Text

Technical Specification Bases Changes and Ufsar/Selected Licensee Commitment Changes
	ML18043A122
Person / Time
Site:	Catawba
Issue date:	02/08/2018
From:	Simril T; Duke Energy Carolinas
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	CNS-18-005
	Download: ML18043A122 (238)
	v • d • e

,, Tom Simril e{.-,DUKE Vice President

~ ENERGY~ Catawba Nuclear Station Duke Energy CN01VP 14800 Concord Road York, SC 29745 o: 803.701.4251 f: 803. 701.3221 tom.simril@duke-energy.com CNS-18-005 10CFR 50.4 10CFR 50.71(e)

February 8, 2018 U.S. Nuclear Regulatory Commission Document Control Desk Washington, DC 20555-0001

Subject:

Duke Energy Carolinas, LLC Catawba Nuclear Station, Units 1 and 2 Docket Nos. 50-413 and 50-414 Technical Specification Bases Changes and UFSAR/Selected Licensee Commitment Changes Pursuant to 10CFR 50.4, please find attached changes to the Catawba Nuclear Station Technical Specification Bases. These Bases changes were made according to the provisions of Technical Specification 5.5.14, "Technical Specifications (TS) Bases Control Program."

Also, Pursuant to 10 CFR 50.71(e), please find attached changes to the Catawba Nuclear Station Selected Licensee Commitments Manual. This document constitutes Chapter 16 of the Updated Final Safety Analysis Report (UFSAR).

Any questions regarding this information should be directed to Tolani Owusu, Regulatory Affairs, at (803) 701-5385.

I certify that I am a duly authorized officer of Duke Energy Carolinas, LLC, and that the information contained herein accurately represents changes made to the Technical Specification Bases since the previous submittal.

Sincerely,

~~

Tom Simril Vice President, Catawba Nuclear Station

Enclosures:

1) TS Bases Insertion/Removal Instructions

2) TS LOEP and Bases Replacement Pages

3) SLC Manual Insertion/Removal Instructions

4) SLC Manual Replacement Pages WWW.duke-energy.com J

0

Catawba Nuclear Station Technical Specifications Manual and Selected Licensee Commitment Manual Amendments CNS-18-005 February 8, 2018 Page 2 xc: w/enclosures Catherine Haney, Regional Administrator U.S. Nuclear Regulatory Commission, Region II Marquis One Tower 245 Peachtree Center Ave., NE Suite 1200 Atlanta, GA 30303-1257 Mike Mahoney NRC Project Manager (CNS)

U.S. Nuclear Regulatory Commission One White Flint North, Mail Stop 08B1A 11555 Rockville Pike Rockville, MD 20852-27 46 Joseph Austin, Senior Resident Inspector Catawba Nuclear Station

Enclosure 1 TS Bases Insertion/Removal Instructions L _ __ _

Removal and insertion instructions for Catawba Nuclear Station Tech Spec Bases Changes for June 2, 2017 through January 24, 2018 .

REMOVE THESE PAGES INSERT THESE PAGES LIST OF EFFECTIVE PAGES Pages 1-18 Revision 11 (1/31/17) Pages1-18 List of Effective Pages Revisions 12-15 have been Revision 16 (1/23/18) superseded by Revision 16 (1/23/18) and therefore do not need to be replaced in your manuals.

TECHNICAL SPECIFICATIONS BASES TAB 3.0 B 3.0-1-83.0-21 B 3.0-1-83.0-21 Revision 3 Revision 4 BASES

B 3.1.2 B 3.1.2-5 Revision 2 TAB 3.1 B 3.1.2 B 3.1.2-5 Revision 3 B 3.1.8 B 3.1.8-6 B 3.1.8 B 3.1.8-6 Revision 2 Revision 3 BASES TAB 3.4 B 3.4.10 B 3.4.10-4 B 3.4.10 B 3.4.10-4 Revision 2 Revision 3 BASES TAB 3.6

B 3.6.3 B 3.6.3-14 Revision 5 B 3.6.3 B 3.6.3-14 Revision 6

B 3.6.10 B 3.6.10-6 B 3.6.10 B 3.6.10-6 Revision 2 Revision 3 BASES TAB 3.7 B 3.7.4 B 3.7.4-4 B 3.7.4 B 3.7.4-4 Revision 2 Revision 3 B 3.7.5 B 3.7.5-9 B 3.7.5 B 3.7.5-9 Revision 3 Revision 4 B 3.7.6 B 3.7.6-3 B 3.7.6 B 3.7.6-3 Revision 4 Revision 5 B 3.7.10 B 3.7.10-9 B 3.7.10 B 3.7.10-9 Revision 10 Revision 11 B 3.7.12-1-83.7.12-7 B 3.7.12 B 3.7.12-7 Revision 6 Revision 7 B 3.7.13 B 3.7.13-5 B 3. 7 .13 B 3. 7. 13-5 Revision 4 Revision 5 BASES TAB 3.8 B 3.8.1 B 3.8.1-30 B 3.8.1 B 3.8.1-30 Revision 5 Revision 6 B 3.8.4 B 3.8.4-11 B 3.8.4-1 - B 3.8.4-11 Revision 10 Revision 11 BASES TAB 3.9 B 3.9.4 B 3.9.4-6 B 3.9.4 B 3.9.4-6 Revision 5 Revision 6 B 3.9.5 B 3.9.5-5 B 3.9.5 B 3.9.5-5 Revision 4 Revision 6 TS Bases B 3.9.5-1 thru 5, Revision 5 was superseded by Revision 6 and although included in this package, does not need to be placed in your manual.

. If you have any questions concerning the contents of this Technical Specification Bases update, please contact

Toni Lowery at (803) 701-5046.

Enclosure 2 TS LOEP and Bases Replacement Pages

Catawba Nuclear Station Technical Specifications Page Number List of Effective Pages Amendments Revision Date 177/169 4/08/99 ii 219/214 3/01/05 iii 215/209 6/21/04 iv 173/165 9/30/98 1.1-1 173/165 9/30/98 1.1-2 268/264 6/25/12 1.1-3 268/264 6/25/12 1.1-4 268/264 6/25/12 1.1-5 281/277 4/29/16 1.1-6 268/264 6/25/12 1.1.7 179/171 8/13/99 1.2-1 173/165 9/30/98 1.2-2 173/165 9/30/98 1.2-3 173/165 9/30/98 1.3-1 173/165 9/30/98 1.3-2 173/165 9/30/98 1.3-3 173/165 9/30/98 1.3-4 173/165 9/30/98 1.3-5 173/165 9/30/98 1.3-6 173/165 9/30/98 1.3-7 173/165 9/30/98 1.3-8 173/165 9/30/98 1.3-9 173/165 9/30/98 1.3-10 173/165 9/30/98 1.3-11 173/165 9/30/98 1.3-12 173/165 9/30/98 1.3-13 173/165 9/30/98 1.4-1 173/165 9/30/98 1.4-2 173/165 9/30/98

.1.4-3 173/165 9/30/98 Catawba Units 1 and 2 Page 1 1/23/2018

1.4-4 2.0-1 3.0-1 3.0-2 173/165 210/204 288/284 235/231 9/30/98 12/19/03 4/26/17 3/19/07 3.0-3 235/231 3/19/07 3.0-4 288/284 4/26/17 3.0-5 235/231 3/19/07 3.0-6 235/231 3/19/07 3.1.1-1 263/259 3/29/11 3.1.2-1 296/292 10/23/17 3.1.2-2 263/259 3/29/11 3.1.3-1 173/165 9/30/98 3.1.3-2 275/271 04/14/15 3.1.3-3 173/165 9/30/98 3.1.4-1 173/165 9/30/98 3.1.4-2 173/165 9/30/98 3.1.4-3 263/259 3/29/11 3.1.4-4 263/259 3/29/11 3.1.5-1 173/165 9/30/98 3.1.5-2 263/259 3/29/11 3.1.6-1 173/165 . 9/30/98 3.1.6-2 173/165 9/30/98 3.1.6-3 263/259 3/29/11 3.1.7-1 173/165 9/30/98 3.1.7-2 173/165 9/30/98 3.1.8-1 291/287 7/26/17 3.1.8-2 263/259 3/29/11 3.2.1-1 173/165 9/30/98 3.2.1-2 173/165 9/30/98 3.2.1-3 263/259 3/29/11 3.2.1-4 263/259 3/29/11 3.2.1-5 263/259 3/29/11 3.2.2-1 173/165 9/30/98 3.2.2-2 173/165 9/30/98 Catawba Units 1 and 2 Page 2 1/23/2018

3.2.2-3 3.2.2-4 3.2.3-1 3.2.4-1 263/259 263/259 263/259 173/165 3/29/11 3/29/11 3/29/11 9/30/98 3.2.4-2 173/165 9/30/98 3.2.4-3 173/165 9/30/98 3.2.4-4 263/259 3/29/11 3.3.1-1 173/165 9/30/98 3.3.1-2 247/240 12/30/08 3.3.1-3 247/240 12/30/08 3.3.1-4 207/201 7/29/03 3.3.1-5 247/240 12/30/08 3.3.1-6 247/240 12/30/08 3.3.1-7 247/240 12/30/08 3.3.1-8 173/165 9/30/98 3.3.1-9 263/259 3/29/11 3.3.1-10 263/259 3/29/11 3.3.1-11 263/259 3/29/11 3.3.1-12 278/274 4/08/16 3.3.1-13 263/259 3/29/11 3.3.1:.14 263/259 3/29/11 .

3.3.1-15 263/259 3/29/11 3.3.1-16 278/274 4/08/16 3.3.1-17 263/259 3/29/11 3.3.1-18 263/259 3/29/11 3.3.1-19 278/274 4/08/16 3.3.1-20 263/259 3/29/11 3.3.1-21 263/259 3/29/11 3.3.1-22 263/259 3/29/11 3.3.2-1 173/165 9/30/98 3.3.2-2 247/240 12/30/08 3.3.2-3 247/240 12/30/08 3.3.2-4 247/240 12/30/08 3.3.2-5 264/260 6/13/11 Catawba Units 1 and 2 Page 3 1/23/2018

3.3.2-6 3.3.2-7 3.3.2-8 3.3.2-9 264/260 249/243 249/243 249/243 6/13/11 4/2/09 4/2/09 4/2/09 3.3.2-10 263/259 3/29/11 3.3.2-11 263/259 3/29/11 3.3.2-12 263/259 3/29/11 3.3.2-13 277/273 12/18/15 3.3.2-14 277/273 12/18/15 3.3.2-15 277/273 12/18/15 3.3.2-16 277/273 12/18/15 3.3.2-17 277/273 12/18/15 3.3.2-18 (new) 277/273 12/18/15 3.3.3-1 219/214 3/1/05 3.3.3-2 219/214 3/1/05 3.3.3-3 263/259 3/29/11 3.3.3-4 219/214 3/1/05 3.3.4-1 213/207 4/29/04 3.3.4-2 263/259 3/29/11 3.3.4-3 272/268 2/27/14 3.3.5-1 173/165 9/30/98 3.3.5-2 277/273 12/18/15 3.3.6-1 196/189 3/20/02 3.3.6-2 263/259 3/29/11 3.3.6-3 196/189 3/20/02 3.3.9-1 207/201 7/29/03 3.3.9-2 207/201 7/29/03 3.3.9-3 263/259 3/29/11 3.3.9-4 263/259 3/29/11 3.4.1-1 210/204 12/19/03 3.4.1-2 210/204 12/19/03 3.4.1-3 263/259 3/29/11 3.4.1-4 283/279 6/02/16 3.4.1-5 (deleted) 184/176 3/01/00 Catawba Units 1 and 2 Page 4 1/23/2018

3.4.1-6 (deleted) 3.4.2-1 3.4.3-1 3.4.3-2 184/176 173/165 173/165 263/259 3/01/00 9/30/98 9/30/98 3/29/11 .

3.4.3-3 281/277 4/29/16 3.4.3-4 212/206 3/4/04 3.4.3-5 281/277 4/29/16 3.4.3-6 212/206 3/4/04 3.4.4-1 263/259 3/29/11 3.4.5-1 207/201 7/29/03 3.4.5-2 207/201 7/29/03 3.4.5-3 263/259 3/29/11 3.4.6-1 212/206 3/4/04 3.4.6-2 263/259 3/29/11 3.4.6-3 282/278 4/26/17 3.4.7-1 212/206 3/4/04 3.4.7-2 263/259 3/29/11 3.4.7-3 282/278 4/26/17 3.4.8-1 207/201 7/29/03 3.4.8-2 282/278 4/26/17 3.4.9-1 173/165 9/30/98 3.4.9-2 263/259 3/29/11 3.4.10-1 294/290 10/23/17 3.4.10-2 173/165 9/30/98 3.4-11-1 213/207 4/29/04 3.4.11-2 173/165 9/30/98 3.4.11-3 263/259 3/29/11 3.4.11-4 263/259 3/29/11 3.4.12-1 212/206 3/4/04 3.4.12-2 213/207 4/29/04 3.4.12-3 212/206 3/4/04 3.4.12-4 212/206 3/4/04 3.4.12-5 263/259 3/29/11 3.4.12-6 263/259 3/29/11 Catawba Units 1 and 2 Page 5 1/23/2018

3.4.12-7 3.4.12-8 3.4.13-1 3.4.13-2 263/259 263/259 267/263 267/263 3/29/11 3/29/11 3/12/12 3/12/12 3.4.14-1 173/165 9/30/98 3.4.14-2 173/165 9/30/98 3.4.14-3 263/259 3/29/11 3.4.14-4 263/259 3/29/11 3.4.15-1 234/230 9/30/06 3.4.15-2 234/230 9/30/06 3.4.15-3 234/230 9/30/06 3.4.15-4 263/259 3/29/11 3.4.16-1 268/264 6/25/12 3.4.16-2 268/264 6/25/12 3.4.16-3(deleted) 268/264 6/25/12 3.4.1_6-4(deleted) 268/264 6/25/12 3.4.17-1 263/259 3/29/11 3.4.18-1 280/276 4/26/16 3.4.18-2 280/276 4/26/16 3.5.1-1 211/205 12/23/03 3.5.1-2 263/259 3/29/11 3.5.1-3 263/259 3/29/11 3.5.2-1 253/248 10/30/09 3.5.2-2 282/278 4/26/17 3.5.2-3 263/259 3/29/11 3.5.3-1 213/207 4/29/04 3.5.3-2 173/165 9/30/98 3.5.4-1 173/165 9/30/98 3.5.4-2 269/265 7/25/12 3.5.5-1 173/165 9/30/98 3.5.5-2 263/259 3/29/11 3.6.1-1 173/165 9/30/98 3.6.1-2 192/184 7/31/01 3.6.2-1 173/165 9/30/98 Catawba Units 1 and 2 Page 6 1/23/2018

3.6.2-2 3.6.2-3 3.6.2-4 3.6.2-5 173/165 173/165 173/165 263/259 9/30/98 9/30/98 9/30/98 3/29/11 3.6.3-1 173/165 9/30/98 3.6.3-2 290/286 7/21/17 3.6.3-3 290/286 7/21/17 3.6.3-4 290/286 7/21/17 3.6.3-5 263/259 3/29/11 3.6.3-6 263/259 3/29/11 3.6.3-7 192/184 7/31/01 3.6.4-1 263/259 3/29/11 3.6.5-1 173/165 9/30/98 3.6.5-2 263/259 3/29/11 3.6.6-1 282/278 4/26/17 3.6.6-2 282/278 4/26/17 3.6.8-1 213/207 4/29/04 3.6.8-2 263/259 3/29/11 3.6.9-1 253/248 10/30/09 3.6.9-2 263/259 3/29/11 3.6.10-1 173/165 9/30/98 3.6.10-2 289/285 5/08/17*

3.6.11-1 263/259 3/29/11 3.6.11-2 263/259 3/29/11 3.6.12-1 263/259 3/29/11 3.6.12-2 263/259 3/29/11 3.6.12-3 263/259 3/29/11 3.6.13-1 256/251 6/28/10 3.6.13-2 263/259 3/29/11 3.6.13-3 263/259 3/29/11 3.6.14-1 173/165 9/30/98 3.6.14-2 263/259 3/29/11 3.6.14-3 270/266 8/6/13 3.6.15-1 173/165 9/30/98 Catawba Units 1 and 2 Page 7 1/23/2018

3.6.15-2 3.6.16-1 3.6.16-2 3.6.17-1 263/259 263/259 263/259 253/248 3/29/11 3/29/11 3/29/11 10/30/09 3.7.1-1 173/165 9/30/98 3.7.1-2 173/165 9/30/98 3.7.1-3 281/277 4/29/16 3.7.2-1 173/165 9/30/98 3.7.2-2 244/238 9/08/08 3.7.3-1 173/165 9/30/98 3.7.3-2 244/238 9/08/08 3.7.4-1 294/290 10/23/17 3.7.4-2 263/259 3/29/11 3.7.5-1 295/291 10/23/17 3.7.5-2 173/165 9/30/98 3.7.5-3 263/259 3/29/11 3.7.5-4 263/259 3/29/11 3.7.6-1 294/290 10/23/17 3.7.6-2 263/259 3/29/11 3.7.7-1 253/248 10/30/09 3.7.7-2 263/259 3/29/11 3.7.8-1 271/267 08/09/13 3.7.8-2 271/267 08/09/13 3.7.8-3 271/267 08/09/13 3.7.8-4 271/267 08/09/13 3.7.9-1 263/259 3/29/11 3.7.9-2 263/259 3/29/11 3.7.10-1 250/245 7/30/09 3.7.10-2 260/255 8/9/10 3.7.10-3 289/285 5/08/17 3.7.11-1 198/191 4/23/02 3.7.11-2 263/259 3/29/11 3.7.12-1 253/248 10/30/09 3.7.12-.2 289/285 5/08/17 Catawba Units 1 and 2 Page 8 1/23/2018

3.7.13-1 3.7.13-2 3.7.14-1 3.7.15-1 198/191 289/285 263/259 263/259 4/23/02 5/08/17 3/29/11 3/29/11 3.7.16-1 233/229 9/27/06 3.7.16-2 233/229 9/27/06 3.7.16-3 233/229 9/27/06 3.7.17-1 263/259 3/29/11 3.8.1-1 253/248 10/30/09 3.8.1-2 173/165 9/30/98 3.8.1-3 253/248 10/30/09 3.8.1-4 173/165 9/30/98 3.8.1-5 263/259 3/29/11 3.8.1-6 263/259 3/29/11 3.8.1-7 263/259 3/29/11 3.8.1-8 263/259 3/29/11 3.8.1-9 292/288 9/08/17 3.8.1-10 263/259 3/29/11 3.8.1-11 263/259 3/29/11 3.8.1-12 292/288 9/08/17 3.8.1-13 292/288 9/08/17 3.8.1-14 292/288 9/08/17 3.8.1-15 263/259 3/29/11 3.8.2-1 173/165 9/30/98 3.8.2-2 207/201 7/29/03 3.8.2-3 173/165 9/30/98 3.8.3-1 175/167 1/15/99 3.8.3-2

263/259 3/29/11 3.8.3-3 263/259 3/29/11 3.8.4-1 173/165 9/30/98 3.8.4-2 263/259 3/29/11 3.8.4-3 292/288 9/08/17 3.8.4-4 292/288 9/08/17 3.8.4-5 262/258 12/20/10 Catawba Units 1 and 2 Page 9 1/23/2018

3.8.5-1 3.8.5-2 3.8.6-1 3.8.6-2 173/165 207/201 253/248 253/248 9/30/98 7/29/03 10/30/09 10/30/09 3.8.6-3 253/248 10/30/09 3.8.6-4 263/259 3/29/11 3.8.6-5 223/218 4/27/05 3.8.7-1 173/165 9/30/98 3.8.7-2 263/259 3/29/11 3.8.8-1 173/165 9/30/98 3.8.8-2 263/259 3/29/11 3.8.9-1 173/165 9/30/98 3.8.9-2 173/165 9/30/98 3.8.9-3 263/259 3/29/11 3.8.10-1 207/201 7/29/03 3.8.10-2 263/259 3/29/11 3.9.1-1 263/259 3/29/11 3.9.2-1 215/209 6/21/04 3.9.2-2 263/259 3/29/11 3.9.3-1 227/222 9/30/05 3.9:3-2 263/259 3/29/11 3.9.4-1 207/201 7/29/03 3.9.4-2 297/293 1/4/18 3.9.5-1 293/289 9/29/17 3.9.5-2 297/293 1/4/18 3.9.6-1 263/259 3/29/11 3.9.7-1 263/259 3/29/11 4.0-1 284/280 6/21/16 4.0-2 233/229 9/27/06 5.1-1 273/269 2/12/15 5.2-1 273/269 2/12/15 5.2-2 273/269 2/12/15 5.2-3 Deleted 9/21/09 5.3-1 273/269 2/12/15 Catawba Units 1 and 2 Page 10 1/23/2018

5.4-1 5.5-1 5.5-2 5.5-3 173/165 286/282 286/282 173/165 9/30/98 9/12/16 9/12/16 9/30/98 5.5-4 173/165 9/30/98 5.5-5 216/210 8/5/04 5.5-6 280/276 4/26/16 5.5-7 280/276 4/26/16 5.5-7a 280/276 4/26/16 5.5-8 280/276 4/26/16 5.5-9 280/276 4/26/16 5.5-10 280/276 4/26/16 5.5-11 280/276 4/26/16 5.5-12 280/276 4/26/16 5.5-13 280/276 4/26/16 5.5-14 280/276 4/26/16 5.5-15 280/276 4/26/16 5.5-16 280/276 4/26/16 5.5-17 280/276 4/26/16 5.5-18 280/276 4/26/16 5.5-19 280/276 4/26/16 5.6-1 222/217 3/31/05 5.6-2 253/248 10/30/09 5.6-3 222/217 3/31/05 5.6-4 284/280 6/21/16 5.6-5 275/271 4/14/15 5.6-6 280/276 4/26/16 5.7-1 273/269 2/12/15 5.7-2 173/165 9/30/98

Catawba Units 1 and 2 Page 11 1/23/2018

ii iii BASES Revision 1 Revision 2 Revision 1 4/08/99 3/01/05 6/21/04 B 2.1.1-1 Revision 0 9/30/98 B 2.1.1-2 Revision 1 12/19/03 B 2.1.1-3 Revision 1 12/19/03 B2.1.2-1 Revision 0 9/30/98 B 2.1.2-2 Revision 0 9/30/98 B 2.1.2-3 Revision 0 9/30/98 B 3.0-1 thru B Revision 4 8/24/17 3.0-21 B 3.1.1-1 thru Revision 3 5/05/11 B 3.1.1-6 B 3.1.2-1 thru Revision 3 11/14/17 B 3.1.2-5 B 3.1.3-1 thru Revision 2 4/14/15 B 3.1.3-6 B 3.1.4-1 thru Revision 1 5/05/11 B 3.1.4-9 B 3.1.5-1 thru Revision 2 5/05/11 B 3.1.5-4 B 3.1.6-1 thru Revision 1 5/05/11 B 3.1.6-6 B3.1.7-1 Revision 0 9/30/98 B 3.1.7-2 Revision 2 1/08/04 B 3.1.7-3 Revision 2 1/08/04 B3.1.7-4 Revision 2 1/08/04 B 3.1.7-5 Revision 2 1/08/04 B 3.1.7-6 Revision 2 1/08/04 B 3.1.8-1 thru Revision 3 11/14/17 B 3.1.8-6 B 3.2.1-1 thru Revision 4 5/05/11 B 3.2.1.-11 Catawba Units 1 and 2 Page 12 1/23/2018

B 3.2.2-1 thru B 3.2.2-10 B 3.2.3-1 thru B 3.2.3-4 Revision 3 Revision 2 5/05/11 5/05/11 B 3.2.4-1 thru Revision 2 5/05/11 B 3.2.4-7 B 3.3.1-1 thru Revision 8 4/08/16 B.3.3.1-55 B 3.3.2-1 thru Revision 12 12/18/15 B 3.3.2-50 B 3.3.3-1 thru Revision 6 4/11/14 B.3.3.3-16 B 3.3.4-1 thru Revision 2 5/05/11 B 3.3.4-5 B 3.3.5-1 thru Revision 3 12/18/15 B 3.3.5-6 B 3.3.6-1 thru Revision 6 08/02/12 B 3.3.6-5 B 3.3.9-1 thru Revision 3 06/02/14 B 3.3.9-5 B 3.4.1-1 thru Revision 3 5/05/11 B 3.4.1-5 B 3.4.2-1 Revision 0 9/30/98 B 3.4.2-2 Revision 0 9/30/98 B 3.4.2-3 Revision 0 9/30/98 B 3.4.3-1 thru Revision 2 5/05/11 B 3.4.3-6

B 3.4.4-1 thru Revision 2 5/05/11 B 3.4.4-3 B 3.4.5-1 thru Revision 3 5/05/11 B 3.4.5-6 B 3.4.6-1 thru Revision 5 4/26/17 B 3.4.6-6

Catawba Units 1 and 2 Page 13 1/23/2018

B 3.4.7-1 thru B 3.4.7-7 B 3.4.8-1 thru B 3.4.8-4 Revision 7 Revision 4 4/26/17 4/26/17 B 3.4.9-1 thru Revision 3 08/02/12 B 3.4.9-5 B 3.4.10-1 thru Revision 3 11/14/17 B 3.4.10-4 B 3.4.11-1 thru Revision 4 5/05/11 B 3.4.11-7 B 3.4.12-1 thru Revision 5 8/19/15 B 3.4.12-14 B 3.4.13-1 thru Revision 7 3/15/12 B 3.4.13-7 B 3.4.14-1 thru Revision 3 5/05/11 B 3.4.14-6 B 3.4.15-1 thru B Revision 6 5/05/11 3.4.15-10 B 3.4.16-1 thru Revision 4 10/23/12 B 3.4.16-5 B 3.4.17-1 thru Revision 2 5/05/11 B 3.4.17-3 B 3.4.18-1 thru Revision 2 4/26/16 B 3.4.18-8 B 3.5.1-1 thm Revision 4 4/26/17 B 3.5.1-8 B 3.5.2-1 thru Revision 4 4/26/17 B 3.5.2-11 B 3.5.3-1 thru Revision 2 4/26/17 B 3.5.3-3 B 3.5.4-1 thru Revision 5 4/11/14 B.3.5.4-5 B 3.5.5-1 thru Revision 1 5/05/11 B 3.5.5-4 Catawba Units 1 and 2 Page 14 1/23/2018

B 3.6.1-1 B 3.6.1-2 B 3.6.1-3 B 3.6.1-4 Revision 1 Revision 1 Revision 1 Revision 1 7/31/01 7/31/01 7/31/01 7/31/01 B 3.6.1-5 Revision 1 7/31/01 B 3.6.2-1 thru Revision 2 5/05/11 B 3.6.2-8 B 3.6.3-1 thru Revision 6 10/30/17 B 3.6.3-14 B 3.6.4-1 thru Revision 2 5/05/11 B 3.6.4-4 B 3.6.5-1 thru Revision 3 07/27/13 B 3.6.5-4 B 3.6.6-1 thru Revision 7 4/26/17 B 3.6.6-8 B 3.6.8-1 thru Revision 3 5/05/11 B 3.6.8-5 B 3.6.9-1 thru Revision 6 5/05/11 B 3.6.9-5 B 3.6.10-1 thru Revision 3 9/05/17 B 3.6.10-6 B 3.6.11-1 thru Revision 5 5/05/11 B 3.6.11-6 B 3.6.12-1 thru Revision 5 5/05/11 B 3.6.12-11 B 3.6.13-1 thru B Revision 4 5/05/11 3.6.13-9 B 3.6.14-1 thru Revision 2 4/11/14 B 3.6.14-5 B 3.6.15-1 thru Revision 1 5/05/11 B 3.6.15-4 B 3.6.16-1 thru Revision 3 5/05/11 B 3.6.16-4 B 3.6.17-1 Revision 1 3/13/08 Catawba Units 1 and 2 Page 15 1/23/2018

B 3.6.17-2 B 3.6.17-3 B 3.6.17-4 B 3.6.17-5 Revision 0 Revision 0 Revision 0 Revision 1 9/30/98 9/30/98 9/30/98 3/13/08 B 3.7.1-1 thru Revision 2 4/29/16 3.7.1-5 B 3.7.2-1 Revision 0 9/30/98 B 3.7.2-2 Revision O 9/30/98 B 3.7.2-3 Revision 2 6/23/10 B 3.7.2-4 Revision 1 9/08/08 B 3.7.2-5 Revision 3 10/30/09 B 3.7.3-1 Revision 0 9/30/98 B 3.7.3-2 Revision 0 9/30/98 B 3.7.3-3 Revision 0 9/30/98 B 3.7.3-4 Revision 0 9/30/98 B 3.7.3-5 Revision 1 9/08/08 B 3.7.3-6 Revision 2 10/30/09 B 3.7.4-1 thru Revision 3 11/14/17 B 3.7.4-4 B 3.7.5-1 thru Revision 4 11/14/17 B 3.7.5-9 B 3.7.6-1 thru Revision 5 11/14/17 B 3.7.6-3 B 3.7.7-1 thru Revision 2 5/05/11 B 3.7.7-5 B 3.7.8-1 thru Revision 5 8/09/13 B 3.7.8-8 B 3.7.9-1 thru Revision 3 5/05/11 B 3.7.9-4 B 3.7.10-1 thru B Revision 11 9/05/17 3.7.10-9 B 3.7.11-1 thru Revision 3 10/24/11 83.7.11-4

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8 3.7.12-1 thru 8 3.7.12-7 8 3.7.13-1 thru 8 3.7.13-5 Revision 7 Revision 5 9/05/17 9/05/17 8 3.7.14-1 thru Revision 2 5/05/11 8 3.7.14-3 8 3.7.15-1 thru Revision 2 5/05/11 8 3.7.15-4 8 3.7.16-1 Revision 2 9/27/06 8 3.7.16-2 Revision 2 9/27/06 8 3.7.16-3 Revision 2 9/27/06 8 3.7.16-4 Revision 0 9/27/06 8 3.7.17-1 thru Revision 2 5/05/11 8 3.7.17-3 8 3.8.1-1 thru Revision 6 10/30/17 8.3.8.1-30 8 3.8.2-1 Revision 0 9/30/98 8 3.8.2-2 Revision O 9/30/98 8 3.8.2-3 Revision 0 9/30/98 8 3.8.2-4 Revision 1 5/10/05 8 3.8.2-5 Revision 2 5/10/05 8 3.8.2-6 Revision 1 5/10/05 8 3.8.3-1 thru Revision 4 5/05/11 8 3.8.3-8 8 3.8.4-1 thru Revision 11 10/30/17 83.8.4.11 8 3.8.5-1 Revision 0 9/30/98 8 3.8.5-2 Revision 2 7/29/03 8 3.8.5-3 Revision 1 7/29/03 8 3.8.6-1 thru Revision 4 5/05/11 8 3.8.6-7 8 3.8.7-1 thru Revision 3 5/05/11 8 3.8.7-4

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B 3.8.8-1 thru B 3.8.8-4 B 3.8.9-1 thru B 3.8.9-10 Revision 3 Revision 2 5/05/11 5/05/11 B 3.8.10-1 thru Revision 3 5/05/11 B 3.8.10-4 B 3.9.1-1 thru Revision 3 5/05/11 B 3.9.1-4 B 3.9.2-1 thru Revision 6 3/21/17 B 3.9.2-3 B 3.9.3-1 thru Revision 4 5/05/11 B 3.9.3-5 B 3.9.4-1 thru Revision 6 1/23/18 B 3.9.4-6 B 3.9.5-1 thru Revision 6 1/23/18 B 3.9.5-5 B 3.9.6-1 thru Revision 2 5/05/11 B 3.9.6-3 B 3.9.7-1 thru Revision 1 5/05/11 B 3.9.7-3

- Catawba Units 1 and 2 Page 18 1/23/2018

LCO Applicability B 3.0

B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY BASES LCOs LCO 3.0.1 through LCO 3.0.10 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated.

LCO 3.0.1 LCO 3.0.1 establishes the Applicability statement within each individual Specification as the requirement for when the LCO is required to be met (i.e., when the unit is in the MODES or other specified conditions of the Applicability statement of each Specification).

LCO 3.0.2 LCO 3.0.2 establishes that upon discovery of a failure to meet an LCO, the associated ACTIONS shall be met. The Completion Time of each Required Action for an ACTIONS Condition is applicable from the point in time that an ACTIONS Condition is entered. The Required Actions establish those remedial measures that must be taken within specified Completion Times when the requirements of an LCO are not met. This Specification establishes that:

a. Completion of the Required Actions within the specified Completion Times constitutes compliance with a Specification; and

b. Completion of the Required Actions is not required when an LCO is met within the specified Completion Time, unless otherwise specified.

There are two basic types of Required Actions. The first type of Required Action specifies a time limit in which the LCO must be met. This time limit is the Completion Time to restore an inoperable system or component to OPERABLE status or to restore variables to within specified limits. If this type of Required Action is not completed within the specified Completion Time, a shutdown may be required to place the unit in a MODE or condition in which the Specification is not applicable.

(Whether stated as a Required Action or not, correction of the entered Condition is an action that may always be considered upon entering ACTIONS.) The second type of Required Action specifies the remedial measures that permit continued operation of the unit that is not further restricted by the Completion Time. In this case, compliance with the Required Actions provides an acceptable level of safety for continued operation .

Catawba Units 1 and 2 B 3.0-1 Revision No. 4

LCO Applicability B 3.0 BASES LCO 3.0.2 (continued)

Completing the Required Actions is not required when an LCO is met or is no longer applicable, unless otherwise stated in the individual Specifications.

The nature of some Required Actions of some Conditions necessitates that, once the Condition is entered, the Required Actions must be completed even though the associated Conditions no longer exist. The individual LCO's ACTIONS specify the Required Actions where this is the case. An example of this is in LCO 3.4.3, "RCS Pressure and Temperature (PIT) Limits."

The Completion Times of the Required Actions are also applicable when a system or component is removed from service intentionally. The reasons for intentionally relying on the ACTIONS include, but are not limited to, performance of Surveillances, preventive maintenance, corrective maintenance, modifications, or investigation of operational problems. Entering ACTIONS for these reasons must be done in a manner that does not compromise safety. Intentional entry into ACTIONS should not be made for operational convenience. Alternatives that would not result in redundant equipment being inoperable should be used instead. Doing so limits the time both subsystems/trains of a safety

function are inoperable and limits the time other conditions exist which result in LCO 3.0.3 being entered. Individual Specifications may specify a time limit for performing an SR when equipment is removed from service or bypassed for testing. In this case, the Completion Times of the Required Actions are applicable when this time limit expires, if the equipment remains removed from service or bypassed.

When a change in MODE or other specified condition is required to comply with Required Actions, the unit may enter a MODE or other specified condition in which another Specification becomes applicable. In this case, the Completion Times of the associated Required Actions would apply from the point in time that the new Specification becomes applicable, and the ACTIONS Condition(s) are entered.

Catawba Units 1 and 2 B 3.0-2 Revision No. 4

LCO Applicability B 3.0

BASES LCO 3.0.3 LCO 3.0.3 establishes the actions that must be implemented when an LCO is not met and:

a. An associated Required Action and Completion Time is not met and no other Condition applies; or

b. The condition of the unit is not specifically addressed by the associated ACTIONS. This means that no combination of Conditions stated in the ACTIONS can be made that exactly corresponds to the actual condition of the unit. Sometimes, possible combinations of Conditions are such that entering LCO 3.0.3 is warranted; in such cases, the ACTIONS specifically

.state a Condition corresponding to such combinations and also that LCO 3.0.3 be entered immediately.

This Specification delineates the time limits for placing the unit in a safe MODE or other specified condition when operation cannot be maintained within the limits for safe operation as defined by the LCO and its ACTIONS. It is not intended to be used as an operational convenience that permits routine voluntary removal of redundant systems or components from service in lieu of other alternatives that would not result in redundant systems or components being inoperable. *

Upon entering LCO 3.0.3, 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to prepare for an orderly shutdown before initiating a change in unit operation. This includes time to permit the operator to coordinate the reduction in electrical generation with the load dispatcher to ensure the stability and availability of the electrical grid. The LCO phrase, "Action shall be initiated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ... "

does not mean that an actual change in load must be commenced by the end of the 1-hour period (Reference 1). The action initiated* at the end of the 1-hour period may be administrative in nature, such as preparing shutdown procedures. If at the end of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , corrective measures which would allow exiting LCO 3.0.3 are not complete, but there is reasonable assurance that they will be completed with enough time remaining to still allow for an orderly unit shutdown, if required, commencing a load decrease may be delayed until that time. The time limits specified to reach lower MODES of operation permit the shutdown to proceed in a controlled and orderly manner that is well within the specified maximum cooldown rate and within the capabilities of the unit, assuming that only the minimum required equipment is OPERABLE. This reduces thermal stresses on components of the Reactor Coolant System and the potential for a plant upset that could challenge safety systems under conditions to which this Specification applies. The use and interpretation of specified times to complete the actions of LCO 3.0.3 are consistent with the discussion of Section 1.3, Completion Times .

Catawba Units 1 and 2 B 3.0-3 Revision No. 4

LCO Applicability B 3.0 BASES LCO 3.0.3 (continued)

A unit shutdown required in accordance with LCO 3.0.3 may be terminated and LCO 3.0.3 exited if any of the following occurs:

a. The LCO is now met.

b. A Condition exists for which the Required Actions have now been performed.

c. ACTIONS exist that do not have expired Completion Times. These Completion Times are applicable from the point in time that the Condition is initially entered and not from the time LCO 3.0.3 is exited.

The time limits of Specification 3.0.3 allow 37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months for the unit to be in MODE 5 when a shutdown is required during MODE 1 operation. If the unit is in a lower MODE of operation when a shutdown is required, the time limit for reaching the next lower MODE applies. If a lower MODE is reached in less time than allowed, however, the total allowable time to reach MODE 5, or other applicable MODE, is not reduced. For example, if MODE 3 is reached in 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , then the time allowed for reaching MODE 4 is the next 11 hours1.273148e-4 days 0.00306 hours 1.818783e-5 weeks 4.1855e-6 months , because the total time for reaching

MODE 4 is not reduced from the allowable limit of 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months . Therefore, if remedial measures are completed that would permit a return to MODE 1, a penalty is not incurred by having to reach a lower MODE of operation in less than the total time allowed.

In MODES 1, 2, 3, and 4, LCO 3.0.3 provides actions for Conditions not covered in other Specifications. *The requirements of LCO 3.0.3 do not apply in MODES 5 and 6 because the unit is already in the most restrictive Condition required by LCO 3.0.3. The requirements of LCO 3.0.3 do not apply in other specified conditions of the Applicability (unless in MODE 1, 2, 3, or 4) because the ACTIONS of individual Specifications sufficiently define the remedial measures to be taken.

Catawba Units 1 and 2 B 3.0-4 Revision No. 4 **

LCO Applicability B 3.0

BASES LCO 3.0.3 (continued)

Exceptions to LCO 3.0.3 are provided in instances where requiring a unit shutdown, in accordance with LCO 3.0.3, would not provide appropriate remedial measures for the associated condition of the unit. An example of this is in LCO 3.7.14, "Spent Fuel Pool (SFP) Water Level."

LCO 3.7.14 has an Applicability of "During movement of irradiated fuel assemblies in the spent fuel pool." Therefore, this LCO can be applicable in any or all MODES. If the LCO and the Required Actions of LCO 3.7.14 are not met while in MODE 1, 2, or 3, there is no safety benefit to be gained by placing the unit in a shutdown condition. The Required Action of LCO 3.7.14 of "Suspend movement of irradiated fuel assemblies in the spent fuel pool" is the appropriate Required Action to complete in lieu of the actions of LCO 3.0.3. These exceptions are addressed in the individual Specifications.

LCO 3.0.4 LCO 3.0.4 establishes limitations on changes in MODES or other specified conditions in the Applicability when an LCO is not met. It allows placing the unit in a MODE or other specified condition stated in that Applicability (e.g., the Applicapility desired to be entered) when unit conditions are such that the requirements of the LCO would not be met,

in accordance with LCO 3.0.4.a, LCO 3.0.4.b, or LCO 3.0.4.c .

LCO 3.0.4.a allows entry into a MODE or other specified condition in the Applicability with the LCO not met when the associated ACTIONS to be entered permit continued operation in the MODE or other specified condition in the Applicability for an unlimited period of time. Compliance with Required Actions that permit continued operation of the unit for an unlimited period of time in a MODE or other specified condition provides an acceptable level of safety for continued operation. This is without regard to the status of the unit before or after the MODE change.

Therefore, in such cases, entry into a MODE or other specified condition in the Applicability may be made in accordance with the provisions of the Required Actions.

LCO 3.0.4.b allows entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, consideration of the results, determination of the acceptability of entering the MODE or other specified condition in the Applicability, and establishment of risk management actions, if appropriate .

Catawba Units 1 and 2 B 3.0-5 Revision No. 4

LCO Applicability B 3.0 BASES LCO 3.0.4 (continued)

The risk assessment may use quantitative, qualitative, or blended approaches, and the risk assessment will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR 50.65(a)(4), which requires that risk impacts of maintenance activities be assessed and managed. The risk assessment, for the purposes of LCO 3.0.4.b, must take into account all inoperable Technical Specification equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)(4) risk assessment scope. The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." Regulatory Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." These documents address general guidance for conduct of the risk assessment, quantitative and qualitative guidelines for establishing risk management actions, and example risk management actions. These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of backup success paths or compensatory measures), and determination

that the proposed MODE change is acceptable. Consideration should also be given to the probability of completing restoration such that the requirements of the LCO would be met prior to the expiration of ACTIONS Completion Times that would require exiting the Applicability.

LCO 3.0.4.b may be used with single, or multiple systems and components unavailable. NUMARC 93-01 provides guidance relative to consideration of simultaneous unavailability of multiple systems and components.

The results of the risk assessment shall be considered in determining the acceptability of entering the MODE or other specified condition in the Applicability, and any corresponding risk management actions. The LCO 3.0.4.b risk assessments do not have to be documented.

Catawba Units 1 and 2 B 3.0-6 Revision No. 4

LCO Applicability B 3.0

BASES LCO 3.0.4 (continued)

The Technical Specifications allow continued operation with equipment unavailable in MODE 1 for the duration of the Completion Time. Since this is allowable, and since in general the risk impact in that particular MODE bounds the risk of transitioning into and through the applicable MODES or other specified conditions in the Applicability of the LCO, the use of the LCO 3.0.4.b allowance should be generally acceptable, as long as the risk is assessed and managed as stated above. However, there is a small subset of systems and components that have been determined to be more important to risk and use of the LCO 3.0.4.b allowance is prohibited. The LCOs governing these systems and components contain Notes prohibiting the use of LCO 3.0.4.b by stating that LCO 3.0.4.b is not applicable.

LCO 3.0.4.c allows entry into a MODE or other specified condition in the Applicability with the LCO not met based on a Note in the Specification which states LCO 3.0.4.c is applicable. These specific allowances permit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not provide for continued operation for an unlimited period of time and a risk assessment has not been performed. This allowance may apply to all the ACTIONS or to a

specific Required Action of a Specification. The risk assessments performed to justify the use of LCO 3.0.4.b usually only consider systems and components. For this reason, LCO 3.0.4.c is typically applied to Specifications which describe values and parameters (e.g., RCS Specific Activity).

The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

The provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, MODE 3 to MODE 4, and MODE 4 to MODE 5 .

Catawba Units 1 and 2 B 3.0-7 Revision No. 4

LCO Applicability B 3.0 BASES LCO 3.0.4 (continued)

Upon entry into a MODE or other specified condition in the Applicability with the LCO not met, LCO 3.0.1 and LCO 3.0.2 require entry into the applicable Conditions and Required Actions until the condition is resolved, until the LCO is met, or until the unit is not within the Applicability of the Technical Specification.

Surveillances do not have to be performed on the associated inoperable equipment (or on variables outside the specified limits), as permitted by SR 3.0.1. Therefore, utilizing LCO 3.0.4 is not a violation of SR 3.0.1 or SR 3.0.4 for any Surveillances that have not been performed on inoperable equipment. However, SRs must be met to ensure OPERABILITY prior to declaring the associated equipment OPERABLE (or variable within limits) and restoring compliance with the affected LCO.

LCO 3.0.5 LCO 3.0.5 establishes the allowance for restoring equipment to service under administrative controls when it has been removed from service or declared inoperable to comply with ACTIONS. The sole purpose of this Specification is to provide an exception to LCO 3.0.2 (e.g., to not comply with the applicable Required Action(s)) to allow the performance of SRs to demonstrate:

a. The OPERABILITY of the equipment being returned to service; or

b. The OPERABILITY of other equipment.

The administrative controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the allowed SRs. This Specification does not provide time to perform any other preventive or corrective maintenance.

An example of demonstrating the OPERABILITY of the equipment being returned to service is reopening a containment isolation valve that has been closed to comply with Required Actions and must be reopened to perform the SRs.

An example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to prevent the trip function from occurring during the performance of an SR on another channel in the other trip system. A similar example of demonstrating the OPERABILITY of other equipment is taking an inoperable channel or trip system out of the tripped condition to permit the logic to function and indicate the appropriate response during the performance of an SR on another channel in the same trip system.

Catawba Units 1 and 2 B 3.0-8 Revision No. 4

LCO Applicability B 3.0

BASES LCO 3.0.6 LCO 3.0.6 establishes an exception to LCO 3.0.2 for support systems that have an LCO specified in the Technical Specifications (TS). This exception is provided because LCO 3.0.2 would require that the Conditions and Required Actions of the associated inoperable supported system LCO be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the unit is maintained in a safe condition are specified in the support system LCO's Required Actions. These Required Actions may include entering the supported system's Conditions and Required Actions or may specify other Required Actions.

When a support system is inoperable and there is an LCO specified for it in the TS, the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' LCOs' Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the

. unit is maintained in a safe condition in the support system's Required Actions. * *

- However, there are instances where a support system's Required Action may either direct a supported system to be declared inoperable or direct entry into Conditions and Required Actions for the supported system.

This may occur immediately or after some specified delay to perform some other Required Action. Regardless of whether it is immediate or after some delay, when a support system's Required Action directs a supported system to be declared inoperable or directs entry into Conditions and Required Actions for a supported system, the applicable Conditions and Required Actions shall be entered in accordance with LCO 3.0.2.

Specification 5.5.15, "Safety Function Determination Program (SFDP),"

ensures loss of safety function is detected and appropriate actions are taken. Upon entry into LCO 3.0.6, an evaluation shall be made to determine if loss of safety function exists. Additionally, other limitations, remedial actions, or compensatory actions may be identified as a result of the support system inoperability and corresponding exception to entering supported system Conditions and Required Actions. The SFDP implements the requirements of LCO 3.0.6 .

Catawba Units 1 and 2 B 3.0-9 Revision No. 4

LCO Applicability B 3.0 BASES LCO 3.0.6 (continued)

Cross train checks to identify a loss of safety function for those support systems that support multiple and redundant safety systems are required.

The cross train check verifies that the supported systems of the redundant OPERABLE support system are OPERABLE, thereby ensuring safety function is retained. If this evaluation determines that a loss of safety function exists, the appropriate Conditions and Required Actions of the LCO in which the loss of safety function exists are required to be entered.

LCO 3.0.7 There are certain special tests and operations required to be performed at various times over the life of the unit. These special tests and operations are necessary to demonstrate select unit performance characteristics, to perform special maintenance activities, and to perform special evolutions. Test Exception LCOs 3.1.8 and 3.4.17 allow specified Technical Specification (TS) requirements to be changed to permit performances of these special tests and operations, which otherwise could not be performed if required to comply with the requirements of these TS. Unless otherwise specified, .all the other TS requirements remain unchanged. This will ensure all appropriate requirements of the MODE or other specified condition not directly associated with or required to be changed to perform the special test or operation will remain in effect.

The Applicability of a Test Exception LCO represents a condition not necessarily in compliance with the normal requirements of the TS.

Compliance with Test Exception LCOs is optional. A special operation may be performed either under the provisions of the appropriate Test Exception LCO or under the other applicable TS requirements. If it is desired to perform the special operation under the provisions of the Test Exception LCO, the requirements of the Test Exception LCO shall be followed.

Catawba Units 1 and 2 B 3.0-10 Revision No. 4

LCO Applicability B 3.0

BASES LCO 3.0.8 LCO 3.0.8 establishes conditions under which systems are considered to remain capable of performing their intended safety function when associated snubbers are not capable of providing their associated support function(s). This LCO states that the supported system is not considered to be inoperable solely due to one or more required snubbers not capable of performing their associated support function(s). This is appropriate because a limited length of time is allowed for maintenance, testing, or repair of one or more required snubbers not capable of performing their associated support function(s) and appropriate compensatory measures are specified in the snubber requirements, which are located outside of the Technical Specifications (TS) under licensee control. The snubber requirements do not meet the criteria in 10 CFR 50.36(c)(2)(ii), and, as such, are appropriate for control by the licensee.

If the allowed time expires and the required snubber(s) are unable to perform their associated support function(s), the affected supported system's LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3.0.2.

LCO 3.0.8.a applies when one or more required snubbers are not capable of providing their associated support function(s) to a single train

or subsystem of a multiple train or subsystem supported system or to a single train or subsystem supported system. LCO 3.0.8.a allows 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to restore the required snubber(s) before declaring the supported system inoperable. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the required snubber(s) are not capable of performing their associated support function and due to the availability of the redundant train of the supported system.

LCO 3.0.8.b applies when one or more required snubbers are not capable of providing their associated support function(s) to more than one train or subsystem of a multiple train or subsystem supported system. LCO 3.0.8.b allows 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to restore the required snubber(s) before declaring the supported system inoperable. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the required snubber(s) are not capable of performing their associated support function .

Catawba Units 1 and 2 B 3.0-11 Revision No. 4

LCO Applicability B 3.0 BASES LCO 3.0.8 (continued)

LCO 3.0.8 requires that risk be assessed and managed. Industry and NRC guidance on the implementation of 10 CFR 50.65(a)(4) (the Maintenance Rule) does not address seismic risk. However, use of LCO 3.0.8 should be considered with respect to other plant maintenance activities, and integrated into the existing Maintenance Rule process to the extent possible so that maintenance on any unaffected train or subsystem is properly controlled, and emergent issues are properly addressed. The risk assessment need not be quantified, but may be a qualitative awareness of the vulnerability of systems and components when one or more required snubbers are not able to perform their

associated support function.

LCO 3.0.9 LCO 3.0.9 delineates the applicability of each specification to Unit 1 and Unit 2 operations.

LCO 3.0.10 LCO 3.0.10 establishes conditions under which systems described in the Technical Specifications are considered to remain OPERABLE when required barriers are not capable of providing their related support function(s).

As stated in NEI 04-08, "Allowance for Non Technical Specification Barrier Degradation on Supported System OPERABILITY (TSTF-427)

Industry Implementation Guidance," March 2006, if the inability of a barrier to perform its support function does not render a supported system governed by the Technical Specifications inoperable (see NRC Regulatory Issues Summary 2001-09, Control of Hazard Barriers, dated April 2, 2001 ), the provisions of LCO 3.0.10 are not necessary, as the supported system is Operable ..

Barriers are doors, walls, floor plugs, curbs, hatches, installed structures or components, or other devices, not explicitly described in Technical Specifications, that support the performance of the safety function of systems described in the Technical Specifications. This LCO states that the supported system is not considered to be inoperable solely due to required barriers not capable of performing their related support function(s) under the described conditions. LCO 3.0.10 allows 30 days before declaring the supported system(s) inoperable and the LCO(s) associated with the supported system(s) not met. A maximum time is placed on each use of this allowance to ensure that as required barriers are found or are otherwise made unavailable, they are restored.

However, the allowable duration may be less than the specified maximum time based on the risk assessment.

Catawba Units 1 and 2 B 3.0-12 Revision No. 4,

LCO Applicability B 3.0

BASES LCO 3.0.10 (continued)

If the allowed time expires and the barriers are unable to perform their related support function(s), the supported system's LCO(s) must be declared not met and the Conditions and Required Actions entered in accordance with LCO 3.0.2.

This provision does not apply to barriers which support ventilation systems or to fire barriers. The Technical Specifications for ventilation systems provide specific Conditions for inoperable barriers. Fire barriers are addressed by other regulatory requirements and associated plant programs. This provision does not apply to barriers which are not required to support system OPERABILITY (see NRC Regulatory Issue Summary 2001-09, "Control of Hazard Barriers," dated April 2, 2001).

The provisions of LCO 3.0.10 are justified because of the low risk associated with required barriers not being capable of performing their related support function. This provision is based on consideration of the following initiating event categories:

Loss of coolant accidents;

High energy line breaks; Feedwater line breaks; Internal flooding; External flooding; Turbine missile ejection; and Tornado or high wind.

The risk impact of the barriers which cannot perform their related support function(s) must be addressed pursuant to the risk assessment and management provision of the Maintenance Rule, 10 CFR 50.65 (a)(4),

and the associated implementation guidance, Regulatory Guide 1.160, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."

Regulatory Guide 1.160 endorses the guidance in Section 11 of NUMARC 93-01, Revision 4A, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." This guidance provides for the consideration of dynamic plant configuration issues, emergent conditions, and other aspects pertinent to plant operation with the barriers unable to perform their related support function(s). These considerations may result in risk management and other compensatory actions being required during the period that barriers are unable to perform their related support function(s).

LCO 3.0.10 may be applied to one or more trains or subsystems of a system supported by barriers that cannot provide their related support function(s), provided that risk is assessed and managed (including consideration of the effects on Large Early Release and from external

Catawba Units 1 and 2 B 3.0-13 Revision No. 4

LCO Applicability B 3.0 BASES LCO 3.0.10 (continued) events). If applied concurrently to more than one train or subsystem of a multiple train or subsystem supported system, the barriers supporting each of these trains or subsystems must provide their related support function(s) for different categories of initiating events. For example, LCO 3.0.10 may be applied for up to 30 days for more than one train of a multiple train supported system if the affected barrier for one train protects against internal flooding and the affected barrier for the other train protects against tornado missiles. In this example, the affected barrier may be the same physical barrier but serve different protection functions for each train. If during the time that LCO 3.0.10 is being used, the required OPERABLE train or subsystem becomes inoperable, it must be restored to OPERABLE status within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . Otherwise, the train(s) or subsystem(s) supported by barriers that cannot perform their related support function(s) must be declared inoperable and the associated LCOs declared not met. This 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period provides time to respond to emergent conditions that would otherwise likely lead to entry into LCO 3.0.3 and a rapid plant shutdown, which is not justified given the low probability of an initiating event which would require the barrier(s) not capable of performing their related support function(s).

During this 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period, the plant risk associated with the existing conditions is assessed and managed in accordance with 10 CFR 50.65(a)(4).

Catawba Units 1 and 2 B 3.0-14 Revision No. 4

LCO Applicability B 3.0

BASES REFERENCES ' 1. Letter from Christopher I. Grimes, Chief, Technical Specifications Branch, Division of Operating Reactor Support, to Frederick J.

Hebdon, Director, Project Directorate 11-4, Division of Reactor Projects 1/11, "Use of Shutdown Times for Corrective Maintenance (TIA 92-08)," December 11, 1992 .

Catawba Units 1 and 2 B 3.0-15 Revision No. 4

SR Applicability B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY B 3.0 BASES SRs SR 3.0.1 through SR 3.0.5 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated.

SR 3.0.1 SR 3.0.1 establishes the requirement that SRs must be met during the MODES or other specified conditions in the Applicability for which the requirements of the LCO apply, unless otherwise specified in the individual SRs. This Specification is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with SR 3.0.2, constitutes a failure to meet an LCO.

Systems and components are assumed to be OPERABLE when the associated SRs have been met. Nothing in this Specification, however, is to be construed as implying that systems or components are OPERABLE when:

a. The systems or components are known to be inoperable, although still meeting the SRs; or

b. The requirements of the Surveillance(s) are known not to be met between required Surveillance performances.

Surveillances do not have to be performed when the unit is in a MODE or other specified condition for which the requirements of the associated LCO are not applicable, unless otherwise specified. The SRs associated with a test exception are only applicable when the test exception is used as an allowable exception to the requirements of a Specification.

Unplanned events may satisfy the requirements (including applicable acceptance criteria) for a given SR. In this case, the unplanned event may be credited as fulfilling the performance of the SR. This allowance includes those SRs whose performance is normally precluded in a given MO.DE or other specified condition.

Surveillances, including Surveillances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with SR 3.0.2, prior to returning equipment to OPERABLE status.

Catawba Units 1 and 2 B 3.0-16 Revision No. 4

SR Applicability B 3.0

BASES SR 3.0.1 (continued)

Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with SR 3.0.2. Post maintenance testing may not be possible in the current MODE or other specified conditions in the Applicability due to the necessary unit parameters not having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and the equipment is not otherwise believed to be incapable of performing its function. This will allow operation to proceed to a MODE or other specified condition where other necessary post maintenance tests can be completed.

SR 3.0.2 SR 3.0.2 establishes the requirements for meeting the specified Frequency for Surveillances and any Required Action with a Completion Time that requires the periodic performance of the Required Action on a "once per ... " interval.

SR 3.0.2 permits a 25% extension of the interval specified in the Frequency. This extension facilitates Surveillance scheduling and considers plant operating conditions that may not be suitable for conducting the Surveillance (e.g., transient conditions or other ongoing Surveillance or maintenance activities).

The 25% extension does not significantly degrade the reliability that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any particular

Surveillance being performed is the verification of conformance with the SRs. The exceptions to SR 3.0.2 are those Surveillances for which the 25% extension of the interval specified in the Frequency does not apply.

These exceptions are stated in the individual Specifications. The requirements of regulations take precedence over the TS. An example of where SR 3.0.2 does not apply is in the Containment Leakage Rate Testing Program. This program establishes testing requirements and Frequencies in accordance with the requirements of regulations. The TS cannot in and of themselves extend a test interval specified in the regulations .

Catawba Units 1 and 2 B 3.0-17 Revision No. 4

SR Applicability B 3.0 BASES SR 3.0.2 (continued)

As stated in SR 3.0.2, the 25% extension also does not apply to the initial portion of a periodic Completion Time that requires performance on a "once per ... " basis. The 25% extension applies to each performance after the initial performance. The initial performance of the Required Action, whether it is a particular Surveillance or some other remedial action, is considered a single action with a single Completion Time. One reason for not allowing the 25% extension to this Completion Time is that such an action usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or the action accomplishes the function of the inoperable equipment in an alternative manner.

The provisions of SR 3.0.2 are not intended to be used repeatedly merely as an operational convenience to extend Surveillance intervals (other than those consistent with refueling intervals) or periodic Completion Time intervals beyond those specified.

SR 3.0.3 SR 3.0.3 establishes the flexibility to defer declaring affE:icted equipment inoperable or an affected variable outside the specified limits when a Surveillance has not been completed within the specified Frequency. A delay period of up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or up to the limit of the specified Frequency, whichever is greater, applies from the point in time that it is discovered that the Surveillance has not been performed in accordance with SR 3.0.2, and not at the time that the specified Frequency was not met.

This delay period provides adequate time to complete Surveillances that have been missed. This delay period permits the completion of a Surveillance before complying with Required Actions or other remedial measures that might preclude completion of the Surveillance.

The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements.

Catawba Units 1 and 2 B 3.0-18 Revision No. 4

SR Applicability B 3.0

BASES SR 3.0.3 (continued)

When a Surveillance with a Frequency based not on time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering MODE 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, SR 3.0.3 allows for the full delay period of up to the specified Frequency to perform the Surveillance. However, since there is not a time interval specified, the missed Surveillance should be performed at the first reasonable opportunity.

SR 3.0.3 provides a time limit for, and allowances for the performance of, Surveillances that become applicable as a consequence of MODE changes imposed by Required Actions.

Failure to comply with specified Frequencies for SRs is expected to be an infrequent occurrence. Use of the delay period established by SR 3.0.3 is a flexibility which is not intended to be used as an operational convenience to extend Surveillance intervals. While up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or the limit of the specified Frequency is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be performed

at the first reasonable opportunity. The determination of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, availability of personnel, and the time required to perform the Surveillance. This risk impact should be managed through the program in place to implement 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants."

This Regulatory Guide addresses consideration of temporary and *I aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensurate with the importance of the component. Missed Surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation determine the risk increase is significant, this evaluation should be used to determine the safest course of action. All missed Surveillances will be placed in the licensee's Corrective Action Program .

Catawba Units 1 and 2 B 3.0:-19 Revision No. 4

SR Applicability B 3.0 BASES SR 3.0.3 (continued)

If a Surveillance is not completed within the allowed delay period, then the equipment is considered inoperable or the variable is considered outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon expiration of the delay period. If a Surveillance is failed within the delay period, then the equipment is inoperable, or the variable is outside the specified limits and the Completion Times of the Required Actions for the applicable LCO Conditions begin immediately upon the failure of the Surveillance.

Completion of the Surveillance within the delay period allowed by this Specification, or within the Completion Time of the ACTIONS, restores compliance with SR 3.0.1.

SR 3.0.4 SR 3.0.4 establishes the requirement that all applicable SRs must be met before entry into a MODE or other specified condition in the Applicability.

This Specification ensures that system and component OPERABILITY requirements and variable limits are met before entry into MODES or other specified conditions in the Applicability for which these systems and

components ensure safe operation of the unit. The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

A provision is included to allow entry into a MODE or other specified condition in the Applicability when an LCO is not met due to a Surveillance not being met in accordance with LCO 3.0.4.

However, in certain circumstances, failing to meet an SR will not result in SR 3.0.4 restricting a MODE change or other specified condition change.

When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated SR(s) are not required to be performed, per SR 3.0.1, which states that surveillances do not have to be performed on inoperable equipment. When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perform the Surveillance(s) within the specified Frequency does not result in an SR 3.0.4 restriction to changing MODES or other specified conditions of the Applicability. However, since the LCO is not met in this instance, LCO 3.0.4 will govern any restrictions that may (or may not) apply to MODE or other specified condition changes. SR 3.0.4 does not restrict changing MODES or other specified conditions of the Applicability Catawba Units 1 and 2 when a Surveillance has not been performed within the specified B 3.0-20 Revision No. 4

SR Applicability B 3.0

BASES SR 3.0.4 (continued)

Frequency, provided the requirement to declare the LCO not met has been delayed in accordance with SR 3.0.3.

The provisions of SR 3.0.4 shall not prevent entry into MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, MODE 3 to MODE 4, and MODE 4 to MODE 5.

The precise requirements for performance of SRs are specified such that exceptions to SR 3.0.4 are not necessary. The specific time frames and conditions necessary for meeting the SRs are specified in the Frequency, in the Surveillance, or both. This allows performance of Surveillances when the prerequisite condition(s) specified in a Surveillance procedure require entry into the MODE or other specified condition in the Applicability of the associated LCO prior to .the performance or completion of a Surveillance. A Surveillance that could not be performed

until after entering the LCO's Applicability, would .have its Frequency ,

specified such that it is not "due" until the specific conditions needed are met. Alternately, the Surveillance may be stated in the form of a Note, as not required (to be met or performed) until a particular event, condition, or time has been reached. Further discussion of the specific formats of SRs' annotation is found in Section 1 A, Frequency.

SR 3.0.5 SR 3.0.5 delineates the applicability of the surveillance activities to Unit 1 and Unit 2 operations .

Catawba Units 1 and 2 B 3.0-21 Revision No. 4

Core Reactivity

B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.2 Core Reactivity B 3.1.2 BASES BACKGROUND According to GDC 26, GDC 28, and GDC 29 (Ref. 1), reactivity shall be controllable, such that subcriticality is maintained under cold conditions, and acceptable fuel design limits are not exceeded during normal operation and anticipated operational occurrences. Therefore, reactivity balance is used as a measure of the predicted versus measured core reactivity during power operation. The periodic confirmation of core reactivity is necessary to ensure that Design Basis Accident (OBA) and transient safety analyses remain valid. A large reactivity difference could be the result of unanticipated changes in fuel, control rod worth, or operation at conditions not consistent with those assumed in the predictions of core reactivity, and could potentially result in a loss of SOM or violation of acceptable fuel design limits. Comparing predicted versus measured core reactivity validates the nuclear methods used in the safety analysis and supports the SOM demonstrations (LCO 3.1.1, "SHUTDOWN MARGIN (SDM))in ensuring the reactor can be brought safely to cold, subcritical conditions .

When the reactor core is critical or in normal power operation, a reactivity balance exists and the net reactivity is zero. A comparison of predicted and measured reactivity is convenient under such a balance, since parameters are being maintained relatively stable under steady state power conditions. The positive reactivity inherent in the core design is b*a1anced by the negative reactivity of the control components, thermal feedback, neutron leakage, and materials in the core that absorb neutrons, such as burnable absorbers producing zero net reactivity.

Excess reactivity can be inferred from the boron letdown curve (or critical boron curve), which provides an indication of the soluble boron concentration in the Reactor Coolant System (RCS) versus cycle burnup.

Periodic measurement of the RCS boron concentration for comparison with the predicted value with other variables fixed (such as rod height, temperature, pressure, and power), provides a convenient method of ensuring that core reactivity is within design expectations and that the calculational models used to generate the safety analysis are adequate.

In order to achieve the required fuel cycle energy output, the uranium enrichment, in the new fuel loading and in the fuel remaining from the previous cycle, provides excess positive reactivity beyond that required to

Catawba Units 1 and 2 B 3.1.2-1 Revision No. 3

Core Reactivity B 3.1.2 BASES BACKGROUND (continued) sustain steady state operation throughout the cycle. When the reactor is critical at RTP and moderator temperature, the excess positive reactivity is compensated by burnable absorbers (if any), control rods, whatever neutron poisons (mainly xenon and samarium) are present in the fuel, and the RCS boron concentration.

When the core is producing THERMAL POWER, the fuel and burnable absorber are being depleted and excess reactivity (except possibly near BOC) is decreasing. As the fuel and burnable absorber deplete, the RCS boron concentration is adjusted to compensate for the net core reactivity change and maintain constant THERMAL POWER. The boron letdown curve is based on steady state operation at RTP. Therefore, deviations from the predicted boron letdown curve may indicate deficiencies in the design analysis, deficiencies in the calculational models, or abnormal core conditions, and must be evaluated.

APPLICABLE The acceptance criteria for core reactivity are that the reactivity balance SAFETY ANALYSES limit ensures plant operation is maintained within the assumptions of the safety analyses.

Accurate prediction of core reactivity is either an explicit or implicit assumption in the accident analysis evaluations. Every accident evaluation (Ref. 2) is, therefore, dependent upon accurate evaluation of core reactivity. In particular, SOM and reactivity transients, such as control rod withdrawal accidents or rod ejection accidents, are very sensitive to accurate prediction of core reactivity. These accident

analysis evaluations rely on computer codes that have been qualified against available test data, operating plant data, and analytical benchmarks. Monitoring reactivity balance additionally ensures that the nuclear methods provide an accurate representation of the core reactivity.

Design calculations and safety analyses are performed for each fuel cycle for the purpose of predetermining reactivity behavior and the RCS boron concentration requirements for reactivity control during fuel depletion.

The comparison between measured and predicted initial core reactivity provides a normalization for the calculational models used to predict core reactivity. If the measured and predicted RCS boron concentrations for identical core conditions at beginning of cycle (BOC) do not agree, then the assumptions used in the reload cycle design analysis or the calculational models used to predict soluble boron requirements may not be accurate. If reasonable agreement between measured and predicted core reactivity exists at BOC, then the prediction may be normalized to Catawba Units 1 and 2 B 3.1.2-2 Revision No. 3

Core Reactivity B 3.1.2

BASES APPLICABLE SAFETY ANALYSES (continued) the measured boron concentration. Thereafter, any significant deviations in the measured boron concentration from the predicted boron letdown curve that develop during fuel depletion may be an indication that the calculational model is not adequate for core burn ups beyond BOC, or that an unexpected change in core conditions has occurred.

The normalization of predicted RCS boron concentration to the measured value is typically performed after reaching RTP following startup from a refueling outage, with the control rods in their normal positions for power operation. The normalization is performed near BOC conditions, so that core reactivity relative to predicted values can be continually monitored and evaluated as core conditions change during the cycle.

Core reactivity satisfies Criterion 2 of 10 CFR 50.36 (Ref. 3).

LCO Long term core reactivity behavior is a result of the core physics design and cannot be easily controlled once the core design is fixed. During operation, therefore, the LCO can only be ensured through measurement and tracking, and appropriat~ actions taken as necessary. Large differences between actual and predicted core reactivity may indicate that the assumptions of the OBA and transient analyses are no longer valid, or that the uncertainties in the Nuclear Design Methodology are larger than expected. A limit on the reactivity balance of+/- 1% L'lk/k has been established based on engineering judgment. A 1% deviation in reactivity from that predicted is larger than expected for normal operation and

should therefore be evaluated.

When measured core reactivity is within 1% L'lk/k of the predicted value at steady state thermal conditions, the core is considered to be operating within acceptable design limits. Since deviations from the limit are normally detected by comparing predicted and measured steady state RCS critical boron concentrations, the difference between measured and predicted values would be between approximately 100 - 150 ppm (depending on the boron worth) before the limit is reached. These values are well within the uncertainty limits for analysis of boron concentration samples, so that spurious violations of the limit due to uncertainty in measuring the RCS boron concentration are unlikely.

APPL! GABI LITY The limits on core reactivity must be maintained during MODES 1 and 2 because a reactivity balance must exist when the reactor is critical or producing THERMAL POWER. As the fuel depletes, core conditions are changing, and confirmation of the reactivity balance ensures the core is operating as designed. This Specification does not apply in MODES 3, 4, Catawba Units 1 and 2 B 3.1.2-3 Revision No. 3

Core Reactivity B 3.1.2 BASES APPLICABILITY (continued) and 5 because the reactor is shut down and the reactivity balance is not changing.

In MODE 6, fuel loading results in a continually changing core reactivity.

Boron concentration requirements (LCO 3.9.1, "Boron Concentration")

ensure that fuel movements are performed within the bounds of the safety analysis. An SOM demonstration is required during the first startup following operations that could have altered core reactivity (e.g.,

fuel movement, control rod replacement, control rod shuffling).

ACTIONS A.1 and A.2 Should an anomaly develop between measured and predicted core reactivity, an evaluation of the core design and safety analysis must be performed. Core conditions are evaluated to determine their consistency with input to design calculations. Measured core and process parameters are evaluated to determine that they are within the bounds of the safety analysis, and safety analysis calculational models are reviewed tp verify that they are adequate for representation of the core conditions.

The required Completion Time of 7 days is based on the low probability of a OBA occurring during this period, and allows sufficient time to assess the physical condition of the reactor and complete the evaluation of the core design and safety analysis.

Following evaluations of the core design and safety analysis, the cause of the reactivity anomaly may be resolved. If the cause of the reactivity anomaly is a mismatch in core conditions at the time of RCS boron concentration sampling, then a recalculation of the RCS boron concentration requirements may be performed to demonstrate that core reactivity is behaving as expected. If an unexpected physical change in the condition of the core has occurred, it must be evaluated and corrected, if possible. If the cause of the reactivity anomaly is in the calculation technique, then the calculational models must be revised to provide more accurate predictions. If any of these results are demonstrated, and it is concluded that the reactor core is acceptable for continued operation, then the boron letdown curve may be renormalized and power operation may continue. If operational restriction or additional SRs are necessary to ensure the reactor core is acceptable for continued operation, then they must be defined.

The required CompJetion Time of 7 days is adequate for preparing whatever operating restrictions or Surveillances that may be required to allow continued reactor operation.

Catawba Units 1 and 2 B 3.1.2-4 Revision No. 3

Core Reactivity B 3.1.2

BASES ACTIONS (continued)

If the core reactivity cannot be restored to within the 1% llk/k limit, the plant must be brought to a MODE in which the LCO does not apply. )"o achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months . If the SOM for MODE 3 is not met, then the boration required by SR 3.1.1.1 would occur. The allowed Completion Time is reasonable, based on operating experience, for reaching MODE 3 from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.1.2.1 REQUIREMENTS Core reactivity is verified by periodic comparisons of measured and predicted RCS boron concentrations. The comparison is made, considering that other core conditions are fixed or stable, including control rod position, moderator temperature, fuel temperature, fuel depletion, xenon concentration, and samarium concentration. The Surveillance is performed prior to entering MODE 1 as an initial check on core conditions and design calculations at BOC. The SR is modified by a Note. The Note indicates that the normalization of predicted core reactivity to the measured value must take place within the first 60 effective full power days (EFPD) after each fuel loading. This allows sufficient time for core conditions to reach steady state, but prevents operation for a large fraction of the fuel cycle without establishing a benchmark for the design calculations. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26, GDC 28, and GDC 29.

2. UFSAR, Chapter 15.

3. 10 CFR 50.36, Technical Specification, (c)(2)(ii).

e Catawba Units 1 and 2 B 3.1.2-5 Revision No. 3

PHYSICS TESTS Exceptions

B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.8 PHYSICS TESTS Exceptions B 3.1.8 BASES BACKGROUND The primary purpose of the PHYSICS TESTS exceptions is to permit relaxations of existing LCOs to allow PHYSICS TESTS to be performed.

Section XI of 10 CFR 50, Appendix B (Ref. 1), requires that a test program be established to ensure that structures, systems, and components will perform satisfactorily in service. All functions necessary to ensure that the specified design conditions are not exceeded during normal operation and anticipated operational occurrences must be tested. This testing is an integral part of the design, construction, and operation of the plant. Requirements for notification of the NRC, for the purpose of conducting tests and experiments, are specified in 10 CFR 50.59 (Ref. 2).

The key objectives of a test program are to (Ref. 3):

a.

b.

c.

Ensure that the facility has been adequately designed; Validate the analytical models used in the design and analysis; Verify the assumptions used to predict unit response;

d. Ensure that installation of equipment in the facility has been accomplished in accordance with the design; and

e. Verify that the operating and emergency procedures are adequate.

To accomplish these objectives, testing is performed prior to initial criticality, during startup, during low power operations, during power ascension, at high power, and after each refueling. The PHYSICS TESTS requirements for reload fuel cycles ensure that the operating characteristics of the core are consistent with the design predictions and that the core can be operated as designed (Ref. 4).

PHYSICS TESTS procedures are written and approved in accordance with established formats. The procedures include all information necessary to permit a detailed execution of the testing required to ensure that the design intent is met. PHYSICS TESTS are performed in accordance with these procedures and test results are approved prior to continued power, escalation and long term power operation.

Catawba Units 1 and 2 B 3.1.8-1 Revision No. 3

PHYSICS TESTS Exceptions B 3.1.8 BASES BACKGROUND (continued)

The PHYSICS TESTS required for reload fuel cycles (Ref. 4) are listed below:

a. Critical Boron Concentration-Control Rods Withdrawn;

b. Control Rod Worth; c.. Isothermal Temperature Coefficient (ITC); and These and other supplementary tests may be required to calibrate the nuclear instrumentation or to diagnose operational problems. These tests may cause the operating controls and process variables to deviate from their LCO requirements during their performance.

APPLICABLE The fuel is protected by LCOs that preserve the initial conditions of the SAFETY ANALYSES core assumed during the safety analyses. The methods for development of the LCOs that are excepted by this LCO are described in the Westinghouse Reload Safety Evaluation Methodology Report (Ref. 5).

The above mentioned PHYSICS TESTS, and other tests that may be required to calibrate nuclear instrumentation or to diagnose operational problems, may require the operating control or process variables to deviate from their LCO limitations.

The UFSAR defines requirements for initial testing of the facility, including PHYSICS TESTS. UFSAR Section 14.3 summarizes the zero, low power, and power tests. Requirements for reload fuel cycle PHYSICS TESTS are defined in ANSI/ANS-19.6.1-1985 (Ref. 4).

Although these PHYSICS TESTS are generally accomplished within the limits for all LCOs, conditions may occur when one or more LCOs must be suspended to make completion of PHYSICS TESTS possible or practical. This is acceptable as long as the fuel design criteria are not violated. When one or more of the requirements specified in LCO 3.1.3, "Moderator Temperature Coefficient (MTC)," LCO 3.1.4, LCO 3.1.5, LCO 3.1.6, and LCO 3.4.2 are suspended for PHYSICS TESTS, the fuel design criteria are preserved as long as the power level is limited to s 5% RTP, the reactor coolant temperature is kept :2: 541 °F, and SOM is within limit specified in the COLR.

The PHYSICS TESTS include measurement of core nuclear parameters or the exercise of control components that affect process variables.

Among the process variables involved are AFD and QPTR, which represent initial conditions of the unit safety analyses. Also involved are the movable control components (control and shutdown rods), which are required to shut down the reactor. The limits for these variables are Catawba Units 1 and 2 B 3.1.8-2 Revision No. 3

PHYSICS TESTS Exceptions B 3.1.8

BASES APPLICABLE SAFETY ANALYSES (continued) specified for each fuel cycle in the COLR. PHYSICS TESTS meet the criteria for inclusion in the Technical Specifications, since the components and process variable LCOs suspended during PHYSICS TESTS meet Criteria 1, 2, and 3 of 10 CFR 50.36 (Ref.6).

Reference 7 allows special test exceptions (STEs) to be included as part of the LCO that they affect. It was decided, however, to retain this STE as a separate LCO because it was less cumbersome and provided additional clarity.

LCO This LCO allows the reactor parameters of MTC and minimum temperature for criticality to be outside their specified limits. In addition, it allows selected control and shutdown rods to be positioned outside of their specified alignment and insertion limits. One Power Range Neutron Flux*Channel may be bypassed, reducing the number of required channels from "4" to "3." Operation beyond specified limits is permitted for the purpose of performing PHYSICS TESTS and poses no threat to fuel integrity, provided the SRs are met.

The requirements of LCO 3.1.3, LCO 3.1.4, LCO 3.1.5, LCO 3.1.6, and LCO 3.4.2 may be suspended, and the number of required channels for LCO 3.3.1, RTS Instrumentation," Functions 2, 3, 6, and 16.e, may be reduced to "3" required channels, during the performance of PHYSICS TESTS provided:

a. RCS lowest loop average temperature is ~ 541 °F; and

b.

SOM is within limit specified in the COLR.

APPLICABILITY This LCO is applicable in MODE 2 when performing low power PHYSICS TESTS. The applicable PHYSICS TESTS are performed in MODE 2 at HZP.

ACTIONS A.1 and A.2 If the SOM requirement is not met, boration must be initiated promptly. A Completion Time of 15 minutes is adequate for an operator to correctly align and start the required systems and components. The operator should begin boration with the best source available for the plant conditions. Boration will be continued until SOM is within limit.

Suspension of PHYSICS TESTS exceptions requires restoration of each of the applicable LCOs to within specification.

Catawba Units 1 and 2 B 3.1.8-3 Revision No. 3

I I

PHYSICS TESTS Exceptions B 3.1.8 BASES ACTIONS (continued)

When THERMAL POWER is > 5% RTP, the only acceptable action is to open the reactor trip breakers (RTBs) to prevent operation of the reactor beyond its design limits. Immediately opening the RTBs will shut down the reactor and prevent operation of the reactor outside of its design limits.

When the RCS lowest Tavg is < 541 °F, the appropriate action is to restore T avg to within its specified limit. The allowed Completion Time of 15 minutes provides time for restoring Tavg to within limits without allowing the plant to remain in an unacceptable condition for an extended period of time. Operation with the reactor critical and with temperature below 541 °F could violate the assumptions for accidents analyzed in the safety analyses.

If the Required Actions cannot be completed within the associated Completion Time, the plant must be brought to a MODE in which the requirement does not apply. To achieve this status, the plant must be brought to at least MODE 3 within an additional 15 minutes. The Completion Time of 15 additional minutes is reasonable, based on operating experience, for reaching MODE 3 in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.1.8.1 REQUIREMENTS The power range and intermediate range neutron detectors must be verified to be OPERABLE in MODE 2 by LCO 3.3.1, "Reactor Trip System (RTS) Instrumentation." A CHANNEL OPERATIONAL TEST is performed on each power range and intermediate range channel prior to initiation of the PHYSICS TESTS. This will ensure that the RTS is properly aligned to provide the required degree of core protection during the performance of the PHYSICS TESTS.

During zero power PHYSICS TESTS, one power range channel is placed in the trip condition and the output of the detector is connected to the reactivity computer.

Catawba Units 1 and 2 B 3.1.8-4 Revision No. 3

PHYSICS TESTS Exceptions B 3.1.8 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.1.8.2 Verification that the RCS lowest loop T avg is ~ 541 °F will ensure that the unit is not operating in a condition that could invalidate the safety analyses. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.1.8.3 Verification that THERMAL POWER is :;::; 5% RTP will ensure that the plant is not operating in the condition that could invalidate the safety analyses. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.1.8.4 The SOM is verified.by performing a reactivity balance calculation, considering the following reactivity effects:

a. RCS boron concentration;

b. Control bank position;

c. RCS average temperature;

d. Fuel burnup based on gross thermal energy generation;

e. Xenon concentration;

f. Samarium concentration; and

g. Isothermal temperature coefficient (ITC).

Using the ITC accounts for Doppler reactivity in this calculation because the reactor is subcritical, and the fuel temperature will be changing at the same rate as the RCS.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program .

Catawba Units 1 and 2 B 3.1.8-5 Revision No. 3

PHYSICS TESTS Exceptions B 3.1.8 BASES REFERENCES 1.

2.

10 CFR 50, Appendix 8,Section XI.

10 CFR 50.59.

3. Regulatory Guide 1.68, Revision 2, August, 1978.

4. ANSI/ANS-19.6.1-1985, December 13, 1985.

5. WCAP-9273-NP-A, Westinghouse Reload Safety Evaluation Methodology Report," July 1985.

6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

7. WCAP-11618, including Addendum 1, April 1989.

Catawba Units 1 and 2 B 3.1.8-6 Revision No. 3

Pressurizer Safety Valves B 3.4.10

B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.10 Pressurizer Safety Valves BASES BACKGROUND The pressurizer safety valves provide, in conjunction with the Reactor Protection System, overpressure protection for the RCS. The pressurizer safety valves are totally enclosed pop type, spring loaded, self actuated valves with backpressure compensation. The safety valves are designed to prevent the system pressure from exceeding the system Safety Limit (SL), 2735 psig, which is 110% of the design pressure.

Because the safety valves are totally enclosed and self actuating, they are considered independent components. The relief capacity for each valve, 420,000 lb/hr, is based on postulated overpressure transient conditions resulting from a locked rotor. This event results in the maximum surge rate into the pressurizer, which specifies the minimum relief capacity for the safety valves. The discharge flow from the pressurizer safety valves is directed to the pressurizer relief tank. This discharge flow is indicated by an increase in temperature downstream of the pressurizer safety valves or increase in the pressurizer relief tank temperature or level.

Overpressure protection is required in MODES 1, 2, 3, 4, and 5; however, in MODE 4, with one or more RCS cold leg temperatures :s; 210°F, and MODE 5 and MODE 6 with the reactor vessel head on, overpressure protection is provided by operating procedures and by meeting the requirements of LCO 3.4.12, "Low Temperature Overpressure Protection (LTOP) System."

The upper pressure limit of +3% is consistent with the ASME requirement (Ref. 1) for lifting pressures above 1000 psig. The lower pressure limit of

-2% is selected such that the minimum LCO lift pressure remains above the uncertainty adjusted high pressure reactor trip setpoint. The lift setting is for the ambient conditions associated with MODES 1, 2, and 3. This requires either that the valves be set hot or that a correlation between hot and cold settings be established.

The pressurizer safety valves are part of the primary success path and mitigate the effects of postulated accidents. OPERABILITY of the safety valves ensures that the RCS pressure will be limited to 110% of design pressure. The consequences of exceeding the American Society of

Catawba Units 1 and 2 83.4.10-1 Revision No. 3

Pressurizer Safety Valves B 3.4.10 BASES BACKGROUND (continued)

Mechanical Engineers (ASME) pressure limit (Ref. 1) could include damage to RCS components, increased leakage, or a requirement to perform additional stress analyses prior to resumption of reactor operation.

APPLICABLE All accident and safety analyses in the UFSAR (Ref. 2) that require safety SAFETY ANALYSES valve actuation assume operation of three pressurizer safety valves to limit increases in RCS pressure. The overpressure protection analysis (Ref. 3) is also based on operation of three safety valves. Accidents that could result in overpressurization if not properly terminated include:

a. Uncontrolled rod withdrawal;

b. Loss of reactor coolant flow; C. Loss of external electrical load;

d. Loss of normal feedwater;

e. Loss of all AC power to station auxiliaries;

f. Locked rotor; and

g. Turbine trip.

Detailed analyses of the above transients are contained in Reference 2.

Compliance with this LCO is consistent with the design bases and accident analyses assumptions.

Pressurizer safety valves satisfy Criterion 3 of 10 CFR 50.36 (Ref. 5).

LCO The three pressurizer safety valves are set to open at the RCS design pressure 2485 psig, and within the ASME specified tolerance, to avoid exceeding the maximum design pressure SL, to maintain accident analyses assumptions, and to comply with ASME requirements. The upper pressure tolerance limit of +3% is consistent with the ASME requirements (Ref. 1) for lifting pressures above 1000 psig. The lower pressure limit of -2% is selected such that the minimum LCO lift pressure remains above the uncertainty adjusted high pressure reactor trip setpoint.

Catawba Units 1 and 2 B 3.4.10-2 Revision No. 3

Pressurizer Safety Valves 83.4.10

BASES LCO (continued)

The limit protected by this Specification is the reactor coolant pressure boundary (RCPB) SL of 110% of design pressure. lnoperability of one or more valves could result in exceeding the SL if a transient were to occur.

The consequences of exceeding the ASME pressure limit could include damage to one or more RCS components, increased leakage, or additional stress analysis being required prior to resumption of reactor operation.

APPLICABILITY In MODES 1, 2, and 3, and portions of MODE 4 above the LTOP arming temperature, OPERABILITY of three valves is required because the combined capacity is required to keep reactor coolant pressure below 110% of its design value during certain accidents. MODE 3 and portions of MODE 4 are conservatively included, although the listed accidents may not require the safety valves for protection.

The LCO is not applicable in MODE 4 when all RCS cold leg temperatures are :s; 210°F or in MODE 5 because LTOP is provided.

Overpressure protection is not required in MODE 6 with the reactor vessel head removed. *

The Note allows entry into MODES 3 and 4 with the lift settings outside the LCO limits. This permits testing and examination of the safety valves at high pressure and temperature near their normal operating range, but only after the valves have had a preliminary cold setting. The cold setting gives assurance that the valves are OPERABLE near their design condition. Only one valve at a time will be removed from service for testing. The 54 hour6.25e-4 days 0.015 hours 8.928571e-5 weeks 2.0547e-5 months exception is based on 18 hour2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months outage time for each of the three valves. The 18 hour2.083333e-4 days 0.005 hours 2.97619e-5 weeks 6.849e-6 months period is derived from operating experience that hot testing can be performed in this timeframe.

ACTIONS With one pressurizer safety valve inoperable, restoration must take place within 15 minutes. The Completion Time of 15 minutes reflects the importance of maintaining the RCS Overpressure Protection System. An inoperable safety valve coincident with an RCS overpressure event could challenge the integrity of the pressure boundary .

- Catawba Units 1 and 2 B 3.4.10-3 Revision No. 3

Pressurizer Safety Valves B 3.4.10 BASES ACTIONS (continued) 8.1 and 8.2 If the Required Action of A.1 cannot be met within the required Completion Time or if two or more pressurizer safety valves are inoperable, the plant must be brought to a MODE in which the requirement does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 with any RCS cold leg temperatures ~ 210°F within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. With any RCS cold leg temperatures at or below 210°F, overpressure protection is provided by the LTOP System. The change from MODE 1, 2, or 3 to MODE 4 reduces the RCS energy (core power and pressure), lowers the potential for large pressurizer insurges, and thereby removes the need for overpressure protection by three pressurizer safety valves.

SURVEILLANCE SR 3.4.10.1 REQUIREMENTS SRs are specified in the lnservice Testing Program. Pressurizer safety valves are to be tested in accordance with the requirements of Section XI

of the ASME Code (Ref. 4), which provides the activities and Frequencies necessary to satisfy the SRs. No additional requirements are specified.

The pressurizer safety valve setpoint is +3% and -2% of the nominal setpoint of 2485 psig for OPERABIUTY; however, the valves are reset to

.+/- 1% during the Surveillance to allow for drift.

REFERENCES 1. ASME, Boiler and Pressure Vessel Code, Section Ill.

2. UFSAR, Chapter 15.

3. UFSAR, Section 5.2.

4. ASME Code for Operation and Maintenance of Nuclear Power Plants.

5. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

Catawba Units 1 and 2 B 3.4.10-4 Revision No. 3

Containment Isolation Valves B 3.6.3

B 3.6 CONTAINMENT SYSTEMS B 3.6.3 Containment Isolation Valves BASES BACKGROUND The containment isolation valves form part of the containment pressure boundary and provide a means for fluid penetrations not serving accident consequence limiting systems to be provided with two isolation barriers that are closed on a containment isolation signal. These isolation devices are either passive or active (automatic). Manual valves, de-activated automatic valves secured in their closed position (including check valves with flow through the valve secured), blind flanges, and closed systems are considered passive devices. Check valves, or other automatic valves designed to close without operator action following an accident, are considered active devices. Two barriers in series are provided for each penetration so that no single credible failure or malfunction of an active component can result in a loss of isolation or leakage that exceeds limits assumed in the safety analyses. One of these barriers may be a closed system. These barriers (typically containment isolation valves) make up the Containment Isolation System .

Automatic isolation signals are produced during accident conditions.

Containment Phase "A" isolation occurs upon receipt of a safety injection signal. The Phase "A" isolation signal isolates nonessential process lines in order to minimize leakage of fission product radioactivity. Containment Phase "B" isolation occurs upon receipt of a containment pressure High-High signal and isolates the remaining process lines, except systems required for accident mitigation. The Containment Purge Ventilation and Containment Air Release and Addition valves also receive an isolation signal on a containment high radiation condition. As a result, the containment isolation valves (and blind flanges) help ensure that the containment atmosphere will be isolated from the environment in the event of a release of fission product radioactivity to the containment atmosphere as a result of a Design Basis Accident (OBA).

The OPERABILITY requirements for containment isolation valves help ensure that containment is isolated within the Time limits assumed in the safety analyses. Therefore, the OPERABILITY requirements provide assurance that the containment function assumed in the safety analyses will be*maintained .

Catawba Units 1 and 2 B 3.6.3-1 Revision No. 6

Containment Isolation Valves B 3.6.3 BASES BACKGROUND (continued)

Containment Purge Ventilation System The Containment Purge Ventilation System consists of the Containment Purge Supply and Exhaust Systems and the lncore Instrumentation Room Purge Supply and Exhaust Systems. These systems are used during refueling and post LOCA conditions and are not utilized during MODES 1 - 4. The penetration valves are sealed closed in MODES 1 -

4.

The Containment Purge Supply System includes one supply duct penetration through the Reactor Building wall into the annulus area.

There are four purge air supply penetrations through the containment vessel, two to the upper compartment and two to the lower compartment.

Two normally closed isolation valves at each penetration through the containment vessel provide containment isolation.

The Containment Purge Exhaust System includes one purge exhaust duct penetration through the Reactor Building wall from the annulus area.

There are three purge exhaust penetrations through the containment vessel, two from the upper compartment and one from the lower compartment. Two normally closed isolation valves at each penetration

through the containment vessel provide containment isolation.

The lncore Instrumentation Room Purge Supply System consists of one purge supply penetration through the Reactor Building wall and one

through the containment vessel. Two normally closed isolation valves at the containment penetration provide containment isolation.

The lncore Instrumentation Room Purge Exhaust System consists of one purge exhaust penetration through the Reactor Building wall and one through the containment vessel. Two normally closed isolation valves at the penetration through the containment vessel provide containment isolation.

Containment Hydrogen Purge System The Containment Hydrogen Purge System consists of a containment hydrogen purge inlet blower, which blows air from the Auxiliary Building through a 4 inch pipe into the upper compartment of the containment.

Another 4 inch pipe originating in the upper compartment of the containment purges air from the containment to the annulus. The penetration valves are sealed closed during MODES 1 - 4 ..

Catawba Units 1 and 2 B 3.6.3-2 Revision No. 6

Containment Isolation Valves B 3.6.3

BASES BACKGROUND (continued)

Containment Air Release and Addition System The Containment Air Release and Addition System is only used for controlling Containment pressure during normal unit operation. Isolation valves are located both inside and outside of the Containment on each containment penetration.

APPLICABLE The containment isolation valve LCO was derived from the assumptions SAFETY ANALYSES related to minimizing the loss of reactor coolant inventory and establishing the containment boundary during major accidents. As part of the containment boundary, containment isolation valve OPERABILITY supports leak tightness of the containment. Therefore, the safety analyses of any event requiring isolation of containment is applicable to this LCO.

The DBAs that result in a release of radioactive material within containment are a loss of coolant accident (LOCA) and a rod ejection accident (Ref. 1)". In the analyses for each of these accidents, itis assumed that containment isolation valves are either closed or function to close within the required isolation time following event initiation. This ensures that potential paths to the environment through containment isolation valves (including containment purge valves) are minimized. The safety analyses assume that the containment purge supply and/or exhaust isolation valves for the lower compartment and the upper compartment, instrument room, and the Hydrogen Purge System are closed at event initiation. Since the Containment Purge Ventilation System and the Hydrogen Purge System isolation valves are sealed closed in MODES 1 - 4, they are not analyzed mechanistically in the dose calculations.

The OBA analysis assumes that, within ::;; 76 seconds after the accident, isolation of the containment is complete and leakage terminated except for the design leakage rate, La. The containment isolation total response time of::;; 76 seconds includes signal delay, diesel generator startup (for loss of offsite power), and containment isolation valve stroke times.

The single failure criterion required to be imposed in the conduct of plant safety analyses was considered in the original design of the containment purge valves. Two valves in series on each purge line provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred .

Catawba Units 1 and 2 B 3.6.3-3 Revision No. 6

Containment Isolation Valves B 3.6.3 BASES APPLICABLE SAFETY ANALYSES (continued)

The containment purge and hydrogen purge valves may be unable to close in the environment following a LOCA. Therefore, each of the containment purge and hydrogen purge valves is required to remain sealed closed during MODES 1, 2, 3, and 4. The containment air release and addition valves may be opened during normal operation. In this case, the single failure criterion remains applicable to the containment air release and addition valves due to failure in the control circuit associated with each valve. The system valve design precludes a single failure from compromising the containment boundary as long as the system is operated in accordance with the subject LCO.

The containment isolation valves satisfy Criterion 3 of 10 CFR 50.36 (Ref. 2).

LCO Containment isolation valves form a part of the containment boundary.

The containment isolation valves' safety function is related to minimizing the loss of reactor coolant inventory and establishing the containment boundary during a DBA.

The automatic power operated isolation valves are required to have,

isolation times within limits and to actuate on an automatic isolation signal. The containment purge supply and exhaust isolation valves for the lower compartment, upper compartment, instrument room, and the Hydrogen Purge _System must be maintained sealed closed. The valves covered by this LCO are listed along with their associated stroke times in the UFSAR (Ref. 3).

The normally closed isolation valves are considered OPERABLE when manual valves are closed, automatic valves are de-activated and secured in their closed position, blind flanges are in place, and closed systems are intact. These passive isolation valves/devices are those listed in Reference 3.

Valves with resilient seals and reactor building bypass valves must meet additional leakage rate requirements. The other containment isolation valve leakage rates are addressed by LCO 3.6.1, "Containment," as Type C testing.

This LCO provides assurance that the containment isolation valves and purge valves will perform their designed safety functions to minimize the loss of reactor coolant inventory and establish the containment boundary during accidents.

Catawba Units 1 and 2 B 3.6.3-4 Revision No. 6

Containment Isolation Valves B 3.6.3

BASES APPLI GABI LITY In MODES 1, 2, 3, and 4, a OBA could cause a release of radioactive material to containment. In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, the containment isolation valves are not required to be OPERABLE in MODE 5. The requirements for containment isolation valves during MODE 6 are addressed in LCO 3.9.3, "Containment Penetrations."

ACTIONS The ACTIONS are modified by a Note allowing penetration flow paths, except for containment purge supply and exhaust isolation valves for the lower and upper compartment, instrument room, and hydrogen purge penetration flow paths, to be unisolated intermittently under administrative controls. These administrative controls consist of stationing a dedicated operator at the valve controls, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a-need for containment isolation is indicated. For valve controls located in the control room, an operator may monitor containment isolation signal status rather than be stationed at the valve controls. Due to the size of the containment purge line penetration and the fact that those penetrations exhaust directly from the containment atmosphere to the environment, the penetration flow path containing these valves may not be opened under administrative controls. A single purge valve in a penetration flow path may be opened to effect repairs to an inoperable valve, as allowed by SR 3.6.3.1.

A second Note has been added to provide clarification that, for this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable containment isolation valve. Complying with the Required Actions may allow for continued operation, and subsequent inoperable containment isolation valves are governed by subsequent Condition entry and application of associated Required Actions.

The ACTIONS are further modified by a third Note, which ensures appropriate remedial actions are taken, if necessary, if the affected systems are rendered inoperable by an inoperable containment isolation valve.

In the event the containment isolation valve leakage results in exceeding the overall containment leakage rate, Note 4 directs entry into the applicable Conditions and Required Actions of LCO 3.6.1 .

Catawba Units 1 and 2 B 3.6.3-5 Revision No. 6

Containment Isolation Valves B 3.6.3 BASES ACTIONS (continued)

A.1 and A.2

- I In the event one containment isolation valve in one or more penetration flow paths is inoperable except for purge valve or reactor building bypass leakage not within limit, the affected penetration flow path must be

isolated. The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic containment isolation valve, a closed manual valve, a blind flange, and a check valve inside containment with flow through the valve secured. For a penetration flow path isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available one to containment. Required Action A.1 must be completed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, considering the time required to isolate the penetration and the relative importance of supporting containment OPERABILITY during MODES 1, 2, 3, and 4*.

For affected penetration flow paths that cannot be restored to OPERABLE status within the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time and that have been isolated in accordance with Required Action A.1, the affected penetration

flow paths must be verified to be isolated on a periodic basis. This is necessary to ensure that containment penetrations required to be isolated following an accident and no longer capable of being automatically isolated will be in the isolation position should an event occur. This Required Action does riot require any testing or device

. manipulation. Rather, it involves verification, through a system walkdown or computer status indication, that those isolation devices outside containment and capable of being mispositioned are in the correct position. The Completion Time of "once per 31 days for isolation devices outside containment" is appropriate considering the fact that the devices are operated under administrative controls and the probability of their misalignment is low. For the isolation devices inside containment, the time period specified as "prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the isolation devices and other administrative controls that will ensure that isolation device misalignment is an unlikely possibility.

Condition A has been modified by a Note indicating that this Condition is only applicable to those penetration flow paths with two containment Catawba Units 1 and 2 B 3.6.3-6 Revision No. 6

Containment Isolation Valves B 3.6.3

BASES ACTIONS (continued) isolation valves. For penetration flow paths with only one containment isolation valve and a closed system, Condition C provides the appropriate actions.

Required Action A.2 is modified by two Notes. Note 1 applies to isolation devices located in high radiation areas and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since the function of locking, sealing, or securing components is to ensure that these devices are not inadvertently repositioned. Therefore, the probability of misalignment of these devices once they have been verified to be in the proper position, is small.

With two containment isolation valves in one or more penetration flow paths inoperable, the affected penetration flow path must be isolated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is consistent with the ACTIONS of LCO 3.6.1. In the event the affected penetration is isolated in accordance with Required Action B.1, the affected penetration must be verified to be isolated on a periodic basis per Required Action A.2, which remains in effect. This periodic verification is necessary to assure leak tightness of containment and that penetrations requiring isolation following an accident are isolated. The Completion Time of once per 31 days for verifying each affected penetration flow path is isolated is appropriate considering the fact that the valves are operated under administrative control and the probability of their misalignment is low.

Condition B is modified by a Note indicating this Condition is only applicable to penetration flow paths with two containment isolation valves.

Condition A of this LCO addresses the condition of one containment isolation valve inoperable in this type of penetration flow path .

Catawba Units 1 and 2 B 3.6.3-7 Revision No. 6

Containment Isolation Valves B 3.6.3 BASES ACTIONS (continued)

C.1 and C.2 With one or more penetration flow paths with one containment isolation valve inoperable, the inoperable valve flow path must be restored to OPERABLE status or the affected penetration flow path must be isolated.

The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure.

Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. A check valve may not be used to isolate the affected penetration flow path.

Required Action C.1 must be completed within the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time. The specified time period is reasonable considering the relative stability of the closed system (hence, reliability) to act as a penetration isolation boundary and the relative importance of maintaining containment integrity during MODES 1, 2, 3, and 4. In the event the affected penetration flow path is isolated in accordance with Required Action C.1, the affected penetration flow path must be verified to be isolated on a periodic basis. This periodic verification is necessary to assure leak tightness of containment and that containment penetrations requiring isolation following an accident are isolated. The Completion Time of once per 31 days for verifying that each affected penetration flow

path is isolated is appropriate because the valves are operated under administrative controls and the probability of their misalignment is low.

Condition C is modified by a Note indicating that this Condition is only applicable to those penetration flow paths with only one containment isolation valve and a closed system. The closed system must meet the requirements of Reference 4. This Note is necessary since this Condition is written to specifically address those penetration flow paths in a closed system.

Required Action C.2 is modified by two Notes. Note 1 applies to valves and blind flanges located in high radiation areas and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since the function of locking, sealing, or securing components is to ensure that these devices are not inadvertently repositioned. Therefore, the probability of misalignment of these valves, once they have been verified to be in the proper position, is small.

Catawba Units 1 and 2 B 3.6.3-8 Revision No. 6

Containment Isolation Valves B 3.6.3

BASES ACTIONS (continued)

D.1 With the reactor building bypass leakage rate not within limit, the assumptions of the safety analyses are not met. Therefore, the leakage must be restored to within limit within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Restoration can be accomplished by isolating the penetration(s) that caused the limit to be exceeded by use of one closed and de-activated automatic valve, closed manual valve, or blind flange. When a penetration is isolated the leakage rate for the isolated penetration is assumed to be the actual pathway leakage through the isolation device. If two isolation devices are used to isolate the penetration, the leakage rate is assumed to be the lesser actual pathway leakage of the two devices. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable considering the time required to restore the leakage by isolating the penetration(s) and the relative importance of secondary containment bypass leakage to the overall containment function.

E.1, E.2, and E.3 In the event one or more containment purge, hydrogen purge, or containment air release and addition valves in one or more penetration flow paths are not within the leakage limits, leakage must be restored to within limits, or the affected penetration flow path must be isolated. The method of isolation must be by the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, closed manual valve, or blind flange. A valve with resilient seals utilized to satisfy Required Action E.1 must have been demonstrated to meet the leakage requirements of SR 3.6.3.6. The specified Completion Time is reasonable, considering that one containment purge valve remains closed so that a gross breach of containment does not exist.

In accordance with Required Action E.2, this penetration flow path must be verified to be isolated on a periodic basis. The periodic verification is necessary to ensure that containment penetrations required to be isolated following an accident, which are no longer capable of being automatically isolated, will be in the isolation position should an event occur. This Required Action does not require any testing or valve manipulation. Rather, it involves verification, through a system walkdown or computer status indication, that those isolation devices outside containment capable of being mispositioned are in the correct position .

Catawba Units 1 and 2 B 3.6.3-9 Revision No. 6

Containment Isolation Valves B 3.6.3 BASES ACTIONS (continued)

For the isolation devices inside containment, the time period specified as "prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days" is based on engineering judgment and is considered reasonable in view of the inaccessibility of the isolation devices and other administrative controls that will ensure that isolation device misalignment is an unlikely possibility.

For the valve with resilient seal that is isolated in accordance with Required Action E.1, SR 3.6.3.6 must be performed at least once every 92 days. This assures that degradation of the resilient seal is detected and confirms that the leakage rate of the containment purge valve does not increase during the time the penetration is isolated.

Required Action E.2 is modified by two Notes. Note 1 applies to isolation devices located in high radiation areas and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted. Note 2 applies to isolation devices that are locked, sealed, or otherwise secured in position and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since the function of locking, sealing, or securing components is to ensure that these devices are not inadvertently repositioned.

F.1 and F.2 If the Required Actions and associated Completion Times are not met, the plant must be brought to a MODE in which the LCO does not apply.

To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.3.1 REQUIREMENTS Each containment purge supply and exhaust isolation valve for the lower compartment and the upper compartment, instrument room, and the Hydrogen Purge System is required to be verified sealed closed. This Surveillance is designed to ens*ure that a gross breach of containment is not caused by an inadvertent or spurious opening of a containment purge Catawba Units 1 and 2 B 3.6.3-10 Revision No. 6

Containment Isolation Valves B 3.6.3

BASES SURVEILLANCE REQUIREMENTS (continued) valve. Detailed analysis of these valves to conclusively demonstrate their ability to close during a LOCA in time to limit offsite doses has not been performed. Therefore, these valves are required to be in the sealed closed position during MODES 1, 2, 3, and 4. A valve that is sealed closed must have motive power to the valve operator removed. This can be accomplished by de-energizing the source of electric power or by removing the air supply to the valve operator. In this application, the term "sealed" has no connotation of leak tightness.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. In the event valve leakage requires entry into Condition E, the Surveillance permits opening one valve in a penetration flow path to perform repairs.

SR 3.6.3.2 This SR ensures that the Containment Air Release and Addition System isolation valves are closed as required or, if open, open for an allowable reason. If a valve is open in violation of this SR, the valve is considered inoperable. If the inoperable valve is not otherwise known to have excessive leakage when closed, it is not considered to have leakage outside of limits. The SR is not required to be met when the valves are open for the reasons stated. The valves may be opened for pressure control, ALARA or air quality considerations for personnel entry, or for Surveillances that require the valves to be operi. The valves are capable of closing in the environment following a LOCA. Therefore, these valves are allowed to be open for limited periods of time. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.6.3.3 This SR requires verification that each containment isolation manual valve and blind flange located outside containment or annulus and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside of the containment boundary is within design limits. This SR does not require any testing or valve manipulation. Rather, it irwolves verification, through system walkdown or computer status indication, that those containment isolation Catawba Units 1 and 2 B 3.6.3-11 Revision No. 6

Containment Isolation Valves B 3.6.3 BASES SURVEILLANCE REQUIREMENTS (continued) valves outside containment and capable of being mispositioned are in the correct position. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. The SR specifies that containment isolation valves that are open under administrative controls are not required to meet the SR during the time the valves are open.

This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be the correct position upon locking, sealing, or securing.

The Note applies to valves and blind flanges located in high radiation areas and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, 3 and 4 for ALARA reasons. Therefore, the probability of misalignment of these containment isolation valves, once SR 3.6.3.4 This SR requires verification that each containment isolation manual

valve and blind flange located inside containment or annulus and not locked, sealed, or otherwise secured and required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside of the containment boundary is within design limits. For containment isolation valves inside containment, the Frequency of "prior to entering MODE 4 from MODE 5 if not performed within the previous 92 days" is appropriate since these containment isolation valves are operated under administrative controls and the probability of their misalignment is low. The SR specifies that containment isolation valves that are open under administrative controls are not required to meet the SR during the time they are open. This SR does not apply to valves that are locked, sealed, or otherwise secured in the closed position, since these were verified to be the correct position upon locking, sealing, or securing.

This Note allows valves and blind flanges located in high radiation areas to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, 3, and 4, for ALARA reasons. Therefore, the probability of misalignment of these containment isolation valves, once they have been verified to be in their proper position, is small.

Catawba Units 1 and 2 B 3.6.3-12 Revision No. 6

Containment Isolation Valves B 3.6.3 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.3.5 Verifying that the isolation time of each automatic power operated containment isolation valve is within limits is required to demonstrate OPERABILITY. The isolation time test ensures the valve will isolate in a time period less than or equal to that assumed in the safety analyses.

The isolation time is specified in the UFSAR and the Frequency of this SR is in accordance with the lnservice Testing Program.

SR 3.6.3.6 For the Containment Purge System valves with resilient seals, additional leakage rate testing beyond the test requirements of 10 CFR 50, Appendix J, Option B is required to ensure OPERABILITY. The measured leakage rate for the Containment Purge System and Hydrogen Purge System valves must be~ 0.05 La when pressurized to Pa.

Operating experience has demonstrated that this type of seal has the potential to degrade in a shorter time period than other seal types. Based on this observation and the importance of maintaining this penetration leak tight (due to the direct path between containment and the environment), these valves will not be placed on the maximum extended test interval. Therefore, these valves will be tested in accordance with NEI 94-01 with a maximum test interval of 30 months.

The Containment Air Release and Addition System valves have a demonstrated history of acceptable leakage. The measured leakage rate for containment air release and addition valves must be ~ 0.01 La when pressurized to Pa. These valves will be tested in accordance with NEI 94-01 with a maximum test interval of 30 months.

SR 3.6.3.7 Automatic containment isolation valves close on a containment isolation signal to prevent leakage of radioactive material from containment following a OBA. This SR ensures that each automatic containment isolation valve will actuate to its isolation position on a containment Catawba Units 1 and 2 B 3.6.3-13 Revision No. 6

Containment Isolation Valves B 3.6.3 BASES SURVEILLANCE REQUIREMENTS (continued) isolation signal. The isolation signals involved are Phase A, Phase B, and Safety Injection. This surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.6.3.8 This SR ensures that the combined leakage rate of all reactor building bypass leakage paths is less than or equal to the specified leakage rate.

This provides assurance that the assumptions in the safety analysis are met. The Frequency is required by the Containment Leakage Rate Testing Program. This SR simply imposes additional acceptance criteria.

Bypass leakage is considered part of La.

REFERENCES 1. UFSAR, Section 15.

2. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

3. UFSAR, Section 6.2.

4. Standard Review Plan 6.2.4.

5. Not used.

Catawba Units 1 and 2 B 3.6.3-14 Revision No. 6

AVS B 3.6.10

B 3.6 CONTAINMENT SYSTEMS B 3.6.1 O Annulus Ventilation System (AVS)

BASES BACKGROUND The AVS is required by 10 CFR 50, Appendix A, GDC 41, "Containment Atmosphere Cleanup" (Ref. 1}, to ensure that radioactive materials that leak from the primary containment into the reactor building (secondary containment) following a Design Basis Accident (OBA) are filtered and adsorbed prior to exhausting to the environment.

The containment has a secondary containment called the reactor building, which is a concrete structure that surrounds the steel primary containment vessel. Between the containment vessel and the reactor building inner wall is an annulus that collects any containment leakage that may occur following a loss of coolant accident (LOCA) or rod ejection accident. This space also allows for periodic inspection of the outer surface of the steel containment vessel.

The AVS establishes a negative pressure in the annulus between the reactor building and the steel containment vessel. Filters in the system then control the release of radioactive contaminants to the environment.

The AVS consists of two separate and redundant trains. Each train includes a heater, prefilter/moisture separators, upstream and downstream high efficiency particulate air (HEPA) filters, an activated carbon adsorber section for removal of radioiodines, and a fan.

Ductwork, valves and/or dampers, and instrumentation also form part of the system. The prefilters/moisture separators function to remove large particles and entrained water droplets from the airstream, which reduces the moisture content. A HEPA filter bank upstream of the carbon adsorber filter bank functions to remove particulates and a second bank of HEPA filters follow the adsorber section to collect carbon fines. Only the upstream HEPA filter and the carbon adsorber section are credited in the analysis.

Catawba Units 1 and 2 B 3.6.10-1 Revision No. 3

AVS B 3.6.10 BASES BACKGROUND (continued)

A heater is included within each filter train to reduce the relative humidity of the airstream, although no credit is taken in the safety analysis. The heaters are not required for OPERABILITY since the carbon laboratory tests are performed at 95% relative humidity, but have been maintained in the system to provide additional margin (Ref. 6). Operation for;;:: 15 continuous minutes demonstrates OPERABILITY of the system. Periodic operation ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action.

The system initiates and maintains a negative air pressure in the reactor building annulus by means of filtered exhaust ventilation of the reactor building annulus following receipt of a safety injection (SI) signal. The system is described in Reference 2. The AVS reduces the radioactive content in the annulus atmosphere following a DBA. Loss of the AVS could cause site boundary doses, in the event of a DBA, to exceed the values given in the licensing basis.

APPLICABLE The AVS design basis is established by the consequences of the SAFETY ANALYSES limiting OBA, which is a LOCA. The accident analysis (Ref. 3) assumes that only one train of the AVS is functional due to a single failure that

disables the other train. The accident analysis accounts for the reduction in airborne radioactive material provided by the remaining one train of this filtration system. The amount of fission products available for release from containment is determined for a LOCA.

The modeled AVS actuation in the safety analyses is based upon a worst case response time following an SI initiated at the limiting setpoint. The CANVENT computer code is used to determine the total time required to achieve a negative pressure in the annulus under accident conditions.

The response time considers signal delay, diesel generator startup and sequencing time, system startup time, and the time for the system to attain the required pressure.

The AVS satisfies Criterion 3 of 10 CFR 50.36 (Ref. 4).

LCO In the event of a DBA, one AVS train is required to provide the minimum iodine removal assumed in the safety analysis. Two trains of the AVS must be OPERABLE to ensure that at least one train will operate, assuming that the other train is disabled by a single active failure.

Catawba Units 1 and 2 B 3.6.10-2 Revision No. 3 e

AVS B 3.6.10

BASES APPLI GABI LITY In MODES 1, 2, 3, and 4, a OBA could lead to fission product release to containment that leaks to the reactor building. The large break LOCA, on which this system's design is based, is a full power event. Less severe LOCAs and leakage still require the system to be OPERABLE throughout these MODES. The probability and severity of a LOCA decrease as core power and Reactor Coolant System pressure decrease. With the reactor shut down, the probability of release of radioactivity resulting from such an accident is low.

In MODES 5 and 6, the probability and consequences of a OBA are low due to the pressure and temperature limitations in these MODES. Under these conditions, the AVS is not required to be OPERABLE.

ACTIONS With one AVS train inoperable, the inoperable train must be restored to OPERABLE status within 7 days. The 7 day Completion Time is based on consideration of such factors as the availability of the OPERABLE redundant AVS train and the low probability of a OBA occurring during this period. The Completion Time is adequate to make most repairs .

8.1 and 8.2 With one or more AVS heaters inoperable, the heater must be restored to OPERABLE status within 7 days. Alternatively, a report must be initiated within 7 days per Specification 5.6.6, which details the reason for the heater's inoperability and the corrective action required to return the heater to OPERABLE status.

The heaters do not affect OPERABILITY of the AVS filter trains because carbon adsorber efficiency testing is performed at 30°C and 95% relative humidity. The accident analysis shows that site boundary radiation doses are within 10 CFR 50.67 limits during a OBA LOCA under these conditions.

e Catawba Units 1 and 2 B 3.6.10-3 Revision No. 3

AVS B 3.6.10 BASES ACTIONS (continued)

C.1 and C.2 If the AVS train cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.6.10.1 REQUIREMENTS Operating each AVS train from the control room with flow through the HEPA filters and carbon adsorbers ensures that all trains are OPERABLE and that all associated controls are functioning properly. Operation for ~

15 continuous minutes demonstrates OPERABILITY of the system.

Periodic operation ensures that blockage, fan or motor failure; or excessive vibration can be detected for correction action. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

e SR 3.6.10.2 This SR verifies that the required AVS filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The AVS filter tests are in accordance with Regulatory Guide 1.52 (Ref. 5). The VFTP includes testing HEPA filter performance, carbon adsorber efficiency, system flow rate, and the physical properties of the activated carbon (general use and following specific operations). Specific test frequencies and additional information are discussed in detail in the VFTP.

Catawba Units 1 and 2 B 3.6.10-4 Revision No. 3

AVS B 3.6.10 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.10.3 The automatic startup on a safety injection signal ensures that each AVS train responds properly. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.6.10.4 The AVS filter cooling electric motor-operated bypass valves are tested to verify OPERABILITY. The valves are normally closed and may need to be opened from the control room to initiate miniflow cooling through a filter unit that has been shutdown following a OBA LOCA. Miniflow cooling may be necessary to limit temperature increases in the idle filter train due to decay heat from captured fission products. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.6.10.5 The proper functioning of the fans, dampers, filters, adsorbers, etc., as a system is verified by the ability of each train to produce the required system flow rate. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.6.10.6 The ability of the AVS train to produce the required negative pressure of at least -0.88 inch water gauge when corrected to elevation 564 feet ensures that the annulus negative pressure is at least -0.25 inch water gauge everywhere in the annulus. The -0.88 inch water gauge annulus pressure includes a correction for an outside air temperature induced hydrostatic pressure gradient of -0.63 inch water gauge. The negative

Catawba Units 1 and 2 B 3.6.10-5 Revision No. 3

AVS B 3.6.10 BASES SURVEILLANCE REQUIREMENTS (continued) pressure prevents unfiltered leakage from the reactor building, since outside air will be drawn into the annulus by the negative pressure differential.

The CANVENT computer code is used to model the thermal effects of a LOCA on the annulus and the ability of the AVS to develop and maintain a negative pressure in the annulus after a design basis accident. The annulus pressure drawdown time during normal plant conditions is not an input to any dose analyses. Therefore, the annulus pressure drawdown time during normal plant conditions is insignificant.

The AVS trains are tested to ensure each train will function as required.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. Furthermore, the SR interval was developed considering that the AVS equipment OPERABILITY is demonstrated at a 31 day Frequency by SR 3.6.10.1. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1.

2.

3.

10 CFR 50, Appendix A, GDC 41.

UFSAR, Sections 6.2.3 and 9.4.9.

UFSAR, Chapter 15.

4. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

5. Regulatory Guide 1.52, Revision 2.

6. Catawba Nuclear Station License Amendments 90/84 for Units 1/2, August 23, 1991.

7. NUREG-0800, Sections 6.2.3 and 6.5.3, Rev. 2, July 1981.

Catawba Units 1 and 2 B 3.6.10-6 Revision No. 3

SG PORVs B 3.7.4 B 3.7 PLANT SYSTEMS B 3.7.4 Steam Generator Power Operated Relief Valves (SG PORVs)

BASES BACKGROUND The SG PORVs provide a method for cooling the unit to residual heat removal (RHR) entry conditions should the preferred heat sink via the Steam Dump System to the condenser not be available, as discussed in the UFSAR, Section 10.3 (Ref. 1). This is done in conjunction with the Auxiliary Feedwater System providing cooling water from the condensate storage system (CSS). The SG PORVs may also be required to meet the design cooldown rate during a normal cooldown when steam pressure drops too low for maintenance of a vacuum in the condenser to permit use of the Steam Dump System.

One SG PORV line for each of the four steam generators is provided.

Each SG PORV line consists of one SG PORV and an associated block valve.

The SG PORVs are provided with upstream block valves to permit their being tested at power, and to provide an alternate means of isolation.

The SG PORVs are equipped with pneumatic controllers to permit control of the cooldown rate.

The SG PORVs are provided with a pressurized gas supply of bottled nitrogen that, on a loss of pressure in the normal instrument air supply, automatically supplies nitrogen to operate the SG PORVs. The nitrogen supply is sized and pressurized (to approximately 2100 psig) to provide the sufficient pressurized gas to operate the SG PO RVs for the time required for Reactor Coolant System cooldown to RHR entry conditions.

In addition, handwheels are provided for local manual operation.

A description of the SG PO RVs is found in Reference 1.

APPLICABLE The design basis of the SG PORVs is established by the capability SAFETY ANALYSES to cool the unit to RHR entry conditions. The PORVs were sized to achieve a 50°F/hr cooldown rate. At cooldown inception, the PORVs will slowly open to maintain the desired cooldown rate. As steam generator pressure decreases, the PORVs will eventually be wide open and the cooldown rate will gradually decrease. Therefore, the cooldown time

Catawba Units 1 and 2 B 3.7.4-1 Revision No. 3

SG PORVs B 3.7.4 BASES APPLICABLE SAFETY ANALYSES (continued) from hot standby to RHR initiation is a function of the chosen maximum cooldown rate, the number of PORVs operating, and the time spent at MODE 3.

In the accident analysis presented in Reference 2, the SG PORVs are assumed to be used by the operator to cool down the unit to RHR entry conditions for accidents accompanied by a loss of offsite power. Prior to operator actions to cool down the unit, the SG PORVs and main steam safety valves (MSSVs) are assumed to operate automatically to relieve steam and maintain the steam generator pressure below the design value. For the recovery from a steam generator tube rupture (SGTR) event, the operator is also required to perform a limited cooldown to establish adequate subcooling as a necessary step to terminate the primary to secondary break flow into the ruptured steam generator. The time required to terminate the primary to secondary break flow for an SGTR is more critical than the time required to cool down to RHR conditions for this event and also for other accidents. Thus, the SGTR is the limiting event for the SG PORVs. The number of SG PO RVs required to be OPERABLE to satisfy the SGTR accident analysis requirements depends upon the number of unit loops and consideration of any single failure assumptions regarding the failure of one SG PORV

to open on demand. Local operation of the SG PO RVs is credited in the event that remote operation is unavailable.

The SG PORVs are equipped with block valves in the event an SG PORV spuriously fails to close during use.

The SG PO RVs satisfy Criterion 3 of 10 CFR 50.36 (Ref. 3).

LCO Four SG PORV lines are required to be OPERABLE. One SG PORV line is required from each of four steam generators to ensure that at least two SG PORV lines are available to conduct a unit cooldown following an SGTR, in which one steam generator becomes unavailable, accompanied by a single, active failure of a second SG PORV line on an unaffected steam generator. The block valves must be OPERABLE to isolate a failed open SG PORV line. A closed block valve does not render it or its SG PORV line inoperable if operator action time to open the block valve is supported in the accident analysis.

Failure to meet the LCO can result in the inability to cool the unit to RHR entry conditions following an event in which the condenser is unavailable for use with the Steam Dump System.

Catawba Units 1 and 2 B 3.7.4-2 Revision No. 3 -**

SG PORVs B 3.7.4

BASES LCO (continued)

An SG PORV is considered OPERABLE when it is capable of providing controlled relief of the main steam flow and capable of fully opening and closing on demand using the nitrogen gas supply.

APPLICABILITY In MODES 1, 2, and 3, and in MODE 4, when a steam generator is being relied upon for heat removal, the SG PORVs are required to be OPERABLE.

In MODE 5 or 6, an SGTR is not a credible event.

ACTIONS With one SG PORV line inoperable, action must be taken to restore OPERABLE status within 7 days. The 7 day Completion Time allows for the redundant capability afforded by the remaining OPERABLE SG PORV lines, a nonsafety grade backup in the Steam Dump System, and MSSVs. .

With two or more SG PORV lines inoperable, action must be taken to restore all but one SG PORV line to OPERABLE status. Since the block valve can be closed to isolate an SG PORV, some repairs may be possible with the unit at power. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is reasonable to repair inoperable SG PORV lines, based on the availability of the Steam Dump System and MSSVs, and the low probability of an event occurring during this period that would require the SG PORV lines.

C.1 and C.2 If the SG PORV lines cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4, without reliance upon steam generator for heat removal, within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems .

Catawba Units 1 and 2 B 3.7.4-3 Revision No. 3

SG PORVs B 3.7.4 BASES SURVEILLANCE REQUIREMENTS SR 3.7.4.1 Verification of the nitrogen supply pressure on at least one tank for each SG PORV ensures that the SG PORVs will be available to mitigate the consequences of a steam generator tube rupture concurrent with the loss of offsite power. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.7.4.2 To perform a controlled cooldown of the RCS, the SG PO RVs must be able to be opened remotely and throttled through their full range using the safety-related nitrogen gas supply. This SR ensures that the SG PO RVs are tested through a full control cycle at least once per fuel cycle.

Performance of inservice testing or use of an SG PORV during a unit cooldown may satisfy this requirement. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.7.4.3 The function of the block valve is to isolate a failed open SG PORV.

Cycling the block valve both closed and open demonstrates its capability to perform this function. Performance of inservice testing or use of the block valve during unit cooldown may satisfy this requirement. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. UFSAR, Section 10.3.

2. UFSAR, Chapter 15.

3. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

Catawba Units 1 and 2 B 3.7.4-4 Revision No. 3

AFW System B 3.7.5

B 3. 7 PLANT SYSTEMS B 3.7.5 Auxiliary Feedwater (AFW) System BASES BACKGROUND The AFW System automatically supplies feedwater to the steam generators to remove decay heat from the Reactor Coolant System upon the loss of normal feedwater supply. The AFW pumps take suction through suction lines from the condensate storage system (CSS)

(LCO 3.7.6) and pump to the steam generator secondary side. The normal supply of water to the AFW pumps is from the condensate system. The supply valves are open with power removed from the valve operator. The assured source of water to the AFW System is supplied by the Nuclear Service Water System. The turbine and motor driven pump discharge lines to each individual steam generator join into a single line outside containment. These individual lines penetrate the containment and enter each steam generator through the auxiliary feedwater nozzle.

The steam generators function as a heat sink for core decay heat. The heat load is dissipated by releasing steam to the atmosphere from the steam generators via the main steam safety valves (MSSVs) (LCO 3.7.1) or SG PO RVs (LCO 3. 7.4). If the main condenser is available, steam may be released via the steam dump valves and recirculated to the hotwell.

The AFW System consists of two motor driven AFW pumps and one steam turbine driven pump configured into three trains. Each of the motor driven pumps supply 100% of the flow requirements to two steam generators, although each pump has the capability to be realigned to feed other steam generators. The turbine driven pump provides 200% of the flow requirements and supplies water to all four steam generators.

Travel stops are set on the steam generator flow control valves such that the pumps can supply the minimum flow required without exceeding the maximum flow allowed. The pumps are equipped with independent recirculation lines to prevent pump operation against a closed system.

Each motor driven AFW pump is powered from an independent Class 1E power supply. The steam turbine driven AFW pump receives steamfrom two main steam lines upstream of the main steam isolation valves. Each of the steam feed lines will supply 100% of the requirements of the turbine driven AFW pump .

Catawba Units 1 and 2 B 3.7.5-1 Revision No. 4

AFW System B 3.7.5 BASES BACKGROUND (continued)

The AFW System is capable of supplying feedwater to the steam generators during normal unit startup, shutdown, and hot standby conditions. One turbine driven pump at full flow is sufficient to remove decay heat and cool the unit to residual heat removal (RHR) entry conditions. During unit cooldown, SG pressures and Main Steam pressures decrease simultaneously. Thus, the turbine driven AFW pump with a reduced steam supply pressure remains fully capable of providing flow to all SGs. Thus, the requirement for diversity in motive power sources for the AFW System is met.

The AFW System is designed to supply sufficient water to the steam generator(s) to remove decay heat with steam generator pressure at the lowest setpoint of the MSSVs plus 3% accumulation. Subsequently, the AFW System supplies sufficient water to cool the unit to RHR entry conditions, with steam released through the SG PORVs or MSSVs.

The motor driven AFW pumps actuate automatically on steam generator water level low-low in 1 out of 4 steam generators by the ESFAS (LCO 3.3.2). The motor driven pumps also actuate on loss of offsite power, safety injection, and trip of all MFW pumps. The turbine driven AFW pump actuates automatically on steam generator water level low-

low in 2 out of 4 steam generators and on loss of offsite power.

The AFW System is discussed in the UFSAR, Section 10.4.9 (Ref. 1).

APPLICABLE The AFW System mitigates the consequences of any event with loss SAFETY ANALYSES of normal feedwater.

The design basis of the AFW System is to supply water to the steam generator to remove decay heat and other residual heat by delivering at least the minimum required flow rate to the steam generators at pressures corresponding to the lowest steam generator safety valve set pressure plus 3%.

In addition, the AFW System must supply enough makeup water to replace steam generator secondary inventory lost as the unit cools to MODE 4 conditions. Sufficient AFW flow must also be available to account for flow losses such as pump recirculation valve leakage and line breaks.

The limiting Design Basis Accidents (DBAs) and transients for the AFW System are as follows:

Catawba Units 1 and 2 B 3.7.5-2 Revision No. 4

AFW System B 3.7.5

BASES APPLICABLE SAFETY ANALYSES (continued)

a. Feedwater Line Break (FWLB); and

b. Loss of MFW.

In addition, the minimum available AFW flow and system characteristics are considered in the analysis of a small break loss of coolant accident (LOCA) and events that could lead to steam generator tube bundle uncovery for dose considerations.

A range of AFW flows is considered for the. analyzed accidents, with the Main Steam Line Break being the most limiting for the maximum AFW flowrate.

The AFW System design is such that it can perform its function following a FWLB between the steam generator and the downstream check valve, combined with a loss of offsite power following turbine trip, and a single active failure of the steam turbine driven AFW pump. In such a case, one motor driven AFW pump would deliver to the broken MFW header at the pump runout flow untilthe problem was detected, and flow terminated by the operator. Sufficient flow would be delivered to the intact steam generators by the redundant AFW pump.

The ESFAS automatically actuates the AFW turbine driven puryip and associated power operated valves and controls when required to ensure an adequate feedwater supply to the steam generators during loss of offsite power. .

The AFW System satisfies the requirements of Criterion 3 of 10 CFR 50.36 (Ref. 2).

LCO This LCO provides assurance that the AFW System will perform its design safety function to mitigate the consequences of accidents that could result in overpressurization of the reactor coolant pressure boundary. Three independent AFW pumps in three diverse trains are required to be OPERABLE to ensure the availability of RHR capability for all events accompanied by a loss of offsite power and a single failure.

This is accomplished by powering two of the pumps from independent emergency buses. The third AFW pump is powered by a different means, a steam driven turbine supplied with steam from a source that is not isolated by closure of the MS IVs .

Catawba Units 1 and 2 B 3.7.5-3 Revision No. 4

AFW System B 3.7.5 BASES LCO (continued)

The AFW System is configured into three trains. The AFW System is considered OPERABLE when the components and flow paths required to provide redundant AFW flow to the steam generators are OPERABLE.

This requires that the two motor driven AFW pumps be OPERABLE in two diverse paths, each supplying AFW to separate steam generators.

The turbine driven AFW pump is required to be OPERABLE with redundant steam supplies from two main steam lines upstream of the MS IVs, and shall be capable of supplying AFW to any of the steam generators. The piping, valves, instrumentation, and controls in the required flow paths also are required to be OPERABLE. The NSWS assured source of water supply is configured into two trains. The turbine driven AFW pump receives NSWS from both trains of NSWS, therefore, the loss of one train of assured source renders only one AFW train inoperable. The remaining NSWS train provides an OPERABLE assured source to the other motor driven pump and the turbine driven pump.

The LCO is modified by a Note indicating that one AFW train, which includes a motor driven pump, is required to be OPERABLE in MODE 4.

This is because of the reduced heat removal requirements and short period of time in MODE 4 during which the AFW is required and the insufficient steam available in MODE 4 to power the turbine driven AFW

pump.

APPLICABILITY In MODES 1, 2, and 3, the AFW System is required to be OPERABLE in the event that it is called upon to function when the MFW is lost. In addition, the AFW System is required to supply enough makeup water to replace the steam generator secondary inventory, lost as the unit cools to MODE 4 conditions.

In MODE 4 the AFW System may be used for heat removal via the steam generators.

In MODE 5 or 6, the steam generators are not normally used for heat removal, and the AFW System is not required.

ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable AFW train when entering MODE 1. There is an increased risk associated with entering MODE 1 with an AFW train inoperable and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not Catawba Units 1 and 2 B 3.7.5-4 Revision No. 4

AFW System B 3.7.5

BASES ACTIONS (continued) be applied in this circumstance.

If one of the two steam supplies to the turbine driven AFW train is inoperable, or if a turbine driven pump is inoperable while in MODE 3 immediately following refueling, action must be taken to restore the inoperable equipment to an OPERABLE status within 7 days. The 7 day Completion Time is reasonable, based on the following reasons:

a. For the inoperability of a steam supply to the turbine driven AFW pump, the 7 day Completion Time is reasonable since there is a redundant steam supply line for the turbine driven pump.

b. For the inoperability of a turbine driven AFW pump while in MODE 3 immediately subsequent to a refueling, the 7 day Completion Time is reasonable due to the minimal decay heat levels in this situation .

C. For both the inoperability of a steam supply line to the turbine driven pump and an inoperable turbine driven AFW pump while in MODE 3 immediately following a refueling, the 7 day Completion Time is reasonable due to the availability of redundant OPERABLE motor driven AFW pumps; and due to the low probability of an event requiring the use of the turbine driven AFW pump.

The second Completion Time for Required Action A.1 establishes a limit on the maximum time allowed for any combination of Conditions to be inoperable during any continuous failure to meet this LCO.

The 10 day Completion Time provides a limitation time allowed in this specified Condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The AND connector between 7 days and 10 days dictates that both Completion Times apply simultaneously, and the more restrictive must be met.

Condition A is modified by a Note which limits the applicability of the Condition to when the unit has not entered MODE 2 following a refueling.

Condition A allows the turbine driven AFW pump to be inoperable for 7 days vice the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time in Condition B. This longer Completion Time is based on the reduced decay heat following refueling and prior to the reactor being critical.

Catawba Units 1 and 2 B 3.7.5-5 Revision No. 4

AFW System B 3.7.5 BASES ACTIONS (continued)

With one of the required AFW trains (pump or flow path) inoperable in MODE 1, 2, or 3 for reasons other than Condition A, action must be taken to restore OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This Condition includes the loss of two steam supply lines to the turbine driven AFW pump. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on redundant capabilities afforded by the AFW System, time needed for repairs, and the low probability of a OBA occurring during this time period.

The second Completion Time for Required Action B.1 establishes a limit on the maximum time allowed for any combination of Conditions to be inoperable during any continuous failure to meet this LCO.

The 1O day Completion Time provides a limitation time allowed in this specified Condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The AND connector between 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 10 days dictates that both Completion Times apply simultaneously, and the more restrictive must be met.

C.1 and C.2 When Required Action A.1 or B.1 cannot be completed within the required Completion Time, or if two AFW trains are inoperable in MODE 1, 2, or.3, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

In MODE 4 with two AFW trains inoperable, operation is allowed to continue because only one motor driven pump AFW train is required in accordance with the Note that modifies the LCO. Although not required, the unit may continue to cool down and initiate RHR.

If all three AFW trains are inoperable in MODE 1, 2, or 3, the unit is in a seriously degraded condition with no safety related means for conducting Catawba Units 1 and 2 B 3.7.5-6 Revision No. 4

AFW System B 3.7.5

BASES ACTIONS (continued) a cooldown, and only limited means for conducting a cooldown with nonsafety related equipment. In such a condition, the unit should not be perturbed by any action, including a power change, that might result in a trip. The seriousness of this condition requires that action be started immediately to restore one AFW train to OPERABLE status.

Required Action D.1 is modified by a Note indicating that all required MODE changes or power reductions are suspended until one AFW train is restored to OPERABLE status. In this case, LCO 3.0.3 is not applicable because it could force the unit into a less safe condition.

In MODE 4, either the reactor coolant pumps or the RHR loops can be used to provide forced circulation. This is addressed in LCO 3.4.6, "RCS Loops-MODE 4." With one required AFW train inoperable, action must be taken to immediately restore the inoperable train to OPERABLE status. The immediate Completion Time is consistent with LCO 3.4.6;

SURVEILLANCE REQUIREMENTS SR 3.7.5.1 Verifying the correct alignment for manual, power operated, and automatic valves in the AFW System water and steam supply flow paths provides assurance that the proper flow paths will exist for AFW operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since they are verified to be in the correct position prior to locking, sealing, or securing. This SR also does not apply to valves that cannot be inadvertently misaligned, such as check valves. This Surveillance does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. The SR is also modified by a note that excludes automatic valves when THERMAL POWER is

~ 10% RTP. Some automatic valves may be in a throttled position to support low power operation.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program .

Catawba Units 1 and 2 B 3.7.5-7 Revision No. 4

AFW System B 3.7.5 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.7.5.2 Verifying that each AFW pump's developed head at the flow test point is greater than or equal to the required developed head ensures that AFW pump performance has not degraded during the cycle. Flow and differential head are normal tests of centrifugal pump performance required by the ASME Code (Ref. 3). Because it is undesirable to introduce cold AFW into the steam generators while they are operating, this testing is performed on recirculation flow. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance.

Performance of inservice testing discussed in the ASME Code (Ref. 3)

(only required at 3 month intervals) satisfies this requirement.

This SR is modified by a Note indicating that the SR should be deferred until suitable test conditions are established. This deferral is required because there is insufficient steam pressure to perform the test.

SR 3.7.5.3 This SR verifies that AFW can be delivered to the appropriate steam generator in the event of any accident or transient that generates an ESFAS, by demonstrating that each automatic valve in the flow path actuates to its correct position on an actual or simulated actuation signal.

This Surveillance is not required for valves that are locked, sealed, or*

otherwise secured in the required position under administrative controls.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note that states the SR is not required in MODE

4. In MODE 4, the required AFW train may already be aligned and operating.

SR 3.7.5.4 This SR verifies that the AFW pumps will start in the event of any accident or transient that generates an ESFAS by demonstrating that each AFW pump starts automatically on an actual or simulated actuation signal in MODES 1, 2, and 3. In MODE 4, the required pump may already be operating and the autostart function is not required. The Surveillance Frequency is based on operating experience, equipment Catawba Units 1 and 2 B 3.7.5-8 Revision No. 4

AFW System B 3.7.5

BASES SURVEILLANCE REQUIREMENTS (continued) reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. Note 1 indicates that the SR can be deferred until suitable test conditions are established. This deferral is required because there is insufficient steam pressure to perform the test.

Note 2 states that the SR is not required in MODE 4. In MODE 4, the required pump may already be operating and the autostart function is not required. In MODE 4, the heat removal requirements would be less providing more time for operator action to manually start the required AFW pump if it were not in operation.

SR 3.7.5.5 This SR verifies that the AFW is properly aligned by verifying the flow paths from the CSS to each steam generator prior to entering MODE 2 after more than 30 days in MODE 5 or 6. OPERABILITY of AFW flow paths must be verified before sufficient core heat is generated that would require the operation of the AFW System during a subsequent shutdown.

The Frequency is reasonable, based on engineering judgment and other administrative controls that ensure that flow paths remain OPERABLE.

To further ensure AFW System alignment, flow path OPERABILITY is verified following extended outages to determine no misalignment of valves has occurred. This SR ensures that the flow path from the CSS to the steam generators is properly aligned.

REFERENCES 1. UFSAR, Section 10.4.9.

2. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

3. ASME Code for Operation and Maintenance of Nuclear Power Plants .

Catawba Units 1 and 2 B 3.7.5-9 Revision No. 4

css B 3.7.6

B 3. 7 PLANT SYSTEMS B 3.7.6 Condensate Storage System (CSS)

BASES BACKGROUND The CSS provides a source of water to the steam generators for removing decay and sensible heat from the Reactor Coolant System (RCS). The CSS provides a passive flow of water, by gravity, to the Auxiliary Feedwater (AFW) System (LCO 3.7.5). The steam produced is released to the atmosphere by the main steam safety valves, the steam generator PO RVs, or to the turbine condenser. The CSS is formed from the Upper Surge Tanks (two 42,500 gallon tanks per unit) and the Condenser Hotwell (normal operating level of 170,000 gallons). The safety grade and seismically designed source of water for the AFW system, which serves as the ultimate long-term safety related source is the Standby Nuclear Service Water Pond. This required source is covered in LCO 3.7.9, "Standby Nuclear Service Water Pond (SNSWP)"

and satisfies all short and long term water supply requirements for the AFW system except for Station Blackout (SBO) requirements .

When the main steam isolation valves are open, the preferred means of heat removal is to discharge steam to the condenser by the nonsafety grade path of the steam dumps to the condenser valves. The condensed steam is returned to the CSS by the condensate pump. This has the advantage of conserving condensate while minimizing releases to the environment.

A description of the CSS is found in the UFSAR, Section 10.4 (Ref. 1).

Note: The Auxiliary Feedwater Condensate Storage Tank (one 42,500 gallon tank per unit) is currently isolated as a normal suction source to the AFW pumps, when the AFW system is aligned for standby readiness, due to air entrainment concerns. This inventory is not available to meet the CSS requirement.

APPLICABLE The SNSWP provides cooling water to remove decay heat and to SAFETY ANALYSES cool down the unit following all events in the accident analysis as discussed in the UFSAR, Chapters 6 and 15 (Refs. 2 and 3, respectively). Because of the water quality, the SNSWP is not used for the normal source of water to the AFW system. The SNSWP serves as a backup source to supply only when the CSS can not supply AFW .

Catawba Units 1 and 2 B 3.7.6-1 Revision No. 5

css B 3.7.6 BASES LCO In order to satisfy recommendations made for the sizing of the system, the CSS contains sufficient cooling water to remove decay heat for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months following a reactor trip from 100% RTP, and then to cool down the RCS to RHR entry conditions, assuming a natural circulation cooldown.

In doing this, it must retain sufficient water to ensure adequate net positive suction head for the AFW pumps during cooldown.

The CSS level required is equivalent to a capacity ~ 225,000 gallons, which is based on holding the unit in MODE 3 for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , followed by a 5 hour5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months cooldown to RHR entry conditions at 50°F/hour. The OPERABILITY of the CSS is determined by maintaining the tanks' levels at or above the minimum required volume.

APPLICABILITY In MODES 1, 2, and 3, and in MODE 4, when steam generator is.being relied upon for heat removal, the CSS is required to be OPERABLE.

In MODE 5 or 6, the CSS is not required because the AFW System is not required.

ACTIONS A.1 and A.2 If the CSS inventory is not within limits, the OPERABILITY of the assured supply should be verified by administrative means within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter. The assured supply is considered the Nuclear Service Water System (NSWS) and ultimately the SNSWP.

OPERABILITY of the assured feedwater supply must include verification that the flow paths from the assured water supply to the AFW pumps are OPERABLE, and that the assured supply has the required volume of water available. The CSS must be restored to OPERABLE status within 7 days, because the assured supply may be performing this function in addition to its normal functions. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, based on operating experience, to verify the OPERABILITY of the assured water supply. The 7 day Completion Time is reasonable, based on ari OPERABLE assured water supply being available, and the low probability of an event occurring during this time period requiring the CSS.

8.1 and 8.2 If the CSS cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least Catawba Units 1 and 2 B 3.7.6-2 Revision No. 5

css B 3.7.6

BASES ACTIONS (continued)

MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4, without reliance on the steam generator for heat removal, within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.6.1 REQUIREMENTS This SR verifies that the CSS contains the required inventory of cooling water. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. UFSAR, Section 10.4.

2. UFSAR, Chapter 6.

3. UFSAR, Chapter 15.

Catawba Units 1 and 2 B 3.7.6-3 Revision No. 5

CRAVS B 3.7.10

B 3. 7 PLANT SYSTEMS B 3.7.10 Control Room Area Ventilation System (CRAVS)

BASES BACKGROUND The CRAVS ensures that the Control Room Envelope (CRE) will remain habitable for occupants during and following all credible accident conditions. This function is accomplished by pressurizing the CRE to ~

1/8 (0.125) inch water gauge with respect to all surrounding areas, filtering the outside air used for pressurization, and filtering a portion of the return air from the CRE to clean up the control rooni environment.

The CRAVS consists of two independent, redundant trains of equipment.

Each train consists of:

a pressurizing filter train fan (1 CRA-PFTF-1 or 2CRA-PFTF-1)

a filter unit (1CRA-PFT-1 or 2CRA-PFT-1) which includes moisture separator/prefilters, HEPA filters, and carbon adsorbers

the associated ductwork, dampers/valves, controls, doors, and barriers Inherent in the CRAVS ability to pressurize the control room is the control room envelope boundary. The CRE is the area within the confines of the CRE boundary that contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions. This area encompasses the control room, and may encompass the non-critical areas to which frequent personnel access or continuous occupancy is not necessary in the event of an accident. The CRE is protected during the normal operation, natural events, and accident conditions. The CRE boundary is the combination of walls, floor, roof, ducting, doors, penetrations and equipment that physically form the CRE. The OPERABILITY of the CRE boundary must be maintained to ensure that the inleakage of unfiltered air into the CRE will not exceed the inleakage assumed in the licensing basis analysis of design basis accident (OBA) consequences to CRE occupants. The CRE and its boundary are defined in the Control Room Envelope Habitability Program. These boundaries must be intact or properly isolated for the CRAVS to function properly.

Catawba Units 1 and 2 B3.7.10-1 Revision No. 11

CRAVS 83.7.10 BASES BACKGROUND (continued)

The CRAVS can be operated either manually or automatically. Key operated selector switches located in the CRE initiate operation of all train related CRAVS equipment. The selected train is in continuous operation. Outside air for pressurization and makeup to the CRE is supplied from two independent intakes. This outside air is mixed with return air from the CRE before being passed through the filter unit. In the filter unit, moisture separator/prefilters remove any large particles in the air, and any entrained water droplets present. A HEPA filter bank upstream of the carbon adsorber filter bank functions to remove particulates and a second bank of HEPA filters follow the carbon adsorber to collect carbon fines. Only the upstream HEPA filters and carbon adsorber bank are credited in the analysis. A heater is included within each filter train to reduce the relative humidity of the airstream, although no credit is taken in the safety analysis. The heaters are not required for OPERABILITY since the carbon laboratory tests are performed at 95% relative humidity, but have been maintained in the system to provide additional margin (Ref. 9). Operation for ;;:: 15 continuous minutes demonstrates OPERABILITY of the system. Periodic operation ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action.

Upon receipt of an Engineered Safety Feature (ESF) signal, the selected CRAVS train continues to operate and the pressurizing filter train fan of the non-selected train is started. This assures control room pressurization, assuming an active failure of one of the pressurizing filter train fans.

The outside air for pressurization is continuously monitored for the presence of smoke, radiation, or chlorine by non-safety related detectors.

If smoke, radiation, or chlorine is detected in an outside air intake, an alarm is received within the CRE, alerting the operators of this condition.

The operator will take the required action to close the affected intake, if necessary, per the guidance of the Annunciator Response Procedures.

A single CRAVS train is capable of pressurizing the CRE to greater than or equal to 0.125 inches water gauge. The CRAVS is designed in accordance with Seismic Category 1 requirements. The CRAVS operation in maintaining the CRE habitable is discussed in the UFSAR, Sections 6.4 and 9.4.1 (Refs. 1 and 2).

The CRAVS is designed to maintain a habitable environment in the CRE for 30 days of continuous occupancy after a OBA without exceeding a 5 rem total effective dose equivalent (TEDE).

Catawba Units 1 and 2 B 3.7.10-2 Revision No. 11

CRAVS B 3.7.10

BASES APPLICABLE The CRAVS components are arranged in redundant, safety related SAFETY ANALYSES ventilation trains. The CRAVS provides airborne radiological protection for the CRE occupants, as demonstrated by the CRE occupant dose analyses for the most limiting design basis loss of coolant accident, fission product release presented in the UFSAR, Chapter 15 (Ref. 3).

The CRAVS provides protection from smoke and hazardous chemicals to CRE occupants. The analysis of hazardous chemical releases demonstrates that the toxicity limits are not exceeded in the CRE following a hazardous chemical release (Ref. 1). The evaluation of a smoke challenge demonstrates that it will not result in the inability of the CRE occupants to control the reactor either from the control room or from the remote shutdown panels (Ref. 9).

The worst case single active failure of a component of the CRAVS, assuming a loss of offsite power, does* not impair the ability of the system to perform its design function.

The CRAVS satisfies Criterion 3 of 10 CFR 50.36 (Ref. 4).

LCO Two independent and redundant CRAVS trains arerequired to be OPERABLE to ensure that at least one is available assuming a single active failure disables the other train. Total system failure, such as from a loss of both ventilation trains or from an inoperable CRE boundary, could result in exceeding a dose of 5 rem to the CRE occupants in the event of a large radioactive release.

Each CRAVS train is considered OPERABLE when the individual components necessary to limit CRE occupant exposure are OPERABLE in both trains. A CRAVS train is OPERABLE when the associated:

a. Pressurizing filter train fan is OPERABLE;

b. HEPA filters and carbon adsorbers are not excessively restricting flow, and are capable of performing their filtration functions; and

c. Ductwork, valves, and dampers are OPERABLE, and air circulation can be maintained.

In order for the CRAVS trains to be considered OPERABLE, the CRE boundary must be maintained such that the CRE occupant dose from a large radioactive release does not exceed the calculated dose in the licensing basis consequence analyses for DBAs, and that the CRE occupants are protected from hazardous chemicals and smoke .

Catawba Units 1 and 2 B 3.7.10-3 Revision No. 11

CRAVS 83.7.10 BASES LCO (continued)

The CRAVS is shared between the two units. The system must be OPERABLE for each unit when that unit is in the MODE of Applicability.

Additionally, both normal and emergency power must also be OPERABLE because the system is shared. A shutdown unit supplying its associated emergency power source (1 EMXG/2EMXH) cannot be credited for OPERABILITY of components supporting the operating unit.

If a CRAVS component becomes inoperable, or normal or emergency power to a CRAVS component becomes inoperable, then the Required Actions of this LCO must be entered independently for each unit that is in

the MODE of Applicability of the LCO.

The LCO is modified by a Note allowing the CRE boundary to be opened intermittently under administrative controls. This Note only applies to openings in the CRE boundary that can be rapidly restored to the design condition, such as doors, hatches, floor plugs, and access panels. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings, these controls should be proceduralized and consist of stationing a dedicated individual at the opening who is in continuous communication with the operators in the CRE. This individual will have a method to rapidly close the opening and to restore the CRE boundary to

a condition equivalent to the design condition when a need for CRE isolation is indicated ..

APPLICABILITY In MODES 1, 2, 3, 4, 5, and 6, the CRAVS must be OPERABLE to ensure that the CRE will remain habitable during and following a OBA.

During movement of irradiated fuel assemblies, the CRAVS must be OPERABLE to cope with the release from a fuel handling accident.

ACTIONS When one CRAVS train is inoperable for reasons other than an inoperable CRE boundary, action must be taken to restore OPERABLE status within 7 days. In this Condition, the remaining OPERABLE CRAVS train is adequate to perform the CRE protection function.

However, the overall reliability is reduced because a single failure in the OPERABLE CRAVS train could result in loss of CRAVS function. The 7 day Completion Time is based on the low probability of a OBA occurring during this time period, and ability of the remaining train to provide the required capability.

Catawba Units 1 and 2 B 3.7.10-4 Revision No. 11

CRAVS B 3.7.10

BASES ACTIONS (continued)

B.1, B.2, and B.3 If the unfiltered inleakage of potentially contaminated air past the CRE boundary and into the CRE can result in CRE occupant radiological dose greater than the calculated dose of the licensing basis analyses of OBA consequences (allowed to be up to 5 rem TEDE), or inadequate protection of CRE occupants from hazardous chemicals or smoke, the CRE boundary is inoperable. Actions must be taken to restore an OPERABLE CRE boundary within 90 days.

During the period that the CRE boundary is considered inoperable, action must be initiated to implement mitigating actions to lessen the effect on CRE occupants from the potential hazards of a radiological or chemical event or a challenge from smoke. Actions must be taken within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to verify that in the event of a OBA, the mitigating actions will ensure that CRE occupant radiological exposures will not exceed the calculated dose of the licensing basis analyses of OBA consequences, and that CRE occupants are protected from hazardous chemicals and smoke. These

mitigating actions (i.e., actions that are taken to offset the consequences of the inoperable CRE boundary) should be preplanned for implementation upon entry into the condition, regardless of whether entry is intentional or unintentional. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is reasonable based on the low probability of a OBA occurring during this time period, and the use of mitigating actions. The 90 day Completion Time is reasonable based on the determination that the mitigating actions will ensure protection of CRE occupants within analyzed limits while limiting the probability that CRE occupants will have to implement protective measures that may adversely affect their ability to control the reactor and maintain it in a safe shutdown condition in the event of a OBA. In addition, the 90 day Completion Time is reasonable time to diagnose, plan and possibly repair, and test most problems with the CRE boundary.

C.1 and C.2 In MODE 1, 2, 3, or 4, if the inoperable CRAVS or CRE boundary train cannot be restored to OPERABLE status within the required Completion Time, the unit must be placed in a MODE that minimizes accident risk.

To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

Catawba Units 1 and 2 B 3.7.10-5 Revision No. 11

CRAVS B 3.7.10 BASES ACTIONS (continued)

D.1 In MODE 5 or 6, if the inoperable CRAVS train cannot be restored to OPERABLE status within the required Completion Time, or during movement of irradiated fuel assemblies, action must be taken to immediately place the OPERABLE CRAVS train in operation. This action ensures that the operating (or running) train is OPERABLE, that no failures preventing automatic actuation will occur, and that any active failure would be readily detected.

An alternative to Required Action D.1 is to immediately suspend activities that could result in a release of radioactivity that might require isolation of the CRE. This places the unit in a condition that minimizes risk. This does not preclude the movement of fuel to a safe position.

E.1 In MODE 5 or 6, or during movement of irradiated fuel assemblies, with two CRAVS trains inoperable, or with one or more CRAVS trains inoperable due to an inoperable CRE boundary, action must be taken

immediately to suspend activities that could result in a release of radioactivity that might require isolation of the CRE. This places the unit in a condition that minimizes the accident risk. This does not preclude the movement of fuel to a safe position.

F.1 If both CRAVS trains are inoperable in MODE 1, 2, 3, or 4, for reasons other than Condition B, the CRAVS may not be capable of performing the intended function and the unit is in a condition outside the accident analyses. Therefore, LCO 3.0.3 must be entered immediately.

G.1 and G.2 With one or more CRAVS heaters inoperable, the heater must be restored to OPERABLE status within 7 days. Alternatively, a report must be initiated per Specification 5.6.6, which details the reason for the heater's inoperability and the corrective action required to return the heater to OPERABLE status.

Catawba Units 1 and 2 B 3.7.10-6 Revision No. 11

e

CRAVS 83.7.10

BASES ACTIONS (continued)

The heaters do not affect OPERABILITY of the CRAVS filter trains because carbon adsorber efficiency testing is performed at 30°C and 95% relative humidity. The accident analysis shows that site boundary and control room operator radiation doses are within 10 CFR 50.67 limits during a OBA LOCA under these conditions.

SURVEILLANCE SR 3.7.10.1 REQUIREMENTS Standby systems should be checked periodically to ensure that they function properly. As the environment and normal operating conditions on this system are not too severe, testing each train once every month provides an adequate check of this system. Operation for.:: 15 continuous minutes demonstrates OPERABILITY of the system. Periodic operation ensures that blockage, fan or motor failure, or excessive vibration can be detected for correction action. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program .

SR 3.7.10.2 This SR verifies that the required CRAVS testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The CRAVS filter tests are in accordance with Regulatory Guide 1.52 (Ref. 5).

The VFTP includes testing the performance of the HEPA filter and carbon adsorber efficiencies and the physical properties of the activated carbon.

Specific test Frequencies and additional information are discussed in detail in the VFTP.

SR 3.7.10.3 This SR verifies that each CRAVS train starts and operates on an actual or simulated actuation signal. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

Catawba Units 1 and 2 B 3.7.10-7 Revision No. 11

CRAVS B 3.7.10 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.7.10.4 This SR verifies the OPERABILITY of the CRE boundary by testing for unfiltered air inleakage past the CRE boundary and into the CRE. The details of the testing are specified in the Control Room Envelope Habitability Program.

The CRE is considered habitable when the radiological dose to CRE occupants calculated in the licensing basis analyses of OBA consequences is no more than 5 rem TEDE and the CRE occupants are protected from hazardous chemicals and smoke. This SR verifies that the unfiltered air inleakage into the CRE is no greater than the flow rate assumed in the licensing basis analyses of OBA consequences. When unfiltered air inleakage is greater than the assumed flow rate, Condition B must be entered. Required Action 8.3 allows time to restore the CRE boundary to OPERABLE status provided mitigating actions can ensure that the CRE remains within the licensing basis habitability limits for the occupants following an accident. Compensatory measures are discussed in Regulatory Guide 1.196, Section C.2.7.3 (Ref. 9), which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F (Ref. 7). These compensatory measures may also be used as mitigating actions as

required by Required Action 8.2. Temporary analytical methods may also be used as compensatory measures to restore OPERABILITY (Ref.

8). Options for restoring the CRE boundary to OPERABLE status include changing the licensing basis OBA consequence analysis, repairing the CRE boundary, or a combination of these actions. Depending upon the nature of the problem and the corrective action, a full scope in leakage test may not be necessary to establish that the CRE boundary has been restored to OPERABLE status.

REFERENCES 1. UFSAR, Section 6.4.

2. UFSAR, Section 9.4.1.

3. UFSAR, Chapter 15.

4. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

5. Regulatory Guide 1.52, Rev. 2.

6. Catawba Nuclear Station License Amendments 90/84 for Units 1/2, August 23, 1991.

Catawba Units 1 and 2 B 3.7.10-8 Revision No. 11

CRAVS B 3.7.10 BASES REFERENCES (continued)

7. NEI 99-03, "Control Room Habitability Assessment", June 2001.

8. Letter from Eric J. Leeds (NRG) to James W. Davis (NEI) dated January 30, 2004, "NEI Draft White Paper, Use of Generic Letter 91-18 Process and Alternative Source Terms in the Context of Control Room Habitability", (ADAMS Accession No. ML040300694).

9. Regulatory Guide 1.196, Rev. 1.

e Catawba Units 1 and 2 B 3.7.10-9 Revision No. 11

ABFVES B 3.7.12

B 3. 7 PLANT SYSTEMS B 3.7.12 Auxiliary Building Filtered Ventilation Exhaust System (ABFVES)

BASES BACKGROUND The ABFVES consists of two independent and redundant trains. Each train consists of a heater demister section and a filter unit section. The heater demister section consists of a prefilter/moisture separator (to remove entrained water droplets) and an electric heater (to reduce the relative humidity of air entering the filter unit). The filter unit section consists of a prefilter, an upstream HEPA filter, an activated carbon adsorber (for the removal of gaseous activity, principally iodines), a downstream HEPA, and a fan. The downstream HEPA filter is not credited in the accident analysis, but serves to collect carbon fines.

Ductwork, valves or dampers, and instrumentation also form part of the system. Following receipt of a safety injection (SI) signal, the system isolates non safety portions of the ABFVES and exhausts air only from the Emergency Core Cooling System (ECCS) pump rooms.

The ABFVES is normally aligned to bypass the system HEPA filters and carbon adsorbers. During emergency operations, the ABFVES dampers are realigned to the filtered position, and fans are started to begin filtration. During emergency operations, the ABFVES dampers are realigned to isolate the non-safety portions of the system and only draw air from the ECCS pump rooms, as well as the Elevation 522 pipe chase, and Elevation 543 and 560 mechanical penetration rooms.

The ABFVES is discussed in the UFSAR, Sections 6.5, 9.4, 14.4, and 15.6 (Refs. 1, 2, 3, and 4, respectively) since it may be used for normal, as well as post accident, atmospheric cleanup functions. The heaters are not required for OPERABILITY, since the laboratory test of the carbon is performed at 95% relative humidity, but have been maintained in the system to provide additional margin (Ref. 9).

Catawba Units 1 and 2 B 3.7.12-1 Revision No. 7

ABFVES 83.7.12 BASES APPLICABLE The design basis of the ABFVES is established by the large break SAFETY ANALYSES LOCA. The system evaluation assumes a constant leak rate of 0.5 gpm in the ECCS pump rooms and a constant leak rate of 0.5 gpm outside the ECCS pump rooms throughout the accident. In such a case, the system limits radioactive release to within the 10 CFR 50.67 (Ref. 6) limits. The analysis of the effects and consequences of a large break LOCA is presented in Reference 4.

The ABFVES satisfies Criterion 3 of 10 CFR 50.36 (Ref. 7).

LCO Two independent and redundant trains of the ABFVES are required to be OPERABLE to ensure that at least one is available, assuming that a single failure disables the other train coincident with a loss of offsite power. Total system failure could result in the atmospheric release from the ECCS pump rooms exceeding 10 CFR 50.67 limits in the event of a Design Basis Accident (OBA).

ABFVES is considered OPERABLE when the individual components necessary to maintain the ECCS pump rooms filtration are OPERABLE in both trains.

An ABFVES train is considered OPERABLE when its associated:

a.

b.

Fan is OPERABLE; HEPA filters and carbon adsorbers are capable of performing their filtration functions; and

c. Ductwork, valves, and dampers are OPERABLE and air circulation can be maintained.

The ABFVES fans power supply is provided by buses which are shared between the two units. A shutdown unit supplying its associated emergency power source (1 EMXG/2EMXH) cannot be credited for OPERABILITY of components supporting the operating unit. If normal or emergency power to the ABFVES becomes inoperable, then the Required Actions of this LCO must be entered independently for each unit that is in the MODE of applicability of the LCO.

Catawba Units 1 and 2 B 3.7.12-2 Revision No. 7

ABFVES 8 3.7.12

BASES LCO (continued)

The LCO is modified by a Note allowing the ECCS pump rooms pressure boundary to be opened intermittently under administrative controls. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings, these controls consist of stationing a dedicated individual at the opening who is in continuous communication with the control room. This individual will have a method to rapidly close the opening when a need for ECCS pump rooms pressure boundary isolation is indicated.

APPLI CASI LITY In MODES 1, 2, 3, and 4, the ABFVES is required to be OPERABLE consistent with the OPERABILITY requirements of the ECCS.

In MODE 5 or 6, the ABFVES is not required to be OPERABLE since the ECCS is not required to be OPERABLE.

ACTIONS With one ABFVES train inoperable, action must be taken to restore OPERABLE status within 7 days. During this time, the remaining OPERABLE train is adequate to perform the ABFVES function.

The 7 day Completion Time is appropriate because the risk contribution is less than that for the ECCS (72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time), and this system is not a direct support system for the ECCS. The 7 day Completion Time is based on the low probability of a OBA occurring during this time period, and ability of the remaining train to provide the required capability.

Concurrent failure of two ABFVES trains would result in the loss of functional capability; therefore, LCO 3.0.3 must be entered immediately.

If the ECCS pump rooms pressure boundary is inoperable such that the ABFVES trains cannot establish or maintain the required pressure, action must be taken to restore an OPERABLE ECCS pump rooms pressure boundary within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . During the period that the ECCS pump rooms pressure boundary is inoperable, appropriate compensatory measures (consistent with the intent, as applicable, of GDC 19, 60, 64, and 10 CFR 50.67) should be utilized to protect plant personnel from potential

Catawba Units 1 and 2 8 3.7.12-3 Revision No. 7

ABFVES B 3.7.12 BASES ACTIONS (continued) hazards such as radioactive contamination, toxic chemicals, smoke, temperature and relative humidity, and physical security. Preplanned measures should be available to address these concerns for intentional and unintentional entry into the condition. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is reasonable based on the low probability of a OBA occurring during this time period and the use of compensatory measures. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is a typically reasonable time to diagnose, plan and possibly repair, and test most problems with the ECCS pump rooms pressure boundary.

C.1 and C.2 If the ABFVES train or ECCS pump rooms pressure boundary cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To

. achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

D.1 and D.2 With one or more ABFVES heaters inoperable, the heater must be restored to OPERABLE status within 7 days. Alternatively, a report must be initiated per Specification 5.6.6, which details the reason for the heater's inoperability and the corrective action required to return the heater to OPERABLE status.

The heaters do not affect OPERABILITY of the ABFVES filter trains because carbon adsorber efficiency testing is performed at 30°C and 95% relative humidity. The accident analysis shows that site boundary radiation doses are within 10 CFR 50.67 limits during a OBA LOCA under these conditions.

SURVEILLANCE SR 3.7.12.1 REQUIREMENTS Systems should be checked periodically to ensure that they function properly. As the environment and normal operating conditions on this system are not severe, testing each train once a month provides an adequate check on this system. Operation for ~ 15 continuous minutes Catawba Units 1 and 2 B 3.7.12-4 Revision No. 7 e

ABFVES B 3.7.12

BASES SURVEILLANCE REQUIREMENTS (continued) demonstrates OPERABILITY of the system. Periodic operation ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.7.12.2 This SR verifies that the required ABFVES testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The ABFVES filter tests are in accordance with Reference 5. The VFTP includes testing HEPA filter performance, carbon adsorbers efficiency, system flow rate, and the physical properties of the activated carbon (general use and following specific operations). The system flow rate determination and in-place testing of the filter unit components is performed in the normal operating alignment with both trains in operation.

Flow through each filter unit in this alignment is approximately 30,000 cfm. The normal operating alignment has been chosen to minimize

. normal radiological protection concerns that occur when the system is operated in an abnormal alignment for an extended period of time.

Operation of the system in other alignments may alter flow rates to the extent that the 30,000 cfm .+/-_10% specified in Technical Specification 5.5.11 will not be met. Flow rates outside the specified band under these operating alignments will not require the system to be considered inoperable.

Certain postulated failures and post accident recovery operational alignments may result in post accident system operation with only one train of ABFVES in a "normal" alignment. Under these conditions system flow rate is expected to increase above the normal flow band specified in Technical Specification 5.5.11. An analysis has been performed which conservatively predicts the maximum flow rate under these conditions is approximately 37,000 cfm. 37,000 cfm corresponds to a face velocity of approximately 48 ft/min that is significantly more than the normal 40 ft/min velocity specified in ASTM 03803-1989 (Ref. 10). Therefore, the laboratory test of the carbon penetration is performed in accordance with ASTM 03803-1989 and Generic Letter 99-02 at a face velocity of 48 ft/min. These test results are to be adjusted for a 2.27 inch bed using the methodology presented in ASTM 03803-1989 prior to comparing them to the Technical Specification 5.5.11 limit. Specific test Frequencies and additional information are discussed in detail in the VFTP.

Catawba Units 1 and 2 B 3.7.12-5 Revision No. 7

ABFVES B3.7.12 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.7.12.3 This SR verifies that each ABFVES train starts and operates with flow through the HEPA filters and carbon adsorbers on an actual or simulated actuation signal. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.7.12.4 This SR verifies the pressure boundary integrity of the ECCS pump rooms. The following rooms are considered to be ECCS pump rooms (with respect to the ABFVES): centrifugal charging pump rooms, safety injection pump rooms, residual heat removal pump rooms, and the containment spray pump rooms. Although the containment spray system is not normally considered an ECCS system, it is included in this ventilation boundary because of its accident mitigation function which requires the pumping of post accident containment sump fluid. The Elevation 522 pipe chase area is also maintained at a negative pressure by the ABFVES. Since the Elevation 543 and 560 mechanical

penetration rooms communicate directly with the Elevation 522 pipe chase area, these penetration rooms are also maintained at a negative pressure by the ABFVES. The ability of the system to maintain the ECCS pump rooms at a negative pressure, with respect to potentially unfiltered adjacent areas, is periodically tested to verify proper functioning of the ABFVES. Upon receipt of a safety injection signal to initiate LOCA operation, the ABFVES is designed to maintain a slight negative pressure in the ECCS pump rooms, with respect to adjacent areas, to prevent unfiltered LEAKAGE. The ABFVES will continue to operate in this mode until the safety injection signal is reset. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

Catawba Units 1 and 2 B 3.7.12-6 Revision No. 7

ABFVES B 3.7.12 BASES REFERENCES 1. UFSAR, Section 6.5.

2. UFSAR, Section 9.4.

3. UFSAR, Section 14.4.

4. UFSAR, Section 15.6.

5. Regulatory Guide 1.52 (Rev. 2).

6. 10 CFR 50.67.

7. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

8. Not used.

9. Catawba Nuclear Station License Amendments 90/84 for Units 1/2, August 23, 1991.

10. ASTM D3803-1989 .

Catawba Units 1 and 2 B 3.7.12-7 Revision No. 7

FHVES B 3.7.13

B 3.7 PLANT SYSTEMS B 3.7.13 Fuel Handling Ventilation. Exhaust System (FHVES)

BASES BACKGROUND The FHVES filters airborne radioactive particulates from the area of the fuel pool following a fuel handling accident. The FHVES, in conjunction with other normally operating systems, also provides environmental control of temperature and humidity in the fuel pool area.

The FHVES consists of two independent and redundant trains with two filter units per train. Each filter unit consists of a heater, prefilters/moisture separators, high efficiency particulate air (HEPA) filters, an activated carbon adsorber section for removal of gaseous activity (principally iodines), and a fan. Ductwork, valves or dampers, and instrumentation also form part of the system. The upstream HEPA filter bank functions to remove particulates and is credited in the safety analysis. A second bank of HEPA filters follows the adsorber section to collect carbon fines. The downstream HEPA filters are not credited in the analysis. A heater is included within each filter unit to reduce the relative humidity of the airstream. The heaters are not required for OPERABILITY, since the carbon laboratory tests are performed at 95%

relative humidity, but have been maintained in the system to provide additional margin (Ref. 11). The system initiates filtered ventilation of the fuel handling building following receipt of a high radiation signal.

The FHVES train does not actuate on any Engineered Safety Feature Actuation System signal. One train is required to be in operation whenever recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months ) is being moved in the fuel handling building. The operation of one train of FHVES ensures, if a fuel handling accident occurs, ventilation exhaust will be filtered before being released to the environment. The prefilters/moisture separators remove any large particles in the air, and any entrained water droplets present.

The FHVES is discussed in the UFSAR, Sections 6.5, 9.4, and 15.7 (Refs. 1, 2, and 3, respectively) because it may be used for normal, as well as atmospheric cleanup functions after a fuel handling accident in the spent fuel pool area .

Catawba Units 1 and 2 B 3.7.13-1 Revision No. 5

FHVES B 3.7.13 BASES APPLICABLE The FHVES design basis is established by the consequences of SAFETY ANALYSES the applicable Design Basis Accidents (OBA), which are the fuel handling accident involving handling recently irradiated fuel and the weir gate drop accident. The analysis of the fuel handling accident assumes that all fuel rods in an assembly are damaged. The OBA analysis of the fuel handling accident assumes that only one train of the FHVES is in operation. The amount of fission products available for release from the fuel handling building is determined for a fuel handling accident. These assumptions and the analysis follow the guidance provided in Regulatory Guide 1.25 (Ref. 4) and 1.183 (Ref. 10).

The FHVES satisfies Criterion 3 of 10 CFR 50.36 (Ref. 5).

LCO Two trains of the FHVES are required to be OPERABLE and one train in operation whenever recently irradiated fuel is being moved in the fuel handling building. Total system failure could result in the atmospheric release from the fuel handling building exceeding the 10 CFR 50.67 (Ref. 9) limits in the event of a fuel handling accident involving handling recently irradiated fuel.

The FHVES is considered OPERABLE when the individual components necessary to control exposure in the fuel handling building are OPERABLE. An FHVES train is considered OPERABLE when its associated:

a. Fans are OPERABLE;

b. HEPA filters and carbon adsorbers are capable of performing their filtration functions; and

c. Ductwork, valves, and dampers are OPERABLE, and air circulation can be maintained.

APPLICABILITY During movement of recently irradiated fuel in the fuel handling area, the FHVES is required to be OPERABLE and in operation to alleviate the consequences of a fuel handling accident.

ACTIONS Required Action A.1 is modified by a Note indicating that LCO 3.0.3 does not apply.

Catawba Units 1 and 2 B 3.7.13-2 Revision No. 5

FHVES B 3.7.13

BASES ACTIONS (continued)

With the movement of recently irradiated fuel in the fuel handling building, two trains of FHVES are required to be OPERABLE and one in operation.

The movement of recently irradiated fuel must be immediately suspended, if one or more trains of FHVES are inoperable or one is not in operation. This does not preclude the movement of an irradiated fuel assembly to a safe position. This action ensures that a fuel handling accident with unacceptable consequences could not occur.

B.1 and B.2 With one or more FHVES heaters inoperable, the heater must be restored to OPERABLE status within 7 days. Alternatively, a report must be initiated per Specification 5.6.6, which details the reason for the heater's inoperability and the corrective action required to return the heater to OPERABLE status.

The heaters do not affect OPERABILITY of the FHVES filter trains because.carbon adsorber efficiency testing is performed at 30°C and 95% relative humidity. The accident analysis shows that site boundary radiation doses are within 10 CFR 50.67 limits during a fuel handling accident under these conditions.

SURVEILLANCE SR 3.7.13.1 REQUIREMENTS With the FHVES train in service, a periodic monitoring of the system for proper operation should be checked on a routine basis to ensure that the system is functioning properly. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.7.13.2 Systems should be checked periodically to ensure that they function properly. Operation for.:::. 15 continuous minutes demonstrates OPERABILITY of the system. Periodic operation ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program .

Catawba Units 1 and 2 B 3.7.13-3 Revision No. 5

FHVES B 3.7.13 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.7.13.3 This SR verifies that the required FHVES testing is performed in accordance with the Ventilation Filter- Testing Program (VFTP). The FHVES filter tests are in accordance with Regulatory Guide 1.52 (Ref. 7).

The VFTP includes testing HEPA filter performance, carbon adsorber efficiency, system flow rate, and the physical properties of the activated carbon (general use and following specific operations). Specific test frequencies and additional information are discussed in detail in the VFTP.

SR 3.7.13.4 This SR verifies the integrity of the fuel building enclosure. The ability of the system to maintain the fuel building at a negative pressure with respect to atmospheric pressure is periodically tested to verify proper function of the FHVES. During operation, the FHVES is designed to maintain a slight negative pressure in the fuel building, to prevent unfiltered LEAKAGE. The FHVES is designed to maintain :,; -0.25 inches water gauge with respect to atmospheric pressure at a flow rate of *

,; 36,443 cfm. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.7.13.5 Operating the FHVES filter bypass damper is necessary to ensure that the system functions properly. The OPERABILITY of the FHVES filter bypass damper is verified if it can be manually closed. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

Catawba Units 1 and 2 B 3.7.13-4 Revision No. 5

FHVES B 3.7.13

BASES REFERENCES 1.

2.

UFSAR, Section 6.5.

UFSAR, Section 9.4.

3. UFSAR, Section 15.7.

4. Regulatory Guide 1.25.

5. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

6. Not used.

7. Regulatory Guide 1.52 (Rev. 2).

8. Not used.

9. 10 CFR 50.67, Accident source term.

10. Regulatory Guide 1.183 (Rev. 0).

11: Catawba Nuclear Station License Amendments 90/84 for Units 1/2, August 23, 1991 .

Catawba Units 1 and 2 B 3.7.13-5 Revision No. 5

AC Sources-Operating B 3.8.1

B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC Sources-Operating BASES BACKGROUND The unit Essential Auxiliary Power Distribution System AC sources consist of the offsite power sources (preferred power sources, normal and alternate(s)), and the onsite standby power sources (Train A and Train B diesel generators (DGs)). As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.

The onsite Class 1E AC Distribution System is divided into redundant load groups (trains) so that the loss of any one group does not prevent the minimum safety functions from being performed. Each train has connections to two preferred offsite power sources and a single DG.

From the transmission network, two electrically and physically separated circuits provide AC power, through step down station auxiliary transformers, to the 4.16 kV ESF buses. A detailed description of the offsite power network and the circuits to the Class 1E ESF buses is found in the UFSAR, Chapter 8 (Ref. 2).

A qualified offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class 1E ESF bus(es) ..

Certain required unit loads are returned to service in a predetermined sequence in order to prevent overloading the transformer supplying offsite power to the onsite Class 1E Distribution System. Within 1 minute after the initiating signal is received, all automatic and permanently .

connected loads needed to recover the unit or maintain it in a safe condition are returned to service via the load sequencer.

The onsite standby power source for each 4: 16 kV ESF bus is a dedicated DG. DGs A and Bare dedicated to ESF buses ETA and ETB, respectively. A DG starts automatically on a safety injection (SI) signal

Catawba Units 1 and 2 B 3.8.1-1 Revision No. 6

/

AC Sources-Operating B 3.8.1 BASES BACKGROUND (continued)

(i.e., low pressurizer pressure or high containment pressure signals) or on an ESF bus degraded voltage or undervoltage signal (refer to LCO 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation"). After the DG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. With no SI signal, there is a 1O minute delay between degraded voltage signal and the DG start signal. The DGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips loads from the ESF bus. When the DG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the DG by automatic load application.

In the event of a loss of preferred power, the ESF electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a Design Basis Accident (OBA) such as a loss of coolant accident (LOCA).

Certain required unit loads are returned to service in a predetermined *.

sequence in order to prevent overloading the DG in the process.

Approximately 1 minute after the initiating signal is received, all loads needed to recover the unit or maintain it in a safe condition are returned to service.

Ratings for Train A and Train B DGs satisfy the requirements of Regulatory Guide 1.9 (Ref. 3). The continuous service rating of each DG is 7000 kW with 10% overload permissible for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in any 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period. The ESF loads that are powered from the 4.16 kV ESF buses are listed in Reference 2.

APPLICABLE The initial conditions of OBA and transient analyses in the UFSAR, SAFETY ANALYSES Chapter 6 (Ref. 4) and Chapter 15 (Ref. 5), assume ESF systems are OPERABLE. The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System (RCS), and containment design limits are not exceeded.

These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coolant System (RCS);

and Section 3.6, Containment Systems.

Catawba Units 1 and 2 B 3.8.1-2 Revision No. 6

AC Sources-Operating B 3.8.1

BASES APPLICABLE SAFETY ANALYSES (continued)

The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the Accident analyses and is based upon meeting the design basis of the unit. This results in maintaining at least one train of the onsite or offsite AC sources OPERABLE during Accident conditions in the event of:

a. An assumed loss of all offsite power or all onsite AC power; and

b. A worst case single failure.

The AC sources satisfy Criterion 3 of 10 CFR 50.36 (Ref. 6).

LCO Two qualified circuits between the offsite transmission network and the onsite Essential Auxiliary Power System and separate and independent DGs for each train ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated OBA.

Qualified offsite circuits are those that are described in the UFSAR and are part of the licensing basis for the unit.

In addition, one required automatic load sequencer per train must be OPERABLE.

Each offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident, while

.connected to the ESF buses.

The 4.16 kV essential system is divided into two completely redundant and independent trains designated A and B, each consisting of one 4.16 kV switchgear assembly, three 4.16 kV/600 V transformers, two 600 V load centers, and associated loads.

Normally, each Class 1E 4.16 kV switchgear is powered from its associated non-Class 1E train of the 6.9 kV Normal Auxiliary Power System as discussed in "6.9 kV Normal Auxiliary Power System" in Chapter 8 of the UFSAR (Ref. 2). Additionally, a standby source of power to each 4.16 kV essential switchgear, not required by General Design Criterion 17, is provided from the 6.9 kV system via two separate and independent 6.9/4.16 kV transformers. These transformers are shared between units and provide the capability to supply a standby

Catawba Units 1 and 2 B 3.8.1-3 Revision No. 6

AC Sources-Operating B 3.8.1 BASES LCO (continued) source of preferred power to each unit's 4.16 kV essential switchgear from either unit's 6.9 kV system. A key interlock scheme is provided to preclude the possibility of connecting the two units together at either the 6.9 or 4.16 kV level.

Each train of the 4.16 kV Essential Auxiliary Power System is also provided with a separate and independent emergency diesel generator to supply the Class 1E loads required to safely shut down the unit following a design basis accident. Additionally, each diesel generator is capable of supplying its associated 4.16 kV blackout switchgear through a connection with the 4.16 kV essential switchgear.

Each DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESF bus on detection of bus undervoltage. This will be accomplished within 11 seconds. Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and continue to operate until offsite power can be restored to the ESF buses. These capabilities are required to be met from a variety of initial conditions such as DG in standby with the engine hot and DG in standby with the engine at ambient conditions.

Additional DG capabilities must be demonstrated to meet required Surveillance, e.g., capability of the DG to revert to standby status on an

ECCS signal while operating in parallel test mode.

Proper sequencing of loads, including tripping of nonessential loads, is a required function for DG OPERABILITY.

The AC sources in one train must be separate and independent (to the extent possible) of the AC sources in the other train. For the DGs, separation and independence are complete.

For the offsite AC sources, separation and independence are provided to the extent practical.

APPLI GABI LITY The AC sources and sequencers are required to be OPERABLE *in MODES 1, 2, 3, and 4 to ensure that

a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and Catawba Units 1 and 2 B 3.8.1-4 Revision No. 6

AC Sources-Operating B 3.8.1

BASES APPLICABILITY (continued)

b. Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated OBA.

The AC power requirements for MODES 5 and 6 are covered in LCO 3.8.2, "AC Sources-Shutdown."

ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable DG.

There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

When entering Required Actions for inoperable offsite circuit(s) and/or DG(s), it is also necessary to enter the applicable Required Actions of any shared systems LCOs when either normal or emergency power to shared components governed by these LCOs becomes inoperable.

These LCOs include 3.7.8, "Nuclear Service Water System (NSWS)";

3.7.10, "Control Room Area Ventilation System (CRAVS)"; 3.7.11, "Control Room Area Chilled Water System (CRACWS)"; and 3.7.12, "Auxiliary Building Filtered Ventilation Exhaust System (ABFVES)".

To ensure a highly reliable power source remains with one offsite circuit inoperable, it is necessary to verify the OPERABILITY of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not met. However, if a second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition C, for two offsite circuits inoperable, is entered.

Required Action A.2, which only applies if the train cannot be powered from an offsite source, is intended to provide assurance that an event coincident with a single failure of the associated DG will not result in a complete loss of safety function of critical redundant required features.

These features are powered from the redundant AC electrical power

Catawba Units 1 and 2 B 3.8.1-5 Revision No. 6

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) train. This includes motor driven auxiliary feedwater pumps. The turbine driven auxiliary feedwater pump is required to be considered a redundant required feature, and, therefore, required to be determined OPERABLE by this Required Action. Three independent AFW pumps are required to ensure the availability of decay heat removal capability for all events accompanied by a loss of offsite power and a single failure. System design is such that the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis.

The Completion Time for Required Action A.2 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:

a. The train has no offsite power supplying it loads; and

b. A required feature on the other train is inoperable.

If at any time during the existence of Condition A (one offsite circuit inoperable) a redundant required feature subsequently becomes inoperable, this Completion Time begins to be tracked.

Discovering no offsite power to one train of the onsite Class 1E Electrical Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with the other train that has offsite power, results in starting the Completion Times for the Required Action. Twenty-four hours is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.

The remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to Train A and Train B of the onsite Class 1E Distribution System. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a OBA occurring during this period.

According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Catawba Units 1 and 2 B 3.8.1-6 Revision No. 6

AC Sources-Operating B 3.8.1

BASES ACTIONS (continued)

°' Condition A for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the unit safety systems. In this Condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1E Distribution System.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources*, a reasonable time for repairs, and the low probability of a OBA occurring during this period:

The second Completion Time for Required Action A.3 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . This could lead to a total of 144 hours0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months , since initial failure to meet the LCO, to restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 6 day Completion Times means that both Completion Times apply simultaneously, *and the more restrictive Completion Time must be met.

As in Required Action A.2, the Completion Time allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."

This will result in establishing the "time zero" at the time that the LCO was initially not met, instead of at the time Condition A was entered.

To ensure a highly reliable power source remains with an inoperable DG, it is necessary to verify the availability of the offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions and Required Actions must then be entered. *

Catawba Units 1 and 2 B 3.8.1-7 Revision No. 6

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

Required Action B.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed with redundant safety related trains. This includes motor driven auxiliary feedwater pumps. The turbine driven auxiliary feedwater pump is required to be considered a redundant required feature, and, therefore, required to be determined OPERABLE by this Required Action. Three independent AFW pumps are required to ensure the availability of decay heat removal capability for all events accompanied by a loss of offsite power and a single failure. System design is such that the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis. Redundant required feature failures consist of inoperable features associated with a train, redundant to the train that has an inoperable DG.

The Completion Time for Required Action B.2 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action,

the Completion Time only begins on discovery that both:

a. An inoperable DG exists; and

b. A required feature on the other train (Train A or Train B) is inoperable.

If at any time during the existence of this Condition (one DG inoperable) a required feature subsequently becomes inoperable, this Completion Time would begin to be tracked.

Discovering one required DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DG, results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is Acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.

In this Condition, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not Catawba Units 1 and 2 B 3.8.1-8 Revision No. 6

AC Sources-Operating B 3.8.1

BASES ACTIONS (continued) been lost. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a OBA occurring during this period.

B.3.1 and B.3.2 Required Action B.3.1 provides an allowance to avoid unnecessary testing of OPERABLE DG(s). If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on other DG(s), the other DG(s) would be declared inoperable upon discovery and Condition E of LCO 3.8.1 would be entered. Once the failure is repaired, the common cause failure* no longer exists, and Required Action B.3.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG(s),

performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of that DG .

In the event the inoperable DG is restored to OPERABLE status prior to completing either B.3.1 or B.3.2, the problem investigation process will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months constraint imposed while in Condition B.

These Conditions are not required to be entered if the inoperability of the DG is due to an inoperable support system, an independently testable component, or preplanned testing or maintenance. If required, these Required Actions are to be completed regardless of when the inoperable DG is restored to OPERABLE status.

According to Generic Letter 84-15 (Ref. 8), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is reasonable to confirm that the OPERABLE DG(s) is not affected by the same problem as the inoperable DG.

According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition B for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

In Condition B, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution

Catawba Units 1 and 2 B 3.8.1-9 Revision No. 6

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

System. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a OBA occurring during this period.

The second Completion Time for Required Action B.4 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

This could lead to a total of 144 hours0.00167 days 0.04 hours 2.380952e-4 weeks 5.4792e-5 months , since initial failure to meet the LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months (for a total of 9 days) allowed prior to complete restoration of the LCO. The 6 day Completion Time provides a limit on time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and 6 day Completion Times means that both Completion Times apply simultaneously, and- the more restrictive Completion Time must be met.

As in Required Action B.2, the Completion Time allows for an exception

to the normal "time zero" for beginning the allowed time "clock." This will result in establishing the "time zero" at the time that the LCO was initially not met, instead of at the time Condition B was entered.

C.1 and C.2 Required Action C.1, which applies when two offsite circuits are inoperable, is intended to provide assurance that an event with a coincident single failure will not result in a complete loss of redundant required safety functions. The Completion Time for this failure of redundant required features is reduced to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from that allowed for one train without offsite power (Required Action A.2). The rationale for the reduction to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is that Regulatory Guide 1.93 (Ref. 7) allows a Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for two required offsite circuits inoperable, based upon the assumption that two complete safety trains are OPERABLE. When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is appropriate. These features are powered from redundant AC safety trains. This includes motor driven auxiliary feedwater pumps.

Single train features, such as turbine driven auxiliary pumps, are not included in the list.

Catawba Units 1 and 2 B 3.8.1-10 Revision No. 6

AC Sources-Operating B 3.8.1

BASES ACTIONS (continued)

The Completion Time for Required Action C.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action the Completion Time only begins on discovery that both:

a. All required offsite circuits are inoperable; and

b. A required feature is inoperable.

If at any time during the existence of Condition C (two offsite circuits inoperable) a required feature becomes inoperable, this Completion Time begins to be tracked.

According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition C for a period that should not exceed 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . This level of degradation means that the offsite electrical power system does not have the capability to effect a safe shutdown and to mitigate the effects of an accident; however, the onsite AC sources have not been degraded. This level of degradation generally corresponds to a total loss of the immediately accessible offsite power sources .

Because of the normally high availability of the offsite sources, this level of degradation may appear to be more severe than other combinations of two AC sources inoperable that involve one or more DGs inoperable.

However, two factors tend to decrease the severity of this level of degradation: *

a. The configuration of the redundant AC electrical power system that remains available is not susceptible to a single bus or switching failure; and

b. The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unavailable onsite AC source.

With both of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a OBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time provides a period of time to effect restoration of one of Catawba Units 1 and 2 B 3.8.1-11 Revision No. 6

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria.

According to Reference 6, with the available offsite AC sources, two less than required by the LCO, operation may continue for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . If two offsite sources are restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , unrestricted operation may continue. If only one offsite source is restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , power operation continues in accordance with Condition A D.1 and D.2 Pursuant to LCO 3.0.6, the Distribution System ACTIONS would not be entered even if all AC sources to it were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition D are modified by a Note to indicate that when Condition D is entered with no AC source to any train, the Conditions and Required Actions for LCO 3.8.9, "Distribution Systems-Operating," must be immediately entered. This allows Condition D to provide requirements for the loss of one offsite circuit and one DG, without regard to whether a train is de-energized. LCO 3.8.9 provides the appropriate restrictions for a de-energized train.

According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition D for a period that should not exceed 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

In Condition D, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the reliability of the power systems in this Condition may appear higher than that in Condition C (loss of both required offsite circuits).

This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

With Train A and Train B DGs inoperable, there are no remaining standby AC sources. Thus, with an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the Catawba Units 1 and 2 B 3.8.1-12 Revision No. 6

AC Sources-Operating B 3.8.1

BASES ACTIONS (continued) minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown (the immediate shutdown could cause grid instability, which could result in a total loss of AC power). Since any inadvertent generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.

According to Reference 7, with both DGs inoperable, operation may continue for a period that should not exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

Ll The sequencer(s) is an essential support system to both the offsite circuit and the DG associated with a given ESF bus. Furthermore, the sequencer is on the primary success path for most major AC electrically powered safety systems powered from the associated ESF bus .

Therefore, loss of an ESF bus sequencer affects every major ESF system in the train. When a sequencer is inoperable, its associated unit and train related offsite circuit and DG must also be declared inoperable and their corresponding Conditions must also be entered. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining sequencer OPERABILITY. This time period also ensures that the probability of an accident (requiring sequencer OPERABILITY) occurring during periods when the sequencer is inoperable is minimal.

G.1 and G.2 If the inoperable AC electric power sources cannot be restored to OPERABLE status within the required Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging plant systems .

Catawba Units 1 and 2 B 3.8.1-13 Revision No. 6

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

H.1 Condition H corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown.

SURVEILLANCE The AC sources are designed to permit inspection and testing of all REQUIREMENTS important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, Appendix A, GDC 18 (Ref. 9).

Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulated accident conditions). The SRs for demonstrating the OPERABILITY of the DGs are in accordance with the recommendations of Regulatory Guide 1.9 (Ref. 3), Regulatory Guide 1.108 (Ref. 10), and Regulatory Guide 1.137 (Ref. 11 ), as addressed in the UFSAR.

Where the SRs discussed herein specify voltage and frequency tolerances, the following is applicable. The minimum steady state output

voltage of 3950 V is 95% of the nominal 4160 V output voltage. This value allows for voltage drop to the terminals of 4000 V motors whose minimum operating voltage is specified as 90% or 3600 V. It also allows for voltage drops to motors and other equipment down through the 120 V level where minimum operating voltage is also usually specified as 90%

of name plate rating.

The specified maximum steady state output voltage of 4580 V is equal to the maximum operating voltage specified for 4000 V motors. It ensures that for a lightly loaded distribution system, the voltage at the terminals of 4000 V motors is no more than the maximum rated operating voltages.

The specified minimum and maximum frequencies of the DG are 58.8 Hz and 61.2 Hz, respectively. These values are equal to+/- 2% of the 60 Hz nominal frequency and are derived from the recommendations given in Regulatory Guide 1.9 (Ref. 3).

Catawba Units 1 and 2 B 3.8.1-14 Revision No. 6

AC Sources-Operating B 3.8.1

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.1 This SR ensures proper clircuit continuity for the offsite AC electrical power supply to the onsit distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to e sure that distribution buses and loads are connected to their preferr d power source, and that appropriate independence of offsite circuits is maintained. The Surveillance Frequency is based on o erating experience, equipment reliability, and plant risk and is controlle under the Surveillance Frequency Control Program.

SR 3.8.1.2 and SR 3.8.1.7 These SRs help to ensur the availability of the standby electrical power supply to mitigate DBAs nd transients and to maintain the unit in a safe shutdown condition.

To minimize the wear on oving parts that do not get lubricated when the engine is not running, the e SRs are modified by a Note (Note 2 for SR 3.8.1.2) to indicate th tall DG starts for these Surveillances may be preceded by an engine pr lube period and followed by a warmup period prior to loading.

For the purposes of SR 3.8.1.2 and SR 3.8.1.7 testing, the DGs are started from standby con itions using a manual start, loss of offsite power signal, safety injec ion signal, or loss of offsite.power coincident with a safety injection sig al. Standby conditions for a DG mean that the diesel engine coolant and oil are being continuously circulated and temperature is being mai tained consistent with manufacturer recommendations.

In order to reduce stress nd wear on diesel engines, the manufacturer recommends a modified art in which the starting speed of DGs is limited, warmup is limited o this lower speed, and the DGs are gradually accelerated to synchrono s speed prior to loading. These start procedures are the intent f Note 3, which is only applicable when such modified start procedures are recommended by the manufacturer.

Catawba Units 1 and 2 B 3.8.1-15 Revision No. 6

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.7 requires that the DG starts from standby conditions and achieves required voltage and frequency within 11 seconds. The 11 second start requirement supports the assumptions of the design basis LOCA analysis in the UFSAR, Chapter 15 (Ref. 5).

The 11 second start requirement is not applicable to SR 3.8.1.2 (see Note 3) when a modified start procedure as described above is used. If a modified start is not used, the 11 second start requirement of SR 3.8.1.7 applies.

Since SR 3.8.1. 7 requires a 11 second start, it is more restrictive than SR 3.8.1.2, and it may be performed in lieu of SR 3.8.1.2. This is the intent of Note 1 of SR 3.8.1.2.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.3 This Surveillance verifies that the DGs are capable of synchronizing with

the offsite electrical system and accepting loads greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.

Although no power factor. requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0.

The 0.8 value is the design rating of the machine, while the 1.0 is an operational limitation to ensure circulating currents are minimized. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by four Notes. Note 1 indicates that diesel engine runs for this Surveillance may include gradual loading, as recommended Catawba Units 1 and 2 B 3.8.1-16 Revision No. 6

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized. Note 2 states that momentary transients, because of changing bus loads, do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test. Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations. Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.

SR 3.8.1.4 This SR provides verification that the level of fuel oil in the day tank is at or above the level at which fuel oil is automatically added. The level is expressed as an equivalent volume in gallons, and is selected to ensure adequate fuel oil for a minimum of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months of DG operation at full load plus 10%.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program .

SR 3.8.1.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the fuel oil day tanks eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. This SR is for preventative maintenance.

The presence of water does not necessarily represent failure of this SR, provided the accumulated water is removed during the performance of this Surveillance.

Catawba Units 1 and 2 B 3.8.1-17 Revision No. 6

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.6 This Surveillance demonstrates that each required fuel oil system operates and transfers fuel oil from its associated storage tanks to its associated day tank. This is required to support continuous operation of standby power sources. This Surveillance provides assurance that the fuel oil valve is OPERABLE, and allows gravity feed of fuel oil to the day tank from underground storage tanks, to ensure the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for fuel transfer systems are OPERABLE.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.7 See SR 3.8.1.2.

SR 3.8.1.8 Transfer of each 4.16 kV ESF bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the capability of the alternate circuit distribution network to power the shutdown loads. The alternate circuit distribution network consists of an offsite power source through a 6.9 kV bus incoming breaker, its associated 6.9 kV bus tie breaker and the aligned 6.9/4.16 kV transformer to the essential bus.

The requirement of this SR is the transfer from the normal offsite circuit to the alternate offsite circuit via the automatic and manual actuation of the 6.9 kV bus tie breaker and 6.9 kV bus incoming breakers upon loss of the normal offsite source that is being credited. The 6.9 kV bus tie breaker provides a means for each of the offsite circuits to act as a backup in the event power is not available from one of the circuits. The Catawba power system design, without the tie breaker, meets all GDC 17 requirements as well as all other standards to which Catawba is committed. If the tie breaker is incapable of closing manually or automatically during its required MODE of applicability, then the Surveillance is not met and the norrnal offsite circuit that supplies that Class 1E ESF bus is inoperable and the applicable Condition shall be entered and the Required Actions shall be performed. Table B 3.8.1-1 identifies the offsite circuit affected by a non-functioning tie breaker.

Catawba Units 1 and 2 B 3.8.1-18 Revision No. 6

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

The intent of the tie breaker is to provide an alternate means of power to a Class 1 E ESF bus; this assumes there are two available offsite circuits.

In the event an offsite circuit is lost for any reason, the function of the tie breaker is to close, and the offsite circuit that is supplying its normally connec_ted Class 1E ESF bus is fully OPERABLE. With the tie breaker closed, then both Class 1E ESF buses are provided power from a single offsite circuit. The normally connected offsite circuit of the Class 1E ESF bus that is being supplied through the tie breaker shall be declared inoperable and the applicable Condition shall be entered and the Required Actions shall be performed. If the tie breaker does not close, then the associated Class 1E ESF bus will be supplied power from its associated DG. In this event, the associated offsite circuit is inoperable and the applicable Condition shall be entered and the Required Actions shall be performed. Capability of manually swapping to a standby transformer is not required to satisfy this SR. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program .

e Catawba Units 1 and 2 B 3.8.1-19 Revision No. 6

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

Table B 3.8.1-1 (page 1 of 1)

Relationship between Tie Breakers and Offsite Circuits Tie Breaker Description Essential Load Center and Affected Offsite Transformer Circuit 1TA-7 7kV Bus 1TA 1ETA from 1ATC Tie Breaker 1TC-7 7kV Bus 1TC 1ETA from SATA from Unit 1 Tie Breaker 1A 2TC-7 7kV Bus 2TC 1ETA from SATA from Unit 2 Tie Breaker 1TD-7 7kV Bus 1TD 1ETB from 1ATD Tie Breaker 1TB-7 7kV Bus 1TB 1ETB from SATB from Unit 1 Tie Breaker 18 2TB-7 2TA-7

?kV Bus 2TB Tie Breaker 7kV Bus 2TA Tie Breaker 1ETB from SATB from Unit 2 2ETA from 2ATC

1TC-7 7kV Bus 1TC 2ETA from SATA from Unit 1 Tie Breaker 2A 2TC-7 7kV Bus 2TC 2ETA from SATA from Unit 2 Tie Breaker 2TD-7 7kV Bus 2TD 2ETB from 2ATD Tie Breaker 1TB-7 7kV Bus 1TB 2ETB from SATB from Unit 1 28 Tie Breaker 2TB-7 7kV Bus 2TB 2ETB from SATB from Unit 2 Tie Breaker Catawba Units 1 and 2 B 3.8.1-20 Revision No. 6

AC Sources-Operating B 3.8.1 BASES e SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.9 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. For this unit, the single load for each DG and its horsepower rating is as follows: Nuclear Service Water pump which is a 1000 H.P. motor. This Surveillance may be accomplished by:

a. Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power, or while solely supplying the bus; or

b. Tripping its associated single largest post-accident load with the DG solely supplying the bus.

As required by Regulatory Guide 1.9 (Ref. 3), the load rejection test is acceptable if the increase in diesel speed does not exceed 75% of the difference between synchronous speed and the overspeed trip setpoint.

The value of 63 Hz has been selected for the frequency limit for the load rejection and it is a more conservative limit than required by Reference 3.

The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 (Ref. 3) recommendations for response during load sequence intervals. The 3 seconds specified is equal to 60% of a typical 5 second load sequence interval associated with sequencing of the largest load. The voltage and frequency specified are consistent with the design range of the equipment powered by the DG. SR 3.8.1.9.a corresponds to the maximum frequency excursion, while SR 3.8.1.9.b and SR 3.8.1.9.c are steady state voltage and frequency values to which the system must recover following load rejection. The Surveillance Frequency is based on operating experience,

equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note. In order to ensure that the DG is tested under load conditions that are as close to design basis conditions as possible, the Note requires that, if synchronized to offsite power, testing must be performed using a power factor::::; 0.9. This power factor is chosen to be representative of the actual design basis inductive loading that the DG would experience .

Catawba Units 1 and 2 B 3.8.1-21 Revision No. 6

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.10 This Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits.

The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions. This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide for DG damage protection. While the DG is not expected to experience this transient during an event and continues to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.

Although not representative of the design basis inductive loading that the DG would experience, a power factor of approximately unity (1.0) is used for testing. This power factor is chosen in accordance with manufacturer's recommendations to minimize DG overvoltage damage during testing.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.11 As required by Regulatory Guide 1.108 (Ref. 10), paragraph 2.a.(1), this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source. This test verifies all actions encountered from the loss of offsite power, including shedding of the nonessential loads and energization of the emergency buses and respective loads from the DG. It further demonstrates the capability of the DG to automatically achieve the required voltage and frequency within the specified time.

The DG autostart time of 11 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability is achieved.

Catawba Units 1 and 2 B 3.8.1-22 Revision No. 6

AC Sources-Operating B 3.8.1

BASES SURVEILLANCE REQUIREMENTS (continued)

The requirement to verify the connection and power supply of the emergency bus and autoconnected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, Emergency Core Cooling Systems (ECCS) injection valves are not desired to be stroked open, or high pressure injection systems are not capable of being operated at full flow, or residual heat removal (RHR) systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG systems to perform these functions is acceptable.

This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This restriction from normally performing the Surveillance in MODE 1, 2, 3, or 4 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, at a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE 1, 2, 3, or 4. Risk insights or deterministic methods may be used for this assessment. Credit may be taken for unplanned events that satisfy this SR.

Catawba Units 1 and 2 B 3.8.1-23 Revision No. 6

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (11 seconds) from the design basis actuation signal (LOCA signal) and operates for ~ 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. SR 3.8.1.12.d ensures that the emergency bus remains energized from the offsite electrical power system on an ESF signal without loss of offsite power.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. This SR is modified by a Note.

The reason for the Note is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations.

SR 3.8.1.13 This Surveillance demonstrates that DG non-emergency protective functions (e.g., high jacket water temperature) are bypassed on a loss of voltage signal concurrent with an ESF actuation test signal. Non-emergency automatic trips are all automatic trips except:

a. Engine overspeed;

b. Generator differential current;

c. Low - low lube oil pressure; and

d. Voltage control overcurrent relay scheme.

The non-emergency trips are bypassed during DBAs and provide an alarm on an abnormal engine condition. This alarm provides the operator with sufficient time to react appropriately. The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG. Currently, DG emergency automatic trips are tested periodically per the station periodic maintenance program.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

Catawba Units 1 and 2 B 3.8.1-24 Revision No. 6

AC Sources-Operating B 3.8.1

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.14 Regulatory Guide 1.108 (Ref. 10), paragraph 2.a.(3), requires demonstration that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelubricating and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.

In order to ensure that the DG is tested under load conditions that are as close to design conditions as possible, testing must be performed using a power factor of~ 0.9. This power factor is chosen to be representative of the actual design basis inductive loading that the DG would experience.

The load band is provided to avoid routine overloading of the DG.

Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program .

This Surveillance is modified by a Note. The Note states that momentary transients due to changing bus loads do not invalidate this test. Similarly, momentary power factor transients above the power factor limit will not invalidate the test.

SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage and frequency within 11 seconds. The 11 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. The load band is provided to avoid routine overloading of the DG. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. The requirement that the diesel has operated for at least an hour at full load

Catawba Units 1 and 2 B 3.8.1-25 Revision No. 6

AC Sources-Operating B 3.8.1 BASES conditions prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. Momentary transients due to changing bus loads do not invalidate this test. Note 2 allows all DG starts to be preceded by an engine prelube period to minimize wear and tear on the diesel during testing.

SR 3.8.1.16 As required by Regulatory Guide 1.108 (Ref. 10), paragraph 2.a.(6), this Surveillance ensures that the manual synchronization and automatic load transfer from the DG to the offsite source can be made and the DG can be returned to standby operation when offsite power is restored. It also ensures that the autostart logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs. The DG is considered to be in standby operation when the DG is at rated speed and voltage, the output breaker is open and can receive an autoclose signal on bus undervoltage, and the load sequence timers are reset.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This restriction from normally performing the Surveillance in MODE 1, 2, 3, or 4 is further amplified to allow the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, at a minimum, consider the potential outcomes and transients associated with a failed Surveillance, a successful Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when the Surveillance is performed in MODE 1, 2, 3, or 4. Risk insights or deterministic methods may be used for this assessment. Credit may be taken for unplanned events that satisfy this SR.

Catawba Units 1 and 2 B 3.8.1-26 Revision No. 6

AC Sources-Operating B 3.8.1

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.17 Demonstration of the test mode override ensures that the DG availability under accident conditions will not be compromised as the result of testing and the DG will automatically reset to standby operation if a LOCA actuation signal is received during operation in the test mode. Standby operation is defined as the DG running at rated speed and voltage with the DG output breaker open. These provisions for automatic switchover are required by Regulatory Guide 1.9 (Ref. 3).

The requirement to automatically energize the emergency loads with offsite power is essentially identical to that of SR 3.8.1.12. The intent in the requirement associated with SR 3.8.1.17 .b is to show that the emergency loading was not affected by the DG operation in test mode.

In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This restriction from normally performing the Surveillance in MODE 1, 2, 3, or 4 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, at a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE 1, 2, 3, or 4. Risk insights or, deterministic methods may be used for this assessment. Credit may be taken for unplanned events that satisfy this SR.

Catawba Units 1 and 2 B 3.8.1-27 Revision No. 6

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.18 Under accident and loss of offsite power conditions loads are sequentially connected to the bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents. The load sequence time interval tolerance in Table 8-6 of Reference 2 ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated.

Table 8-6 of Reference 2 provides a summary of the automatic loading of ESF buses.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.19 In the event of a OBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

This Surveillance demonstrates the DG operation, as discussed in the Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ESF actuation signal. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations for DGs. The reason for Note 2 is that the performance of the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. This restriction from normally performing the Surveillance in MODE 1, 2, 3, or 4 is further amplified to Catawba Units 1 and 2 B 3.8.1-28 Revision No. 6

AC Sources-Operating B 3.8.1

BASES SURVEILLANCE REQUIREMENTS (continued) allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, at a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE 1, 2, 3, or 4. Risk insights or deterministic methods may be used for this assessment. Credit may be taken for unplanned events that satisfy this SR.

SR 3.8.1.20 This Surveillance demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by a Note. The reason for the Note is to minimize wear on the DG during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations .

Catawba Units 1 and 2 B 3.8.1-29 Revision No. 6

AC Sources-Operating B 3.8.1 BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.

2. UFSAR, Chapter 8.

3. Regulatory Guide 1.9, Rev. 2, December 1979.

4. UFSAR, Chapter 6.

5. UFSAR, Chapter 15.

6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

7. Regulatory Guide 1.93, Rev. 0, December 1974.

8. Generic Letter 84-15, "Proposed Staff Actions to Improve and Maintain Diesel Generator Reliability," July 2, 1984.

9. 10 CFR 50, Appendix A, GDC 18.

10. Regulatory Guide 1.108, Rev. 1, August 1977 (Supplement September 1977).

11. Regulatory Guide 1.137, Rev. 1, October 1979.

12. ASME, Boiler and Pressure Vessel Code,Section XI.

13. Response to a Request for Additional Information (RAI) concerning the June 5, 2006 License Amendment Request (LAR) Applicable to Technical Specification (TS) 3.8.1, "AC Sources-Operating,"

Surveillance Requirement (SR) 3.8.1.13, (TAC NOS. MD3217, MD3218, MD3219, and MD3220), April 4, 2007.

Catawba Units 1 and 2 B 3.8.1-30 Revision No. 6

DC Sources-Operating B 3.8.4

B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.4 DC Sources-Operating BASES BACKGROUND The station DC electrical power system provides the AC emergency power system with control power. It also provides both motive and control power to selected safety related equipment and preferred AC vital bus power (via inverters). As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the DC electrical power system is designed to have sufficient independence, redundancy, and testability to perform its safety functions, assuming a single failure. The DC electrical power system also conforms to the recommendations of Regulatory Guide 1.6 (Ref. 2) and IEEE-308 (Ref. 3).

The 125 VDC electrical power system consists of four independent and redundant safety related Class 1E DC electrical power subsystems (Channels A, B, C, and D). Each channel consists of one 125 VDC battery (each battery is capable of supplying 2 channels of DC loads for a train), the associated battery charger(s) for each battery, and all the associated control equipment and interconnecting cabling.

There is one spare battery charger which provides backup service in the event that the preferred battery charger is out of service. If the spare battery charger is substituted for one of the preferred battery chargers, then the requirements of independence and redundancy between trains

. are maintained.

During normal operation, the 125 VDC load is powered from the battery chargers with the batteries floating on the system. In case of loss of normal power to the battery charger, the DC load is automatically powered from the station batteries.

The Channels A and D of DC electrical power subsystems or the Diesel Generator (DG) DC electrical power subsystems provide through auctioneering diode assemblies, the buses EDE for the A train and EDF for the B train to supply the control power for its associated Class 1E AC power load group, 4.16 kV switchgear, and 600 V load centers. The DC electrical power subsystems also provide DC electrical power to the inverters, which in turn power the AC vital buses .

Catawba Units 1 and 2 B 3.8.4-1 Revision No. 11

DC Sources-Operating B 3.8.4 BASES BACKGROUND (continued)

The DC power distribution system is described in more detail in Bases for LCO 3.8.9, "Distribution System-:-Operating," and LCO 3.8.1 O, "Distribution Systems-Shutdown."

Each 125 V vital DC battery (EBA, EBB, EBC, EBO) has adequate storage capacity to carry the required duty cycle of its own load group and the loads of another load group for a period of two hours. Each 125 V vital DC battery is also capable of supplying the anticipated momentary loads during this two hour period. The 125 V DC DG batteries have adequate storage capacity to carry the required duty cycle for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

Each 125 V vit~I DC battery is separately housed in a ventilated room apart from its charger and distribution centers. Each subsystem or channel is located in an area separated physically and electrically from the other subsystem to ensure that a single failure in one subsystem does not cause a failure in a redundant subsystem. There is no sharing between redundant Class 1E subsystems, such as batteries, battery chargers, or distribution panels, except for the spare battery charger which may be aligned to either train.

The batteries for each channel DC electrical power subsystems are sized to produce require~ capacitdy aft 80% of namedplahte rati~J* correspondingd ~

to warranted capacity at en o life cycles an t e 100 10 design deman . W' Battery size is based on 125% of required capacity. The voltage limit is 2.13 V per cell, which corresponds to a total minimum voltage output of 125 V per battery discussed in the UFSAR, Chapter 8 (Ref. 4). The criteria for sizing large lead storage batteries are defined in IEEE-485 (Ref. 5).

Each channel of DC electrical power subsystem has ample power output capacity for the steady state operation of connected loads required during normal operation, while at the same time maintaining its battery bank fully charged. Each battery charger also has sufficient capacity to restore the battery from the design minimum charge to its fully charged state within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months while supplying normal steady state loads discussed in the UFSAR, Chapter 8 (Ref. 4).

APPLICABLE The initial conditions of Design Basis Accident (OBA) and transient SAFETY ANALYSES analyses in the UFSAR, Chapter 6 (Ref. 6), and in the UFSAR, Chapter 15 (Ref. 7), assume that Engineered Safety Feature (ESF) systems are OPERABLE. The DC electrical power system provides Catawba Units 1 and 2 B 3.8.4-2 Revision No. 11

DC Sources-Operating B 3.8.4 BASES APPLICABLE SAFETY ANALYSES (continued) normal and emergency DC electrical power for the DGs, emergency auxiliaries, and control and switching during all MODES of operation.

The OPERABILITY of the DC sources is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining the DC sources OPERABLE during accident conditions in the event of:

a. An assumed loss of all offsite AC power or all onsite AC power; and

b. A worst case single failure.

The DC sources satisfy Criterion 3 of 10 CFR 50.36 (Ref. 8).

LCO The DC electrical power subsystems, each subsystem consisting of one battery, battery charger and the corresponding control equipment and interconnecting cabling supplying power to the associated bus within the train are required to be OPERABLE to ensure the availability of the required power to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (AOO) or a postulated OBA. Loss of any train DC electrical power subsystem does not prevent the minimum safety function from being performed (Ref. 4).

An OPERABLE DC electrical power subsystem requires a battery and respective charger to be operating and connected to the associated DC bus.

APPLICABILITY The DC electrical power sources are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure safe unit operation and to ensure that:

a. Acceptable fuel design limits and reactor coolant pressure .

boundary limits are not exceeded as a result of AOOs or abnormal transients; and

b. Adequate core cooling is provided, and containment integrity and other vital functions are maintained in the event of a postulated OBA.

The DC electrical power requirements for MODES 5 and 6 are addressed in the Bases for LCO 3.8.5, "DC Sources-Shutdown."

Catawba Units 1 and 2 B 3.8.4-3 Revision No. 11

DC Sources-Operating 8 3.8.4 BASES ACTIONS A.1 and A.2 Condition A represents the loss of one channel for a DC source. The inoperable channel must be energized from an OPERABLE source within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The inoperable channel may be powered from that train's other DC channel battery by closing the bus tie breakers. Each channel battery is sized and tested to supply two channels of DC for a period of two hours, in the event of a postulated OBA. Being powered from an OPERABLE source, the inoperable channel must be returned to OPERABLE status within 10 days or the plant must be prepared for a safe and orderly shutdown. The spare battery charger (ECS), which must be powered from the same train which it is supplying, may be substituted for the channel's battery charger to maintain a fully OPERABLE channel. In this case, Condition A is not applicable.

8.1 and 8.2 If the inoperable channel of DC electrical power subsystem cannot be restored to OPERABLE status within the required Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To

achieve this status, the unit must be brought to at least MODE 3 within 6.hours and to MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required

unit conditions from full power conditions in an orderly manner and .

without .challenging plant systems.

Condition C represents one train's loss of the ability to adequately supply the DG with the required DC power and the DG is inoperable. The DG is no longer capable of supplying the required 4.16 kV AC power and

. applicable Condition(s) and Required Action(s) for the AC sources must be entered immediately.

D.1 Being powered from auctioneering diode circuits from either the A channel of DC or the A Train of DG DC, distribution center EDE supplies breaker control power to the 4.16 kV AC and the 600 VAC switchgear, auxiliary feedwater pump controls, and other important DC loads. The EDF center is powered from the 8 Train of DG DC or the D channel of DC and provides DC power to Train 8 loads, similar to EDE center. With Catawba Units 1 and 2 8 3.8.4-4 Revision No. 11

DC Sources-Operating B 3.8.4

BASES ACTIONS (continued) the loss of the channel DC power and the associated DG DC power, the load center power for the train is inoperable and the Condition(s) and Required Action(s) for the Distribution Systems must be entered immediately.

SURVEILLANCE SR 3.8.4.1 REQUIREMENTS Verifying battery terminal voltage while on float charge for the batteries helps to ensure the effectiveness of the charging system and the ability of the batteries to perform their intended function. Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery (or battery cell) and maintain the battery (or a battery cell) in a fully charged state. The voltage requirements are based on the nominal design voltage of the battery and are consistent with the initial voltages assumed in the battery sizing calculations. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program .

SR 3.8.4.2 Not used.

SR 3.8.4.3 For the DC channel and DG batteries, visual inspection to detect corrosion of the battery terminals and connections, or measurement of the resistance of each intercell, interrack, intertier, and terminal connection, provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance. The presence of visible corrosion does not necessarily represent a failure of this SR, provided an evaluation determines that the visible corrosion does not affect the OPERABILITY of the battery.

For any connection that shows corrosion, the resistance shall be measured at that connection to verify acceptable connection resistance (Ref. 11 ). The limits for battery connection resistance are specified in Table 3.8.4-1 .

Catawba Units 1 and 2 B 3.8.4-5 Revision No. 11

DC Sources-Operating B 3.8.4 BASES SURVEILLANCE REQUIREMENTS (continued)

The plant safety analyses do not assume a specific battery connection resistance value, but typically assume that the batteries will supply adequate power for a specified period of time. The resistance of each battery connection varies independently from all the others. Some of these individual connection resistance values may be higher or lower than the others, and the battery will still be able to perform its design function. Overall connection resistance, which is the sum total of all connection resistances, has a direct impact on battery operability. The values listed in Table 3.8.4-1 are based on the battery manufacturer's recommended connection voltage drop. As long as battery connection resistance values are at or below the values listed in Table 3.8.4-1, battery OPERABILITY will not be in question based on intercell, interrack, intertier, and terminal connection resistance*.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.4.4 For the DC channel and DG batteries, visual inspection of the battery

cells, cell plates, and battery racks provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance. The presence of physical damage or deterioration does not necessarily represent a failure of this SR, provided an evaluation determines that the physical damage or deterioration does not affect the OPERABILITY of the battery (its ability to perform its design function).

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.4.5 and SR 3.8.4.6 Visual inspection and resistance measurements of intercell, interrack, intertier, terminal, and the average intercell connection resistance provide an indication of physical damage or abnormal deterioration that could indicate degraded battery condition. Average intercell connection resistance is defined as the battery manufacturer's maximum allowed intercell connection *voltage drop divided by the maximum battery duty cycle load current, and includes the battery post to intercell connection resistance. The limits for battery connection resistance are specified in Table 3.8.4-1.

Catawba Units 1 and 2 B 3.8.4-6 Revision No. 11

DC Sources-Operating B 3.8.4

BASES SURVEILLANCE REQUIREMENTS (continued)

The plant safety analyses do not assume a specific battery connection resistance value, but typically assume that the batteries will supply adequate power for a specified period of time. The resistance of each battery connection varies independently from all the others. Some of these individual connection resistance values may be higher or lower than the others, and the battery will still be able to perform its design function. Overall connection resistance, which is the sum total of all connection resistances, has a direct impact on battery operability. The values listed in Table 3.8.4-1 are based on the battery manufacturer's recommended connection voltage drop. As long as battery connection resistance values are at or below the values listed in Table 3.8.4-1, battery OPERABILITY will not be in question based on intercell, interrack, intertier, and terminal connection resistance. The anticorrosion material, as recommended by the manufacturer for the batteries, is used to help ensure good electrical connections and to reduce terminal deterioration.

The visual inspection for corrosion is not intended to require removal of and inspection under each terminal connection. The removal of visible corrosion is a preventive maintenance SR. The presence of visible corrosion does not necessarily represent a failure of this SR provided visible corrosion is removed during performance of SR 3.8.4.5 .

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.4.7 This SR requires that each battery charger for the DC channel be capable of supplying at least 200 amps and at least 75 amps for the DG chargers. All chargers shall be tested at a voltage of at least 125 V for

.: 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . These requirements are based on the design capacity of the chargers (Ref. 4). According to Regulatory Guide 1.32 (Ref. 10), the battery charger supply is required to be based on the largest combined demands of the various steady state loads and the charging capacity to restore the battery from the design minimum charge state to the fully charged state, irrespective of the status of the unit during these demand occurrences. The minimum required amperes and duration ensures that these requirements can be satisfied.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program .

Catawba Units 1 and 2 B 3.8.4-7 Revision No. 11

DC Sources-Operating B 3.8.4 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.4.8 A battery service test is a special test of battery capability, as found, to satisfy the design requirements (battery duty cycle) of the DC electrical power system. The vital battery's actual duty cycle is identified in calculation CNC-1381.05-00-0011, 125 voe Vital Instrumentation and Control Power System Battery and Battery Charger Sizing Calculation.

The test duty cycle is the actual duty cycle adjusted for the temperature correction factor for 60°F operation, and a design margin of typically 1O to 15% for load addition. The minimum DC battery terminal voltage is determined through Calculation CNC-1381.05-00-0149, 125 voe Vital l&C Power System (EPL) Voltage Drop Analysis. The DG battery's actual duty cycle is identified in calculation CNC-1381.05-00-0050, 125 VDC Diesel Generator Battery and Battery Charger Sizing Calculation.

The test duty cycle is the actual duty cycle adjusted for the temperature correction factor for 60°F operation, and a design margin of typically 1O to 15% for load addition. The minimum DG battery terminal voltage is determined through Calculations CNC-1381.05-00-0235, Unit 1 125 VDC Essential Diesel Power System (EPQ) Voltage Drop Analysis and CNC-1381.05-00-0236, Unit 2 125 voe Essential Diesel Power System (EPQ)

Voltage Drop Analysis. (Note: The duty cycle in the UFSAR is used for battery sizing and includes the temperature factor of 11 %, a design

margin of 15%, and an aging factor of 25%.)

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. Note 1 allows the performance of a modified performance discharge test in lieu of a service test.

The modified performance discharge test is a performance discharge test that is augmented to include the high-rate, short duration discharge loads (during the first minute and 11-to-12 minute discharge periods) of the service test. The duty cycle of the modified performance test must fully envelope the duty cycle of the service test if the modified performance discharge test is to be used in lieu of the service test. Since the ampere-hours removed by the high-rate, short duration discharge periods of the service test represents a very small portion of the battery capacity, the test rate can be changed to that for the modified performance discharge test without compromising the results of the performance discharge test.

The battery terminal voltage for the modified performance discharge test should remain above the minimum battery terminal voltage specified in the battery service test for the duration of time equal to that of the service test.

Catawba Units 1 and 2 B 3.8.4-8 Revision No. 11

DC Sources-Operating B 3.8.4

BASES SURVEILLANCE REQUIREMENTS (continued)

A modified discharge test is a test of the battery capacity and its ability to provide a high rate, short duration load (usually the highest rates of the duty cycle). This will often confirm the battery's ability to meet the critical periods of the load duty cycle, in addition to determining its percentage of rated capacity. Initial conditions for the modified performance discharge test should be identical to those specified for a service test. The reason for Note 2 is that performing the Surveillance would perturb the electrical distribution system and challenge safety systems. This restriction from normally performing the Surveillance in MODE 1, 2, 3, or 4 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, at a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE 1, 2, 3, or 4. Risk insights or deterministic methods may be used for this assessment. Credit may be taken for unplanned events that satisfy this SR.

SR 3.8.4.9 A battery performance discharge test is a test of constant current capacity of a battery, normally done in the as found condition, after having been in service, to detect any change in the capacity determined by the acceptance test. The test is intended to determine overall battery degradation due to age and usage.

A battery modified performance discharge test is described in the Bases for SR 3.8.4.8. Either the battery performance discharge test or the modified performance discharge test is acceptable for satisfying SR 3.8.4.9; however, only the modified performance discharge test may be used to satisfy SR 3.8.4.9 while satisfying the requirements of SR 3.8.4.8 at the same time.

The acceptance criteria for this Surveillance are consistent with IEEE-450 (Ref. 9). This reference recommends that the battery be replaced if its capacity is below 80% of the manufacturer's rating. A capacity of 80%

Catawba Units 1 and 2 B 3.8.4-9 Revision No. 11

DC Sources-Operating B 3.8.4 BASES SURVEILLANCE REQUIREMENTS (continued) shows that the battery rate of deterioration is increasing, even if there is ample capacity to meet the load requirements.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. If the battery shows degradation, or if the battery has reached 85% of its expected life and capacity is < 100% of the manufacturer's rating, the Surveillance Frequency is reduced to 18 months. However (for DC vital batteries only), if the battery shows no degradation but has reached 85% of its expected life, the Surveillance Frequency is only reduced to 24 months for batteries that retain capacity::::: 100% of the manufacturer's rating.

Degradation is indicated, according to IEEE-450 (Ref. 9), when the battery capacity drops by more than 10% relative to its average capacity on the previous performance tests or when it is ::::: 10% below the manufacturer's rating. This SR is modified by a Note which is applicable to the DG batteries only. The reason for the Note is that performing the Surveillance would perturb the associated electrical distribution system and challenge safety systems. This restriction from normally performing

.the Surveillance in MODE 1, 2, 3, or 4 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, at a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE 1, 2, 3, or 4. Risk insights or deterministic methods may be used for this assessment. Credit may be taken for unplanned events that satisfy this SR.

Catawba Units 1 and 2 B 3.8.4-10 Revision No. 11

DC Sources-Operating B 3.8.4 BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.

2. Regulatory Guide 1.6, March 10, 1971.

3. IEEE-308-1971 and 1974.

4. UFSAR, Chapter 8.

5. IEEE-485-1983, June 1983.

6. UFSAR, Chapter 6.

7. UFSAR, Chapter 15.

8. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

9. IEEE-450-1975 and/or 1980.

10. Regulatory Guide 1.32, February 1977.

11. IEEE-450-1995 .

Catawba Units 1 and 2 B 3.8.4-11 Revision No. 11

RHR and Coolant Circulation-High Water Level B 3.9.4

B 3.9 REFUELING OPERATIONS B 3.9.4 Residual Heat Removal (RHR) and Coolant Circulation-High Water Level BASES BACKGROUND The purpose of the RHR System in MODE 6 is to remove decay heat and sensible heat from the Reactor Coolant System (RCS), as required by GDC 34, to provide mixing of borated coolant and to prevent boron stratification (Ref. 1). Heat is removed from the RCS by circulating reactor coolant through the RHR heat exchanger(s), where the heat is transferred to the Component Cooling Water System. The coolant is then returned to the RCS via the RCS cold leg(s). Operation of the RHR System for normal cooldown or decay heat removal is manually accomplished from the control room. The heat removal rate is adjusted by controlling the flow of reactor coolant and component cooling water through the RHR heat exchanger(s). Mixing of the reactor coolant is maintained by this continuous circulation of reactor coolant through the RHR System.

APPLICABLE If the reactor coolant temperature is not maintained below 200°F, boiling SAFETY ANALYSES of the reactor coolant could result. This could lead to a loss of coolant in the reactor vessel. Additionally, boiling of the reactor coolant could lead to a reduction in boron concentration in the coolant due to boron plating out on components near the areas of the boiling activity. The loss of reactor coolant and the reduction of boron concentration in the reactor coolant would eventually challenge the integrity of the fuel cladding, which is a fission product barrier. One train of the RHR System is required to be operational in MODE 6, with the water level ~ 23 ft above the top of the reactor vessel flange, to prevent this challenge. The LCO does permit de-energizing the RHR pump for short durations, under the condition that the boron concentration is not diluted. This conditional de-energizing of the RHR pump does not result in a challenge to the fission product barrier.

The RHR System satisfies Criterion 4 of 10 CFR 50.36 (Ref. 2).

LCO Only one RHR loop is required for decay heat removal in MODE 6, with the water level*~ 23 ft above the top of the reactor vessel flange. Only one RHR loop is required to be OPERABLE, because the volume of water above the reactor vessel flange provides backup decay heat removal capability. At least one RHR loop must be OPERABLE and in operation to provide:

Catawba Units 1 and 2 B 3.9.4-1 Revision No. 6

RHR and Coolant Circulation-High Water Level B 3.9.4 BASES LCO (continued)

a. Removal of decay heat;

b. Mixing of borated coolant to minimize the possibility of criticality; and

c. Indication of reactor coolant temperature.

An OPERABLE RHR loop includes an RHR pump, a heat exchanger, valves, piping, instruments, and controls to ensure an OPERABLE flow path and to determine the low end temperature. The flow path starts in one of the RCS hot legs and is returned to the RCS cold legs. The operability of the operating RHR train and the supporting heat sink is dependent on the ability to maintain the desired RCS temperature. If not in its normal RHR alignment from the RCS hot leg and returning to the RCS cold legs, the required RHR loop is OPERABLE provided the system may be placed in service from the control room, or may be placed in service in a short period of time by actions outside the control room and there are no restraints to placing the equipment in service. Management of gas voids is important to RHR System OPERABILITY.

The LCO is modified by a Note that allows the required operating RHR loop to be removed from service for up to 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months per 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period, provided no operations are permitted that would dilute the RCS boron concentration with coolant at boron concentrations less than required to meet the minimum boron concentration of LCO 3.9.1. Boron concentration reduction with coolant at boron concentrations less than required to assure the minimum required RCS boron concentration is maintained is prohibited because uniform concentration distribution cannot be ensured without forced circulation. This permits operations such as core mapping or alterations in the vicinity of the reactor vessel hot leg nozzles and RCS to RHR isolation valve testing. During this 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period, decay heat is removed by natural convection to the large mass of water in the refueling cavity.

The acceptability of the LCO and the LCO Note is based on preventing boiling in the core in the event of the loss of RHR cooling. However, it has been determined that when the upper internals are in place in the reactor vessel there is insufficient communication with the water above the core for adequate decay heat removal by natural circulation. As a result, boiling in the core could occur in a relatively short time if RHR cooling is lost. Therefore, during the short period of time that the upper internals are installed, administrative processes are implemented to reduce the risk of core boiling. The availability of additional cooling equipment, including equipment not required to be OPERABLE by the Technical Specifications, contributes to this risk reduction. The plant staff assesses these cooling sources to assure that the desired minimal level of risk is maintained.

Catawba Units 1 and 2 B 3.9.4-2 Revision No. 6

RHR and Coolant Circulation-High Water Level B 3.9.4

BASES LCO (continued)

This is commonly referred to as defense-in-depth. This strategy is consistent with NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management" (Ref. 3).

APPLICABILITY One RHR loop must be OPERABLE and in operation in MODE 6, with the water level ~ 23 ft above the top of the reactor vessel flange, to provide decay heat removal. The 23 ft water level was selected because it corresponds to the 23 ft requirement established for fuel movement in LCO 3.9.6, "Refueling Cavity Water Level." Requirements for the RHR System in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS), and Section 3.5, Emergency Core Cooling Systems (ECCS). RHR loop requirements in MODE 6 with the water level

< 23 ft are located in LCO 3.9.5, "Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level."

ACTIONS RHR loop requirements are met by having one RHR loop OPERABLE and in operation, except as permitted in the Note to the LCO .

If RHR loop requirements are not met, there will be no forced circulation to provide mixing to establish uniform boron concentrations. Suspending positive reactivity additions that could result in failure to meet the minimum boron concentration limit is required to assure continued safe operation.

Introduction of coolant inventory must be from sources that have a boron concentration greater than that which would be required in the RCS for minimum refueling boron concentration. This may result in an overall reduction in RCS boron concentration, but provides acceptable margin to maintaining subcritical operation.

If RHR loop requirements are not met, actions shall be taken immediately to suspend loading of irradiated fuel assemblies in the core. With no forced circulation cooling, decay heat removal from the core occurs by natural convection to the heat sink provided by the water above the core.

A minimum refueling water level of 23 ft above the reactor vessel flange provides an adequate available heat sink. Suspending any operation that would increase decay heat load, such as loading a fuel assembly, is a prudent action under this condition.

Catawba Units 1 and 2 B 3.9.4-3 Revision No. 6

RHR and Coolant Circulation-High Water Level 8 3.9.4 BASES ACTIONS (continued)

If RHR loop requirements are not met, actions shall be initiated and continued in order to satisfy RHR loop requirements. With the unit in MODE 6 and the refueling water level ~ 23 ft above the top of the reactor vessel flange, corrective actions shall be initiated immediately.

A.4, A.5, A.6.1, and A.6.2 When RHR loop requirements are not met, the following actions must be taken:

a. The containment equipment hatch must be closed and secured with four bolts,

b. One door in each air lock must be closed, and

c. Each penetration providing direct access from the containment atmosphere to the outside atmosphere must be either closed by a manual or automatic isolation valve, blind flange, or equivalent, or verified to be capable of being closed on a high containment radiation signal.

With RHR loop requirements not met, the potential exists for the coolant to boil and release radioactive gas to the containment atmosphere.

Performing the actions described above ensures that all containment penetrations are either closed or can be closed so that the dose limits are not exceeded.

The Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months allows fixing of most RHR problems and is reasonable, based on the low probability of the coolant boiling in that time.

SURVEILLANCE , SR 3.9.4.1 REQUIREMENTS This Surveillance demonstrates that the RHR loop is in operation and circulating reactor coolant. The flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability and to prevent thermal and boron stratification in the core. The RCS temperature is determined to ensure the appropriate decay heat removal is maintained. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

Catawba Units 1 and 2 8 3.9.4-4 Revision No. 6

RHR and Coolant Circulation-High Water Level B 3.9.4

BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.9.4.2 RHR System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR loops and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.

Selection of RHR System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.

The RHR System is OPERABLE when it is sufficiently filled with water.

Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump),

the Surveillance is not met. If it is determined by subsequent evaluation that the RHR System is not rendered inoperable by the accumulated gas (i.e., the system is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas.should be eliminated or brought within the acceptance criteria limits.

RHR System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations.

Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.

Catawba Units 1 and 2 B 3.9.4-5 Revision No. 6

RHR and Coolant Circulation-High Water Level B 3.9.4 BASES SURVEILLANCE REQUIREMENTS (continued)

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation.

REFERENCES 1. UFSAR, Section 5.5.7.

2. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

3. NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management."

Catawba Units 1 and 2 B 3.9.4-6 Revision No. 6

RHR and Coolant Circulation-Low Water Level B 3.9.5

B 3.9 REFUELING OPERATIONS B 3.9.5 Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level BASES BACKGROUND The purpose of the RHR System in MODE 6 is to remove decay heat and sensible heat from the Reactor Coolant System (RCS), as required by GDC 34, to provide mixing of borated coolant, and to prevent boron stratification (Ref. 1). Heat is removed from the RCS by circulating reactor coolant through the RHR heat exchangers where the heat is transferred to the Component Cooling Water System. The coolant is then returned to the RCS via the RCS cold leg(s). Operation of the RHR System for normal cooldown decay heat *removal is manually accomplished from the control room. The heat removal rate is adjusted by controlling the flow of reactor coolant and component cooling water through the RHR heat exchanger(s). Mixing of the reactor coolant is maintained by this continuous circulation of reactor coolant through the RHR System.

APPLICABLE If the reactor coolant temperature is not maintained below 200°F, boiling SAFETY ANALYSES of the reactor coolant could result. This could lead to a loss of coolant in the reactor vessel. Additionally, boiling of the reactor coolant could lead to a reduction in boron concentration in the coolant due to the boron plating out on components near the areas of the boiling activity. The loss of reactor coolant and the reduction of boron concentration in the reactor coolant will eventually challenge the integrity of the fuel cladding, which is a fission product barrier. Two trains of the RHR System are required to be OPERABLE, and one train in operation, in order to prevent this challenge.

The RHR System satisfies Criterion 4 of 10 CFR 50.36 (Ref. 2).

LCO In MODE 6, with the water level< 23 ft above the top of the reactor vessel flange, both RHR loops must be OPERABLE.

Additionally, one loop of RHR must be in operation in order to provide:

a. Removal of decay heat;

b. Mixing of borated coolant to minimize the possibility of criticality; and

c. Indication of reactor coolant temperature .

Catawba Units 1 and 2 B 3.9.5-1 Revision No. 6

RHR and Coolant Circulation-Low Water Level B 3.9.5 BASES LCO (continued)

This LCO is modified by two Notes. Note 1 permits the RHR pumps to be removed from operation for s 15 minutes when switching from one train to another. The circumstances for stopping both RHR pumps are to be limited to situations when the outage time is short and the core outlet temperature is maintained > 1O degrees F below saturation temperature.

Note 1 also prohibits boron dilution or draining operations when RHR forced flow is stopped. Note 2 allows one RHR loop to be inoperable for a period of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months provided the other loop is OPERABLE and in operation.

Prior to declaring the loop inoperable, consideration should be given to the existing plant configuration. This consideration should include that the core time to boil is short, there is no draining operation to further reduce RCS water level, and that the capability exists to inject borated water into the reactor vessel. This permits surveillance tests to be performed on the inoperable loop during a time when these tests are safe and possible.

An OPERABLE RHR loop consists of an RHR pump, a heat exchanger, valves, piping, instruments and controls to ensure an OPERABLE flow path and to determine the low end temperature. The flow path starts in one of the RCS hot legs and is returned to the RCS cold legs. The operability of the operating RHR train and the supporting heat sink is dependent on the ability to maintain the desired RCS temperature. If not in its normal RHR alignment from the RCS hot leg and returning to the

RCS cold legs, the required RHR loop is OPERABLE provided the system may be placed in service from the control room, or may be placed in service in a short period of time by actions outside the control room and there are no restraints to placing the equipment ii") service. Management of gas voids is important to RHR System OPERABILITY.

Both RHR pumps may be aligned to the Refueling Water Storage Tank to support filling the refueling cavity or for performance of required testing.

APPLICABILITY Two RHR loops are required to be OPERABLE, and one RHR loop must be in operation in MODE 6, with the water level < 23 ft above the top of the reactor vessel flange, to provide decay heat removal. Requirements for the RHR System in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS), and Section 3.5, Emergency Core Cooling Systems (ECCS). RHR loop requirements in MODE 6 with the water level ;;::: 23 ft are located in LCO 3.9.4, "Residual Heat Removal (RHR) and Coolant Circulation-High Water Level."

Catawba Units 1 and 2 B 3.9.5-2 Revision No. 6

RHR and Coolant Circulation-Low Water Level B 3.9.5

BASES ACTIONS A.1 and A.2 If less than the required number of RHR loops are OPERABLE, action shall be immediately initiated and continued until the RHR loop is restored to OPERABLE status and to operation or until ~ 23 ft of water level is established above the reactor vessel flange. When the water level is

~ 23 ft above the reactor vessel flange, the Applicability changes to that of LCO 3.9.4, and only one RHR loop is required to be OPERABLE and in operation. An immediate Completion Time is necessary for an operator to initiate corrective actions.

If no RHR loop is in operation, there will be no forced circulation to provide mixing to establish uniform boron concentrations. Suspending positive reactivity additions that could result in failure to meet the minimum boron concentration limit is required to assure continued safe operation.

Introduction of coolant inventory must be from sources that have a boron concentration greater than that which would be required in the RCS for minimum refueling boron concentration. This may result in an overall reduction in RCS boron concentration, but provides acceptable margin to maintaining subcritical operation .

If no RHR loop is in operation, actions shall be initiated immediately, and continued, to restore one RHR loop to operation. Since the unit is in Conditions A and B concurrently, the restoration of two OPERABLE RHR loops and one operating RHR loop should be accomplished expeditiously.

B.3, B.4, B.5.1, and B.5.2 If no RHR loop is in operation, the following actions must be taken:

a. The containment equipment hatch must be closed and secured with four bolts,

b. One door in each air lock must be closed, and

c. Each penetration providing direct access from the containment atmosphere to the outside atmosphere must be either closed by a manual or automatic isolation valve, blind flange, or equivalent, or verified to be capable of being closed on a high radiation signal.

With RHR loop requirements not met, the potential exists for the coolant to boil and release radioactive gas to the containment atmosphere.

Performing the actions described above ensures that all containment penetrations are either closed or can be closed so that the dose limits are not exceeded .

Catawba Units 1 and 2 B 3.9.5-3 Revision No. 6

RHR and Coolant Circulation-Low Water Level B 3.9.5 BASES The Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months allows fixing of most RHR problems and is reasonable, based on the low probability of the coolant boiling in that time.

SURVEILLANCE SR 3.9.5.1 REQUIREMENTS This Surveillance demonstrates that one RHR loop is in operation and circulating reactor coolant. The flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability, prevent vortexing in the suction of the RHR pumps, and to prevent thermal and boron stratification in the core. The RCS temperature is determined to ensure the appropriate decay heat removal is maintained. In addition, during operation of the RHR loop with the water level in the vicinity of the reactor vessel nozzles, the RHR pump suction requirements must be met.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.9.5.2 Verification that the required pump is OPERABLE ensures that an additional RCS or RHR pump can be placed in operation, if needed, to maintain decay heat removal and reactor coolant circulation. Verification is performed by verifying proper breaker alignment and power available to the required pump. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.9.5.3 RHR System piping and components have the potential to develop voids and pockets of-entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR loops and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.

Selection of RHR System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.

Catawba Units 1 and 2 B 3.9.5-4 Revision No. 6

RHR and Coolant Circulation-Low Water Level B 3.9.5

BASES SURVEILLANCE REQUIREMENTS (continued)

The RHR System is OPERABLE when it is sufficiently filled with water.

Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an acceptance criteria for gas volume at the suction or discharge of a pump),

the Surveillance is not met. If it is determined by subsequent evaluation that the RHR System is not rendered inoperable by the accumulated gas (i.e., the system is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits.

RHR System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations.

Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or

- personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by location susceptible to gas accumulation.

REFERENCES 1. UFSAR, Section 5.5.7.

2. 10 CFR 50.36, Technical Specifications, (c)(2)(ii) .

Catawba Units 1 and 2 B 3.9.5-5 Revision No. 6

RHR and Coolant Circulation-Low Water Level B 3.9.5

B 3.9 REFUELING OPERATIONS B 3.9.5 Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level BASES BACKGROUND The purpose of the RHR System in MODE 6 is to remove decay heat and sensible heat from the Reactor Coolant System (RCS), as required by GDC 34, to provide mixing of borated coolant, and to prevent boron stratification (Ref. 1). Heat is removed from the RCS by circulating reactor coolant through the RHR heat exchangers where the heat is transferred to the Component Cooling Water System. The coolant is then returned to the RCS via.the RCS cold leg(s). Operation of the RHR System for normal cooldown decay heat removal is manually accomplished from the control room. The heat removal rate is adjusted by controlling the flow of reactor coolant and component cooling water through the RHR heat exchanger(s). Mixing of the reactor coolant is maintained by this continuous circulation of reactor coolant through the RHR System.

APPLICABLE If the reactor coolant temperature is not maintained below 200°F, boiling SAFETY ANALYSES of the reactor coolant could result. This could lead to a loss of coolant in the reactor vessel. Additionally, boiling of the reactor coolant could lead to a reduction in boron concentration in the coolant due to the boron plating out on components near the areas of the boiling activity. The loss of reactor coolant and the reduction of boron concentration in the reactor coolant will eventually challenge the integrity of the fuel cladding, which is a fission product barrier. Two trains of the RHR System are required to be OPERABLE, and on~ train in operation, in order to prevent this challenge.

The RHR System satisfies Criterion 4 of 10 CFR 50.36 (Ref. 2).

LCO In MODE 6, with the water level < 23 ft above the top of the reactor vessel flange, both RHR loops must be OPERABLE.

Additionally, one loop of RHR must be in operation in order to provide:

a. Removal of decay heat;

b. Mixing of borated coolant to minimize the possibility of criticality; and C. Indication of reactor coolant temperature.

Catawba Units 1 and 2 B 3.9.5-1 Revision No. 5

RHR and Coolant Circulation-Low Water Level B 3.9.5 BASES LCO (continued)

This LCO is modified by two Notes. Note 1 permits the RHR pumps to be removed from operation for ~ 15 minutes when switching from one train to another. The circumstances for stopping both RHR pumps are to be limited to situations when the outage time is short and the core outlet temperature is maintained > 10 degrees F below saturation temperature.

Note 1 also prohibits boron dilution or draining operations when RHR forced flow is stopped. Note 2 allows one RHR loop to be inoperable for a period of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months provided the other loop is OPERABLE and in operation.

Prior to declaring the loop inoperable, consideration should be given to the existing plant configuration. This consideration should include that the core time to boil is short, there is no draining operation to further reduce RCS water level, and that the capability exists to inject borated water into the reactor vessel. This permits surveillance tests to be performed on the inoperable loop during a time when these tests are safe and possible.

An OPERABLE RHR loop consists of an RHR pump, a heat exchanger, valves, piping, instruments and controls to ensure an OPERABLE flow path and to determine the low end temperature. The flow path starts in one of the RCS hot legs and is returned to the RCS cold legs. The operability of the operating RHR train and the supporting heat sink is dependent on the ability to maintain the desired RCS temperature. If not in its normal RHR alignment from the RCS hot leg and returning to the RCS cold legs, the required RHR loop is OPERABLE provided the system may be placed in service from the control room, or may be placed in service in a short period of time by actions outside the control room and there are no restraints to placing the equipment in service. Management of gas voids is important to RHR System OPERABILITY.

Both RHR pumps may be aligned to the Refueling Water Storage Tank to support filling the refueling cavity or for performance of required testing.

APPLICABILITY Two RHR loops are required to be OPERABLE, and one RHR loop must be in operation in MODE 6, with the water level < 23 ft above the top of the reactor vessel flange, to provide decay heat removal. Requirements for the RHR System in other MODES are covered by LCOs in Section 3.4, Reactor Coolant System (RCS), and Section 3.5, Emergency Core Cooling Systems (ECCS). RHR loop requirements in MODE 6 with the water level ~ 23 ft are located in LCO 3.9.4, "Residual Heat Removal (RHR) and Coolant Circulation-High Water Level."

Catawba Units 1 and 2 B 3.9.5-2 Revision No. 5

RHR and Coolant Circulation-Low Water Level B 3.9.5 e BASES ACTIONS A.1 and A.2 If less than the required number of RHR loops are OPERABLE, action shall be immediately initiated and continued until the RHR loop is restored to OPERABLE status and to operation or until ;:c: 23 ft of water level is established above the reactor vessel flange. When the water level is

c

23 ft above the reactor vessel flange, the Applicability changes to that of LCO 3.9.4, and only one RHR loop is required to be OPERABLE and in operation. An immediate Completion Time is necessary for an operator to initiate corrective actions.

If no RHR loop is in operation, there will be no forced circulation to provide mixing to establish uniform boron concentrations. Suspending positive reactivity additions that could result in failure to meet the minimum boron concentration limit is required to assure continued safe operation.

Introduction of coolant inventory must be from sources that have a boron concentration greater than that which would be required in the RCS for minimum refueling boron concentration. This may result in an overall reduction in RCS boron concentration, but provides acceptable margin to maintaining subcritical operation .

If no RHR loop is in operation, actions shall be initiated immediately, and continued, to restore one RHR loop to operation. Since the unit is in Conditions A and B concurrently, the restoration of two OPERABLE RHR loops and one operating RHR loop should be accomplished expeditiously.

If no RHR loop is in operation, all containment penetrations providing direct access from the containment atmosphere to the outside atmosphere must be closed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . With the RHR loop requirements not met, the potential exists for the coolant to boil and release radioactive gas to the containment atmosphere. Closing containment penetrations that are open to the outside atmosphere ensures that dose limits are not exceeded. The Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is appropriate for the majority of time during refueling operations, based on time to coolant boiling, since water level is not routinely maintained at low levels .

Catawba Units 1 and 2 B 3.9.5-3 Revision No. 5

RHR and Coolant Circulation-Low Water Level B 3.9.5 BASES SURVEILLANCE REQUIREMENTS SR 3.9.5.1 This Surveillance demonstrates that one RHR loop is in operation and circulating reactor coolant. The flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability, prevent vortexing in the suction of the RHR pumps, and to prevent thermal and boron stratification in the core. The RCS temperature is determined to

. ensure the appropriate decay heat removal is maintained. In addition, during operation of the RHR loop with the water level in the vicinity of the reactor vessel nozzles, the RHR pump suction requirements must be met.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.9.5.2 Verification that the required pump is OPERABLE ensures that an additional RCS or RHR pump can be placed in operation, if needed, to maintain decay heat removal and reactor coolant circulation. Verification is performed by verifying proper breaker alignment and power available to the required pump. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.9.5.3 RHR System piping and components have the potential to develop voids and pockets of entrained gases. Preventing and managing gas intrusion and accumulation is necessary for proper operation of the RHR loops and may also prevent water hammer, pump cavitation, and pumping of noncondensible gas into the reactor vessel.

Selection of RHR System locations susceptible to gas accumulation is based on a review of system design information, including piping and instrumentation drawings, isometric drawings, plan and elevation drawings, and calculations. The design review is supplemented by system walk downs to validate the system high points and to confirm the location and orientation of important components that can become sources of gas or could otherwise cause gas to be trapped or difficult to remove during system maintenance or restoration. Susceptible locations depend on plant and system configuration, such as stand-by versus operating conditions.

The RHR System is OPERABLE when it is sufficiently filled with water.

Acceptance criteria are established for the volume of accumulated gas at susceptible locations. If accumulated gas is discovered that exceeds the acceptance criteria for the susceptible location (or the volume of accumulated gas at one or more susceptible locations exceeds an Catawba Units 1 and 2 B 3.9.5-4 Revision No. 5

RHR and Coolant Circulation-Low Water Level B 3.9.5

BASES SURVEILLANCE REQUIREMENTS (continued) acceptance criteria for gas volume at the suction or discharge of a pump),

the Surveillance is not met. If it is determined by subsequent evaluation that the RHR System is not rendered inoperable by the accumulated gas (i.e., the system is sufficiently filled with water), the Surveillance may be declared met. Accumulated gas should be eliminated or brought within the acceptance criteria limits.

RHR System locations susceptible to gas accumulation are monitored and, if gas is found, the gas volume is compared to the acceptance criteria for the location. Susceptible locations in the same system flow path which are subject to the same gas intrusion mechanisms may be verified by monitoring a representative sub-set of susceptible locations.

Monitoring may not be practical for locations that are inaccessible due to radiological or environmental conditions, the plant configuration, or personnel safety. For these locations alternative methods (e.g., operating parameters, remote monitoring) may be used to monitor the susceptible location. Monitoring is not required for susceptible locations where the maximum potential accumulated gas void volume has been evaluated and determined to not challenge system OPERABILITY. The accuracy of the method used for monitoring the susceptible locations and trending of the results should be sufficient to assure system OPERABILITY during the Surveillance interval.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. The Surveillance Frequency may vary by

location susceptible to gas accumulation.

REFERENCES 1. UFSAR, Section 5.5.7.

2. 10 CFR 50.36, Technical Specifications, (c)(2)(ii) .

Catawba Units 1 and 2 B 3.9.5-5 Revision No. 5

Enclosure 3 SLC Manual Insertion/Removal Instructions

Remove and Insert Replace the following page(s) of Catawba Nuclear Station Selected Licensee Commitments (SLC) Manual with the attached revised page(s). The revised page(s) are identified by Section number and contains marginal lines indicating the areas of change.

REMOVE THESE PAGES INSERT THESE PAGES LIST OF EFFECTIVE SECTIONS Pages 1-5 Pages 1-5 Revision 69 Revision 72 List of Effective Sections Revisions 70 and 71 have been superseded by Revision 72 and therefore do not need to be replaced in the SLC Manual.

TAB 16.9 16.9-1, Pages 1-7 16.9-1, Pages 1-7 Revision 8 Revision 9 16.9-4, Pages 1-12 16.9-4, Pages 1-12 Revision 4 Revision 5 16.9-5, Pages 1-22 16.9-5, Pages 1-22 Revision 7 Revision 8 TAB 16.11 16.11-7, Pages 1-15 16.11-7, Pages 1-15 Revision 9 Revision 10 If you have any questions concerning the contents of this Catawba Nuclear Station Selected Licensee Commitments (SLC) Manual update, please contact Toni Lowery at (803) 701-5046.

Enclosure 4 SLC Manual Replacement Pages

LIST OF EFFECTIVE SECTIONS

SECTION TABLE OF CONTENTS 16.1 REVISION NUMBER 15 1

REVISION DATE 05/10/16 08/27/08 16.2 2 08/21/09 16.3 1 08/21/09 16.5-1 4 09/15/16 16.5-2 Deleted 16.5-3 1 02/20/04 16.5-4 0 10/09/02 16.5-5 1 01/28/10 16.5-6 1 08/21/09 16.5-7 2 02/06/15 16.5-8 2 12/22/08 16.5-9 1 02/20/12 16.5-10 Deleted 16.6-1 0 10/09/02 16.6-2 Deleted 16.6-3 1 08/21/09 16.6-4 1 08/21/09 16.6-5 2 01/09/13 16.7-1 1 08/21/09 16.7-2 4 02/03/11 16.7-3 4 07/27/13 16.7-4 2 08/21/09 16.7-5 2 08/21/09

Catawba Units 1 and 2 Page 1 Revision 72

LIST OF EFFECTIVE SECTIONS

SECTION 16.7-6 16.7-7 REVISION NUMBER 3

1 REVISION DATE 06/10/16 08/21/09 16.7-8 2 08/21/09 16.7-9 10 08/03/17 16.7-10 7 03/28/16 16.7-11 1 08/21/09 16.7-12 1 08/21/09 16.7-13 3 06/10/16 16.7-14 1 08/21/09 16.7-15 1 08/21/09 16.7-16 0 06/08/09 16.7-17 0 02/10/15 16.7-18 0 05/10/16 16.8-1 6 12/10/15 16.8-2 2 02/20/12 16.8-3 1 10/24/06 16.8-4 2 11/05/07 16.8-5 3 08/21/09 16.9-1 9 12/18/17 16.9-2 6 08/03/17 16.9-3 4 08/03/17 16.9-4 5 09/11/17 16.9-5 8 09/11/17 16.9-6 11 08/03/17

Catawba Units 1 and 2 Page 2 Revision 72

LIST.OF EFFECTIVE SECTIONS

SECTION 16.9-7 16.9-8 REVISION NUMBER 4

5 REVISION DATE 08/21/09 08/21/09 16.9-9 3 08/21/09 16.9-10 5 08/21/09 16.9-11 3 08/21/09 16.9-12 3 02/10/15 16.9-13 4 09/27/16 16.9-14 1 09/25/06 16.9-15 2 08/21/09 16.9-16 2 08/21/09 16.9-17 0 10/09/02 16.9-18 0 10/09/02 16.9-19 3 02/20/12 16.9-20 0 10/09/02 16.9-21 1 . 10/13/16 16.9-22 1 08/21/09 16.9-23 5 08/03/17 16.9-24 2 10/24/06 16.9-25 2 08/21/09 16.9-26 0 03/05/12 16.10-1 1 08/21/09 16.10-2 1 10/24/06 16.10-3 1 08/21/09 16.11-1 1 07/27/13 Catawba Units 1 and 2 Page 3 Revision 72

LIST OF EFFECTIVE SECTIONS

SECTION 16.11-2 16.11-3 REVISION NUMBER 4

0 REVISION DATE 02/10/15 10/09/02 16.11-4 1 08/21/09 16.11-5 0 10/09/02 16.11-6 3 08/03/15 16.11-7 10 11/29/17 16.11-8 0 10/09/02 16.11-9 0 10/09/02 16.11-10 1 08/21/09 16.11-11 1 03/20/03 16.11-12 0 10/09/02 16.11-13 1 07/27/13 16.11-14 0 10/09/02 16.11-15 0 10/09/02 16.11-16 1 10/24/11 16.11-17 0 10/09/02 16.11-18 1 08/21/09 16.11-19 0 10/09/02 16.11-20 2 03/28/16 16.11-21 0 10/09/02 16.12-1 0 10/09/02 16.13-1 1 08/03/17 16.13-2 Deleted 16.13-3 Deleted

Catawba Units 1 and 2 Page4 Revision 72

LIST OF EFFECTIVE SECTIONS

SECTION 16.13-4 REVISION NUMBER 1

REVISION DATE 08/03/17

Catawba Units 1 and 2 Page 5 Revision 72

Fire Suppression Water System 16.9-1

16.9 AUXILIARY SYSTEMS 16.9-1 Fire Suppression Water System COMMITMENT The Fire Suppression Water System shall be FUNCTIONAL with:

a. At least two fire suppression pumps, each with a capacity of 2500 gpm, with their discharge aligned to the fire suppression header, and

b. A FUNCTIONAL flow path capable of taking suction from Lake Wylie and transferring the water through distribution piping with FUNCTIONAL sectionalizing valves and isolation valves for each sprinkler system, hose standpipe, or fire hydrant required to be FUNCTIONAL per SLCs 16.9-2, 16.9-4, and 16.9-23.

APPLICABILITY: At all times .

Catawba Units 1 and 2 16.9-1-1 Revision 9

Fire Suppression Water System 16.9-1 REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One required pump A.1 Restore non-functional 7 days and/or associated water equipment to supply non-functional. FUNCTIONAL status.

OR A.2 Provide alternate backup 7 days pump or supply.

B. Automatic starting B.1 Place at least one pump in Immediately function for all required continuous operation.

pumps non-functional.

AND B.2 Restore non-functional 7 days equipment to FUNCTIONAL status.

C. Sectionalizing or isolation valve non-functional.

C.1 Evaluate impact on downstream fire suppression features (sprinkler system, hose standpipe, or fire hydrant) and enter SLCs 16.9-2, 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 16.9-4, and 16.9-23 as necessary.

AND C.2 Implement necessary 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months administrative controls to ensure a FUNCTIONAL flow path is maintained.

D. Fire Suppression Water 0.1 Establish backup Fire 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months System non-functional Suppression Water for reasons other than System.

Condition A, B, or C.

Catawba Units 1 and 2 16.9-1-2 Revision 9

Fire Suppression Water System 16.9-1

TESTING REQUIREMENTS TR 16.9-1-1 TEST Start each electric motor-driven pump and operate it for~

FREQUENCY 21 days on a I 15 minutes on recirculation flow. STAGGERED TEST BASIS TR 16.9-1-2 Verify that each manual, power operated, or automatic In accordance with valve in the flow path, which is accessible during plant performance operation, is in the correct position. based criteria in BASES TR 16.9-1-3 Perform a system flush of the outside distribution loop 6 months and verify no flow blockage by fully opening the hydraulically most remote hydrant.

TR 16.9-1-4 ---------------------------------NO TE---------------------------------

Not applicable to valves RF389B, RF447B, and RF457B.

TR 16.9-1-5 Cycle each testable valve in the flow path through at least one complete cycle of full travel.

Verify that each manual, power operated, or automatic valve in the flow path, which is inaccessible during plant 12 months 18 months operation, is in the correct position.

TR 16.9-1-6 Perform a system functional test, including simulated 18 months automatic actuation of the system throughout its operating sequence, and:

a. Verify that each fire suppression pump starts within 1O psig of its intended starting pressure (A pump, primary switch - 95 psig; B pump, primary switch - 90 psig; and C pump, primary switch -

85 psig); and

b. Verify that each pump develops~ 2500 gpm at a net pressure ~ 144 psig by testing at three points on the pump performance curve.

(continued)

Catawba Units 1 and 2 16.9-1-3 Revision 9

Fire Suppression Water System 16.9-1 TESTING REQUIREMENTS (continued TR 16.9-1-7 TEST Cycle each valve in the flow path which is not testable FREQUENCY 18 months during plant operation through at least one complete cycle of full travel.

TR 16.9-1-8 Perform a system flow test in accordance with Chapter 8, 3 years Section 16 of the National Fire Protection Association Fire Protection Handbook, 15th Edition.

BASES The FUNCTIONALITY of the Fire Suppression Systems ensures that adequate fire suppression capability is available to confine and extinguish fires occurring in any portion of the facility where safety related equipment is located. The Fire Suppression System consists of the water supply/distribution system, sprinkler systems, fire hose stations, fire hydrants, and CO 2 systems. The collective capability of the Fire Suppression Systems is adequate to minimize potential damage to safety related equipment and is. a major element in the facility Fire Protection Program.

The intent of COMMITMENT b. is to ensure a FUNCTIONAL flow path

from the water source (in this case Lake Wylie), through FUNCTIONAL pumps a.s required in COMMITMENT a., and through the main header distribution piping - up to and including the branch lines for each sprinkler system, hose standpipe, or fire hydrant required to be FUNCTIONAL per SLCs 16.9-2, 16.9-4, and 16.9-23. When a sectionalizing valve or an isolation valve becomes non-functional, then the fire suppression features

(sprinkler system, hose standpipe, or fire hydrant) affected must be evaluated and the applicable SLCs entered (16.9-2, 16.9-4, and 16.9-23).

Condition C of this SLC would only apply if a non-functional sectionalizing valve(s) or isolation valve(s) rendered the entire main distribution piping non-functional.

The intent of TR 16.9-1-4 and TR 16.9-1-7 is to ensure the sectionalizing valve (main header valve used to isolate sections of the header) or isolation valve (branch line valve used to isolate specific fire suppression features (sprinkler system, hose standpipe, or fire hydrant)) is operating properly and can be used to achieve isolation when called upon. If a sectionalizing or isolation valve cannot be cycled but is in the correct position ensuring a FUNCTIONAL flow path (fully open) as required by COMMITMENT b., then the associated feature (sprinkler system, hose standpipe, or fire hydrant) can be considered FUNCTIONAL. If a sectionalizing or isolation valve cannot be cycled and is in the incorrect BASES (continued)

Catawba Units 1 and 2 16.9-1-4 Revision 9

Fire Suppression Water System 16.9-1

position, or its position cannot be determined, thereby not ensuring a FUNCTIONAL flow path (not fully open) as required by COMMITMENT b., then the affected fire suppression feature (sprinkler system, hose standpipe, or fire hydrant) must be evaluated and the applicable SLCs entered (16.9-2, 16.9-4, and 16.9-23). If a sectionalizing valve in a loop header (i.e., flow path from two directions) cannot be cycled and it cannot be verified as fully open, then administrative controls may need to be implemented to ensure the available flow path is not isolated.

The ability to demonstrate that the valves in the RF/RY flow path can be cycled is critical to maintaining the system properly. The containment isolation valves (RF3898 and RF4478) and the annulus sprinkler system isolation valve (RF4578) are required to be cycled or stroked in accordance with the Catawba lnservice Testing Program. Therefore, credit can be taken for cycling these valves under the IWV program, and they do not need to be cycled annually to meet the SLC criteria.

The proper positioning of RF/RY valves is critical to delivering fire suppression water at the fire source as quickly as possible. The option of increasing or decreasing the frequency of valve position verification allows the ability to optimize plant operational resources. Should an adverse trend develop with RF/RY valve positions, the frequency of verification shall be increased. Similarly, if the RF/RYvalve position trends are positive, the frequency of verification could be decreased .

Through programmed trending of RF/RY as found valve positions, the RF/RY System will be maintained at predetermined reliability standards.

The Fire Protection Engineer is responsible for trending and determining verification frequencies based on the following:

Initially the frequency shall be monthly.

Annually review the results of the completed valve position verification procedures.

If the results demonstrate that the valves are found in the correct position at least 99% of the time, the frequency of conducting the valve position verification may be decreased from monthly to quarterly or quarterly to semiannually or semiannually to annually as applicable.

The frequency shall not be extended beyond annually (plus grace period).

If the results demonstrate that the valves are not found in the correct position at least 99% of the time, the frequency of conducting the valve position verification shall be increased from annually to semiannually or semiannually to quarterly or quarterly to monthly as applicable. The valve position verification need not be conducted more often than monthly .

Catawba Units 1 and 2 16.9-1-5 Revision 9

Fire Suppression Water System 16.9-1 BASES (continued)

The term STAGGERED TEST BASIS is from the Catawba Standard Technical Specifications and is defined in the Catawba Surveillance Frequency Control Program (SFCP). The intent of the STAGGERED TEST BASIS for the total population of fire suppression pumps (n = 3) is to ensure at least one pump is tested (start and operate for ~ 15 minutes) once every 21 days. The 21 days is derived from taking the overall targeted frequency (2 months, which equals 63 days in the PM program) divided by the number of components in the population (n = 3). With all three fire suppression pumps available, a different pump shall be tested every 21 days. In the event one of the fire suppression pumps is unavailable, then the two remaining available pumps shall be tested on alternate 21 days. With only one pump available, the remaining pump would be required to be tested every 21 days.

In the event that portions of the Fire Suppression Systems are non-functional, alternate backup fire fighting equipment is required to be made available in the affected areas until the non-functional equipment is restored to service. When the non-functional fire fighting equipment is intended for use as a backup means of fire suppression, a longer period of time is allowed to provide an alternate means of fire fighting than if the non-functional equipment is the primary means of fire suppression.

In the event the Fire Suppression Water System becomes non-functional, immediate corrective measures must be taken since this system provides

the major fire suppression capability of the plant.

Since the requirement for fire suppression pump automatic starting functions is intended to provide a high level of system standby readiness, loss of a primary pressure switch renders its associated main fire pump non-functional. If the primary pressure switch for one of the two required pumps is non-functional, its associated pump is non-functional if not placed in continuous operation and Condition A applies. If both primary pressure switches for the required pumps are non-functional, it is acceptable to place at least one of the two required pumps in continuous operation and restore FUNCTIONALITY within 7 days, which is essentially meeting the requirements of Condition A (one of the two required pumps non-functional).

This SLC is part of the Catawba Fire Protection Program and therefore subject to the provisions of the Catawba Renewed Facility Operating License Conditions 2.C.(5).

REFERENCES 1. Catawba UFSAR, Section 9.5.1.

2. Catawba Nuclear Station 10 CFR 50.48(c) Fire Protection Safety Evaluation (SE).

Catawba Units 1 and 2 16.9-1-6 Revision,9

Fire Suppression Water System 16.9-1

3.

4.

Catawba Plant Design Basis Specification for Fire Protection, CNS-1465.00-00-0006, as revised.

Catawba UFSAR, Section 18.2.8.

5. Catawba License Renewal Commitments, CNS-1274.00 0016, Section 4.12.1.

6. Catawba Renewed Facility Operating License Conditions 2.C.(5). .

7. CN-SFL, Surveillance Frequency List

Catawba Units 1 and 2 16.9-1-7 Revision 9

Fire Hose Stations 16.9-4

16.9 AUXILIARY SYSTEMS 16.9-4 Fire Hose Stations COMMITMENT The Fire Hose Stations shown in Table 16.9-4-1 shall be FUNCTIONAL.

APPLICABILITY: At all times.

REMEDIAL ACTIONS

NOTES-------------------------------------------------------

1. To prevent a hazard to station personnel, plant equipment, or the hose itself, the fire hose can be stored in a roll at the outlet of the FUNCTIONAL Fire Hose Station or Fire Hydrant.

2. Credit can be taken for additional hose in yard hose equipment houses for providing equivalent capacity hose length to reach unprotected area when crediting a Fire Hydrant.

CONDITION REQUIRED ACTION COMPLETION TIME

NO TE------------------

Sig nag e shall be placed at ttie non-functional Fire Hose Station to identify the proper FUNCTIONAL Fire Hose Station or Fire Hydrant to use.

A. One or more Fire Hose A.1 Stage personnel at the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Stations non-functional appropriate locations to due to system establish a Fire Hose alignments associated Station flow path in the with lnservice Valve event of a Fire Brigade Testing for RF389B. response.

OR (continued)

Catawba Units 1 and 2 16.9-4-1 Revision 5

Fire Hose Stations 16.9-4 REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) A.2 Provide additional 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months equivalent capacity fire hose of length to reach unprotected area at nearest FUNCTIONAL Fire Hose Station(s) or Fire Hydrant(s).

---------NO TE----------------------

Signage shall be placed at the non-functional Fire Hose Station to identify the proper FUNCTIONAL Fire Hose Station or Fire Hydrant to use.

8. One or more Fire Hose 8.1 Provide additional 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Stations non-functional equivalent capacity fire for reasons other than hose of length to reach Condition A unprotected area at nearest FUNCTIONAL Fire Hose Station(s) or Fire Hydrant(s).

OR 8.2 Complete an evaluation as Prior to terminating permitted by NRC RIS Required Action 8.1 2005-07 and implement alternative compensatory measures as required Catawba Units 1 and 2 16.9-4-2 Revision 5

Fire Hose Stations 16.9-4 e

TESTING REQUIREMENTS TEST FREQUENCY TR 16.9-4-1 Perform a visual inspection of the Fire Hose Stations In accordance with accessible during plant operation to assure all required performance equipment is at the station and the fire hose shows no based criteria in physical damage. BASES TR 16.9-4-2 Perform a visual inspection of the Fire Hose Stations not 18 months accessible during plant operation to assure all required equipment is at the station and the fire hose shows no physical damage.

TR 16.9-4-3 Inspect all fire hose gaskets and replace any degraded 18 months gaskets in the couplings.

I*

TR 16.9-4-4 Partially open each Fire Hose Station valve to verify 3 years valve FUNCTIONALITY and no flow blockage .

TR 16.9-4-5 Perform a hose hydrostatic test at a pressure of~ 200 3 years psig or~ 50 psig above maximum fire main operating pressure, whichever is greater.

TR 16.9-4-6 Remove each hose from the Fire Hose Station for 3 years inspection and reracking.

TR 16.9-4-7 Perform a functional test which simulates automatic 18 month actuation that verifies automatic valves in the flow path actuate to their correct position .

Catawba Units 1 and 2 16.9-4-3 Revision 5

Fire Hose Stations 16.9-4 Table 16.9-4-1 (page 1 of 7)

Fire Hose Stations

LOCATION ELEVATION HOSE RACK NUMBER

1. Auxiliary Building 59, FF 522+0 1RF235 55, FF 522+0 1RF248 63-64, KK 543+0 1RF210 63, MM 543+0 1RF211 60, MM 543+0 1RF212 58, pp 543+0 1RF218 59, GG-HH 543+0 1RF236 60-61, FF-GG 543+0 1RF237 61-62, CC-DD 543+0 2RFA64 57, JJ 543+0 1RF242 54-55, GG 543+0 1RF249 57, FF 543+0 1RF250 52-53, GG 543+0 1RF255

52-53, CC-DD 543+0 1RFA64 50-51, JJ-KK 543+0 1RF262 53, MM 543+0 1RF268 50-51, NN 543+0 1RF271 62, MM-NN 560+0 1RF203 63, JJ-KK 560+0 1RF213 58, pp 560+0 1RF219 56, NN 560+0 1RF220 59, HH 560+0 1RF239 57, KK 560+0 1RF243 54-55, FF-GG 560+0 1RF251 51, KK 560+0 1RF263 52, MM-NN 560+0 1RF269 58, BB 554+0 1RF484 65, BB-CC 560+0 1RF485 (1) 62, AA-BB 560+0 1RF486 (1) 56, BB 554+0 1RF487 52, AA-BB 560+0 1RF488 (2) 49, BB-CC 560+0 1RF489 {2) 68-69, BB 560+0 1RF996 {1) 45-46, BB 560+0 1RF997 {2}

63, NN 577+0 1RF204 61, LL 577+0 1RF214 63, KK-LL 577+0 1RF215 58, pp 577+0 1RF221 59,JJ 577+0 1RF230 (continued)

Catawba Units 1 and 2 16.9-4-4 Revision 5

Fire Hose Stations 16.9-4

Table 16.9-4-1 (page 2 of 7)

Fire Hose Stations LOCATION ELEVATION HOSE RACK NUMBER 58, GG 577+0 1RF240 56, KK 577+0 1RF244 54, GG 577+0 1RF252 52-53, KK 577+0 1RF258 51, KK 577+0 1RF264 51-52, NN 577+0 1RF272 56, pp 577+0 1RF278 68-69, BB 577+0 1RF478 (3) 65, BB-CC 577+0 1RF479 (3) 59, DD 574+0 1RF480 60,AA 574+0 1RF481 49, BB-CC 577+0 1RF490 (4) 45, BB 577+0 1RF491 (4) 55, DD 574+0 1RF492 54,AA 574+0 1RF493 63,AA 577+0 1RF993 (3) 51, AA 577+0 1RF998 (4) 62, NN 594+0 1RF205 57, MM 594+0 1RF222 63, JJ 594+0 1RF231 57, HH 594+0 1RF245 57, EE 594+0 1RF253 51, JJ 594+0 1RF259 53, NN 594+0 1RF275 64, BB 594+0 1RF984 (3) 50, BB 594+0 1RF985 (4) 51, KK 605+10 1RF265 63, JJ 605+10 1RF233 63-64, MM 631+6 1RF483 50-51, MM 631+6 1RF495

2. Fuel Pools 65, TT-UU 605+10 1RF208 48, TT-UU 605+10 1RF276 63-64, MM 605+10 1RF482 50-51, MM 605+10 1RF822 (continued)

- Catawba Units 1 and 2 16.9-4-5 Revision 5

Fire Hose Stations 16.9-4 Table 16.9-4-1 (page 3 of 7)

Fire Hose Stations LOCATION ELEVATION HOSE RACK NUMBER

3. Low Pressure Service Water (LPSW) Intake Structure 5,A 583+0 1RY178 2, E 583+0 1RY4

4. Service Building 31, S 568+0 1RF163 26, S 568+0 1RF165 23, S 568+0 1RF166 20, R 568+0 1RF168 29, S 568+0 1RF175 20, U 568+0

1RF424.

17, S 568+0 1RF425 35, P 574+0 1RF162 35, U-V 574+0 1RF310 27, R 594+0 1RF167 20, R 594+0 1RF169 18, T 594+0 1RF173 16, S 594+0 1RF174 30, S 594+0 1RF176 32, S 594+0 1RF311 35,Q 594+0 1RF312 35, U 594+0 1RF313 27, U 594+0 1RF314 22, R, 594+0 1RF315 20, P 594+0 1RF316 22, T 594+0 1RF426 18, V 594+0 1RF430 33, Q 608+0 1RF419 33, U 608+0 1RF420 28, V 608+0 1RF971 28, S-T 608+0 1RF972 16, R 610+0 1RF432 37, R 611+0 1RF308 55, cc 611+0 1RF309 37, T 611+0 1RF475 33-34, Q 619+6 1RF422 (continued)

Catawba Units 1 and 2 16.9-4-6 Revision 5

Fire Hose Stations 16.9-4

Table 16.9-4-1 (page 4 of 7)

Fire Hose Stations LOCATION ELEVATION HOSE RACK NUMBER 33-34, U 619+6 1RF423 22, 1N 619+6 1RF853 22, 2N 619+6 2RF853

5. Standby Shutdown Facilitt {SSF}

7,B 594+0 1RF934 7, B 594+0 1RF935 5, C 594+0 1RF936 4, B 594+0 1RF937 6, C 611+0 1RF933

6. Unit 1 Reactor Buildin

126° in Pi~e Chase 552+0 1RF396 6° in Pipe Chase 552+0 1RF397 287° in Pi~e Chase 552+0 1RF398 10° in Lower Containment 552+0 1RF399 202° in Lower Containment 552+0 1RF400 211 ° in Pi12e Chase 552+0 1RF401 68° in Pi12e Chase 565+0 1RF458 10° in Ui2per Containment 605+0 1RF152 170° in U1212er Containment 605+0 1RF153

7. Unit 1 Turbine Building 34, 1H 568+0 1RF28 29, 1L 568+0 1RF45 26, 1L 568+0 1RF48 23, 1M 568+0 1RF50 20, 1N 568+0 1RF53 17, 1L 568+0 1RF56 18, 1H 568+0 1RF59 17, 1E 568+0 1RF62 19, 1E 568+0 1RF63 22, 1E 568+0 1RF67 26, 1E 568+0 1RF70 29, 1E 568+0 1RF73 32, 1E 568+0 1RF74 30, 1H 568+0 1RF77 (continued)

Catawba Units 1 and 2 16.9-4-7 Revision 5

Fire Hose Stations 16.9-4 Table 16.9-4-1 (page 5 of 7)

Fire Hose Stations LOCATION ELEVATION HOSE RACK NUMBER 31, 1L 568+0 1RF78 30, 1H 594+0 1RF22 34, 1H 594+0 1RF30 29, 1L 594+0 1RF44 26, 1L 594+0 1RF47 23, 1M 594+0 1RF49 20, 1L 594+0 1RF52 16, 1J 594+0 1RF55 18,1H/1J 594+0 1RF58 16, 1F 594+0 1RF61 19, 1E 594+0 1RF64 22, 1E 594+0 1RF66 26, 1E 594+0 1RF69 29, 1E 594+0 1RF72 32, 1E 594+0 1RF75 31, 1L 594+0 1RF79 15, 1H 619+6 1RF24 22, 1E 619+6 1RF26 34, 1H 619+6 1RF32 29, 1L 619+6 1RF43 32, 1L 619+6 1RF46 619+6 1RF54 20, 1L 619+6 1RF57 16, 1E 619+6 1RF60 19, 1E 619+6 1RF65 26, 1E 619+6 1RF68 29, 1E 619+6 1RF71 32, 1E 619+6 1RF76 31, 1L 619+6 1RF80

8. Unit 2 Reactor Building*

126° in Pipe Chase 552+0 2RF396 287° in Pipe Chase 552+0 2RF398 10° in Lower Containment 552+0 2RF399 202° in Lower Containment 552+0 2RF400 211 ° in Pipe Chase 552+0 2RF401 6° in Pipe Chase 552+0 2RF397 68° in Pipe Chase 565+0 2RF458 10° in Upper Containment 605+0 2RF152

( continued)

Catawba Units 1 and 2 16.9-4-8 Revision 5

Fire Hose Stations 16.9-4

Table 16.9-4-1 (page 6 of 7)

Fire Hose Stations LOCATION ELEVATION HOSE RACK NUMBER 170° in Upper Containment 605+0 2RF153

9. Unit 2 Turbine Building 34, 2H 568+0 2RF28 29,2L 568+0 2RF45 26,2L 568+0 2RF48 23, 2M 568+0 2RF50 20, 2N 568+0 2RF53 17, 2L/2K 568+0 2RF56 18, 2H/2J 568+0 2RF59 17,2E 568+0 2RF62 19,2E 568+0 2RF63 22,2E 568+0 2RF67 26,2E 568+0 2RF70 29, 2E 568+0 2RF73 32, 2E 568+0 2RF74 30, 2H 568+0 2RF77 31, 2L 568+0 2RF78 30, 2H 594+0 2RF22 34, 2H 594+0 2RF30 29,2L 594+0 2RF44 26,2L 594+0 2RF47 23, 2M 594+0 2RF49 20,2L 594+0 2RF52 16,2J 594+0 2RF55 18, 2H 594+0 2RF58 16,2F 594+0 2RF61 19,2E 594+0 2RF64 22, 2E 594+0 2RF66 26, 2E 594+0 2RF69 29, 2E 594+0 2RF72 32, 2E 594+0 2RF75 31,2L 594+0 2RF79 15, 2H 619+6 2RF24 22,2E 619+6 2RF26 34, 2H 619+6 2RF32 29,2L 619+6 2RF43 26,2L 619+6 2RF46 17,2L 619+6 2RF54 20,2L 619+6 2RF57

'( continued)

Catawba Units 1 and 2 16.9-4-9 Revision 5

Fire Hose Stations 16.9-4 Table 16.9-4-1 (page 7 of 7)

Fire Hose Stations LOCATION ELEVATION HOSE RACK NUMBER 16, 2E 619+6 2RF60 19, 2E 619+6 2RF65 26, 2E 619+6 2RF68 29, 2E 619+6 2RF71 32, 2E 619+6 2RF76 31,2L 619+6 2RF80

The containment Fire Hose Station headers are normally isolated for flood protection reasons and are exempt from Testing Requirement 16.9-4-4.

(1) Isolated by Deluge Valve 2RFB06 (2) Isolated by Deluge Valve 1RFB06 (3) Isolated by Deluge Valve 2RFB10 (4) Isolated by Deluge Valve 1RFB10 Catawba Units 1 and 2 16.9-4-10 Revision 5

Fire Hose Stations 16.9-4

BASES The FUNCTIONALITY of the Fire Suppression Systems ens1:1res that adequate fire suppression capability is available to confine and extinguish fires occurring in any portion of the facility where safety related

equipment is located. The Fire Suppression System consists of the water supply/distribution system, sprinkler systems, fire hose stations, fire hydrants, and CO 2 systems. The collective capability of the Fire Suppression Systems is adequate to minimize potential damage to safety related equipment and is a major element in the facility Fire Protection Program.

The alignment of the Fire Suppression System during lnservice Valve Testing (Containment Valve Injection Water System and stroke time testing) for RF3898 results in the isolation of some of the required hose stations listed in Table 16.9-4-1. The flow path to the isolated hose stations can be restored using a few simple operator actions. The lnservice Valve Test alignments, the staging of personnel, and associated operator actions to reestablish a flow path are controlled by station procedures.

The location of the required equipment at the Fire Hose Station and the physical condition of the fire hose are critical to fire brigade operations.

The option of increasing or decreasing the frequency of the fire hose inspections allows the ability to optimize plant operational resources.

Should an adverse trend develop with Fire Hose Station equipment or fire hose condition, the frequency of the inspection shall be increased.

Similarly, if the Fire Hose Station equipment or fire hose condition trends are positive, the frequency of verification could be decreased. Through programmed trending of Fire Hose Station inspections, Fire Hose Stations will be maintained at predetermined reliability standards. The Fire Protection Engineer is responsible for trending and determining inspection frequencies based on the following:

Initially the frequency shall be monthly.

Annually review the results of the completed Fire Hose Station inspection procedure.

If the results demonstrate that the Fire Hose Stations are found acceptable at least 99% of the time, the frequency of conducting the Fire Hose Station inspection may be decreased from monthly to quarterly or quarterly to semiannually or semiannually to annually as applicable. The frequency shall not be extended beyond annually (plus grace period).

If the results demonstrate that the Fire Hose Stations are not found acceptable at least 99% of the time, the frequency of conducting the Fire Hose Station inspections shall be increased from annually to semiannually or semiannually to quarterly or quarterly to monthly as

Catawba Units 1 and 2 16.9-4-11 Revision 5

Fire Hose Stations 16.9-4 BASES (continued) applicable. The verification need not be conducted more often than monthly.

The SSF, LPSW Intake, Reactor Buildings, Turbine Buildings and Service Building fire hose stations were added as result of transition to the NFPA 805 fire protection licensing basis. NFPA 805 Chapter 3, Section 3.6.1 states that all power block buildings shall have a standpipe and hose system installed.

In the event that portions of the Fire Suppression Systems are non-functional, alternate backup fire fighting equipment is required to be made available in the affected areas until the non-functional equipment is restored to service. When the non-functional fire fighting equipment is intended for use as a backup means of fire suppression, a longer period of time is allowed to provide an alternate means of fire fighting than if the non-functional equipment is the primary means of fire suppression.

The headers for Fire Hose Stations 1RF478, 1RF479, 1RF485, 1RF486, 1RF488, 1RF489, 1RF490, 1RF491, 1RF984, 1RF985, 1RF993, 1RF996, 1RF997, and 1RF998 are isolated by deluge valves that are actuated by manual pull stations located adjacent to each hose station. These headers are maintained isolated in order to satisfy internal flood PRA requirements.

This SLC is part of the Catawba Fire Protection Program and therefore subject to the provisions of the Catawba Renewed Facility Operating License Conditions 2:C.(5).

REFERENCES 1. Catawba UFSAR, Section 9.5.1.

2. Catawba Nuclear Station 10 CFR 50.48(c) Fire Protection Safety Evaluation (SE).

3. Catawba Plant Design Basis Specification for Fire Protection, CNS-1465.00-00-0006, as revised.

4. Catawba UFSAR, Section 18.2.8.

5. Catawba License Renewal Commitments, CNS-1274.00 0016, Section 4.12.1.

6. RIS 2005-07, Compensatory Measures to Satisfy the Fire Protection Program Requirements.

7. Catawba Renewed Facility Operating License Conditions 2.C.(5).

Catawba Units 1 and 2 16.9-4-12 Revision 5

Fire Rated Assemblies 16.9-5

16.9 AUXILIARY SYSTEMS 16.9-5 Fire Rated Assemblies COMMITMENT All required Fire Rated Assemblies (walls, floors/ceilings, cable enclosures and other fire barriers) and all sealing devices in fire rated assembly penetrations (fire doors, fire dampers, and penetration seals) shall be FUNCTIONAL.

APPLICABILITY: At all times.

NOTE---------- .---------------------------------------------

Non-function aI or breached fire barrier features (walls, floors, ceilings, doors, dampers, and penetration seals) in the diesel generator rooms and the auxiliary feedwater pump rooms may affect CO 2 System FUNCTIONALITY. See SLC 16.9-3, "CO 2 Systems".

REMEDIAL ACTIONS IF the required Fire Rated Assembly sealing device is a Fire Door, see Table 16.9-5-1 IF the required Fire Rated Assembly sealing device is a Fire Damper see Table 16.9.:.5-2

IF required Fire Rated Assembly is a Fire Barrier or Penetration Seal:

1. Identify the location of the impaired fire protection feature by elevation, column, and building

2. Refer to CN-1209-10 series drawings to identify the Fire Area on both sides of the impaired feature

3. IF either of the Fire Areas is identified as High Safety Significant (HSS) (see Table 16.9-5-3) then implement the REQUIRED ACTION CONDITION A .

4. IF the Fire Areas are not HSS, then identify the associated shutdown trains/methods of the Fire Areas on each side of the barrier using Table 16.9-5-4 and implement the REQUIRED ACTION as identified in the following Chart:

Shutdown Train (Side 1 & Side 2)

A B sss AorB A andB CONDITION CONDITION CONDITION CONDITION CONDITION A C B B C B CONDITION CONDITION CONDITION CONDITION CONDITION B B C B C B CONDITION CONDITION CONDITION CONDITION CONDITION sss B B C B B CONDITION CONDITION CONDITION CONDITION CONDITION A orB C C B C B CONDITION CONDITION CONDITION CONDITION CONDITION A andB B B B B C

Catawba Units 1 and 2 16.9-5-1 Revision 8

Fire Rated Assemblies 16.9-5 REMEDIAL ACTIONS A.

CONDITION One or more HSS* A.1 REQUIRED ACTION Establish a continuous fire COMPLETION TIME 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months required Fire Rated watch on at least one side Assemblies is non- of the assembly.

functional.

OR A.2.1 Verify at least one side of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months the assembly has FUNCTIONAL fire detection instrumentation.

A.2.2 Establish an hourly fire 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months watch patrol on at least one side of the assembly.

OR A.3 Complete an evaluation as Prior to terminating permitted by NRG RIS 2005-07 to institute required action(s).

Required Action A.1 or A.2

( continued)

Catawba Units 1 and 2 16.9-5-2 Revision 8

Fire Rated Assemblies 16.9-5

REMEDIAL ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B. One or more LSS** B.1 Establish an hourly fire 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months required Fire Rated watch on at least one side Assemblies is non- of the assembly.

functional.

OR B.2.1 Verify at least one side of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months the assembly has FUNCTIONAL fire detection instrumentation.

AND B.2.2 Establish a once per shift 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months fire watch patrol on at least one side of the assembly.

OR

B.3 Complete an evaluation as permitted by NRC RIS 2005-07 to institute required action(s).

Prior to terminating Required Action B.1 or B.2 (continued)

Catawba Units 1 and 2 16.9-5-3 Revision 8

Fire Rated Assemblies 16.9-5 REMEDIAL ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. One or more DID*** C.1 Establish a once per shift 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months required Fire Rated fire watch on at least one Assemblies is non- side of the assembly.

functional.

OR C.2 Verify at least one side of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months the assembly has FUNCTIONAL fire detection instrumentation.

OR C.3 Complete an evaluation as Prior to terminating permitted by NRC RIS Required Action C.1 2005-07 to institute required action(s).

High Safety Significant (HSS) Fire Areas containing required Fire Rated Assemblies are defined in Table 16.9-5-3.

- Low Safety Significant (LSS) Fire Areas containing required Fire Rated Assemblies are defined as those areas with a boundary between redundant shutdown trains.

- - Defense-in-Depth (DID) Fire Areas containing required Fire Rated Assemblies are defined as analysis compartment boundaries or PRA compartment boundaries that do not meet the HSS or LSS definitions.

Catawba Units 1 and 2 16.9-5-4 Revision 8

Fire Rated Assemblies 16.9-5

TESTING REQUIREMENTS TR 16.9-5-1 TEST Verify each HSS and LSS interior unlocked fire door is FREQUENCY 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months closed.

TR 16.9-5-2 Verify each HSS and LSS locked closed fire door is 7 days closed.

TR 16.9-5.:.3 Perform an inspection and functional test of the release 6 months and closing mechanism and latches for each swinging fire door shown in Table 16.9-5-1.

TR 16.9-5-4 Perform a visual inspection of the exposed surfaces of 18 months each required Fire Rated Assembly.

TR 16.9-5-5 ---------------------------- *----NOTE---------------------------------

Any abnormal changes or degradation shall be identified and resolved via the corrective action program. Based on the investigation results, additional dampers may be selected for inspection. Samples will be grouped by unit, system, and train and shall be selected such that each damper is inspected every 15 years.

Perform a visual inspection of fire dampers in each HSS 18 months, in and LSS required Fire Rated Assembly. accordance with the predefined inspection schedule (continued)

Catawba Units 1 and 2 16.9-5-5 Revision 8

Fire Rated Assemblies 16.9-5 TESTING REQUIREMENTS (continued)

TEST FREQUENCY TR 16. 9-5-6 ---------------------------------NO TE---------------------------------

Any abnormal changes or degradation shall be identified and resolved via the corrective action program. Based on the investigation results, additional Fire Rated Assemblies may be selected for inspection. Samples shall be selected such that each Fire Rated Assembly is inspected every 15 years.

Perform a visual inspection of penetration seals in each 18 months, in HSS AND LSS required Fire Rated Assembly. accordance with the predefined inspection schedule TR 16. 9-5-7 Perform an inspection and functional test of the 18 Months automatic hold open, release c;tnd closing mechanism for each rolling fire door shown in Table 16.9-5-1.

Catawba Units 1 and 2 16.9-5-6 Revision 8

Fire Rated Assemblies 16.9-5

DOOR BLDG LOCATION Table 16.9-5-1 Required Fire Doors ELEVATION FIRE AREA RISK REMEDIAL NUMBER INTERFACE CRITERIA ACTION CONDITION AX500F AUX 56, FF 522+0 1/4 DID C AX214A AUX 54-55, FF-GG 543+0 1/4 DID C AX214B AUX 58-59, FF-GG 543+0 1/4 DID C AX217D AUX 52-53, BB 543+0 3/34 LSS B AX217F{ 1J AUX 51, AA-BB 543+0 3/40 LSS B AX217G AUX 52-53, BB 543+0 3/32 LSS B AX227D AUX 54-55, MM-NN 543+0 4/22 DID C AX227E AUX 59-60, MM-NN 543+0 4/22 DID C AX228A AUX 56-57, EE 543+0 4/9 DID C AX228B AUX 57-58, EE 543+0 4/10 DID C AX248 AUX 57-58, QQ 543+0 4/ASB LSS B AX260B AUX 61-62, BB-CC 543+0 2/36 LSS B AX260F{ 1J AUX 62, AA-BB 543+0 2/39 LSS B AX260G AUX 61-62, BB-CC 543+0 2/31 LSS B AX260H AUX 61-62, BB-CC 543+0 2/33 LSS B T527#1 AUX 52-53, BB-CC 543+0 3/37 LSS B AX202 AUX 51, NN 543+0 4/STAIR DID c AX253A AUX 63, NN 543+0 4/STAIR DID C AX227A AUX 59, FF-GG 543+0 4/STAIR DID C AX260E AUX 52, cc 543+0 3/STAIR DID C AX516M AUX 62, cc 543+0 2/STAIR DID C AX354A AUX 55, DD-EE 554+0 22/45 LSS B AX354B AUX 59, DD-EE 554+0 22/46 LSS B AX418 AUX 57, BB 554+0 9/10 DID C AX419 AUX 57, DD-EE 554+0 9/10 DID C AX420A AUX 59, DD-EE 554+0 9/46 LSS B AX421A AUX 55, DD-EE 554+0 10/45 LSS B S102A AUX 53-54, AA 554+0 10/SRV LSS B AX302 AUX 41, CC-DD 556+0 25/41 DID C AX304 AUX 41, AA-BB 556+0 26/42 DID C AX306 AUX 73, DD-EE 556+0 27/43 DID C AX308 AUX 73, BB-CC 556+0 28/44 DID C AX348B AUX 54-55, MM-NN 560+0 11/22 DID C AX348C AUX 53-54, HH 560+0 4/11 DID C AX348D AUX 59-60, MM-NN 560+0 11/22 DID C AX348E AUX 60-61, HH 560+0 4/11 DID C AX352B AUX 53, CC-DD 560+0 6/STAIR HSS A AX352C AUX 53, CC-DD 560+0 10/STAIR DID C AX352D AUX 46-47, BB-CC 560+0 6/RB1 HSS A AX353 AUX 45, BB 560+0 6/8 HSS A AX353B AUX 45, AA-BB 560+0 8/41 LSS B AX353C AUX 45, AA-BB 560+0 8/42 DID C (continued)

Catawba Units 1 and 2 16.9-5-7 Revision 8

Fire Rated Assemblies 16.9-5 Table 16.9-5-1 Required Fire Doors DOOR BLDG LOCATION ELEVATION FIRE AREA RISK REMEDIAL NUMBER INTERFACE CRITERIA ACTION CONDITION AX393B AUX 61, CC-DD 560+0 9/STAIR DID C AX393C AUX 61, CC-DD 560+0 5/STAIR DID C AX393D AUX 67-68, BB-CC 560+0 5/RB2 LSS B AX394 AUX 69, BB 560+0 5/7 DID C AX394B AUX 69, AA-BB 560+0 7/43 LSS B AX394C AUX 69, AA-BB 560+0 7/44 DID C AX395 AUX 61, AA-BB 560+0 7/9 LSS B AX396 AUX 53, AA-BB 560+0 .8/10 LSS B AX415 AUX 45-46, CC-DD 560+0 6/RB1 HSS A AX416 AUX 68-69, CC-DD 560+0 5/RB2 LSS B AX417 AUX 57, QQ 560+0 11/ASB LSS B AX313D AUX 51, NN 560+0 11/STAIR DID C AX388B AUX 63, NN 560+0 11/STAIR DID C AX348 AUX 59, FF-GG 560+0 11/STAIR DID C AX355A AUX 53-54, FF 568+0 4/11 DID C AX355D AUX 60, FF 568+0 4/11 DID C AX355E AUX 60, FF 568+0 11/STAI.R DID C AX515 AUX 54, BB 574+0 17/45 HSS A AX516 AX516A AX516K AUX AUX AUX 56-57, DD 57-58, DD 57, AA-BB 574+0 574+0 574+0 14/45 16/46 16/17 HSS HSS HSS A

A A

e AX517A AUX 53-54, DD-EE 574+0 22/45 LSS B AX517B AUX 60-61, DD-EE 574+0 22/46 LSS B AX517C AUX 57, DD-EE . 574+0 45/46 DID C AX517D AUX 57, DD-EE 574+0 9/46 LSS B AX517E AUX 56-57, DD-EE 574+0 10/46 LSS B AX518 AUX 60, BB 574+0 16/46 HSS A S303 SRV 36-37, 1N 574+0 45/SRV DID C S303C SRV 36-37, V 574+0 45/SRV DID C S304A AUX 60, AA 574+0 46/SRV DID C AX500H AUX 54-55, MM-NN 577+0 18/22 DID C AX500K AUX 53-54, HH-GG 577+0 4/18 DID C AX500L AUX 59-60, MM-NN 577+0 18/22 DID C AX500N AUX 60-61, HH-GG 577+0 4/18 DID C AX513B AUX 53, CC-DD 577+0 13/STAIR HSS A AX514 AUX 45, BB 577+0 13/15 HSS A AX514B AUX 45-46, AA-BB 577+0 6/13 HSS A AX517 AUX 57, EE 577+0 9/18 DID C AX525 AUX 55-56, QQ 577+0 18/ASB LSS B AX525B AUX 56, QQ 577+0 18/ASB LSS B AX526D AUX 58, QQ 577+0 18/ASB LSS B A314#3 AUX 61, CC-DD 577+0 12/STAIR HSS A AX533C AUX 61, CC-DD 577+0 46/STAIR DID C AX534 AUX 69, BB 577+0 12/14 HSS A

( continued)

Catawba Units 1 and 2 16.9-5-8 Revision 8

Fire Rated Assemblies 16.9-5 Table 16.9-5-1 Required Fire Doors DOOR BLDG LOCATION ELEVATION FIRE AREA RISK REMEDIAL NUMBER INTERFACE CRITERIA ACTION CONDITION AX534B AUX 68-69, AA-BB 577+0 7/14 HSS A AX535A AUX 61, AA-BB 577+0 14/46 HSS A AX536 AUX 53, AA-BB 577+0 15/45 HSS A AX656 AUX 53, CC-DD 577+0 45/STAIR DID C AX500P AUX 51, NN 577+0 18/STAIR DID C AX500S AUX 63, NN 577+0 18/STAIR DID C AX338A AUX 60, FF-GG 577+0 18/STAIR DID C AX602 AUX 52, UU-VV 594+0 24/ASB DID C AX627 AUX 62, UU-VV 594+0 23/ASB DID C AX630 AUX 58, QQ 594+0 22/ASB LSS B AX632 AUX 57, QQ 594+0 22/ASB LSS B AX635 AUX 60-61, QQ 594+0 22/ASB LSS B AX635E AUX 53-54, QQ 594+0 22/ASB LSS B AX635F AUX 53-54, QQ 594+0 22/ASB LSS B AX655 AUX 62-63, DD 594+0 19/48 LSS B AX656C AUX 61, CC-DD 594+0 19/22 LSS B AX657 AUX 60-61, cc 594+0 19/22 LSS B AX657A{2l AUX 54, BB 594+0 21/35 HSS A AX657B AUX 52-53, CC-DD 594+0 20/22 LSS B AX657E{2l AUX 53, BB 594+0 21/35 HSS A AX657F AUX 60, DD-EE 594+0 21/22 HSS A AX657G AUX 57-58, DD-EE 594+0 21/22 HSS A AX657H AUX 54, DD-EE 594+0 21/22 HSS A AX657J AUX 53, BB-CC 594+0 20/21 HSS A AX658B AUX 51-52, DD 594+0 20/49 LSS B S400 AUX 55-56, AA 594+0 21/SRV HSS A S406 AUX 58-59, AA 594+0 21/SRV HSS A AX635G AUX 51, NN 594+0 22/STAIR DID C AX635H AUX 63, NN 594+0 22/STAIR DID C AX654A AUX 60, FF 594+0 22/STAIR DID C AX654B AUX 61, CC-DD 594+0 19/STAIR DID C AX665B AUX 53, CC-DD 594+0 22/STAIR DID C AX700B AUX 50-51, JJ-KK 605+10 24/RB1 LSS B AX700D AUX 63-64, KK 605+10 22/23 LSS B AX701 AUX 50-51, JJ-KK 605+10 22/RB1 LSS B AX714B AUX 63-64, JJ-KK 605+10 23/RB2 LSS B AX720 AUX 50-51, HH-JJ 605+10 22/RB1 LSS B AX721 AUX 63-64, HH-JJ 605+10 22/RB2 LSS B AX714C AUX 50-51, KK 605+10 22/24 LSS B AX715A AUX 63-64, JJ-KK 605+10 22/RB2 LSS B s211{2J TB1 17, V 568+0 SRV/TB1 DID C S212 TB1 19, V 568+0 SRV/TB1 DID C S210 TB1 21,V 568+0 SRV/TB1 DID C (contiAued) e Catawba Units 1 and 2 16.9-5-9 Revision 8

Fire Rated Assemblies 16.9-5 Table 16.9-5-1 Required Fire Doors DOOR BLDG LOCATION ELEVATION FIRE AREA RISK REMEDIAL NUMBER INTERFACE CRITERIA ACTION CONDITION S206 TB1 22, V 568+0 SRV/TB1 DID C S201 TB1 33, V 568+0 SRV/TB1 DID C SR3t3l TB1 30-31, V 568+0 SRV/TB1 DID C S201A TB1 27, V 568+0 SRV/TB1 DID C T101 TB1 31, 1K 568+0 TB1/U1 OTT DID C S424 TB1 24-25, V 594+0 SRV/TB1 DID C S425 TB1 23, V 594+0 SRV/TB1 DID C S426 TB1 22, V 594+0 SRV/TB1 DID C SR21<3) TB1 24,V 594+0 SRV/TB1 DID C S472 TB1 27, V 594+0 SRV/TB1 DID C S423 TB1 29, V 594+0 SRV/TB1 DID C S422 TB1 29, V 594+0 SRV/TB1 DID C SR7<3l TB1 29-30, V 594+0 SRV/TB1 DID C S416 TB1 32, V 594+0 SRV/TB1 DID C S444 TB1 15, V 594+0 SRV/TB1 DID C TR4l 3l TB1 15-16, V 594+0 SRV/TB1 DID C T200A TB1 32, 1J-1K 594+0 TB1/U1 MTOT DID C S701 TB1 22, 1L 619+6 SRV/TB1 DID C S704 TB1 33, 1L 619+6 SRV/TB1 DID C S209 TB2 20, P 568+0 SRV/TB2 DID C S208 TB2 22, P 568+0 SRV/TB2 DID C SR2t3l TB2 32-33, P 568+0 SRV/TB2 DID C S462 TB2 32, P 568+0 SRV/TB2 DID C SR4t3l TB2 30-31, P 568+0 SRV/TB2 DID C S1102 TB2 27, P 568+0 SRV/TB2 DID C T151 TB2 31, 2K 568+0 TB2/U2 OTT DID C S423E TB2 26, P-Q 594+0 SRV/TB2 DID C S416A TB2 32, P 594+0 SRV/TB2 DID C SR8t3l TB2 29-30, P 594+0 SRV/TB2 DID C S422A TB2 29, P 594+0 SRV/TB2 DID C S423A TB2 29, P 594+0 SRV/TB2 DID C S435 TB2 24-25, P 594+0 SRV/TB2 DID C S436 TB2 23, P 594+0 SRV/TB2 DID C S437 TB2 22, P 594+0 SRV/TB2 DID C SR22t3l TB2 24, P 594+0 SRV/TB2 DID C S444A TB2 15, P 594+0 SRV/TB2 DID C SR16<3l TB2 15-16, P 594+0 SRV/TB2 DID C S472A TB2 27, P 594+0 SRV/TB2 DID C T250A TB2 32, 2J-2K 594+0 TB2/U2 MTOT DID C S701A TB2 22, 2L 619+6 SRV/TB2 DID C S704A TB2 33,2L 619+6 SRV/TB2 DID C AX662A NSWPS 600+0 29/30 LSS B (1) These doors are not equipped with closing mechanisms or latches and are therefore exempt from TESTING REQUIREMENT 16.9-5-3.

(2) These doors are held open with a fusible link.

(3) Rolling Door.

Catawba Units 1 and 2 16.9-5-10 Revision 8

Fire Rated Assemblies 16.9-5

DAMPER BLDG LOCATION Table 16.9-5-2 Required Fire Dampers ELEVATION FIRE AREA RISK REMEDIAL NUMBER INTERFACE CRITERIA ACTION CONDITION 1VA-FD001 AUX 53/GG-FF 522+0 1/4 DID C 1VA-FD002 AUX 53/GG-HH 522+0 1/4 DID C 1VA-FD003 AUX 55-56/GG-HH 522+0 1/4 DID C 1VA-FD004 AUX 55-56/GG-HH 522+0 1/4 DID C 1VA-FD005 AUX 54-55/GG-HH 522+0 1/4 DID C 1VA-FD006 AUX 54-55/GG-HH 522+0 1/4 DID C 1VA-FD007 AUX 53/GG-FF 522+0 1/4 DID C 1VA-FD008 AUX 53/GG-FF 522+0 1/4 DID C 1/1 (ND 1VA-FD009 AUX 53-54/FF-GG 522+0 DID C PUMPS) 1VA-FD010 AUX 56-57/ GG-HH, 522+0 1/4 DID C 1VA-FD011 AUX 56-57/FF 522+0 1/4 DID C 1VA-FD012 AUX 51/NN-PP 543+0 11/STAIR DID C 1VA-FD013 AUX 54/MM 543+0 4/22 DID C 1VA-FD014 AUX 54/MM 543+0 4/22 DID C 1VA-FD015 AUX 54-55/MM-NN 543+0 4/22 DID C 1VA-FD016 AUX 54-55/MM-NN 543+0 4/22 DID C 1VA-FD017 AUX 54-55/MM-NN 543+0 4/22 DID C 4/4 (NV 1VA-FD020 AUX 55/JJ-KK 543+0 DID C PUMPS) 1VA-FD033 AUX 51-52/AA-BB 543+0 3/40 LSS B 1VA-FD034 AUX 51-52/AA-BB 543+0 3/40 LSS B 1VA-FD035 AUX 52/AA-BB 543+0 3/32 LSS B 1VA-FD036 AUX 52-53/BB 543+0 3/32 LSS B 1VA-FD038 AUX 52-53/BB 543+0 3/34 LSS B 1VA-FD039 AUX 52-53/BB 543+0 3/34 LSS B 1VA-FD040 AUX 52-53/BB 543+0 3/32 LSS B 1VA-FD041 AUX 52-53/BB 543+0 3/32 LSS B 1VA-FD042 AUX 53/CC 543+0 3/STAIR DID C 1VA-FD043 AUX 53/CC-DD 543+0 3/STAIR DID C 1VA-FD045 AUX 52-53/DD 560+0 3/6 HSS A 1VA-FD046 AUX 52-53/CC-DD 577+0 6/13 HSS A 1VA-FD047 AUX 52-53/CC-DD 577+0 6/13 HSS A 1VA-FD048 AUX 54/MM-NN 560+0 11/22 DID C 1VA-FD049 AUX 54/MM 560+0 11/22 DID C 1VA-FD050 AUX 54-55/MM 560+0 4/22 DID C 1VA-FD051 AUX 54-55/MM 560+0 4/22 DID C 1VA-FD052 AUX 55/MM-NN 560+0 11/22 DID C 1VA-FD053 AUX 55/MM 560+0 11/22 DID C 1VA-FD054 AUX 53/GG-HH 560+0 4/11 DID C 1VA-FD055 AUX 53/GG-HH 560+0 4/11 DID C 1VA-FD056 AUX 53/KK 560+0 4/11 DID C 1VA-FD057 AUX 53/GG-HH 560+0 4/11 DID C (continued)

Catawba Units 1 and 2 16.9-5-11 Revision 8

Fire Rated Assemblies 16.9-5 DAMPER NUMBER BLDG LOCATION Table 16.9-5-2 REQUIRED FIRE DAMPERS ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION 1VA-FD058 AUX 53-54/HH 560+0 4/11 DID C 1VA-FD059 AUX 54/GG-HH 560+0 4/11 DID C 1VA-FD060 AUX 54/HH 560+0 4/11 DID C 1VA-FD061 AUX 56-57/QQ 577+0 18/ASB LSS B 1VA-FD062 AUX 55-56/QQ 577+0 18/ASB LSS B 1VA-FD063 AUX 55/MM-NN 577+0 18/22 DID C 1VA-FD064 AUX 55/MM 577+0 18/22 DID C 1VA-FD065 AUX 54/MM 577+0 18/22 DID C 1VA-FD066 AUX 54/MM 577+0 18/22 DID C 1VA-FD067 AUX 54/HH 577+0 4/18 DID C 1VA-FD068 AUX 53-54/HH 577+0 4/18 DID C 1VA-FD069 AUX 54/GG-HH 577+0 4/18 DID C 1VA-FD070 AUX 53-54/HH 577+0 4/18 DID C 1VA-FD071 AUX 53-54/HH 577+0 4/18 DID C 1VA-FD072 AUX 53/HH 577+0 4/18 DID C 1VA-FD073 AUX 53/HH 577+0 4/18 DID C 1VA-FD074 AUX 53/GG-HH 577+0 4/18 DID C 1VA-FD075 AUX 53-54/KK-LL 594+0 18/22 DID C 1VA-FD076 AUX 53-54/KK-LL 594+0 18/22 DID C 1VA-FD078 AUX 57/NN 594+0 22/STAIR DID C 1VA-FD087 AUX 55-56/QQ 594+0 22/ASB LSS B 1VA-FD088 AUX 53-54/QQ 594+0 22/ASB LSS B 1VA-FD133 AUX 53/CC-DD 594+0 22/STAIR DID C 1VA-FD139 AUX 51-52/DD 543+0 3/4 DID C 1VA-FD140 AUX 53-54/FF-GG 560+0 4/11 DID C 1VA-FD141 AUX 53-54/FF-GG 560+0 4/11 DID C 1VA-FD142 AUX 53/GG 560+0 4/11 DID C 1VA-FD143 AUX 53/JJ-HH 560+0 4/11 DID C 1VA-FD144 AUX 53/KK 560+0 4/11 DID C 1VA-FD145 AUX 51/KK 560+0 11/18 DID C 1VA-FD146 AUX 51/KK 560+0 11/18 DID C 1VA-FD147 AUX 52/MM 560+0 11/18 DID C 1VA-FD148 AUX 52/MM-NN 560+0 4/11 DID C 1VA-FD149 AUX 52-53/DD 560+0 3/6 HSS A 1VA-FD150 AUX 52-53/DD 560+0 3/6 HSS A 1VA-FD152 AUX 52-53/BB-CC 543+0 3/37 LSS B 1VA-FD153 AUX 52-53/CC 543+0 3/37 LSS B 1VA-FD154 AUX 53-54/GG-HH 594+0 4/22 DID C 1VA-FD155 AUX 53-54/GG-HH 594+0 4/22 DID C 1VA-FD159 AUX 49-50/AA-BB 543+0 CO2 HSS A 1VA-FD160 AUX 50-51/AA-BB 543+0 CO2 HSS A 1VA-FD163 AUX 56/EE 543+0 10/45 LSS B 1VA-FD164 AUX 56-57/EE 543+0 4/10 DID C 2VA-FD001 AUX 61/GG-FF 522+0 1/4 DID C 2VA-FD002 AUX 61/GG-FF 522+0 1/4 DID C (continued)

Catawba Units 1 and 2 16.9-5-12 Revision 8

Fire Rated Assemblies 16.9-5

DAMPER NUMBER BLDG LOCATION Table 16.9-5-2 REQUIRED FIRE DAMPERS ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION 1/1 (ND 2VA-FD003 AUX 60-61/FF-GG 522+0 DID C PUMPS}

2VA-FD004 AUX 61/GG-FF 522+0 1/4 DID C 2VA-FD005 AUX 60-61/GG-HH 522+0 1/4 DID C 2VA-FD006 AUX 59-60/GG-HH 522+0 1/4 DID C 2VA-FD007 AUX 59-60/GG-HH 522+0 1/4 DID C 2VA-FD008 AUX 58-59/GG-HH 522+0 1/4 DID C 2VA-FD009 AUX 58-59/GG-HH 522+0 1/4 DID C 2VA-FD010 AUX 57-58/GG-HH 522+0 1/4 DID C 2VA-FD011 AUX 57-58/FF 522+0 1/4 DID C 2VA-FD012 AUX 59-60/MM-NN 543+0 4/22 DID C 2VA-FD013 AUX 59/MM 543+0 4/22 DID C 2VA-FD014 AUX 59/MM 543+0 4/22 DID C 2VA-FD015 AUX 59-60/MM-NN 543+0 4/22 DID C 2VA-FD020 AUX 63/NN 534+0 4/STAIR DID C 4/4 (NV 2VA-FD023 AUX 59/JJ-KK 543+0 DID C PUMPS}

2VA-FD036 AUX 61-62/DD 560+0 2/5 LSS 8*

2VA-FD037 . AUX 61-62/CC-DD 577+0 5/12 HSS A 2VA-FD038 AUX 61-62/CC-DD 577+0 5/12 HSS A 2VA-FD040 AUX 62-63/M-88 543+0 2/39 LSS 8 2VA-FD041 AUX 62-63/M-88 543+0 2/39 LSS 8 2VA-FD042 AUX 62/M-88 543+0 2/31 LSS 8 2VA-FD043 AUX 61-62/88 543+0 2/31 LSS 8 2VA-FD045 AUX . 61/CC 543+0 2/STAIR DID .C 2VA-FD046 AUX 61/CC-DD 543+0 2/STAIR DID C 2VA-FD048 AUX . 61-62/88 543+0 2/33 LSS 8 2VA-FD049 AUX 61-62/88 .543+0 2/33 LSS 8 2VA-FD050 AUX 61-62/88 543+0 2/31 LSS 8 2VA-FD051 AUX 61-62/88 543+0 2/31 LSS 8 2VA-FD053 AUX 60/MM 560+0 11/22

DID C 2VA-FD054 AUX 59/MM-NN 560+0 11/22 DID C 2VA-FD056 AUX 60/MM-NN 560+0 11/22 DID C 2VA-FD057 AUX 59-60/MM 560+0 11/22 DID C 2VA-FD058 AUX 59-60/MM 560+0 4/22 DID C 2VA-FD059 AUX 60-61/HH 560+0 4/11 DID C 2VA-FD060 AUX 61/HH-JJ 560+0 4/11 DID C 2VA-FD061 AUX 60-61/GG-HH 560+0 4/11 DID C 2VA-FD062 AUX 61/GG-HH 560+0 4/11 DID C 2VA-FD063 AUX 61/GG-HH 560+0 4/11 DID C 2VA-FD064 AUX 60-61/GG-HH 560+0 4/11 DID C 2VA-FD065 AUX 61/HH 560+0 4/11 DID C

2VA-FD069 AUX 58-59/QQ 577+0 18/AS8 LSS 8 2VA-FD070 AUX 59-60/QQ 577+0 18/AS8 LSS 8 2VA-FD071 AUX 59-60/MM-NN 577+0 18/22 DID C

2VA-FD072 AUX Catawba Units 1 and 2 59-60/MM 577+0 16.9-5-13 18/22 DID Revision 8 C

(continued)

Fire Rated Assemblies 16.9-5 DAMPER NUMBER BLDG LOCATION Table 16.9-5-2 REQUIRED FIRE DAMPERS ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION 2VA-FD073 AUX 60/MM 577+0 18/22 DID C 2VA-FD074 AUX 60/MM 577+0 18/22 DID C 2VA-FD075 AUX 60/HH 577+0 4/22 DID C 2VA-FD076 AUX 60/HH 577+0 4/22 DID C 2VA-FD077 AUX 60-61/HH 577+0 4/22 DID C 2VA-FD078 AUX 60-61/HH 577+0 4/22 DID C 2VA-FD079 AUX 61/HH 577+0 4/22 DID C 2VA-FD080 AUX 61/GG-HH 577+0 4/22 DID C 2VA-FD081 AUX 61/HH 577+0 4/22 DID C 2VA-FD083 AUX 63/NN 594+0 22/STAIR DID C 2VA-FD086 AUX 60/FF 594+0 22/STAIR DID C 2VA-FD087 AUX 59-60/QQ 594+0 22/ASB LSS B 2VA-FD088 AUX 60-61/QQ 594+0 22/ASB LSS B 2VA-FD093 AUX 58-59/QQ 594+0 22/ASB LSS B 2VA-FD097 AUX 61/CC-DD 594+0 22/STAIR DID C 2VA-FD108A AUX 57-59/QQ 611+0 22/ASB LSS B 2VA-FD108B AUX 57-59/QQ 611+0 22/ASB LSS B 2VA-FD114 AUX 59-60/KK-LL 594+0 18/22 DID C 2VA-FD115 AUX 59-60/KK-LL 594+0 18/22 DID C 2VA-FD137 AUX 60-61/FF-GG 560+0 4/18 DID C 2VA-FD138 AUX 60-61/FF-GG 560+0 4/18 DID C 2VA-FD139 AUX 61/GG 560+0 4/11 DID C 2VA-FD141 AUX 62-63/DD 543+0 2/4 DID C 2VA-FD142 AUX 60-61/KK 560+0 4/11 DID C 2VA-FD143 AUX 62-63/KK 560+0 4/18 DID C 2VA-FD144 AUX 63/KK 560+0 4/18 DID C

. 2VA-FD145 AUX 61-62/MM-NN 560+0 4/11 DID C 2VA-FD146 AUX 61-62/DD 560+0 2/5 LSS B 2VA-FD147 AUX 61-62/DD 560+0 2/5 LSS B 2VA-FD151 AUX 61-62/BB-CC 543+0 2/36 LSS B 2VA-FD152 AUX 61-62/CC 543+0 2/36 LSS B 2VA-FD153 AUX 60-61/GG-HH 594+0 4/22 DID C 2VA-FD154 AUX 60-61/GG-HH 594+0 4/22 DID C 2VA-FD157 AUX 63-64/AA-BB 543+0 CO2 HSS A 2VA-FD158 AUX 64-65/AA-BB 543+0 CO2 HSS A 2VA-FD160 AUX 57-58/QQ 543+0 4/ASB LSS B 2VA-FD161 AUX 57-58/QQ 543+0 4/ASB LSS B 2VA-FD163 AUX 58/EE 543+0 9/46 LSS B 2VA-FD164 AUX 57-58/EE 543+0 4/9 DID C 0BRS-FD001 AUX 54-55/DD-EE 554+0 10/22 DID C 0BRS-FD010 AUX 57/DD-EE 554+0 9/10 DID C 0BRS-FD019 AUX 59/DD-EE 554+0 9/22 DID C OBRX-FD001A AUX 54-55/DD-EE 554+0 10/22 DID C OBRX-FD001B AUX 54-55/DD-EE 554+0 10/22 DID C (continued)

Catawba Units 1 and 2 16.9-5-14 Revision 8

Fire Rated Assemblies 16.9-5 Table 16.9-5-2 REQUIRED FIRE DAMPERS DAMPER BLDG LOCATION ELEVATION FIRE AREA RISK REMEDIAL NUMBER INTERFACE CRITERIA ACTION CONDITION OBRX-AUX 54-55/DD-EE 554+0 10/22 DID C FD001C OBRX-AUX 54-55/DD-EE 554+0 10/22 DID C FD001D OBRX-AUX 54-55/DD-EE 554+0 10/22 DID C FD001E OBRX-AUX 54-55/DD-EE 554+0 10/22 DID C FD001F OBRX-AUX 54-55/DD-EE 554+0 10/22 DID C FD001G OBRX-AUX 54-55/DD-EE 554+0 10/22 DID C FD001H 0BRX-FD002 AUX 54-55/DD-EE 554+0 10/22 DID C 0BRX-FD009 AUX 57/AA-BB 554+0 9/10 DID C 0BRX-FD010 AUX 57/AA-BB 554+0 9/10 DID C 0BRX-FD011 AUX 57/BB-CC 554+0 9/10 DID C 0BRX-FD012 AUX 57/CC-DD 554+0 9/10 DID C 0BRX-FD013 AUX 57/CC-DD 554+0 9/10 DID C 0BRX-FD014 AUX 57/DD-EE 554+0 9/10 DID C 0BRX-FD021 AUX 60/DD-EE 554+0 9/22 DID C OBRX-AUX 60/DD-EE 554+0 9/22 DID C FD022A OBRX-AUX 60/DD-EE 554+0 9/22 DID C FD022B OBRX-AUX 60/DD-EE 554+0 9/22 DID C FD022C OBRX-AUX 60/DD-EE 554+0 9/22 DID C FD022D OBRX-AUX 60/DD-EE 554+0 9/22 DID C FD022E OBRX-AUX 60/DD-EE 554+0 9/22 DID C FD022F OBRX-AUX 60/DD-EE 554+0 9/22 DID C FD022G OBRX-AUX 60/DD-EE 554+0 9/22 DID C FD022H 0BRX-FD023 AUX 57/BB-CC 554+0 9/10 DID C 1CRA-AUX 54-55/DD-EE 594+0 21/22 HSS A FD005A 1CRA-AUX 54-55/DD-EE 594+0 21/22 HSS A FD005B 1CRA-FD008 AUX 54/AA 594+0 21/35 HSS A 1CRA-FD009 AUX 53-54/CC-DD 594+0 22/STAIR DID C 1CRA-FD010 AUX 53-54/CC 594+0 21/STAIR HSS A 1CRA-FD011 AUX 53/AA-BB 594+0 20/35 DID C 1CRA-FD012 AUX 53/BB-CC 594+0 20/21 HSS A (continuea)

Catawba Units 1 and 2 16.9-5-15 Revision 8

Fire Rated Assemblies 16.9-5 DAMPER BLDG LOCATION Table 16.9-5-2 REQUIRED FIRE DAMPERS ELEVATION FIRE AREA RISK REMEDIAL NUMBER INTERFACE CRITERIA ACTION CONDITION 1CRA-FD013 AUX 52/CC-DD 594+0 20/22 LSS B 1CRA-FD016 AUX 54-55/DD-EE 574+0 22/45 LSS B 1CRA-FD017 AUX 54-55/DD 574+0 17/45 HSS A 1CRA-FD018 AUX 54-55/00 574+0 17/45 HSS A 1CRA-FD019 AUX 54/AA-BB 574+0 17/45 HSS A 1CRA-FD020 AUX 57/CC-DD 574+0 16/17 HSS A 1CRA-FD021 AUX 53-54/00-EE 574+0 22/45 LSS B 1CRA-FD022 AUX 55-56/DD 574+0 17/45 HSS A 1CRA-FD023 AUX 56-57/DD 574+0 17/45 HSS A 1CRA-AUX 57/00-EE 574+0 45/46 DID C FD024A 1CRA-AUX 57/00-EE 574+0 45/46 DID C FD024B 1CRA-AUX 54-55/00-EE 574+0 22/45 LSS B FD025A 1CRA-AUX 54-55/00-EE 574+0 22/45 LSS B FD025B 1CRA-FD026 AUX

54-55/EE 577+0 18/22 DID C 1CRA-FD028 AUX 53-54/EE 577+0 18/22 DID C 1CRA-FD029 AUX 54-55/EE 568+0 11/22 DID C 1CRA-FD030 AUX 54-55/EE 568+0 11/22 DID C 18/18 (KC 1CRA-FD039 AUX 57/EE-FF 577+0 DID C PUMPS) 1CR-FD001 AUX 55-56/00-EE 594+0 21/22 HSS A 1CR-FD002 AUX 55-56/00-EE 594+0 21/22 HSS A 1CR-FD003 AUX 54/AA-BB 594+0 21/35 HSS A 1CR-FD004 AUX 53-54/BB 594+0 21/35 HSS A 1CR-FD005 AUX 53-54/BB 594+0 21/35 HSS A 1CR-FD007 AUX 51/CC-DD 594+0 13/20 HSS A 2CRA-AUX 59-60/DD-EE 594+0 21/22 HSS A FD005A 2CRA-AUX 59-60/DD-EE 594+0 21/22 HSS A FD005B 2CRA-FD008 AUX 60/AA-BB 594+0 19/21 HSS A 2CRA-FD009 AUX 60-61/CC 594+0 19/22 LSS B 2CRA-FD012 AUX 61/CC-DD 594+0 19/22 LSS B 2CRA-FD015 AUX 59-60/00-EE 574+0 22/46 LSS B 2CRA-FD016 AUX 59-60/DD 574+0 16/46 HSS A 2CRA-FD017 AUX 59-60/DD 574+0 16/46 HSS A 2CRA-FD018 AUX 60/AA-BB 574+0 16/46 HSS A 2CRA-FD019 AUX 58-59/DD 574+0 16/46 HSS A 2CRA-FD020 AUX 57-58/DD 574+0 16/46 HSS A 2CRA-FD021 AUX 60-61/00-EE 574+0 22/46 LSS B 2CRA-AUX 59-60/00-EE 574+0 22/46 LSS B FD022A (continued)

Catawba Units 1 and 2 16.9-5-16 Revision 8

Fire Rated Assemblies 16.9-5

DAMPER NUMBER BLDG LOCATION Table 16.9-5-2 REQUIRED FIRE DAMPERS ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION 2CRA-AUX 59-60/DD-EE 574+0 22/46 LSS B FD022B 2CRA-FD023 AUX 59-60/EE 577+0 18/22 DID C 2CRA-FD025 AUX 60-61/EE 577+0 18/22 DID C 2CRA-FD026 AUX 59-60/EE 568+0 11/22 DID C 2CRA-FD027 AUX 59-60/EE 568+0 11/22 DID C 2CR-FD001 AUX 58-59/DD-EE 594+0 21/22 HSS A 2CR-FD002 AUX 58-59/DD 594+0 21/22 HSS A 2CR-FD003 AUX 63-64/CC 594+0 12/19 HSS A 1VF-FD001A AUX 51, NN-PP 605+10 22/24 LSS B 1VF-FD001B AUX 51, NN-PP 605+10 22/24 LSS B 1VF-FD002A AUX 50-51/NN-PP 631+6 24/38 DID C 1VF-FD002B AUX 50-51/NN-PP 631+6 24/38 DID C 1VF-FD004 AUX 49/PP-QQ 631+6 24/38 DID C 1VF-FD005 AUX 49-50/PP-QQ 631+6 24/38 DID C 1VF-FD006 AUX 50-51 631+6 24/38 DID C 1VF-FD007 AUX 50-51/KK-LL 605+10 22/24 LSS B 1VF_;FD010

AUX 50-51/KK 605+10 22/24 LSS B 1VF-FD011 AUX 50-51/JJ-KK 631+6 22/38 LSS B 1VF-FD013 AUX 50-51/JJ-KK 616+10 22/24 LSS B 1VF-FD014 AUX 50-51/JJ-KK 616+10 22/24 LSS B 2VF-FD001A AUX 63, NN-PP 605+10 22/23 LSS B 2VF-FD001B AUX 63, NN-PP 605+10 22/23 LSS B 2VF-FD002A AUX 63-64/NN-PP 631+6 23/47 DID C 2VF-FD002B AUX 63-64/NN-PP 631+6 23/47 DID C 2VF-FD004 AUX 65/PP-QQ 631+6 23/47 DID C 2VF-FD005 AUX 64-65/PP-QQ 631+6 23/47 DID C 2VF-FD006 AUX 63-64/PP-QQ 631+6 23/47 DID C 2VF-FD007 AUX 63-64/KK-LL 605+10 22/23 LSS B 2VF-FD010 AUX 63-64/KK 605+10 22/23 LSS B 2VF-FD011 AUX 64-64/JJ-KK 631+6 22/47 LSS B 2VF-FD013 AUX 63-64/JJ-KK 616+10 22/23 LSS B 2VF-FD014 AUX 63-64/JJ-KK 616+10 22/23 LSS B 1TB-FD001 TB1 18-19N 594+0 TB1/SRV DID C 1TB-FD002 TB1 18-19N 594+0 TB1/SRV DID C 1TB-FD003 TB1 18-19N 594+0 TB1/SRV DID C 1TB-FD004 TB1 18-19N 594+0 TB1/SRV DID C 1TB-FD005 TB1 18-19N 594+0 TB1/SRV DID C 1TB-FD006 TB1 18-19N 594+0 TB1/SRV DID C 1TB-FD007 TB1 21-22N 594+0 TB1/SRV DID C 1TB-FD008 TB1 21-22N 594+0 TB1/SRV DID C 1TB-FD009 TB1 21-22N 594+0 TB1/SRV DID C 1TB-FD010 TB1 21-22N 594+0 TB1/SRV DID C 1TB-FD011 TB1 21-22N 594+0 TB1/SRV DID C 1TB-FD012 TB1 21-22N 594+0 TB1/SRV DID C

1TB-FD032 TB1 Catawba Units 1 and 2 18-19N 594+0 16.9-5-17 TB1/SRV DID Revision 8 C

(continued)

Fire Rate d Assemblies 16.9-5 Table 16.9-5-2 REQUIRED FIRE DAMPERS

DAMPER BLDG LOCATION ELEVATION FIRE AREA RISK REMEDIAL NUMBER INTERFACE CRITER IA ACTION CONDITION 1TB-FD038 TB1 16-17N 594+0 TB1/SRV DID C 1TB-FD039 TB1 16-17N 594+0 TB1/SRV DID C 1TB-FD040 TB1 16N 594+0 TB1/SRV DID C 1TB-FD043 TB1 30-31/1J-1K 568+0 TB1/0TT DID C 1TB-FD044 TB1 32/1J-1 K 594+0 TB1/MTOT DID C 1TB-FD045 TB1 30/1J-1K 594+0 TB1/MTOT DID C 1TB-FD046 TB1 32/1 K-1 L 568+0 TB1/0TT DID C 2TB-FD013 TB2 21-22/P 594+0 TB2/SRV DID C 2TB-FD014 TB2 21-22/P 594+0 TB2/SRV DID C 2TB-FD015 TB2 21-22/P 594+0 TB2/SRV DID C 2TB-FD016 TB2 21-22/P 594+0 TB2/SRV DID C 2TB-FD017 TB2 21-22/P 594+0 TB2/SRV DID C 2TB-FD018 TB2 21-22/P 594+0 TB2/SRV DID C 2TB-FD019 TB2 18-19/P 594+0 TB2/SRV DID C 2TB-FD020 TB2 18-19/P 594+0 TB2/SRV DID C 2TB-FD021 TB2 18-19/P 594+0 TB2/SRV DID C 2TB-FD022 TB2 18-19/P 594+0 TB2/SRV DID C 2TB-FD023 TB2 18-19/P 594+0 TB2/SRV DID C 2TB-FD024 TB2 18-19/P 594+0 TB2/SRV DID C 2TB-FD031 TB2 32/2K-2L 568+0 TB2/0TT DID C 2TB-FD032 TB2 18/P 594+0 TB2/SRV DID C 2TB-FD036 TB2 16-17/P 594+0 TB2/SRV DID C 2TB-FD038 TB2 17-18/P 594+0 TB2/SRV DID C 2TB-FD039 TB2 32/2J-2K 594+0 TB2/MTOT DID C 2TB-FD040 TB2 30/2J-2K 594+0 TB2/MTOT DID C 2TB-FD041 TB2 30-31/2J/2K 568+0 TB2/0TT DID C SB-FD158 SRV 18-19N 568+0 TB1/SRV DID C I Table 16.9-5-3 HIGH SAFETY SIGNIFICANT (HSS) FIRE AREAS*

FIRE AREA BLDG ELEVATION DESCRIPTION 6 AUX 560+0 Unit 1 Electrical Pen Ro om El 560 12 AUX 577+0 Unit 2 Electrical Pen Ro om El 577 13 AUX 577+0 Unit 1 Electrical Pen Ro om El 577 14 AUX 577+0 Unit 2 4160V Essential Swg r Room (2ETA) 15 AUX 577+0 Unit 1 4160V Essential Sw r Room (1ETA) 16 AUX 574+0 Unit 2 Cable Room El574 17 AUX 574+0 Unit 1 Cable Room El574 21 AUX 594+0 Main Control Room El594

High Safety Significant (HSS) Fire Areas are defined as the areas with HSS fi re barrier features in accordance with the Catawba NFPA 805 Monitoring Program.

Catawba Units 1 and 2 16.9-5-18 Revision 8

Fire Rated Assemblies 16.9-5

Table 16.9-5-4 FIRE AREAS AND SHUTDOWN TRAIN/ METHOD ASSURED FIRE SHUTDOWN AREA FIRE AREA DESCRIPTIONS TRAIN/ METHOD 1 ND & NS Pum~ Room El 522 (Common) sss 2 Unit 2 CA Pum~ Room El 543 sss 3 Unit 1 CA Pum~ Room El 543 sss 4 Aux Bldg. Gen Area & NV Pum~ Room El 543 (Common} sss 5 Unit 2 Electrical Pen Room El 560 A 6 Unit 1 Electrical Pen Room El 560 A 7 Unit 2 4160V Essential SWGR Room El 560 A 8 Unit 1 4160V Essential SWGR Room El 560 A 9 Unit 2 Battery Room El 554 sss 10 Unit 1 Battery Room El 554 sss 11 Aux Bldg. Gen Area & U1 KC Pum~ Room El 560 (Common} sss 12 Unit 2 Electrical Pen Room El 577 B 13 Unit 1 Electrical Pen Room El 577 B 14 Unit 2 4160V Essential SWGR Room El 577 B 15 Unit 1 4160V Essential SWGR Room El 577 B 16 Unit 2 Cable Room El 574 sss 17 Unit 1 Cable Room El 574 sss

18 19 20 21 22

23 Aux Bldg. Gen Area & U2 KC Pum~ Room El 577 (Common}

Unit 2 Electrical Pen Room El 594 Unit 1 Electrical Pen Room El 594 Control Room El 594 (Common}

Aux Bldg. Gen Area El 594 (Common}

Unit 2 Fuel Storage Area El 605 sss A

A sss sss A

24 Unit 1 Fuel Storage Area El 605 A 25 Diesel Generator Bldg. 1A El 556 B 25A Diesel Generator Bldg. 1A Stairwell B 26 Diesel Generator Bldg. 1B El 556 A 268 Diesel Generator Bldg. 1B Stairwell A 27 Diesel Generator Bldg. 2A El 556 B 27A Diesel Generator Bldg. 2A Stairwell B 28 Diesel Generator Bldg. 28 El 556 A 288 Diesel Generator Bldg. 28 Stairwell A 29 Train A RN Pum~ Structure El 600 (Common} B 30 Train B RN Pum~ Structure El 600 (Common) A 31 Unit 2 Train A Aux Shutdown Panel El 543 B 32 Unit 1 Train A Aux Shutdown Panel El 543 B 33 Unit 2 Train B Aux Shutdown Panel El 543 A 34 Unit 1 Train B Aux Shutdown Panel El 543 A 35 Control Room Tagout Area El 594 A or B 36 Unit 2 Turbine Driven CA Pum~ Control Panel Room El 543 B 37 Unit 1 Turbine Driven CA Pum~ Control Panel Room El 543 B 38 Unit 1 Fuel Storage Area HVAC Room El 631 A or B (continued)

Catawba Units 1 and 2 16.9-5-19 Revision 8

Fire Rated Assemblies 16.9-5 Table 16.9-5-4 FIRE AREAS AND SHUTDOWN TRAIN/ METHOD ASSURED FIRE SHUTDOWN AREA FIRE AREA DESCRIPTIONS TRAIN/ METHOD 39 Unit 2 Turbine Driven CA Pump Pit El 543 B 40 Unit 1 Turbine Driven CA Pump Pit El 543 B 41 DG1A Sequencer Tunnel El 556 B 42 DG 1B Sequencer Tunnel El 556 A 43 DG2A Sequencer Tunnel El 556 B 44 DG2B Sequencer Tunnel El 556 A 45 Unit 1 Cable Room Corridor El 574 B 46 Unit 2 Cable Room Corridor El 574 B 47 Unit 2 Fuel Storage Area HVAC Room El 631 A or B 48 Unit 2 Interior Doghouse A and B 49 Unit 1 Interior Doghouse A and B 50 Unit 2 Exterior Doghouse A and B 51 Unit 1 Exterior Doghouse A and B ASB Auxiliary Service Building A or B RB1 Unit 1 Reactor Building A and B RB2 Unit 2 Reactor Building A and B SRV Service Building B SSF TB2 Standby Shutdown Facility STAIR* Stairway TB1 Unit 1 Turbine Building Unit 2 Turbine Building YRD** Yard Area A or B See Note A or B A or B A or B

IF the barrier in a stairway is adjacent to a HSS Fire Area (see Table 16.9-5-3), enter CONDITION A; otherwise enter CONDITION C. .

- Exterior walls that interface with the YRD do not require entry into a CONDITION statement and therefore do not have a REQUIRED ACTION.

A =A TRAIN B=BTRAIN SSS = STANDBY SHUTDOWN SYSTEM Catawba Units 1 and 2 16.9-5-20 Revision 8

Fire Rated Assemblies 16.9-5

BASES The functional integrity of the Fire Rated Assemblies and associated sealing devices ensures that fires will be confined or adequately retarded so as not to spread between fire areas/compartments.

The fire barriers and associated penetration seals are passive elements in the facility fire protection program and are subject to periodic inspections.

Risk-informed insights from the Fire PRA process can apply to compensatory actions. The safety significance of the fire area can provide relief for required compensatory actions. In addition, the presence of functional fire detection can reduce the required compensatory actions. Functional fire detection in the area provides early warning of a fire for fire brigade response. Fire detection can provide a compensatory action equivalent to or better than fire watch.

Fire barrier penetration seals, including cable/pipe penetration seals, fire doors, and fire dampers, are considered FUNCTIONAL when the visually observed condition indicates no abnormal change in appearance or abnormal degradation. An evaluation is performed to determine the cause of any identified fire barrier penetration seal abnormal change in appearance or abnormal degradation and the effect of this change on the ability of the fire barrier penetration seal to perform its function. Based on this evaluation additional inspections may be performed.

During periods of time when a barrier is not FUNCTIONAL, either:

(1) Perform the recommended fire watch in accordance with the criteria in the remedial actions, or (2) a licensee may choose to implement a different required action or a combination of actions (e.g., additional administrative controls, operator briefings, temporary procedures, interim shutdown strategies, operator manual actions, temporary fire barriers, temporary detection or suppression systems). Such a change must be made to the approved Fire Protection Plan (FPP). However, the licensee must complete a documented evaluation of the impact of the proposed required action to the FPP. The evaluation must demonstrate that the required actions would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. Any change to the FPP must maintain compliance with the General Design Criteria and 10 CFR 50.48(a).

The evaluation of the required action should incorporate risk insights regarding the location, quantity, and type of combustible material in the fire area; the presence of ignition sources and their likelihood of occurrence; the automatic fire suppression and the fire detection capability in the fire area; the manual fire suppression capability in the fire area; and the human error probability where applicable .

Catawba Units 1 and 2 16.9-5-21 Revision 8

Fire Rated Assemblies 16.9-5 BASES (continued)

The expectation is to promptly complete the corrective action at the first available opportunity and eliminate the reliance on the required action.

This SLC is part of the Catawba Fire Protection Program and therefore subject to the provisions of Section 2.C.(5) of the Catawba Renewed Facility Operating Licenses.

REFERENCES 1. Catawba UFSAR, Section 9.5.1.

2. Catawba Nuclear Station 10 CFR 50.48(c) Fire Protection Safety Evaluation (SE).

3. Catawba Plant Design Basis Specification for Fire Protection, CNS-1465.00-00-0006, as revised.

4. Catawba UFSAR, Section 18.2.8.

5. Catawba License Renewal Commitments, CNS-1274.00 0016, Section 4.12.2.

6. NRC Regulatory Issue Summary 2005-07, Compensatory Measures to Satisfy the Fire Protection Program Requirements, April 19, 2005.

7. Catawba Renewed Facility Operating License Conditions 2.C.(5).

8. CNC-1435.00-00-0084, Catawba NFPA 805 Monitoring Program.

9. CNC-1435.00-00-0044, Fire Protection Nuclear Safety Capability Assessment.

10. CN-1209.1 O series drawings.

Catawba Units 1 and 2 16.9-5-22 Revision 8

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7

16.11 RADIOLOGICAL EFFLUENTS CONTROLS 16.11-7 COMMITMENT Radioactive Gaseous Effluent Monitoring Instrumentation The Radioactive Gaseous Effluent Monitoring Instrumentation channels shown in Table 16.11-7-1 shall be FUNCTIONAL with their Alarm/Trip Setpoints set to ensure that the limits of SLC 16.11-6 are not exceeded.

The Alarm/Trip Setpoints of these channels shall be determined and adjusted in accordance with the methodology and parameters in the OFFSITE DOSE CALCULATION MANUAL (ODCM).

APPLICABILITY: As shown in Table 16.11-7-1.

REMEDIAL ACTIONS

NOTE--------------------------------------------------------

Se para te Condition entry is allowed for each Function .

A.

CONDITION One or more Radioactive Gaseous A.1 REQUIRED ACTION Suspend the release of radioactive gaseous COMPLETION TIME Immediately Effluent Monitoring effluents monitored by the Instrumentation affected channel(s).

channel(s) Alarm/Trip Setpoint less OR conservative than required. A.2 Declare the channel(s) Immediately non-functional.

B. One or more B.1 Enter the applicable Immediately Radioactive Gaseous Conditions and Required Effluent Monitoring Actions specified in Table Instrumentation 16.11-7-1 for the channel(s) non- channel(s).

functional.

(continued)

Catawba Units 1 and 2 16.11-7-1 Revision 10 l

~-------

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 REMEDIAL ACTIONS (continued)

C.

CONDITION One channel non- C.1 REQUIRED ACTION Verify that EMF-36 (Low COMPLETION TIME Prior to initiating a functional. Ran~e) is FUNCTIONAL. release C.2.1 Analyze two independent Prior to initiating a samples of the tank's release contents.

C.2.2 Perform independent Prior to initiating a verification of the release discharge line valving.

C.2.3.1 Perform independent Prior to initiating a verification of manual release-portion of the computer input for release rate calculations performed by computer.

OR C.2.3.2Perform independent Prior to initiating a verification of entire release calculations for release rate calculations performed manually.

C.2.4 Restore channel to 14 days FUNCTIONAL status.

OR C.3 Suspend release of Immediately radioactive effluents via this pathway.

(continued)

Catawba Units 1 and 2 16.11-7-2 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7

REMEDIAL ACTIONS continued D.

CONDITION One or more flow rate D.1 REQUIRED ACTION Estimate the flow rate of COMPLETION TIME Once per 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months measurement device the release. during releases channel(s) non-functional.

D.2 Restore channel to 30 days FUNCTIONAL status.

E. One or more Noble Gas E.1 Obtain grab samples from Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Activity Monitor effluent pathway. *during releases channel(s) non-functional. AND E.2 Perform an analysis of Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of grab samples for obtaining the sample radioactivity.

AND

E.3 Restore channel to FUNCTIONAL status.

30 days (continued)

Catawba Units 1 and 2 16.11-7-3 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 REMEDIAL ACTIONS (continued)

F.

CONDITION Noble Gas Activity F.1 REQUIRED ACTION

NO TE--------------

COMPLETION TIME

Monitor (EMF Low In order to utilize Required Range) providing Action F.1, the following automatic termination of conditions must be release via the satisfied:

Containment Purge 1. The affected unit is in Exhaust System (CPES) MODES 5 or 6.

non-functional. 2. EMF-36 is FUNCTIONAL and in service for the affected unit.

3. The Reactor Coolant System for the affected unit has been vented.

4. Either the reactor vessel head is in place (bolts are not required),

or if it is not in place, the lifting of heavy loads over the reactor vessel and the movement of irradiated fuel assemblies within containment have been suspended.

Restore the non-functional 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months channel to FUNCTIONAL status.

G. Required Action and G.1 Suspend PURGING of Immediately associated Completion radioactive effluents via Time of Condition F not this pathway.

met.

OR Required Action F.1 not utilized.

(continued)

Catawba Units 1 and 2 16.11-7-4 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7

REMEDIAL ACTIONS (continued)

H.

CONDITION One or more sampler H.1 REQUIRED ACTION Perform sampling with COMPLETION TIME Continuously channel(s) non- auxiliary sampling functional. equipment as required by Table 16.11-6-1.

AND H.2 Restore channel to 30 days FUNCTIONAL status.

I. One Condenser 1.1 --------------NO TE-------------

Evacuation System Applicable to effluent Noble Gas Activity releases via the Condenser Monitor (EMF-33) Steam Air Ejector (ZJ) ,,

channel non-functional. System.

Obtain grab samples from Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months effluent pathway. during releases AND 1.2 --------------NO TE-------------

Applicable to effluent releases via the Condenser Steam Air Ejector (ZJ)

System.

Perform an analysis of Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of grab samples for obtaining the sample radioactivity.

AND (continued)

Catawba Units 1 and 2 16.11-7-5 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 REMEDIAL ACTIONS I.

CONDITION (continued) 1.3 REQUIRED ACTION

NO TE-------------

COMPLETION TIME

Applicable to effluent releases via the Steam Generator Blowdown (BB)

System atmospheric vent valve (BB-27) in the off-normal mode.

Perform an analysis of Once per 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months grab samples for during releases radioactivity at a lower limit when secondary 7

of detection of 10- specific activity is >

microCurie/ml. 0.01 microCurie/gm DOSE EQUIVALENT I

1-131 AND Once per 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months during releases when secondary specific activity is ~

0.01 microCurie/gm DOSE EQUIVALENT 1-131 AND 1.4 Restore channel to 30 days FUNCTIONAL status.

J. Noble Gas Activity J.1 Verify that EMF-36 is Prior to initiating a Monitor (EMF Low FUNCTIONAL. release Range) providing automatic termination of OR release via the Containment Air J.2.1 Analyze two independent Prior to initiating a Release and Addition samples of the release System non-functional. containment atmosphere.

AND (continued)

Catawba Units 1 and 2 16.11-7-6 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7

REMEDIAL ACTIONS J.

CONDITION (continued) J.2.2 REQUIRED ACTION Perform independent COMPLETION TIME Prior to initiating a verification of the release discharge line valving.

J.2.3.1 Perform independent Prior to initiating a verification of manual release portion of the computer input for release rate calculations performed by computer.

OR J.2.3.2 Perform independent Prior to initiating a verification of entire release calculations for release rate calculations performed manually .

AND J. 2 .4 --------------NO TE-------------

1f channel remains or is anticipated to remain non-functional for 2'., 90 days, re-evaluate the configuration of the affected unit in accordance with the applicable portions of 10 CFR 50.59 and 10 CFR 50.65(a)(4) prior to expiration of the 90-day period.

Restore channel to 30 days FUNCTIONAL status.

(continued)

Catawba Units 1 and 2 16.11-7-7 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 REMEDIAL ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME K. Required Action and K.1 Explain why the non- In the next associated Completion functionality was not scheduled Time of Condition C, D, corrected within the Radioactive Effluent E, F, H, I, or J not met. specified Completion Time. Release Report pursuant to Technical Specification 5.6.3 TESTING REQUIREMENTS

N OT E--------------------------------------------------------

Refer to Table 16.11-7-1 to determine which TRs apply for each Radioactive Gaseous Effluent Monitoring Instrumentation channel.

TEST FREQUENCY TR 16.11-7-1 Perform CHANNEL CHECK.

TR 16. 11-7-2 ---------------------------------NO TE---------------- ----------------

Prior to each release For Instruments 1a, 4, and 5, a SOURCE CHECK for these channels shall be the qualitative assessment of channel response when the channel sensor is exposed to a light-emitting diode.

Perform SOURCE CHECK. Prior to each release TR 16.11-7-3 Perform CHANNEL CHECK. 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months TR 16.11-7-4 Perform CHANNEL CHECK. 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months TR 16.11-7-5 Perform CHANNEL CHECK. 7 days

( continued)

Catawba Units 1 and 2 16.11-7-8 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7

TESTING REQUIREMENTS (continued)

TEST TR 16.11-7-6 ---------------------------------NOTE---------------------------------

FREQUENCY For Instruments 2 and 3a, a SOURCE CHECK for these channels shall be the qualitative assessment of channel response when the channel sensor is exposed to a light-emitting diode.

Perform SOURCE CHECK. 31 days TR 16. 11-7-7 ----- *---------------------------NO TE------------------------ --------

For Instruments 1a, 3a, 3c, 5, and 6a, the COT shall also demonstrate, as applicable; that automatic isolation of this pathway and control room alarm annunciation (for EMF-58, alarm annunciation is in the Monitor Tank Building control room and on the Monitor Tank Building control panel remote annunciator panel) occur if any of the following conditions exist:

a. Instrument indicates measured levels above the Alarm/Trip Setpoint, or

b. Circuit failure/instrument downscale failure (alarm only)

Perform COT. 9 months TR 16 .11-7-8 ---------------------------------NOTE---------------------------------

For Instruments 2 and 4, the COT shall also demonstrate that automatic isolation of this pathway and control room alarm annunciation occur if any of the following conditions exist:

a. Instrument indicates measured levels above the Alarm/Trip Setpoint, or

b. Circuit failure/instrument downscale failure (alarm only)

Perform COT. 18 months (continued)

Catawba Units 1 and 2 16.11-7-9 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 TESTING REQUIREMENTS continued TEST TR 16.11-7-9 ---------------------------------NOTE---------------------------------

FREQUENCY

For Instruments 1a, 2, 3a, 3c, 4, 5, and 6a, the initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards (NBS) or using standards that have been obtained from suppliers that participate in measurement assurance activities with NBS. These standards shall permit calibrating the system over its intended range of energy and measurement range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used.

Perform CHANNEL CALIBRATION. 18 months Catawba Units 1 and 2 16.11-7-10 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7

Table 16.11-7-1 Radioactive Gaseous Effluent Monitoring Instrumentation (page 1 of 2)

INSTRUMENT REQUIRED CONDITIONS APPLICABLE TESTING CHANNELS MODES REQUIREMENTS

1. Waste Gas Holdup System 1.a Noble Gas Activity Monitor - Providing 1 per station A,C,K At all times except TR 16.11-7-1 Alarm and Automatic Termination of when the isolation TR 16.11-7-2 Release valve is closed and TR 16.11-7-7 (EMF Low Range) locked TR 16.11-7-9 1.b Effluent System Flow Rate Measuring 1 per station D,K At all times except TR 16.11-7-1 Device when the isolation TR 16.11-7-9 valve is closed and locked

2. Condenser Evacuation System Noble A, I, K When air ejectors TR 16.11-7-3 Gas Activity Monitor are in operation TR 16.11-7-6 (EMF-33) (BB-27 is only isolation (Apply Required TR 16.11-7-8 function required) (Note 1) Action 1.3 when air TR 16.11-7-9 ejectors are not in operation)

3. Vent System 3.a Noble Gas Activity Monitor A,E,K At all times TR 16.11-7-4 (EMF Low Range) TR 16.11-7-6 TR 16.11-7-7 TR 16.11-7-9 3.b Deleted.

3.c Particulate Sampler A,H,K At all times TR 16.11-7-4 (EMF-35) (Note 2) TR 16.11-7-6 TR 16.11-7-7 TR 16.11-7-9 3.d Unit Vent Stack Flow Rate Meter D,K At all times TR 16.11-7-4 (no alarm/trip function) (Note 2) TR 16.11-7-9 3.e Unit Vent Radiation Monitor Flow Meter E,K At all times TR 16.11-7-4 (Note 2) TR 16.11-7-9

4. Containment Purge System Noble Gas A, F,G, K 5, 6 TR 16.11-7-2 Activity Monitor - Providing Alarm and TR 16.11-7-3 Automatic Termination of Release TR 16.11-7-8 (EMF Low Range) TR 16.11-7-9 (continued)

Catawba Units 1 and 2 16.11-7-11 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Table 16.11-7-1 Radioactive Gaseous Effluent Monitoring Instrumentation (page 2 of 2)

INSTRUMENT REQUIRED CONDITIONS APPLICABLE TESTING CHANNELS MODES REQUIREMENTS

5. Containment Air Release and Addition A, J, K 1,2,3,4,5,6 TR 16.11-7-2 System Noble Gas Activity Monitor - TR 16.11-7-3 Providing Alarm and Automatic TR 16.11-7-7 Termination of Release TR 16.11-7-9 (EMF Low Range)

6. Monitor Tank Building HVAC 6.a Noble Gas Activity Monitor - Providing 1 per station A,E,K At all times TR 16.11-7-4 Alarm (Note 2) TR 16.11-7-6 (EMF Low Range) TR 16.11-7-7 TR 16.11-7-9 6.b Effluent Flow Rate Measuring Device 1 per station D,K At all times TR16.11-7-4 (Note 2) TR 16.11-7-9 Note 1: The setpoint is as required by the primary to secondary leak rate monitoring program.

Note 2: Except when the effluent pathway is mechanically isolated; thus, a release to the environment is not possible.

Catawba Units 1 and 2 16.11-7-12 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7

BASES The Radioactive Gaseous Effluent Monitoring Instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in gaseous effluents during actual or potential releases of gaseous effluents. The Alarm/Trip Setpoints for these instruments shall be calculated and adjusted in accordance with the methodology and parameters in the ODCM to ensure that the Alarm/Trip will occur prior to exceeding the limits of 10 CFR Part 20. The FUNCTIONALITY and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63, and 64 of Appendix A to 10 CFR Part 50. The sensitivity of any noble gas activity monitor used to show compliance with the gaseous effluent release requirements of SLC 16.11-8 shall be such that concentrations as low as 1 x 1o-6 µCi/cc are measurable.

Regarding Note 2 of Table 16.11-7-1, isolation of the effluent pathway is to be by mechanical means (e.g., valve closure). Electrical or pneumatic isolation is not required, unless the isolation is designed to receive an automatic signal to open.

In MODES 5 and 6, initiation of the Containment Purge Exhaust System (CPES) with EMF-39 non-functional is not permissible. The basis for Required Action F.1 is to allow the continued operation of the CPES with EMF-39 initially FUNCTIONAL. Continued operation of the CPES is contingent upon the ability of the affected unit to meet the requirements as noted in Required Action F.1.

TR 16.11-7-7 requires the performance of a COT on the applicable Radioactive Gaseous Effluent Radiation Monitors. The test ensures that a signal from the control room module can generate the appropriate alarm and actuations. The required actuations/isolations for a High Radiation condition (i.e., radiation level above its Trip 2 setpoint) are listed below for each monitor.

OEMF Waste Gas Discharge Monitor 1WG160 closes when EMF-50 detects radiation level above its setpoint.

1/2EMF Unit Vent Noble Gas Monitor The following actuations occur when EMF-36 detects radiation level above its setpoint:

1. Containment Air Release and Addition System fans discharge to unit vent valve VQ10 closes.

2. Auxiliary Building unfiltered ventilation exhaust fans A and B stop.

3. Fuel Handling Ventilation Exhaust System (FHVES) exhaust trains align to the filter units.

4. (For 1EMF-36 only) 1WG160 closes.

1/2EMF Unit Vent Particulate Monitor (Sampler)

The following actuations occur when EMF-35 detects radiation level above its setpoint:

1. Containment Air Release and Addition System fans discharge to unit vent valve VQ1 O closes.

2. Auxiliary Building unfiltered ventilation exhaust fans A and B stop.

3. Fuel Handling Ventilation Exhaust System (FHVES) exhaust trains align to the filter units.

4. ((For 1EMF-35 only) 1WG160 closes .

Catawba Units 1 and 2 16.11-7~13 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 BASES (continued) 1/2EMF Containment Noble Gas Monitor The following actuations occur when EMF-39 detects radiation level above its setpoint:

1. Signals are provided to both trains of the Solid State Protection System (SSPS) to initiate a CPES isolation. This is verified by*observing that Relays K615 in the SSPS A output cabinet and the SSPS B output cabinet are latched.

2. EMF-39 isolates the CPES without going through the SSPS by stopping CPES supply fans A and B, CPES exhaust fans A and B, and by closing the appropriate valves and dampers.

3. Containment Evacuation Alarm, unless the source range trip is blocked.

OEMF-58 This monitor provides no control function.

TR 16.11-7-8 requires the performance of a COT on the Condensate Steam Air Ejector Exhaust Monitor, 1/2EMF-33 and Containment Noble Gas Monitor, 1/2EMF-39. The test ensures that a signal from the control room module can generate the appropriate alarm and actuations. The required actuations/isolations for a High Radiation condition (i.e., radiation level above its Trip 2 setpoint) are listed below.

1/2EMF Condensate Steam Air Ejector Exhaust Monitor The following actuations occur when EMF-33 detects radiation level above its setpoint:

1. Closure of 8827 is required in order to isolate the Slowdown Tank from the environment. Because of plant limitations/restrictions:

a. Opening the valve (in order to verify it goes closed on a High Radiation signal) is only possible during outages due to the negative effects on the Slowdown System with the unit at power.

b. Testing during innages will be by verification of relay contacts opening in the valve circuit.

2. Closure of 8824, 8865, 8869, and 8873 is required to minimize the amount of potentially contaminated material being delivered to the Slowdown Tank.

3. Closure of NM269, NM270, NM271, and NM272 is required to minimize the amount of potentially contaminated material being delivered to the

4. Conventional Sampling System.Closure of NM267 is required to minimize the amount of potentially contaminated material being delivered to the Condensate Storage Tank by isolating flow through EMF-34.

5. Closure of 8848 is required to minimize the amount of potentially contaminated material being delivered from the Slowdown System discharge to the Turbine Building sump.

1/2EMF Containment Noble Gas Monitor The following actuations occur when EMF-39 detects radiation level above its setpoint:

Catawba Units 1 and 2 16.11-7-14 Revision 10

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7

BASES (continued)

1. Signals are provided to both trains of the Solid State Protection System (SSPS) to initiate a Containment Air Release and Addition System isolation. This is verified by observing that relays K615 in the SSPS Train A output cabinet and the SSPS Train B output cabinet are latched.

2. Containment Evacuation Alarm, unless the source range trip is blocked.

REFERENCES 1. Catawba Offsite Dose Calculation Manual.

2. 10 CFR Part 20 .

- Catawba Units 1 and 2 16.11-7-15 Revision 10

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