back to the normal source is manual only. There are two automatic transfers to CSSTR B from either CSSTR A or C. Fast transfer is initiated in the event a fault is sensed within the CSSTR, or other transformers supplied from the common source. The other automatic transfer is a slow bus transfer which is initiated by bus undervoltage on the normal feeder (< 70 percent of nominal). The transfer is delayed until the bus residual voltage has decayed to 30 percent of nominal and if the alternate feeder voltage is > 90 percent of nominal. Fast transfers are defined as < 6 cycle transfers. Both CSSTR A and C can transfer their loads to CSSTR B at the same time automatically for either a fault or undervoltage condition. Manual transfer of the 1A, 1B, 2A, and 2B start bus uses a "make before break" transfer scheme. The undervoltage condition is annunciated in the main control room (MCR).

Each of the four start buses has its own undervoltage detection scheme which will initiate a transfer to its alternate supply (CSSTR B). If an undervoltage transfer of only one start bus occurs then the start board breaker interlock scheme will prevent subsequent start bus transfers except from the same transformer. See Table 8.2.1-1 for complete description of board transfer schemes.

The 250V DC control power for the breakers feeding start bus 1A and 2A is supplied from a battery and battery distribution board separate from that of the breakers feeding start buses 1B and 2B.

The board is protected by overcurrent, ground overcurrent, and differential current protective relays.

Manual control of the circuit breakers is provided on the electrical control board in the main control room. The operator has instrumentation showing the voltage on each of the two buses and current flowing in each of the four feeder breakers. The following annunciation is provided:

1. Start Bus Fan Failure

2. Start Bus Transfer

3. Start Bus Failure or Undervoltage S8-2.doc 8.2-10

SQN-23 Annunciation of No. 3 above is composed of bus differential relay operation, bus AC voltage failure, and control bus DC voltage failure.

Start bus 1A is the normal feeder to 6.9-kV unit boards IA and 1C. Start bus 1B is the normal feeder to 6.9-kV unit boards 1B and 1D. Start Bus 2A is the normal feeder to 6.9-kV common board A and 6.9-kV unit boards 2A and 2C. Start bus 2B is the normal feeder to 6.9-kV common board B and 6.9-kV unit boards 2B and 2D.

8.2.1.7 6.9-kV Unit Board Control and Relayinq The normal feeder to each 6.9-kV unit board is from one of the start buses. The alternate feeder for 6.9kV Unit Boards 2A and 2B is from 6.9kV Unit Board 1D. The alternate feeder for 6.9 kV Unit Boards 2C and 2D is from 6.9 kV Unit Board 1A.

Each 6.9-kV unit board can be selected for manual transfer between the normal and alternate supply breakers. Manual transfers are high speed (6 cycles or less), and can be made from the normal to the alternate supply or from the alternate to the normal supply. Automatic transfers can only be made from the alternate to the normal supply. Automatic transfers initiated by loss of voltage (less than 70 percent of nominal) on the unit board are delayed until the voltage decreases to 30 percent of normal while those initiated by reactor trip or turbine trip signals are high speed transfers (delayed 30 seconds). See Table 8.2.1-1 for complete description of board transfer schemes.

The boards are protected by overcurrent, ground overcurrent, and differential current protective relays.

Manual control of the two feeder breakers of each board is provided on the unit control board in the main control room. The operator has instrumentation that gives the voltage and frequency of each board and the current flowing in either of the two feeder breakers. The following annunciation is provided:

1. Unit Board Transfer

2. Unit Board Failure or Undervoltage Annunciation of No. 2 above is composed of board differential relay operation, board AC voltage failure, and control bus DC voltage failure.

The final link to the onsite (standby) power system (the 6.9-kV shutdown boards) is feeders from the unit boards. Unit boards 1B, lC, 2B, and 2C are the normal supplies to 6.9-kV shutdown boards 1A-A, 1B-B, 2A-A, and 2B-B, respectively, while unit boards 1A, 1D, 2A, and 2D are the alternate supplies respectively. These feeders are protected by overcurrent and ground overcurrent relays. All of these feeder breakers are normally closed with all transfers between the normal and alternate feeders occurring at the 6.9-kV shutdown board and are manual only.

8.2.1.8 Conformance with Standards This section discusses provisions included in the design of the offsite power system to achieve a system design in conformance with applicable requirements of GDC 17, Regulatory Guides 1.6 Rev.

0, and 1.32, Rev. 2.

The following requirements of Regulatory Guides 1.6 Rev. 0 and 1.32, Rev. 2, and GDC 17 are applicable:

Requlatory Guide 1.6 Regulatory Guide 1.6, Rev. 0 requires that "Each ac load group should have a connection to the preferred (offsite) power source. A preferred power source may serve redundant load groups."

S8-2.doc 8.2-11

SQN Regulatory Guide 1.32 Regulatory Guide 1.32, Rev. 2 states that "Criterion 17 delineates the design requirements regarding availability of power from the transmission network. Accordingly, a preferred design would include two immediate access circuits from the transmission network. An acceptable design would substitute a delayed access circuit for one of the immediate access circuits provided that availability of the delayed access circuit conforms to General Design Criterion 17."

Criterion 17 General Design Criterion 17 requires that:

(1) "the offsite power supply be of sufficient capacity and capability to assure, assuming the onsite (standby) power supply is not functioning, that (a) specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded as a result of anticipated operational occurrences.

and (b) the core is cooled and containment integrity and other vital functions are maintained in the event of postulated accidents."

(2) "electric power from the transmission network to the onsite electric distribution system shall be supplied by two physically independent circuits (not necessarily on separate rights of way) designed and located so as to minimize to the extent practical the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions.

A switchyard common to both circuits is permitted."

(3) each of the two circuits supplying electric power from the transmission network to the onsite electric distribution system "shall be designed to be available in sufficient time following a loss of all onsite alternating current power supplied and the other offsite electric power circuit, to assure that specified acceptable fuel design limits and design conditions of the reactor coolant pressure boundary are not exceeded."

(4) one of the two circuits supplying electric power from the transmission network to the onsite electric distribution system "shall be designed to be available within a few seconds following a loss-of-coolant accident to assure that core cooling, containment integrity, and other vital safety functions are maintained."

(5) "provisions shall be included to minimize the probability of losing electrical power from any of the remaining sources as a result of, or coincident with, the loss of power from the transmission network, or the loss of power from the onsite electrical power sources."

Each of the above requirements and the provisions included in the design to meet them is addressed in some form in the discussion which follows:

The discussion is arranged in two parts:

(1) Physical measures for achieving independence and physical measures taken to minimize the likelihood of failures of portions of the offsite power system inducing failure of the other power sources.

S8-2.doc 8.2-12

SON (2) Functional provisions for achieving adequate capacity, capability, and availability; functional measures taken to achieve independence; and functional measures taken to minimize the likelihood of failure of portions of the offsite power system inducing failure of other power sources.

Physical Measures The CSSTR's and buses are connected and arranged to provide two physically independent 113 offsite power circuits to the onsite distribution system. Any one of these can be used as the preferred power supply.

For physical description and characteristics of the common station service buses, see Section 8.2.1.3.

The above ground buses run on separate support structures and run approximately 40 feet before entering the start board: The underground cable buses are located in conduit and run approximately 250 feet before entering the start board. The above ground buses are provided with gas resistant seals at the entry to the switchgear. The start board consists of a normal feeder breaker and an alternate feeder breaker for each start bus which obtain their supply from separate buses and separate CSSTR's, thereby giving each start bus two possible and 13 independent sources of power. The normal supply breaker and the alternate supply breaker for each start bus are separated in the start board by two cubicles, therefore, preventing a fault in one breaker from causing damage to the alternate supply breaker.

From the feeder breakers of the 6.9-kV start board the four 6.9-kV unit start buses run as pairs (1A and 1B, 2A and 28), each pair on a common support structure parallel and adjacent to the south turbine building wall for approximately 55 feet to their penetration through the wall at elevation 717.0 and 719.6. Horizontal spacing of the start buses for this run is 4'-6 inches from centerline-to-centerline and 12 inches minimum between adjacent enclosure walls of the separate buses and minimum vertical spacing is 2'-6 inch centerline-to-centerline with 11-5/16 inches between adjacent enclosure walls of the separate buses. The conductors are fully insulated with flame-retardant material, bus supports are flame retardant, and the metal enclosures will prevent any arcing fault in one bus from damaging the other bus.

The start buses are tapped at appropriate places and routed to the appropriate supply breakers in 13 the 6.9-kV unit and 6.9-kV common boards. The normal supply breaker and alternate supply breaker for each board are separated along the length of the board by. several feeder breakers, thereby preventing a fault in one breaker from damaging the alternate supply breaker. All buses are provided with gas-resistant seals at entry to the switchgear.

The power from the unit boards is supplied to the shutdown boards by means of cables routed via separate cable trays and conduits to their respective boards. The minimum distance between trays carrying the normal and alternate cables to the redundant shutdown boards is approximately 30 feet, while the trays carrying normal and alternate supplies to the same shutdown board are at a minimum separation of 1 foot. Circuit breakers have been provided at each end of these cables so that even a simultaneous failure of the normal and alternate supply cables to one shutdown board will not effect the offsite power supply to the redundant board.

During the case of failure or fault of a CSSTR, the spare CSSTR is immediately available if not already providing distribution for the other CSSTR. Refer to Table 8.2.1-1 for transfer information.

$8-2 .doc 8.2-13

SQN-23 Functional Measures Regulatory Guide 1.6, Rev. 0 has been implemented by providing each redundant load group with a connection to each of the preferred source circuits. Figure 8.1.2-1 indicates that redundant load groups in each unit are normally fed from different preferred power source circuits. Figure 8.1.2-1 also indicates that alternate feeder alignments may result in feeding redundant load groups in each unit from a common preferred power source circuit. The two preferred power source circuits are shared between the two nuclear units.

Regulatory Guide 1.32, Rev. 2 has been implemented by providing an immediate and delayed access circuits to the transmission network. Figures 8.1.2-1 and 8.2.1-1 indicate the functional arrangement of these continuously-energized circuits.

The rest of the discussion deals mainly with the manner in which GDC 17 has been implemented.

Refer to section 8.2.1.1 for the components that comprise the preferred power system. Analysis to show that GDC 17 is satisfied consists of two parts: (1) a qualitative analysis to show that the loss of any one of the components will not cause loss of availability of offsite power to the 6900-volt shutdown boards, and (2) a quantitative analysis to show that the capacity of each of the components is such that it will carry its required load in the event of a simultaneous LOCA of one unit and orderly safe shutdown of the other unit with any of the other components out of service.

Refer to sections 8.2.1.2 and 8.2.1.3 for arrangement details for the components of the preferred power system. Each CSSTR has two 6.9-kV secondary windings. Each secondary of CSSTR's A and C is the normal source for one start bus with CSSTR B providing the alternate source. Each start bus serves as the normal source to two of the eight 6900-volt unit boards for the two units. Each of the two 6900-volt shutdown boards for each unit has a normal feed from one unit board and the alternate feed from another unit board; these two unit boards have normal feeds from different start buses which have automatic transfer between CSSTR's. Refer to Table 8.2.1-1 for board transfer information.

Thus both 6900-volt shutdown boards for each unit will be energized from offsite power following the loss of any one CSSTR, start bus, unit board, or supply cable from unit board to shutdown board.

The four start buses are physically independent in that each bus has its own housing. Thus each bus is protected against migration of a fault from the other start bus by two barriers. This circuit independence extends through the start board on to the common station service transformer terminals.

In the event of a LOCA on one generating unit and a orderly safe shutdown on the other generating unit while one CSSTR is out of service, the two remaining CSSTR's will supply power to the emergency loads on the LOCA unit and to those loads on both units associated with normal operation which are not automatically tripped. These normal operation loads are subsequently reduced by action of the unit operators. However, no operator action is assumed during the first 10 minutes following a LOCA. All loads on both 6900-volt shutdown boards which start automatically are assumed to start simultaneously. All unit normal running loads are assumed to remain without reduction following the accident signals, except those loads automatically tripped.

The overcurrent protective relays for the 6900-volt breakers are coordinated to provide a selective system for line faults and for ground faults. Thus a fault on a non-safety load circuit supplied from a 6900-volt unit board, will be isolated so that the continuity of power to that unit board and to the shutdown board fed from that unit board will not be jeopardized by the fault. Each 6900-volt unit board main bus is protected by bus differential relays which will isolate this bus in the event of a unit board bus fault. With the change in manual transfer scheme for start bus supply breakers, the Unit 1 and Unit 2 6.9 kv unit boards, and 6.9 kV turbine building common boards may be subjected to a momentary exposure of fault current that exceeds their rating. This condition only occurs while the start bus is being supplied by both transformers during a manual transfer. Due to the low probability of a close-in three phase fault occurring while this parallel configuration exists, this does not impose a significant risk to the switchgear.

S8-2.doc 8.2-14

SQN-23 TABLE 8.2.1-1 (Sheet 1)

AUXILIARY POWER SUPPLIES AND BUS TRANSFER SCHEMES General Remarks:

All normal and alternate breakers which supply a given bus are interlocked to prevent paralleling sources except Start Bus 1A, 18, 2A, and 2B whose supply breakers parallel sources when manually transferring.

2. Unit 1is shown. Unit 2 is similar except for unit designation. Unit 2 isshown for those exceptions to above.

Power Supplies Power Supplies Item Board/Bus Normal Alternate Remarks I 6.9-kV Start Common Station Common Station The secondaries of the CSSTR's A, B,and C feed into the 6.9-kV start board containing eight circuit breakers.

Bus lA Service Trans A, Service Trans B, These breakers are the normal and alternate supply breakers for the four start buses. Start buses 1A and 2A 4

XWinding 4 XWindina are normally fed from CSSTR A,and start buses IB and 2B are normally fed from CSSTR C. Transfer to CSSTR B may be automatic or manual but transfer back to the normal source is manual only. There are two 2 6.9-kv Start Common Station Common Station automatic transfers to CSSTR Bfrom either CSSTR A or C. Fast transfer is accomplished by having the start Bus 1B Service Trans C, Service Trans B, board breakers control switches inthe auto position and is initiated inthe event a fault is sensed within the Y Winding YWinding CSSTR, other transformers supplied from the common source, or inthe supply sources to the CSSTR. The other automatic transfer is a slow bus transfer which is initiated by bus undervoltage. The slow bus transfer is 2A 6.9-kv Start CSST A CSST B accomplished by having the start board breaker control switches inthe auto position and is initiated by

_ Bus 2A Y Winding YWinding undervoltage on the normal feeder (<70 percent of nominal) and is delayed until the bus residual voltage has decayed to 30 percent of nominal and ifthe alternate feeder voltage is > 90 percent of nominal. Manual and 2B fast transfers are defined as_< 6 cycle transfers. Manual transfers are made with one switch held inthe "closed 6.9-kv Start CSST C CSST B position while the other switch is turned to the "trip" position. Manual transfers on Start Bus 1A, 1B, 2A, and 2B

_ Bus 2B X Winding XWinding are achieved by dosing the standby transformer feeder breaker, observing a closed indication as well as load pickup, and opening the original feeder breaker. Start Bus 1A and 1Bcan transfer load to CSSTR Bwhile CSSTR Bis supplying load to the other Unit 1 bus. Start Bus 2A and 28 can transfer load to CSSTR Bwhile CSSTR Bis supplying load to the other Unit 2 bus. The undervoltage condition at 70 percent nominal voltage is annunciated inthe main control moom (MCR).

3 6.9-kv Unit Start Bus Common Board B Transfer from the unit station service transformer to the start bus is automatic on loss-of-board voltage.

Board 1A 1A Transfer is initiated by undervoltage relay at 70% nominal voltage with actual closure of start bus breaker at 30% normal voltage ifstart bus supply voltage > 90% nominal. Transfers to the start bus source may be 3A 6.9-kV Unit Start Bus 6.9-kV Unit manual or automatic, but transfers back to the unit station service transformer source are manual only. All Board 2A 2A Board 1D manual transfers and those transfers initiated by generator electrical protection signals are fast transfers (L6 cycles). Other trip signals are fast transfers after a 30 second time delay. Continued voltage failure for 5 4 6.9-kv Unit Start Bus Common Board B seconds will trip all motor breakers connected to the deenergized bus. MCR isannunciated on undervoltage Board 1B 1B condition at 70% nominal voltage.

4A 6.9-kv Unit Start Bus 6.9-kV Unit Board 28 28 Board 1D T82-1 .doc

SQN-23 TABLE 8.2.1-1 (Sheet 2)

AUXILIARY POWER SUPPLIES AND BUS TRANSFER SCHEMES Power Supplies Power Supplies Item Board/Bus Normal Alternate Remarks 5 6.9-kv Unit Start Bus N/A Board 1C 1A 6 6.9-kv Unit Start Bus N/A Board 1D 1B 15 6.9-kv Unit 6.9-kV 6.9-kV Transfer between the normal and alternate sources will be manual fast transfer L< 6 cydes). Loss-of-bus voltage L<

Board 1A-A Unit Board 1B Unit Board 1A 80 percent) for 1.25 seconds starts the diesel generators, trips incoming feeder breakers and most motor breakers. I When diesel generator is up to rated speed and voltage, the emergency breaker will dose automatically to connect Standby- Diesel Gen IA-A the diesel to the board, and loads will be applied as required by a sequential timer. Return to normal supply is manual only and isa fast transfer (L6 cydes). INormal or alternate feeder breaker is tripped and annunciated inthe 16 6.9-kv Unit 6.9-kV 6.9-kV MCR after a time delay of 1.25 seconds on loss of voltage condition at 80% nominal. Transfer to the diesel generator Board 1B-B Unit Board 1C Unit Board 1D for a sustained degraded undervoltage (UV) is initiated at setpoint 9.5 seconds (ifa SI has been initiated, or is subsequently initiated) and 5 minutes for non-SI if below setpoint of 93.5% nominal. MCR annunciation occurs for Standby - Diesel Gen 1B-B UV of 93.5% nominal and overvoltage of 105% nominal. The shutdown utility bus allows any 6.9-kV shutdown board to be connected to any other or all other 6.9-kV shutdown boards. All circuit breakers connected to this bus are normally open and disconnected. Use of the bus requires manual insertion and dosing of two of the breakers.

T821-1.doc

Amps X 100 START BUS (Nom. kV=6.9, Plot Ref. kV=6.9)

.5 3 5 10 30 50 100 300 500 1K 3K 5K 10K 1KF- I.

300 D LOA K KBIER 100 /

50 - , - -

30 xXFA* I LA;t C9 3 COD MI

.3 - I I I I STT CB4 UNIT B L REAKER

.01

.5 1 3 5 10 30 50 100

_ _ _ _ _ K -_. i.

300 500 1K J ..

31K 5K 10K Amps X 100 START BUS (Nom. kV=6.9, Plot Ref. kV=6.9)

FIGURE 8.3.1-17 6900 Volt Containment Penetration Protection Revised by Amendment 23

SQN-18 9.0 AUXILIARY SYSTEMS 9.1 FUEL STORAGE AND HANDLING 9.1.1 New Fuel Storage 9.1.1.1 Design Bases

1. Storage space will be provided for a total of approximately 146 fuel assemblies.

2. New fuel, up to 5.0% by weight U-235, will be stored dry in the new fuel storage facility but in an array such that Keff will be less than 0.95 ifflooded with unborated water or less than 0.98 if optimally moderated.

3. The new fuel storage facility shall be capable of withstanding loads imposed by the dead load of the fuel assemblies, loads resulting from the impact and handling of fuel assemblies and loads from 1/2 Safe Shutdown Earthquake (SSE) and SSE's. Any resulting damage shall not be such as to increase Ke, above 0.95 ifflooded with unborated water or above 0.98 if optimally moderated. The facility shall not be required to withstand loads that would be imposed by dropping heavy objects onto it, but the movement of such object over it shall be administratively prohibited.

4. Consideration of criticality safety analyses is discussed in Subsection 4.3.2.

9.1.1.2 Description The location of the new fuel storage vault is shown in Figure 9.1.1-1 and in Figures 1.2.3-4 and 1.2.3-8.

Figure 9.1.1-2 shows the design of the new fuel storage racks.

9.1.1.3 Safety Evaluation The racks are individual vertical cells fastened together in a 4 x 5 array forming modules that are firmly bolted to embedded plates in the floor of the new fuel vault. The new fuel racks, including supports, are made of austenitic stainless steel and are constructed so that it is impossible to insert fuel assemblies except in prescribed locations having a minimum center-to-center spacing of 21 inches in both directions. However, to preclude criticality during optimum moderation conditions, 34 of the 180 cells are physically blocked to prevent use (configuration shown in Technical Specification Figure 5.6-4). The spacing is sufficient to assure Keff <0.95 even ifimmersed in unborated water or Keff < 0.98 if optimally moderated by being enveloped by an aqueous foam or mist. The new fuel storage racks are designed in accordance with AISC, Sixth Edition, 1963. The new fuel storage vault is designed in accordance with ACI 318-1963.

The racks and the anchor bolts which hold them in place, have been designed to withstand SSE, 1/2 SSE, and shipping and handling loads as well as the dead load of the fuel assemblies. They can withstand impacts imposed by bumping them with objects normally handled in the new fuel pit including fuel assemblies and tools.

With new fuel in storage vaults, movement of heavy objects over the facility is administratively prohibited so that the fuel will not be damaged from heavy falling objects. The facility is shared between the two units; however, this does not increase the potential for damage to the new fuel.

Sharing of the new fuel storage between two operating reactors has no effect on the safety or operation of the plant.

S9-1.doc 9.1-1

SQN-23 The details of the seismic design and testing procedures are presented in Section 3.7.

9.1.2 Spent Fuel Storage 9.1.2.1 Design Bases

1. Spent fuel storage space will be provided for a total of 10 cores (193 per core) plus 161 extra storage positions. However, only 159 of the 161 extra storage spaces may be utilized due to physical obstructions. Therefore, 2089 total spaces are available for fuel assembly storage.

Storage space for full core offload capability is an operating strategy, maintaining full core offload capability in the spent fuel pool is not a licensing requirement.

2. Spent fuel storage racks are designed for new fuel enriched to a maximum of 5.0% by weight U-235 with K eff less than 1.0 when flooded with unborated water and considering uncertainties.

With partial credit for dissolved boron in the pool, Keff is less than 0.95 with 300 ppm boron for normal conditions.

The racks are regionalized into three arrangements as to what limitations exist on fuel assemblies stored in each region.

3. Administrative controls over fuel loading, discussed in Section 4.3.2.7, assures that the fuel will be stored in an array such that Keff will be less than 1.0 even if the water in the storage pit contains no boron. However, for some accident conditions, the presence of dissolved boron in the pool water is taken into account as a realistic initial condition. This assumption can be made by applying the double contingency principle of ANSI N16.1-1975 which requires two unlikely, independent, concurrent events to produce a criticality accident. Maintaining 700 ppm dissolved boron in the pool shall meet the criteria for Keff to be less than 0.95 with consideration of uncertainties.

4. The depth of shielding water over the spent fuel will be sufficient to limit the radiation dose to acceptable levels.

5. The spent fuel storage facility will be capable of withstanding loads imposed by the dead load of the fuel assemblies, loads resulting from the impact and handling of fuel assemblies, the maximum uplift force from the spent fuel bridge hoist and loads from 1/2 SSE and SSE's.

Damage to spent fuel pit and storage racks will neither be sufficient to cause a loss of water below the top of the racks nor increase Keff to 1.0.

6. Electrical and mechanical interlocks are provided to prevent the movement of loads over stored spent fuel.

7. The spent fuel shipping cask loading area will not be separated from the spent fuel storage area.

A cask drop is not a credible event provided that heavy loads and safe load paths are in place in accordance with NUREG-0612 (SRP-9.1.2, NUREG-0800).

8. Adequate cooling water will be available for cooling the pool water (Section 9.1.3).

9. Consideration of criticality safety analysis is discussed in Section 4.3.2.

S9-1 .doc 9.1-2

SQN-23 ACA Systems The ACA systems are two independent subsystems located on elevation 734.0 of the Auxiliary Building. This is a seismic Class I structure and above maximum possible flood elevation. The two independent auxiliary systems are powered from separate emergency electrical power sources to prevent a single failure or power loss rendering the system inoperable.

The ACA Systems are designed to Class I seismic requirements (except for the piping downstream of the moisture traps and moisture trap bypass isolation valves which is Class I {L}). A single failure cannot render both systems inoperable since they are completely separated.

The auxiliary compressors start automatically upon loss of air from the SCSA System for any reason at a predetermined pressure. The ACA System is automatically isolated from the SCSA System whenever the system pressure falls below a designated pressure. The ACA System is sized and equipped so that ample system capacity is provided for both units under all design basis accident conditions. Redundancy and train separation has been provided in the ACA System to the extent that no initial "design basis event" followed by an arbitrarily selected "single active failure" will prevent the system from performing its necessary safety functions.

Air cylinders, accumulators, and regulators are provided for the steam-driven auxiliary feedwater pump level control valves. These allow the valves to be manually closed during a total loss of all offsite and onsite alternating current power (excluding vital instrument power).

The auxiliary control air compressor's suction is taken from a nonfiltered area. Calculations were performed to verify that the amount of radioactivity introduced into the main control room habitability area during an accident condition is not significant.

The ACA Systems ensures plant safe shutdown and accident mitigation assuming a failure of the SCSA System and a single failure on one redundant train of the ACA System.

9.3.1.4 Tests and Inspections All system components were tested prior to plant operation both under normal conditions and simulated accident conditions. Periodic tests are performed to ensure proper operation of the ACA System and isolation valves.

In accordance with Generic Letter 88-14, routine air quality testing and set point verification of moisture elements in the ACA and SCSA Systems are performed.

9.3.1.5 Instrumentation Applications SCSA System Local indication is provided at various points in the system for temperature, pressure. Pressure indication is provided in the MCR. Audible alarms are produced in the main control room for low compressor oil pressure, high oil temperature, and high air pressure for each of the four SCSA compressors. Closure of the service air isolation valve is also annunciated in the control room.

ACA Systems The auxiliary air compressors are started upon loss of air pressure from the SCSA system. Local position lights give indication upon closure of isolation valves between the SCSA and ACA

$9-3.doc 9.3-3

SQN-16 Systems. Audible alarms are produced in main control room for compressor high air temperature, compressor low oil level, high dewpoint of control air, and low control air pressure. There is local indication of air pressure at various points and in the MCR. The safety-related display instrumentation for Post Accident Monitoring is discussed in Section 7.5.

9.3.2 Process Sampling System 9.3.2.1 Design Basis The sampling system is designed to obtain samples from the various process systems in each of the two units. The samples are obtained in the secondary chemistry sampling facility, hot sample room, post accident sampling facility, condensate demineralizer building, and locally (grab samples) for laboratory analysis. The waste gas analyzer also obtains samples see Section 11.3. This system has no safety-related functions (except as necessary for containment isolation, SG isolation, etc.). During a Loss-of-Coolant Accident (LOCA), this system is isolated at the containment boundary for these samples which originate within containment. Sampling system discharges are designed to limit flows under normal operation and anticipated malfunctions or failure to preclude any fission product release in excess of the limits stated in 10 CFR 20.

9.3.2.2 System Description The sampling system consists of the following types of collection areas and equipment:

1. The hot sample room where primary side and steam generator blowdown samples are routed for grab sampling and online analysis. Radioactive grab samples are taken to the radiochemical laboratory for analysis. Selected variables will be monitored by Chemistry in order to detect any that exceed established limits.

2. Local grab samples may be taken throughout the plant for detailed chemical and radiochemical analysis.

3. The Gas Analyzer System monitors the Gaseous Waste Disposal Decay Tanks for hydrogen and oxygen concentrations in a nitrogen atmosphere. The concentrations are indicated and alarmed at the analyzer and waste disposal panel 0-L-2A.

4. Secondary chemistry lab where online Condensate and Feedwater system samples are processed for automatic analysis of several variables such as pH, conductivity (specific and cation), etc.

The liquid sampling system is operated manually throughout the full range of power operations. All sample lines originating within containment have air-operated or solenoid isolation valves near the sample point and inside and outside containment for containment isolation. All sample lines originating outside containment have manual isolation valves, except the volume control tank vent and RHR miniflow lines which have air-operated or solenoid isolation valves. All air-operated or solenoid isolation valve handswitches are located on a wall panel at the hot S9-3.doc 9.3-4

SQN-23 The two turbine driven, variable speed main feedwater pumps are capable of delivering feedwater to the four steam generators under all expected operating conditions. Main feedwater pump speed is automatically adjusted to meet system demands. The main feedwater pump speed control system maintains a differential pressure determined by the average steam flow from all four steam generators.

This setpoint is compared to the actual differential pressure between the main steam header and the main feed pump discharge header. Any difference between the steam flow derived setpoint and the actual setpoint changes pump speed accordingly.

The main feedwater pump manual/auto stations provide the operator with the flexibility of choosing various operating modes. The unit operator will have the option to operate (1) both pumps on manual speed control to base load his operation, (2) to operate one pump on manual with the other automatically swinging with plant load changes, or (3) to let both pumps swing with the load changes.

Feedwater flow to the individual steam generators is controlled automatically above 15 percent load by adjustment of a feedwater regulator valve in the piping to each steam generator. The valve's position is determined by a three element controller that uses steam generator water level, steam flow, and feedwater flow as the control variables. The regulator valves are pneumatically operated and are designed to fail closed on loss of air. During startup and operation below 15 percent load, additional control is available from small bypass valves around the feedwater regulator valves.

The bypass valve's position is determined using steam generator narrow range and wide range levels along with FW temperature, turbine load, and operator entered level setpoint. Prior to the generator sync, the steam generator level with operator entered level setpoint develops a single element control signal that can be modified by a variable gain unit that adjusts the control signal output based upon feedwater temperature to compensate for feedwater mass density. After the generator is placed online, the turbine impulse pressure developed setpoint replaces the operator entered setpoint. The control signal can also be modified based upon the wide range steam generator level. The bypass valve control is designed to reduce the affects of steam generator level shrink and swell at low power.

The bypass valve control is placed into automatic at about 2% power and as the plant SS10-04.doc 10.4-17

SQN-22 escalates in power, the bypass valve continues to open and control level until about 16-18% power.

The bypass valve can transfer to three element control at about 13-14% power. (Three element control uses steam generator level, feedwater flow, and steam flow to control the regulating valve.) At about 15-18% power, the Distributed Control System begins to open the main feedwater regulating valve and begins the process of transferring control from the bypass valve to the main regulating valve.

The feedwater system normally operates at full load with three hotwell, three demineralized condensate, three condensate booster, and two main feedwater pumps in service.

Heating of the condensate-feedwater is accomplished by passing it through a series of closed heat exchangers as described below:

a. Gland Steam Condenser - This exchanger condenses the steam leakoff from all turbine shaft seals and removes the noncondensables (the result of shaft inleakage of air) from this steam. A weighted check valve is provided in a bypass around the condenser to ensure minimum required flow through the condenser at low condensate flow conditions and to minimize pressure drop through the condenser during high condensate flow conditions.

b. Main Feedwater Pumo Turbine Condensers - Each main feedwater pump turbine is equipped with an individual surface type condenser. Control valves in the inlet and outlet condensate piping to these condensers provide the ability to isolate a condenser if its associated turbine is rendered inoperative and to force 100 percent condensate flow through the operating condenser, thus allowing maximum power operation of the remaining turbine. In order to ensure the availability of a condensate flow path following a trip of both main feedwater pumps, only one of the two condensers can be automatically isolated at any given time. The hotwell pumps will automatically trip if this flow path is not available.

c. Feedwater Heaters - Three parallel strings of heaters, each consisting of three low pressure feedwater heaters, three intermediate pressure feedwater heaters, and one high pressure feedwater heater are provided.

The heaters are numbered from 1 to 7 with the highest pressure heater designated as No. 1.

Motor-operated isolation valves are provided at the inlet to each No. 7 heater and the outlet of each No. 5 heater, the inlet to each No. 4 heater and the outlet of each No. 2 heater, and at the inlet and outlet of each No. I heater. High-high level in an applicable heater shell will cause the isolation of the group of heaters in the string in which the high-high level occurred (either the 5, 6, 7, heaters, 2, 3, and 4 heaters, or No. 1 heater in either the A, B, or C string).

Tubes for all heaters are 304 Stainless Steel (SS) except for heaters 5, 6, and 7. The tubes for heaters 5, 6, and 7 are SA-688-304 SS. Tube-to-tube sheet joints in the No. 1 and No. 2 heaters are expanded and welded; tube-to-tube sheet joints are only expanded in the No. 3 through No. 7 heaters.

Minimum flow bypasses are provided for equipment protection. The Condensate System minimum flow bypass is located immediately upstream of the No. 7 heaters. The bypass control valve receives its operating signal from the station flow nozzle located upstream of the gland steam condenser. The valve plug's position is modulated to maintain approximately 5500 gal/min flow through the flow nozzle. This flow is sufficient to protect the hotwell and demineralized condensate pumps and to provide adequate cooling water to the gland steam condenser at all times.

SS10-04.doc 10.4-18

SON 11.4 PROCESS AND EFFLUENT RADIOLOGICAL MONITORING SYSTEMS Means are provided for monitoring during normal operations, including anticipated operational occurrences, and during accident conditions various process streams and gaseous and liquid

.effluent discharge paths. Some of the monitors initiate automatic control actions.

11.4.1 Design Objectives The Process and Effluent Radiological Monitoring Systems are designed to perform these basic functions:

1. Give warning of a condition which might lead to radioactivity releases that could result in exceeding the limits set forth in 10CFR20 and in 10CFR50.

2. Warn plant personnel of increasing radiation levels which might result in a radiation health hazard.

3. Rapidly provide information on fuel clad and equipment failures or malfunctions.

4. Provide means for detection of leakage of primary coolant to the secondary coolant.

5. Initiate automatic control actions to prevent the unnecessary discharge of excessive radioactivity to the environment.

6. Initiate automatic control actions to prevent the transfer to plant tanks of radioactivity in concentrations above design limits.

7. Perform primary safety functions and postaccident monitoring.

11.4.2 Continuous Monitoring An instrumentation assembly that includes one or more radiation detectors or radioactive material sample collectors, or both, and all associated instrumentation outside the assembly constitutes a radiation monitor. Each radiation monitor described in this section is composed of one or more of the following channels:

1. gaseous effluent or gaseous process noble gas,.

2. gaseous effluent particulate,

3. gaseous effluent iodine,

4. gaseous process exposure rate, and

5. liquid effluent or liquid process.

J13 In the case of two or more monitor channels constituting a single monitor, the monitor channels are considered to share common instrumentation. For example, a three-channel monitor's sampling system is shared among the three channels. Also, part of a sampling system may be shared among two or more monitors.

Most monitor channels have several components. In this section, the unique identification of the I -

detector of any of these monitor channels is used to designate the entire monitor channel.

SS1 1-4.doc 1 1.4-1

SQN-23 For monitor channels that do not have uniquely identified components, monitor channel identification requires both the unique identification of the monitor skid assembly which houses the radioactive material sample collectors or channel detectors, or both, and a verbal description sufficient to identify the specific channel of the monitor.

The identification of a monitor channel, monitor skid, and any plant system component that is automatically actuated by a monitor channel begins with one of the character sets, 1-, 2-, or 0-, to denote unit 1, unit 2, or common, respectively. Whenever an identification in this section does not contain one of these character sets, both unit 1 and unit 2 channels, monitor skid assemblies or actuated components exist.

The liquid process and effluent monitors are listed in Table 11.4.2-1. The gaseous process and effluent monitors are listed in Table 11.4.2-2. These tables also list for each monitor channel the electrical safety class, the seismic category, the type of detector, the location of the detector assembly, and the channel range.

Provisions for indication, recording, and alarm annunciation, both locally (i.e., in the vicinity of the detector assembly) and remotely on an MCR panel, are listed in Table 11.4.2-3.

11.4.2.1 Process and Effluent Liquid Monitors The radiation monitoring system has two basic types of process liquid monitors: (1) off-line monitors and (2) on-line monitors. Each off-line monitor extracts a portion of the process fluid to provide a sample of liquid effluent for real time detection of the effluent radioactivity. The on-line monitors provide real time detection of process liquid radioactivity by means of the detection of dose rates in the vicinity of process liquid piping.

11.4.2.1.1 Waste Disposal System Liquid Discharge Monitor (O-RE-90-122)

Instrument malfunction or detection of radioactivity in excess of the effluent concentration setpoint shall automatically initiate closure of this effluent path to the cooling tower blowdown system by closing RCV-77-43. The setpoint is predetermined by nuclear chemistry Offsite Dose Calculation Manual (ODCM) compliance sampling program prior to each effluent discharge. The sampling program is responsible for determining the acceptability of each release and adherence to 10CFR20 criteria. This monitor provides additional assurance that the effluent releases are consistent with the compliance sampling to preclude potential discharges composed of inconsistent concentrations or piping misalignment.

11.4.2.1.2 Essential Raw Cooling Water Discharge Monitors (O-RE-90-133,140)

(O-RE-90-134, 141)

Two monitor channels that share a common sample delivery system are used to continuously monitor each of the two separately trained ERCW discharge headers. Channels O-RE-90-133, 140 monitor discharge header A. Channels O-RE-90-134, 141 monitor discharge header B. The entire sample flow may be routed through either detector channel or divided between each detector channel. These channels provide means for detecting tube leakage in the component cooling heat exchangers or the containment spray heat exchangers, which are served by ERCW.

SS1 1-4.doc 11.4-2

SQN-23 11.4.2.1.11 Condensate Demineralizer Liquid Monitor (O-RE-90-225)

The condensate demineralizer liquid monitor channel continuously monitors the effluent from the neutralization tank, high crud tanks A and B or the non-reclaimable waste tank prior to discharge of these effluents to the cooling tower blowdown or turbine building sump.

At the channel high radioactivity setpoint, several automatic functions are initiated: (1) effluent lines to the cooling tower blowdown are isolated, (2) recirculation of the contents of the non-reclaimable waste tank is begun, (3) the flow path from the neutralization tank to the non-reclaimable waste tank is closed, and (4) recirculation of the contents of the neutralization tank is begun. The following specific control actions occur to accomplish these functions: (1) valve O-FCV-14-288 closes to isolate effluent from the high crud filter vessel, (2) valve O-FCV-14-360 closes to isolate effluent from the non-reclaimable waste tank, (3) valve O-FCV-14-345 opens to provide recirculation of the contents of the non-reclaimable waste tank, (4) valve O-FCV-14-187 closes to isolate the discharge line of the neutralization tank, and (5) valve O-FCV-14-188 opens to provide recirculation of the contents of the neutralization tank.

The channel high radioactivity setpoint is determined in accordance with the ODCM methodology.

11.4.2.1.12 Station (Turbine Building) Sump Discharge Monitor (O-RE-90-212)

The station sump discharge monitor is an on-line (in close proximity to discharge pipe) channel that monitors the discharge flow from the station sump, located in the Turbine Building, to the yard discharge culvert.

The monitor high radioactivity setpoint is determined in accordance with the ODCM methodology.

11.4.2.2 Process and Effluent Gas Monitors Three types of effluent gas monitor channels exist in the radiation monitoring system: (1) off-line monitor channels, (2) on-line monitor channels, and (3) an in-line monitor channel.

Off-line channels employ a sampling system, which may be shared, to provide a continuous sample of gaseous effluent for one of five purposes: (1) real-time detection of noble gases or gross radioactivity, (2) collection of particulates on a filter for subsequent laboratory analysis, (3) collection of iodine on an adsorber for subsequent laboratory analysis, (4) collection of particulates for real-time detection of particulate radioactivity, and (5) collection of iodine for real-time detection of iodine radioactivity.

Channels that provide detection of gross radioactivity are called noble gas channels since contributions from other nuclides to the measured gross radioactivity are negligible.

SS1 1-4.doc 11.4-5

SQN-17 On-line effluent gas monitor channels provide real time detection of effluent noble gas radioactivity by means of the detection of dose rates in the vicinity of the effluent pipe or duct.

An in-line gas monitor channel has its scintillation detector in line with the gas decay tank release piping.

The radiation monitoring system employs three types of process gas monitor channels: (1) in-line monitor channel, (2) off-line monitor channels, and (3) area-type monitors. Each off-line channel employs a sampling system to provide a continuous sample of process gas for real-time detection of noble gas radioactivity. Two area-type monitors that are employed in the system to monitor the fuel pool air space are arbitrarily categorized as process gas ncnitcrs since the dcze rates that they would measure during a fuel handling accident would be predominantly from noble gas radioactivity.

11.4.2.2.1 Waste Gas Effluent Monitors (O-RE-90-118)

The in-line noble gas channel, O-RE-90-118, continuously monitors the gaseous release from the waste gas decay tanks to the Shield Building vent and initiates isolation of the gas decay tanks by closing valve O-FCV-77-119 on a high radioactivity or instrument malfunction signal.

Gas decay tanks are sampled and analyzed for radioactivity concentrations prior to release. The monitor high radioactivity setpoint for channel O-RE-90-118 is determined in accordance with the ODCM methodology.

11.4.2.2.2 Condenser Vacuum Pump Exhaust Monitors (RE-90-119, 99, 255, 256)

Two low range monitors, RE-90-99 and RE-90-119, and two accident monitors (mid & high range),

RE-90-255 & 256, provide detection of noble gases over the entire range of concentrations that could exist during normal operations and during accident conditions. Monitor channel ranges overlap.

RE-90-99 or -119 continuously samples the condenser vacuum pump exhaust to monitor noble gas concentrations for indications of primary to secondary leakage and for evaluations of radioactivity released to the environment. The RE-90-99 and -119 monitors cover the same range of concentrations and only one of the two should be sampling the exhaust at a time. The other monitor is a spare/backup monitor to be used during failures or maintenance periods. Both monitors should not be in service at the same time due to flow limitations on the condenser vacuum pump exhaust.

The accident range area type monitor channels RE-90-255, 256 monitor noble gas concentrations over the upper several decades of the design range. These monitor channels, which have overlapping ranges, monitor effluent radioactivity concentrations by detection of dose rates in the vicinity of the condenser vacuum pump exhaust duct.

Each low range channel utilizes a single beta scintillation detector. The mid and high range noble gas area monitor, utilize a G-M tube (255) and ion chamber (256).

Portable samplers can be utilized for laboratory analyses of particulate and iodine radioactivity as required.

Samples for RE-90-99 and RE-90-119 (low range) condenser vacuum pump exhaust monitor channels are obtained with cylindrical sampling manifolds that extend completely across the 12-inch diameter exhaust duct. The sample enters the manifold through four upstream facing openings that are uniformly spaced along the cylindrical surface of the manifold.

SS1 1-4.doc 11.4-6

SQN-23 TABLE 11.4.2-1 (Sheet 1) (7)

PROCESS AND EFFLUENT RADIATION MONITORS - LIQUID MEDIA Range(') (6)

TVA Quantity Electrical Detector Amb Min. Det. Max. Det.

Instrument of Monitor Seismic Safety Location Detector Background(') Conc. Conc.

Monitor No. Channels Class Class FI. Elev. Building Type mremlhr. Nudide uCi/cc uCiHcc Station Sump Disch 0-RE-90-212 I/plant None None 662.5 Turbine Gamma Scint. 1.0 Co-60 7.38(-8) 3.26(-2)

Monitor Cs-1 37 2.49(-7) 1.06(-1) 1-131 3.15(-7) 1.39(-1)

Waste Disposal System 0-RE-90-122 1/plant 1(L) None 669 Auxiliary Gamma Scint. 1.0 Co-60 1.9(-5) 4.20(-2)

Discharge Monitor Cs-137 3.5(-5) 7.80(-2) 1-131 4.23(-6) 2.38(-2)

Essential Raw Cooling 0-RE-90-133 4/plant 1(L) None 669 Auxiliary Gamma Scint. 1.0 Co-60 2.75(-6) 1.55(-2)

Water Discharge 0-RE-90-134 (2 channels Cs- 137 5.07(-6) 2.85(-2)

Monitor 0-RE-90-140 per monitor) 1-131 4.23(-6) 2.38(-2) 0-RE-90-141 Condensate Deminer. 0-RE-90-225 i/plant None None 685 Demin Gamma Scint. 1.0 Co-60 6.37(-8) 1.55(-2)

Liquid Cs-137 1.17(-7) 2.84(-2)

Monitor 1-131 9.78(-8) 2.38(-2)

Steam Generator Blwdn 1-RE-90-120 4/plant None None 685 Turbine Gamma Scint. 1.0 Co-60 2.75(-6) 1.55(-2)

Liquid Discharge 2-RE-90-120 (2 channels Cs-137 5.07(-6) 2.85(-2)

Monitor 1-RE-90-121 per monitor) 1-131 4.23(-6) 2.38(-2) 2-RE-90-121 TT1 142-1.doc

SQN-19 TABLE 11.4.2-1 (Sheet 2) (7)

PROCESS AND EFFLUENT RADIATION MONITORS - LIQUID MEDIA RariMe(01 (6)

TVA Quantity Electrical Detector Amb Min. Det Max. Det Instrument of Monitor Seismic Safety Location Detector Background(') Cono. Cone.

Monitor No. Channels Class Class A.Elev. Buildin Te mrem/hr. Nuclide &L22 uCV02 I

Component Cooling O-RE-90-123 3/plant 1(L) None 714 Auxiliary Gamma Scint. 1.0 Co-60 2.75(-6) 1.55(-2)

Sys Monitor 1-RE-90-123 CS-1 s7 5.07(-6) 2.84(-2) 2-RE-90-123 1-131 4.23(-6) 2.38(-2)

(1) The minimum detectable concentration Is determined at the above background. The actual demonstrated range encompasses the minimum and maximum detectable concentration values shown in Table.

(6) These values are based on prototype calibration factors from the manufactures and not the installed detector. The Installed detector will vary from I

these values due to individual detector sensitivities however, they are in compliance with the TVA required tolerances.

(7) Accuracy analysis performed by NE calculation SON-APS3-1 00.

SQN-23 Enclosures about these areas furnish necessary shielding, but their principal purpose is to minimize the spread of contamination.

Outside Areas Except for the foll6wing, all areas outside the plant buildings are unlimited access areas as defined in Table 12.1.2-1 during normal operation including anticipated operational occurrences.

1. For short periods of time when solid waste shipping is imminent, the casks will be outside. The number of casks allowed outside at any one time is controlled and depends on the dose rates from each. The maximum dose rate from each cask satisfies the provisions of 49 CFR 173.

Access to the outside region where these casks are located during the short preshipment periods is controlled. The type of control required depends on the designated access type which, in turn, is established by the dose rate.

2. During solid waste and spent fuel shipment, the area immediately adjacent to the transport vehicle may be reevaluated.

3. There are six outside tanks that contain radioactive liquids: two refueling water storage tanks, two primary water storage tanks, and two condensate storage tanks. The activity in each is low level, and no shielding is required. Maximum deep dose equivalent rates at the exclusion area boundary from these tanks is 2.OE-4 mrem/hr for all tanks total. The radiation analysis is summarized in SQN-DC-V-21.0, FSAR Reference 15.5.8.17.

4. Guidance for the cumulative radiation dose to the public is provided in 10 CFR 20.1301 and 10 CFR 72.104. SQN is a dual NRC licensed facility that will [1] produce nuclear power with Unit 1 and Unit 2 in accordance with 10 CFR Part 50 and [2] will store spent fuel utilizing up to 90 HOLTEC HI-STORM 100 Cask System in accordance with 10 CFR Part 72.210. Therefore, the radiation doses affiliated with the operations of SQN Unit 1 and Unit 2 reactor power facilities must be summed with the dose from 90 HI-STORM 100 Cask Systems and yield a total value less than the limitation provided by 10 CFR 20.1301 and 10 CFR 72.104. This summation is provided in SQN's Independent Spent Fuel Storage Installation (ISFSI) Section 9.1.5 (Reference calculations SQN-TI-534, SQS2-0171, and SQS2-0234).

5. The Old Steam Generator Storage Facility (OSGSF) is a non-safety related, non-seismic, reinforced concrete structure that provides interim storage for the Old Steam Generators (OSGs) removed from the Reactor Building as a result of steam generator replacement during the Unit 1 Cycle 12 refueling outage. The OSGSF is located north of the plant, outside the protected area but within the exclusion area and site boundary. The general location of the OSGSF is shown on Figure 2.1.2-1.

The reinforced concrete walls and roof (minimum density of 150 lb/cft) of the OSGSF and its access vestibule have been designed to ensure that the dose rates outside the facility are within the limits of 10 CFR 20 and 40 CFR 190 (See Reference 9). The interior of the OSGSF is classified as a "high radiation area (controlled)" and the vestibule entrance is classified a "regulated access" area as defined in UFSAR Table 12.1.2-1.

The radiation close assessment was accomplished using the SHIELD-SG and Multigroup Oak Ridge Stochastic Experiment (MORSE) computer codes. SHIELD-SG is a point-kernel program used to calculate direct doses at various distances from the source. MORSE is a Monte-Carlo program that calculates direct and skyshine doses. See Reference 9.

SS12-1 .doc 12.1-9

SQN-23 Shieldinq For Accident Conditions Some shielding provided for normal operation also has a function during accident conditions.

However, other shielding has a function during accident conditions only. This accident shielding is required to serve two functions: (1) it must restrict the dose at the exclusion area boundary from activity in the containment to a small fraction of 10 CFR 100 limits, and (2) it must attenuate dose rates at interior and other onsite locations from activity in the containment to levels which will allow required access. Requirements are the following:

1. Continuous control room occupancy is required.

2. Visits of several minutes duration into the shutdown board rooms to operate breakers and switches must be possible. For these visits, which may occur at any time after the start of accident conditions, the operator will wear appropriate protective equipment.

3. Since a single crew cannot remain in the control room for the duration of the accident, it must be possible to make the trip from the exclusion area boundary to the control room sometime after 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> without receiving an excessive dose.

4. The diesel fuel will have to be replenished during the course of the accident. The onsite storage allows about seven days of operation.

The Shield Building is the principal structure that limits dose at the exclusion area boundary and at site exterior locations from activity in the containment. The Shield Building also, in concert with other shields, limits dose rates at interior and other onsite locations. The accident shielding functions of the Shield Building are shared by the structures that shield its penetrations, such as the steam line penetrations, the personnel hatches, the equipment hatch, ventilation ducts, and the many smaller penetrations. Some of the structures that shield the Shield Building penetrations are Auxiliary Building internal walls. These and other Auxiliary Building walls and the Auxiliary Building ceilings further attenuate radiation from sources within the containment to improve accessibility during accident conditions.

The ESF equipment compartment shielding provides for emergency maintenance. To make possible this maintenance, the equipment will be drained before the maintenance begins and the operator will wear appropriate protective equipment. In the case of ESF equipment, such as the RHR pumps which also operate during normal operation, the shielding required for normal operation is controlling.

The control room is shielded so that the total effective dose equivalent from external sources (activity inside the primary containment, in the passing cloud, and in surrounding rooms) obtained during occupancy following a LOCA is less than 5.0 rem. The remainder of the total effective dose equivalent will come from the airborne activity within the control room. (The dose from this airborne activity which is more difficult to limit than that from the external sources is discussed in Subsection 15.5.3, which considers integrated doses in the control room under accident conditions from all sources.)

In the control room shielding design, sufficiently thick walls, ceiling, and floor are provided. In addition, special attention is given to the doorways. Radiation shielding is provided at the entrances from the Turbine Building to attenuate radiation from the radioactive cloud which is assumed to occupy the Turbine Building. The door shielding shall have a radiation attenuation coefficient greater than or equal to the Main Control Room C36 pressurization door including the security bullet plate barrier.

Analysis shows that shield doors at the small entrances from the control room to the Auxiliary Building are not necessary.

SS12-1 .doc 12.1-10

SQN-23 A control room layout drawing is included as Figure 1.2.3-3.

Shielding Calculations Shielding required to reduce the dose rates, from conservative source strengths in known source geometries as design objective values, are determined with hand calculations and/or with computer codes. Both the hand calculations and the computer codes employ the point-to-point kernel integration method. The PATH code and the QAD-P5Z code integrate the basic exponential attenuation point kernel over the various geometries to provide the uncollided gamma-ray flux. Many of the integrations found in the Reactor Shielding Design Manual (Reference 2) are utilized. Dose rates are obtained by multiplying the uncollided flux by the product of the flux weighted buildup factor and a dose-conversion factor. The computer program COROD is used to solve the equations for the beta and gamma dose rates from airborne activity in the control room. COROD also provides the gamma dose rate after attenuation by a shield. The equations solved are given in Subsection 15.5.3.

The computer codes addressed above are utilized in radiation analyses to demonstrate compliance to 10 CFR 20, 10 CFR 50.49, 10 CFR 50 Appendix AGDC-19, and 10 CFR 100 requirements. These analyses are summarized in SQN-DC-V-21.0, FSAR Referencel15.5.8.17.

12.1.3 Source Terms Radiation analyses utilized for normal plant operations and post accident conditions are described in FSAR Chapters 11.1 and 15.5, respectively. These radiation analyses are summarized in SQN-DC-V-21.0, FSAR Reference 15.5.8.17.

12.1.4 Low Range Area Monitoring 12.1.4.1 Obiectives and Design Basis Area radiation monitors are provided to assist in compliance with 10 CFR 50, Appendix A, General Design Criteria 19, 63, and 64, and with 10 CFR 20.

Monitors are provided to monitor exposure rates and warn plant personnel of increasing radiation levels in the general area of the monitors.

12.1.4.2 Operational Characteristics Table 12.1.4-1 lists the physical location of each area monitor, type of detector, and detector range.

The area Radiation Monitoring System has the following operational characteristics.

12.1.4.2.1 Area Monitor Detector Detectors are Geiger-Mueller type gamma detectors. Each detector has its own independent high-voltage power supply located in the Main Control Room (MCR) and has a remote-operated check source mechanism with actuation from its rate meter in the MCR.

12.1.4.2.2 Deleted SS12-1.doc 12.1-11

SQN-23 12.1.4.2.3 Local Indicating Ratemeter With the exception of the MCR monitor, each monitor has a local indicator, high radiation light and audible alarm, and a power-on light.

12.1.4.2.4 Trending The area monitors are trended on multi-point recorders or on the plant computer in the main control room.

12.1.4.2.5 Ran-ge and Setpoints The ranges of the instrumentation are provided in Table 12.1.4-1. The area monitor's setpoints are adjustable over the entire range.

12.1.4.3 Calibration and Maintenance Periodic calibrations will be performed on each monitor. The calibration procedure may be performed by means of sequential, overlapping, or total channel steps including:

1. Calibration check of each monitor using a portable radiation calibration source.

2. Electronic calibration of all ratemeters and recorders.

3. Verification for all monitors that "Instrument Malfunction" annunciation is initiated on downscale ratemeter trip or loss of power.

4. Verification that "High Radiation" annunciation is initiated on upscale ratemeter trip.

5. Each detector is checked using its built-in check source.

Maintenance will be performed if any of the above checks indicate a malfunction. Unscheduled maintenance will be performed as required.

12.1.5 Operating Procedures Radiation protection systems and administrative controls are designed to maintain radiation doses within the site ALARA goals and within the criteria specified in 10 CFR 20 during normal operations.

Plant areas are classified into zones with varying degrees of administrative control. Allowable dose rates are based on anticipated frequencies and duration of occupancy. Dose rates and occupancy times are controlled. Table 12.1.2-1 summarizes these general classifications of plant areas.

The entrance to all zones are marked in accordance with the regulations of 10 CFR 20. To prevent inadvertent entry by personnel into high and very high radiation areas (controlled or prohibited classifications) rigid access control is maintained, including locked or barricaded doors, interlocks, and a system of local and remote alarms. Administrative control includes the use of radiation work permits, radiological control surveys, and a high or very high radiation key issued at the site radiological control (RADCON) or Shift Manager's Supervisors' office. All other less hazardous areas are properly identified in accordance with Table 12.1.2-1 with radiation work permits required when plant working guidelines for radiation dose may be approached.

SS1 2-1 .doc 12.1-12

SQN-23 A radiation work permit (RWP) is required for all work where employee doses are anticipated to exceed 50 mrem/day (deep dose equivalent). RWP's are required for contamination zones, airborne radioactivity areas, and when radiation systems are being breached. Personnel doses are tracked and each supervisor routinely informed. Personnel will be scheduled by their supervisor so that doses are in accordance with the ALARA objective.

RADCON coverage at the plant is provided as necessary in an effort to maintain radiation doses ALARA.

The general procedures have been formulated from various successful programs in use at other power reactor facilities and radioactive materials-handling facilities.

The working guidelines applied at the plant will result in radiation doses below 10 CFR 20 criteria and as such provide for a conservative approach toward assuring ALARA radiation doses.

The radiation monitors are used to enhance the radiological control program. The following statements describe the monitors and their intended use.

1. Portal monitors - The portal monitor is a radiation monitoring device for providing a visual and audible warning when radioactive contamination is detected on an individual. The monitor scans the entire body.

The portal monitors are located at the exit from the Access Control Portal and in the plant at the exit from the auxiliary building.

2. Local rate meter radiation monitors (friskers) - The local ratemeter is a small compact count rate meter operated by ac line or by a rechargeable battery. Trickle charging occurs while the unit is plugged into the line. Battery condition may be checked on the control panel.

12.1.6 Estimates of Doses Peak External Dose Rates Peak external gamma dose rates for various access types during power operations are given in Table 12.1.6-1. Peak rates given are based on operation with 1.0 percent failed fuel.

Annual Doses Personnel dose estimates are calculated annually for each fiscal year to establish site ALARA goals consistent with current industry practices and standards.

The following method is used to establish the annual personnel dose estimates. First, the work scope and the number of man-hours to be performed in each area of the plant is determined. Then by projecting radiation dose rates for these involved plant areas, an estimate is calculated by multiplying the number of hours in the area by the area dose rates. Historical dose data for similar work activities is also reviewed. By comparing the calculated and historical values, the personnel radiation dose for the upcoming fiscal year is estimated.

Non-emergency radiation doses to plant personnel are controlled by the requirements imposed by 10 CFR 20.

SS12-1 .doc 12.1-13

SQN-23 The remaining sections of FSAR subsection 12.1.6 describe personnel radiation dose estimates for plant maintenance and operational activities as calculated prior to plant operation, and are included for historical purposes only.

Estimates of yearly doses to plant nonmaintenance personnel are made by estimating the total time per year that plant personnel occupy access control areas as defined in Table 12.1.2-1. For this analysis, occupancy (man-hours/yr) in each type zone is multiplied by the estimated average dose rate (rem/hr) within the type zone to obtain the estimated man-rem/yr for occupancy in that type zone. The sum over all zone types is the estimated man-rem/yr for the Sequoyah Plant.

The estimates are based on a working time of 2000 hours0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> per year for each person considered and as such includes the dose to these persons during one refueling and during minor maintenance that they may perform during the year. The estimates follow.

Occupancy Dose Rate, Plant Dose Access Tvye* (man-hours/vr) mrem/hr man-rem/yr Unlimited access - 56,700 operators 0.1 5.67 operators continuous occupancy 20,000 others 2.00 others 76,700 total 7.67 total Unlimited access - 19,600 operators 1.0 19.60 operators intermittent occupancy 23,775 others 23.80 others 43,375 total 43.40 total Regulated access - 5,700 operators 15.0 85.50 operators Radiation area 2,225 others 33.80 others 7,925 total 119.30 total High radiation area 120 operators 200 24 operators (controlled) 330 others 66 others 450 total 90 total High radiation area 10 operators 1000 10 operators (restricted) 20 others 20 others 30 total 30 total Subtotal 82,130 operators All 144.77 operators Subtotal 46,350 others 145.60 others Grand Total 128,480 total 290.37 total

• Definitions are provided in Table 12.1.2-1.

As used in the above table, the category, "Operators," includes only the approximately 164 persons directly involved in plant operation. These persons are the manager supervisors, unit supervisors, unit operators, and assistant unit operators. The personnel category, "Others," are the other plant nonmaintenance personnel who will experience some radiation dose as a result of plant operation.

These approximately 210 persons are radiological control, radiochemistry, and other technical support personnel.

As determined from the above table, the dose per year for "Operators" is 0.88 rem/yr per man and for "Others" is 0.69 rem/yr per man. If the total man-rem dose is averaged over the total nonmaintenance SS12-1.doc 12.1-14

SQN-23 staff of approximately 600 ("Operators," "Others," and "Administrative"), the average dose is 0.48 rem/yr per man. The doses given in the table are not expected during the early years of plant operation since they are based partly on the extreme condition of operation throughout the year with 1.0 percent failed fuel. However, they could be approached after a few years as plant activated corrosion product inventory increases.

Doses to the plant employees (approximately 700), whose primary duties are maintenance activities, are explained below. There is experience available from operating plants to serve as a guide for making such predictions. The experience available does suggest that such doses (to maintenance personnel) will be a significant fraction of 10 CFR 20 limits. A value of 0.5 rem/yr to 1.0 rem/yr per maintenance man is a reasonable expectation. With increasing plant age, this dose will increase due to accumulation of corrosion product activities on process surfaces and due to increasing plant maintenance requirements.

The estimates made for yearly man-rem dose are consistent with data reported from operating PWR power plants.

12.1.7 References

1. 10 CFR 50.59 Safety Evaluation for FSAR Chapter 12 Change Request 13-V12.

2. Reactor Shielding Design Manual, Theodore Rockwell III, D. Van Nostrund Company, Incorporated, New York, New York, 1956.

3. Communication from Westinghouse Electric Corporation, TVA-87-776.

4. Deleted

5. Deleted

6. Deleted

7. Deleted

8. D. H. Charlesworth, "Water Reactor Plant Contamination and Decontamination Requirements - A Survey," conducted by the Sub- committee on Nuclear Systems, ASME Research Committee on Boiler Feedwater Studies, paper prepared for presentation at the 33rd Annual Meeting of the American Power Conference, 1971.

9. SQS2-0216, "Old Steam Generator Storage Facility Dose Assessment."

SS12-1 .doc 12.1-15

SQN-23 break is upstream of the isolation valves or one valve fails to close, the break will be isolated to three steam generators while the faulted one will continue to blow down. Only the case in which one steam generator continues to blow down is discussed here since the break followed by isolation of all steam generators will terminate the transient.

A safety injection signal (generated a few seconds after the break) will cause main feedwater isolation to occur. The only source of water available to the faulted steam generator is then the auxiliary feedwater system. Following steam line isolation, steam pressure in the steam line with the faulted steam generator will continue to fall rapidly, while the pressure stabilizes in the remaining three steam lines. The indication of the different steam pressures will be available to the operator within a few seconds of steam line isolation. This will provide the information necessary to identify the faulted steam generator so that auxiliary feedwater to it can be isolated. Manual controls are provided in the control room for start and stop of the auxiliary feedwater pumps and for the control valves associated with the auxiliary feedwater system. The means for detecting the faulted steam generator and isolation of auxiliary feedwater to it requires only the use of safety grade equipment available following the break. The removal of decay heat in the long term (following the initial cooldown) using the remaining steam generators requires only the Auxiliary Feedwater System as a water source and the secondary system safety valves and/or the power operated relief valve to relieve steam. Power to the motor driven auxiliary feedwater pumps is supplied by the onsite diesel generator units. The turbine driven AFW pump has redundant steam supplies. Flow (440 gpm) from one motor-driven auxiliary feedwater pump to one steam generator is sufficient for long term cooling.

The operator has available, in the control room, an indication of pressurizer water level from the instrumentation used in the reactor protection system. Indicated water level returns to the pressurizer in approximately five to seven minutes following the steam line break. The Operators have the procedures and equipment necessary to terminate the safety injection and gain control of the pressurizer level prior to pressurizer overfill. The pressurizer level instrumentation and manual controls for operation of the charging pumps meet the required standards for safety systems.

As indicated, the information for terminating auxiliary feedwater is available to the operator within one minute of the break while the information required for stopping the charging pumps and safety injection pump becomes available within five to seven minutes following the break. The requirements to terminate auxiliary feedwater flow to the faulted steam generator and stop the charging pumps and safety injection pumps can be met by simple switch actions by the operators, i.e., closing auxiliary feed discharge valves and stopping charging pumps and safety injection pumps. Thus, the required simple actions to limit the cooldown and depressurization can be easily recognized, planned, and performed within ten minutes. For the longer time requirements for decay heat removal and plant cooldown the operator has time on the order of hours to respond.

The worst case condition for long term cooling following a steam line break is loss of offsite power with failure of one emergency power train, since the condition requires the greatest amount of operator action and the longest time to achieve cold shutdown. However, since the plant can be maintained safely at hot standby conditions for extended periods of time, there is no safety requirement which dictates rapid achievement of cold shutdown conditions.

With only onsite power available, the plant can be maintained in a safe hot standby condition using the intact steam generators by supplying feedwater with the auxiliary feedwater system, and venting steam through the secondary side, power-operated relief valves. The relief valves will be controlled to gradually reduce pressure and temperature as the core residual heat decays. Ifthe relief valves SS15-4.doc 15.4-13

SQN-21 are not available, the safety valves will be used for steam dump. In this case, the primary system pressure would be controlled such that adequate subcooling is maintained. Primary system temperature would be maintained at that value necessary to lift the steam generator safety valves as necessary to match the decay heat from the core. This temperature would be approximately 553 F which corresponds to the lowest steam generator safety valve setpoint of 1064 psig. For either means of steam relief, the steam generator water level will be maintained within the span of the narrow range indicators.

Marqin to Critical Heat Flux A complete set of statepoints are reviewed to determine the most limiting condition. Past experience in performing DNB analyses for steam line breaks for Westinghouse cores has shown that Case B (inside break with offsite power) is always worse than Case A. Cases A and B generally have very similar temperatures and pressures, but Case B returns to a power level of 1.5 to 2 percentage points greater than Case A. It is this higher power level that makes Case B the worse of the two.

A detailed nuclear and thermal-hydraulic analysis of the limiting steam line break, Case B, statepoint (see Table 15.4.2-1) was performed. The results of the analysis show that minimum DNBR is very high. This assures that DNB will not occur and that the DNB design basis is met for the steam line break event.

15.4.2.1.3 Framatome ANP Safety Evaluation With ReDlacement Steam Generators in Unit 1 The thermal response characteristics of the transient discount a challenge to the RCS and main steam system pressure limit. RCS pressure is reduced throughout the transient in response to the excessive heat removal from the steam generators. Therefore, this event is analyzed for DNB concerns.

Two of the critical parameters that effect the system and core responses to the steam line break are 2 (primary-to-secondary) heat transfer area and break size. The OSG has a maximum area of 4.6 ft whereas, the RSG has a flow restrictor at the exit of the SG with an area of 1.42ft 2. The OSG represents an increased heat transfer area relative to the RSG. It is expected that the greater heat transfer area will increase primary heat removal but the flow restrictor will limit the increase in over-cooling. It follows that there is a potential for an increase in the return to power associated with the RSG. The Steam Line Break, therefore was reanalyzed for the RSGs utilizing identical methods described in Section 15.4.2.1.2.

The RELAP5/MOD2 analyses show that the return to power with the RSGs is slightly greater than that with the OSGs. However, the RCS pressure remains higher at the time of peak power. As a result, the LYNXT analysis showed a slightly higher margin to DNB. Therdfore, the analysis with OSGs remains bounding and applicable to Sequoyah Unit 1 with RSGs. All acceptance criteria for this event continue to be met subsequent to the installation of the RSGs.

15.4.2.2 Maior Rupture of a Main Feedwater Pipe 15.4.2.2.1 Identification of Causes and Accident Description A major feedwater line rupture is defined as a break in a feedwater pipe large enough to prevent the addition of sufficient feedwater to the steam generators to maintain shellside fluid inventory in the steam generators. If the break is postulated in a feedline between the check valve and the steam generator, fluid from the steam generator may also be discharged through the break.

SS15-4.doc 15.4-14