Text

Transmittal of Selected Licensee Commitments Manual (SLC)
	ML12349A264
Person / Time
Site:	Oconee
Issue date:	12/12/2012
From:	Gillespie T; Duke Energy Carolinas
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	Download: ML12349A264 (163)
	v • d • e

Duke

Energy, T. PRESTON GILLESPIE, Jr.

Vice President Oconee Nuclear Station Duke Energy ON01 VP / 7800 Rochester Hwy.

Seneca, SC 29672 864-873-4478 864-873-4208 fax T. Gillespie@duke-energy. com December 12, 2012 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, DC 20555

Subject:

Duke Energy Carolinas, LLC Oconee Nuclear Station Docket Numbers 50-269, 50-270, and 50-287 Selected Licensee Commitments Manual (SLC)

Pursuant to 10CFR 50.4 and 50.71, please find attached the latest revision to the Oconee Selected Licensee Commitments (SLC) Manual. SLC Change 2012-09 extends certain 18 month Selected Licensee Commitment SR frequencies to 24 months.

Sincerely, T. Preston, Gillespie, Jr.

Vice President Oconee Nuclear Station Attachment A 76' -3 www. duke-energy, com

U.S. Nuclear Regulatory Commission December12, 2012 Page 2 xc:

Mr. Victor M. McCree, Administrator, Region II U.S. Nuclear Regulatory Commission Marquis One Tower 245 Peachtree Center Ave., NE, Suite 1200 Atlanta, GA 30303-1257 Mr. John P. Boska, Project Manager (By electronic mail only)

U. S. Nuclear Regulatory Commission Office of Nuclear Reactor Regulation One White Flint North, M/S O-8G9A 11555 Rockville Pike Rockville, MD 20852 NRC Senior Resident Inspector Oconee Nuclear Station

December 12, 2012

Subject:

Oconee Selected Licensee Commitments Manual (SLC) Revision On November 6, 2012, Station Management approved the following Oconee Selected Licensee Commitments. SLC Change 2012-09 extends certain 18 month Selected Licensee Commitment SR frequencies to 24 months.

Please revise your manual as instructed below.

Remove these pagqes SLC LOEP Pages 1-12 SLC Page 16.5.1-1 thru 3 SLC Page 16.5.2-1 thru 3 SLC Page 16.5.4-1 thru 2 SLC Page 16.5.9-1 thru 2 SLC Page 16.6.3-1 SLC Page 16.6.4-1 thru 6 SLC Page 16.6.6-1 SLC Page 16.6.9-1 thru 2 SLC Page 16.6.10-1 thru 3 SLC Page 16.6.11-1 thru 2 SLC Page 16.6.12-1 thru 3 SLC Page 16.6.15-1 thru 2 SLC Page 16.7.1-1 thru 2 SLC Page 16.7.2-1 thru 3 SLC Page 16.7.3-1 thru 2 SLC Page 16.7.5-1 thru 4 SLC Page 16.7.6-1 thru 4 SLC Page 16.7.7-1 thru 2 SLC Page 16.7.10-1 thru 2 SLC Page 16.7.11-1 thru 3 SLC Page 16.7.13-1 thru 3 SLC Page 16.7.14-1 thru 4 Insert these pagqes SLC LOEP Pages 1-12 SLC Page 16.5.1-1 thru 3 SLC Page 16.5.2-1 thru 3 SLC Page 16.5.4-1 thru 2 SLC Page 16.5.9-1 thru 2 SLC Page 16.6.3-1 SLC Page 16.6.4-1 thru 6 SLC Page 16.6.6-1 SLC Page 16.6.9-1 thru 2 SLC Page 16.6.10-1 thru 3 SLC Page 16.6.11-1 thru 2 SLC Page 16.6.12-1 thru 3 SLC Page 16.6.15-1 thru 2 SLC Page 16.7.1-1 thru 2 SLC Page 16.7.2-1 thru 3 SLC Page 16.7.3-1 thru 2 SLC Page 16.7.5-1 thru 4 SLC Page 16.7.6-1 thru 4 SLC Page 16.7.7-1 thru 2 SLC Page 16.7.10-1 thru 2 SLC Page 16.7.11-1 thru 3 SLC Page 16.7.13-1 thru 3 SLC Page 16.7.14-1 thru 4

December 12, 2012 Page 2 SLC Page 16.9.2-1 thru 5 SLC Page 16.9.3-1 thru 2 SLC Page 16.9.4-1 thru 5 SLC Page 16.9.5-1 thru 4 SLC Page 16.9.6-1 thru 9 SLC Page 16.9.9-1 thru 4 SLC Page 16.9.11-1 thru 8 SLC Page 16.9.11a-1 thru 15 SLC Page 16.9.12-1 thru 22 SLC Page 16.10.1-1 thru 2 SLC Page 16.10.4-1 SLC Page 16.14.1-1 SLC Page 16.15.2-1 thru 5 SLC Page 16.15.3-1 thru 5 SLC Page 16.9.2-1 thru 5 SLC Page 16.9.3-1 thru 2 SLC Page 16.9.4-1 thru 5 SLC Page 16.9.5-1 thru 4 SLC Page 16.9.6-1 thru 9 SLC Page 16.9.9-1 thru 4 SLC Page 16.9.11-1 thru 8 SLC Page 16.9.11a-1 thru 15 SLC Page 16.9.12-1 thru 22 SLC Page 16.10.1-1 thru 2 SLC Page 16.10.4-1 SLC Page 16.14.1-1 SLC Page 16.15.2-1 thru 5 SLC Page 16.15.3-1 thru 5 Any questions concerning these revisions may be directed to Kent Alter at 864-873-3255.

Oconee Nuclear Station Selected Licensee Commitments Revised 11/15/12 List of Effective Pages Pacqe Revision Date LOEP 1 11/15/12 LOEP 2 11/15/12 LOEP 3 11/15/12 LOEP 4 11/15/12 LOEP 5 11/15/12 LOEP 6 11/15/12 LOEP 7 11/15/12 LOEP 8 11/15/12 LOEP 9 11/15/12 LOEP 10 05/31/12 LOEP 11 05/31/12 LOEP 12 11/15/12 16.0-1 3/15/11 16.0-2 6/03/11 16.0-3 6/03/11 16.0-4 3/15/11 16.0-5 3/15/11 16.0-6 3/15/11 16.1-1 10/15/07 16.2-1 3/27/99 16.2-2 3/27/99 16.2-3 3/27/99 16.3-1 3/27/99 16.5.1-1 11/15/12 16.5.1-2 11/15/12 16.5.1-3 11/15/12 16.5.2-1 11/15/12 16.5.2-2 11/15/12 16.5.2-3 11/15/12 16.5.2-4 Delete 5/11/99 16.5.2-5 Delete 5/11/99 16.5.3-1 02/21/07 16.5.3-2 02/21/07 16.5.3-3 02/21/07 16.5.4-1 11/15/12 16.5.4-2 11/15/12 16.5.5-1 Delete 5/16/09 16.5.5-2 Delete 5/16/09 16.5.5-3 Delete 5/16/09 16.5.5-4 Delete 5/16/09 16.5.5-5 Delete 5/16/09 LOEP 1

Oconee Nuclear Station Selected Licensee Commitments Revised 11/15/12 List of Effective Pages Paqe Revision Date 16.5.6-1 02/05/08 16.5.6-2 02/05/08 16.5.7-1 12/13/06 16.5.7-2 12/13/06 16.5.7-3 12/13/06 16.5.7-4 12/13/06 16.5.7-5 12/13/06 16.5.7-6 12/13/06 16.5.8-1 01/31/07 16.5.8-2 01/31/07 16.5.8-3 01/31/07 16.5.8-4 01/31/07 16.5.8-5 01/31/07 16.5.8a-1 5/19/05 16.5.8a-2 5/19/05 (Delete) 16.5.8a-3 5/19/05 (Delete) 16.5.9-1 11/15/12 16.5.9-2 11/15/12 16.5.10-1 10/8/03-16.5.10-2 10/8/03 16.5.11-1 1/31/00 16.5.12-1 3/27/99 16.5.13-1 3/27/99 16.5.13-2 12/01/99 16.5.13-3 12/01/99 16.6.1-1 07/23/12 16.6.1-2 07/23/12 16.6.1-3 07/23/12 16.6.1-4 07/23/12 16.6.1-5 Delete 16.6.2-1 01/31/07 16.6.2-2 01/31/07 16.6.2-3 01/31/07 16.6.2-4 01/31/07 16.6.2-5 01/31/07 16.6.2-6 01/31/07 16.6.2-7 01/31/07 16.6.2-8 Delete 16.6.2-9 Delete 16.6.2-10 Delete 16.6.2-11 Delete LOEP 2

Oconee Nuclear Station Selected Licensee Commitments Revised 11/15/12 List of Effective Pages Paqe Revision Date 16.6.2-12 Delete 16.6.3-1 11/15/12 16.6.4-1 11/15/12 16.6.4-2 11/15/12 16.6.4-3 11/15/12 16.6.4-4 11/15/12 16.6.4-5 11/15/12 16.6.4-6 11/15/12 16.6.5-1 12/14/00 16.6.6-1 11/15/12 16.6.7-1 3/27/99 16.6.8-1 3/27/99 16.6.9-1 11/15/12 16.6.9-2 11/15/12 16.6.10-1 11/15/12 16.6.10-2 11/15/12 16.6.10-3 11/15/12 16.6.11-1 11/15/12 16.6.11-2 11/15/12 16.6.12-1 11/15/12 16.6.12-2 11/15/12 16.6.12-3 11/15/12 16.6.12-4 5/17/05 (Delete) 16.6.12-5 Delete 16.6.12-6 Delete 16.6.12-7 Delete 16.6.13-1 03/31/08 16.6.13-2 03/31/08 16.6.13-3 03/31/08 16.6.14-1 8/15/02 16.6.14-2 8/15/02 16.6.14-3 8/15/02 16.6.14-4 8/15/02 16.6.15-1 11/15/12 16.6.15-2 11/15/12 16.7.1-1 11/15/12 16.7.1-2 11/15/12 16.7.2-1 11/15/12 16.7.2-2 11/15/12 16.7.2-3 11/15/12 16.7.3-1 11/15/12 LOEP 3

Oconee Nuclear Station Selected Licensee Commitments Revised 11/15/12 List of Effective Pages Paqe Revision Date 16.7.3-2 11/15/12 16.7.4-1 7/14/05 16.7.4-2 7/f14/05 16.7.4-3 7/14/05 16.7.5-1 11/15/12 16.7.5-2 11/15/12 16.7.5-3 11/15/12 16.7.5-4 11/15/12 16.7.6-1 11/15/12 16.7.6-2 11/15/12 16.7.6-3 11/15/12 16.7.6-4 11/15/12 16.7.7-1 11/15/12 16.7.7-2 11/15/12 16.7.8-1 3/27/99 16.7.8-2 3/27/99 16.7.9-1 10/23/03 16.7.10-1 11/15/12 16.7.10-2 11/15/12 16.7.11-1 11/15/12 16.7.11-2 11/15/12 16.7.11-3 11/15/12 16.7.12-1 6/30/04 16.7.12-2 6/30/04 16.7.13-1 11/15/12 16.7.13-2 11/15/12 16.7.13-3 11/15/12 16.7.14-1 11/15/12 16.7.14-2 11/15/12 16.7.14-3 11/15/12 16.7.14-4 11/15/12 16.7.15-1 6/03/11 16.7.15-2 6/03/11 16.7.15-3 6/03/11 16.8.1-1 8/09/01 16.8.1-2 8/09/01 16.8.2-1 2/10/05 16.8.2-2 2/10/05 16.8.3-1 10/20/09 16.8.3-2 10/20/09 16.8.3-3 10/20/09 LOEP 4

Oconee Nuclear Station Selected Licensee Commitments Revised 11/15/12 List of Effective Pages Page Revision Date 16.8.3-4 10/20/09 16.8.3-5 10/20/09 16.8.3-6 10/20/09 16.8.3-7 10/20/09 16.8.4-1 2/10/05 16.8.4-2 2/10/05 16.8.4-3 2/10/05 16.8.4-4 2/10/05 16.8.4-5 Delete 2/10/05 16.8.4-6 Delete 2/10/05 16.8.4-7 Delete 2/10/05 16.8.4-8 Delete 2/10/05 16.8.4-9 Delete 9/25/04 16.8.5-1 07/23/12 16.8.5-2 07/23/12 16.8.5-3 07/23/12 16.8.5-4 Delete 12/21/04 16.8.5-5 Delete 12/21/04 16.8.6-1 01/04/07 16.8.6-2 01/04/07 16.8.6-3 01/04/07 16.8.7-1 1/31/00 16.8.8-1 1/31/00 16.8.9-1 6/21/05 16.8.9-2 6/21/05 16.8.9-3 6/21/05 16.8.9-4 6/21/05 16.9.1-1 1/31/00 16.9.1-2 3/27/99 16.9.1-3 3/27/99 16.9.1-4 3/27/99 16.9.1-5 6/12/01 16.9.2-1 11/15/12 16.9.2-2 11/15/12 16.9.2-3 11/15/12 16.9.2-4 11/15/12 16.9.2-5 11/15/12 16.9.3-1 11/15/12 16.9.3-2 11/15/12 16.9.4-1 11/15/12 16.9.4-2 11/15/12 LOEP 5

Oconee Nuclear Station Selected Licensee Commitments Revised 11/15/12 List of Effective Pages Page Revision Date 16.9.4-3 11/15/12 16.9.4-4 11/15/12 16.9.4-5 6/12/01 16.9.5-1 11/15/12 16.9.5-2 11/15/12 16.9.5-3 11/15/12 16.9.5-4 11/15/12 16.9.6-1 11/15/12 16.9.6-2 11/15/12 16.9.6-3 11/15/12 16.9.6-4 11/15/12 16.9.6-5 11/15/12 16.9.6-6 11/15/12 16.9.6-7 11/15/12 16.9.6-8 11/15/12 16.9.6-9 11/15/12 16.9.7-1 07/23/12 16.9.7-2 07/23/12 16.9.7-3 07/23/12 16.9.7-4 07/23/12 16.9.7-5 07/23/12 16.9.7-6 07/23/12 16.9.7-7 07/23/12 16.9.7-8 07/23/12 16.9.7-9 Delete 16.9.8-1 2/15/06 16.9.8-2 2/15/06 16.9.8-3 Delete 2/15/06 16.9.8-4 Delete 16.9.8-5 Delete 16.9.8-6 Delete 16.9.8-7 Delete 16.9.8a-1 2/7/05 16.9.8a-2 2/7/05 16.9.8a-3 2/7/05 16.9.9-1 11/15/12 16.9.9-2 11/15/12 16.9.9-3 11/15/12 16.9.9-4 11/15/12 16.9.10-1 1/12/04 16.9.10-2 1/12/04 LOEP 6

Oconee Nuclear Station Selected Licensee Commitments Revised 11/15/12 List of Effective Pages Page Revision Date 16.9.11-1 11/15/12 16.9.11-2 11/15/12 16.9.11-3 11/15/12 16.9.11-4 11/15/12 16.9.11-5 11/15/12 16.9.11-6 11/15/12 16.9.11-7 11/15/12 16.9.11-8 11/15/12 16.9.11a-1 11/15/12 16.9.11 a-2 11/15/12 16.9.11a-3 11/15/12 16.9.11 a-4 11/15/12 16.9.11a-5 11/15/12 16.9.11 a-6 11/15/12 16.9.11a-7 11/15/12 16.9.11 a-8 11/15/12 16.9.11a-9 11/15/12 16.9.1 la-10 11/15/12 16.9.11a-11 11/15/12 16.9.11a-12 11/15/12 16.9.11a-13 11/15/12 16.9.11 a-14 11/15/12 16.9.11a-15 11/15/12 16.9.1 la-16 Deleted 3/10/08 16.9.12-1 11/15/12 16.9.12-2 11/15/12 16.9.12-3 11/15/12 16.9.12-4 11/15/12 16.9.12-5 11/15/12 16.9.12-6 11/15/12 16.9.12-7 11/15/12 16.9.12-8 11/15/12 16.9.12-9 11/15/12 16.9.12-10 11/15/12 16.9.12-11 11/15/12 16.9.12-12 11/15/12 16.9.12-13 11/15/12 16.9.12-14 11/15/12 16.9.12-15 11/15/12 16.9.12-16 11/15/12 16.9.12-17 11/15/12 LOEP 7

Oconee Nuclear Station Selected Licensee Commitments Revised 11/15/12 List of Effective Pages Pacqe Revision Date 16.9.12-18 11/15/12 16.9.12-19 11/15112 16.9.12-20 11/15/12 16.9.12-21 11/15/12 16.9.12-22 11/15/12 16.9.13-1 01/31/07 16.9.13-2 01/31/07 16.9.13-3 01/31/07 16.9.13-4 01/31/07 16.9.14-1 10/28/04 16.9.14-2 10/28/04 16.9.15-1 3/27/99 16.9.15-2 3/27/99 16.9.15-3 3/27/99 16.9.16-1 4/01/08 16.9.16-2 4/01/08 16.9.16-3 4/01/08 16.9.17-1 5/23/01 16.9.17-2 3/27/99 16.9.18-1 5/02/07 16.9.18-2 5/02/07 16.9.18-3 5/02/07 16.9.18-4 5/02/07 16.9.18-5 5/02/07 16.9.18-6 5/02/07 16.9.18-7 5/02/07 16.9.18-8 5/02/07 16.9.18-9 5/02/07 16.9.18-10 5/02/07 16.9.18-11 5/02/07 16.9.18-12 5/02/07 16.9.18-13 5/02/07 16.9.18-14 5/02/07 16.9.18-15 5/02/07 16.9.18-16 5/02/07 16.9.19-1 3/31/05 16.9.19-2 3/31/05 16.9.20-1 12/21/09 16.9.20-2 12/21/09 16.9.20-3 12/21/09 16.9.20-4 12/21/09 LOEP 8

Oconee Nuclear Station Selected Licensee Commitments Revised 11/15/12 List of Effective Pages Pacqe Revision Date 16.9.20-5 12/21/09 16.9.21-1 07/09/09 16.9.21-2 07/09/09 16.9.21-3 07/09/09 16.9.21-4 07/09/09 16.10.1-1 11/15/12 16.10.1-2 11/15/12 16.10.1-3 Deleted 9/18/03 16.10.2-1 12/2/03 16.10.2-2 12/2/03 16.10.3-1 3/27/99 16.10.3-2 3/27/99 16.10.4-1 11/15/12 16.10.5-1 Deleted 8/24/04 16.10.6-1 3/27/99 16.10.7-1 4/29/99 16.10.7-2 4/29/99 16.10.7-3 1/31/00 16.10.7-4 4/29/99 16.10.7-5 4/29/99 16.10.7-6 4/29/99 16.10.7-7 4/29/99 16.10.7-8 4/29/99 16.10.7-9 4/29/99 16.10.8-1 11/27/06 16.10.8-2 11/27/06 16.10.8-3 11/27/06 16.10.8-4 11/27/06 16.10.8-5 11/27/06 16.10.9-1 11/25/09 16.10.9-2 11/25/09 16.10.9-3 11/25/09 16.10.9-4 11/25/09 16.10.9-5 11/25/09 16.11.1-1 3/15/11 16.11.1-2 3/15/11 16.11.1-3 3/15/11 16.11.1-4 3/15/11 16.11.1-5 3/15/11 16.11.1-6 3/15/11 16.11.1-7 3/15/11 LOEP 9

Oconee Nuclear Station Selected Licensee Commitments Revised 11/15/12 List of Effective Pages Paqe Revision Date 16.11.2-1 1/31/00 16.11.2-2 3/27/99 16.11.2-3 1/31/00 16.11.2-4 3/27/99 16.11.2-5 1/31/00 16.11.2-6 1/31/00 16.11.3-1 11/20/08 16.11.3-2 11/20/08 16.11.3-3 11/20/08 16.11.3-4 11/20/08 16.11.3-5 11/20/08 16.11.3-6 11/20/08 16.11.3-7 11/20/08 16.11.3-8 11/20/08 16.11.3-9 11/20/08 16.11.3-10 11/20/08 16.11.3-11 11/20/08 16.11.3-12 11/20/08 16.11.3-13 11/20/08 16.11.3-14 11/20/08 16.11.3-15 11/20/08 16.11.3-16 11/20/08 16.11.3-17 11/20/08 16.11.3-18 11/20/08 16.11.3-19 11/10/04 (Deleted) 16.11.4-1 09/30/09 16.11.4-2 09/30/09 16.11.4-3 09/30/09 16.11.4-4 09/30/09 16.11.4-5 09/30/09 16.11.4-6 09/30/09 16.11.4-7 09/30/09 16.11.4-8 11/10/04 (Delete) 16.11.5-1 10/30/02 16.11.5-2 10/30/02 16.11.5-3 10/30/02 16.11.5-4 10/30/02 16.11.6-1 05/31/12 16.11.6-2 05/31/12 16.11.6-3 05/31/12 16.11.6-4 05/31/12 LOEP 10

Oconee Nuclear Station Selected Licensee Commitments Revised 11/15/12 List of Effective Pages Paqe Revision Date 16.11.6-5 05/31/12 16.11.6-6 05/31/12 16.11.6-7 05/31/12 16.11.6-8 05/31/12 16.11.6-9 05/31/12 16.11.6-10 05/31/12 16.11.7-1 1/31/00 16.11.7-2 1/31/00 16.11.7-3 3/27/99 16.11.7-4 1/31/00 16.11.8-1 12/21/09 16.11.8-2 12/21/09 16.11.9-1 03/22/10 16.11.9-2 03/22/10 16.11.9-3 03/22/10 16.11.10-1 2/25/03 16.11.10-2 2/25/03 16.11.11-1 3/27/99 16.11.12-1 4/10/03 16.11.12-2 4/10/03 16.11.13-1 3/27/99 16.11.13-2 3/27/99 16.11.14-1 3/27/99 16.11.14-2 3/27/99 16.12.1-1 3/27/99 16.12.2-1 5/3/07 16.12.2-2 5/3/07 16.12.3-1 5/1/03 16.12.3-2 5/1/03 16.12.4-1 3/27/99 16.12.5-1 3/27/99 16.12.6-1 11/08/07 16.13.1-1 5/13/04 16.13.1-2 5/13/04 16.13.1-3 5/13/04 16.13.1-4 5/13/04 16.13.1-5 5/13/04 16.13.1-6 5/13/04 16.13.1-7 5/13/04 16.13.1-8 5/13/04 16.13.1-9 5/13/04 LOEP 11

Oconee Nuclear Station Selected Licensee Commitments Revised 11/15/12 List of Effective Pages Paqe Revision Date 16.13.2-1 12/15/04 16.13.2-2 Delete 12/15/04 16.13.2-3 Delete 12/15/04 16.13.2-4 Delete 12/15/04 16.13.3-1 12/15/04 16.13.3-2 Delete 12/15/04 16.13.4-1 3/27/99 16.13.5-1 Delete 16.13.5-2 Delete 16.13.6-1 3/27/99 16.13.7-1 12/15/04 16.13.7-2 12/15/04 16.13.8-1 3/27/99 16.13.9-1 3/27/99 16.13.9-2 3/27/99 16.13.10-1 3/27/99 16.13.11-1 3/27/99 16.14.1-1 11/15/12 16.14.2-1 07/23/12 16.14.2-2 07/23/12 16.14.3-1 3/27/99 16.14.4-1 Deleted 3/15/11 16.14.4.a-1 3/15/11 16.15.1-1 4/12/06 16.15.1-2 Deleted 4/12/06 16.15.1-3 Deleted 4/12/06 16.15.1-4 Deleted 4/12/06 16.15.1-5 Deleted 4/12/06 16.15.2-1 11/15/12 16.15.2-2 11/15/12 16.15.2-3 11/15/12 16.15.2-4 11/15/12 16.15.2-5 11/15/12 16.15.3-1 11/15/12 16.15.3-2 11/15/12 16.15.3-3 1)/i15/12 16.15.3-4 11/15/12 16.15.3-5 11/15/12 LOEP 12

Reactor Coolant System Vents 16.5.1 16.5 REACTOR COOLANT SYSTEM (RCS) 16.5.1 Reactor Coolant System Vents COMMITMENT

a.

The following reactor coolant system vent paths shall be OPERABLE:

1) Reactor Vessel Head Vent

2) Pressurizer Steam Space Vent (through PORV)

3) RCS Loop A High Point Vent

4) RCS Loop B High Point Vent APPLICABILITY:

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One RCS vent path A.1 Restore to OPERABLE 30 days inoperable, status.

B.

Two or more RCS vent B.1 Restore to OPERABLE 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months paths inoperable, status.

C.

The Required Actions C.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and associated Completion Times of AND Condition A or B not met.

C.2 Be in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months 16.5.1-1 11/15/12 1

Reactor Coolant System Vents 16.5.1 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.5.1.1 Verify an open flow path for each RCS vent 24 months path by testing the head vent, loop high point vents and Pressurizer vent.

SR 16.5.1.2 Perform high point vent valve testing.

In accordance with ASME Section X1 BASES The reactor vessel head vent should be capable of venting noncondensible gas from the reactor vessel hot legs (to the elevation of the top of the outlet nozzle) and cold legs.

Additional venting capability is required for those portions of each hot leg that cannot be vented through the reactor vessel head vent or Pressurizer. Venting of the Pressurizer is required to assure its availability for system pressure and volume control. These are important considerations, especially during natural circulation.

For the Hot Leg Loop "A" Vent Valves, Hot Leg Loop "B" Vent Valves, Reactor Vessel Head Vent Valves:

The RCS vents have two valves in series, which are capable of being powered from emergency buses. The valves are normally closed with power removed to prevent inadvertent opening of the valves. In order for a vent path to perform its intended safety function of venting, the two electrically operated valves in the flow path must be capable of being opened, and all manual valves must be open.

For the "Pressurizer Vent Valves Power Operated Relief Valve (PORV) and Block Valve:

The block valve is a normally open motor operated valve. The PORV is normally closed and is automatically operated in response to RCS system pressure signals. In order for the vent path to perform its intended safety function of venting, the PORV block valve in the flow path must be open or capable of being opened and the PORV must be capable of being opened.

16.5.1-2 11/15/12 1

Reactor Coolant System Vents 16.

5.1 REFERENCES

1. NUREG 0737, "Clarification of TMI Action Plan Requirements," November 1980.

2. Generic Letter 83-37, "NUREG-0737 Technical Specifications (Generic Letter No. 83-37)," dated November 1, 1983.

3. Letter, John F. Stolz (NRC) to H. B. Tucker (Duke Power Company) "NUREG-0737, Item Il.B.1, Reactor Coolant System Vents," dated November 2, 1983.

16.5.1-3 11/15/12 1

Low Temperature Overpressure Protection System 16.5.2 16.5 REACTOR COOLANT SYSTEM (RCS) 16.5.2 Low Temperature Overpressure Protection System COMMITMENT APPLICABILITY:

Perform SURVEILLANCE REQUIREMENTS.

MODE 3 when any RCS cold leg temperature is _< 3250F, MODES 4, 5, and 6 when an RCS vent path capable of mitigating the most limiting LTOP event is not open.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Not Applicable A.

Not Applicable Not Applicable SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.5.2.1 Verify travel stops limit flow through HP-120 to 24 months the specified limit.

SR 16.5.2.2 Perform Channel Calibration on pressurizer 24 months level and RCS pressure alarms.

SR 16.5.2.3 Perform an inspection of the PORV.

every 2 refueling cycles 16.52-1 11/15/12 1

Low Temperature Overpressure Protection System 16.5.2 SURVEILLANCE FREQUENCY SR 16.5.2.4 NOTE Only required to be met when vent(s) are being used for overpressure protection.

Verify valves in the flowpath for the RCS vent(s) are open.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for valves not locked, sealed, or otherwise secured open AND 31 days for valves locked, sealed, or otherwise secured open BASES BACKGROUND This SLC is provided to establish the SURVEILLANCE REQUIREMENTS for operability of the Administrative Controls (second train) of the LTOP system in accordance with ITS 3.4.12.

The COMMITMENTS for the Administrative Controls are located in the LCO Section of ITS Bases 3.4.12. The associated ACTION requirements are contained in ITS 3.4.12. The BASES for the LTOP requirements and the associated Administrative Controls are described in ITS Bases 3.4.12.

APPLICABILITY The SLC is applicable when the provisions of ITS 3.4.12 are applicable. This SLC is not applicable for operating conditions above 3250F since the possibility of non-ductile failure is significantly diminished. Vent paths capable of mitigating the most limiting LTOP event are' specified in Operations procedures. If an LTOP event were to occur, violation of this SLC could result in exceeding the brittle fracture pressure limits, overstressing the reactor vessel and closure head, or require reanalysis to demonstrate the resulting stresses would not impair further operation.

16.5.2-2 11/15/12 1

Low Temperature Overpressure Protection System 16.5.2 SURVEILLANCE REQUIREMENTS The identified surveillance requirements are provided to assure that the second train of LTOP is functioning properly and gives the operator 10 minutes to mitigate an LTOP event.

REFERENCES:

1.

ITS 3.4.12

2.

10 CFR 50 Appendix G "Fracture Toughness Requirements."

3.

Calc. File OSC-4445, Revision 8, "Low Temperature Overpressure Protection Evaluation,"

dated 4/30/99.

16.5.2-3 11/15/12 1

RCS Boron Sampling 16.5.4 16.5 REACTOR COOLANT SYSTEM (RCS) 16.5.4 Reactor Coolant System (RCS) Boron Sampling COMMITMENT APPLICABILITY:

Perform specified SURVEILLANCE REQUIREMENT.

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.1 Not Applicable A.1 Not Applicable Not Applicable SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.5.4.1 Perform J-leg Sample Point Test per 24 months Chemistry procedures.

BASES The Steam Generator Tube Rupture (SGTR) Event requires that a boron sample be taken post accident. The SGTR Event Mitigation Requirements calculation (Ref. 4) documents the necessity of taking this boron sample. Capability must be maintained for taking the RCS boron sample from the Post Accident Liquid Sample System (PALSS). During a SGTR, letdown may not be available. If letdown is not available, PALSS is the only mechanism for retrieving an RCS boron sample.

This is a regulatory commitment that is required to be maintained as part of the implementation of Amendment Nos. 346, 348, & 347 (Ref. 3).

SURVEILLANCE SR 16.5.4.1 Performance of the J-leg sample point test will simulate obtaining an RCS Boron sample; thereby, ensuring that all PALSS sample valves required for sampling if letdown is isolated are functional. This testing is currently done once every 24 months and is deemed adequate based 16.5.4-1 11/15/12 1

RCS Boron Sampling 16.5.4 on operating experience. Due to previously identified concerns about thermal stress, this test shall be completed prior to entering MODE 4 on startup.

REFERENCES

1. PIP 03-2433, Elimination of Post Accident Monitoring.

2.

PIP 04-6415, Declare the Unit 1 and Unit 2 PALS MR A(1).

3. Amendment 346, 348, & 347, Eliminate Requirements For Post Accident Sampling.

4. OSC-6116, Steam Generator Tube Rupture (SGTR) Event Mitigation Requirements.

16.5.4-2 11/15/12 1

Testing Following Opening of System (Core Barrel Bolt Inspections) 16.5.9 16.5 REACTOR COOLANT SYSTEM (RCS) 16.5.9 Testing Following Opening of System (Core Barrel Bolt Inspections)

COMMITMENT APPLICABILITY:

Two sets of main internal bolts (connecting the core barrel to the core support shield and to the lower grid cylinder) shall remain in place and under tension.

MODES 1, 2, 3, 4, and 5.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A.

A.1 N/A.

N/A SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY 16.5.9.1 Visually inspect the core barrel to lower grid NOTE -----

cylinder welded bolt locking caps.

Not required during U3 EOC 25 Refueling Outage Whenever the internals are removed from the vessel 16.5.9-1 11/15/12 1

Testing Following Opening of System (Core Barrel Bolt Inspections) 16.5.9 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY 16.5.9.2 Visually inspect the core barrel to core support shield welded bolt locking caps.

-N OTE-----

The provisions of SLC 16.2.7 do not apply.

24 months +25%

AND Whenever the internals are removed from the vessel BASES The requirement(s) of this SLC section were relocated from CTS 4.2.2 during the conversion to ITS.

To assure the structural integrity of the reactor internals throughout the life of the unit, the two sets of main internals bolts (connecting the core barrel to the core support shield and to the lower grid cylinder) must remain in place and under tension. This is verified by visual inspection to determine that the welded bolt locking caps remain in place.

REFERENCES N/A 16.5.9-2 11/15/12 1

Containment Heat Removal Verification Frequency 16.6.3 16.6 ENGINEERED SAFETY FEATURES 16.6.3 Containment Heat Removal Verification Frequency COMMITMENT APPLICABILITY:

Performed required SRs.

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A.

A.1 N/A.

N/A SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.6.3.1 Verify containment heat removal capability is As determined by LPI and sufficient to maintain post accident conditions RBCU fouling rate within design limits.

BASES The requirement(s) of this SLC section were relocated from CTS 4.5.3.1.b during the conversion to ITS.

The safety functions of the LPI system, RB Spray system, and RBCUs include maintaining containment pressure and temperature below design limits following an accident. This surveillance assures that containment heat removal capability is adequate assuming a worst case single failure. ITS SR 3.6.5.4 requires that the containment heat removal capability be verified on an 24 month frequency. Since service induced fouling can reduce containment heat removal capability, a fouling rate must be determined in order to establish a more frequent test interval if required.

REFERENCE UFSAR, Chapter 18, Section 18.3.17.13.

16.6.3-1 11/15/12 1

LPI System Leakage 16.6.4 16.6 ENGINEERED SAFETY FEATURES 16.6.4 Low Pressure Injection (LPI) System Leakage COMMITMENT APPLICABILITY:

The maximum allowable leakage from the LPI System components (which includes valve stems, flanges and pump seals) shall not exceed two gallons per hour.

MODES 1, 2, 3 and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A.

A.1 N/A.

N/A SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.6.4.1 Verify leakage from the portion of the LPI-

NOTE -----

System, except piping from the containment The provisions of SLC emergency sump to the low pressure injection 16.2.7 do not apply.

pump suction isolation valve, that is outside the containment is within the limit either by use in normal operation or by hydrostatically 24 months +25%

testing at >_ 350 psig.

SR 16.6.4.2 Verify leakage from piping from the NOTE -----------

containment emergency sump to the LPI The provisions of SLC pump suction isolation valve is within limit 16.2.7 do not apply.

when tested at > 59 psig.

24 months +25%

16.6.4-1 11/15/12 1

LPI System Leakage 16.6.4 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 16.6.4.3 Verify leakage is within limit by visual

NOTE------

inspection for excessive leakage from The provisions of SLC components of the system.

16.2.7 do not apply.

24 months +25%

BASES The requirement(s) of this SLC section were relocated from CTS 4.5.5 and Technical Specification Interpretetion.(TSI) 4.5.2/3.3.2 during the conversion to ITS.

Excessive leakage shall be measured by collection and weighing or by another equivalent method. The leakage rate limit for the Low Pressure Injection System is a judgement value based on assuring that the components can be expected to operate without mechanical failure for a period on the order of 200 days after a loss of coolant accident. The test pressure (350 psig) achieved either by normal system operation or by hydrostatically testing, gives an adequate margin over the highest pressure within the system after a design basis accident.

Similarly, the pressure test for the return lines from the containment to the Low Pressure Injection System (59 psig) is equivalent to the design pressure of the containment. The dose to the thyroid calculated as a result of this leakage is 0.76 rem for a two-hour exposure at the site boundary.

SURVEILLANCE TEST PRESSURE Leakage is measured during refueling outage surveillance testing. The surveillance testing may be performed as a hydrostatic test, or measured during system operation. Hydrostatic testing is used for the RBES suction lines, from the sump to LP-19/20. Required testing for the remaining portions of the system is accomplished through leakage measurement during alignment and/or operation of the LPI System, test pressure may be below 350 psig as necessary to meet operating limits. The test pressure of the rest of the LPI System is at or above the specified 59 psig or 350 psig.

Leakage rates corrections can be made, as described in the Bases, for the actual pressure versus the specified test pressure. These corrections are small - less than 10%.

16.6.4-2 11/15/12 I

LPI System Leakage 16.6.4 The following practices are used to ensure that requirements are met:

a)

The test pressure for the discharge side of the, LPI System is established as near to 350 psig as practical, within the operating limits in plant procedures.

b)

If the total measured leakage (uncorrected) is above 1.8 gph, the measured leakage will be evaluated for pressure differences prior to comparison to the 2 gph limit.

LEAKAGE OBSERVED DURING UNIT OPERATION LPI System leakage found during operation in MODES 1, 2, 3 or 4, which would be in excess of 2 gph at the specified pressures of this SLC, requires entry into the appropriate Actions of ITS 3.5.3 or ITS LCO 3.0.3.

The affected train, based on the location of the leakage, must be declared out of service in accordance with the appropriate Actions of ITS 3.5.3. In addition, the point of leakage must be isolated. As an alternative to isolating the leakage, provisions may be made to take steps, in the event of a LOCA, which would isolate the leakage or prevent it from exceeding 2 gph during emergency sump recirculation. If the LPI train remains capable of performing its safety functions after isolating the leakage, or if the planned steps in the event of a LOCA would still allow all subsequent safety functions to be performed by each train, the Action of ITS 3.5.3 can be exited.

If leakage exists in each train, and would be greater than 2 gph from each train, ITS LCO 3.0.3 must be entered. Also, if there is a point of leakage which would exceed 2 gph, and this leakage could not be isolated or reduced to less than 2 gph during emergency sump recirculation of at least one operable LPI train, ITS LCO 3.0.3 must be entered.

The 2 gph limit is based upon assuring that there is no existing leakage which could indicate that mechanical components might not continue to operate during long term core cooling. It is also based upon limiting the amount of off site dose due to leakage of highly contaminated primary coolant that is recirculated from the RB emergency sump. The 59 psig / 350 psig pressures are conservative values for which leakage is to be evaluated in the LPI suction /

discharge piping.

SURVEILLANCE TEST PRESSURE Performance of the leakage measurement during LPI System operation is a valid test method.

This method is used for required portions of the LPI System other than the lines between the RBES and LP-19/20. However, operational limits, fluid dynamics characteristics, and other considerations prevent achieving the exact 59 psig or 350 psig pressures. In the pump suction piping, the measurements are performed at > 59 psig. When an LPI pump is on, the pressure between the pump and throttle valve(s) LP-12/14 may be higher than the required 350 psig.

The pressure downstream of the throttle valve(s) is approximately equal to RCS pressure.

The fact that portions of the discharge side of the LPI System cannot be pressurized to 350 psig does not invalidate the testing. The specified 350 psig test pressure is an arbitrary value for evaluation of leakage, rather than a true hydrostatic test pressure. (The lowest design pressure in this portion of the system is 470 psig. Leakage rate, not structural integrity, 16.6.4-3 11/15/12 1

LPI System Leakage 16.6.4 is being evaluated.) However, the discharge side measurements are performed with the LPI System as near as practical to its operating limit (300 psig for Unit 1 and 2, 290 psig for unit 3).

Given any particular flow path, flow rate varies primarily with the square root of the pressure drop across the flow path. Therefore, the measured leakage rate can be adjusted for a difference between the actual test pressure and the specified test pressure as follows:

MEASURED LEAKAGE X SQUARE ROOT (SPECIFIED PRESS / ACTUAL PRESS)

Neglecting the adjustment is conservative where the actual pressure is higher than specified.

Neglecting the adjustment is slightly non-conservative where the actual pressure is lower than the specified pressure. For example, if actual test pressure were 310 psig at a point of leakage measured as 1.0 gph, the normalized leakage for 350 psig would be about 1.06 gph. Because the correction is small, adjustment ofthe measured leakages is not necessary when uncorrected leakage is well within the 2 gph limit (i.e., when uncorrected leakage is < 1.8 gph).

Water temperatures are different during testing of different portions of the system, so that density corrections could be considered. Because higher temperatures result in conservative offsite dose results due to evaporation rate, the UFSAR, assumes temperatures of 252 degrees and 115 degrees on the LPI System suction and discharge sides, respectively. However, the UFSAR evaluation expresses leakage in drops/minute, and converts drops per minute to cc/hr without considering temperatures. Actual leakage measurements are made by a combination of drop counting and/or collection of leakage in a container (which approaches room temperature).

Therefore, correction of measured leakage for temperature/density effects goes beyond the precision assumed in the analysis, and would conflict with accepted measurement techniques.

It is concluded that density corrections are unnecessary.

LEAKAGE OBSERVED-DURING UNIT OPERATION During operation in MODES 1, 2, 3 or 4, if it is determined that leakage exists such that the limit of this SLC would not be met, two actions must be taken. The affected LPI train(s) must be declared out of service, and provisions must be made to limit any leakage of recirculating RBES water, outside of containment, from exceeding 2 gph during an accident. It is not sufficient to simply declare an affected LPI train out of service. If both LPI trains are affected, such that it is not possible to take measures which would limit leakage to < 2 gph during recirculation, while also maintaining an operable LPI train, then ITS LCO 3.0.3 must be entered.

These requirements apply to the outside-of-containment leakage boundaries of those portions of the LPI System which would be used during emergency sump recirculation. Declaration of affected LPI train(s) as being out-of-service must be made upon determination that the limits of this SLC would be exceeded. Actions to isolate leakage or provide steps to limit leakage to < 2 gph, should be completed promptly as dictated by ITS 3.5.3 Actions or ITS LCO 3.0.3.

If the LPI train(s) remain capable of performing all safety functions after isolating the leakage, or if the planned steps in the event of a LOCA would still allow all subsequent safety functions to be performed by each train, the affected train(s) can be declared operable after the isolation /

provision of planned steps is completed.

16.6.4-4 11/15/12 I

LPI System Leakage 16.6.4 Because recirculation would not be required for some accidents, and because an affected train might be needed prior to beginning recirculation, physically securing an affected train may not always be the best method for controlling leakage. Example 2 below illustrates this point.

Situations in which more complex provisions are necessary should be addressed by a procedure.

The basis for these requirements is that-leakage above 2 gph could cause the offsite doses during an accident to exceed those which have been evaluated in the UFSAR. Because of the high concentration of fission products assumed to be present in the primary coolant after a large break LOCA significant offsite dose is associated with even small amounts of primary coolant leakage outside containment.

These practices, and the examples below, represent a conservative application of this SLC during operation in MODES 1, 2, 3 or 4, when ITS LCO 3.5.3 also applies. The 2 gph limit is relatively restrictive. Therefore, the Compliance Section should be contacted when marginal rates of LPI System leakage could cause a unit shutdown.

Example 1:

During power operation with the LPI pumps not running, leakage around the shaft of the 'A' LPI pump is observed. The leakage is determined to be about 3 gph (from BWST head). To repair the leakage, the pump must be isolated.

The required action is to declare LPI Train 'A' out of service, and to enter the 7 day Required Action A.1 for ITS 3.5.3. In addition, the 'A' pump must be isolated.

Example 2:

During power operation with the LPI pumps not running, leakage is observed around the packing of LP-9. The leakage is determined to be about 1 gph. It is also determined that this leakage would exceed 2 gph at 350 psig, but be less than 2 gph at 59 psig. Repairs do not require isolating LP-9.

The required action is to declare LPI Train 'A' out of service, and to enter the 7 day Required Action A.1 for ITS 3.5.3. Action must also be taken to control the leakage. Because isolating LP-9 is not necessary for repairs, it is preferable to leave the 'A' LPI train aligned for ES actuation even though it is declared out of service. To prevent leakage in excess of 2 gph in recirculation mode, verbal instructions and a turnover sheet item could be provided to turn off the 'A' LPI pump, prior to initiating the recirculation mode during an accident.

Example 3:

During power operation, the 3/8" line between LP-38 and LP-39 (PALS LINE ISOLATION VALVES) becomes disconnected. Leakage which would exceed 2 gph at 350 psig is observed coming from both directions (i.e., > 2 gph from 'A' and > 2 gph from 'B' The leakage cannot be controlled by closing LP-38 and LP-39.

The required action is to enter ITS LCO 3.0.3, and to attempt to reduce leakage.

16.6.4-5 11/15/12

LPI System Leakage 16.6.4 Example 4:

Leakage is observed around LP-28.

This problem is not applicable to this SLC, because LP-28 is neither in the emergency sump recirculation flow path nor a boundary of this flow path.

References:

1)

UFSAR Sections 6.0.3, 6.0.3.1, 6.0.3.2, 6.0.3.4, and 6.0.3.5

2)

UFSAR Section 15.15.4 and 6.3.3.2.2

2)

PT/l/A/0203/04 LPI System Leakage PT/2/A/0203/04 LPI System Leakage PT/3/A/0203/04 LPI System Leakage

3)

OP/I/A/1 104/04 LPI System Operation OP/2/A/1 104/04 LPI System Operation OP/3/A/1 104/04 LPI System Operation

4)

PIR 3-090-0019 Leakage on 3LP-9 Exceeded Tech Specs 16.6.4-6 11/15/12 1

Core Flooding System Test 16.6.6 16.6 ENGINEERED SAFETY FEATURES 16.6.6 Core Flooding System Test COMMITMENT APPLICABILITY:

Perform required SRs.

MODES 1 and 2, MODE 3 with Reactor Coolant System (RCS) pressure > 800 psig.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A.

A.1 N/A.

N/A SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.6.6.1 Verify that the check and isolation valves in NOTE----------

the core flooding tank discharge lines operate The provisions of SLC properly during pressurization of the Reactor 16.2.7 do not apply.

Coolant System.

24 months +25%

BASES The requirement(s) of this SLC section were relocated from CTS 4.5.1.1.3 during the conversion to ITS.

With the reactor shut down, the valves in each core flooding line are checked for operability by reducing the Reactor Coolant System Pressure until the indicated level in the core flood tanks verify that the check and isolation valves have opened. The test will be considered satisfactory if control board indication of core flood tank level verifies that all valves have opened.

REFERENCE N/A 16.6.6-1 11/15/12

Containment Purge Valve Testing 16.6.9 16.6 ENGINEERED SAFETY FEATURES 16.6.9 Containment Purge Valve Testing COMMITMENT APPLICABILITY:

Perform specified SRs.

MODES 1, 2, 3 and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A.

A. 1 N/A.

N/A SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.6.9.1 NOTE

1.

Not required to be performed for purge valves that have not been operated if conducted within the preceeding 184 days.

2.

Perform after final closing when the purge valves have been operated.

Perform leakage integrity tests.

After every entry into MODE 5 from MODE 4 16.6.9-1 11/15/12 I

Containment Purge Valve Testing 16.6.9 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 16.6.9.2 Visually inspect and adjust or replace the

NOTE-----

valve seals of the purge isolation valves.

The provisions of SLC 16.2.7 do not apply.

24 months +25%

BASES The requirement(s) of this SLC section were relocated from CTS 4.4.4.1 and 4.4.4.3 during the conversion to ITS.

Leakage integrity tests of the purge supply and isolation valves are conducted in order to identify excessive degradation of the resilient seals. Excessive leakage past resilient seals is typically caused by severe environmental conditions and/or wear due to frequent-use.

REFERENCE N/A 16.6.9-2 11/15/12

TSP 16.6.10 16.6 ENGINEERED SAFETY FEATURES 16.6.10 Trisodium Phosphate (TSP)

NOTE --------------------------------------------

Applicable on each Unit after completion of the Caustic Addition System Enhancement modification on the respective Unit.

COMMITMENT APPLICABILITY:

The TSP baskets shall contain > 333 ft3 and < 375 ft3 of active TSP.

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

TSP not within limits.

A.1 Restore TSP to within 7 days limits.

B.

Required Action and B.1 Initiate performance of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Associated Completion Engineering evaluation to Time not met.

verify that the volume of TSP is adequate.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.6.10.1 Verify TSP volume is > 333 ft3 and < 375 ft3.

24 months 16.6.10-1 11/15/12 I

TSP 16.6.10 BASES BACKGROUND The control of pH in recirculated coolant after a Loss-of-Coolant Accident (LOCA) is important to minimize the re-evolution of gaseous radioactive iodine isotopes that are dissolved in the coolant in the RB basement and emergency sump. Maintaining the radioiodine in solution reduces radioactive material releases to the environment. The Trisodium Phosphate Dodecahydrate (TSP) Addition System performs this function during a LOCA. It has no function during normal plant operation. TSP is stored in wire mesh baskets in the reactor building.

Following an accident, the TSP will be dissolved by the containment fluid. This will raise the pH of the water in the containment following a Design Basis Accident (DBA). The quantity of TSP stored in the baskets is sufficient to raise the containment sump fluid pH to at least 7.0 at STP following a DBA. The TSP must be at least 90% assay (% of TSP) and have a density > 53.53 Ibm/ft3. The required TSP volume determined by Reference 1 is 300 ft3 assuming "pure" TSP and a density of 53.53 Ibm/ft3. Since a 90% assay is available, a volume of 333 ft3 is required.

The pH of the sump fluid following DBA will not affect the Environmental Qualification (EQ) of reactor building equipment and components.

APPLICABLE SAFETY ANALYSIS Following a DBA, the fission product of primary concern is radioiodine. Reactor Building Spray (RBS) will remove elemental and particulate iodine from containment atmosphere in the injection phase using borated water from the Borated Water Storage Tank (BWST). The amount of iodine that comes out of solution during sump recirculation is reduced as pH is increased.

The predicted sump pH over time, which is based on TSP amounts required herein, is input into a Dose Analysis model to ensure that acceptable offsite doses would be expected during a DBA.

Sufficient volume, density, and solubility of TSP is required to adjust the sump pH and ensure iodine stays in the solution during sump recirculation. The density and solubility are not expected to change significantly over time. The volume may change slightly due to moisture absorption as well as change due to spillage.

APPLICABILITY This SLC applies in MODES 1, 2, 3, & 4. This applicability is consistent with the RBS system operability requirement in Technical Specification 3.6.5, "Reactor Building Spray and Containment Cooling Systems." In MODES 1, 2, 3, & 4, a DBA could cause a release of radioactive material to containment requiring the operation of TSP addition system. The TSP addition system will assist in reducing the iodine from coming out of solution during sump recirculation.

TSP addition system is not required in MODES 5 and 6. The probability and consequences of a DBA without the TSP addition system will be reduced during these modes due to the RCS pressure and temperature limitations. At these conditions RBS actuation is not anticipated, thus without RBS operation, re-evolution of gaseous iodine is expected to be small.

16.6.10-2 11/15/12 1

TSP 16.6.10 ACTIONS A.1 With the TSP in the Reactor Building not within limits, action must be taken to restore the TSP to within limits. The TSP baskets are located in the Reactor Building and may not be accessible during power operation. The RBS system will still be available to remove the iodine from containment atmosphere in the event of a DBA.

A Completion Time of 7 days is allowed for restoring TSP within limits. The Completion Time is consistent with other ECCS components. The Completion Time is also acceptable due to the low probability of the worst-case DBA occurring during the period.

B. 1 If the TSP addition system cannot be restored to within limits within the required Completion Time given, an engineering evaluation must be completed within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to ensure that an adequate volume of TSP is available. The evaluation can be done using methodology in the referenced calculations. The allowed Completion Time is reasonable based on TSP function.

SURVEILLANCE REQUIREMENTS SR 16.6.10.1 Periodic determination of the volume of TSP in Containment must be performed due to the possibility of leaking components in the Reactor Building that could cause dissolution of the TSP during normal operation. A Frequency of 24 months is required to determine visually that the amount of TSP contained in the'baskets is maintained within a minimum of 333 cubic feet and a maximum of 375 cubic feet. This requirement ensures that there is an adequate volume of TSP to adjust the pH of the post LOCA sump solution to a value > 7.0.

The TSP addition system is a passive system. The TSP baskets are located in the reactor building and therefore not normally accessible during power operation. The 24 month interval is acceptable because the system is passive and a significant volume change is unlikely during this time period.

REFERENCES

1. OSC-7735 - "Post-Accident Reactor Building Sump pH Analysis for Proposed Passive Caustic Modification"

2. OSC-7736 - "Post-Accident Iodine Re-Volatilization Analysis For Proposed Passive Caustic-Modification"

3. Letter dated October 16, 2001 from W. R. McCollum, Jr. (Duke) to Document Control Desk (NRC) - License Amendment Request for Full-Scope Implementation of the Alternative Source Term.

16.6.10-3 11/15/12 1

Containment Debris Sources 16.6.11 16.6 ENGINEERED SAFETY FEATURES 16.6.11 Containment Debris Sources COMMITMENT Maintain Containment free of debris sources that could affect the OPERABILITY of the Containment Sump.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Debris source found in A.1 Eliminate potential for Upon completion of a Containment that could debris source to be Containment entry(ies) impact Containment transported to the Sump OPERABILITY.

Containment Sump.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.6.11.1 Visually inspect the Containment areas Upon completion of a occupied or traversed during Containment Containment entry(ies) entry to verify that no potential debris source(s) exists that could impact OPERABILITY of the Containment Sump.

SR 16.6.11.2 Visually inspect the accessible areas of the 24 months Containment to verify that no potential debris source(s) exists that could impact OPERABILITY of the Containment Sump.

16.6.11-1 11/15/12 1

Containment Debris Sources 16.6.11 BASES During outages and Containment entries, the potential exists for debris sources to be created that could be transported to the Containment Sump screen inlet following a Loss of Coolant Accident (LOCA). This would impact the ability of the Containment Sump to perform its function (i.e., serve as the suction source to the Emergency Core Cooling Systems (ECCS) during the recirculation phase of the accident). Periodic inspections of the Containment to identify debris sources will ensure the Containment Sump suction inlet will remain unrestricted in the event of a LOCA and subsequent operation of the ECCS in the recirculation mode of operation.

REFERENCES

1.

Problem Investigation Process Report 0-01-3796

2.

Site Directive 1.3.9

3.

MP/O/AI3005/012 16.6.11-2 11/15/12 1

Additional HPI Requirements 16.6.12 16.6 ENGINEERED SAFETY FEATURES 16.6.12 Additional High Pressure Injection (HPI) Requirements COMMITMENT:

APPLICABILITY:

The HPI System shall be OPERABLE with:

a. Two HPI discharge crossover valves OPERABLE

b. Two LDST to RBES drain isolation valves OPERABLE MODES 1 and 2, MODE 3 with Reactor Coolant System (RCS) temperature

> 3500F.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more HPI A.1 Enter Condition A of HPI Immediately discharge crossover TS 3.5.2.

valves inoperable.

B.

One HPI LDST to B.1 Restore both required 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months RBES drain isolation HPI LDST to RBES drain valve inoperable isolation valves to OPERABLE status.

C.

Required Action and C.1 Enter Condition G of HPI Immediately associated Completion TS 3.5.2.

Time of Condition B not met D.

Two HPI LDST to D.1 Enter Condition H of HPI Immediately RBES drain isolation TS 3.5.2.

valves inoperable OCONEE UNITS 1, 2, & 3 16.6.12-1 11/15/12 1

Additional HPI Requirements 16.6.12 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.6.12.1 Perform CHANNEL CHECK for each HPI 31 days discharge crossover valve flow instrument.

SR 16.6.12.2 Perform CHANNEL CALIBRATION for each 24 months HPI discharge crossover valve flow instrument.

BASES BACKGROUND The SLC establishes SURVEILLANCE REQUIREMENTS for the OPERABILITY of the flow instruments associated with the HPI discharge crossover valves.

The HPI LDST to RBES drain isolation valves (HP-939 and HP-940) were installed as part of a modification to resolve two different design issues: 1) Operator burden associated with local isolation HPI pump minimum flow lines, and 2) LDST Relief Valve HP-79 discharges to Auxiliary Building. The HPI LDST to RBES drain isolation valves ensure a minimum flow path for the HPI pumps while the HPI system is aligned in piggy-back mode of operation. Loss of the minimum flow path for the HPI pumps while the HPI system is aligned in piggy-back mode will result in over-pressurization of the LDST and cause the LDST relief valve, (HP-79) or either of the RCP Seal Return Cooler outlet relief valves (HP-73 or HP-76) to release RBES fluid to the Auxiliary Building during a LOCA event. Preventing the actuation of these relief valves during LOCA events is necessary to prevent RBES inventory loss and excessive dose rates. The HPI LDST to RBES drain isolation valves also ensure LPI OPERABILITY by providing a post LOCA relieving flow path for any received leakage into the LDST from check valve HP-97.

APPLICABILITY The SLC is applicable when the provisions of ITS 3.5.2 are applicable.

OCONEE UNITS 1, 2, & 3 16.6.12-2 11/15/12 1

Additional HPI Requirements 16.6.12 SURVEILLANCE REQUIREMENTS SR 16.6.12.1 and SR 16.6.12.2 This SLC specifies Surveillance Requirements for the flow instruments associated with the HPI discharge crossover valves. SLC SR 16.6.12.1 and SR 16.6.12.2 require a CHANNEL CHECK and CHANNEL CALIBRATION be performed for these flow instruments at a Frequency of 31 days and 24 months, respectively. If one or both of these SRs is not met, the associated HPI discharge crossover valve (i.e., HP-409 or HP-410) must be declared inoperable, because the Bases for Technical Specification 3.5.2 requires that the associated flow instrument be OPERABLE to support the valve's OPERABILITY.

REFERENCES

1.

Letter from D. E. LaBarge (NRC) to W. R. McCollum (Duke), NRC Safety Evaluation Report on the Oconee High Pressure Injection System, dated September 6, 2000.

2.

UFSAR Sections 5.4.7.2, 6.3.1, 6.3.2.2.1, and 9.3.2, and Chapter 15.

3.

ITS 3.5.2.

OCONEE UNITS 1, 2, & 3 16.6.12-3 11/15/12 1

HPI & LWD System Leakage 16.6.15 16.6 ENGINEERED SAFETY FEATURES 16.6.15 High Pressure Injection (HPI) and Liquid Waste Disposal (LWD) System Leakage COMMITMENT:

APPLICABILITY:

Leakage from components in the applicable portions of the HPI and LWD Systems (which includes valve stems, flanges and pump seals) when combined with applicable LPI System Leakage shall not exceed two gallons per hour.

MODES 1, 2, 3 and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A.

A.1 N/A.

N/A.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.6.15.1 Verify external leakage from the components

NOTE-----

located in the LDST-to-RBES return line from The provisions of SLC the RBES through the HPI motor-operated 16.2.7 do not apply.

containment isolation valves and through the first LWD manual containment isolation valve is within the limit when tested at > 55 psig.

24 months +25%

BASES The leakage limit is based upon limiting the amount of off site dose due to leakage of highly contaminated primary coolant that is recirculated from the RBES (Reference 5).

The LDST-to-RBES return line is an extension of the HPI system and ties into the LWD system.

This return line is credited for supporting long-term LPI operation following a LOCA by providing a flow path for LPI system leakage back to the RBES. The portion of the return line upstream of 16.6.15-1 11/15/12 1

HPI & LWD System Leakage 16.6.15 the MOVs is normally exposed to operating pressures; leakage monitoring for this piping is therefore subject to the same surveillance by operations staff that is applied to the rest of the HPI system. However, the portion of piping downstream of the MOVs is not normally exposed to an elevated operating pressure. Therefore, leakage through components in this piping should be minimized.

If leakage is observed, an engineering evaluation is required. The observed leakage must be combined with the surveillance results from SLC 16.6.4, "LPI System Leakage" and shall not exceed the two gallons per hour limit of that SLC.

This surveillance is intended to address leakage in this return line due to recirculation of the sump fluid. The containment Integrated Leak Rate Test continues to be relied upon for ensuring containment integrity for other conditions.

SURVEILLANCE TEST PRESSURE Leakage is measured during refueling outage surveillance testing. The surveillance testing is performed using either pressurized water or air. The test pressure for the LDST-to-RBES return line (55 psig) is the maximum calculated pressure for this piping when this line is open in the sump recirculation mode (References 1, 6 and 7).

References:

1)

OSC-8644, "Hydraulic Analysis to Support Unit 3 LDST-RBES Return Line Surveillance Testing for NSM-ON-33106," Rev. 0.

2)

OMP 2-1, "Duties and Responsibilities of Operations Shift Personnel," section 4.1, item 17.

3)

UFSAR Section 15.15.4, "Effects of Engineered Safeguard System Leakage"

4)

UFSAR Section 6.1.3, "Leakage and Radiation Considerations"

5)

OSC-3781, Rev 7., "Documentation of Maximum Hypothetical Accident (MHA) Dose Model for Oconee Nuclear Station (Supersedes OSC-6600, OSC-5669)"

6)

OSC-8552, "Hydraulic Analysis For LDST To RBES Return Line Modification for NSM ON-13106," Rev. 0.

7)

OSC-8583, "Hydraulic Analysis For LDST To RBES Return Line Modification for NSM ON-23106," Rev. 0.

16.6.15-2 11/15/12 1

Accident Monitoring Instrumentation - Noble Gas Effluent Monitor (RIA-56) 16.7.1 16.7 INSTRUMENTATION 16.7.1 Accident Monitoring Instrumentation - Noble Gas Effluent Monitor (RIA-56)

COMMITMENT APPLICABILITY:

The noble gas effluent monitor shall be OPERABLE.

MODES 1 AND 2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Noble Gas Effluent A.1 Institute alternative 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Monitor (RIA-56) noble gas monitoring inoperable, program.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.7.1.1 Perform CHANNEL FUNCTIONAL TEST.

31 days SR 16.7.1.2 Perform CHANNEL CALIBRATION.

24 months BASES The Noble Gas Effluent Monitor (RIA-56) is utilized for detection of significant releases and release assessment.

The Alternative methods for monitoring noble gas effluent during inoperability of RIA-56 shall include one or more of the following methods:

- RIA-45 normal range noble gas monitor on the unit vent.

- RIA-46 high range noble gas monitor on the unit vent.

- Actual vent sample.

- Direct radiation readings on RIA-45 and RIA-46 sample line.

16.7.1-1 11/15/12 1

Accident Monitoring Instrumentation - Noble Gas Effluent Monitor (RIA-56) 16.7.1 BASES (continued)

REFERENCES:

1. Generic Letter 83-37

2. Regulatory Guide 1.97, Rev. 2 16.7.1-2 11/15/12 1

Anticipated Transients Without Scram 16.7.2 16.7 INSTRUMENTATION 16.7.2 Anticipated Transients Without Scram COMMITMENT APPLICABILITY:

The ATwS Mitigation Systems Actuation Circuitry (AMSAC) and Diverse Scram System (DSS) shall be OPERABLE.

MODE 1, MODE 2 when Keff >_ 1.0 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or both channels of A.1 Restore AMSAC to 7 days AMSAC inoperable.

OPERABLE status.

B.

One or both channels of B.1 Restore DSS to 7 days DSS inoperable.

OPERABLE status.

C.

Required Action and -

NOTE---------

associated Completion When initiated, the Required Time not met.

Action must be completed.

C.1 Submit a written report 30 days to the NRC outlining the cause of the channel(s) or system(s) malfunction and the plans for restoring the channel(s) or system(s) to OPERABLE status.

16.7.2-1 11/15/12 1

Anticipated Transients Without Scram 16.7.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.7.2.1 Perform a Channel Logic Test of AMSAC.

184 days SR 16.7.2.2 Perform a Channel Logic Test of DSS.

184 days SR 16.7.2.3 Perform an Actuation Test of AMSAC.

24 months SR 16.7.2.4 Perform an Actuation Test of DSS.

24 months BASES The AMSAC and DSS are provided to mitigate the consequences of anticipated transient without scram. These anticipated transients are beyond the design basis for the plant. These events are associated with a failure of the reactor to normally trip when required as defined in the references below.

The AMSAC/DSS consists of two channels and uses a two-out-of-two coincidence logic to actuate. Each channel has an AMSAC portion and a DSS portion.

The AMSAC circuitry of each channel receives input signals on low Feedwater pump Turbine (FDWPT) control oil pressure or low Feedwater pump (FDWP) discharge pressure. Upon a valid input signal to the AMSAC portions of the two AMSAC/DSS channels, an output is generated to trip the Main Turbine and start all operable Emergency Feedwater Pumps.

The DSS circuitry of each channel receives an input signal from the Inadequate Core Cooling Monitoring System RCS pressure signals. Upon a valid signal (RCS Pressure Very High / 2!

2450 psig nominal) to both DSS portions of each channel an output is generated to interrupt power to the Control Rod Drive System gate drives for regulating rod groups 5 through 7 and the auxiliary gate drives (for Unit(s) with the Control Rod Drive Control System (CRDCS) digital upgrade not complete) or power to all SCR gating circuits to the Control Rod Single Rod Power Supplies (for Unit(s) with the CRDCS digital upgrade complete).

An AMSAC/DSS channel is considered operable if it has met the surveillance criteria of this commitment and the AMSAC/DSS enabled light (located in the control room) is on and the AMSAC/DSS Ch. 1 and Ch. 2 bypassed lights (also located in the control room) are not on and 16.7.2-2 11/15/12 1

Anticipated Transients Without Scram 16.7.2 "Sy Max" Programmable Controllers RUN Lights (ON) and HALT Lights (OFF) for AMSAC/DSS Ch. 1 AND AMSAC/DSS Ch. 2.

An Actuation Test consists of a complete test from input sensors through output actuation relays.

REFERENCES:

1. Code of Federal Regulations, Section 10 CFR 50.62, "The ATWS Rule".

2. B&WOG Generic ATWS Design Basis Document 47-1159091-00, October 9, 1985.

3. NRC Safety Evaluation Report on 47-1159091, June 30, 1988.

4. AMSAC and DSS Final Design Description, August 30, 1988.

5. NRC Safety Evaluation Report for Final Design of Oconee ATWS Modification (TACs 59119/59120/59121), November 29, 1989.

16.7.2-3 11/15/12 1

Emergency Feedwter - Low Level Initiation 16.7.3 16.7 INSTRUMENTATION 16.7.3 Emergency Feedwater - Low Level Initiation COMMITMENT APPLICABILITY:

Automatic low level initiation of both MDEFW pumps shall be OPERABLE.

MODES 1, 2, and 3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or both channels A.1 Restore to OPERABLE 7 days inoperable, status.

B.

Required Action and NOTE -------

associated Completion When initiated the Required Time not met.

Action must be completed.

B.1 Submit a written report 30 days to the NRC outlining the cause of the channel(s) or system(s) malfunction and the plans for restoring the channel(s) or system(s) to OPERABLE status.

16.7.3-1 11/15/12 1

Emergency Feedwter - Low Level Initiation 16.7.3 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.7.3.1 Perform a CHANNEL CALIBRATION.

24 months BASES The Steam Generator Level Control System (SGLCS) receives four OTSG level signals. Each train receives one signal from each OTSG (OTSG A & B Level to Train A and the same to Train B). These level signals are used to start the MDEFWPs upon 2 out of 2 low level in either OTSG. A level signal indicating below the initiation setpoint or failed low is considered to be operable.

The most limiting transient for the EFW system is the Loss of Main Feedwater (LMFW), (Ref.

UFSAR Section 10.4.7). The primary success path to mitigate the LMFW includes initiation of the EFW system. The UFSAR evaluation credits automatic initiation of EFW on loss of both main feedwater pumps as sensed by low hydraulic oil pressure. In addition, for plant conditions in which automatic initiation circuitry must be disabled (i.e., turbine header pressure < 850 psig) adequate time is available for manual initiation of EFW. Thus, initiation of EFW on low OTSG level is not credited for any DBA or transient. EFW initiation on low OTSG level has been included as a SLC in response to GL 89-19 and USI A-47 and provides additional protection from OTSG dryout.

EFW initiation on low OTSG level is applicable above 2500F, although it is not required for operability of the EFW System.

In order to provide additional protection from OTSG dryout, RCS temperature may not be increased above 250°F with low level initiation of MDEFW inoperable. However, if the Unit is above 2500F, shutdown is not required since low level initiation is not credited for any DBA or transient.

REFERENCES:

1. Generic Letter 89-19, Safety Implication of Control Systems 16.7.3-2 11/15/12 I

Steam Generator Overfill Protection 16.7.5 16.7 INSTRUMENTATION 16.7.5 Steam Generator Overfill Protection COMMITMENT The steam generator overfill protection system shall be OPERABLE.

NOTE When a Main Feedwater pump is incapable of feeding the steam generators, the associated portions of the steam generator overfill protection system are not required to be OPERABLE.

APPLICABILITY:

MODES 1 and 2, MODE 3 when RCS Tare > 3250F ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Steam generator overfill A.1 Restore to OPERABLE 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months protection system status.

inoperable.

B.

Required Action and NOTE---------

associated Completion When initiated the Required Time not met.

Action must be completed.

B.1 Submit a written report 30 days to the NRC outlining the cause of the channel(s) or system(s) malfunction and the plans for restoring the channel(s) or system(s) to OPERABLE status.

16.7.5-1 11/15/12 I

Steam Generator Overfill Protection 16.7.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY

NOTE--------------

Not required to be performed if SR 16.7.5.2 has been met within the preceding 32 days.

SR 16.7.5.1 Perform Trip Test (SV6).

92 days SR 16.7.5.2 Perform Trip Test (SV12).

24 months SR 16.7.5.3 Perform CHANNEL FUNCTIONAL TEST.

24 months SR 16.7.5.4 Perform CHANNEL CALIBRATION.

24 months BASES BACKGROUND This commitment supports closure of Generic Letter 89-19 by providing limiting conditions for operation, actions, and surveillances for steam generator overfill protection.

APPLICABLE SAFETY ANALYSES Steam generator overfill protection (e.g., the high steam generator level feedwater pump trip) plays an important role in the mitigation of Main Feedwater (MFW) overfill events that could lead to Pressurized Thermal Shock (PTS). Studies have been performed by Duke, the B&W Owners Group, and Oak Ridge National Laboratory (ORNL) to assess the probability of vessel failure due to PTS events. The high level trip is credited in many of these studies to mitigate overfill transients; thus, the PTS results are highly dependent on the functioning of the high level trip.

However, the PTS sequences which lead to core melt contribute less than 1 % to the overall calculated core melt frequency.

16.7.5-2 11/15/12 1

Steam Generator Overfill Protection 16.7.5 APPLICABILITY The overfill protection system is required to be operable for RCS temperatures above 3250F to assure that an overcooling event due to steam generator overfill will not lead to pressurized thermal shock of the reactor vessel. For RCS temperatures < 3250F, the Low Temperature Overpressure Protection (LTOP) system provides protection against overpressure concerns.

COMMITMENT Steam generator overfill protection is provided through the ICS to terminate main feedwater when the high level setpoint is reached. Two transmitters per steam generator monitor steam generator water level. Protection is provided by 2 out of 2 logic on either steam generator which actuates two trip devices. The high level monitoring circuits deenergize to trip: thus a deenergized module is operable. Two trip devices (SV6 and SV12) are provided on each MFWPT. For example, 2 out of 2 logic on the "A" steam generator will actuate both trip devices-on both MFWPTs. Since either steam generator can cause an overcooling event, then the overfill protection logic for both steam generators are required to be operable for the overfill protection system to be considered operable.

This Commitment is modified by a Note that states portions of the steam generator overfill protection system may be inoperable when the associated MFWP is incapable of feeding the steam generators (e.g., when the pump is uncoupled, or the steam supply to its turbine is isolated).

ACTIONS The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months completion time in Required Action A.1 provides an adequate level of availability of the overfill protection system for performing its function while allowing reasonable time to permit necessary maintenance on the system.

SURVEILLANCE REQUIREMENTS SR 16.7.5.1 This surveillance verifies that the SV6 trip device will trip the associated MFWPT. SV6 is exercised by the "oil trip" test. When the oil trip is exercised, SV6 is energized thus tripping the overspeed governor which trips the mechanical trip mechanism of the MFWPT. This surveillance can be performed on line and is part of the secondary system protection test. The 92 day frequency for this Surveillance was determined to be adequate based on operating experience.

A Note was added to allow the SR to not be performed if SR 16.7.5.2 has been met within the preceding 32 days. This surveillance provides assurance that the MFWPT mechanical trip mechanism will work to protect against steam generator overfill. There is only one mechanical trip mechanism on the MFWPT, which may be actuated from two independent paths. The normal trip path is SV12 which will work at any speed or condition, and thus cannot be tested with the MFWPT in service. The alternate path is SV6 which operates the overspeed trip mechanism and will only operate when the MFWPT is above a certain minimum speed. This 16.7.5-3 11/15/12 I

Steam Generator Overfill Protection 16.7.5 SR 16.7.5.1 (continued) path may be tested only when the MFWPT is in service. This surveillance exercises the alternate path. Since the purpose of the trip test is to prove that the mechanical trip mechanism will work, SR 16.7.5.2 will suffice to establish operability during the small period between reset of the MFWPT and operation at normal speed, when this surveillance requirement can then be performed.

SR 16.7.5.2 This surveillance verifies that the SV12 trip device will trip the associated MFWPT. This Surveillance can only be performed when the MFWPT is out of service. The 24 month frequency for this Surveillance was determined to be adequate based on operating experience.

SR 16.7.5.3 This surveillance requires a CHANNEL FUNCTIONAL TEST which verifies a trip signal is provided in response to high steam generator level. The 24 month frequency for this Surveillance was determined to be adequate based on operating experience.

SR 16.7.5.4 This surveillance requires a CHANNEL CALIBRATION which verifies the channel responds to steam generator level with the necessary range and accuracy. This surveillance is also required by ITS SR 3.3.8-1 for Item 12. The 24 month frequency for this surveillance was determined to be adequate based on operating experience.

REFERENCES:

1.

Generic Letter 89-19, Request for Action Related to Resolution of Unresolved Safety Issue A-47 "Safety Implication of Control Systems in LWR Nuclear Power Plants."

2.

H. B. Tucker (Duke) to NRC Document Control Desk, Response to GL 89-19, March 19, 1990 16.7.5-4 11/15/12 1

Diverse Actuation Systems 16.7.6 16.7 INSTRUMENTATION 16.7.6 Diverse Actuation Systems COMMITMENT

a.

Two input channels and the actuation logic of the Diverse Low Pressure Injection Actuation System (DLPIAS) shall be functional.

b.

Two input channels and the actuation logic of the Diverse High Pressure Injection Actuation System (DHPIAS) shall be functional.

NOTE Not applicable on each Unit until after completion of the Reactor Protective System/Engineered Safeguards Protective System digital upgrade on the respective Unit.

APPLICABILITY:

MODE 1 and 2, MODE 3 and 4 when ESPS channels are required to be OPERABLE ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more required A.1 Restore DLPIAS to 7 days input channels OR functional status.

actuation logic of DLPIAS nonfunctional B.

One or more required B.1 Restore DHPIAS to 7 days input channels OR functional status.

actuation logic of DHPIAS nonfunctional.

(continued) 16.7.6-1 11/15/12 1

Diverse Actuation Systems 16.7.6 ACTION (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C.

Required Action and

NOTE associated Completion When initiated, the Required Time not met.

Action must be completed.

C.1 Submit a written report 30 days to the NRC outlining the cause of the channel(s) or system(s) malfunction and the plans for restoring the channel(s) or system(s) to functional status.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.7.6.1 Perform an input Channel Calibration of 24 months DLPIAS.

SR 16.7.6.2 Perform an input Channel Calibration of 24 months DHPIAS.

SR 16.7.6.3 Perform an Actuation Test of DLPIAS.

24 months SR 16.7.6.4 Perform an Actuation Test of DHPIAS.

24 months.

16.7.6-2 11/15/12 1

Diverse Actuation Systems 16.7.6 BASES The DLPIAS and DHPIAS are provided to mitigate the consequences of software common mode failure (SWCMF) coincident with selected Chapter 15 events as detailed in the Defense in Depth and Diversity (D3) analysis as submitted on March 20, 2003 (Reference 1) and approved by NRC letter dated January 28, 2010 (Reference 2). These events are beyond the design basis for the plant and are associated with a failure of the Engineered Safeguards Protective System (ESPS) to actuate LPI or HPI when required.

The DHPIAS provides automatic High Pressure Injection (HPI) in the case of the Small Break Loss of Coolant Accident (SBLOCA) concurrent with a SWCMF of the digital ESPS. The DHPIAS automatically actuates HPI and other ESPS Channel 1 and Channel 2 components on Low Reactor Coolant (RC) Pressure. Additionally, manual initiation can be accomplished using ESPS Trip/Reset pushbuttons located on the main control board. The trip circuit for the ESPS manual trip bypasses the ESPS logic and allows the operator to initiate Engineered Safeguards (ES) actuation on a per channel basis. The DHPIAS actuation setpoint (Reference 3) is set to initiate an HPI actuation after an ESPS initiated actuation of HPI. The DHPIAS consists of three redundant channels each receiving input from its own measurement channel. An input channel consists of an ESPS RCS pressure input signal, its bistable, and its associated bistable interposing trip relay and its contacts. Only two channels are required to be functional as defined by Reference 4. The DHPIAS trip circuit requires 2 bistables to be tripped for an HPI actuation to occur. Actuation circuit relays are energized to actuate which prevents a loss of 120VAC or 24VDC control power from resulting in an actuation. The actuation logic consists of all components in DHPIAS (other than the input channel components) required for an actuation signal satisfied by two tripped bistables to be provided to the ES Channel 1 and 2 output interposing relays. The Non-Safety Related Reactor Coolant pressure signals fed into the DHPIAS are isolated from the Safety-Related Reactor Coolant pressure signals utilizing signal isolators. The signal isolation occurs in the Safety-Related analog signal conditioning portion of the ESPS prior to the analog-to-digital conversion. The channel calibration surveillance requirement verifies proper calibration from the ESPS RCS pressure input signal to the DHPIAS bistables. The actuation test verifies the trip logic combinations and that a system trip signal is applied to the ES Channel 1 and 2 output interposing relays. DHPIAS is considered functional if it has met the surveillance requirements of this commitment, two input channels are functional, the DHPIAS Bypassed statalarm is not on, and the DHPIAS Override light (in the control room) is not on.

The DLPIAS provides automatic Low Pressure Injection (LPI) in the case of the Large Break Loss of Coolant Accident (LBLOCA) concurrent with a SWCMF of the digital ESPS. The DLPIAS automatically actuates LPI and other ESPS channel 3 and channel 4 components on Low-Low Reactor Coolant (RC) pressure. Additionally, manual initiation can be accomplished using ESPS Trip/Reset pushbuttons located on the main control board. The trip circuit for the ESPS manual trip bypasses the digital ESPS logic and allows the operator to initiate Engineered Safeguards (ES) actuation on a per channel basis. The DLPIAS actuation setpoint (Reference 3) is set to initiate an LPI actuation after an ESPS initiated actuation of LPI. The DLPIAS consists of three redundant channels each receiving input from its own measurement channel. An input channel consists of a bistable, its associated RCS pressure input signal, and its associated bistable interposing trip relay. Only two channels are required to be functional as defined by Reference 4. The DLPIAS trip circuit requires 2 bistables to be tripped for an LPI 16.7.6-3 11/15/12 1

Diverse Actuation Systems 16.7.6 actuation to occur. Actuation circuit relays are energized to actuate which prevents a loss of 120VAC or 24VDC control power from resulting in an actuation. The actuation logic consists of all components in DLPIAS (other than the input channel components) required for an actuation signal satisfied by two tripped bistables to be provided to the ES Channel 3 and 4 output interposing relays. The Non-Safety-Related Reactor Coolant pressure signals fed into the DLPIAS are isolated from the Safety-Related Reactor Coolant pressure signals utilizing signal isolators. The signal isolation occurs in the Safety-Related analog signal conditioning portion of the ESPS prior to the analog-to-digital conversion. The channel calibration surveillance requirement verifies proper calibration from the ESPS RCS pressure input signal to the DLPIAS bistables. The actuation test verifies the trip logic combinations and that a system trip signal is applied to the ES Channel 3 and 4 output interposing relays. DLPIAS is considered functional if it has met the surveillance requirements of this commitment, two input channels are functional, the DLPIAS Bypassed statalarm is not on, and the DLPIAS Override light (in the control room) is not on.

The DLPIAS allows acceptance criteria to be met for the D3 Analysis performed for the LBLOCA concurrent with a SWCMF of the digital ESPS. The DHPIAS eliminates the need to rely on operator action and allows acceptance criteria to be met for the SBLOCA concurrent with a SWCMF.

REFERENCES:

1. Duke letter to NRC dated March 20, 2003, Defense in Depth and Diversity Assessment Associated with the Digital Upgrade of Oconee's Reactor Protective System and Engineered Safeguards Protective System

2. NRC letter to Duke dated January 28, 2010, Safety Evaluation Report for Oconee RPS/ESPS Digital Upgrade.

3. Calculation OSC-8125, Diverse High/Low Pressure Injection Actuation System Loop Uncertainty and Setpoint.

4. NSD 203, Revision 23, Operability/Functionality.

16.7.6-4 11/15/12 I

Position Indicator Channel Testing 16.7.7 16.7 INSTRUMENTATION 16.7.7 Position Indicator Channel Testing COMMITMENT APPLICABILITY:

Perform specified SR.

MODES 1 and 2.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A.

A.1 N/A.

N/A SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.7.7.1 Perform CHANNEL CALIBRATION of the --

NOTE------

Absolute and Relative Position Indication The provisions of SLC Channels for each CONTROL ROD.

16.2.7 do not apply.

24 months +25%

BASES The requirement(s) of this SLC section were relocated from CTS Table 4.1-1, Item 23 and 24 during the conversion to ITS.

Calibration of the CONTROL ROD Absolute and Relative position indication channels supports OPERABILITY of the CONTROL ROD position indication channels required by ITS LCO 3.1.7 16.7.7-1 11/15/12 1

Position Indicator Channel Testing 16.

7.7 REFERENCES

1. ITS B 3.1.7

2. UFSAR, Section 7.6 16.7.7-2 11/15/12 I

CFT Instrumentation 16.7.10 16.7 INSTRUMENTATION 16.7.10 Core Flood Tank (CFT) Instrumentation COMMITMENT APPLICABILITY:

One level instrument channel and one pressure instrument channel shall be OPERABLE for each CFT.

MODES 1 and 2, MODE 3 with Reactor Coolant System (RCS) pressure

> 800 psig.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Commitment not met.

A.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months AND A.2 BE in MODE 5.

36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.7.10.1 Perform CHANNEL CHECK.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 16.7.10.2 Perform CHANNEL CALIBRATION.

NOTE -..........

The provisions of SLC 16.2.7 do not apply.

24 months +25%

16.7.10-1 11/15/12 1

CFT Instrumentation 16.7.10 BASES The requirement(s) of this SLC section were relocated from CTS 3.3.3 and Table 4.1-1, Item 25 during the conversion to ITS.

REFERENCES N/A 16.7.10-2 11/15/12 1

Display Instrumentation 16.7.11 16.7 INSTRUMENTATION 16.7.11 Display Instrumentation COMMITMENT APPLICABILITY:

Perform specified Surveillance Requirements for each Function in Table 16.7.11-1.

According to Table 16.7.11-1.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A.

A.1 N/A.

N/A SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.7.11.1 Perform CHANNEL CHECK.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months SR 16.7.11.2 Perform CHANNEL CHECK.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months SR 16.7.11.3 Perform CHANNEL CHECK.

31 days SR 16.7.11.4 N/A N/A SR 16.7.11.5 Perform functional test.

31 days (continued) 16.7.11-1 11/15/12 I

Display Instrumentation 16.7.11 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 16.7.11.6 Perform CHANNEL CALIBRATION.

12 months SR 16.7.11.7 Perform CHANNEL CALIBRATION.

NOTE------

The provisions of SLC 16.2.7 do not apply.

24 months +25%

BASES The requirement(s) of this SLC section were relocated from CTS Table 4.1-1, Items 22, 27, 32, 33, 36, 38, 40, and 50 during the conversion to ITS.

REFERENCES N/A 16.7.11-2 11/15/12 1

Display Instrumentation 16.7.11 Table 16.7.11-1 (page 1 of 1)

Display Instrumentation Function APPLICABLE MODES SURVEILLANCE OR OTHER SPECIFIED REQUIREMENTS CONDITIONS

1. Pressurizer temperature 1,2,3 SR 16.7.11.1 SR 16.7.11.7

2. Letdown storage tank level 1,2,3 SR 16.7.11.2 SR 16.7.11.7

3. CBAST Level 1,2,3 SR 16.7.11.6

4. CBAST Temperature 1,2,3 SR 16.7.11.3 SR 16.7.11.6

5. Containment Temperature 1,2,3 SR 16.7.11.7

6. Environmental Monitors At all times SR 16.7.11.5 SR 16.7.11.7

7. Reactor Building Emergency Sump Level 1,2,3 SR 16.7.11.7

8. Turbine Overspeed Trip 1,2,3 SR 16.7.11.7

9. PORV Position 1,2,3 SR 16.7.11.3 SR 16.7.11.7

10. Primary System Safety Relief Valve Position 1,2,3 SR 16.7.11.3 SR 16.7.11.7 16.7.11-3 11/15/12 I

SSF Instrumentation 16.7.13 16.7 INSTRUMENTATION 16.7.13 SSF Instrumentation COMMITMENT Perform specified Surveillance Requirements for each Function in Table 16.7.13-1.

APPLICABILITY:

MODES 1, 2 and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A.

A.1 N/A.

N/A SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.7.13.1

NOTE This Surveillance shall be performed when the associated pump is operated during IST.

Perform CHANNEL CHECK.

92 days SR 16.7.13.2 Perform CHANNEL CALIBRATION.

12 months SR 16.7.13.3 Perform CHANNEL CALIBRATION.

.NOTE The provisions of SLC 16.2.7 do not apply.

24 months +25%

(continued) 16.7.13-1 11/15/12 1

SSF Instrumentation 16.7.13 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 16.7.13.4 Perform CHANNEL CALIBRATION.

24 months BASES The requirement(s) of this SLC section were relocated from Technical Specification Table 4.20-1, Items 2, 5, 7 and 8 during the conversion to Improved Technical Specifications.

The surveillance requirements for the SSF Instrumentation are based on experience in operation of both conventional and nuclear systems. The minimum checking frequency stated is deemed adequate for SSF Instrumentation. Calibration is performed to assure the presentation and acquisition of accurate information. Process system instrumentation errors induced by drift can be expected to remain within acceptable tolerances if recalibration is performed at the intervals specified.

REFERENCES N/A 16.7.13-2 11/15/12 I

SSF Instrumentation 16.7.13 Table 16.7.13-1 (page 1 of 1)

SSF Instrumentation Function

1. SSF RC Makeup Pump Suction Pressure

2. SSF RC Makeup Pump Discharge Pressure

3. SSF RC Makeup Pump.Suction Temperature

4. SSF RC Makeup Pump Discharge Flow

5. SSF Auxiliary Service Water Pump Suction Pressure

6. SSF Auxiliary Service Water Pump Discharge Pressure

7. SSF Auxiliary Service Water Pump Unit 1 Flow

8. SSF Auxiliary Service Water Pump Unit 2 Flow

9. SSF Auxiliary Service Water Pump Unit 3 Flow

10. SSF Auxiliary Service Water Pump Discharge Test Flow

11. SSF Auxiliary Service Water Pump Suction Temperature

12. Underground Fuel Oil Storage Tank Inventory

13. DIG Service Water Pump Discharge Flow

14. D/G Service Water Pump Discharge Pressure SURVEILLANCE REQUIREMENTS SR 16.7.13.1 SR 16.7.13.3 SR 16.7.13.1 SR 16.7.13.3 SR 16.7.13.1 SR 16.7.13.3 SR 16.7.13.1 SR 16.7.13.3 SR 16.7.13.1 SR 16.7.13.2 SR 16.7.13.1 SR 16.7.13.2 SR 16.7.13.4 SR 16.7.13.4 SR 1.6.7.13.4 SR 16.7.13.1 SR 16.7.13.4 SIR 16.7.13.1 SR 16.7.13.2 SR 16.7.13.4 SR 16.7.13.1 SIR 16.7.13.4 SR 16.7.13.1 SR 16.7.13.4 16.7.13-3 11/15/12 1

Rod Withdrawal Limit Alarm 16.7.14 16.7 INSTRUMENTATION 16.7.14 Rod Withdrawal Limit Alarm COMMITMENT APPLICABILITY:

One Rod Withdrawal Limit Alarm shall be OPERABLE.

MODE 1 when Regulating Rods are in Automatic Control ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Rod Withdrawal Limit A.1 Verify regulating rod 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Alarm inoperable, groups meet the position limits as AND specified in the COLR.

Once per 30 minutes thereafter AND A.2 Limit Makeup flow to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months

< 110 gpm AND A.3 Limit Letdown flow to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months

< 110 gpm B.

Makeup or Letdown B.1 Verify regulating rod 15 minutes flow not limited to < 110 groups meet the position gpm as required by limits as specified in the Actions A.2 and A.3 COLR above AND Once per 15 minutes thereafter 16.7.14-1 11/15/12 I

Rod Withdrawal Limit Alarm 16.7.14 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.7.14.1 Verify ROD Withdrawal limit alarm values are 24 months established consistent with the COLR.

16.7.14-2 11/15/12 1

Rod Withdrawal Limit Alarm 16.7.14 BASES BACKGROUND The Rod Withdrawal Limit Alarm is relied upon to alert the operator of a sudden boron dilution event. The alarm is provided by the OAC. Whenever the computer is out of service, a manual surveillance of the regulating rod position is required at 30 minute intervals to ensure a dilution event is not occurring.

APPLICABLE SAFETY ANALYSES The Moderator Dilution Accident is analyzed in Reference 1. The analysis for when the reactor is in MODE 1, with the CONTROL RODS in automatic, relies on the Rod Withdrawal Limit Alarm to alert the operators that a dilution event is in progress. The operators then have 15 minutes to stop the dilution.

No other moderator dilution scenario analyzed in Reference 1 relies on this alarm function. The consequence of diluting the CONTROL RODS beyond the withdrawal limit is the possible loss of SHUTDOWN MARGIN in the event of a reactor trip.

The alarm requires that the OAC be operable. If the OAC is operable, the alarm is considered operable. This is valid based on the low probability of losing the alarm function itself without losing any other sub-system of the OAC thus rendering the OAC itself inoperable.

The time available to the operator to stop the dilution following receipt of the alarm is dependent on the dilution flow rate, the boron concentration of the dilution source, and the available SHUTDOWN MARGIN following reactor trip. The worst combination of these is assumed in the Reference 1 analysis.

If the Alarm is unavailable, then the potential dilution flowrates are controlled such that there exists 30 minutes before operator action is required to mitigate the event.

COMMITMENT This Commitment provides controls to ensure that the rod withdrawal limit alarm is OPERABLE. The rod withdrawal limit alarm is credited for mitigating a boron dilution event in MODE 1 with the CONTROL RODS in automatic control.

APPLICABILITY In MODE 1 when Regulating Rods are in Automatic Control.

In MODES 2, 3, 4, 5 and 6 the regulating rods are not credited.

16.7.14-3 11/15/12 1

ACTIONS A.1 When the rod withdrawal limit alarm is inoperable, regulating rod groups shall be verified to meet the position limits as specified in the COLR within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of losing the alarm and once every 30 minutes thereafter.

This Action allows the operators 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months before the first rod position surveillance is performed. This is judged acceptable given the low probability that a dilution event is in progress immediately following the loss of OAC, the time required to enter the procedure and perform the higher priority functions first, and the fact that the rod positions are verified frequently while the OAC is available. After the first 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , the rod positions shall be verified manually once per 30 minutes to prevent the loss of shutdown margin while a dilution event is in progress. With administrative controls in place to limit the dilution flow rate to less than 110 gpm, 30 minutes is the allowable time to recognize that a dilution event is in progress and allow the operators 15 minutes to stop the dilution event.

A.2 This action places administrative controls on makeup flow within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months following the entrance to the loss of OAC procedure to ensure a dilution rate cannot exceed 110 gpm.

A.3 This action places administrative controls on letdown flow within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months following the entrance to the loss of OAC procedure to ensure a dilution rate cannot exceed 110 gpm.

B. 1 This action requires the rod positions be verified once per 15 minutes to prevent the loss of shutdown margin whenever a dilution event of > 110 gpm is possible. It is applicable whenever makeup and letdown flows are not limited to less than 110 gpm SURVEILLANCE SR 16.7.14.1 REQUIREMENTS This SR requires verification that the ROD Withdrawal limit alarm values are established consistent with the COLR.

REFERENCES

1.

UFSAR, Section 15.4 16.7.14-4 11/15/12 I

Sprinkler and Spray Systems 16.9.2 16,9 AUXILIARY SYSTEMS 16,9.2 Sprinkler and Spray Systems COMMITMENT APPLICABILITY:

Sprinkler and Spray Systems in safety related areas listed in Table 16.9.2-1 shall be OPERABLE.

At all times.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more required A.1 Establish continuous fire 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Sprinkler or Spray watch with backup fire Systems inoperable, suppression equipment in the area.

AND Affected Area(s) has no OPERABLE fire detection.

B.

One or more required B.1 Establish hourly fire 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Sprinkler or Spray watch with backup fire Systems inoperable, suppression equipment in the area.

AND Affected Area(s) has OPERABLE fire detection.

16.9.2-1 11/15/12 1

Sprinkler and Spray Systems 16.9.2 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.9.2.1

NOTE -

Not required to be performed for systems in the cable spreading room, equipment rooms and cable shafts.

Functionally test each required Sprinkler or Spray System.

NOTE------

The required frequency for CT 1, 2, 3, & Keowee equipment is 18 months 24 months SR 16.9.2.2 Inspect each required Sprinkler System's spray headers and nozzles.

NOTE ------------

The required frequency for CT 1, 2, 3, & Keowee equipment is 18 months 24 months SR 16.9.2.3 Verify by visual inspection _< 4 nozzles are

NOTE blocked, clogged, or misdirected.

The required frequency for CT 1, 2, 3, & Keowee equipment is 18 months 24 months SR 16.9.2.4 Verify by visual inspection that no two

-NOTE.

inoperable nozzles are adjacent or on the The required frequency same exposed face.

for CT 1, 2, 3, & Keowee equipment is 18 months 24 months 16.9.2-2 11/15/12 1

Sprinkler and Spray Systems 16.9.2 Table 16.9.2-1 Sprinkler and Spray Systems

a. Oconee Nuclear Station

i.

Turbine Driven Emergency FDW Pump ii.

Transformers',2 iii.

Cable Room iv.

Equipment Room

v.

Cable Shaft (3rd Level) vi.

Cable Shaft (4th & 5th Level)

b. Keowee Hydro Station

i.

Main Lube Oil Storage Room ii.

Main Transformer Units 1, 2, and 3 CT-I, CT-2, CT-3, CT-4, and CT-5 Units 1, 2, and 3 Units 1, 2, and 3 Units 1, 2, and 3 Units 1, 2, and 3

1.

Transformers CT-1, CT-2, CT-3 and CT-5 do not have fire detection devices. They have Activation devices that actuate the deluge valve of the fire suppression systems only.

2.

Transformer CT-4 Blockhouse does have fire detection instrumentation. Reference SLC 16.9.6.

16.9.2-3 11/15/12 I

Sprinkler and Spray Systems 16.9.2 BASES The OPERABILITY of the NRC committed Fire Suppression System ensures that adequate fire suppression capability is available to confine and extinguish fires occurring at the Oconee or Keowee facilities. The regulatory requirement is to have NRC committed Sprinkler and Spray Systems OPERABLE only when the equipment it is protecting is required OPERABLE for plant safety. However, to protect the equipment for property conservation and minimize equipment loss due to fire; the Oconee and Keowee NRC committed Sprinkler and Spray Systems will be required to be OPERABLE at all times.

The Oconee CT-1, 2, 3, and 5 transformers do not have fire detection devices. They have fire actuation devices that actuate the deluge valve of the fire suppression systems. These actuation devices do not directly annunciate to the Control Rooms. When the deluge valve trips, the flow pressure switch is the sensor that activates the Control Room alarms. With HPSW deactivated for maintenance or testing, there is no form of annunciation of a fire in the Control Room. Transformer CT-4 Blockhouse does have fire detection instrumentation.

In fire protection, the design intent is to ensure that all potential fire surface areas are covered by a water spray pattern. However, equipment protected by the sprinkler systems has irregular surfaces and it is not intended that every convolution in the surface be wetted during the test to demonstrate operability. Since some overlap is provided among the sprinkler nozzle placement, it is acceptable/possible for a sprinkler head(s) to be clogged and the sprinkler spray system to still effectively put out a fire. In addition, a blocked sprinkler head increases the system's residual pressure, thereby, allowing increased water flow from the existing free flow nozzles which effectively delivers to the fire the same total water flow discharge. The fire suppression system provides a cloud-like shroud of water around the equipment/area being protected to ensure that spray controls the flames from reaching any other vital equipment and helps to mitigate/control the fire at the point of origin.

During periods of time when the Sprinkler or Spray System is not OPERABLE and detection instrumentation is OPERABLE, a hourly fire watch patrol will be required to inspect the affected area frequently as a precaution. If the Sprinkler or Spray System in the area is not OPERABLE and no detection instrumentation is OPERABLE, a continuous fire watch is required to be maintained in the vicinity of the affected Sprinkler or Spray System until the system is restored to OPERABLE status.

In the event that portions of the Fire Suppression Systems are inoperable, alternate backup fire-fighting equipment is required to be made available in the affected areas until the inoperable equipment is restored to service.

The test requirements provide assurance that the minimum OPERABILITY requirements of the Fire Suppression Systems are met.

This Selected Licensee Commitment is part of the Oconee Fire Protection Program and therefore subject to the provisions of Oconee Facility Operating License conditions.

16.9.2-4 11/15/12 1

Sprinkler and Spray Systems 16.

9.2 REFERENCES

1. Oconee UFSAR, Chapter 9, Section 9.5.1 and UFSAR, Chapter 18, Table 18-1 (Portions of this SLC are credited in the Fire Protection Program for License Renewal).

2. Oconee License Renewal Commitments, OSS-0274.00-00-0016.

3. Oconee Fire Protection SER dated August 11, 1978.

4. Oconee Fire Protection Review, (currently contained in the Fire Protection DBD), as revised.

5. Oconee Plant Design Basis Specification for Fire Protection, as revised.

16.9.2-5 11/15/12 I

Keowee CO 2 Systems 16.9.3 16.9 AUXILIARY SYSTEMS 16.9.3 Keowee CO 2 Systems COMMITMENT APPLICABILITY:

The automatic CO 2 system provided for the generators at Keowee Hydro Station shall be OPERABLE.

At all times.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Keowee CO 2 System A.1 Establish continuous fire 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable and watch with backup fire associated KHU suppression equipment in OPERABLE.

the area.

B.

Keowee CO 2 System B.1 Establish backup fire 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable and suppression equipment in associated KHU the area.

inoperable.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.9.3.1 Verify each valve in the flow path is in its 31 days correct position.

SR 16.9.3.2 Verify CO 2 storage tank weight is _> 90% full 184 days charge weight.

SR 16.9.3.3 Verify system actuates manually and 24 months automatically upon receipt of a simulated action signal.

16.9.3-1 11/15/12 1

Keowee C02 Systems 16.9.3 SURVEILLANCE FREQUENCY SR 16.9.3.4 Perform flow test through headers and 24 months nozzles to assure no blockage.

BASES The OPERABILITY of the NRC committed Keowee C02 Fire Suppression system ensures that adequate fire suppression capability is available to protect safety-related equipment by confining and extinguishing fires occurring in the Keowee electric generators. The regulatory requirement is to have the Keowee CO 2 Fire Suppression System OPERABLE only when the equipment it is protecting is required OPERABLE for plant safety, however to also protect the equipment for property conservation and minimize equipment loss due to a fire; the Keowee C02 Fire Suppression System will be required OPERABLE at all times.

The Fire Suppression System consists of the water system, spray and/or sprinklers, Keowee CO 2 system and fire hose stations. 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.

In the event that portions of the Fire Suppression Systems are inoperable, alternate backup fire-fighting equipment is required to be made available in the affected areas until the inoperable equipment is restored to service. The Testing Requirements provide assurance that the minimum OPERABILITY requirements of the Fire Suppression Systems are met.

This Selected Licensee Commitment is part of the Oconee Fire Protection Program and therefore subject to the provisions of Oconee Facility Operating License Conditions.

The Keowee C02 Fire Suppression System initiates an emergency lockout of the Keowee generator upon detection of fire. Surveillance of this risk significant Maintenance Rule function is accomplished by SR 16.9.3.3.

REFERENCES:

1. Oconee UFSAR, Chapter 9.5-1.

2. Oconee Fire Protection SER dated August 11, 1978.

3. Oconee Fire Protection Review, (currently contained in the Fire Protection DBD), as revised.

4. Oconee Plant Design Basis Specification for Fire Protection, as revised.

5. 10 CFR 50.65, "Maintenance Rule."

6. PIP 02-4679, Assess Adequacy of Administrative Controls for Risk Significant Equipment.

16.9.3-2 11/15/12 1

Fire Hose Stations 16.9.4 16.9 AUXILIARY SYSTEMS 16.9.4 Fire Hose Stations COMMITMENT APPLICABILITY:

The Fire Hose Stations listed in Table 16.9.4-1 shall be OPERABLE.

At all times.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Required Fire Hose A.1 Provide additional 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Station outside reactor equivalent capacity fire building inoperable, hose of length to reach unprotected area at OPERABLE hose station.

B.

Required Fire Hose B.1 Ensure availability of 4 NA Station inside reactor portable fire extinguishers building inoperable outside the reactor building (water not available to in the personnel air lock isolation valves LPSW-area of the auxiliary building 563 and LPSW-564).

for fire brigade use upon entering reactor building.

16.9.4-1 11/15/12 I

Fire Hose Stations 16.9.4 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.9.4.1 Perform visual inspection, including inspection 31 days of coupling gaskets, of the fire hose stations located outside the reactor building and inside reactor building that are accessible during power operation.

SR 16.9.4.2 Perform visual inspection, including inspection 24 months of coupling gaskets, of reactor building fire hose stations that are inaccessible during power operation.

SR 16.9.4.3 Partially stroke test Fire Hose Station Valves.

36 months SR 16.9.4.4 Subject each fire hose to hydrostatic test at 36 months pressure _> 50 psig greater than the maximum pressure at the station.

SR 16.9.4.5 Perform maintenance inspection including 36 months removal and reracking the hoses and inspection of coupling gaskets.

16.9.4-2 11/15/12 1

Fire Hose Stations 16.9.4 Table 16.9.4-1 Fire Hose Stations

a. Oconee Nuclear Station Location No.

Valve No.

Area or Component Protected 3-D-28 2HPSW-194 1 &2 Blockhouse, 1 & 2 3rd Floor Switchgear AX-35 1 HPSW-436

1 Cable Spread Room AX-32 2HPSW-436

2 Cable Spread Room AX-33 2HPSW-437 1 & 2 Cable Spread Room AX-30 3HPSW-436

3 Cable Spread Room AX-31 3HPSW-437

3 Cable Spread Room 5-M-31 2HPSW-304 1 & 2 Control Room, I & 2 Emergency Shutdown Panels TOH-3 3HPSW-338

3 Control Room, #3 Emergency Shutdown Panels 1-J-28 2HPSW-242

1 First Floor MCCs HPSW Pumps, 1 & 2 LPSW Pumps 1-J-43 3HPSW-344

3 1 st Floor Motor Control Centers 1--B-19 1HPSW-283

1 EFWP 1-D-39 2HPSW-236

2 EFWP 1-D-53 3HPSW-336

3 EFWP AX-1 3 1 HPSW-448 1 & 2 HPI Pumps, 1 & 2 LPI Pumps AX-14 3HPSW-449 3 HPI Pumps, 3 LPI Pumps 1-J-47 3HPSW-348 3 LPSW Pumps AX-36 1 HPSW-445

1 West Penetration Room AX-45 1 HPSW-444

1 East Penetration Room AX-42 2HPSW-444

2 East Penetration Room AX-43 2HPSW-445

2 West Penetration Room AX-29 3HPSW-444

3 East Penetration Room AX-44 3HPSW-445

3 West Penetration Room AX-21 HPSW-457 1 & 2 Equipment Room AX-19 3HPSW-458 3 Equipment Room 3-M-24 HPSW-176 1 Equipment Room 3-M-29 2HPSW-245 2 Equipment Room 3-M-43 3HPSW-339 3 Equipment Room 3-J-28 2HPSW-241 1 & 2 3rd Floor Switchgear 3-M-43 3HPSW-339 3 3rd Floor Switchgear, 600V Load Center AX-22 1 HPSW-440 1 Battery Room AX-20 2HPSW-440 2 Battery Room AX-18 3HPSW-440 3 Battery Room 1RBH1 1 LPSW-471 Ground Floor Level - East Side 2RBH1 2LPSW-471 Basement Floor Level - East Side 3RBH1 3LPSW-471 Basement - East side 1 RBH2 1 LPSW-473 Intermediate Floor Level - East Side 2RBH2 2LPSW-473 Intermediate Floor Level - East Side 3RBH2 3LPSW-473 Intermediate Floor Level - East Side 1 RBH3 1 LPSW-475 Top of Shielding Floor Level - East Side 2RBH3 2LPSW-475 Top of Shielding Floor Level - East Side 3RBH3 3LPSW-475 Top of Shielding Floor Level - East Side 1 RBH4 1 LPSW-465 Top of Shielding Floor Level - West Side 2RBH4 2LPSW-465 Top of Shielding Floor Level - West Side 3RBH4 3LPSW-465 Top of Shielding Floor Level - West Side 1 RBH5 1 LPSW-467 Intermediate Floor Level - West Side 16.9.4-3 11/15/12 I

Fire Hose Stations 16.9.4 Table 16.9.4-1 Fire Hose Stations Location No.

Valve No.

Area or Component Protected 2RBH5 2LPSW-467 Intermediate Floor Level - West Side 3RBH5 3LPSW-467 Intermediate Floor Level - West Side 1 RBH6 1 LPSW-469 Ground Floor Level - West Side 2RBH6 2LPSW-469 Basement Floor Level - West Side 3RBH6 3LPSW-469 Basement - West Side VBH-1 HPSW-916 Essential Siphon Vacuum Building VBH-2 HPSW-917 Essential Siphon Vacuum Building Basement EL. 777' 6" Ground EL. 797' 6" Intermediate EL. 825' 0" Top of Shielding EL. 861' 0"

b. Keowee Hydro Station Location No.

Valve No.

Area or Component Protected Operating Deck (NW)

KH-1 Operating Floor Operating Deck (NE)

KH-2 Operating Floor Operating Deck (SW)

KH-4 Operating Floor Operating Deck (SE)

KH-3 Operating Floor Control Room KH-6 Control Room Mech. Equip. Gallery KH-5 Mech. Equip. Gallery 16.9.4-4 11/15/12 1

Fire Hose Stations 16.9.4 BASES The OPERABILITY of the NRC committed Fire Suppression System ensures that adequate fire suppression capability is available to confine and extinguish fires occurring at the Oconee or Keowee facilities. The regulatory requirement is to have NRC committed Fire Hose Stations OPERABLE only when the equipment it is protecting is required OPERABLE for plant safety.

However, to protect the equipment for property conservation and minimize equipment loss due to fire; the Oconee and Keowee NRC committed Fire Hose Stations will be required to be OPERABLE at all times.

In the event that portions of the Fire Suppression Systems are inoperable, alternate backup fire-fighting equipment is required to be made available for the affected areas until the inoperable equipment is restored to service.

The testing requirements provide assurance that the minimum OPERABILITY requirements of the Fire Suppression System are met.

This Selected Licensee Commitment is part of the Oconee Fire Protection Program and therefore subject to the provisions of Oconee Facility Operating License Conditions.

REFERENCES:

1. Oconee UFSAR, Chapter 9, Section 9.5.1 and UFSAR, Chapter 18, Table 18-1 (Portions of this SLC are credited in the Fire Protection Program for License Renewal).

2. Oconee License Renewal Commitments, OSS-0274.00-00-0016.

3. Oconee Fire Protection SER dated August 11, 1978.

4. Oconee Fire Protection Review, (currently contained in the Fire Protection DBD), as revised.

5. Oconee Plant Design Basis Specification for Fire Protection, as required.

16.9.4-5 11/15/12 I

Fire Barriers 16.9.5 16.9 AUXILIARY SYSTEMS 16.9.5 Fire Barriers COMMITMENT APPLICABILITY:

All Fire Barriers (including mechanical and electrical penetrations, fire doors, fire dampers, walls, ceilings and floors) boundaries, as shown on the 0-31 0-K and O-310-L series drawings, shall be OPERABLE.

At all times ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Required Fire Barrier A.1 Determine OPERABILITY 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable, status of fire detection instrumentation for the AND affected area(s).

There is OPERABLE AND fire detection instrumentation within A.2 Establish an hourly fire 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 15 feet on both sides of watch patrol on at least the fire barrier one side of the fire boundary inoperability boundary.

location.

B.

Required Fire Barrier B.1 Determine OPERABILITY 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable, status of fire detection instrumentation for the AND affected area(s).

Affected Area(s) has AND OPERABLE fire detection B.2 Establish hourly fire watch 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months instrumentation within patrol in the area that does 15 feet on only one side not have OPERABLE fire of the fire barrier detection instrumentation.

boundary inoperability location.

16.9.5-1 11/15/12 I

Fire Barriers 16.9.5 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C. Required Fire Barrier C.1 Establish continuous fire 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months inoperable, watch on one side of affected penetration fire AND barrier.

Affected Area(s) has no OPERABLE fire detection instrumentation within 15 feet.

16.9.5-2 11/15/12 I

Fire Barriers 16.9.5 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.9.5.1 Visually inspect exposed surfaces of each fire 24 months rated barrier except fire doors.

SR 16.9.5.2 Visually inspect at least 10% of all fire 24 months dampers. If apparent changes in appearance or abnormal degradation is found, a visual inspection of an additional 10% of the dampers shall be made. This inspection process shall continue until a 10% sample with no apparent changes in appearance or abnormal degradation is found. Samples shall be selected such that each fire damper will be inspected every 15 years.

SR 16.9.5.3 Visually inspect at least 10% of each type of 24 months sealed penetration. If apparent changes in appearance or abnormal degradations are found, a visual inspection of an additional 10% of each type of sealed penetration shall be made. This inspection process shall continue until a 10% sample with no apparent changes in appearance or abnormal degradation is found. Samples shall be selected such that each penetration seal will be inspected every 15 years.

SR 16.9.5.4 Visually inspect and functionally test fire doors 2 months in Units 1, 2, and 3 as identified in the implementing procedure.

16.9.5-3 11/15/12 1

Fire Barriers 16.9.5 BASES The functional integrity of the penetration fire barriers (including mechanical and electrical penetrations, fire doors, fire dampers, walls, and floors) ensures that fires will be confined or adequately retarded from spreading to adjacent portions of the facility. This design feature minimizes the possibility of a single fire rapidly involving several areas of the facility prior to detection and extinguishment. The penetration fire barriers are a passive element in the facility fire protection program and are subject to periodic inspections and sampling.

The OPERABILITY of a NRC committed fire barrier ensures that fires will be confined or adequately retarded from spreading to adjacent portions of the facility. The regulatory requirement is to have NRC committed Fire Barriers OPERABLE only when the equipment it is protecting is required OPERABLE for plant safety. However, to also protect the equipment for property conservation and minimize equipment loss due to fire; the Oconee and Keowee NRC committed Fire Barriers will be required to be OPERABLE at all times.

During periods of time when a barrier is not functional, a fire watch patrol will be required to inspect the affected area frequently as a precaution in addition to the fire detection instrumentation in the area. If fire detection instrumentation in the area is not operable, a continuous fire watch is required to be maintained in the vicinity of the affected barrier until the barrier is restored to functional status. Fire detection is not specifically designed at ONS to provide early detection of fire near the committed fire boundaries as denoted on the drawing series 0-310K and O-310L. Fire detection instrumentation design locations were typically based on protecting specific equipment and areas important to safety or where major fire hazards were located and not to provide full detection coverage for all areas of the plant. In actuality fire detection instrumentation's ability to quickly respond to the incipient stages of a fire are based on distance from the hazard, type of hazard, obstruction, and air flows in the area.

The application of the specific fire detection instrumentation used at ONS provide a adequate response time for a floor distance of approximately 15 feet in radius from the detector location.

This Selected Licensee Commitment is part of the Oconee Fire Protection Program and therefore subject to the provisions of Oconee Facility Operating License Conditions.

REFERENCES:

1.

Oconee UFSAR, Chapter 9, Section 9.5.1 and UFSAR, Chapter 18, Table 18-1 (Portions of this SLC are credited in the Fire Protection Program for License Renewal).

2.

Oconee License Renewal Commitments, OSS-0274.00-00-0016.

3.

Oconee Fire Protection SER dated August 11, 1978.

4.

Oconee Fire Protection Review, (currently contained in the Fire Protection DBD), as revised.

5.

Oconee Plant Design Basis Specification for Fire Protection, as revised.

6.

NUREG-1723, Safety Evaluation Report Related to the License Renewal of Oconee Nuclear Station, Units 1, 2, and 3 dated March 1, 2000.

16.9.5-4 11/15/12 1

Fire Detection Instrumentation 16.9.6 16.9 AUXILIARY SYSTEMS 16.9.6 Fire Detection Instrumentation COMMITMENT The provided Fire Detection Instrumentation for each equipment/location shall be OPERABLE as listed in Table 16.9.6-1.

-NOTE Fire Detection Instrumentation located within containment is not required to be OPERABLE during the performance of Type A Containment Leakage Rate Tests.

APPLICABILITY:

At all times.

16.9.6-1 11/15/12 I

Fire Detection Instrumentation 16.9.6 ACTIONS Nn OPERABILITY of fire detection instrumentation for adequate equipment/location coverage may also be determined by the Site Fire Protection Engineer or designee.

CONDITION REQUIRED ACTION COMPLETION TIME A.

> 50% of required A.1 ----------

NOTE-------

detectors for one or An hourly firewatch is not more Oconee required for inaccessible equipment/location equipment/locations such inoperable, as the Reactor Building at power operation. Periodic OR inspections using a TV camera (if available) are 2 required adjacent permitted as described in detectors for one or Site Directives, or, the more Oconee inaccessible equipment equipment/location condition may be inoperable, monitored by remote indications which would provide early warning of a fire.

Establish hourly fire watch 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months patrol (or as permitted by Site Directives) to inspect the accessible area with the inoperable instrumentation.

16.9.6-2 11/15/12 1

Fire Detection Instrumentation 16.9.6 ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B.

> 50% of required B.1 Establish hourly fire watch 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months detectors for one or patrol to inspect the more Keowee accessible area with the equipment/location inoperable inoperable, instrumentation.

OR 2 required adjacent detectors for one or more Keowee equipment/location inoperable.

16.9.6-3 11/15/12 1

Fire Detection Instrumentation 16.9.6 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.9.6.1 Perform CHANNEL FUNCTIONAL TEST of 31 days Oconee Fire Detection Instruments using Fire Detection Instrumentation Control Board Panel Test Switch.

SR 16.9.6.2 Visually inspect Oconee Fire Detection 184 days Instruments accessible during power operation.

SR 16.9.6.3 Visually inspect Keowee Fire Detection 184 days Instruments.

SR 16.9.6.4 Test each Oconee fire detector for sensitivity.

12 months SR 16.9.6.5 Perform CHANNEL FUNCTIONAL TEST of 12 months Keowee Fire Detection Instruments.

SR 16.9.6.6

NOTE Not required to be performed for Keowee Generator Detectors.

Test each Keowee fire detector for sensitivity.

12 months SR 16.9.6.7 Visually inspect Oconee Fire Detection 24 months Instruments not accessible during power operation.

16.9.6-4 11/15/12 1

Fire Detection Instrumentation 16.9.6 Table 16.9.6-1 FIRE DETECTION INSTRUMENTATION OCONEE NUCLEAR STATION Units 1 2. and 3 Reactor Buildings Equipment Detectors Provided Reactor Building Penetrations 8 (each unit)

Reactor Building Cooling Units 6 (each unit)

Reactor Coolant Pumps 8 (each unit)

Units 1. 2. and 3 Auxiliary Building EL. 822' +0 Room No.

Equipment Detectors Provided 71-Q Unit 1 Cable Shaft 2

510 Unit 1 and 2 Control Room 25 75-Q Unit 2 Cable Shaft 2

552 Unit 3 Control Room 8

90-Q Unit 3 Cable Shaft 2

EL. 809' + 3" Room No.

Equipment Detectors Provided 400 Unit 1 Control Battery Room 5

402 Unit 1 East Penetration Room 12 403 Unit 1 Cable Room and Cable Shaft 19 404 Unit 2 Cable Room and Cable Shaft 18 405 Unit 2 Cable Room Closet 1

407 Unit 2 East Penetration Room 20 408 Unit 2 Control Battery Room 5

409 Unit 1 West Penetration Room 5

410 Unit 2 West Penetration Room 5

450 Unit 3 Cable Room 28 452 Unit 3 East Penetration Room 10 455 Unit 3 Ventilation Equipment 2

456 Unit 3 West Penetration Room 5

458 Unit 3 Control Battery Room 2

16.9.6-5 11/15/12 I

Fire Detection Instrumentation 16.9.6 Table 16.9.6-1 FIRE DETECTION INSTRUMENTATION EL. 796' +6" Room No.

Equipment Detectors Provided 300 Unit 1 Work Area 9

310 Unit 1 Equipment Room and Cable Shaft 13 311 Unit 2 Equipment Room and Cable Shaft 15 313 Janitor's Closet (Unit 1) 1 314 Clean Protective Clothing Storage (Unit 1) 1 322 Protective Clothes Storage (Unit 2) 1 329 Hot Lab 1

330 Cold Lab 1

331 Counting Room (Unit 2) 1 333 Health Physics (Unit 2) 1 334 Office (Unit 2) 1 335 Environmental Lab (Unit 2) 1 337 Laundry Sorting (Unit 2) 1 338 Laundry Storage (Unit 2) 1 339 Laundry (Unit 2) 2 347 Work Area (Unit 2) 8 354 Unit 3 Equipment Room and Cable Shaft 21 357 Janitor's Storage (Unit 3) 1 364 Towel Storage (Unit 3) 1 365 Janitor's Storage (Unit 3) 1 366 Protective Clothing (Unit 3) 1 369 HP Office (Unit 3) 1 369A Supv. Technicians Office 1

369B Secondary Chemistry Lab 1

369C I.C. Computer 1

376 Unit 3 Work Area 10 EL. 771' + 0 Room No.

Equipment Detectors Provided 117 Gas Analyzer Panel 1

119 Unit 1 and 2 LPI Hatch Area 4

159 Unit 3 LPI Hatch Area 2

EL. 838"+0 Room No.

Equipment Detectors Provided 611 Protective Clothing Storage (Unit 2) 1 658 Protective Clothing Storage (Unit 3) 1 EL. 783' + 9" Room Equipment Detectors Provided 204 Storage (Unit 1) 1 207 Chemical Handling and Storage (Unit 1) 1 220 Hot Instrument Shop (Unit 2) 1 224 Storage (Unit 2) 1 264 Storage (Unit 3) 1 16.9.6-6 11/15/12 1

Fire Detection Instrumentation 16.9.6 Table 16.9.6-1 FIRE DETECTION INSTRUMENTATION EL. 758' +0 Room No.

Equipment Detectors Provided 54 Unit 1 High Pressure Injection Pumps 1

56 Unit 1 and 2 High Pressure Injection Pumps 1

58 Unit 2 High Pressure Injection Pumps 1

61 Unit 1 Low Pressure Injection Pumps 2

62 Unit 1 and 2 Low Pressure Injection Pumps 2

63 Unit 2 Low Pressure Injection Pumps 2

76 Unit 3 High Pressure Injection Pumps 1

77 Unit 3 High Pressure Injection Pumps 1

81 Unit 3 Low Pressure Injection Pumps 2

82 Unit 3 Low Pressure Injection Pumps 2

Units 1, 2. and 3 Turbine Buildings EL. 775'+0 Equipment Detectors Provided MCC lXC, 1XD, iXE, iXF; Unit 1 FDW 10 Turbines; Unit 1 Emergency Feedwater Turbine; Unit 1 H2 Panel; Unit 1 EHC Unit MCC 2XB, 2XC, 2XD, 2XE, 2XF; Unit 2 FDW 11 Turbine; Unit 2 Emergency Feedwater Turbine; Unit 2 H2 Panel; Unit 2 EHC Unit MCC 3XC, 3XD, 3XE, 3XF; Unit 3 FDW 10 Turbines; Unit 3 Emergency Feedwater Turbine; Unit 3 H2 Panel; Unit 3 EHC Unit EL. 796' + 6" Equipment Detectors Provided Switchgear 1TA, 1TB, 2TA, 2TB; Load Centers 8

lX1, 1X2, 1X3, 1X4, lX5, 1X6, 2X1, 2X2, 2X3, 2X4, 2X5, 2X6 Switchgear BIT, B2T; Transformer CT4 5

Switchgear 3B1T, 3B2T 3

MCC lXA 1

ITTC5 and ITTC6 1

Unit 1 Main Turbine Oil Tank 1

Unit 2 Main Turbine Oil Tank 1

Unit 3 Main Turbine Oil Tank 2

Unit 1 Power Batteries; Switchgear 1TC, 12 1TD, 1TE; Load Center 1X10, MCC 1XS4, 1XS5, 1XS6 MCC 1XGA 1

Unit 2 Power Batteries; Switchgear 2TC, 13 2TD, 2TE; Load Center 2X1 0, MCC 2XS4, 2XS5, 2XS6, 2LS1 MCC 2XGB 1

Load Center 3Xl, 3X2, 3X3, 3X4, 3X1 0; MCC 3XGA, 3XS6; 1

Switchgear 3TC, 3TD, 3TE, Panel 3LS1 8

MCC 3XGB 16.9.6-7 11/15/12 1

Fire Detection Instrumentation 16.9.6 Table 16.9.6-1 FIRE DETECTION INSTRUMENTATION EL. 822' + 0 Equipment Detectors Provided Bearing Oil Lift Pumps for All Units 2 ea unit High Pressure Unit for All Units 2 ea unit KEOWEE HYDRO STATION Equipment Detectors Provided Control Room 4

Computer Room 2

Battery Room 4

Mechanical Equipment Gallery 5

Main Lube Oil Storage Room 1

Generators 1 and 2 6 ea Operating Floor 6

ESSENTIAL SIPHON VACUUM BUILDING 6

16.9.6-8 11/15/12 1

Fire Detection Instrumentation 16.9.6 BASES OPERABILITY of the NRC committed Fire Detection Instrumentation ensures that adequate warning capability is available for the prompt detection of fires in areas containing safety related and important to safety equipment at Oconee and Keowee Facilities. Prompt detection of fires will reduce the potential for damage to safety related equipment and is an integral element in the overall facility fire protection program. The regulatory requirement is to have NRC committed Fire Detection Instrumentation OPERABLE only when the equipment it is protecting is required OPERABLE for plant safety. However, to also protect the equipment for property conservation and minimize equipment loss due to fire; the Oconee and Keowee NRC committed Fire Detection Instrumentation will be required to be OPERABLE at all times.

In the event that a portion of the Fire Detection Instrumentation is inoperable, the establishment of compensatory actions in the affected areas is required to provide detection capability until the inoperable instrumentation is restored to operability.

This Selected Licensee Commitment is part of the Oconee Fire Protection Program and therefore subject to the provisions of Oconee Facility Operating License Conditions.

REFERENCES:

1.

Oconee UFSAR, Chapter 9.5-1.

2.

Oconee Fire Protection SER dated August 11, 1978.

3.

Oconee Fire Protection Review, (currently contained in the Fire Protection DBD), as revised.

4.

Oconee Plant Design Basis Specification for Fire Protection, as revised.

5.

Oconee Plant Design Basis Specification for Fire Detection, as revised.

16.9.6-9 11/15/12 1

Auxiliary Service Water System and Main Steam Atmospheric Dump Valves 16.9.9 16.9 AUXILIARY SYSTEMS 16.9.9 Auxiliary Service Water (ASW) System and Main Steam Atmospheric Dump Valves COMMITMENT a.

The ASW Pump shall be OPERABLE.

b. The ASW 4160 volt Switchgear shall be OPERABLE.

APPLICABILITY:

MODES 1, 2, and 3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

ASW system A.1 Restore ASW system to 30 days inoperable.

OPERABLE status.

AND Standby Shutdown Facility (SSF) ASW System is OPERABLE.

B.

ASW system B. 1 Restore ASW system to 7 days inoperable.

OPERABLE status.

AND Standby Shutdown Facility (SSF) ASW System is inoperable.

C.

Required Action and C.1 Submit report to the NRC 30 day associated Completion outlining plans and Time not met.

procedures to be used to provide for loss of the system.

16.9.9-1 11/15/12 1

Auxiliary Service Water System and Main Steam Atmospheric Dump Valves 16.9.9 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.9.9.1 Verify appropriate ASW pump discharge 92 days capabilities.

SR 16.9.9.2 Stroke Main Steam Atmospheric Dump 24 months Valves.

SR 16.9.9.3 Verify capability of aligning ASW 4160 volt 90 months Switchgear power to HPI.

BASES The ASW system is designed to mitigate the consequences of a tornado or a loss of Lake Keowee event by providing emergency cooling water to one or more of the three Oconee Units OTSG's and HPI pump motor coolers. OPERABILITY of the ASW pump includes the ASW pump, the associated piping, and the valves necessary to supply water to each applicable units OTSG's and HPI pump motor coolers. The Main Steam atmospheric dump valves (Reference

9) are required to be operable for the ASW system to be considered operable because the atmospheric dump valves must be opened to depressurize the OTSGs to allow the low-head ASW pump to supply water to the OTSGs. Operability of the ASW 4160 volt switchgear (including breakers, cable, and connectors) to the applicable Unit's HPI Pump motors is required to address a power failure event to the HPI Pump motors from loss of 4160 volt Main Feeder Busses caused by such events as Tornado, Blackout and High Energy Line Break. The 4160 volt switchgear ASWS breakers are defined as follows: ASWS07 (Unit 1), ASWS08 (Unit

2) and ASWS01 (Unit 3).

Although it is desirable to maintain the ASW system operable to mitigate events, short periods of inoperability are necessary for testing and maintenance to assure a high degree of reliability for the ASW system. Since the probability of a direct tornado strike or a loss of Lake Keowee event is low, a seven day limiting condition for operability (LCO) is reasonable for routine testing and maintenance.

The SSF ASW system is a redundant system and its availability reduces the need of the ASW system. The allowance of 30 days is deemed sufficient time for extended maintenance to be 16.9.9-2 11/15/12 1

Auxiliary Service Water System and Main Steam Atmospheric Dump Valves 16.9.9 BASES (continued) performed on the system as long as the SSF ASW system is available. The testing requirements provide assurance that the minimum OPERABILITY requirements of the ASW system are met.

Operability of the station ASW system is dependent upon the following requirements:

1. The Unit 2 CCW Inlet pipe is full (not unwatered and not partially unwatered).

2. An OPERABLE flowpath to reclaim the station ASW pump recirculation water that discharges to the Unit 2 CCW Discharge pipe to be routed back to the Unit 2 CCW inlet pipe.

3. An OPERABLE flowpath for each applicable Unit that is in MODE 1, 2 or 3 to reclaim that Units CCW inlet and discharge pipes inventory to be routed to the Unit 2 CCW Inlet pipe.

Specific combinations of the applicable Units' CCW Intake and Discharge Unwatering and CCW Cross-Connect valves and the Unit 2 Condensate Cooler valves will ensure the necessary ASW Pump suction flowpath and inventory to satisfy the Unit(s) decay heat removal requirements to address a function of the Station ASW System to mitigate a Loss of Lake Keowee event.

These valve combinations are defined as follows:

Unit 1 (applicable when Unit 1 is in MODE 1, 2, or 3)

(2CCW-31, -32, -75, -78, -79, -86, -87) OR (1CCW-30, -40 AND 2CCW-31, -41) are required to reclaim the ASW Pump Recirculation water that discharges to the Unit 2 CCW discharge pipe.

1 CCW-30, -31, -32, -40 and 2CCW-41 are required to cross-connect the Unit 1 CCW Inlet and Discharge inventory to the Unit 2 CCW Inlet pipe.

Unit 2 (applicable when Unit 2 is in MODE 1, 2, or 3)

(2CCW-31, -32, -75, -78, -79, -86, -87) OR (1CCW-30, -40 AND 2CCW-31, -32, -41) are required to reclaim the ASW Pump Recirculation water that discharges to the Unit 2 CCW Discharge pipe and to cross-connect the Unit 2 CCW Discharge to the Unit 2 CCW Inlet pipe.

Unit 3 (applicable when Unit 3 is in MODE 1, 2, or 3)

(2CCW-31, -32, -75, -78, -79, -86, -87) OR (1 CCW-30, -40 AND 2CCW-31,-41) are required to reclaim the ASW Pump Recirculation water that discharges to the Unit 2 CCW Discharge pipe.

(3CCW-31, -32, -33 AND 2CCW-30) OR (3CCW-30, -31, -32, -33, -42, -94 AND 2CCW-41) are required to cross-connect the Unit 3 CCW Inlet and Discharge inventory to the Unit 2 CCW Inlet Pipe.

Surveillance Requirement 16.9.9.3 verifies the capability to power one (either A or B) HPI pump from ASW Switchgear every 90 months. It is not necessary to alternate between the HPI pumps during subsequent tests. This frequency applies to each unit and is adequate based on 1) more frequent surveillance tests which verifies the operability of the HPI pumps and ASW Switchgear separately and 2) more frequent verification of the availability of equipment needed for Time Critical Operator Actions (TCOA). This TCOA is required to mitigate a high energy line break or tornado.

16.9.9-3 11/15/12 I

Auxiliary Service Water System and Main Steam Atmospheric Dump Valves 16.

9.9 REFERENCES

1.

Design Basis Specification for the Emergency Feedwater and Auxiliary Service Water Systems (OSS-0254.00-00-1000).

2.

Design Basis Specification for the High Pressure Injection and Purification and Deborating Demineralizer Systems (OSS-0254.00-00-1001).

3.

Oconee UFSAR, Section 3.2.2 and Section 9.2.3.

4.

Oconee Probabilistic Risk Analysis, Section 3.4.

5.

Calculational File OSC-2262, "Tornado Protection Analysis."

6.

Calculational File OSC-5771, "PRA Risk-Significant SSC's for the Maintenance Rule."

7.

Calculational File OSC-0864, "RC System Decay Heat Removal Following Loss of Intake Canal/Structure."

8.

Work Process Manual Section 607, "Maintenance Rule Assessment of Equipment Removed From Service."

9.

Technical Specification 3.7.4, Atmospheric Dump Valves (ADVs).

16.9.9-4 11/15/12 1

Turbine Building Flood Protection Measures 16.9.11 16.9 AUXILIARY SYSTEMS 16.9.11 Turbine Building Flood Protection Measures COMMITMENT Turbine Building Flood Protection Measures shall be OPERABLE as follows:

a.

Each CCW Pump Discharge Valve (1,2,3CCW-10 through -13) shall:

1.

be capable of being closed remotely, or

2.

be closed with its breaker open and its handwheel locked, or

3.

one of the following conditions shall exist:

a.

the unwatering blocks are installed for the associated CCW inlet piping,

b.

the associated condensate coolers CCW flowpath is isolated with locked closed valve(s), the associated waterbox inlet valves are locked closed, the crossover tie valves are locked closed, the CCW inlet piping is vented at the high point to disable the first siphon, and the CCW inlet piping is intact inside the Turbine Building, or

c.

Keowee lake level is _< 796.5 ft. absolute and the associated CCW inlet piping is vented at the high point to disable the first siphon.

b.

Each Condenser Outlet Valve (1,2,3CCW-20 through -25) shall

1.

be capable of closing automatically when all CCW pumps on the applicable unit are tripped to mitigate certain Turbine Building flood conditions, 16.9.11-1 11/15/12 1

Turbine Building Flood Protection Measures 16.9.11

-NOTE-The condenser outlet valve control switch may be placed in the HAND position, with the valve open, for the purpose of immediately closing the valve, without entering Condition A.

2.

be closed and capable of being operated manually or automatically,

3.

be closed and air locked with air pressure vented and strongback installed,

4.

be closed with its operator removed and strongback installed, or

5.

one of the following conditions shall exist:

a.

the unwatering blocks are installed for the associated CCW discharge piping, or

b.

Keowee lake level is < 791 ft. absolute and the associated CCW discharge piping is vented at the high point to prevent reverse siphon flow.

c.

Two flowpaths (one each from two different units) shall be available for gravity induced reverse flow through the Condensate Coolers whenever Keowee lake level is greater than 793.7 ft.

d.

NOTE When Keowee lake level is at or below full pond, openings above the full pond level are excluded from Commitment d.

Prior to opening any condenser waterbox access hatch or creating any opening in the CCW or LPSW systems > 24 inches diameter (or multiple openings with equivalent diameter > 24 inches) inside the Turbine Building, an isolation boundary with single barriers shall be established to isolate the opening from the lake using the following methods, as applicable:

1.

Any manual valves > 24 inches diameter used for the isolation boundary shall be locked closed,

2.

Any motor-operated valve > 24 inches diameter used for the isolation boundary shall be closed with its breaker locked open and the handwheel locked, 16.9.11-2 11/15/12 1

Turbine Building Flood Protection Measures 16.9.11

3.

Any condenser outlet valve used for the isolation boundary shall be closed and air-locked with air pressure vented and strongback installed,

4.

A physical barrier, such as unwatering blocks or blank flange, may be used for boundary isolation instead of valves.

e.

The Turbine Building/Auxiliary Building boundary wall penetrations shall be sealed below Elevation 795 ft. with all water tight doors operable.

f.

The Turbine Basement Water Emergency High Level alarm shall be operable.

g.

The six foot diameter Turbine Building Flood drain shall be operable.

APPLICABILITY:

At all times.

16.9.11-3 11/15/12 1

Turbine Building Flood Protection Measures 16.9.11 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Turbine Building Flood Protection Measures inoperable.

A. 1------- NOTE ------

If Turbine Building Flood Protection Measures are inoperable due to planned activities, then these activities shall be performed in a prompt manner without delay.

Initiate action to restore flood protection measures to OPERABLE status.

AND A.2 --------

NOTE --------------

Entry into the associated Condition results in unavailability for all three units.

Log unavailability duration in the Operations Log for Maintenance Rule Performance monitoring.

AND A.3 Perform a Risk Assessment using the Electronic Risk Assessment Tool.

Immediately None None 16.9.11-4 11/15/12 1

Turbine Building Flood Protection Measures 16.9.11 SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.9.11.1 Verify OPERABILITY of Turbine Basement 12 months Water Emergency High Level Alarm.

SR 16.9.11.2 Verify capability to close all four CCW pump 24 months discharge valves.

SR 16.9.11.3 Verify capability to automatically close 24 months condenser outlet valves when all CCW pumps are tripped.

BASES One of the risk-significant Maintenance Rule functions for the CCW System is to maintain system integrity to prevent or mitigate a Turbine Building flood. The purpose of this Selected Licensee Commitment is to monitor the performance of the major design features associated with this function. To monitor performance of this function, any unavailability must be logged.

The Oconee UFSAR Section 3.4.1.1.1 describes the flood protection measures for the Turbine Building (TB) and Auxiliary Building (AB). These measures are the basis for the commitments in SLC 16.9.11. The flood protection measures were implemented to reduce the overall risk of a Turbine Building flood, as determined by the Oconee Probabilistic Risk Assessment (PRA) study.

Upon detection of a TB flood, operators would trip the CCW pumps which would automatically close all condenser outlet valves. They would also close all CCW pump discharge valves which may be performed by using a pushbutton in the control room that closes all four valves on that unit. The CCW pump discharge valves can also be closed individually using pushbuttons at the breaker compartment in the Equipment Room. If the CCW pump discharge valve breakers are open for testing, remote closure may be credited for maintenance rule availability if 1) contingency steps to close breakers and valves are in a written procedure, 2) a dedicated Operator is stationed at the breakers and is in constant communication with the Control Room during the entire duration the breakers are opened so as to be able to promptly restore the breakers to closed, and 3) equipment is not tagged out of service. These requirements align with Systems, Structures, and Components (SSC) Maintenance Rule (MR) Unavailability considerations for testing as outlined by NRC Maintenance Rule Frequently Asked Questions

.16.9.11-5 11/15/12 1

Turbine Building Flood Protection Measures 16.9.11 (FAQs) for Unavailability. Per Reg Guide 1.160, the NRC currently endorses NUMARC 93-01 Rev. 2. NUMARC 93-01 Rev. 3 included revisions to incorporate this NRC FAQ and Rev. 4 is currently issued for comments within the NRC. This definition for testing unavailability is included in Appendix B of the NUMARC (See Unavailability definition as related to Testing).

This SLC is intended to ensure that the functional capability of the CCW pump discharge valves and condenser outlet valves will be maintained unless alternative actions have been taken.

In Commitment a, each CCW pump discharge valve shall be capable of being closed remotely, or shall be closed with its breaker open and its handwheel locked. This precludes credit for manual operation of the valves during a flood since there may not be adequate time to take credit for manual operation. Additional options are provided in case the valves cannot be closed remotely, or are not already closed with the breaker open and handwheel locked.

Option 3a requires the unwatering blocks to be installed for the associated CCW inlet piping.

Option 3b includes locking closed the condensate coolers CCW flowpath, the waterbox inlet valves, the crossover tie valves, and venting the CCW inlet piping at the high point. Option 3c involves Keowee lake level < 796.5 feet absolute with the associated CCW inlet piping vented at the high point to disable the first siphon. The high point may be vented by opening valves or by other means, such as manways. These options provide additional flexibility to allow maintenance to be performed on the CCW pump discharge valves while preventing the possibility of CCW siphoning into the Turbine Building basement.

In Commitment b, additional options are provided to allow maintenance to be performed on the condenser outlet valves. Option 1 allows the valves to be capable of closing automatically when all CCW pumps on the applicable unit are tripped to mitigate certain Turbine Building flood scenarios. Option 2 of Commitment b allows an affected condenser outlet valve to be closed and capable of operating with the control switch in either the HAND or AUTO position. With the valve in the closed position, there is no need for the valve to be capable of automatically closing. The requirement to be "capable of operating..." prevents the valve actuator from being disabled unless one of the other options is met. The Note prior to this option allows the control switch to be placed in the HAND position for the purpose of immediately closing the valve without entering an Action. Option 3 allows a condenser outlet valve to be out of service if the valve is blocked closed with the air supply to the valve operator defeated. Option 4 is similar to Option 3 except that it allows the valve operator to be removed for maintenance if the strongback is installed. Option 5a involves installing the unwatering blocks at the CCW discharge. Option 5b allows the automatic valve operation to be out of service if the lake level is < 791 feet absolute and the high point of the discharge piping is vented. Below this lake level, the CCW discharge pipe could not be refilled from the lake. Venting the high point may be accomplished by opening manways or by any available means. Credit cannot be taken for the normally open mid-point vents on the discharge piping, because these vents may not prevent reverse siphon flow.

Options 5a or 5b of Commitment b will make the affected flowpath incapable of applying towards the requirements in Commitment c, which requires two flowpaths for reverse gravity flow. However, Commitment c may still be met using other available flowpaths (e.g., other units).

For Commitment c, if Keowee lake level is greater than 793.7 ft., gravity induced reverse flow can be used to provide suction to the LPSW pumps and SSF ASW pump. The licensing basis 16.9.11-6 11/15/12 1

Turbine Building Flood Protection Measures 16.9.11 for Oconee takes credit for the SSF to mitigate a Turbine Building flood, and there is no commitment to meet single failure criteria. However, maintaining the capability for decay heat removal using LPSW can reduce overall plant risk for some flood scenarios. There is no commitment to maintain the lake level above 793.7 feet at all times. The PRA addresses the probability of lake levels below 793.7 feet, resulting in loss of gravity induced reverse flow capability. See SLC 16.9.7 for additional information. (Note that for Keowee lake levels

< 793.7 ft, commitment c is not applicable and condition entry is not required). An analysis was performed to determine the optimum flowpath to supply suction to these pumps while minimizing any excess flow that would contribute to additional flooding. This analysis determined that flowpaths through one condensate cooler and one flow control valve on each of two units would be optimum. As a result of this analysis, Condensate Coolers CCW Flow Control Valves for Units 2 and 3 (2, 3CCW-84) have been permanently failed open by having their instrument air supplies removed. If either flowpath through Units 2 or 3 will be unavailable, an alternate flowpath should be provided on Unit 1 by failing open 1CCW-84. A flowpath for gravity induced reverse flow consists of an open condenser discharge header, one failed-open condensate cooler CCW flow control valve, one open condensate cooler, and an open flowpath to the suction of the LPSW and SSF ASW Pumps (Unit 2 CCW inlet pipe).

Commitment d is provided to control activities that would create openings in the CCW or LPSW Systems. These activities are controlled to ensure that such openings are isolated from the lake using physical barriers (e.g., locks) and not just administrative barriers (e.g., valve tags).

Per UFSAR Section 3.4.1.1.1, the worst-case flood would involve failure of the expansion joint at the inlet to the condenser. There are other possible failures could lead to a Turbine Building flood. The flood consequences would vary depending upon the size of the opening and other factors. A flood that involved an opening greater than approximately 24 inches diameter may affect the Low Pressure Service Water (LPSW) pumps. Therefore, emphasis is placed on any activities that would create openings in the piping greater than 24 inches diameter.

Commitment d requires that an isolation boundary be established on a case-by-case basis prior to opening a condenser waterbox access-hatch and for any openings > 24 inches, including multiple openings equivalent to 24 inches diameter. Single isolation is acceptable, but the isolation boundary must include physical barriers, such as locked closed valves, and not just administrative barriers, such as valve tags. Physical barriers may include blocks or blank flanges. A stoppel plug or wet-tapping machine may also act as a physical barrier. This SLC is intended to address only the isolation of the opening from the lake. This SLC is applicable to the LPSW pump inlet isolation valves: LPSW-1,-2,-3 and 3LPSW-120,-123. Note that the discharge of each LPSW pump is 18"; thus, there are no valves downstream of the pumps within the scope of the SLC.

Commitment d does not apply to openings above 800 ft. absolute in the CCW and LPSW systems when Keowee lake level is at or below full pond. Per UFSAR 2.4.1.2, full pond for Keowee lake level is 800 ft. Openings in the CCW and LPSW system are excluded due to the inability of hydrostatic pressure to drive water above this elevation. When Keowee lake level is above full pond, commitment d still applies to all CCW and LPSW openings > 24 inches diameter (or multiple openings with equivalent diameter > 24 inches) inside the Turbine Building.

Commitment e requires that the Turbine Building/Auxiliary Building boundary wall penetrations shall be sealed below elevation 795 ft. with all water tight doors operable. The plates sealing 16.9.11-7 11/15/12 I

Turbine Building Flood Protection Measures 16.9.11 the unused doors (Architectural doors 104, 105, and 106) between the Tubine Building and Auxiliary Building are sealed with fasteners and RTV sealant around the plate perimeter. A block wall was installed on the Auxiliary Building side where the door was previously located.

The RTV sealant around the plate perimeter is required to prevent Turbine Building flood water from pressurizing the block wall which would cause a failure of the block wall and allow flood water to access the Auxiliary Building.

Commitment f requires that the Turbine Basement Water Emergency High Level alarm shall be operable. The Turbine Basement Water Emergency High Level Alarm consists of a 2 out of 4 logic circuit, which yields 6 different alarm circuit combinations. Operability is based on at least 1 of the 6 alarm circuit combinations being functional.

REFERENCES

1.

UFSAR Sections 3.4.1.1.1, 9.2.2, 9.6, and Figure 9-9, 12/31/97 update.

2.

Engineering Directives Manual EDM-210, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants or the Maintenance Rule."

3.

OSS-0254.00-00-1003, "Design Basis Specification for the Condenser Circulating.Water (CCW) System," Rev. 20.

4.

OSS-0254.00-00-3005, "Design Basis Specification for the Turbine Building Structure,"

Rev. 1.

5.

AP/1,2,3/A/1 700/10, "Uncontrollable Flooding of Turbine Building," Approved 4/30/97.

6.

Calculation No. C-OSA-SA-83-0002-0, Rev. 0, 3/1/83, "Turbine Building Flood CCW Reverse Flow Analysis."

7.

Calculation No. OSC-6522, Rev. 0, 2/29/96, "Turbine Building Flood CCW Reverse Flow Analysis."

8.

Calculation No. OSC-6577, Rev. 0, 6/7/96, "CCW Turbine Building Flood Analysis."

9.

PT/1,2,3/A/0261/020, "ECCW System Test."

10.

IP/O/B/0235/03. "Turbine Basement Water Level Alarm System Check."

11.

Calculation No. OSC-5771, PRA Risk-Significant SSC's for the Maintenance Rule."

12.

Work Process Manual Section 607. "Maintenance Rule Assessment of Equipment Removed From Service".

13.

OP/1,2,3/A/1 104/12, "Condenser Circulating Water System."

14.

Calculation OSC-6081, Rev. 2, CCW Seismic-LOOP Response."

15.

Oconee Unit 3 Probabilistic Risk Assessment, Rev. 1, November. 1990.

16.

OSC-5349, Rev. 5, "Minimum Lake Level Required to Maintain Sufficient NPSH to the LPSW Pumps Via Gravity Flow."

17.

NRC Maintenance Rule Frequently Asked Questions, July 9, 2000 version. Unavailability Credit for Operator Action.

18. NRC Regulation Guide 1.160, Rev. 2, 03/1997

19. NUMARC 93-01, Rev. 4a, April 2011

20. NUMARC 93-01, Rev. 2, April 1996 16.9.11-8 11/15/12 I

AB Flood Protection Measures 16.9.11a 16.9 AUXILIARY SYSTEMS 16.9.1 la Auxiliary Building Flood Protection Measures COMMITMENT Auxiliary Building (AB) Flood Protection Measures shall be OPERABLE as follows:

a.

AB Flood Barriers

1.

Low Pressure Service Water (LPSW) and High Pressure Service Water (HPSW) piping structural integrity shall be intact.

2.

HPSW 21 and HPSW-958 shall be closed to isolate the 16 inch HPSW supply in the AB. 3HPSW-453 shall be closed to isolate the alternate 4 inch HPSW supply in the AB.

3.

LPSW-427 and LPSW-428 shall be closed to isolate the flushing supply to the waste monitor tank.

4.

1 HPSW-561 shall be closed to isolate the fire hose header that passes over the Unit 1 and 2 Low Pressure Injection (LPI) pump hatch area.

5.

First and second floor AB curbs shall be in place to the LPI hatch areas.

6.

Turbine/Auxiliary Building wall, as well as other AB wall, floor and penetration seals credited shall be intact.

7.

High Pressure Injection (HPI)/LPI Pump Room walls and penetration seals shall be intact.

b.

AB Flood Detection

1. Seismic trigger and statalarm shall be operable.

2. The High Activity Waste Tank (HAWT) and Low Activity Waste Tank (LAWT) sump level detection systems shall be capable of generating a level alarm in the control room.

3. The LPI sump level detection system shall be capable of generating a level alarm in the control room.

c.

AB Flood Mitigating Equipment

1. Critical, manual valves used to isolate a potential flooding source shall be capable of closing.

16.9.11a-1 11/15/12 1

AB Flood Protection Measures 16.9.11a

2. Flow limiting valves that restrict potential break flows shall be capable of limiting flow.

3. Check valves that prevent back flow through a potential break location are operable.

APPLICABILITY:

MODES 1, 2, 3,4, 5, and 6 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

AB Flood Protection A.1 ---------- NOTE-----

Measures If AB Flood Protection commitments a.2 Measures are (HPSW-21 & 958, inoperable due to 3HPSW-453), a.3 planned activities, (LPSW-427 & 428), or then these activities a.4 (1HPSW-561) not shall be performed in met.

a prompt manner without delay.

Restore AB flood 7 days protection measures commitments a.2, a.3, or a.4 to OPERABLE status.

B.

AB Flood Protection B.1.1 In MODES 1-3, NA Measures perform a risk commitments other assessment using the than those specified in Electronic Risk Condition A not met.

Assessment Tool.

OR B.1.2 In MODES 4-6, NA develop a risk management plan in accordance with NSD-403.

16.9.11 a-2 11/15/12 1

AB Flood Protection Measures 16.9.11 a CONDITION REQUIRED ACTION COMPLETION TIME (continued)

AND B.1.3 Implement 7 days compensatory actions in accordance with Table 16.9.11a-1.

C. Required Actions and C.1 Initiate a PIP.

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Associated Completion Times not met.

16.9.11 a-3 11/15/12 1

AB Flood Protection Measures 16.9.11a SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.9.11 a.1 Verify that the LPI hatch area curbs are 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months in place and not obstructed.

SR 16.9.1 la.2 Verify that HPSW-21 and 958 and 31 days 3HPSW-453 are closed; unless locked, sealed, or otherwise secured in the closed position.

SR 16.9.1 la.3 Verify that LPSW-427 and 428 are 31 days closed; unless locked, sealed, or otherwise secured in the closed position.

SR 16.9.11 a.4 Verify that 1HPSW-561 is closed; 31 days unless locked, sealed, or otherwise secured in the closed position.

SR 16.9.1 la.5 Verify that the seismic trigger and 24 months statalarm are operable.

SR 16.9.1 la.6 Verify that the LAWT, HAWT, and LPI 24 months sump level detection systems provide an alarm in the control room and associated level instrumentation is calibrated.

SR 16.9.11 a.7

Note -----------------------

Only applicable to Units with flood impoundment modifications completed.

Verify OPERABILITY of the 18 months Turbine/Auxiliary Building and HPI/LPI rooms wall, and other credited AB walls/floors and penetration seals.

16.9.11 a-4 11/15/12 1

AB Flood Protection Measures 16.9.11a SURVEILLANCE FREQUENCY SR 16.9.11 a.8 Verify that critical manual valves used 2 years in the AB flood abnormal operating procedure are capable of being closed.

SR 16.9.1 la.9 Verify that all credited check valves are 2 years operable.

SR 16.9.11a.10 Inspect/replace all credited flow limiting 5 years valves to verify capability to limit flow.

SR 16.9.1 la. 11 Inspect the structural integrity of the In accordance with the Service LPSW and HPSW piping by performing Water Inspection Program ultrasonic or radiographic inspections of the associated piping.

16.9.1 la-5 11/15/12 1

AB Flood Protection Measures 16.9.11 a Table 16.9.1 la-1 Compensatory Actions Com#

Protective Measure Compensatory Action a.1 LPSW and HPSW piping structural

1. Isolate affected section, or integrity shall be intact.

2. Station a watch near the affected section a.5 First and second floor curbs shall

1. Station a continuous watch near the be in place.

removed curb, and

2. Restore curb (or an equivalent) in the event of a flood, or

3. Install equivalent curb.

a.6 Building and penetration seals shall

1. Assess impact of leak rate through the be intact and capable of preventing location of the degradation. Determine if water egress.

any additional action is prudent, or

2. Provide temporary seals or dams to prevent leakage past seal.

a.7 HPI/LPI Pump room walls and

1. Assess impact of leak rate through the penetration seals shall be intact, location of the degradation. Determine if any additional action is prudent, or

2. Provide temporary seals or dams to prevent leakage past seal.

b. 1 Seismic trigger and statalarm shall NA be operable.

b.2 The HAWT and LAWT sump level Survey affected section every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

detection systems shall be capable of generating a level alarm in the control room.

b.3 LPI sump level detection systems Survey affected section every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

shall be capable of generating a level alarm in the control room.

c. 1 Critical, manual valves used to

1. Isolate the source outside of the AB, or isolate a potential flooding source

2. Identify an equivalent isolation device in shall be capable of closing, event of a flood.

c.2 Flow limiting valves that restrict

1. Isolate the source outside of the AB, or potential break flows shall be

2. Identify needed isolation, including capable of limiting flow.

timeliness, in the event of a flood.

c.3 Check valves that prevent back

1. Isolate the source outside of the AB, or flow through a potential break

2. Identify needed isolation, including location are operable.

timeliness, in the event of a flood.

16.9.11a-6 11/15/12 1

AB Flood Protection Measures 16.9.11a BASES In a letter dated September 26, 1972, the AEC requested Oconee to: "Review Oconee Nuclear Station Units 1, 2, and 3 to determine whether the failure of any non-category I (seismic) equipment, particularly in the circulating water system and fire protection, could result in a condition, such as flooding or the release of chemicals, that might potentially adversely affect the performance of safety-related equipment required for safe shutdown of the facilities or to limit the consequences of an accident."

If a non-seismically designed system retaining water located in the AB were to fail, then the water would drain to either the LAWT or in some cases, to the LPI pump room sumps. If the source of the flood was continuous and was not secured, the water would eventually flood the HPI pump rooms, the LPI and Building Spray (BS) pump rooms, and the floor above (elevation 771 ft.) which contains the Component Cooling (CC) pump breakers. If both the HPI pumps and the CC pumps were lost and the Standby Shutdown Facility (SSF) was not OPERABLE, a Reactor Coolant Pump (RCP) seal Loss of Coolant Accident (LOCA) could occur.

The objective of this Selected Licensee Commitment (SLC) is to minimize the unavailability of barrier, detection, and mitigating equipment to reduce the consequences of an AB flood event.

Compensatory actions will be implemented to reduce the risk associated with inoperable equipment. Since the consequences of an AB flood event increases if certain Structures, Systems, or Components (SSCs) beyond the scope of this SLC are out of service, a risk analysis will be performed in MODES 1, 2, and 3 using the Electronic Risk Assessment Tool and a risk management plan will be developed in MODES 4, 5 and 6 upon entry into the SLC for all commitments except a.2, a.3, and a.4. A risk analysis has already been performed for these commitments and concluded the valves can be open < 7 days without a significant increase in risk.

The following flood barriers, mitigating equipment, and flood detection devices are currently used to minimize the consequences of an auxiliary building flood:

AB Flood Barriers LPSW and HPSW Piping Structural Integrity Several water systems with non-safety piping in the AB have a limited water volume and can not flood the HPI pump motors or the CC pump breakers. Examples include the Chilled Water (WC), CC, and Recirculating Cooling Water (RCW) systems.

However, a pipe break in the LPSW and HPSW systems could result in a large, continuous flood that might eventually submerge the HPI, LPI, and BS pump motors as well as the CC pump breakers if not isolated.

Maintaining the structural integrity of the LPSW and HPSW piping system is the first line of defense against an AB flood event. Examples of unacceptable structural integrity include:

1. A general reduction in the thickness of the piping below acceptable levels per the Service Water Inspection program.

2. Damaged hangers or other supports below acceptable levels as evaluated by Mechanical/Civil Engineering (MCE)-Civil.

16.9.1 la-7 11/15/12 1

AB Flood Protection Measures 16.9.11a Leakage from pump seals, valve piping, or pipe pin holes is considered acceptable. Opening portions of the LPSW and HPSW systems for maintenance is treated as a critical activity to reduce the risk of an inadvertent flood.

The applicable surveillance to verify structural integrity per SR 16.9.11 a. 11 is as follows:

Ultrasonic inspections of the associated piping by the Service Water Inspection program.

HPSW-21/958, LPSW-427/428, 1HPSW-561 and 3HPSW-453 HPSW-21 and 958 are used to isolate the 16 inch HPSW header in the AB. This is the largest potential non-seismic pipe break source in the auxiliary building. Maintaining the valves in a closed position eliminates the potential for flooding if any section of HPSW piping were to fail.

3HPSW-453 is used to isolate the 4 inch HPSW header into the AB. This header is normally maintained closed since it is not flow limited. A normal flow limit supply of HPSW is maintained around HPSW-958.

LPSW-427 and 428 isolate the flush water supply to the waste monitor tank. Even though the associated supply is much smaller than the 16 inch HPSW supply header, the valves are still maintained in the closed position to eliminate any potential for flooding if the downstream piping were to break.

1 HPSW-561 isolates the fire header from the AB to the hot machine shop to prevent potential flooding of the Unit 1 and 2 LPI pump rooms.

The position of these valves will be periodically checked using SR 16.9.1 la.2, SR 16.9.1 la.3, and SR 16.9.11a.4.

AB First and Second Floor Curbs The following curbs are critical to the prevention of LPI/BS room flooding:

LPI Hatch Area Entrance Curbs Curb outside "Overlook" onto Unit 1 HPI Hatch Area The LPI/BS rooms have a much smaller allowable flood volume than the HPI rooms. The curbs delay flooding of these rooms in the event of an AB flood and allow sufficient time for operators to terminate the source of the flood.

Acceptable surveillances for this portion of SR 16.9.11 a. 1 are as follows:

Operations verifies and documents that the curbs are installed during shift rounds.

" These curbs are periodically inspected by the auxiliary building flood program coordinator.

Auxiliary/Turbine Buildinq and HPI/LPI Room Walls, Floors and Penetration Seals The following walls, floors and penetration seals ensure that a break on the upper elevations of the AB does not adversely impact equipment in adjacent rooms:

16.9.11a-8 11/15/12 1

AB Flood Protection Measures 16.9.11a Spent Fuel Cooler Room Floor Penetrations Expansion Joints above LPI Hatch Area HPI/LPI Room walls and penetrations Auxiliary/Turbine Building walls and penetrations East Penetration floor seals Applicable surveillances for SR 16.9.11 a.7 are as follows:

The building and penetration seals, above, are periodically inspected during fire barrier inspections or As part of the AB Flood program Surveillance of the East Penetration floor seals is not required to be established until December 31, 2007, which coincides with completion of the flood impoundment modifications. This surveillance is modified by a note that states it is only applicable to units that have the flood impoundment modifications installed. The flood impoundment modifications are OD100505, OD200506, and OD300507.

Flood Detection Seismic Trigqger and Statalarm The seismic trigger and associated statalarm provides indication of an earthquake. Upon identification of the earthquake, operators will be dispatched to the AB to inspect its structural integrity in accordance with the earthquake AP. Any floods resulting from an earthquake, would, as a minimum, be identified in this manner.

The applicable surveillance for SR 16.9.1 la.5 is as follows:

Instruments are calibrated and alarms are checked via instrument procedures.

There are no compensating actions for an inoperable seismic trigger and statalarm since operations would sense building motion during a large earthquake.

Level Detection Systems The LAWT, HAWT, and LPI sump level detection systems provide an early means of detecting a flood. In order to be OPERABLE, each system should generate an alarm in the control room.

Although the LAWT level detection system will be the source of detection for most large floods, the other two systems provide detection of smaller floods or leaks. If left unsecured, the smaller leaks or floods could damage critical equipment. Additionally, a number of closed system drains discharge into the LPI room sumps. Also, there are non-seismic pipes (such as RCW) that could break in the areas that would drain to these sumps. If these drains go unsecured, the LPI rooms could flood due to the small volume below the pumps in these rooms.

16.9.11a-9 11/15/12 1

AB Flood Protection Measures 16.9.11 a The applicable surveillance for SR 16.9.1 la.6 is as follows:

Tests are performed to verify that the LAWT, HAWT, and LPI sump level detection systems provide an alarm in the control room in the event of high level.

" Associated level instrumentation is calibrated.

Mitigating Equipment Manual Valves used in the Auxiliary Building Flood Abnormal Procedure In order to preserve safety equipment subsequent to a flood, the flood source must be isolated.

The valves used to isolate a potential flood are identified in the abnormal procedure for AB flooding. The list of valves are provided in Table 16.9.1 la -2.

The applicable surveillance for SR 16.9.1 la.8 is as follows:

Verify that the essential valves used in the AB flood abnormal procedure are capable of being closed.

Flow Limitinq Valves Flow limiting valves are used to limit the rate of flow into the AB if a line break should occur.

The limited flow rate ensures that operators have at least 45 minutes to secure the source of the flood. The valves currently credited are provided in Table 16.9.11a-3.

The applicable surveillance for SR 16.9.1 la.10 is as follows:

Inspect all credited flow limiting valves to ensure capability to limit flow. The flow limiting valves are spring loaded devices that reduce their cross sectional flow area as the flow attempts to increase. This SR can be met by replacing or dismantling and visually inspecting the valves.

Check Valves Credited in the AB Flood Analysis Check valves and elevation head prevent water from the discharge side of the LPSW from entering the AB in the event of a break. Where elevation head is insufficient to prevent back flow, the check valves should be capable of eliminating significant back flow through a break.

The valves currently credited are provided in Table 16.9.1 la-4.

The applicable surveillance for SR 16.9.1 la.9 is as follows:

Verify that all credited check valves restrict back flow sufficiently. This requirement can be verified by performing a leak test across the valve, dismantling and visually inspecting the valve or performing a UT or RT to verify that the valve closes. Since the check valves are passive devices, a surveillance frequency of 2 years is appropriate.

16.9.11a-1 0 11/15/12 1

AB Flood Protection Measures 16.9.11a ACTIONS A.1 If the following AB Flood Barriers commitments are not met:

HPSW-21 and HPSW-958 shall be closed to isolate the,16 inch HPSW supply in the AB.

3HPSW-453 shall be closed to isolate the 4 inch HPSW supply into the AB.

0 LPSW-427 and LPSW-428 shall be closed to isolate the flushing supply to the waste monitor tank.

0 1 HPSW-561 shall be closed to isolate the fire hose header that passes over the Unit 1 and 2 LPI pump hatch area.

Flood Protection measures shall be restored within 7 days. This is based on a risk analysis (Reference 4); the valves can be opened < 7 days per year without a significant increase in risk.

The Action is modified by a note that states if AB Flood Protection measures are inoperable due to planned activities, then these activities shall be performed in a prompt manner without delay.

B.1.1, B.1.2 and B.1.3 Required Action B. 1.1 requires that the Electronic Risk Assessment Tool be used to determine the overall risk during MODES 1, 2, and 3. In these MODES, an increase in the probability of an AB flood increases the probability of the loss of RCP seal cooling. The loss of seal cooling results from the loss of the HPI pumps. The loss of RCP seal cooling could cause a Small Break LOCA. Consequently, the risk determined by the Electronic Risk Assessment Tool is sensitive to the condition of equipment that provides backup RCP seal cooling or that might aid in the mitigation of a LOCA. Examples of backup seal cooling include the component cooling system and the SSF reactor makeup system. Examples of systems that can be used to defend against a LOCA include LPI and BS.

In MODES 4, 5, and 6, Required Action B.1.2 requires that a risk management plan be generated in accordance with NSD-403, Shutdown Risk Management (Modes 4, 5, 6, and No-Mode) per 10CFR50.65(a)(4). In MODES 4, 5, and 6, an AB Flood could result in the loss of the LPI pumps and associated decay heat cooling. Consequently, the risk management plan will be sensitive to whether alternate forms of decay heat cooling are available. Alternates include secondary cooling (if the secondary is available for cooling and the primary is filled and not vented), water in the refueling cavity (if flooded), and gravity flow from the Borated Water Storage Tank (BWST).

Required Action B. 1.3 implements compensatory actions to minimize the consequences of an AB flood while equipment important to the prevention, detection, or mitigation of a flood is inoperable.

16.9.11a-1 1

11/15/12 1

AB Flood Protection Measures 16.9.11a Electronic Risk Assessment Tool/Risk Manaqement Plan If the Electronic Risk Assessment tool or risk management plan reveals an elevated risk, actions can be taken at the station level in the planning or performance of work to minimize the risk.

An Electronic Risk Assessment and/or risk management plan may need to be generated for one or more units if the SLC is entered.

Example 1:

If substantial pipe degradation was discovered in the 4 inch HPSW header running through the lower elevations of the building, an Electronic Risk Assessment tool model or risk management plan would need to be developed for each unit. A break in the HPSW header would affect all three units. Units in MODES 1, 2, and 3 would use the Electronic Risk Assessment tool approach and units in MODES 4, 5, and 6 would use the risk management plan approach.

Example 2:

If the first floor curb were removed leading into the Unit 3 LPI room area, a risk assessment would only be performed for Unit 3. The unavailability of this barrier could only affect Unit 3.

C.1 If the required actions and associated completion times of Conditions A and B are not met, a PIP shall be initiated within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

REFERENCES

1. ONS Flood Protection Engineering Support Document.

2. Letter from R. A. Jones to the NRC, "Proposed License Amendment Regarding Revisions to the Licensing Basis for the UFSAR Section on Water Level (Flood) Design" dated November 1,2002.

3. PIP 0-98-3017.

4. Calculation SAAG-81 1, "Evaluation of Risk Associated with Periodic Opening of HPSW Header Isolation Valves."

5. UFSAR Section 3.4.1.1.1, "Current Flood Protection Measures for Turbine and Auxiliary Buildings."

6. PIP 04-5381.

7. PIP 99-1286 CA 29.

8. Drawing series 0-310K and O-310L.

9. OSC-8671, "Aux Bldg Flood Design Values."

10. NSD-415, "Operational Risk Management (MODES 1-3) per 10CFR50.65(a)(4)."

11. WPM-608, "Outage Risk Assessment Utilizing ORAM-Sentinel."

12. WPM-609, "Innage Risk Assessment Utilizing ORAM-Sentinel."

13. NSD-403, "Shutdown Risk Management (MODES 4, 5, 6, and No-MODE) per 1 OCFR50.65(a)(4).

14. WPM-612, "Short Cycle Work Process."

15. NSD-213, "Risk Management Process."

16.9.11a-12 11/15/12 1

AB Flood Protection Measures 16.9.11a Table 16.9.1 la-2 Manual Valves Used in the Auxiliary Building Flood Abnormal Procedure Unit Valve No.

Valve Description Valve Location 0

CCW-460 A & B Chiller CCW Supply Isolation T-1/G-29, 3' NE 0

DW-55 RB/AB Header Supply T-1/M-25, N 12' up 0

FW-15 TB Header Block Water Treatment Room, 15' E of Maintenance Shop door, against wall, 7' up 0

HPSW-959 HPSW Supply to Flow Limiter Block T-1/M-22 Valve 0

LPSW-66 Units 1 & 2 AB AHU Supply T-1/L-32, 2' NW 0

LPSW-260 AB AHU Supply Block T-1/L-32, 4' N o

LPSW-943 Cooling Water Discharge to Storm T-1/Dd-28, 11' SW Drain Isolation 0

LPSW-944 Cooling Water Discharge to CCW T-1/Dd-28, 17'W Isolation 0

LWD-1 173 LPI Sump Isolation Valve T-72, LPI Hatch Room 0

PDW-106 Units 1 & 2 Supply Block A-4, Water Heater Room, N of 2CA & 2CB Battery Room, 6' off of floor 0

PDW-411 AB PDW Supply Isolation T-3/M-32 3

LPSW-500 Unit 3 AHU Return to CCW Discharge T-1I/L-47, NW 12' up 3

LPSW-501 Unit 3 AHU Return to Storm Drains T-1/L-47, W 12' up 3

LPSW-770 AB AHU Supply T-1I/M-46, 8' S 3

LPSW-844 AB AHU Supply T-1I/M-46, 6' SE 3

LWD-1179 LWD DRN ISO TO LPI SUMP RM 81 A-1I/T-87, Unit 3 LPI Hatch 3

LWD-1 180 AHU 3-6 COND DRN ISO A-3W-90a, Unit 3 Cask Decon Rm 16.9.11a-13 11/15/12 1

AB Flood Protection Measures 16.9.11 a Table 16.9.1 la-3 Flow Limiting Valves Valve Flow Limit (gpm)

Equipment Supplied HPSW-960 600 HPSW to Aux Bldg flow limiting valve (Turbine Building Basement Column M-22)

LPSW-845 200 AHU 3, 4, 5 (Unit 1&2 HPI Pump Room)

AHU 6 (Unit 1 LPI Pump Room - Room

61)

AHU 7 (Unit 1&2 LPI Pump Room -

Room #62)

AHU 8 (Unit 2 LPI Pump Room - Room

63)

LPSW-846 700 AHU 9, 10 (Vent. Equip. Room - Elev.

838)

AHU 15, 16 (Vent. Equip. Room - Elev.

822)

AHU 1-19 (Unit 1 West Pen. Room)

AHU 1-20, 1-32, 1-33 (Unit 1 East Pen.

Room) 3LPSW-845 300 AHU 3-7, 3-8 (Vent. Equip. Room -

Elev. 822)

AHU 3-9, 3-10 (Vent. Equip. Room -

Elev. 838)

AHU 3-5, 3-32, 3-33 (Unit 3 East Pen.

Room)

AHU 3-6 (Unit 3 West Pen. Room)

LPSW-1181 120 Unit 1 &2 LPI Rooms AHUs LPSW flow limiter (Aux Building, Rm. 62, Col. S-73) 3LPSW-150 Unit 3 HPI/LPI Room AHU LPSW flow 1176 limiter (Turbine Building, Column M-46) 3LPSW-100 Unit 3 LPI Room 81 AHU 3-1 LPSW 1144 flow limiter (Column S-72 Room 77)

PDW-422 300 Aux Bldg Plant Drinking Water Flow Regulator 16.9.11 a-14 11/15/12 1

AB Flood Protection Measures 16.9.11a Table 16.9.1 la-4 Check Valves Used in the Auxiliary Building Flood Abnormal Procedure Unit Valve No.

Valve Description Valve Location 1&2 LPSW-1101 Unit 1 & 2 HPI/LPI Room LPSW T-1/J-31, 8' SW Return Check Valve 1&2 LPSW-1 182 Unit 1 & 2 LPI Rooms 62 AHU 3-1 Aux. Building, Rm 62, LPSW Return Check Valve Col. S-73, 3' W 3

LPSW-1179 Unit 3 HPI/LPI Room LPSW Return T-I/M-46, 4'S Check Valve 3

LPSW-1 147 Unit 3 LPI Room 81 AHU 3-1 LPSW S-72, Rm 77, HPI Return Check Valve Pump Room 16.9.11a-15 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 16.9 AUXILIARY SYSTEMS 16.9.12 Additional Low Pressure Service Water (LPSW) And Siphon Seal Water (SSW) System OPERABILITY Requirements The following Structures, Systems and Components (SSCs) shall be OPERABLE:

COMMITMENT a.

b.

C.

d.

e.

f.

g.

h.

i.

j.

k.1.

LPSW-4 ("A" LPI COOLER SHELL OUTLET)

LPSW-5 ("B" LPI COOLER SHELL OUTLET)

LPSW Pump Minimum Flow Recirculation Lines LPSW-1 39 (LPSW SUPPLY TO TB NON-ESSENTIAL HDR)

LPSW-251 ("A" LPI COOLER LPSW CONTROL)

LPSW-252 ("B" LPI COOLER LPSW CONTROL)

LPSW flow to each Reactor Building Cooling Unit (RBCU) 2/3LPSW-577 (RB Vent Cooling Coil Al Inlet) 2/3LPSW-582 (RB Vent Cooling Coil A2 Inlet)

LPSW alignment to the RB Auxiliary Cooler (RBAC) Cooling Coils One required SSW Header LPSW Pump(s) required for SSW Header OPERABILITY as defined by TS 3.7.7 APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

LPSW flowpath through A.1 Declare associated LPI Immediately an LPI cooler isolated train inoperable.

by a manual valve.

B.

LPSW-4 inoperable and B.1 Declare associated LPI Immediately

closed, train inoperable.

OR LPSW-5 inoperable and closed.

16.9.12-1 11/15/12 I

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 CONDITION REQUIRED ACTION COMPLETION TIME C.

LPSW flowpath through C.1 Verify all required Immediately an LPI cooler not LPSW Pumps are isolated by manual OPERABLE valve.

AND AND LPSW-4 inoperable and C.2 Restore LPSW-4 to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months not closed.

OPERABLE status.

D.

LPSW flowpath D.1 Verify all required Immediately through an LPI cooler LPSW Pumps are not isolated by OPERABLE.

manual valve.

AND AND D.2 Restore LPSW-5 to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months LPSW-5 inoperable OPERABLE status.

and not closed.

16.9.12-2 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 CONDITION REQUIRED ACTION COMPLETION TIME E.

One required LPSW E.1 Restore required LPSW 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months pump minimum flow pump minimum flow recirculation line recirculation line to inoperable.

OPERABLE status.

OR Two required Unit 3 LPSW Pump minimum flow recirculation lines inoperable OR Two required Unit 1&2 LPSW Pump minimum flow recirculation lines inoperable when two LPSW pumps are required to be OPERABLE by TS 3.7.7.

F.

Two or more Unit 1 and F.1 Declare affected LPSW Immediately 2 LPSW pump Pumps inoperable.

minimum recirculation lines inoperable when three LPSW pumps are required to be OPERABLE by TS 3.7.7.

16.9.12-3 11/15/12 1

Additional Low Pressure Service Water (LPSW)

System OPERABILITY Requirements and Siphon Seal Water (SSW) 16.9.12 CONDITION REQUIRED ACTION COMPLETION TIME

-NOTE ----------

G.1 Verify all required LPSW Immediately If either Unit 1 or Unit 2 is in Pumps are OPERABLE.

the MODE of APPLICA-BILITY, then both 1LPSW-AND 139 and 2LPSW-139 are required to be OPERABLE.

G.2 Restore LPSW-139 to 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months OPERABLE status G.

LPSW-139 inoperable and associated flow path not isolated by a manual valve.

H.

1LPSW-139 inoperable H.1 Verify all required LPSW Immediately and associated flow Pumps OPERABLE.

path not isolated by a manual valve.

AND AND 2LPSW-139 inoperable H.2 Restore LPSW-139 on 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months and associated flow Unit 1 and 2 to path not isolated by a OPERABLE status.

manual valve.

AND Total Unit 1 and 2 LPSW non-essential header flow is less than 10,000 gpm.

16.9.12-4 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 CONDITION REQUIRED ACTION COMPLETION TIME 1LPSW-139 inoperable 1.1 Declare all Unit 1 and 2 Immediately and associated flow LPSW Pumps inoperable.

path not isolated by a manual valve.

AND 2LPSW-139 inoperable and associated flow path not isolated by a manual valve.

AND Total Unit 1 and 2 LPSW non-essential header flow is 10,000 gpm or greater.

J.

LPSW-251 inoperable J.1 Declare associated LPI Immediately and not failed open.

train inoperable.

OR LPSW-252 inoperable and not failed open.

K.

LPSW flow to any K.1 Declare Containment Immediately RBCU is less than 420 inoperable.

gpm.

AND AND K.2 Declare all required Immediately The LPSW inlet LPSW pumps inoperable.

isolation valve for the associated RBCU is not closed.

16.9.12-5 11/15/12 I

I Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 I

CONDITION REQUIRED ACTION COMPLETION TIME NOTE Applicable to Units that do not have RBAC modification installed.

L.

2/3LPSW-577 or 2/3LPSW-582 not open.

AND The "B" RBCU inlet isolation valve (2/3LPSW-19) is not closed.

OR The RBAC Inlet isolation valve (2/3LPSW-565) is not closed.

OR

--NOTE Applicable to Units that have RBAC modification installed.

L. 1 Declare Containment inoperable.

Immediately Immediately AND L.2 Declare all required LPSW pumps inoperable.

2/3LPSW-577 or 2/3LPSW-582 not open.

AND All of the RBAC Supply Header Valves (2/3LPSW-1 051, 1054, 1055, 1058) are not closed.

16.9.12-6 11/15/12 I

Additional Low Pressure Service Water,(LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 CONDITION I

REQUIRED ACTION I COMPLETION TIME

-NOTE --------------

Applicable to Units that do not have RBAC modification installed.

M.

Eight or more RBAC cooling coils isolated by their individual isolation

- valves..

AND The "B" RBCU inlet isolation valve (LPSW-19) is not closed.

OR The RBAC inlet isolation valve (LPSW-565) is not closed.

OR

--NOTE -------

Applicable to Units that have RBAC modification installed.

M.1 Declare Containment inoperable.

I Immediately Immediately AND M.2 Declare all required LPSW pumps inoperable.

Eight or more RBAC cooling coils isolated by their individual isolation valves.

AND All of the RBAC Supply Header Valves (LPSW-1051, 1054, 1055, 1058) are not closed.

16.9.12-7 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 CONDITION REQUIRED ACTION COMPLETION TIME N.

A and B SSW headers N.1 Declare all ECCW Immediately inoperable, headers inoperable.

0.

One SSW header 0.1 Restore A and B SSW 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months inoperable, headers to OPERABLE status.

AND OR One required LPSW Pump inoperable on 0.2 Restore required LPSW 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Unit supplying pump to OPERABLE OPERABLE SSW status.

header as defined by TS 3.7.7.

P.

Required ACTION and P.1 Be in MODE 3.

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months associated Completion Time not met for AND Condition C, D, E, G, H, or 0 P.2 Be in MODE 5.

60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.9.12.1 Test LPSW-4, LPSW-5, LPSW-139, and In accordance with the check valves in the SSW headers in Inservice Testing accordance with the Inservice testing Program Program.

SR 16.9.12.2 Verify that the LPSW pump minimum 'flow 24 months recirculation lines can pass required flow.

16.9.12-8 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 SURVEILLANCE FREQUENCY SR 16.9.12.3 Verify that each RBCU that has an open inlet Every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

isolation valve has LPSW flow that is 420 gpm or greater.

SR 16.9.12.4

NOTE---------------

Only Applicable to Units 2 and 3.

For Units with RBAC modification installed, Prior to entering MODE 4 verify that LPSW-577 and LPSW-582 are from MODE 5.

open, or one of the RBAC Supply Header Valves (LPSW-1 051, 1054, 1055, 1058) is closed.

OR For Units that do not have the RBAC modification installed, verify that LPSW-577 and LPSW-582 are open, or that either valve LPSW-19 or LPSW-565 is closed.

SR 16.9.12.5 For Units that have the RBAC modification Prior to entering MODE 4 installed, verify that 7 or less RBAC cooling from MODE 5.

coils are isolated by their individual isolation valves, or one of the RBAC Supply Header Valve (LPSW-1051, 1054, 1055, 1058) is closed.

OR For Units that do not have the RBAC modification installed, verify that 7 or less RBAC cooling coils are isolated by their individual isolation valves, or that either valves LPSW-19 or LPSW-565 are closed.

16.9.12-9 11/15/12 I

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 BASES BACKGROUND The Low Pressure Service Water (LPSW) System provides cooling water for normal and emergency services throughout the station. Safety related functions served by this system include the Reactor Building cooling units (RBCUs), Low Pressure Injection (LPI) coolers, and coolers for the High Pressure Injection (HPI) and Emergency Feedwater (EFW) motors. LPSW also provides cooling water for the non-safety related Reactor Building Auxiliary Cooling units (RBAC).

The Siphon Seal Water (SSW) System consists of two full capacity headers.

The "A" SSW header is supplied by the Unit 1 and 2 LPSW system. The Unit 3 LPSW System supplies the "B" SSW header. Each SSW header is capable of providing sealing flow to Unit 1, 2 and 3's ESV pumps.

APPLICABLE SAFETY ANALYSES Sufficient LPSW System flow is required to meet the acceptance criteria of containment heat removal safety analyses. In addition, LPSW piping inside containment forms a closed loop. The pressure boundary of this closed loop inside containment must be maintained to ensure containment integrity following an accident or transient.

The analysis to support Generic Letter 96-06 determined the magnitude of the waterhammer pressure pulses in the LPSW System resulting from column closure and condensation induced waterhammers during Loss of Coolant Accident (LOCA) and Main Steam Line Break (MSLB) events (Refs.

15 and 16). The calculation determined that severe waterhammers could occur that are not bounded by existing analysis during a LOCA/LOOP or MSLB/LOOP scenario if the required LPSW flow or alignment is not maintained to the RBCUs and RBACs on the Units that do not have the RBAC modification installed. Per the analysis, a minimum of 30% of normal flow to operating RBCUs (i.e., 420 gpm) is required to prevent waterhammer concerns (Refs. 15 and 16) unless LPSW flow through the RBCU is isolated by closing the RBCU inlet isolation valve. There are no waterhammer concerns with the RBCU inlet isolation valve closed and the associated outlet isolation valve open. If an RBCU is hydraulically isolated by closing.

the inlet and outlet RBCU isolation valves, the isolated piping within containment must be drained or vented to prevent overpressurization during any of the above events. For the Units that have the RBAC modification installed, the LPSW piping to and from the RBACs has been separated from the "B" RBCU piping.

16.9.12-10 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 APPLICABLE SAFETY ANALYSES (continued)

The RBACs contain a total of 16 cooling coils with individual isolation valves.

Valves 2/3LPSW-577 and 2/3LPSW-582 are located in horizontal sections of piping near the RBACs. Column closure waterhammer magnitudes are larger for steam voids that close on hard end points such as valves or dead-ended piping. Large waterhammers, not bounded by existing analysis, could occur during a LOCA/LOOP or MSLB/LOOP if these valves are in the closed position. Thus, valves 2/3LPSW-577 and 2/3LPSW-582 shall be open (Refs. 15, 16, and 17) unless LPSW flow through the RBACs is isolated by closing the RBCU inlet isolation valve (LPSW-19) or the RBAC inlet isolation valve (LPSW-565) on the Units that do not have the RBAC modification installed. On the Units where the RBAC modification is installed, flow through the RBAC is isolated by closing either LPSW-1051, 1054, 1055, or 1058. There are no waterhammer concerns with the RBCU inlet isolation valve (LPSW-19) closed and the associated outlet isolation valve (LPSW-21) open. There are also no waterhammer concerns with the RBAC inlet isolation valve (LPSW-565) closed and the RBCU outlet isolation valve (LPSW-21) open. On the Units where the RBAC modification is installed, there are no waterhammer concerns when either LPSW-1 051, 1054, 1055, or 1058 is closed. If an RBCU is hydraulically isolated by closing the inlet and outlet RBCU isolation valves, the isolated piping within containment must be drained or vented to prevent overpressurization during any of the above events.

If eight (8) or more of the 16 RBAC cooling coils are simultaneously isolated, the resulting higher velocities in the remaining cooling coils and piping could cause larger column closure type waterhammers not bounded by the existing analysis (Ref. 15, 16). Thus, no more than 7 RBAC cooling coils shall be isolated unless LPSW flow through the RBACs are isolated by closing the RBCU inlet isolation valve (LPSW-1 9) or the RBAC inlet isolation valve (LPSW-565) on the Units that do not have the RBAC modification installed. On the Units where the RBAC modification is installed, flow through the RBAC is isolated by closing either LPSW-1051, 1054, 1055, or 1058. There are no waterhammer concerns with the RBCU inlet isolation valve closed and the associated outlet isolation valve open. There are also no waterhammer concerns with the RBAC inlet isolation valve (LPSW-565) closed and the RBCU outlet isolation valve (LPSW-21) open. On the Units where the RBAC modification is installed, there are no waterhammer concerns when either LPSW-1051, 1054, 1055, or 1058 is closed. If an RBCU is hydraulically isolated by closing the inlet and outlet RBCU isolation valves, the isolated piping within containment must be drained or vented to prevent overpressurization during any of the above events.

16.9.12-11 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 APPLICABLE SAFETY ANALYSES (continued)

On the Units that do not have the RBAC modification installed, the "B" RBCU flow is determined using LPSW flow instrumentation shared between the "B" RBCU and RBACs. Hydraulic losses are less in an RBCU when compared to the RBACs. If the "B" RBCU and RBACs are simultaneously in-service, the required flow is 840 gpm (2x420 gpm).

The SSW System is a support system to the ECCW System.

Maintaining the ECCW siphon headers OPERABLE during accident and transient events is an assumption in the accident and transient analysis. The SSW System is required to ensure ECCW siphon header piping remains sufficiently primed to supply siphon flow to the LPSW suction piping.

SSW header OPERABILITY requires that it be supplied from LPSW.

OPERABILITY of an ESV pump requires that it be supplied by at least one OPERABLE SSW header. Each SSW header has a non-safety related HPSW backup. Since the HPSW supply is not safety related, HPSW is not credited to supply the SSW system during a design basis accident. If an ESV pump is operated without seal water, degradation can occur within minutes.

COMMITMENT

" LPSW-4 and LPSW-5 are considered OPERABLE when the valves are capable of being throttled from the Control Room.

" LPSW-1 39 is considered OPERABLE if capable of being closed from the Control Room unless previously closed or isolated.

LPSW-251 and LPSW-252 are considered OPERABLE when they maintain the capability to fail open either as directed from the Control Room or on a loss of Instrument Air.

" The required LPSW alignment is maintained to each out of service RBCU.

" LPSW flow through each RBCU aligned for flow is 420 gpm or greater to support both Containment and LPSW pump operability.

" 2/3LPSW-577 and 2/3LPSW-582 are required to be open or the RBACs isolated with the inlet isolation valve (LPSW-565) closed or the RBCU inlet isolation valve (LPSW-19) closed on the Units that do not have the RBAC modification installed

2/3LPSW-577 and 2/3LPSW-582 are required to be open or the RBACs isolated with at least one of the inlet isolation valves LPSW-1051, 1054, 1055, or 1058 closed on the Units where the RBAC modification has been installed.

7 or less RBAC cooling coils are isolated by their individual isolation valves or the RBACs isolated with the inlet isolation valve (LPSW-565) closed or the RBCU inlet isolation valve (LPSW-1 9) closed on the Units that do not have the RBAC modification installed.

16.9.12-12 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 COMMITMENT

7 or less RBAC cooling coils are isolated by their individual isolation (continued) valves or the RBACs isolated with at least one of the inlet isolation valves LPSW-1 051, 1054, 1055, or 1058 closed on the Units that have the RBAC modification installed.

" The required SSW header is considered OPERABLE when it is supplied from the LPSW system.

" LPSW Pump(s) shall be OPERABLE to support OPERABILITY of the required SSW header as defined by TS 3.7.7.

APPLICABILITY This SLC applies in MODES 1, 2, 3, and 4. This applicability is consistent with the LPSW System OPERABILITY requirements in Technical Specification 3.7.7 and ECCW OPERABILITY requirements in TS 3.7.8. In MODES 5 and 6 the OPERABILITY requirements of the LPSW System are determined by the system it supports.

ACTIONS A.1 If the LPSW flowpath through an LPI cooler is isolated due to a closed manual valve, although LPSW pump NPSH and LPSW flow to other safety related loads would be adequate, LPSW flow to the affected LPI cooler would not be sufficient. The affected LPI train shall be declared inoperable immediately.

B. 1 During normal operation, LPSW flow is isolated to the LPI coolers with block valves LPSW-4 and LPSW-5 in the closed position. If a LOCA occurs, LPSW-4 and LPSW-5 are required to be opened after Reactor Building Emergency Sump (RBES) recirculation is established. If LPSW-4 or LPSW-5 is closed and not capable of throttling LPSW flow, then LPSW pump NPSH and LPSW flow to the other safety related loads would be adequate.

However, the LPSW flow to the affected LPI cooler would not be adequate.

Thus, if LPSW-4 or LPSW-5 is closed and do not have throttle capability, then the affected LPI train shall be declared inoperable immediately.

16.9.12-13 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 ACTIONS C.1, C.2, D.1, D.2 (continued)

If LPSW-4 or LPSW-5 are not closed and do not have throttle capability, OPERABILITY of all required LPSW pumps shall be verified immediately to ensure adequate LPSW pump NPSH and flow to safety related loads. In addition, LPSW-4 and/or LPSW-5 must be restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months completion time is consistent with TS 3.7.7.

For Units 1 & 2, both units would be affected if a valve on either unit is inoperable. In Condition C or D, LPSW pump NPSH and LPSW flow to the safety-related loads may be inadequate. If a single failure of an LPSW pump is not assumed, then sufficient LPSW flow to, and NPSH for, the safety related loads would exist.

E. 1 LPSW-4 and LPSW-5 are not actuated by an ES signal. By maintaining isolation of LPSW flow to the LPI Coolers during the initial phase of a LOCA, the potential exists for the LPSW pumps to be operated below the manufacturer's recommended minimum continuous flow rate. If all LPSW pumps successfully start and operate during the event, the potential exists for a stronger pump to deadhead a weaker pump during low flow conditions. To avoid damaging a pump due to minimum flow concerns, minimum flow recirculation piping exists for each LPSW pump. The minimum flow recirculation lines ensure the OPERABILITY of a deadheaded pump until LPSW-4 or LPSW-5 are open on the LOCA unit after RBES recirculation is established. If an LPSW pump's minimum flow recirculation line is inoperable, the LPSW system cannot withstand a single failure and still be capable of fulfilling its safety function. Thus ACTION must be taken to restore the recirculation line to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months which is consistent with TS 3.7.7.

If both Unit 3 LPSW pump minimum flow recirculation lines are inoperable, the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is still appropriate because the stronger LPSW pump will always have sufficient flow and will maintain operability. Likewise, if the Unit 1 &2 LPSW system is in a condition that only requires two OPERABLE LPSW pumps per TS 3.7.7, the minimum flow recirculation lines associated with both OPERABLE pumps may be simultaneously inoperable for a duration of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . LPSW pump minimum flow recirculation lines are not required to be OPERABLE if the associated pumps are inoperable.

16.9.12-14 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 ACTIONS F. 1 (continued)

If Unit 1 and 2 are in a MODE that requires three OPERABLE LPSW pumps (per TS 3.7.7) and two or more minimum flow recirculation lines are out-of-service, the affected LPSW Pumps shall be declared inoperable imrmiediately.

G. 1, G2 In the event of a LOCA, LPSW-1 39 is credited to close after RBES Recirculation is established, but prior to opening valves LPSW-4 and LPSW-5. Since the Unit 1 & 2 LPSW system is shared, both 1LPSW-139 and 2LPSW-1 39 shall be closed if the non-LOCA unit has tripped due to a concurrent Loss-Of-Offsite-Power (LOOP). Closing LPSW-1 39 maintains sufficient LPSW pump NPSH and adequate LPSW flow to the safety related loads.

If LPSW-139 is not capable of closing and a single failure of an LPSW pump occurs, LPSW pump flow to the safety related loads might be insufficient and LPSW pump NPSH may be inadequate. In this Condition, all required LPSW pumps shall be verified OPERABLE immediately and LPSW-139 shall be restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Since the Unit 1 & 2 LPSW system is shared and 1LPSW-139 and 2LPSW-139 are normally open, the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time applies to both Units 1 and 2 if either 1 LPSW-1 39 or 2LPSW-139 is inoperable.

If all required LPSW pumps are available, LPSW pump NPSH and LPSW flow to the safety-related loads will be sufficient. If 1 LPSW-1 39 or 2LPSW-1 39 is closed or isolated by system block valves, e.g. for maintenance during a unit outage, remote closure capability of the valve is not required.

H.1, H.2 If both 1LPSW-139 and 2LPSW-139 are inoperable and not isolated by a manual valve, and total Unit 1 & 2 LPSW non-essential header flow is less than 10,000 gpm, OPERABILITY of all required LPSW pumps shall be verified immediately to ensure that there will be sufficient LPSW pump flow to, and NPSH for safety related loads. Additionally, 1 LPSW-1 39 and 2LPSW-139 must be restored to OPERABLE status within the stated 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time.

16.9.12-15 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 ACTIONS 1.1 (continued)

If 1LPSW-139 and 2LPSW-139 are inoperable and not isolated by a manual valve, and total Unit 1 & 2 LPSW non-essential header flow is greater than 10,000 gpm, sufficient LPSW pump flow to, and NPSH for the safety related loads would not be available, even with all three LPSW pumps available.

Consequently, all of the Unit 1 and 2 LPSW pumps shall be declared inoperable immediately.

J.1 Air operated valves LPSW-251 and LPSW-252 are the normal LPI cooler flow control valves. The control valves fail open on a loss of Instrument Air (IA). If a LOCA occurs, IA and Auxiliary Instrument Air (AIA) are assumed unavailable since they are not safety related. With LPSW-251 and LPSW-252 failed open, LPSW-4 and LPSW-5 are credited for throttling LPI cooler shell side flow to maintain sufficient LPSW pump Net Positive Suction Head (NPSH) and adequate LPSW flow to the safety related loads. LPSW-251 and LPSW-252 may also be failed open by placing the Fail Switch in the FAIL OPEN position or by isolating instrument air to the valve actuator and bleeding air pressure from the actuator. Should either LPSW-251 or LPSW-252 become inoperable and not fail open, the associated LPI train shall be declared inoperable immediately.

K.1, K.2 If a LOCA/LOOP or MSLB/LOOP were to occur while in this Condition, the integrity of the LPSW flowpath, as well as containment, can not be assured.

Consequently, either the affected RBCU inlet isolation valve must be closed, or all required LPSW pumps and containment shall be immediately declared inoperable. Large waterhammers, not bounded by existing analysis, could occur in LPSW piping that does not maintain the required LPSW alignment to the RBCUs.

In order to hydraulically isolate a RBCU without causing a waterhammer, the RBCU inlet LPSW isolation valve (i.e. LPSW-16,-19,-22) must be closed prior to closing the outlet LPSW isolation valve. For the purposes of this SLC Condition, LPSW-566 is not considered an RBCU inlet isolation valve on the Units that do not have the RBAC modification installed. The RBCU isolated piping must be vented to containment or drained to preclude thermal over-pressurization.

16.9.12-16 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 ACTIONS L.1 L.2 (continued)

A NOTE is added to specify that the following is true on the Units that do not have the RBAC modification installed:

If a LOCA/LOOP or MSLB/LOOP were to occur while in this Condition, large water hammers could occur that would challenge the integrity of the LPSW flowpath as well as containment.

Consequently, either (1) the "B" RBCU inlet isolation valve (LPSW-

19) must be closed or RBAC inlet isolation valve (LPSW-565) must be closed, or (2) all required LPSW pumps and containment shall be immediately declared inoperable.

In order to hydraulically isolate a RBCU without causing a waterhammer, the "B" RBCU inlet isolation valve (LPSW-19) must be closed prior to closing the outlet LPSW isolation valve. For the purposes of this SLC Condition, LPSW-566 is not considered an RBCU inlet isolation valve. The RBCU isolated piping must be vented to containment or drained to preclude thermal over-pressurization.

A NOTE is added to specify that the following is true on the Units that have the RBAC modification installed:

If a LOCA/LOOP or MSLB/LOOP were to occur while in this Condition, large water hammers could occur that would challenge the integrity of the LPSW flowpath as well as containment.

Consequently, either (1) one of the RBAC Supply Header Valves (LPSW-1051, 1054, 1055, or 1058) must be closed, or (2) all required LPSW pumps and containment shall be immediately declared inoperable.

16.9.12-17 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 ACTIONS M.1, M.2 (continued)

A NOTE is added to specify that the following is true on the Units that do not have the RBAC modification installed.

If a LOCA/LOOP or MSLB/LOOP were to occur while in this Condition, large water hammers could occur that would challenge the integrity of the LPSW flowpath as well as containment.

Consequently, either the (1) "B" RBCU inlet isolation valve (LPSW-

19) must be closed or RBAC inlet isolation valve (LPSW-565) must be closed, or (2) all required LPSW pumps and containment shall be immediately declared inoperable.

In order to hydraulically isolate a RBCU without causing a waterhammer, the "B" RBCU inlet isolation valve (LPSW-19) must be closed prior to closing the outlet LPSW isolation valve. For the purposes of this SLC Condition, LPSW-566 is not considered an RBCU inlet isolation valve. The RBCU isolated piping must be vented to containment or drained to preclude thermal over-pressurization.

A NOTE is added to specify that the following is true on the Units that have the RBAC modification installed:

If a LOCA/LOOP or MSLB/LOOP were to occur while in this Condition, large water hammers could occur that would challenge the integrity of the LPSW flowpath as well as containment.

Consequently, either (1) one of the RBAC Supply Header Valves (LPSW-1051, 1054, 1055, or 1058) must be closed, or (2) all required LPSW pumps and containment shall be immediately declared inoperable.

N.1 One SSW header shall be OPERABLE to support the ESV pumps and ECCW siphon headers. If no SSW header is OPERABLE, all ECCW siphon headers are inoperable.

16.9.12-18 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 ACTIONS 0.1,0.2 (continued)

At least one SSW header is required to be OPERABLE and aligned to the ESV pumps. TS 3.7.7 requires OPERABILITY of the LPSW Pumps and allows one required LPSW pump on each LPSW System to be inoperable for a limited duration. OPERABILITY of the SSW headers requires OPERABILITY of the LPSW Pumps as allowed by TS 3.7.7. If one required LPSW pump is inoperable on the LPSW System supplying the required SSW header and only one SSW header is OPERABLE, the ESV system is not single failure proof. ACTION must be taken to either restore the inoperable SSW header to OPERABLE status or restore the required LPSW Pump to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . Reference Bases table 16.9.12-1. The 72-hour Completion Time is consistent with the Completion Times for LPSW and ESV. If both SSW headers are OPERABLE and aligned to each ESV pump and one required LPSW pump is out of service on the Unit 1 and 2 and/or Unit 3 LPSW System, the SSW supply to the ESV pumps is single failure proof and no Condition entry is required.

P.1, P.2 If the Required ACTION and associated Completion Times of Conditions C, D, E, G, H or 0 are not met, the unit must be placed in a MODE in which the SLC does not apply, i.e., in at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and MODE 5 within 60 hours6.944444e-4 days 0.0167 hours 9.920635e-5 weeks 2.283e-5 months . These Completion Times are consistent with the Completion Times for LPSW and ESV.

SURVEILLANCE SR 16.9.12.1 REQUIREMENTS This SR requires that LPSW-4, LPSW-5, LPSW-139, and check valves in the SSW headers be tested per Oconee's ASME Section XI IST Program. Testing under this program is adequate to assure OPERABILITY.

SR 16.9.12.2 This SR requires that the LPSW pump minimum flow recirculation lines be tested every 24 months. A 24 month frequency is adequate to ensure significant degradation has not occurred due to service water related fouling.

16.9.12-19 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 SURVEILLANCE SR 16.9.12.3 REQUIREMENTS (continued)

This SR requires that LPSW flow to each RBCU that is not isolated from LPSW flow be verified once per shift to be > 420 gpm. The inlet or outlet LPSW flow gauge may be used.

This surveillance can also be met by verifying one of the following system alignments:

1.

The RBCU inlet and outlet LPSW motor operated isolation valves are full open and the required LPSW pumps are in operation.

2.

The RBCU inlet LPSW isolation valve is closed and the outlet isolation valve is open.

3.

The RBCU inlet and outlet LPSW isolation valves are closed with the RBCU piping vented to containment or drained. If the RBCU outlet is isolated with its ES actuated valve, its breaker shall be open to prevent the valve from automatically opening on ES.

This frequency is adequate to ensure the required alignment is maintained.

SR 16.9.12.4 On the Units that do not have the RBAC modification installed, this SR requires that LPSW-577 and LPSW-582 (Units 2 & 3 only) are verified open or that either LPSW 19 or LPSW-565 is closed prior to entering MODE 4 from MODE 5.

On the Units that have the RBAC modification installed, this SR requires that LPSW-577 and LPSW-582 (Units 2 & 3 only) are verified open or that one of the RBAC Supply Header Valves (LPSW-1 051, 1054, 1055, or 1058) is closed prior to entering MODE 4 from MODE 5.

SR 16.9.12.5 On the Units that do not have the RBAC modification installed, this SR requires that no more than 7 RBAC cooling coils are isolated by their individual isolation valves or that either LPSW-1 9 or LPSW-565 is closed prior to entering MODE 4 from MODE 5.

On the Units that have the RBAC modification installed, this SR requires that no more than 7 RBAC cooling coils are isolated by their individual isolation valves or that one of the RBAC Supply Header Valves (LPSW-1 051, 1054, 1055, or 1058) is closed prior to entering MODE 4 from MODE 5.

16.9.12-20 11/15/121

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW)

System OPERABILITY Requirements 16.9.12 REFERENCES

1.

OSS-0254.00-00-1039, Design Basis Specification for the Low Pressure Service Water System, rev. 26.

2.

OSC-2280, LPSW Pump NPSH and Minimum Required Lake Level, rev.

16.

3.

OSC-4672, Unit 1&2 LPSW System Response to a Large Break LOCA Using a Benchmarked Computer Hydraulic Model, rev. 9

4.

OSC-4489, Predicted Unit 3 LPSW System Response to a Large Break LOCA Using a Benchmarked Computer Hydraulic Model, rev. 7.

5.

PT/1/A/0251/023, LPSW System Flow Test, performed on 11/16/97.

6.

PT/2/A/0251/023, LPSW System Flow Test, performed on 4/20/96.

7.

PT/3/A/0251/023, LPSW System Flow Test, performed on 1/19/97.

8.

PT/1,3/A/0251/01, LPSW Pump Test.

9. TS 3.5.3, 3.7.7 and 3.7.8.

10. Oconee UFSAR Section 9.2.2, 12/31/02 update.

11. Letter from J. W. Hampton, (DPC), to USNRC, dated June 6, 1996, Proposed Technical Specification amendment for LPSW-4, -5.

12. NRC Safety Evaluation Report, dated August 19, 1996, Technical Specification Amendment 217/217/214.

13. Operability Evaluation of PIP 98-3629, RBCU Minimum Flow Rate Requirements.

14. OSC-7445.05, Waterhammer Analysis of Reactor Building Cooling Units, rev. 0.

15. OSC-7445.06, Waterhammer Analysis of Reactor Building Cooling Units, rev. 0.

16. Letter from Altran Corporation to Timothy Brown dated 12/30/98, "Letter Report: Response to Additional Items for Waterhammer."

17. OSC-5409 rev. 7, Single Failure Analysis of the ECCW System Supply to the LPSW System.

18. Letter from Gregory Zysk of Altran Corporation to Timothy Brown dated 11/14/01, "GL 96-06 Concerns for the Isolation of an RBCU at Power."

(correspondence file OS-293)

19. Letter from Gregory Zysk of Altran Corporation to Timothy Brown dated 02/20/02, "Effects of RBCU Isolation." (correspondence file OS-293) 16.9.12-21 11/15/12 1

Additional Low Pressure Service Water (LPSW) and Siphon Seal Water (SSW),--,.

System OPERABILITY Requirements 16.9.12 TABLE 16.9.12-1 Operability Status of SSW Headers Both SSW Headers "A" SSW Header "B" SSW Header Operable Inoperable Inoperable One Required 72 hr Required Action 72 hr Required 72 hr Required LPSW Pump Completion Time on Action Completion Action Completion Inoperable on Unit 1 and 2 per TS Time on Unit 1 and 2 Time on Unit 1 and 2 Unit 1 and 2 3.7.7.

per TS 3.7.7.

0 72 hr Required Action Completion Time on Unit 1,2, and 3, per this SLC.

One Required 72 hr Required Action

° 72 hr Required 72 hr Required LPSW Pump Completion Time on Action Completion Action Completion Inoperable on Unit 3 per TS 3.7.7.

Time on Unit 3 per Time on Unit 3 per Unit 3 TS 3.7.7.

TS 3.7.7.

72 hr Required Action Completion Time on Unit 1, 2, and 3, per this SLC.

NOTE: Table assumes Unit 1, 2, and 3 are in Mode 1, 2, 3, or 4.

16.9.12-22 11/15/12 I

Local Start of Turbine-Driven EFW Pump 16.10.1 16.10 STEAM AND POWER CONVERSION SYSTEMS 16.10.1 Local Start of Turbine Driven Emergency Feedwater (EFW) Pump COMMITMENT:

Local start capability of the Turbine Driven EFW pump shall be maintained.

APPLICABILITY:

MODES 1, 2, and 3 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

Commitment not met.

A.1 Initiate action to restore local Immediately start capability of the turbine driven EFW pump.

AND A.2 Restore local start capability 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months of the turbine driven EFW pump.

B.

Required Action and B.1 Submit report to the NRC 30 days associated Completion outlining plans to restore Time not met.

local start capability of the turbine driven EFW pump.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.10.1.1 Start the Turbine Driven Emergency 24 months Feedwater Pump (TDEFWP) in local manual operation.

BASES Local manual start capability is a design feature of the Turbine Driven EFW Pump (TDEFWP).

Following a High Energy Line Break (HELB) local start of the TDEFWP may provide an alternate source of secondary cooling water to an OTSG (in addition to that which could be provided by EFW from another unit or SSF ASW). Providing an alternate source of OTSG cooling within 15 minutes following a HELB is considered a Time Critical Operator Action (TCOA) in accordance with HELB commitments to the NRC in Report No. OS-73.2.

16.10.1-1 11/15/12 I

Local Start of Turbine-Driven EFW Pump 16.10.1 BASES (continued)

Applicability in MODES 1, 2, and 3 is consistent with operability requirements for the TDEFWP in LCO 3.7.5. The TDEFWP is not required to be operable in Mode 4.

The required action completion time of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is comparable with that of the TDEFWP in TS LCO 3.7.5 and would be available for making necessary repairs.

The 24 month Surveillance Frequency for verifying TDEFWP local manual start capability is considered adequate.

REFERENCES

1.

UFSAR, Section 10.4.7.2.2, "Turbine Driven EFW Pump (TDEFWP)."

2.

UFSAR, Section 10.4.7.3.2, "EFW Response Following a HELB."

3.

UFSAR, Section 3.6.1.3, "Safety Evaluation."

4.

OSS-0254.00-00-1000, Design Basis Specification for the Emergency Feedwater and the Auxiliary Service Water Systems.

5.

OSS-0254.00-00-4005, Design Basis Specification for the Design Basis Event.

6.

OSC-7299, HELB Analysis.

7.

Duke Letter to NRC, Thies to Giambusso (Report No. OS-73.2) dated April 25, 1973.

8.

Duke Letter to NRC, Thies to Giambusso (Supplement 1 to Report No. OS-73.2) dated June 22, 1973.

16.10.1-2 11/15/12 1

LPSW System Testing 16.10.4 16.10 STEAM AND POWER CONVERSION SYSTEMS 16.10.4 Low Pressure Service Water (LPSW) System Testing COMMITMENT APPLICABILITY:

Manually align valves LPSW-4 and LPSW-5 from the control room to demonstrate OPERABILITY of the Low Pressure Injection Coolers.

MODES 1, 2, 3 and 4 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A.

A.1 N/A.

N/A SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.10.4.1 Verify valves LPSW-4 and LPSW-5 actuate to ---------

NOTE------

the correct position upon manual actuation The provisions of SLC from the control room.

16.2.7 do not apply.

24 months +25%

BASES The requirement(s) of this SLC section were relocated from CTS 4.5.1.1.2.a(2) during the conversion to ITS.

SR 16.10.4.1 verifies that LPSW-4 and -5 (LPSW supply to LPI coolers) respond as required to manual alignment from the control room. The test will be considered satisfactory if valves LPSW-4 and LPSW-5 have completed their travel.

REFERENCES N/A 16.10.4-1 11/15/12 1

APSR Movement 16.14.1 16.14 CONTROL RODS AND POWER DISTRIBUTION 16.14.1 APSR Movement COMMITMENT APPLICABILITY:

Perform specified SR.

MODES 1 and 2 ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A.

A.1 N/A.

N/A SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.14.1.1 Verify that loss of power will not cause APSR NOTE-----

movement.

The provisions of SLC 16.2.7 do not apply.

24 months +25%

BASES The requirement(s) of this SLC section were relocated from CTS 4.7.1 during the conversion to ITS.

REFERENCES N/A 16.14.1-1 11/15/12 1

Control Room Pressurization and Filtering System 16.15.2 16.15 VENTILATION FILTER TESTING PROGRAM 16.15.2 Control Room Pressurization and Filtering System COMMITMENT APPLICABILITY:

Perform specified Surveillance Requirements.

MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A.

A.1.1 N/A.

N/A.

SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.15.2.1 Verify carbon sample removed from the 31 days after removal of Control Room Booster Fan train Filters carbon sample provide >_ 97.5% radioactive methyl iodide removal when tested in accordance with ASTM D3803-1989 (300C, and 95% R.H.).

SR 16.15.2.2 Verify pressure drop across pre-filters is _< 1 92 days inch of water and pressure drop across HEPA filters is _< 2 inches of water when tested in accordance with ANSI N510-1975 at system design flow (+/-10%).

(continued) 16.15.2-1 11/15/12 1

Control Room Pressurization and Filtering System 16.15.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE I

FREQUENCY SR 16.15.2.3 Verify Control Room Booster Fan train HEPA filters provide _> 99.5% DOP removal when tested in accordance with ANSI N510-1975 at system design flow +/- (10%).

NOTE ------------

The provisions of SLC 16.2.7 do not apply.

24 months +25%

AND Once after each complete or partial replacement of a HEPA filter bank AND Once after any structural maintenance on the system housing AND Once after painting, fire, or chemical release in any ventilation zone communicating with the system (continued) 16.15.2-2 11/15/12 1

Control Room Pressurization and Filtering System 16.15.2 SURVEILLANCE REQUIREMENTS (continued)

SURVEILLANCE FREQUENCY SR 16.15.2.4 Verify Control Room Booster Fan train charcoal adsorber filters provide _> 99%

halogenated hydrocarbon removal when tested in accordance with ANSI N510-1975 at system design flow +/- (10%).

NOTE------

The provisions of SLC 16.2.7 do not apply.

24 months +25%

AND Once after each complete or partial replacement of a charcoal adsorber bank AND Once after any structural maintenance on the system housing AND Once after painting, fire, or chemical release in any ventilation zone communicating with the system 16.15.2-3 11/15/12 1

Control Room Pressurization and Filtering System 16.15.2 SURVEILLANCE FREQUENCY SR 16.15.2.5 Remove carbon samples from Control Room NOTE------

Booster Fan trains for laboratory analysis The provisions of SLC 16.2.7 do not apply.

24 months +25%

AND Once after 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of system operation AND Once after painting, fire or chemical release in any ventilation zone communicating with the system BASES The requirement(s) of this SLC section were relocated from CTS 4.12 during the conversion to ITS. This SLC also includes the Ventilation Filter Testing Program requirements for the Control Room Booster Fan train filters specified in ITS 5.5.12, Ventilation Filter Testing Program.

Surveillance Requirements 16.15.2.2, 16.15.2.3 and 16.15.2.4 require filter testing to be performed in accordance with ANSI N510-1975 at system design flow +/-10%. The system flow measurement methods are based on the recommendations of the ACGIH Industrial Ventilation Manual and the physical limitations of the installed duct system. Flow measurements meet the intent and requirements of ANSI N510-1975. Flow through the filter is measured in the Auxiliary Building near the filter inlet and flow balance between the north and south intakes is measured on the roof of the Turbine Building.

The purpose of the control room pressurization filtering system is to protect the control room operators from the effects of accidental release of radioactive effluents or toxic gases in the Turbine Building or Auxiliary Building only. The system is designed with two 50 percent capacity filter trains each of which consists of a prefilter, high efficiency particulate filters, carbon filters, booster fans, air handling unit fans, and associated ductwork to pressurize the control room with outside air.

Since these systems are not normally operated, a periodic test is required to ensure their operability when needed. Quarterly testing of this system will show that the system is available.

16.15.2-4 11/15/12 I

Control Room Pressurization and Filtering System 16.15.2 Refueling frequency testing of the installed carbon adsorber stage and absolute filters will verify the leak integrity of the cleanup system.

REFERENCES N/A 16.15.2-5 11/15/12 I

Spent Fuel Pool Ventilation System 16.15.3 16.15 VENTILATION FILTER TESTING PROGRAM 16.15.3 Spent Fuel Pool Ventilation System COMMITMENT APPLICABILITY:

Perform specified Surveillance Requirements During movement of recently irradiated fuel within the spent fuel storage pool.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

N/A A.1 N/A N/A SURVEILLANCE REQUIREMENTS SURVEILLANCE FREQUENCY SR 16.15.3.1 Verify carbon sample removed from the 31 days after removal of Reactor Building Purge Filters provide _> 90%

carbon sample radioactive methyl iodide removal when tested in accordance with ASTM D3803-1989 (30 0C, and 95% R.H.).

SR 16.15.3.2 Verify each Spent Fuel Ventilation fan NOTE------

operates at design flow (+/-10%) when tested in The provisions of SLC accordance with ANSI N510-1975.

16.2.7 do not apply.

24 months +25%

(continued) 16.15.3-1 11/15/12 I

Spent Fuel Pool Ventilation System 16.15.3 SURVEILLANCE FREQUENCY 4

SR 16.15.3.3 Remove carbon sample from Reactor Building Purge Filters for laboratory analysis.

NOTE------

The provisions of SLC 16.2.7 do not apply.

24 months +25%

AND Once after 720 hours0.00833 days 0.2 hours 0.00119 weeks 2.7396e-4 months of system operation AND Once after painting, fire, or chemical release in any ventilation zone communicating with the System (continued) 16.15.3-2 11/15/12 1

Spent Fuel Pool Ventilation System 16.15.3 SURVEILLANCE FREQUENCY i

SR 16.15.3.4 Verify Reactor Building purge HEPA filters provide > 99% DOP removal when tested in accordance with ANSI N510-1975 at design flow (+/- 10%).

NOTE---

The provisions of SLC 16.2.7 do not apply.

24 months +25%

AND Once after each complete or partial replacement of HEPA filter bank AND Once after any structural maintenance on the system housing AND Once after painting, fire, or chemical release in any ventilation zone communicating with the system (continued) 16.15.3-3 11/15/12 1

Spent Fuel Pool Ventilation System 16.15.3 SURVEILLANCE FREQUENCY SR 16.15.3.5 Verify Reactor Building purge charcoal adsorber filters provide >_ 99% halogenated hydrocarbon removal when tested in accordance with ANSI N510-1975 at design flow (+/- 10%).

NOTE------

The provisions of SLC 16.2.7 do not apply.

24 months +25%

AND Once after each complete or partial replacement of charcoal adsorber bank AND Once after any structural maintenance on the system housing AND Once after painting, fire, or chemical release in any ventilation zone communicating with the system BASES The requirement(s) of this SLC section were relocated from CTS 4.14 during the conversion to ITS. This SLC also includes the Ventilation Filter Testing Program requirements for the Spent Fuel Pool Ventilation System specified in ITS 5.5.12, Ventilation Filter Testing Program.

With the adoption of the Alternate Source Term and installation of various plant modifications, Spent Fuel Pool Ventilation System (SFPVS) is not credited in dose analysis calculations. The dose analysis for all analyzed Fuel Handling Accidents does not assume operation of the SFPVS in order to meet the requirements of 10 CFR 50.67. These assumptions and the analyses are consistent with the guidance in Regulatory Guide 1.183.

The Unit 2 Reactor Building purge filter is used in the ventilation system for the common spent fuel pool for Units 1 and 2. The Unit 3 Reactor Building purge filter is used in the Unit 3 spent fuel pool ventilation system. Each filter is constructed with a prefilter, an absolute filter and a 16.15.3-4 11/15/12 I

Spent Fuel Pool Ventilation System 16.15.3 charcoal filter in series. The high efficiency particulate air (HEPA) filters are installed before the charcoal adsorbers to prevent clogging of the iodine adsorbers. The charcoal adsorbers are installed to reduce the potential release of radioiodine.

Bypass leakage for the charcoal adsorbers and particulate removal efficiency for HEPA filters are determined by halogenated hydrocarbon and DOP respectively. The laboratory carbon sample test results indicate a radioactive methyl iodide removal efficiency for expected accident conditions. Operation of the fans significantly different from the design flow will change the removal efficiency of the HEPA filters and charcoal adsorbers. If the performances are as specified, the doses for a fuel handling accident involving 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 ) assemblies would be minimized.

The frequency of tests and sample analysis are necessary to show that the HEPA filters and charcoal adsorbers can perform as evaluated. Replacement adsorbent should be qualified according to the guidelines of Regulatory Guide 1.52. The charcoal adsorber efficiency test procedures should allow for the removal of one adsorber tray, emptying of one bed from the tray, mixing the adsorbent thoroughly and obtaining at least two samples. Each sample should be replaced. Any HEPA filters found defective should be replaced with filters qualified pursuant to Regulatory Position C.3.d of Regulatory Guide 1.52.

Operation of the spent fuel pool ventilation system every month will demonstrate operability of the fans, filters and adsorber system.

If painting, fire or chemical release occurs during system operation such that the HEPA filter or charcoal adsorber could become contaminated from the fumes, chemicals or foreign materials, the same tests and sample analysis should be performed as required for operational use.

REFERENCES

1. Regulatory Guide 1.52, Rev. 2.

2. ITS 5.5.12, Ventilation Filter Testing Program

3. Amendment 338, 339, & 339, Renewed Facility Operating Licenses DPR-38, DPR-47 and DPR-55 dated June 1, 2004.

16.15.3-5 11/15/12 1

ML12349A264

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ML12349A264

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5.1 REFERENCES

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