Text

Technical Specification Bases Revision
	ML032670598
Person / Time
Site:	Mcguire, McGuire
Issue date:	09/16/2003
From:	Gordon Peterson; Duke Power Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	Download: ML032670598 (60)
	v • d • e

i ~ '4 i ^ Duke GARY R. PETERSON rSPowert Vice President A Duke Energy Company McGuire Nuclear Station Duke Power MG01 VP / 12700 Hagers Ferry Road Huntersville, NC 28078-9340 704 875 5333 704 875 4809 fax grpeters@duke-energy. corn September 16, 2003 United States Nuclear Regulatory Commission ATTENTION: Document Control Desk Washington, DC 20555-0001

SUBJECT:

Duke Energy Corporation McGuire Nuclear Station Units 1 and 2 Docket Nos. 50-369 and 50-370 Technical Specification Bases Revision Attached are revisions to the McGuire Technical Specification (TS) Bases. These revisions are being furnished to you per the requirements of TS 5.5.14.

TS Bases 3.5.2, Emergency Core Cooling System (ECCS) -

Operating, is revised to clarify the method of verifying ECCS piping full of water.

TS Bases 3.8.1, Alternating Current (AC) Sources -

Operating, and 3.8.2, AC Sources - Shutdown, are revised to clarify the terms load sequencing, load shedding, tripping of non-essential loads and sequencing time and their effect on emergency diesel generator, sequencer and safety AC bus operability.

Attachment 1 contains the revised TS List of Effective Pages/Sections. Attachment 2 contains revised TS Bases 3.5.2, 3.8.1, and 3.8.2.

Please contact P.T. Vu at (704) 875-4302 if you have any questions regarding this submittal.

Very truly yours, G. R. Peterson GRP/PTV/s Attachments www. duke-energy. corn

I i

U. S. Nuclear Regulatory Commission September 16, 2003 Page 2 xc (w/attachments):

L. A. Reyes U. S. Nuclear Regulatory Commission Regional Administrator, Region II Atlanta Federal Center 61 Forsyth St., SW, Suite 23T85 Atlanta, GA 30303 R. E. Martin U. S. Nuclear Regulatory Commission Mail Stop 0-8G9 One White Flint North 11555 Rockville Pike Rockville, MD 20852-2738 J. B. Brady Senior Resident Inspector U. S. Nuclear Regulatory Commission McGuire Nuclear Station B. 0. Hall, Chief Division of Radiation Protection 1645 Mail Service Center Raleigh, NC 27699-1645

X ATTACHMENT 1 REVISED TS LIST OF EFFECTIVE PAGES/SECTIONS

McGuire Nuclear Station Technical Specifications Ust of Affected Pages / Sections Page Number Amendment Revision Date 184/166 9/30/98 ii 184/166 9/30/98 iii 184/166 9/30/98 iv 184/166 9/30/98 1.1-1 184/166 9/30/98 1.1-2 184/166 9/30/98 1.1-3 206/187 8/23/02 1.1-4 194/175 9/18100 1.1-5 206/187 8/23/02 1.1-6 206/187 8/23/02 1.1-7 194/175 9/18/00 1.2-1 184/166 9/30/98 1.2-2 184/166 9/30/98 1.2-3 184/166 9/30/98 1.3-1 184/166 9/30/98 1.3-2 184/166 9/30/98 1.3-3 184/166 9/30/98 1.3-4 184/166 9/30/98 1.3-5 184/166 9/30/98 1.3-6 184/166 9/30/98 1.3-7 1841166 9/30/98 1.3-8 184/166 9/30/98 1.3-9 184/166 9/30198 1.3-10 184/166 9/30/98 1.3-11 184/166 9/30/98 1.3-12 184/166 9/30/98 1.3-13 184/166 9/30/98 1.4-1 184/166 9/30/98 1.4-2 184/166 9/30/98 1.4-3 184/166 9/30/98 1.4-4 184/166 9/30/98 McGuire Units 1 and 2 Page Revision 43

Page Number Amendment Revision Date 2.0-1 184/166 9/30/98 2.0-2 191/172 3/20/00 3.0-1 184/166 9/30/98 3.0-2 184/166 9/30/98 3.0-3 184/166 9/30/98 3.0-4 205/186 8/12/02 3.0-5 184/166 9/30/98 3.1.1-1 184/166 9/30/98 3.1.2-1 184/166 9/30/98 3.1.2-2 184/166 9/30/98 3.1.3-1 184/166 9/30/98 3.1.3-2 184/166 9/30/98 3.1.3-3 184/166 9/30/98 3.1.4-1 184/166 9/30/98 3.1.4-2 184/166 9/30/98 3.1.4-3 184/166 9/30/98 3.1.4-4 1861167 9/8/99 3.1.5-1 184/166 9/30/98 3.1.5-2 184/166 9/30/98 3.1.6-1 184/166 9/30/98 3.1.6-2 184/166 9/30/98 3.1.6-3 184/166 9/30/98 3.1.7-1 184/166 9/30/98 3.1.7-2 184/166 9/30/98 3.1.8-1 184/166 9/30/98 3.1.8-2 184/166 9/30/98 3.2.1-1 184/166 9/30/98 3.2.1-2 184/166 9/30/98 3.2.1-3 184/166 9/30/98 3.2.1-4 188/169 9/22/99 3.2.1-5 188/169 9/22/99 3.2.2-1 184/166 9/30/98 3.2.2-2 184/166 9/30/98 McGuire Units 1 and 2 Page 2 Revision 43

Page Number Amendment Revision Date 3.2.2-3 184/166 9/30/98 3.2.2-4 188/169 9/22/99 3.2.3-1 184/166 9/30/98 3.2.4-1 184/166 9/30/98 3.2.4-2 184/166 9/30/98 3.2.4-3 184/166 9/30/98 3.2.4-4 184/166 9/30/98 3.3.1-1 184/166 9/30/98 3.3.1-2 184/166 9/30/98 3.3.1-3 184/166 9/30/98 3.3.1-4 184/166 9/30/98 3.3.1-5 184/166 9/30/98 3.3.1-6 184/166 9/30/98 3.3.1-7 184/166 9/30/98 3.3.1-8 184/166 9/30/98 3.3.1-9 184/166 9/30/98 3.3.1-10 184/166 9/30/98 3.3.1-11 184/166 9/30/98 3.3.1-12 184/166 9/30/98 3.3.1-13 184/166 9/30/98 3.3.1 -14 194/175 9/18/00 3.3.1-15 194/175 9/1 8/00 3.3.1-16 194/175 9/18/00 3.3.1-17 194/175 9/18/00 3.3.1-18 202/183 5/23/02 3.3.1 -19 202/183 5/23/02 3.3.1-20 184/166 9/30/98 3.3.2-1 184/166 9/30/98 3.3.2-2 184/166 9/30/98 3.3.2-3 184/166 9/30/98 3.3.2-4 184/166 9/30/98 3.3.2-5 184/166 9/30/98 3.3.2-6 198/179 4/12/01 McGuire Units 1 and 2 Page 3 Revision 43

Page Number Amendment Revision Date 3.3.2-7 198/179 4/12/01 3.3.2-8 184/166 9/30/98 3.3.2-9 184/166 9/30/98 3.3.2-10 194/175 9/18/00 3.3.2-11 194/175 9/18/00 3.3.2-12 194/175 9/18/00 3.3.2-13 198/179 4/12/01 3.3.2-14 194/175 9/18/00 3.3.2-15 184/166 9/30/98 3.3.3-1 184/166 9/30/98 3.3.3-2 184/166 9/30/98 3.3.3-3 184/166 9/30/98 3.3.3-4 184/166 9/30/98 3.3.4-1 184/166 9/30/98 3.3.4-2 184/166 9/30/98 3.3.4-3 184/166 9/30/98 3.3.5-1 184/166 9/30/98 3.3.5-2 194/175 9/18/00 3.3.6-1 184/166 9/30/98 3.3.6-2 184/166 9/30/98 3.3.6-3 194/175 9/18/00 3.4.1-1 191/172 3/20/00 3.4.1-2 191/172 3/20/00 3.4.1-3 184/166 9/30/98 3.4.1-4 191/172 3/20/00 3.4.2-1 184/166 9/30/98 3.4.3-1 214/195 7/3/03 3.4.3-2 184/166 9/30/98 3.4.3-3 214/195 7/3/03 3.4.3-4 214/195 7/3/03 3.4.3-5 214/195 7/3/03 3.4.3-6 214/195 7/3/03 3.4.3-7 214/195 7/3/03 McGuire Units and 2 Page 4 Revision 43

Page Number Amendment Revision Date 3.4.3-8 214/195 7/3/03 3.4.4-1 184/166 9/30/98 3.4.5-1 184/166 9/30/98 3.4.5-2 184/166 9/30/98 3.4.5-3 184/166 9/30/98 3.4.6-1 184/166 9/30/98 3.4.6-2 184/166 9/30/98 3.4.7-1 184/166 9/30198 3.4.7-2 184/166 9/30/98 3.4.8-1 184/166 9/30/98 3.4.8-2 184/166 9/30/98 3.4.9-1 184/166 9/30/98 3.4.9-2 184/166 9/30/98 3.4.10-1 184/166 9/30/98 3.4.10-2 184/166 9/30/98 3.4-11-1 184/166 9/30/98 3.4.11-2 184/166 9/30/98 3.4-11-3 184/166 9/30/98 3.4.11-4 184/166 9/30/98 3.4.12-1 184/166 9/30/98 3.4.12-2 214/195 7/3/03 3.4.12-3 214/195 7/3/03 3.4.12-4 214/195 7/3/03 3.4.12-5 184/166 9/30/98 3.4.12-6 184/166 9/30/98 3.4.13-1 184/166 9/30/98 3.4.13-2 184/166 9/30/98 3.4.14-1 184/166 9/30/98 3.4.14-2 184/166 9/30/98 3.4.14-3 184/166 9/30/98 3.4.14-4 184/166 9/30/98 3.4.15-1 184/166 9/30/98 3.4.15-2 184/166 9/30/98 McGuire Units 1 and 2 Page 5 Revision 43

Page Number Amendment Revision Date 3.4.15-3 184/166 9/30/98 3.4.16-1 184/166 9/30/98 3.4.16-2 184/166 9/30/98 3.4.16-3 184/166 9/30/98 3.4.16-4 184/166 9/30/98 3.4.17-1 184/166 9/30/98 3.5.1-1 184/166 9/30/98 3.5.1-2 184/166 9/30/98 3.5.2-1 184/166 9/30/98 3.5.2-2 184/166 9/30/98 3.5.2-3 184/166 9/30/98 3.5.3-1 184/166 9/30/98 3.5.3-2 184/166 9/30/98 3.5.4-1 184/166 9/30/98 3.5.4-2 184/166 9/30/98 3.5.5-1 184/166 9/30/98 3.5.5-2 184/166 9/30/98 3.6.1-1 207/188 9/4/02 3.6.1-2 207/188 9/4/02 3.6.2-1 184/166 9/30/98 3.6.2-2 184/166 9/30/98 3.6.2-3 184/166 9/30/98 3.6.2-4 184/166 9/30/98 3.6.2-5 207/188 9/4/02 3.6.3-1 184/166 9/30/98 3.6.3-2 184/166 9/30/98 3.6.3-3 184/166 9/30/98 3.6.3-4 184/166 9/30/98 3.6.3-5 184/166 9/30/98 3.6.3-6 207/188 9/4/02 3.6.3-7 207/188 9/4/02 3.6.4-1 184/166 9/30/98 3.6.5-1 184/166 9/30/98 McGuire Units 1 and 2 Page 6 Revision 43

Page Number Amendment Revision Date 3.6.5-2 184/166 9/30/98 3.6.6-1 184/166 9/30/98 3.6.6-2 184/166 9/30/98 3.6.7-1 184/166 9/30/98 3.6.7-2 184/166 9/30/98 3.6.8-1 184/166 9/30/98 3.6.8-2 184/166 9/30/98 3.6.9-1 184/166 9/30/98 3.6.9-2 184/166 9/30/98 3.6.10-1 184/166 9/30/98 3.6.10-2 184/166 9/30/98 3.6.11-1 184/166 9/30/98 3.6.11-2 184/166 9/30/98 3.6.12-1 184/166 9/30/98 3.6.12-2 201/182 3/13/02 3.6.12-3 201/182 3/13/02 3.6.13-1 184/166 9/30/98 3.6.13-2 184/166 9/30/98 3.6.13-3 184/166 9/30/98 3.6.14-1 184/166 9/30/98 3.6.14-2 184/166 9/30/98 3.6.14-3 184/166 9/30/98 3.6.15-1 184/166 9/30/98 3.6.15-2 184/166 9/30/98 3.6.16-1 212/193 5/8/03 3.6.16-2 212/193 5/8/03 3.7.1-1 184/166 9/30/98 3.7.1-2 184/166 9/30/98 3.7.1-3 184/166 9/30/98 3.7.2-1 184/166 9/30/98 3.7.2-2 184/166 9/30/98 3.7.3-1 184/166 9/30/98 3.7.3-2 184/166 9/30/98 McGuire Units 1 and 2 Page 7 Revision 43

Page Number Amendment Revision Date 3.7.4-1 184/166 9/30/98 3.7.4-2 184/166 9/30/98 3.7.5-1 184/166 9/30/98 3.7.5-2 184/166 9/30/98 3.7.5-3 184/166 9/30/98 3.7.5-4 184/166 9/30/98 3.7.6-1 184/166 9/30/98 3.7.6-2 184/166 9/30/98 3.7.7-1 184/166 9/30/98 3.7.7-2 184/166 9/30/98 3.7.8-1 184/166 9/30/98 3.7.8-2 184/166 9/30/98 3.7.9-1 187/168 9/22/99 3.7.9-2 187/168 9/22/99 3.7.9-3 184/166 9/30/98 3.7.10-1 184/166 9/30/98 3.7.10-2 184/166 9/30/98 3.7.11-1 184/166 9/30/98 3.7.11-2 184/166 9/30/98 3.7.12-1 184/166 9/30/98 3.7.12-2 184/166 9/30/98 3.7.13-1 184/166 9/30/98 3.7.14-1 184/166 9/30/98 3.7.15-1 197/178 11/27/00 3.7.15-2 197/178 11/27/00 3.7.15-3 197/178 11/27/00 3.7.15-4 197/178 11/27/00 3.7.15-5 197/178 11/27/00 3.7.15-6 197/178 11/27/00 3.7.15-7 197/178 11/27/00 3.7.15-8 197/178 11/27/00 3.7.15-9 210/191 2/4/03 3.7.15-10 210/191 2/4/03 McGuire Units 1 and 2 Page 8 Revision 43

Page Number Amendment Revision Date 3.7.15-11 210/191 2/4/03 3.7.15-12 197/178 11/27/00 3.7.15-13 197/178 11/27/00 3.7.15-14 197/178 11/27/00 3.7.15-15 197/178 11/27/00 3.7.15-16 210/191 2/4/03 3.7.15-17 210/191 214/03 3.7.15-18 210/191 214/03 3.7.15-19 210/191 2/4/03 3.7.15-20 197/178 11/27/00 3.7.15-21 197/178 11/27/00 3.7.16-1 184/166 9/30/98 3.8.1-1 184/166 9/30/98 3.8.1-2 184/166 9/30/98 3.8.1-3 184/166 9/30/98 3.8.1-4 184/166 9/30/98 3.8.1-5 184/166 9/30/98 3.8.1-6 184/166 9/30/98 3.8.1-7 184/166 9/30/98 3.8.1-8 192/173 3/15/00 3.8.1-9 184/166 9/30/98 3.8.1-10 184/166 9/30/98 3.8.1-11 192/173 3/15/00 3.8.1-12 184/166 9/30/98 3.8.1-13 184/166 9/30/98 3.8.1-14 184/166 9/30/98 3.8.1-15 184/166 9/30/98 3.8.2-1 184/166 9/30/98 3.8.2-2 184/166 9/30/98 3.8.2-3 184/166 9/30/98 3.8.3-1 184/166 9/30/98 3.8.3-2 184/166 9/30/98 3.8.3-3 184/166 9/30/98 McGuire Units 1 and 2 Page 9 Revision 43

Page Number Amendment Revision Date 3.8.4-1 184/166 9/30/98 3.8.4-2 184/166 9/30/98 3.8.4-3 209/190 12/17/02 3.8.5-1 184/166 9/30/98 3.8.5-2 184/166 9/30/98 3.8.6-1 184/166 9/30/98 3.8.6-2 184/166 9/30/98 3.8.6-3 184/166 9/30/98 3.8.6-4 184/166 9/30/98 3.8.7-1 184/166 9/30/98 3.8.8-1 184/166 9/30/98 3.8.8-2 184/166 9/30/98 3.8.9-1 184/166 9/30/98 3.8.9-2 184/166 9/30/98 3.8.10-1 184/166 9/30/98 3.8.10-2 184/166 9/30/98 3.9.1-1 184/166 9/30/98 3.9.2-1 184/166 9/30/98 3.9.3-1 184/166 9/30/98 3.9.3-2 184/166 9/30/98 3.9.4-1 184/166 9/30/98 3.9.4-2 184/166 9/30/98 3.9.5-1 184/166 9/30/98 3.9.5-2 184/166 9/30/98 3.9.6-1 184/166 9/30/98 3.9.6-2 184/166 9/30/98 3.9.7-1 184/166 9/30/98 4.0.1 210/191 2/4/03 4.0.2 197/178 11/27/00 5.1-1 213/194 6/6/03 5.2-1 184/166 9/30/98 5.2-2 184/166 9/30/98 5.2-3 213/194 6/6/03 McGuire Units 1 and 2 Page 10 Revision 43

9 J Page Number Amendment Revision Date 5.3-1 213/194 6/6/03 5.4-1 184/166 9/30/98 5.5-1 212/193 5/8/03 5.5-2 212/193 5/8/03 5.5-3 184/166 9/30/98 5.5-4 184/166 9/30/98 5.5-5 190/171 12/21/99 5.5-6 184/166 9/30/98 5.5-7 184/166 9/30/98 5.5-8 184/166 9/30/98 5.5-9 184/166 9/30/98 5.5-10 184/166 9/30/98 5.5-11 184/166 9/30/98 5.5-12 184/166 9/30/98 5.5-13 184/166 9/30/98 5.5-14 196/177 11/2/00 5.5-15 184/166 9/30/98 5.5-16 184/166 9/30/98 5.5-17 204/185 7/17/02 5.5-18 184/166 9/30/98 5.6-1 184/166 9/30/98 5.6-2 208/189 10/1/02 5.6-3 208/189 10/1/02 5.6-4 203/184 7/10/02 5.6-5 184/166 9/30/98 5.7-1 2131194 6/6/03 5.7-2 184/166 9/30/98 BASES (Revised per section)

Revision 0 9/30/98 ii Revision 0 9/30/98 iii Revision 0 9/30/98 McGuire Units 1 and 2 Page Revision 43

Page Number Amendment Revision Date B 2.1.1 Revision 0 9/30/98 B 2.1.2 Revision 0 9/30/98 B 3.0 Revision 35 8/12/02 B 3.1.1 Revision 0 9/30/98 B 3.1.2 Revision 10 9/22/00 B 3.1.3 Revision 10 9/22/00 B 3.1.4 Revision 0 9/30/98 B 3.1.5 Revision 19 1/10/02 B 3.1.6 Revision 0 9/30/98 B 3.1.7 Revision 15 01/04/01 B 3.1.8 Revision 0 9/30/98 B 3.2.1 Revision 34 10/1/02 B 3.2.2 Revision 10 9/22/00 B 3.2.3 Revision 34 10/1/02 B 3.2.4 Revision 10 9/22/00 B 3.3.1 Revision 31 9/17/02 B 3.3.2 Revision 38 1/30/03 B 3.3.3 Revision 26 1/15/02 B 3.3.4 Revision 0 9/30/98 B 3.3.5 Revision 11 9/18/00 B 3.3.6 Revision 0 9/30/98 B 3.4.1 Revision 8 3/20/00 B 3.4.2 Revision 0 9/30/98 B 3.4.3 Revision 44 7/3103 B 3.4.4 Revision 0 9/30/98 B 3.4.5 Revision 0 9/30/98 B 3.4.6 Revision 0 9/30/98 B 3.4.7 Revision 0 9/30/98 B 3.4.8 Revision 0 9/30/98 B 3.4.9 Revision 0 9/30/98 B 3.4.10 Revision 0 9/30/98 B 3.4.11 Revision 0 9/30/98 B 3.4.12 Revision 44 7/3/03 McGuire Units 1 and 2 Page 12 Revision 43

Page Numbver Amendment Revision Date B 3.4.13 Revision 0 9/30/98 B 3.4.14 Revision 0 9/30/98 B 3.4.15 Revision 0 9/30/98 B 3.4.16 Revision 0 9/30/98 B 3.4.17 Revision 0 9/30/98 B 3.5.1 Revision 30 8/13/02 B 3.5.2 Revision 45 8/20/03 B 3.5.3 Revision 0 9/30/98 B 3.5.4 Revision 0 9/30/98 B 3.5.5 Revision 0 9/30/98 B 3.6.1 Revision 32 10/4/02 B 3.6.2 Revision 32 10/4/02 B 3.6.3 Revision 32 10/4/02 B 3.6.4 Revision 0 9/30/98 B 3.6.5 Revision 0 9/30/98 B 3.6.6 Revision 0 9/30/98 B 3.6.7 Revision 0 (Pg 4 Rev 3) 9/30/98 (Rev 3 - 2/99)

B 3.6.8 Revision 0 9/30/98 B 3.6.9 Revision 0 9/30/98 B 3.6.10 Revision 43 5/28/03 B 3.6.11 Revision 0 9/30/98 B 3.6.12 Revision 25 3/13102 B 3.6.13 Revision 0 9/30/98 B 3.6.14 Revision 0 9/30/98 B 3.6.15 Revision 0 9/30/98 B3.6.16 Revision 40 5/8/03 B 3.7.1 Revision 0 9/30/98 B 3.7.2 Revision 0 9/30/98 B 3.7.3 Revision 0 9/30/98 B 3.7.4 Revision 0 9/30/98 B 3.7.5 Revision 38 1/30/03 B 3.7.6 Revision 0 9/30/98 B 3.7.7 Revision 0 9/30/98 McGuire Units 1 and 2 Page 13 Revision 43

Page N~umber Amnendment Revision Date B 3.7.8 Revision 0 9/30/98 B 3.7.9 Revision 43 5/28/03 B 3.7.10 Revision 0 9/30/98 B 3.7.11 Revision 39 3/19/03 B 3.7.12 Revision 28 5/17/02 B 3.7.13 Revision 0 9/30/98 B 3.7.14 Revision 37 2/4/03 B 3.7.15 Revision 37 2/4/03 B 3.7.16 Revision 0 9/30/98 B 3.8.1 Revision 46 9/4/03 B 3.8.2 Revision 46 9/4/03 B 3.8.3 Revision 0 9/30/98 B 3.8.4 Revision 36 12/17/02 B 3.8.5 Revision 0 9/30/98 B 3.8.6 Revision 0 9/30/98 B 3.8.7 Revision 20 1/10/02 B 3.8.8 Revision 0 9/30/98 B 3.8.9 Revision 24 2/4/02 B 3.8.10 Revision 0 9/30/98 B 3.9.1 Revision 0 9/30/98 B 3.9.2 Revision 0 9/30/98 B 3.9.3 Revision 27 5/14/02 B 3.9.4 Revision 0 9/30/98 B 3.9.5 Revision 0 9/30/98 B 3.9.6 Revision 0 9/30/98 B 3.9.7 Revision 0 9/30/98 McGuire Units 1 and 2 Page 14 Rtwvision 43

ATTACHMENT 2 REVISED TS BASES

ECCS-Operating B 3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.2 ECCS-Operating BASES BACKGROUND The function of the ECCS is to provide core cooling and negative reactivity to ensure that the reactor core is protected after any of the following accidents:

a. Loss of coolant accident (LOCA), coolant leakage greater than the capability of the normal charging system;

b. Rod ejection accident;

c. Loss of secondary coolant accident, including uncontrolled steam or feedwater release; and

d. Steam generator tube rupture (SGTR).

The addition of negative reactivity is designed primarily for the loss of secondary coolant accident where primary cooldown could add enough positive reactivity to achieve criticality and return to significant power.

There are three phases of ECCS operation: injection, cold leg recirculation, and hot leg recirculation. In the injection phase, water is taken from the refueling water storage tank (RWST) and injected into the Reactor Coolant System (RCS) through the cold legs. When sufficient water is removed from the RWST to ensure that enough boron has been added to maintain the reactor subcritical and the containment sumps have enough water to supply the required net positive suction head to the ECCS pumps, suction is switched to the containment sump for cold leg recirculation. When the core decay heat has decreased to a level low enough to be successfully removed without direct RHR pump injection flow, the RHR cold leg injection path is realigned to discharge to the auxiliary containment spray header. After approximately 7 hours8.101852e-5 days 0.00194 hours 1.157407e-5 weeks 2.6635e-6 months , part of the ECCS flow is shifted to the hot leg recirculation phase to provide a backflush which, for a cold leg break, would reduce the boiling in the top of the core and prevent excessive boron concentration.

The ECCS consists of three separate subsystems: centrifugal charging (high head), safety injection (SI) (intermediate head), and residual heat removal (RHR) (low head). Each subsystem consists of two redundant, 100% capacity trains. The ECCS accumulators and the RWST are also part of the ECCS, but are not considered part of an ECCS flow path as described by this LCO.

McGuire Units 1 and 2 B 3.5.2-1 Revision No. 45

ECCS-Operating B 3.5.2 BASES BACKGROUND (continued)

The ECCS flow paths consist of piping, valves, heat exchangers, and pumps such that water from the RWST can be injected into the RCS following the accidents described in this LCO. The major components of each subsystem are the centrifugal charging pumps, the RHR pumps, heat exchangers, and the SI pumps. Each of the three subsystems consists of two 100% capacity trains that are interconnected and redundant such that either train is capable of supplying 100% of the flow required to mitigate the accident consequences. This interconnecting and redundant subsystem design provides the operators with the ability to utilize components from opposite trains to achieve the required 100% flow to the core.

During the injection phase of LOCA recovery, a suction header supplies water from the RWST to the ECCS pumps. Mostly separate piping supplies each subsystem and each train within the subsystem. The discharge from the centrifugal charging pumps combines, then divides again into four supply lines, each of which feeds the injection line to one RCS cold leg. The discharge from the SI and RHR pumps divides and feeds an injection line to each of the RCS cold legs. Throttle valves in the SI lines are set to balance the flow to the RCS. This balance ensures sufficient flow to the core to meet the analysis assumptions following a LOCA in one of the RCS cold legs. The flow split from the RHR lines cannot be adjusted. Although much of the two ECCS trains are composed of completely separate piping, certain areas are shared between trains. The most important of these are 1) where both trains flow through a single physical pipe, and 2) at the injection connections to the RCS cold legs. Since each train must supply sufficient flow to the RCS to be considered 100% capacity, credit is taken in the safety analyses for flow to three intact cold legs. Any configuration which, when combined with a single active failure, prevents the flow from either ECCS pump in a given train from reaching all four cold legs injection points on that train is unanalyzed and might render both trains of that ECCS subsystem inoperable.

For LOCAs that are too small to depressurize the RCS below the shutoff head of the SI pumps, the centrifugal charging pumps supply water until the RCS pressure decreases below the SI pump shutoff head. During this period, the steam generators are used to provide part of the core cooling function.

During the recirculation phase of LOCA recovery, RHR pump suction is transferred to the containment sump. The RHR pumps then supply the other ECCS pumps. Initially, recirculation is through the same paths as the injection phase. Subsequently, for large LOCAs, the recirculation phase includes injection into both the hot and cold legs.

McGuire Units 1 and 2 B 3.5.2-2 Revision No. 45

ECCS-Operating B 3.5.2 BASES BACKGROUND (continued)

The high and intermediate head subsystems of the ECCS also functions to supply borated water to the reactor core following increased heat removal events, such as a main steam line break (MSLB). The limiting design conditions occur when the moderator temperature coefficient is highly negative, such as at the end of each cycle.

During low temperature conditions in the RCS, limitations are placed on the maximum number of ECCS pumps that may be OPERABLE. Refer to the Bases for LCO 3.4.12, Low Temperature Overpressure Protection (LTOP) System,' for the basis of these requirements.

The ECCS subsystems are actuated upon receipt of an Si signal. The actuation of safeguard loads is accomplished in a programmed time sequence. If offsite power is available, the safeguard loads start immediately in the programmed sequence. If offsite power is not available, the Engineered Safety Feature (ESF) buses shed normal operating loads and are connected to the emergency diesel generators (EDGs). Safeguard loads are then actuated in the programmed time sequence. The time delay associated with diesel starting, sequenced loading, and pump starting determines the time required before pumped flow is available to the core following a safety injection actuation.

The active ECCS components, along with the passive accumulators and the RWST covered in LCO 3.5.1, Accumulators, and LCO 3.5.4, ORefueling Water Storage Tank (RWST),0 provide the cooling water necessary to meet GDC 35 (Ref. 1).

APPLICABLE The LCO helps to ensure that the following acceptance criteria for the SAFETY ANALYSES ECCS, established by 10 CFR 50.46 (Ref. 2), will be met following a small break LOCA and there is a high level of probability that the criteria are met following a large break LOCA:

a. Maximum fuel element cladding temperature is

22000F;

b. Maximum cladding oxidation is < 0.17 times the total cladding thickness before oxidation;

c. Maximum hydrogen generation from a zirconium water reaction is

< 0.01 times the hypothetical amount generated if all of the metal in the cladding cylinders surrounding the fuel, excluding the cladding surrounding the plenum volume, were to react; Revision No. 45 McGuire Units McGuire and 22 Units 1 and B 3.5.2-3 B 3.5.2-3 Revision No. 45

ECCS-Operating B 3.5.2 BASES APPLICABLE SAFETY ANALYSES (continued)

d. Core is maintained in a coolable geometry; and

e. Adequate long term core cooling capability is maintained.

The LCO also limits the potential for a post trip return to power following an MSLB event and ensures that containment pressure and temperature limits are met.

Each ECCS subsystem is taken credit for in a large break LOCA event at full power (Refs. 3 and 4). This event has the greatest potential to challenge the limits on runout flow set by the manufacturer of the ECCS pumps. It also sets the maximum response time for their actuation. Direct flow from the centrifugal charging pumps and SI pumps is credited in a small break LOCA event. The RHR pumps are also credited, for larger small break LOCAs, as the means of supplying suction to these higher head ECCS pumps after the switch to sump recirculation. This event establishes the flow and discharge head at the design point for the centrifugal charging pumps. The MSLB analysis also credits the SI and centrifugal charging pumps. Although some ECCS flow is necessary to mitigate a SGTR event, a single failure disabling one ECCS train is not the limiting single failure for this transient. The SGTR analysis primary to secondary break flow is increased by the availability of both centrifugal charging and SI trains. Therefore, the SGTR analysis is penalized by assuming both ECCS trains are operable as required by the LCO. The OPERABILITY requirements for the ECCS are based on the following LOCA analysis assumptions:

a. A large break LOCA event, with loss of offsite power and a single failure disabling one ECCS train; and

b. A small break LOCA event, with a loss of offsite power and a single failure disabling one ECCS train.

During the blowdown stage of a LOCA, the RCS depressurizes as primary coolant is ejected through the break into the containment. The nuclear reaction is terminated either by moderator voiding during large breaks or control rod insertion for small breaks. Following depressurization, emergency cooling water is injected into the cold legs, flows into the downcomer, fills the lower plenum, and refloods the core.

The effects on containment mass and energy releases are accounted for in appropriate analyses (Ref. 3). The LCO ensures that an ECCS train will deliver sufficient water to match boiloff rates soon enough to minimize the consequences of the core being uncovered following a large LOCA.

B 3.5.2-4 Revision No.45 Units 1 McGuire Units and 2 1 and 2 B 3.5.2-4 Revision No. 45

ECCS-Operating B 3.5.2 BASES APPLICABLE SAFETY ANALYSES (continued)

It also ensures that the centrifugal charging and SI pumps will deliver sufficient water and boron during a small LOCA to maintain core subcriticality. For smaller LOCAs, the centrifugal charging pump delivers sufficient fluid to maintain RCS inventory. For a small break LOCA, the steam generators continue to serve as the heat sink, providing part of the required core cooling.

The ECCS trains satisfy Criterion 3 of 10 CFR 50.36 (Ref. 5).

LCO In MODES 1, 2, and 3, two independent (and redundant) ECCS trains are required to ensure that sufficient ECCS flow is available, assuming a single failure affecting either train. Additionally, individual components within the ECCS trains may be called upon to mitigate the consequences of other transients and accidents.

In MODES 1, 2, and 3, an ECCS train consists of a centrifugal charging subsystem, an SI subsystem, and an RHR subsystem. Each train includes the piping, instruments, and controls to ensure an OPERABLE flow path capable of taking suction from the RWST upon an SI signal and automatically transferring suction to the containment sump.

During an event requiring ECCS actuation, a flow path is required to provide an abundant supply of water from the RWST to the RCS via the ECCS pumps and their respective supply headers to each of the four cold leg injection nozzles. In the long term, this flow path may be switched to take its supply from the containment sump and to supply its flow to the RCS hot and cold legs. The flow path for each train must maintain its designed independence to ensure that no single failure can disable both ECCS trains.

APPLICABILITY In MODES 1, 2, and 3, the ECCS OPERABILITY requirements for the limiting Design Basis Accident, a large break LOCA, are based on full power operation. Although reduced power would not require the same level of performance, the accident analysis does not provide for reduced cooling requirements in the lower MODES. The centrifugal charging pump performance is based on a small break LOCA, which establishes the pump performance curve and has less dependence on power. The SI pump performance requirements are based on a small break LOCA. For both of these types of pumps, the large break LOCA analysis depends only on the flow value at containment pressure, not on the shape of the flow versus pressure curve at higher pressures. MODE 2 and MODE 3 requirements are bounded by the MODE 1 analysis.

McGuire Units 1 and 2 B 3.5.2-5 Revision No. 45

ECCS-Operating B 3.5.2 BASES APPLICABILITY (continued)

This LCO is only applicable in MODE 3 and above. Below MODE 3, the Si signal setpoint is manually bypassed by operator control, and system functional requirements are relaxed as described in LCO 3.5.3, ECCS-Shutdown."

As indicated in the Note, the flow path may be isolated for 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in MODE 3, under controlled conditions, to perform pressure isolation valve testing per SR 3.4.14.1. The flow path is readily restorable from the control room.

In MODES 5 and 6, plant conditions are such that the probability of an event requiring ECCS injection is extremely low. Core cooling requirements in MODE 5 are addressed by LCO 3.4.7, RCS Loops-MODE 5, Loops Filled,' and LCO 3.4.8, RCS Loops-MODE 5, Loops Not Filled." MODE 6 core cooling requirements are addressed by LCO 3.9.5, Residual Heat Removal (RHR) and Coolant Circulation-High Water Level,' and LCO 3.9.6, Residual Heat Removal (RHR) and Coolant Circulation-Low Water Level."

ACTIONS A.1 With one or more trains inoperable and at least 100% of the ECCS flow equivalent to a single OPERABLE ECCS train available, the inoperable components must be returned 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 based on an NRC reliability evaluation (Ref. 6) and is a reasonable time for repair of many ECCS components.

An ECCS train is inoperable if it is not capable of delivering design flow to the RCS. Individual components are inoperable if they are not capable of performing their design function or supporting systems are not available.

The LCO requires the OPERABILITY of a number of independent subsystems. Due to the redundancy of trains and the diversity of subsystems, the inoperability of one component in a train does not render the ECCS incapable of performing its function. Neither does the inoperability of two different components, each in a different train, necessarily result in a loss of function for the ECCS. The intent of this Condition is to maintain a combination of equipment such that 100% of the ECCS flow equivalent to a single OPERABLE ECCS train remains available. This allows increased flexibility in plant operations under circumstances when components in opposite trains are inoperable.

B 3.5.2-6 Revision No.45 McGuire Units 1 McGuire Units and 2 1 and 2 B 3.5.2-6 Revision No. 45

ECCS-Operating B 3.5.2 BASES ACTIONS (continued)

An event accompanied by a loss of offsite power and the failure of an EDG can disable one ECCS train until power is restored. A reliability analysis (Ref. 6) has shown that the impact of having one full ECCS train inoperable is sufficiently small to justify continued operation for 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

Reference 7 describes situations in which one component, such as an RHR crossover valve, can disable both ECCS trains. With one or more component(s) inoperable such that 100% of the flow equivalent to a single OPERABLE ECCS train is not available, the facility is in a condition outside the accident analysis. Therefore, LCO 3.0.3 must be immediately entered.

B.1 and B.2 If the inoperable trains cannot be returned to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE SR 3.5.2.1 REQUIREMENTS Verification of proper valve position ensures that the flow path from the ECCS pumps to the RCS is maintained. Misalignment of these valves could render both ECCS trains inoperable. Securing these valves using the power disconnect switches in the correct position ensures that they cannot change position as a result of an active failure or be inadvertently misaligned. These valves are of the type, described in Reference 7, that can disable the function of both ECCS trains and invalidate the accident analyses. A 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered reasonable in view of other administrative controls that will ensure a mispositioned valve is unlikely.

SR 3.5.2.2 Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these were verified to be in the correct position prior to locking, sealing, and 22 Units 1 and 3.5.2-7 B3.5.2-7 Revision No. 45 McGuire Units McGuire B Revision No. 45

ECCS-Operating B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued) or securing. A valve that receives an actuation signal is allowed to be in a nonaccident position provided the valve will automatically reposition within the proper stroke time. This Surveillance does not require any testing or valve manipulation. Rather, it involves verification that those valves capable of being mispositioned are in the correct position. The 31 day Frequency is appropriate because the valves are operated under administrative control.

This Frequency has been shown to be acceptable through operating experience.

SR 3.5.2.3 ECCS piping is verified to be water-filled by venting to remove gas from accessible locations susceptible to gas accumulation. Alternative means may be used to verify water-filled conditions (e.g., ultrasonic testing or high point sightglass observation). Maintaining the piping from the ECCS pumps to the RCS full of water ensures that the system will perform properly, injecting its full capacity into the RCS upon demand. This will also prevent water hammer, pump cavitation, and pumping of noncondensible gas (e.g., air, nitrogen, or hydrogen) into the reactor vessel following an Si signal or during shutdown cooling. The 31 day Frequency takes into consideration the gradual nature of gas accumulation in the ECCS piping and the procedural controls governing system operation.

SR 3.5.2.4 Periodic surveillance testing of ECCS pumps to detect gross degradation caused by impeller structural damage or other hydraulic component problems is required by Section Xi of the ASME Code. This type of testing may be accomplished by measuring the pump developed head at only one point of the pump characteristic curve. This verifies both that the measured performance is within an acceptable tolerance of the original pump baseline performance and that the performance at the test flow is greater than or equal to the performance assumed in the plant safety analysis. SRs are specified in the Inservice Testing Program, which encompasses Section Xl of the ASME Code. Section Xl of the ASME Code provides the activities and Frequencies necessary to satisfy the requirements.

McGuire Units 1 and 2 B 3.5.2-8 Revision No. 45

ECCS-Operating B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.5.2.5 and SR 3.5.2.6 These Surveillances demonstrate that each automatic ECCS valve actuates to the required position on an actual or simulated SI signal and that each ECCS pump starts on receipt of an actual or simulated SI signal. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The 18 month Frequency is based on the need to perform these Surveillances under the conditions that apply during a plant outage and the potential for unplanned plant transients if the Surveillances were performed with the reactor at power. The 18 month Frequency is also acceptable based on consideration of the design reliability (and confirming operating experience) of the equipment. The actuation logic is tested as part of ESF Actuation System testing, and equipment performance is monitored as part of the Inservice Testing Program.

SR 3.5.2.7 The position of throttle valves in the flow path on an SI signal is necessary for proper ECCS performance. These valves have mechanical locks to ensure proper positioning for restricted flow to a ruptured cold leg, ensuring that the other cold legs receive at least the required minimum flow. The 18 month Frequency is based on the same reasons as those stated in SR 3.5.2.5 and SR 3.5.2.6.

SR 3.5.2.8 Periodic inspections of the containment sump suction inlet ensure that it is unrestricted and stays in proper operating condition. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and on the need to have access to the location. This Frequency has been found to be sufficient to detect abnormal degradation and is confirmed by operating experience.

and 22 B 3.5.2-9 Revision No.45 McGuire McGuire Units 1 and Units 1 B 3.5.2-9 Revision No. 45

ECCS-Operating B 3.5.2 BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 35.

2. 10 CFR 50.46.

3. UFSAR, Section 6.2.1.

4. UFSAR, Chapter 15.

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

6. NRC Memorandum to V. Stello, Jr., from R.L. Baer, Recommended Interim Revisions to LCOs for ECCS Components," December 1, 1975.

7. IE Information Notice No. 87-01.

and 22 1 and 3.5.2-100 B 3.5.2-1 Revision No.45 McGuire Units 1 B Revision No. 45

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

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

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

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

The offsite transmission systems normally supply their respective unit's onsite power supply requirements. However, in the event that one or both buslines of a unit become unavailable, it is acceptable to supply that units offsite to onsite power requirements by aligning the affected 41 60V bus of the opposite unit via the standby transformers, SATA and SATB. In this alignment, one units offsite transmission system would simultaneously supply its own 41 60V busses and one or both of the busses of the other unit. Each unit's Train A and B 4160V bus must be aligned to offsite power via separate buslines (BLI A, BLI B, BL2A, BL2B). Although a single auxiliary transformer (IATA, 1ATB, 2ATA, 2ATB) is sized to carry all of the auxiliary loads of its unit plus both trains of essential 41 60V loads of the opposite unit, the LCO would not be met in this alignment due to separation criteria.

Acceptable train and unit specific breaker alignment options are described below:

McGuire Units 1 and 2 B 3.8.1-1 Revision No. 46

UNIT 1 A Train and B Train options must be from separate buslinelauxiliary transformer.

A Train B Train

1. BL1 A-1 ATA-1TA-1ATC-1 ETA 1. BLlB-iATB-1TD-1ATD-1ETB

2. BLIB-IATB-ITA-lATC-1ETA 2. BL1A-1ATA-1TD-1ATD-1ETB

3. BL2A-2ATA-2TC-SATA-1 ETA 3. BL2A-2ATA-2TB-SATB-1 ETB

4. BL2B-2ATB-2TC-SATA-1 ETA 4 BL2B-2ATB-2TB-SATB-1 ETB UNIT 2 A Train and B Train options must be from separate busline/auxiliary transformer.

A Train B Train

1. BL2A-2ATA-2TA-2ATC-2ETA 1. BL2B-2ATB-2TD-2ATD-2ETB

2. BL2B-2ATB-2TA-2ATC-2ETA 2. BL2A-2ATA-2TD-2ATD-2ETB

3. BL1A-1ATA-1TC-SATA-2ETA 3. BLIA-iATA-ITB-SATB-2ETB

4. BL1 B-1 ATB-iTC-SATA-2ETA 4. BLIB-lATB-lTB-SATB-2ETB Certain required unit loads are returned to service in a predetermined sequence in order to prevent overloading the transformer supplying offsite power to the onsite Class E Distribution System. Typically (via accelerated sequencing), within 1 minute after the initiating signal is received, all loads needed to recover the unit or maintain it in a safe condition are returned to service.

The onsite standby power source for each 4.16 kV ESF bus is a dedicated DG.

DGs A and B are dedicated to ESF buses ETA and ETB, respectively. A DG starts automatically on a safety injection (SI) signal (i.e., low pressurizer pressure or high containment pressure signals) or on an ESF bus degraded voltage or undervoltage signal (refer to LCO 3.3.5, Loss of Power (LOP)

Diesel Generator (DG) Start Instrumentation'). After the DG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or McGuire Units 1 and 2 B 3.8.1-2 Revision No. 46

AC Sources-Operating B 3.8.1 BASES BACKGROUND (continued) degraded voltage, independent of or coincident with an SI signal. The DGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips loads from the ESF bus. When the DG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the DG by automatic load application.

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

Certain required unit loads are returned to service in a predetermined sequence in order to prevent overloading the DG in the process.

Typically (via accelerated sequencing), within 1 minute after the initiating signal is received, all loads needed to recover the unit or maintain it in a safe condition are returned to service.

Ratings for Train A and Train B DGs satisfy the requirements of Regulatory Guide 1.9 (Ref. 3). The continuous service rating of each DG is 4000 kW with 10% overload permissible for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in any 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period. The ESF loads that are powered from the 4.16 kV ESF buses are listed in Reference 2.

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

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

and Section 3.6, Containment Systems.

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

McGuire Units 1 and 2 B 3.8.1-3 Revision No. 46

AC Sources-Operating B 3.8.1 BASES APPLICABLE SAFETY ANALYSES (continued)

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

b. A worst case single failure.

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

LCO Two qualified circuits between the offsite transmission network and the onsite Class 1E Electrical Power System and separate and independent DGs for each train ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated DBA.

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

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

Each offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident, while connected to the ESF buses.

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

Normnally, each Class 1E 4.16 k switchgear is powered from its associated non-Class 1E train of the 6.9 kV Normal Auxiliary Power System as discussed in 6.9 kV Normal Auxiliary Power System in Chapter 8 of the UFSAR (Ref. 2). Additionally, an alternate source of power to each 4.16 kcV essential switchgear is provided from the 6.9 kV system via a separate and independent 6.9/4.16 kV transformer. Two transformers are shared between units and provide the capability to supply an alternate source of power to each units 4.16 kV essential switchgear from either unit's 6.9 kV system. A key interlock scheme is provided to preclude the possibility of connecting the two units together at either the 6.9 or 4.16 kV level.

Each train of the 4.16 kV Essential Auxifliary Power System is also provided with a separate and ndependent emergency diesel generator to supply the Class 1E loads required to safely shut down the unit following a design basis accident.

McGuire Units 1 and 2 B 3.8.1-4 Revision No. 46

AC Sources-Operating B 3.8.1 BASES LCO (continued)

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

Additional DG capabilities must be demonstrated to meet required Surveillance, e.g., capability of the DG to revert to standby status on an ECCS signal while operating in parallel test mode.

Proper sequencing of loads is a function of Sequencer OPERABILITY.

Proper load shedding is a function of DG OPERABILITY. Proper tripping of non-essential loads is a function of AC Bus OPERABILITY (Condition A of Technical Specification 3.8.9).

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

APPLICABILITY The AC sources and sequencers are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure that:

a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and

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

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

ACTIONS A.1 To ensure a highly reliable power source remains with one offsite circuit inoperable, it is necessary to verify the OPERABILITY of the remaining required offsite circuit on a more frequent basis. Since the Required Action only specifies perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not met. However, if a second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition C, for two offsite circuits inoperable, is entered.

McGuire Units 1 and 2 B 3.8.1-5 Revision No. 46

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

A.2 Required Action A.2, which only applies if the train cannot be powered from an offsite source, is intended to provide assurance that an event coincident with a single failure of the associated DG will not result in a complete loss of safety function of critical redundant required features. These features are powered from the redundant AC electrical power train. This includes motor driven auxiliary feedwater pumps. The turbine driven auxiliary feedwater pump is required to be considered a redundant required feature, and, therefore, required to be determined OPERABLE by this Required Action. Three independent AFW pumps are required to ensure the availability of decay heat removal capability for all events accompanied by a loss of offsite power and a single failure. System design is such that the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis.

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

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

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

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

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

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

McGuire Units 1 and 2 B 3.8.1-6 Revision No. 46

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

A-3 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition A for a period that should not exceed 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the unit safety systems. In this Condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1E Distribution System.

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

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

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

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

B.1 To ensure a highly reliable power source remains with an inoperable DG, it is necessary to verify the availability of the offsite circuits on a more frequent basis. Since the Required Action only specifies perform,o a McGuire Units 1 and 2 B 3.8.1-7 Revision No. 46

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions and Required Actions must then be entered.

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

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

a. An inoperable DG exists; and

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

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

Discovering one required DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DG, results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is Acceptable because it minimizes risk while McGuire Units 1 and 2 B 3.8.1 -8 Revision No. 46

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) allowing time for restoration before subjecting the unit to transients associated with shutdown.

In this Condition, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

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

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

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

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

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

McGuire Units 1 and 2 B 3.8.1-9 Revision No. 46

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

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

In Condition B, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

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

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

As in Required Action B.2, the Completion Time allows for an exception to the normal time zero" for beginning the allowed time clock.0 This will result in establishing the time zeros at the time that the LCO was initially not met, instead of at the time Condition B was entered.

C.1 and C.2 Required Action C.1, which applies when two offsite circuits are inoperable, is intended to provide assurance that an event with a coincident single failure will not result in a complete loss of redundant required safety functions. The Completion Time for this failure of redundant required features Is reduced to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from that allowed for one train without offsite power (Required Action A.2). The rationale for the reduction to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is that Regulatory Guide 1.93 (Ref. 7) allows a Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for two required offsite circuits inoperable, McGuire Units 1 and 2 B 3.8.1 -10 Revision No. 46

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) based upon the assumption that two complete safety trains are OPERABLE. When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is appropriate. These features are powered from redundant AC safety trains. This includes motor driven auxiliary feedwater pumps.

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

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

a. All required offsite circuits are inoperable; and

b. A required feature is inoperable.

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

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

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

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

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

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

McGuire Units 1 and 2 B 3.8.1 -1 1 Revision No. 46

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

With both of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a DBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time provides a period of time to effect restoration of one of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria.

According to Reference 6, with the available offsite AC sources, two less than required by the LCO, operation may continue for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . If two offsite sources are restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , unrestricted operation may continue. If only one offsite source is restored within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , power operation continues in accordance with Condition A.

D.1 and D.2 Pursuant to LCO 3.0.6, the Distribution System ACTIONS would not be entered even if all AC sources to it were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition D are modified by a Note to indicate that when Condition D is entered with no AC source to any train, the Conditions and Required Actions for LCO 3.8.9, Distribution Systems-Operating," must be immediately entered. This allows Condition D to provide requirements for the loss of one offsite circuit and one DG, without regard to whether a train is de-energized. LCO 3.8.9 provides the appropriate restrictions for a de-energized train.

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

In Condition D, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the reliability of the power systems in this Condition may appear higher than that in Condition C (loss of both required offsite circuits). This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.

McGuire Units 1 and 2 B 3.8.1-12 Revision No. 46

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

E.1 With Train A and Train B DGs inoperable, there are no remaining standby AC sources. Thus, with an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown (the immediate shutdown could cause grid instability, which could result in a total loss of AC power). Since any inadvertent generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.

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

F.1 The sequencer(s) is an essential support system to both the offsite circuit and the DG associated with a given ESF bus. Furthermore, the sequencer is on the primary success path for most major AC electrically powered safety systems powered from the associated ESF bus.

Therefore, loss of an ESF bus sequencer affects every major ESF system in the train. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining sequencer OPERABILITY. This time period also ensures that the probability of an accident (requiring sequencer OPERABILITY) occurring during periods when the sequencer is inoperable is minimal.

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

McGuire Units 1 and 2 B 3.8.1-13 Revision No. 46

AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)

H.1 Condition H corresponds to a level of degradation in which all redundancy in the AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown.

SURVEILLANCE The AC sources are designed to permit inspection and testing of all REQUIREMENTS important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, Appendix A, GDC 18 (Ref. 9).

Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulated accident conditions). The SRs for demonstrating the OPERABILITY of the DGs are in accordance with the recommendations of Regulatory Guide 1.9 (Ref. 3) and Regulatory Guide 1.137 (Ref. 11), as addressed in the UFSAR.

Since the McGuire DG manufacturer, Nordberg, is no longer in business, McGuire engineering is the designer of record. Therefore, the term manufacturer's or vendor's recommendations is taken to mean the recommendations as determined by McGuire engineering, with specific Nordberg input as it is available, that were intended for the DGs, taking into account the maintenance, operating history, and industry experience, when available.

Where the SRs discussed herein specify voltage and frequency tolerances, the following is applicable. The minimum steady state output voltage of 3740 V is 90% of the nominal 4160 V output voltage. This value allows for voltage drop to the terminals of 4000 V motors whose minimum operating voltage is specified as 90% or 3600 V. It also allows for voltage drops to motors and other equipment down through the 120 V level where minimum operating voltage is also usually specified as 90%

of name plate rating. The specified maximum steady state output voltage of 4580 V is equal to the maximum operating voltage specified for 4000 V motors. It ensures that for a lightly loaded distribution system, the voltage at the terminals of 4000 V motors is no more than the maximum rated operating voltages. The specified minimum and maximum frequencies of the DG are 58.8 Hz and 61.2 Hz, respectively. These values are equal to

+/- 2% of the 60 Hz nominal frequency and are derived from the recommendations given in Regulatory Guide 1.9 (Ref. 3).

McGuire Units 1 and 2 B 3.8.1-14 Revision No. 46

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.1 This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to their preferred power source, and that appropriate independence of offsite circuits is maintained. The 7 day Frequency is adequate since breaker position is not likely to change without the operator being aware of it and because its status is displayed in the control room.

SR 3.8.1.2 and SR 3.8.1.7 These SRs help to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and to maintain the unit in a safe shutdown condition.

To minimize the wear on moving parts that do not get lubricated when the engine is not running, these SRs are modified by a Note (Note 2 for SR 3.8.1.2) to indicate that all DG starts for these Surveillances may be preceded by an engine prelube period and followed by a warmup period prior to loading.

For the purposes of SR 3.8.1.2 and SR 3.8.1.7 testing, the DGs are started from standby conditions using a manual start, loss of offsite power signal, safety injection signal, or loss of offsite power coincident with a safety injection signal. Standby conditions for a DG mean that the diesel engine coolant and oil are being continuously circulated and temperature is being maintained consistent with manufacturer recommendations.

In order to reduce stress and wear, the manufacturer recommends a modified start in which the DGs are gradually accelerated to synchronous speed prior to loading. These start procedures are the intent of Note 3, which is only applicable when such modified start procedures are recommended by the manufacturer.

SR 3.8.1.7 requires that, at a 184 day Frequency, the DG starts from standby conditions and achieves required voltage and frequency within 11 seconds. The 11 second start requirement supports the assumptions of the design basis LOCA analysis In the UFSAR, Chapter 15 (Ref. 5).

McGuire Units 1 and 2 B 3.8.1-15 Revision No. 46

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

The 11 second start requirement is not applicable to SR 3.8.1.2 (see Note 3) when a modified start procedure as described above is used. If a modified start is not used, the 11 second start requirement of SR 3.8.1.7 applies.

Since SR 3.8.1.7 requires a 11 second start, it is more restrictive than SR 3.8.1.2, and it may be performed in lieu of SR 3.8.1.2. This is the intent of Note 1 of SR 3.8.1.2.

The normal 31 day Frequency for SR 3.8.1.2 and the 184 day Frequency for SR 3.8.1.7 are consistent with Regulatory Guide 1.9 (Ref. 3) Table 1.

These Frequencies provide adequate assurance of DG OPERABILITY, while minimizing degradation resulting from testing.

SR 3.8.1.3 This Surveillance verifies that the DGs are capable of synchronizing with the offsite electrical system and accepting loads greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.

Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0.

The 0.8 value is the design rating of the machine, while the 1.0 is an operational limitation to ensure circulating currents are minimized. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

The 31 day Frequency for this Surveillance is consistent with Regulatory Guide 1.9 (Ref. 3) Table 1.

This SR is modified by four Notes. Note 1 indicates that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized. Note 2 states that momentary transients, because of changing bus loads, do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test. Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations. Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.

McGuire Units 1 and 2 B 3.8.1-16 Revision No. 46

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.4 This SR provides verification that the level of fuel oil in the day tank is at or above the level at which fuel oil is automatically added. The level is expressed as an equivalent volume in gallons, and is adequate for approximately 30 minutes of DG operation at full load.

The 31 day Frequency is adequate to assure that a sufficient supply of fuel oil is available, since low level alarms are provided and facility operators would be aware of any large uses of fuel oil during this period.

SR 3.8.1.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the fuel oil day tanks once every 31 days eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequencies are established by Regulatory Guide 1.137 (Ref. 11). This SR is for preventative maintenance. The presence of water does not necessarily represent failure of this SR, provided the accumulated water is removed during the performance of this Surveillance.

SR 3.8.1.6 This Surveillance demonstrates that each required fuel oil transfer pump operates and transfers fuel oil from its associated storage tank to its associated day tank. This is required to support continuous operation of standby power sources. This Surveillance provides assurance that the fuel oil transfer pump is OPERABLE, the fuel oil piping system is intact, the fuel delivery piping is not obstructed, and the controls and control systems for automatic fuel transfer systems are OPERABLE.

The design of fuel transfer systems is such that pumps operate automatically or may be started manually in order to maintain an adequate volume of fuel oil in the day tanks during or following DG testing. Therefore, a 31 day Frequency is appropriate.

McGuire Units 1 and 2 B 3.8.1-17 Revision No. 46

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.1.7 See SR 3.8.1.2.

SR 3.8.1.8 Transfer of each 4.16 kV ESF bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the OPERABILITY of the alternate circuit distribution network to power the shutdown loads.

The 18 month Frequency of the Surveillance is based on engineering judgment, taking into consideration the unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency.

Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is modified by a Note. The reason for the Note is that, during operation with the reactor critical, performance of this SR could cause perturbations to the electrical distribution systems that could challenge continued steady state operation and, as a result, unit safety systems.

SR 3.8.1.9 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. For this unit, the single load for each DG and its kilowatt rating is as follows: Nuclear Service Water Pump which is a 576 kW motor. This Surveillance may be accomplished by:

a. Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power, or while solely supplying the bus; or

b. Tripping its associated single largest post-accident load with the DG solely supplying the bus.

As required by Regulatory Guide 1.9 (Ref. 3), the load rejection test is acceptable if the increase in diesel speed does not exceed 75% of the difference between synchronous speed and the overspeed trip setpoint, or 15% above synchronous speed, whichever is lower.

McGuire Units 1 and 2 B 3.8.1-1 8 Revision No. 46

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 (Ref. 3) recommendations for response during load sequence intervals. The 3 seconds specified is equal to 60% of a typical 5 second load sequence interval associated with sequencing of the largest load. The voltage and frequency specified are consistent with the design range of the equipment powered by the DG.

SR 3.8.1 .9.a corresponds to the maximum frequency excursion, while SR 3.8.1 .9.b and SR 3.8.1.9.c are steady state voltage and frequency values to which the system must recover following load rejection. The 18 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) Table 1.

This Surveillance is performed with the DG connected to its bus in parallel with offsite power supply. The DG is tested under maximum kVAR loading, which is defined as being as close to design basis conditions as practical subject to offsite power conditions. Design basis conditions have been calculated to be greater than 0.9 power factor. During DG testing, equipment ratings are not to be exceeded (i.e., without creating an overvoltage condition on the DG or 4 kV emergency buses, over-excitation in the generator, or overloading the DG emergency feeder while maintaining the power factor greater than or equal to 0.9).

This Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.

SR 3.8.1.10 This Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits.

The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions. This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide for DG damage protection. While the DG is not expected to experience this transient during an event and continues to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.

Although not representative of the design basis inductive loading that the DG would experience, a power factor of approximately unity (1.0) is used for testing. This power factor is chosen in accordance with manufacturer's recommendations to minimize DG overvoltage during testing.

McGuire Units 1 and 2 B 3.8.1 -19 Revision No. 46

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

The 18 month Frequency is consistent with the recommendation of Regulatory Guide 1.9 (Ref. 3) and is intended to be consistent with expected fuel cycle lengths.

This Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.

SR 3.8.1.11 As required by Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.4, this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source. This test verifies the de-energization of the emergency buses, load shedding from the emergency buses and energization of the emergency buses and blackout loads from the DG. Tripping of non-essential loads is not verified in this test. It further demonstrates the capability of the DG to automatically achieve the required voltage and frequency within the specified time.

The DG autostart time of 11 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability is achieved.

The requirement to verify the connection and power supply of the emergency bus and autoconnected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, Emergency Core Cooling Systems (ECCS) injection valves are not desired to be stroked open, or high pressure injection systems are not capable of being operated at full flow, or residual heat removal (RHR) systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG systems to perform these functions is acceptable.

This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1, takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

McGuire Units 1 and 2 B 3.8.1-20 Revision No. 46

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (11 seconds) from the design basis actuation signal (LOCA signal) and operates for 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. SR 3.8.1.12.d ensures that the emergency bus remains energized from the offsite electrical power system on an ESF signal without loss of offsite power. This Surveillance also verified the tripping of non-essential loads. Tripping of non-essential loads is verified only once, either in this SR or in SR 3.8.1.19, since the same circuitry is tested in each SR.

The Frequency of 18 months is consistent with Regulatory Guide 1.9 (Ref. 3) Table 1 and takes into consideration unit conditions required to perform the Surveillance and is intended to be consistent with the expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint. This SR is modified by a Note. The reason for the Note is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations.

SR 3.8.1.13 This Surveillance demonstrates that DG noncritical protective functions (e.g., high jacket water temperature) are bypassed on a loss of voltage signal concurrent with an ESF actuation test signal, and critical protective functions (engine overspeed, generator differential current, low lube oil pressure, generator voltage-controlled overcurrent) trip the DG to avert substantial damage to the DG unit. The noncritical trips are bypassed McGuire Units 1 and 2 B 3.8.1-21 Revision No. 46

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) during DBAs and provide an alarm on an abnormal engine condition.

This alarm provides the operator with sufficient time to react appropriately. The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG.

The 18 month Frequency is consistent with Regulatory Guide 1.9 (Ref. 3)

Table 1, taking into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths. Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This SR is not normally performed in MODE 1 or 2, but it may be performed in conjunction with periodic preplanned preventative maintenance activity that causes the DG to be inoperable. This is acceptable provided that performance of the SR does not increase the time the DG would be inoperable for the preplanned preventative maintenance activity.

SR 3.8.1.14 Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.9, requires demonstration once per 18 months that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , 2 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of which is at a load equivalent from 105% to 110% of the continuous duty rating and the remainder of the time at a load equivalent to the continuous duty rating of the DG. The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelubricating and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.

This Surveillance is performed with the DG connected to its bus in parallel with offsite power supply. The DG is tested under maximum kVAR loading, which is defined as being as close to design basis conditions as practical subject to offsite power conditions. Design basis conditions have been calculated to be greater than 0.9 power factor. During DG testing, equipment ratings are not to be exceeded (i.e., without creating an overvoltage condition on the DG or 4 kV emergency buses, over-excitation in the generator, or overloading the DG emergency feeder while maintaining the power factor greater than or equal to 0.9).

The load band is provided to avoid routine overloading of the DG.

Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.

McGuire Units I and 2 B 3.8.1-22 Revision No. 46

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)

The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1, takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This Surveillance is modified by two Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this test. Note 2 allows gradual loading of the DG in accordance with recommendation from the manufacturer.

This Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.

SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage and frequency within 11 seconds. The 11 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA. The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1.

This SR is modified by two Notes. Note 1 ensures that the test is performed with the diesel sufficiently hot. The load band is provided to avoid routine overloading of the DG. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. The requirement that the diesel has operated for at least 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months at full load conditions prior to performance of this Surveillance is based on manufacturer recommendations for achieving hot conditions. Momentary transients due to changing bus loads do not invalidate this test. Note 2 allows all DG starts to be preceded by an engine prelube period to minimize wear and tear on the diesel during testing.

SR 3.8.1.16 As required by Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.11, this Surveillance ensures that the manual synchronization and automatic load transfer from the DG to the offsite source can be made and the DG can be returned to standby operation when offsite power is restored. It also ensures that the autostart logic is reset to allow the DG to reload if a McGuire Units 1 and 2 B 3.8.1-23 Revision No. 46

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) subsequent loss of offsite power occurs. The DG is considered to be in standby operation when the DG is at rated speed and voltage, the output breaker is open and can receive an autoclose signal on bus undervoltage, and the load sequence timers are reset.

The Frequency of 18 months is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1, and takes into consideration unit conditions required to perform the Surveillance. This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.17 Demonstration of the test mode override ensures that the DG availability under accident conditions will not be compromised as the result of testing and the DG will automatically reset to standby operation if a LOCA actuation signal is received during operation in the test mode. Standby operation is defined as the DG running at rated speed and voltage with the DG output breaker open. These provisions for automatic switchover are required by Regulatory Guide 1.9 (Ref. 3), paragraph 2.2.13. The requirement to automatically energize the emergency loads with offsite power is essentially identical to that of SR 3.8.1.12. The intent in the requirement associated with SR 3.8.1.1 7.b is to show that the emergency loading was not affected by the DG operation in test mode. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The 18 month Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1, takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.18 Under accident and loss of offsite power conditions loads are sequentially connected to the bus by the automatic load sequencer. The sequencing McGuire Units 1 and 2 B 3.8.1-24 Revision No. 46

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents. The load sequence time interval tolerance in Table 8-16 of Reference 2 ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated.

Table 8-1 of Reference 2 provides a summary of the automatic loading of ESF buses. The sequencing times of Table 8-16 are committed and required for OPERABILITY. The typical 1 minute loading duration seen by the accelerated sequencing scheme is NOT required for OPERABILITY.

Operating experience has shown that these components usually pass the SR when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

This takes into consideration unit conditions required to perform the Surveillance, and is intended to be consistent with expected fuel cycle lengths.

SR 3.8.1.19 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

This Surveillance verifies the de-energization of the emergency buses, load shedding from the emergency buses, tripping of non-essential loads and energization of the emergency buses and ESF loads from the DG.

Tripping of non-essential loads is verified only once, either in this SR or in SR 3.8.1.12, since the same circuitry is tested in each SR. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

The Frequency of 18 months is consistent with Regulatory Guide 1.9 (Ref. 3) Table 1.

This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations for DGs. The reason for Note 2 is that the performance of the Surveillance would remove a McGuire Units 1 and 2 B 3.8.1-25 Revision No. 46

AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.

SR 3.8.1.20 This Surveillance demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously.

The 10 year Frequency is consistent with the recommendations of Regulatory Guide 1.9 (Ref. 3) Table 1.

This SR is modified by a Note. The reason for the Note is to minimize wear on the DG during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.

2. UFSAR, Chapter 8.

3. Regulatory Guide 1.9, Rev. 3, July 1993.

4. UFSAR, Chapter 6.

5. UFSAR, Chapter 15.

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

7. Regulatory Guide 1.93, Rev. 0, December 1974.

8. Generic Letter 84-15, Proposed Staff Actions to Improve and Maintain Diesel Generator Reliability," July 2, 1984.

9. 10 CFR 50, Appendix A, GDC 18.

10. Regulatory Guide 1.137, Rev. 1, October 1979.

11. IEEE Standard 308-1971.

McGuire Units 1 and 2 B 3.8.1-26 Revision No. 46

AC Sources-Shutdown B 3.8.2 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.2 AC Sources-Shutdown BASES BACKGROUND A description of the AC sources is provided in the Bases for LCO 3.8.1,

AC Sources-Operating.*

APPLICABLE The OPERABILITY of the minimum AC sources during MODES 5 and 6 SAFETY ANALYSES and during movement of irradiated fuel assemblies ensures that:

a. The unit can be maintained in the shutdown or refueling condition for extended periods;

b. Sufficient instrumentation and control capability is available for monitoring and maintaining the unit status; and

c. Adequate AC electrical power is provided to mitigate events postulated during shutdown, such as a fuel handling accident.

In general, when the unit is shut down, the Technical Specifications requirements ensure that the unit has the capability to mitigate the consequences of postulated accidents. However, assuming a single failure and concurrent loss of all offsite or all onsite power is not required.

The rationale for this is based on the fact that many Design Basis Accidents (DBAs) that are analyzed in MODES 1, 2, 3, and 4 have no specific analyses in MODES 5 and 6. Worst case bounding events are deemed not credible in MODES 5 and 6 because the energy contained within the reactor pressure boundary, reactor coolant temperature and pressure, and the corresponding stresses result in the probabilities of occurrence being significantly reduced or eliminated, and in minimal consequences. These deviations from DBA analysis assumptions and design requirements during shutdown conditions are allowed by the LCO for required systems.

During MODES 1, 2, 3, and 4, various deviations from the analysis assumptions and design requirements are allowed within the Required Actions. This allowance is in recognition that certain testing and maintenance activities must be conducted provided an acceptable level of risk is not exceeded. During MODES 5 and 6, performance of a significant number of required testing and maintenance activities is also required. In MODES 5 and 6, the activities are generally planned and administratively controlled. Relaxations from MODE 1, 2, 3, and 4 LCO requirements are acceptable during shutdown modes based on:

McGuire Units 1 and 2 B 3.8.2-1 Revision No.46

AC Sources-Shutdown B 3.8.2 BASES APPLICABLE SAFETY ANALYSES (continued)

a. The fact that time in an outage is limited. This is a risk prudent goal as well as a utility economic consideration.

b. Requiring appropriate compensatory measures for certain conditions. These may include administrative controls, reliance on systems that do not necessarily meet typical design requirements applied to systems credited in operating MODE analyses, or both.

c. Prudent utility consideration of the risk associated with multiple activities that could affect multiple systems.

d. Maintaining, to the extent practical, the ability to perform required functions (even if not meeting MODE 1, 2, 3, and 4 OPERABILITY requirements) with systems assumed to function during an event.

In the event of an accident during shutdown, this LCO ensures the capability to support systems necessary to avoid immediate difficulty, assuming either a loss of all offsite power or a loss of all onsite diesel generator (DG) power.

The AC sources satisfy Criterion 3 of 10 CFR 50.36 (Ref. 1).

LCO One offsite circuit capable of supplying the onsite Class 1E power distribution subsystem(s) of LCO 3.8.10, Distribution Systems-Shutdown," ensures that all required loads are powered from offsite power. An OPERABLE DG, associated with the distribution system train required to be OPERABLE by LCO 3.8.10, ensures a diverse power source is available to provide electrical power support, assuming a loss of the offsite circuit. Together, OPERABILITY of the required offsite circuit and DG ensures the availability of sufficient AC sources to operate the unit in a safe manner and to mitigate the consequences of postulated events during shutdown (e.g., fuel handling accidents).

The qualified offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident, while connected to the Engineered Safety Feature (ESF) bus(es).

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

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

McGuire Units 1 and 2 B 3.8.2-2 Revision No.46

AC Sources-Shutdown B 3.8.2 BASES LCO (continued)

Normally, each Class 1E 4.16 kV switchgear is powered from its associated non-Class 1E train of the 6.9 kV Normal Auxiliary Power System as discussed in 6.9 kV Normal Auxiliary Power System" in Chapter 8 of the UFSAR. Additionally, an alternate source of power to each 4.16 kV essential switchgear is provided from the 6.9 kV system via two separate and independent 6.9/4.16 kV transformers. These transformers are shared between units and provide the capability to supply an alternate source of preferred power to each unit's 4.16 kV essential switchgear from either units 6.9 kV system. A key interlock scheme is provided to preclude the possibility of connecting the two units together at either the 6.9 or 4.16 kV level.

Each train of the 4.16 kV Essential Auxiliary Power System is also provided with a separate and independent emergency diesel generator to supply the Class 1E loads required to safely shut down the unit following a design basis accident.

The DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESF bus on detection of bus undervoltage. This sequence must be accomplished within 11 seconds.

The DG must be capable of accepting required loads within the assumed loading sequence intervals, and continue to operate until offsite power can be restored to the ESF buses. These capabilities are required to be met from a variety of initial conditions such as DG in standby with the engine hot and DG in standby at ambient conditions.

The sequencer associated with the required DG is also required to be OPERABLE. Proper sequencer operation on safety injection signal is not required by this LCO since safety injection signal is not required to be OPERABLE in the MODES applicable to this LCO.

Proper sequencing of blackout loads is a function of Sequencer OPERABILITY. Proper load shedding is a function of DG OPERABILITY.

In addition, proper sequencer operation is an integral part of offsite circuit OPERABILITY since its inoperability impacts on the ability to start and maintain energized loads required OPERABLE by LCO 3.8.10.

It is acceptable for trains to be cross tied during shutdown conditions, allowing a single offsite power circuit to supply all required trains.

APPLICABILITY The AC sources required to be OPERABLE in MODES 5 and 6 and during movement of irradiated fuel assemblies provide assurance that:

McGuire Units 1 and 2 B 3.8.2-3 Revision No.46

AC Sources-Shutdown B 3.8.2 BASES APPLICABILITY (continued)

a. Systems to provide adequate coolant inventory makeup are available for the irradiated fuel assemblies in the core;

b. Systems needed to mitigate a fuel handling accident are available;

c. Systems necessary to mitigate the effects of events that can lead to core damage during shutdown are available; and

d. Instrumentation and control capability is available for monitoring and maintaining the unit in a cold shutdown condition or refueling condition.

The AC power requirements for MODES 1, 2, 3, and 4 are covered in LCO 3.8.1.

ACTIONS A.1 An offsite circuit would be considered inoperable if it were not available to one required ESF train. Although two trains are required by LCO 3.8.10, the one train with offsite power available may be capable of supporting sufficient required features to allow continuation of CORE ALTERATIONS and fuel movement. By the allowance of the option to declare required features inoperable, with no offsite power available, appropriate restrictions will be implemented in accordance with the affected required features LCO's ACTIONS.

A.2.1. A.2.2. A.2.3. A.2.4. B.1. B.2. B.3. and B.4 With the offsite circuit not available to all required trains, the option would still exist to declare all required features inoperable. Since this option may involve undesired administrative efforts, the allowance for sufficiently conservative actions is made. With the required DG inoperable, the minimum required diversity of AC power sources is not available. It is, therefore, required to suspend CORE ALTERATIONS, movement of irradiated fuel assemblies, and operations involving positive reactivity additions. The Required Action to suspend positive reactivity additions does not preclude actions to maintain or increase reactor vessel inventory provided the required SDM is maintained.

Suspension of these activities does not preclude completion of actions to establish a safe conservative condition. These actions minimize the probability or the occurrence of postulated events. It is further required to immediately initiate action to restore the required AC sources and to McGuire Units 1 and 2 B 3.8.2-4 Revision No.46

AC Sources-Shutdown B 3.8.2 BASES ACTIONS (continued) continue this action until restoration is accomplished in order to provide the necessary AC power to the unit safety systems.

The Completion Time of immediately is consistent with the required times for actions requiring prompt attention. The restoration of the required AC electrical power sources should be completed as quickly as possible in order to minimize the time during which the unit safety systems may be without sufficient power.

Pursuant to LCO 3.0.6, the Distribution System's ACTIONS would not be entered even if all AC sources to it are inoperable, resulting in de-energization. Therefore, the Required Actions of Condition A are modified by a Note to indicate that when Condition A is entered with no AC power to any required ESF bus, the ACTIONS for LCO 3.8.10 must be immediately entered. This Note allows Condition A to provide requirements for the loss of the offsite circuit, whether or not a train is de-energized. LCO 3.8.10 would provide the appropriate restrictions for the situation involving a de-energized train.

SURVEILLANCE SR 3.8.2.1 REQUIREMENTS SR 3.8.2.1 requires the SRs from LCO 3.8.1 that are necessary for ensuring the OPERABILITY of the AC sources in other than MODES 1, 2, 3, and 4. SR 3.8.1.8 is not required to be met since only one offsite circuit is required to be OPERABLE. SRs 3.8.1.12 and 3.8.1.19 are not required to be met because the ESF signals, required for the SRs, are not required to be OPERABLE in MODES 5 or 6. SR 3.8.1.17 is not required to be met because the required OPERABLE DG(s) is not required to undergo periods of being synchronized to the offsite circuit. SR 3.8.1.20 is excepted because starting independence is not required with the DG(s) that is not required to be operable.

This SR is modified by a Note. The reason for the Note is to preclude requiring the OPERABLE DG(s) from being paralleled with the offsite power network or otherwise rendered Inoperable during performance of SRs, and to preclude de-energizing a required 4160 V ESF bus or disconnecting a required offsite circuit during performance of SRs. With limited AC sources available, a single event could compromise both the required circuit and the DG. It is the intent that these SRs must still be capable of being met, but actual performance is not required during periods when the DG and offsite circuit is required to be OPERABLE.

Refer to the corresponding Bases for LCO 3.8.1 for a discussion of each SR.

McGuire Units 1 and 2 B 3.8.2-5 Revision No.46

AC Sources-Shutdown B 3.8.2 BASES REFERENCES 1. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

McGuire Units 1 and 2 B 3.8.2-6 Revision No.46

ML032670598

Text

SUBJECT:

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