Text

Technical Specifications and Technical Specification Bases Updates
	ML093130164
Person / Time
Site:	Mcguire, McGuire
Issue date:	10/29/2009
From:	Beaver B; Duke Energy Carolinas
To:	; Office of Nuclear Reactor Regulation
References
	DUK093020036
	Download: ML093130164 (97)
	v • d • e

DISPOSITION OF THE ORIGINAL DOCUMENT WILL BE TO

,RIORL-- Normal THE TRANSMITTAL SIGNATURE UNLESS RECIPIENT IS Date: 10/29/09 OTHERWISE IDENTIFIED BELOW Document Transmittal #: DUK093020036

1) 01749 L C GIBBY - MG01VP

2) 02049 NGO PRA MANAGER ECO81 Duke Energy QA CONDITION [] Yes U No

3) 02388 DAVID DZIADOSZ LYNCHBG, VA

4) 02532 MCG NRC INSP MG-ADMIN MAIL RM DOCUMENT TRANSMITTAL FORM OTHER ACKNOWLEDGEMENT REQUIRED

Yes IF QA OR OTHER ACKNOWLEDGEMENT REQUIRED, PLEASE

5) 02546 WC LIBRARY - MG01WC ACKNOWLEDGE RECEIPT BY RETURNING THIS FORM TO:

REFERENCE

6) 03044 MCG DOC CNTRL MISC MAN MG05DM

7) 03283 P R TUCKER MG01RP MCGUIRE NUCLEAR STATION Duke Energy

8) 03614 MCG OPS PROCEDURE GP MG01OP McGuire

9) 03743 MCG QA TEC SUP MNT QC MG01MM DCRM MGO2DM RECORD RETENTION # 581188

0) 03744 OPS TRNG MGR. MG03OT 13225 Hagers Ferry Road

1) 03759 U S NUC REG WASHINGTON, DC Huntersville, N.C. 28078

2) 03796 SCIENTECH DUNEDIN, FL TECHNICAL SPECIFICATIONS (TS)

3) 04698 D E BORTZ EC08G TECHNICAL SPECIFICATIONS

4) 04809 MCG PLANT ENG. LIBR. MG05SE

5) 05162 MCG SHIFT WORK MGRS MG010P BASES (TSB)

Rec'd By .A.

Page 2A of 3B Date DOCUMENT NO QA COND REV #/DATE DISTR CODE 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 TOTAL

'S & TSB MEMORANDUM (1 PAGE) NA --- 10/15/09 MADM-04B V1 V1 V1 V1 V1 X V1 V1 VI V3 V8 V1 V1 V2. V1 47

'S LIST OF EFFECTIVE PAGES (11PAGES) NA 084 10/15/09 S 5.5-6 AMEND 252/232 (1PAGE) NA --- 10/15/09.

SB LIST OF EFFECTIVE SECTIONS (3 PAGES) NA 096 10/15/09 SB 2.1.2 (3PAGES) NA 102 10/15/09 SB 3.4.10 (4PAGES) NA 102 10/15/09 "SB 3.4.11 (7PAGES) NA 102 10/15/09

-SB 3.4.12 (12PAGES NA 102 10/15/09

-SB 3.4.14 (6PAGES) NA 102 10/15/09

-SB 3.5.2 (10PAGES) NA 102 10/15/09

-SB 3.6.6 (7PAGES) NA 102 10/15/09 "SB 3.7.1 (5PAGES) NA 102 10/15/09

-SB 3.7.2 (5PAGES) NA 102 10/15/09 "SB 3.7.3 (6PAGES) NA 102 10/15/09

-SB 3.7.5 (8PAGES) NA 102 10/15/09 1EMARKS: PLEASE UPDATE ACCORDINGLY. B H HAMILTON VICE PRESIDENT REPRO: ONE SIDED COPIES THREE HOLE PUNCH MCGUIRE NUCLEAR STATION BY:

RECIPIENT # 00422 PREVIOUSLY COMPLETED B C BEAVER MG01RC BCB/TLC 0$)/

DISPOSITION OF THE ORIGINAL DOCUMENT WILL BE TO PRIOFW7( Normal THE TRANSMITTAL SIGNATURE UNLESS RECIPIENT IS Date: 10/29/09 OTHERWISE IDENTIFIED BELOW Document Transmittal #: DUK093020036

1) 01749 L C GIBBY - MG01VP

2) 02049 NGO PRA MANAGER EC081 Duke Energy QA CONDITION [: Yes

No

3) 02388 DAVID DZIADOSZ LYNCHBG, VA

4) 02532 MCG NRC INSP MG-ADMIN MAIL RM DOCUMENT TRANSMITTAL FORM OTHER ACKNOWLEDGEMENT REQUIRED

Yes IFQA OR OTHER ACKNOWLEDGEMENT REQUIRED, PLEASE

5) 02546WC LIBRARY - MG01WC ACKNOWLEDGE RECEIPT BY RETURNING THIS FORM TO:

REFERENCE

6) 03044 MCG DOC CNTRL MISC MAN MG05DM

7) 03283 P R TUCKER MG01RP MCGUIRE NUCLEAR STATION Duke Energy

8) 03614 MCG OPS PROCEDURE GP MG01OP McGuire

9) 03743 MCG QA TEC SUP MNT QC MG01MM DCRM MGO2DM RECORD RETENTION # 581188

0) 03744 OPS TRNG MGR. MG03OT 13225 Hagers Ferry Road

1) 03759 U S NUC REG WASHINGTON, DC Huntersville, N.C. 28078

2) 03796 SCIENTECH DUNEDIN, FL TECHNICAL SPECIFICATIONS (TS)

3) 04698 D E BORTZ EC08G TECHNICAL SPECIFICATIONS

4) 04809 MCG PLANT ENG. LIBR. MG05SE

5) 05162 MCG SHIFT WORK MGRS MG010P BASES (TSB)

Rec'd By Page 2B of 3B Date DOCUMENT NO IQA CONDI REV #I DATEI DISTR CODE 1 12 13. 4 ]5 6 7 8 9 10 11 12 113 {14 115 ITOTAL FSB 3.7.7 (6PAGES) NA 101 10/15/09 MADM-04B V1 V1 Vi x V1 Vi V1 V3 V8 V1 V1 V2 vi 47 REMARKS: PLEASE UPDATE ACCORDINGLY. B H HAMILTON REPRO: ONE SIDED COPIES VICE PRESIDENT THREE HOLE PUNCH MCGUIRE NUCLEAR STATION BY:

RECIPIENT # 00422 PREVIOUSLY COMPLETED B C BEAVER MG01RC BCB/TLC

October 15, 2009 MEMORANDUM To: All McGuire Nuclear Station Technical Specification (TS) and Technical Specification Bases (TSB)

Manual Holders

Subject:

McGuire TS and TSB Updates REMOVE INSERT TS Manual TS LOEP (entire doc) Rev 83 TS LOEP (entire doc) Rev 84 TS 5.5-6 (one page only) TS 5.5-6 (252/232) (one page only)

TSB Manual TS Bases LOES (entire doc) rev 95 TS Bases LOES (entire doc) rev 96 TSB 2.1.2 (entire doc) TSB 2.1.2 (entire doc) rev 102 TSB 3.4.10 (entire doc) TSB 3.4.10 (entire doc) rev 102 TSB 3.4.11 (entire doc) TSB 3.4.11 (entire doc) rev 102 TSB 3.4.12 (entire doc) TSB 3.4.12 (entire doc) rev 102 TSB 3.4.14 (entire doc) TSB 3.4.14 (entire doc) rev 102 TSR 3.5.2 (entire doc) TSB 3.5.2 (entire doc) rev 102 TSR 3.6.6 (entire doc) TSB 3.6.6 (entire doc) rev 102 TSB 3.7.1 (entire doc) TSB 3.7.1 (entire doc) rev 102 TSB 3.7.2 (entire doc) TSB 3.7.2 (entire doc) rev 102 TSB 3.7.5 (entire doc) SB 3.7.5 (entire doe) rev 102 TSB 3.7.7 (entire doc) TSB 3.7.7 (entire doc) rev 101 S.1.3 (en'rc JoeR Revision numbers may skip numbers due to Regulatory Compliance Filing System.

Please call me if you have questions.

Bonnie Beaver Regulatory Compliance 875-4180

McGuire Nuclear Station Technical Specifications LOEP Page Number Amendment Revision Date 184/166 9/30/98 ii 227/209 4/4/05 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 1.1-3 237/219 3/1/07 1.1-4 194/175 9/18/00 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 1.3-7 184/166 9/30/98 1.3-8 184/166 9/30/98 1.3-9 184/166 9/30/98 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 2.0-1 219/201 1/14/04 McGuire Units I and 2 Page I Revision 84

Page Number Amendment Revision Date 3.0-1 238/220 3/29/07 3.0-2 221/203 4/29/04 3.0-3 238/220 3/29/07 3.0-4 205/186 8/12/02 3.0-5 221/203 4/29/04 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 3.1.4-4 186/167 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 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 McGuire Units 1 and 2 Page 2 Revision 84

Page Number Amendment Revision Date 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 3.3.1-2 248/228 3/9/09 3.3.1-3 248/228 3/9/09 3.3.1-4 216/197 7/29/03 3.3.1-5 250/230 3/9/09 3.3.1-6 248/228 3/9/09 3.3.1-7 248/228 3/9/09 3.3.1-8 184/166 9/30/98.

3.3.1-9 184/1 66 9/30/98 3.3.1-10 248/228 3/9/09 3.3.1-11 248/228 3/9/09 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 3.3.1-15 222/204 6/21/04 3.3.1-16 194/175 9/18/00 3.3.1-17 194/175 9/18/00 3.3.1-18 219/201 1/14/04 3.3.1-19 219/201 1/14/04 3.3.1-20 184/166 9/30/98 3.3.2-1 184/166 9/30/98 3.3.2-2 250/230 3/9/09 3.3.2-3 248/228 3/9/09 3.3.2-4 248/228 3/9/09 3.3.2-5 248/228 3/9/09 3.3.2-6 198/179 4/12/01 3.3.2-7 198/179 4/12/01 3.3.2-8 250/230 3/9/09 3.3.2-9 184/166 9/30/98 McGuire Units 1 and 2 Page 3 Revision 84

Page Number Amendment Revision Date 3.3.2-10 220/202 3/18/04 3.3.2-11 220/202 3/18/04 3.3.2-12 224/206 1/27/05 3.3.2-13 220/202 3/18/04 3.3.2-14 220/202 3/18/04 3.3.3-1 221/203 4/29/04 3.3.3-2 227/209 4/4/05 3.3.3-3 227/209 4/4/05 3.3.3-4 227/209 4/4/05 3.3.4-1 221/203 4/29/04 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 Not Used - 243/224 7/26/07 3.4.1-1 219/201 1/14/04 3.4.1-2 219/201 1/14/04 3.4.1-3 184/166 9/30/98 3.4.1-4 219/201 1/14/04 3.4.2-1 184/166 9/30/98 3.4.3-1 214/195 7/3/03 3.4.3-2 184/1 66 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 3.4.3-8 214/ 195 7/3/03 3.4.4-1 184/166 9/30/98 3.4.5-1 216/197 7/29/03 3.4.5-2 216/197 7/29/03 3.4.5-3 184/166 9/30/98 3.4.6-1 216/197 7/29/03 3.4.6-2 216/197 7/29/03 McGuire Units 1 and 2 Page 4 Revision 84

Page Number Amendment Revision Date 3.4.7-1 216/197 7/29/03 3.4.7-2 216/197 7/29/03 3.4.7-3 216/197 7/29/03 3.4.8-1 216/197 7/29/03 3.4.8-2 216/197 7/29/03 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 3.4-11-1 221/203 4/29/04 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 3.4.12-2 221/203 4/29/04 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 3.4.13-1 237/219 3/1/07 3.4.13-2 237/219 3/1/07 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 3.4.15-1 235/217 9/30/06 3.4.15-2 235/217 9/30/06 3.4.15-3 235/217 9/30/06 3.4.15-4 235/217 9/30/06 3.4.16-1 221/203 4/29/04 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 McGuire Units 1 and 2 Page 5 Revision 84

Page Number Amendment Revision Date 3.4.17-1 184/166 9/30/98 3.4.18-1 237/219 3/1/07 3.4.18-2 237/219 3/1/07 3.5.1-1 218/200 12/23/03 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 3.5.2-3 240/222 5/4/07 3.5.3-1 221/203 4/29/04 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 3.6.3-1 243/224 7/26/07 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 3.6.3-5 243/224 7/26/07 3.6.3-6 243/224 7/26/07 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 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 Not Used - 227/209 4/4/05 McGuire Units 1 and 2 Page 6 Revision 84

Page Number Amendment Revision Date 3.6.8-1 221/203 4/29/04 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 3.6.12-2 217/199 9/29/03 3.6.12-3 217/199 9/29/03 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 3.6.14-1 228/210 4/5/05 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 3.7.4-1 221/203 4/29/04 3.7.4-2 184/166 9/30/98 3.7.5-1 221/203 4/29/04 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 McGuire Units'l and 2 Page 7 Revision 84

Page Number Amendment Revision Date 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 3.7.9-1 249/229 1/30/09 3.7.9-2 249/229 1/30/09 3.7.9-3 249/229 1/30/09 3.7.10-1 184/166 9/30/98 3.7.10-2 184/166 9/30/98 3.7.11-1 229/211 6/2/05 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 3.7.15-1 225/207 3/17/05 3.7.15-2 225/207 3/17/05 3.7.15-3 225/207 3/17/05 3.7.15-4 225/207 3/17/05 3.7.15-5 225/207 3/17/05 3.7.15-6 225/207 3/17/05 3.7.15-7 225/207 3/17/05 3.7.15-8 225/207 3/17/05 3.7.15-9 225/207 3/17/05 3.7.15-10 225/207 3/17/05 3.7.15-11 225/207 3/17/05 3.7.15-12 225/207 3/17/05 3.7.15-13 225/207 3/17/05 3.7.15-14 225/207 3/17/05 3.7.15-15 225/207 3/17/05 3.7.15-16 225/207 3/17/05 3.7.15-17 225/207 3/17/05 McGuire Units 1 and 2 Page 8 P evision 84

Page Number Amendment Revision Date 3.7.15-18 225/207 3/17/05 3.7.15-19 225/207 3/17/05 3.7.15-20 225/207 3/17/05 3.7.15-21 225/207 3/17/05 3.7.15-22 225/207 3/17/05 3.7.15-23 225/207 3/17/05 3.7.15-24 225/207 3/17/05 3.7.15-25 225/207 3/17/05 3.7.15-26 225/207 3/17/05 3.7.15-27 225/207 3/17/05 3.7.15-28 225/207 3/17/05 3.7.15-29 225/207 3/17/05 3.7.15-30 225/207 3/17/05 3.7.15-31 225/207 3/17/05 3.7.15-32 225/207 3/17/05 3.7.16-1 184/166 9/30/98 3.8.1-1 221/203 4/29/04 3.8.1-2 184/166 9/30/98 3.8.1-3 241/-, 06/08/07 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 3.8.1-11 242/223 7/25/07 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 3.8.2-2 216/197 7/29/03 3.8.2-3 184/166 9/30/98 McGuire Units 1 and 2 Page 9 Revision 84

Page Number Amendment Revision Date 3.8.3-1 184/166 9/30/98 3.8.3-2 184/166 9/30/98 3.8.3-3 215/196 8/4/03 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 3.8.5-2 216/197 7/29/03 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 3.8.8-2 216/197 7/29/03 3.8.9-1 184/166 9/30/98 3.8.9-2 184/166 9/30/98 3.8.10-1 216/197 7/29/03 3.8.10-2 184/166 9/30/98 3.9.1-1 231/213 9/1/05 3.9.2-1 184/166 9/30/98 3.9.3-1 216/197 7/29/03 3.9.3-2 184/166 9/30/98 3.9.4-1 236/218 12/22/06 3.9.4-2 184/166 9/30/98 3.9.5-1 216/197 7/29/03 3.9.5-2 184/166 9/30/98 3.9.6-1 216/197 7/29/03 3.9.6-2 184/166 9/30/98 3.9.7-1 184/166 9/30/98 4.0.1 225/207 3/17/05 4.0.2 225/207 3/17/05 5.1-1 213/194 6/6/03 5.2-1 239/221 04/12/07 McGuir*e Units 1 and 2 Page 10 R'evision 84

Page Number Amendment Revision Date 5.2-2 253/233 9/21/09 5.2-3 213/194 6/6/03 5.3-1 213/194 6/6/03 5.4-1 184/166 9/30/98 5.5-1 244/193 2/13/08 5.5-2 212/193 5/8/03 5.5-3 184/166 9/30/98 5.5-4 184/166 9/30/98 5.5-5 223/205 8/5/04 5.5-6 254/234 .8/17/09 5.5-7 237/219 3/1/07 5.5-8 237/219 3/1/07 5.5-9 237/219 3/1/07 5.5-10 237/219 3/1/07 5.5-11 237/219 3/1/07 5.5-12 237/219 3/1/07 5.5-13 237/219 3/1/07 5.5-14 249/229 1/30/09 5.5-15 249/229 1/30/09 5.6-1 226/208 3/1/07 5.6-2 226/208 3/1/07 5.6-3 226/208 3/1/07 5.6-4 230/212 8/23/05 5.6-5 237/219 3/1/07 5.7-1 213/194 6/6/03 5.7-2 184/166 9/30/98 McGuire Units 1 and 2 Page I I Revision 84

Programs and Manuals 5.5 5.5 Programs and Manuals (continued) 5.5.8 Inservice Testing Program This program provides controls for inservice testing of ASME Code Class 1, 2, and 3 components including applicable supports. The program shall include the following:

a. Testing frequencies applicable to the ASME Code for Operation and Maintenance of Nuclear Power Plants (ASME OM Code) and applicable Addenda as follows:

ASME OM Code and applicable Required Frequencies for Addenda terminology for performing inservice testing inservice testing activities activities Weekly At least once per 7 days Monthly At least once per 31 days Quarterly or every 3 months At least once per 92 days Semiannually or every 6 months At least once per 184 days Every 9 months At least once per 276 days Yearly or annually At least once per 366 days Biennially or every 2 years At least once per 731 days

b. The provisions of SR 3.0.2 are applicable to the above required Frequencies and to other normal and accelerated Frequencies specified as 2 years or less in the Inservice Testing Program for performing inservice testing activities;

c. The provisions of SR 3.0.3 are applicable to inservice testing activities; and

d. Nothing in the ASME OM Code shall be construed to supersede the requirements of any TS.

5.5.9 Steam Generator (SG) Program A Steam Generator Program shall be established and implemented to ensure that SG tube integrity is maintained. In addition, the Steam Generator Program shall include the following provisions:

a. Provisions for condition monitoring assessments. Condition monitoring assessment means an evaluation of the "as found" condition of the tubing with respect to the performance criteria for structural integrity and accident induced leakage. The "as found" condition refers to the condition of the tubing during an SG inspection outage, as determined from the inservice inspection results or by other means, prior to the plugging (continued)

McGuire Units 1 and 2 5.5-6 u Amendment Nos. 252/232

McGuire Nuclear Station Technical Specification Bases LOES TS Bases are revised by section Page Number Revision Revision Date BASES (Revised per section)

Revision 87 8/15/07 ii Revision 87 8/15/07 iii Revision 87 8/15/07 B 2.1.1 Revision 51 1/14/04 B 2.1.2 Revision 102 8/17/09 B 3.0 Revision 81 3/29/07 B 3.1.1 Revision 73 3/6/06 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 58 06/23/04 B 3.1.8 Revision 0 9/30/98 B 3.2.1 Revision 74 5/3/06 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 99 3/9/09 B 3.3.2 Revision 99 3/9/09 B 3.3.3 Revision 100 4/13/09 B 3.3.4 Revision 57 4/29/04 B 3.3.5 Revision 11 9/18/00 B 3.3.6 Not Used - Revision 87 6/29/06 B 3.4.1 Revision 51 1/14/04 B 3.4.2 Revision 0 9/30/98 B 3.4.3 Revision 44 7/3/03 B 3.4.4 Revision 86 6/25/07 B 3.4.5 Revision 86 6/25/07 McGuire Units 1 and 2 Page I Revision 96

Page Number Amendment Revision Date B 3.4.6 Revision 86 6/25/07 B 3.4.7 Revision 86 6/25/07 B 3.4.8 Revision 41 7/29/03 B 3.4.9 Revision 0 9/30/98 B 3.4.10 Revision 102 8/17/09 B 3.4.11 Revision 102 8/17/09 B 3.4.12 Revision 102 8/17/09 B 3.4.13 Revision 86 6/25/07 B 3.4.14 Revision 102 8/17/09 B 3.4.15 Revision 82 9/30/06 B 3.4.16 Revision 57 4/29/04 B 3.4.17 Revision 0 9/30/98 B 3.4.18 Revision 86 6/25/07 B 3.5.1 Revision 70 10/5/05 B 3.5.2 Revision 102 8/17/09 B 3.5.3 Revision 57 4/29/04 B 3.5.4 Revision 70 10/5/04 B 3.5.5 Revision 0 9/30/98 B 3.6.1 Revision 53 2/17/04 B 3.6.2 Revision 98 3/24/09 B 3.6.3 Revision 87 6/29/06 B 3.6.4 Revision 0 9/30/98 B 3.6.5 Revision 0 9/30/98 B 3.6.5-2 Revision 6 10/6/99 B 3.6.6 Revision 102 8/17/09 B 3.6.7 Not Used - Revision 63 4/4/05 B 3.6.8 Revision 63 4/4/05 B 3.6.9 Revision 63 4/4/05 B 3.6.10 Revision 43 5/28/03 B 3.6.11 Revision 78 9/25/06 B 3.6.12 Revision 53 2/17/04 B 3.6.13 Revision 96 9/26/08 B 3.6.14 Revision 64 4/23/05 B 3.6.15 Revision 0 9/30/98 McGuire Units 1 and 2 Page 2 Revision 96

Page Number Amendment Revision Date B 3.6.16 Revision 40 5/8/03 B 3.7.1 Revision 102 8/17/09 B 3.7.2 Revision 102 8/17/09 B 3.7.3 Revision 0 9/30/98 B 3.7.4 Revision 57 4/29/04 B 3.7.5 Revision102 8/17/09 B 3.7.6 Revision 0 9/30/98 B 3.7.7 Revision 101 9/17/09 B 3.7.8 Revision 0 9/30/98 B 3.7.9 Revision 97 1/30/09 B 3.7.10 Revision 75 6/12/06 B 3.7.11 Revision 65 6/2/05 B 3.7.12 Revision 28 5/17/02 B 3.7.13 Revision 85 2/26/07 B 3.7.14 Revision 66 6/30/05 B 3.7.15 Revision 66 6/30/05 B 3.7.16 Revision 0 9/30/98 B 3.8.1 Revision 92 1/28/08 B 3.8.2 Revision 92 1/28/08 B 3.8.3 Revision 53 2/17/04 B 3.8.4 Revision 100 4/13/09 B 3.8.5 Revision 41 7/29/03 B 3.8.6 Revision 0 9/30/98 B 3.8.7 Revision 20 1/10/02 B 3.8.8 Revision 41 7/29/03 B 3.8.9 Revision 24 2/4/02 B 3.8.10 Revision 41 7/29/03 B 3.9.1 Revision 68 9/1/05 B 3.9.2 Revision 41 7/29/03 B 3.9.3 Revision 91 11/7/07 B 3.9.4 Revision 84 2/20/07 B 3.9.5 Revision 59 7/29/04 B 3.9.6 Revision 41 7/29/03 B 3.9.7 Revision 88 9/5/07 McGuire Units 1 and 2 Page 3 Revision 96

RCS Pressure SL B 2.1.2 B 2.0 SAFETY LIMITS (SLs)

B 2.1.2 Reactor Coolant System (RCS) Pressure SL BASES BACKGROUND The SL on RCS pressure protects the integrity of the RCS against overpressurization. In the event of fuel cladding failure, fission products are released into the reactor coolant. The RCS then serves as the primary barrier in preventing the release of fission products into the atmosphere. By establishing an upper limit on RCS pressure, the continued integrity of the RCS is ensured. According to 10 CFR 50, Appendix A, GDC 14, "Reactor Coolant Pressure Boundary," and GDC 15, "Reactor Coolant System Design" (Ref. 1), the reactor coolant pressure boundary (RCPB) design conditions are not to be exceeded during normal operation and anticipated operational occurrences (AOOs).

Also, in accordance with GDC 28, "Reactivity Limits" (Ref. 1), reactivity accidents, including rod ejection, do not result in damage to the RCPB greater than limited local yielding.

The design pressure of the RCS is 2500 psia. During normal operation and AOOs, RCS pressure is limited from exceeding the design pressure by more than 10%, in accordance with Section III of the ASME Code (Ref. 2). To ensure system integrity, all RCS components are hydrostatically tested at 125% of design pressure, according to the ASME Code requirements prior to initial operation when there is no fuel in the core. Following inception of unit operation, RCS components shall be pressure tested, in accordance with the requirements of the ASME OM Code (Ref. 3).

Overpressurization of the RCS could result in a breach of the RCPB. If such a breach occurs in conjunction with a fuel -cladding failure, fission products could enter the containment atmosphere, raising concerns relative to limits on radioactive releases specified in 10 CFR 100, "Reactor Site Criteria" (Ref. 4).

APPLICABLE The RCS pressurizer safety valves, the main steam safety valves SAFETY ANALYSES (MSSVs), and the reactor high pressure trip have settings established to ensure that the RCS pressure SL will not be exceeded.

The RCS pressurizer safety valves are sized to prevent system pressure from exceeding the design pressure by more than 10%, as specified in Section III of the ASME Code for Nuclear Power Plant Components McGuire Units 1 and 2 B 2.1.2-1 Revision No. 102

RCS Pressure SL B 2.1.2 BASES APPLICABLE SAFETY ANALYSES (continued)

(Ref. 2), for anticipated operational occurrences. During the transient, no control actions are assumed, except that the safety valves on the secondary plant are assumed to open when the steam pressure reaches the secondary plant safety valve settings, and nominal feedwater supply is maintained.

The Reactor Trip System setpoints (Ref. 5), together with the settings of the MSSVs, provide pressure protection for normal operation and AOOs.

The reactor high pressure trip setpoint is specifically set to provide protection against overpressurization (Ref. 5). The safety analyses for both the high pressure trip and the RCS pressurizer safety valves are performed using conservative assumptions relative to pressure control devices.

More specifically, no credit is taken for operation of the following:

a. Pressurizer power operated relief valves (PORVs);

b. Steam Generator (SG) PORVs;

c. Steam Dump System;

d. Rod Control System;

e. Pressurizer Level Control System; or

f. Pressurizer spray valves.

SAFETY LIMITS The maximum transient pressure allowed in the RCS pressure vessel under the ASME Code,Section III, is 110% of design pressure. The maximum transient pressure allowed in the RCS piping, valves, and fittings under ASME Code Section III (Ref. 2) is 120% of design pressure.

The most limiting of these two allowances is the 110% of design pressure; therefore, the SL on maximum allowable RCS pressure is 2735 psig.

APPLICABILITY SL 2.1.2 applies in MODES 1, 2, 3, 4, and 5 because this SL could be approached or exceeded in these MODES due to overpressurization events. The SL is not applicable in MODE 6 because the reactor vessel head closure bolts are not fully tightened, making it unlikely that the RCS can be pressurized.

McGuire Units 1 and 2 B 2.1.2-2 Revision No. 102 '

RCS Pressure SL B 2.1.2 BASES SAFETY LIMIT If the RCS pressure SL is violated when the reactor is in MODE I or 2, VIOLATIONS the requirement is to restore compliance and be in MODE 3 within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

Exceeding the RCS pressure SL may cause immediate RCS failure and create a potential for radioactive releases in excess of 10 CFR 100, "Reactor Site Criteria," limits (Ref. 4).

The allowable Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months recognizes the importance of reducing power level to a MODE of operation where the potential for challenges to safety systems is minimized.

If the RCS pressure SL is exceeded in MODE 3, 4, or 5, RCS pressure must be restored to within the SL value within 5 minutes. Exceeding the RCS pressure SL in MODE 3, 4, or 5 is more severejthan exceeding this SL in MODE 1 or 2, since the reactor vessel temperature may be lower and the vessel material, consequently, less ductile. As such, pressure must be reduced to less than the SL within 5 minutes. The action does not require reducing MODES, since this would require reducing temperature, which would compound the problem by adding thermal gradient stresses to the existing pressure stress.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 14, GDC 15, and GDC 28.

2. ASME, Boiler and Pressure Vessel Code,Section III, 1971 Edition, Winter 1971 Addenda.

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

4. 10 CFR 100.

5. UFSAR, Section 7.2.

McGuire Units 1 and 2 B 2.1.2-3 Revision No. 102

Pressurizer Safety Valves B 3.4.10 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.10 Pressurizer Safety Valves BASES BACKGROUND The pressurizer safety valves provide, in conjunction with the Reactor Protection System, overpressure protection for the RCS.

The pressurizer safety valves are totally enclosed pop type, spring loaded, self actuated valves with backpressure compensation.

The safety valves are designed to prevent the system pressure from exceeding the system Safety Limit (SL), 2735 psig, which is 110% of the design pressure.

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

Overpressure protection is required in MODES 1, 2, 3, 4, and 5; however, in MODE 4, with one or more RCS cold leg temperatures < 300 0 F, and MODE 5 and MODE 6 with the reactor vessel head on, overpressure protection is provided by operating procedures and by meeting the requirements of LCO 3.4.12, "Low Temperature Overpressure Protection (LTOP) System."

The upper pressure limit of +3% is consistent with the ASME requirement (Ref. 1)for lifting pressures above 1000 psig. The lower pressure limit of -2% is selected such that the minimum LCO lift pressure remains above the uncertainty adjusted high pressure reactor trip setpoint. The lift setting is for the ambient conditions associated with MODES 1, 2, and 3. This requires either that the valves be set hot or that a correlation between hot and cold settings be established.

The pressurizer safety valves are part of the primary success path and mitigate the effects of postulated accidents. OPERABILITY of McGuire Units 1 and 2 B 3.4.10-1 Revision No. 102 )

Pressurizer Safety Valves B 3.4.10 BASES BACKGROUND (continued) the safety valves ensures that the RCS pressure will be limited to 110% of design pressure. The consequences of exceeding the American Society of Mechanical Engineers (ASME) pressure limit (Ref. 1) could include damage to RCS components, increased leakage, or a requirement to perform additional stress analyses prior to resumption of reactor operation.

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

a. Uncontrolled rod withdrawal;

b. Loss of reactor coolant flow;

c. Loss of external electrical load;

d. Loss of normal feedwater;

e. Loss of all AC power to station auxiliaries;

f. Locked rotor; and

g. Turbine trip.

Detailed analyses of the above transients are contained in Reference 2. Compliance with this LCO is consistent with the design bases and accident analyses assumptions.

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

5).

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

McGuire Units 1 and 2 B 3.4.10-2 Revision No. 102

Pressurizer Safety Valves B 3.4.10 BASES LCO (continued)

The limit protected by this Specification is the reactor coolant pressure boundary (RCPB) SL of 110% of design pressure.

Inoperability of one or more valves could result in exceeding the SL if a transient were to occur. The consequences of exceeding the ASME pressure limit could include damage to one or more RCS components, increased leakage, or additional stress analysis being required prior to resumption of reactor operation.

APPLICABILITY In MODES 1, 2, and 3, and portions of MODE 4 above the LTOP arming temperature, OPERABILITY of three valves is required because the combined capacity is required to keep reactor coolant pressure below 110% of its design value during certain accidents.

MODE 3 and portions of MODE 4 are conservatively included, although the listed accidents may not require the safety valves for protection.

The LCO is not applicable in MODE 4 when all RCS cold leg temperatures are _< 300OF or in MODE 5 because LTOP is provided. Overpressure protection is not required in MODE 6 with the reactor vessel head removed.

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

ACTIONS A..1 With one pressurizer safety valve inoperable, restoration must take place within 15 minutes. The Completion Time of 15 minutes reflects the importance of maintaining the RCS Overpressure Protection System. An inoperable safety valve coincident with an RCS overpressure event could challenge the integrity of the pressure boundary.

McGuire Units 1 and 2 B 3.4.10-3 Revision No. 102

Pressurizer Safety Valves B 3.4.10 BASES ACTIONS (continued)

B.1 and B.2 If the Required Action of A.1 cannot be met within the required Completion Time or if two or more pressurizer safety valves are inoperable, the plant must be brought to a MODE in which the requirement does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 with any RCS cold leg temperatures < 3001F 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. With any RCS cold leg temperatures at or below 3001F, overpressure protection is provided by the LTOP System. The change from MODE 1, 2, or 3 to MODE 4 reduces the RCS energy (core power and pressure), lowers the potential for large pressurizer insurges, and thereby removes the need for overpressure protection by three pressurizer safety valves.

SURVEILLANCE SR 3.4.10.1 REQUIREMENTS SRs are specified in the Inservice Testing Program. Pressurizer safety valves are to be tested in accordance with the requirements of the ASME OM Code (Ref. 4), which provides the activities and Frequencies necessary to satisfy the SRs. No additional requirements are specified.

The pressurizer safety valve setpoint is + 3% and - 2% of the nominal setpoint of 2485 psig for OPERABILITY; however, the valves are reset to +/- 1% during the Surveillance to allow for drift.

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

2. UFSAR, Chapter 15.

3. UFSAR Section 5.2.

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

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

McGuire Units 1 and 2 B 3.4.10-4 Revision No. 102

Pressurizer PORVs B 3.4.11 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.11 Pressurizer Power Operated Relief Valves (PORVs)

BASES BACKGROUND The pressurizer is equipped with two types of devices for pressure relief:

pressurizer safety valves and PORVs. The PORVs are air operated valves that are controlled to open at a specific set pressure when the pressurizer pressure increases and close when the pressurizer pressure decreases. The PORVs may also be manually operated from the control room.

Block valves, which are normally open, are located between the pressurizer and the PORVs. The block valves are used to isolate the PORVs in case of excessive leakage or a stuck open PORV. Block valve closure is accomplished manually using controls in the control room. A stuck open PORV is, in effect, a small break loss of coolant accident (LOCA). As such, block valve closure terminates the RCS depressurization and coolant inventory loss.

The PORVs and their associated block valves may be used by plant operators to depressurize the RCS to recover from certain transients if normal pressurizer spray is not available. Additionally, the series arrangement of the PORVs and their block valves permit performance of surveillances on the valves during power operation.

The PORVs may also be used for feed and bleed core cooling in the case of multiple equipment failure events that are not within the design basis, such as a total loss of feedwater.

The PORVs, their block valves, and their controls are powered from the vital buses that normally receive power from offsite power sources, but are also capable of being powered from emergency power sources in the event of a loss of offsite power. Three PORVs and their associated block valves are powered from two separate safety trains (Ref. 1).

The plant has three PORVs, each having a relief capacity of 210,000 lb/hr at 2335 psig. The functional design of the PORVs is based on maintaining pressure below the Pressurizer Pressure-High reactor trip setpoint following a step reduction of 50% of full load with steam dump.

In addition, the PORVs minimize challenges to the pressurizer safety valves and also may be used for low temperature overpressure protection (LTOP). See LCO 3.4.12, "Low Temperature Overpressure Protection (LTOP) System."

McGuire Units 1 and 2 B 3.4.11 -1 Revision No. 102

Pressurizer PORVs B 3.4.11 BASES APPLICABLE Plant operators employ the PORVs to depressurize the RCS in response SAFETY ANALYSES to certain plant transients if normal pressurizer spray is not available. For the Steam Generator Tube Rupture (SGTR) event, the safety analysis assumes that manual operator actions are required to mitigate the event.

A loss of offsite power is assumed to accompany the event, and thus, normal pressurizer spray is unavailable to reduce RCS pressure. The PORVs are assumed to be used for manual RCS depressurization, which is one of the steps performed to equalize the primary and secondary' pressures in order to terminate the primary to secondary break flow and the radioactive releases from the affected steam generator.

The PORVs are assumed to operate in safety analyses for events that result in increasing RCS pressure for which departure from nucleate boiling ratio (DNBR) criteria are critical. By assuming PORV automatic actuation, the primary pressure remains below the high pressurizer pressure trip setpoint; thus, the DNBR calculation is more conservative.

Events that assume this condition include uncontrolled bank withdrawal at power, uncontrolled bank withdrawal from subcritical, and single rod withdrawal at power (Ref. 2).

Pressurizer PORVs satisfy Criterion 3 of 10 CFR 50.36 (Ref. 3).

LCO The LCO requires the PORVs and their associated block valves to be .,

OPERABLE for manual operation to mitigate the effects associated with an SGTR.

By maintaining two PORVs and their associated block valves OPERABLE, the single failure criterion is satisfied. Three PORVs are required to be OPERABLE to meet RCS pressure boundary requirements. The block valves are available to isolate the flow path through either a failed open PORV or a PORV with excessive leakage.

Satisfying the LCO helps minimize challenges to fission product barriers.

APPLICABILITY In MODES 1, 2, and 3, the PORV and its block valve are required to be OPERABLE to limit the potential for a small break LOCA through the flow path. The most likely cause for a PORV small break LOCA is a result of a pressure increase transient that causes the PORV to open. Imbalances in the energy output of the core and heat removal by the secondary system can cause the RCS pressure to increase to the PORV opening setpoint. The most rapid increases will occur at the higher operating power and pressure conditions of MODES 1 and 2.

McGuire Units 1 and 2 B 3.4.11-2 Revision No. 102

Pressurizer PORVs B 3.4.11 BASES APPLICABILITY (continued)

Pressure increases are less prominent in MODE 3 because the core input energy is reduced, but the RCS pressure is high. Therefore, the LCO is applicable in MODES 1, 2, and 3. The LCO is not applicable in MODE 4 when both pressure and core energy are decreased and the pressure surges become much less significant. The PORV setpoint is reduced for LTOP in MODES 4 < 300 0 F, 5, and 6 with the reactor vessel head in place. LCO 3.4.12 addresses the PORV requirements in these MODES.

ACTIONS A Note has been added to clarify that all pressurizer PORVs are treated as separate entities, each with separate Completion Times (i.e., the Completion Time is on a component basis).

A._1 With the PORVs inoperable and capable of being manually cycled, either the PORVs must be restored or the flow path isolated within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . The block valves should be closed but power must be maintained to the associated block valves, since removal of power would render the block valve inoperable. Although a PORV may be designated inoperable, it may be able to be manually opened and closed, and therefore, able to perform its function. PORV inoperability may be due to seat leakage or other causes that do not prevent manual use and do not create a possibility for a small break LOCA. For these reasons, the block valve may be closed but the Action requires power be maintained to the valve.

This Condition is only intended to permit operation of the plant for a limited period of time not to exceed the next refueling outage (MODE 6) so that maintenance can be performed on the PORVs to eliminate the problem condition. Normally, the PORVs should be available for automatic mitigation of overpressure events and should be returned to OPERABLE status prior to entering startup (MODE 2).

Quick access to the PORV for pressure control can be made wheni power remains on the closed block valve. The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is based on plant operating experience that has shown that minor problems can be corrected or closure accomplished in this time period.

McGuire Units 1 and 2 B 3.4.11-3 Revision No. 102

Pressurizer PORVs B 3.4.11 BASES ACTIONS (continued)

B.1. B.2, and B.3 If one or two PORVs are inoperable and not capable of being manually cycled, it must be either restored or isolated by closing the associated block valve and removing the power to the associated block valve. If one PORV is inoperable as a result of the Required Action C.2, then Required Actions B.1 and B.2 are not applicable. The Completion Times of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months are reasonable, based on challenges to the PORVs during this time period, and provide the operator adequate time to correct the situation. If the inoperable valve cannot be restored to OPERABLE status, it must be isolated within the specified time. Because there is one PORV that remains OPERABLE, an additional 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is provided to restore an additional PORV to OPERABLE status when two PORVs are inoperable.

If the PORV cannot be restored within this additional time, the plant must be brought to a MODE in which the LCO does not apply, as required by Condition D. With only one PORV inoperable, operation may continue provided Required Actions B.1 and B.2 are met.

C.1 and C.2 If one block valve is inoperable, then it is necessary to.either restore the block valve to OPERABLE status within the Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or place the associated PORV in the closed position. The prime importance for the capability to close the block valve is to isolate a stuck open PORV.

Therefore, if the block valve cannot be restored to OPERABLE status within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , the Required Action is to place the PORV in the closed position and remove power from the solenoid to preclude its automatic opening for an overpressure event and to avoid the potential for a stuck open PORV at a time that the block valve is inoperable. The actions for an inoperable PORV are not entered due to these actions, however, the associated PORV is inoperable and must be included in subsequent inoperability determinations. The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is reasonable, based on the small potential for challenges to the system during this time period, and provides the operator time to correct the situation.

D.1 and D.2 If the Required Action of Condition A, B, or C is not met, then the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times McGuire Units 1 and 2 B 3.4.11-4 Revision No. 102

Pressurizer PORVs B 3.4.11 BASES ACTIONS (continued) 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. In MODES 4 and 5, maintaining PORV OPERABILITY may be required. See LCO 3.4.12.

E.1, E.2, E.3, and E.4 If three PORVs are inoperable and not capable of being manually cycled, it is necessary to either restore at least one valve within the Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months or isolate the flow path by closing and removing the power to the associated block valves. The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is reasonable, based on the small potential for challenges to the system during this time and provides the operator time to correct the situation. If one PORV is restored and two PORVs remain inoperable, then the plant will be in Condition B with the time clock started at the original declaration of having two PORVs inoperable. If no PORVs are restored within the Completion Time, then the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 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 pla'nt conditions from full power conditions in an orderly manner and without challenging plant systems.

In MODES 4 and 5, maintaining PORV OPERABILITY may be required.

See LCO 3.4.12.

F.1 and F.2 If two block valves are inoperable, it is necessary to either restore one block valve within the Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , or place the associated PORVs in the closed position and restore one block valve within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The Completion Times are reasonable, based on the small potential for challenges to the system during this time and provide the operator time to correct the situation.

G.1 and G.2 If three block valves are inoperable, it is necessary to place the associated PORVs in the closed position and verify the PORVs closed within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and restore at least one block valve within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . The Completion Times are reasonable, based on the small potential for challenges to the system during this time and provide the operator time to correct the situation.

McGuire Units 1 and 2 B 3.4.11-5 Revision No. 102

Pressurizer PORVs B 3.4.11 BASES ACTIONS (continued)

H.1 and H.2 If the Required Actions of Condition F or G are not met, then the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 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. In MODES 4 and 5, maintaining PORV OPERABILITY may be required. See LCO 3.4.12.

SURVEILLANCE SR 3.4.11.1 REQUIREMENTS Block valve cycling verifies that the valve(s) can be closed if needed. The basis for the Frequency of 92 days is the ASME OM Code (Ref. 4). If the block valve is closed to isolate a PORV that is capable of being manually cycled, the OPERABILITY of the block valve is of importance, because opening the block valve is necessary to permit the PORV to be used for manual control of reactor pressure. If the block valve is closed to isolate an otherwise inoperable PORV, the maximum Completion Time to restore the PORV and open the block valve is 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months , which is well within the allowable limits (25%) to extend the block valve Frequency of 92 days.

Furthermore, these test requirements would be completed by the reopening of a recently closed block valve upon restoration of the PORV to OPERABLE status (i.e., completion of the Required Actions fulfills the SR).

The Note modifies this SR by stating that it is not required to be met with the block valve closed, in accordance with the Required Action of this LCO.

SR 3.4.11.2 SR 3.4.11.2 requires a complete cycle of each PORV. Operating a PORV through one complete cycle ensures that the PORV can be manually actuated for mitigation of an SGTR. The Frequency of 18 months is based on a typical refueling cycle and industry accepted practice.

The SR is modified by a Note which states that the SR is required to be performed in MODE 3 or 4 When the temperature of the RCS cold legs is

> 300OF consistent with Generic Letter 90-06 (Ref. 5).

McGuire Units 1 and 2 B 3.4.11-6 Revision No. 102

Pressurizer PQRVs B 3.4.11 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.4.11.3 The Surveillance demonstrates that the emergency nitrogen supply can be provided and is performed by transferring power from normal air supply to emergency nitrogen supply and cycling the valves. The Frequency of 18 months is based on a typical refueling cycle and industry accepted practice.

REFERENCES 1. Regulatory Guide 1.32, February 1977.

2. UFSAR, Section 15.4.

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

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

5. Resolution of Generic Issue 70, "Power-Operated Relief Valve and Block Valve Reliability," and Generic Issue 94, "Additional Low-Temperature Overpressure Protection for Light-Water Reactors,"

Pursuant to 10 CFR 50:54(f) (Generic Letter 90-06).

McGuire Units 1 and 2 B 3.4..11-7 Revision No. 102

LTOP System B 3.4.12 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.12 Low Temperature Overpressure Protection (LTOP) System BASES BACKGROUND The LTOP System controls RCS pressure at low temperatures so the integrity of the reactor coolant pressure boundary (RCPB) is not compromised by violating the pressure and temperature (P/T) limits of 10 CFR 50, Appendix G (Ref. 1). The reactor vessel is.the limiting RCPB component for demonstrating such protection. This specification provides the maximum allowable actuation logic setpoints for the power operated relief valves (PORVs) and LCO 3.4.3, "RCS Pressure and Temperature (P/T) Limits,," provides the maximum RCS pressure for the existing RCS cold leg temperature during cooldown, shutdown, and heatup to meet the Reference I requirements during the LTOP MODES.

The reactor vessel material is less tough at low temperatures than at normal operating temperature. As the vessel neutron exposure accumulates, the material toughness decreases and becomes less resistant to pressure stress at low temperatures (Ref. 2). RCS pressure, therefore, is maintained low at low temperatures and is increased only as temperature is increased.

The potential for vessel overpressurization is most acute when the RCS is water solid, occurring only while shutdown; a pressure fluctuation can occur more quickly than an operator can react to relieve the condition.

Exceeding the RCS P/T limits by a significant amount could cause brittle cracking of the reactor vessel. LCO 3.4.3 requires administrative control of RCS pressure and temperature during heatup and cooldown to prevent exceeding the specified limits.

This LCO provides RCS overpressure protection by having a minimum coolant input capability and having adequate pressure relief capacity:

Limiting coolant input capability requires all but one centrifugal charging pump or one safety injection pump incapable of injection into the RCS and isolating the accumulators. The pressure relief capacity requires either two redundant PORVs or a depressurized RCS and an RCS vent of sufficient size. One PORV or the open RCS vent is the overpressure protection device that acts to terminate an increasing pressure event.

With minimum coolant input capability, the ability to provide core coolant addition is restricted. The LCO does not require the makeup control McGuire Units 1 and 2 B 3.4.12-1 Revision No. 102

LTOP System B 3.4.12 BASES BACKGROUND (continued) system deactivated or the safety injection (SI) actuation circuits blocked.

Due to the lower pressures in the LTOP MODES and the expected core decay heat levels, the makeup system can provide adequate flow via the makeup control valve. If conditions require the use of more than one centrifugal charging pump for makeup in the event of loss of inventory, then pumps can be made available through manual actions.

PORV Requirements As designed for the LTOP System, each PORV is signaled to open if the RCS pressure reaches 385 psig when the PORVS are in the "lo-press" mode of operation. If the PORVs are being used to meet the requirements of this specification, then RCS cold leg temperature is limited in accordance with the LTOP analysis. For cases where no reactor coolant pumps are in operation, this temperature limit is met by monitoring of BOTH the Wide Range Cold Leg temperatures and Residual Heat Removal Heat Exchanger discharge temperature. These temperatures are the most representative of the fluid in the reactor vessel downcomer region. The LTOP actuation logic monitors both RCS temperature and RCS pressure. The signals used to generate the pressure setpoints originate from the safety related narrow range pressure transmitters. The signals used to generate the temperature permissives originate from the wide range RTDs on cold leg C and hot leg D. Each signal is input to the appropriate NSSS protection system cabinet where it is converted to an internal signal and then input to a comparator to generate an actuation signal. If the indicated pressure meets or exceeds the bistable setpoint, a PORV is signaled to open.

This Specification presents the PORV setpoints for LTOP. Having the setpoints of both valves within the limits ensures that the Reference 1 limits will not be exceeded in any analyzed event.

When a PORV is opened in an increasing pressure transient, the release of coolant will cause the pressure increase to slow and reverse. As the PORV releases coolant, the RCS pressure decreases until a reset pressure is reached and the valve is signaled to close. The pressure continues to decrease below the reset pressure as the valve closes.

RCS Vent Requirements Once the RCS is depressurized, a vent exposed to the containment atmosphere will maintain the RCS at containment ambient pressure in an RCS overpressure transient, if the relieving requirements of the transient do not exceed the capabilities of the vent. Thus, the vent path must be McGuire Units 1 and 2 B 3.4.12-2 Revision No. 102

LTOP System B 3.4.12 BASES BACKGROUND (continued) capable of relieving the flow resulting from the limiting LTOP mass or heat input transient, and maintaining pressure below the P/T limits. The required vent capacity may be provided by one or more vent paths.

The vent path(s) must be above the level of reactor coolant, so as not to drain the RCS when open.

APPLICABLE Safety analyses (Ref. 4) demonstrate that the reactor vessel is SAFETY ANALYSES adequately protected against exceeding the Reference 1 PIT limits. In MODES 1, 2, and 3, and in MODE 4 with RCS cold leg temperature exceeding 3000 F, the pressurizer safety valves will prevent RCS pressure from exceeding the Reference 1 limits. At about 300OF and below, overpressure prevention falls to two OPERABLE PORVs or to a depressurized RCS and a sufficient sized RCS vent. Each of these means has a limited overpressure relief capability.

The actual temperature at which the pressure in the P/T limit curve falls below the pressurizer safety valve setpoint increases as the reactor vessel material toughness decreases due to neutron embrittlement. Each time the P/T curves are revised, the LTOP System must be re-evaluated to ensure its functional requirements can still be met using the PORV method or the depressurized and vented RCS condition.

Any change to the RCS must be evaluated against the Reference 4 analyses to determine the impact of the change on the LTOP acceptance limits.

Transients that are capable of overpressurizing the RCS are categorized as either mass or heat input transients, examples of which follow:

Mass Input Type Transients

a. Inadvertent safety injection; or

b. Charging/letdown flow mismatch.

Heat Inout Tvoe Transients

a. Inadvertent actuation of pressurizer heaters;

b. Loss of RHR cooling; or McGuire Units 1 and 2 B 3.4.12-3 Revision No. 102 J

LTOP System B 3.4.12 BASES APPLICABLE SAFETY ANALYSES (continued)

c. Reactor coolant pump (RCP) startup with temperature asymmetry within the RCS or between the RCS and steam generators.

The following are required during the LTOP MODES to ensure that mass and heat input transients do not occur, which either of the LTOP overpressure protection means cannot handle:

a. Rendering all but one centrifugal charging pump or one safety injection pump incapable of injection;

b. Deactivating the accumulator discharge isolation valves in their closed positions; and

c. Disallowing start of an RCP if secondary temperature is more than 50°F above primary temperature in any one loop. LCO 3.4.6, "RCS Loops-MODE 4," and LCO 3.4.7, "RCS Loops-MODE 5, Loops Filled," provide this protection.

The Reference 4 analyses demonstrate that either one PORV or the depressurized RCS and RCS vent can maintain RCS pressure below limits when only one centrifugal charging pump or one safety injection pump are actuated. Thus, the LCO allows only one centrifugal charging pump or one safety injection pump OPERABLE during the LTOP MODES. Since neither one PORV nor the RCS vent can handle the pressure transient from accumulator injection when RCS temperature is low the LCO also requires the accumulators isolation when accumulator pressure is greater than or equal to the maximum RCS pressure for the existing RCS cold leg temperature allowed in LCO 3.4.3.

The isolated accumulators must have their discharge valves closed and power removed.

Fracture mechanics analyses established the temperature of LTOP Applicability at 300 0 F.

The consequences of a small break loss of coolant accident (LOCA) in LTOP MODE 4 conform to 10 CFR 50.46 and 10 CFR 50, Appendix K (Refs. 5 and 6), requirements by having a maximum of one centrifugal charging pump OPERABLE and SI actuation enabled.

McGuire Units 1 and 2 B 3.4.12-4 Revision No. 102

LTOP System B 3.4.12 BASES APPLICABLE SAFETY ANALYSES (continued)

PORV Performance The fracture mechanics analyses show that the vessel is protected when the PORVs are set to open at or below the specified limit. The setpoints are derived by analyses that model the performance of the LTOP System, assuming the limiting LTOP transient of one centrifugal charging pump or one safety injection pump injecting into the RCS. These analyses consider pressure overshoot and undershoot beyond the PORV opening and closing, resulting from signal processing and valve stroke times. The PORV setpoints at or below the derived limit ensures the Reference 1 P/T limits will be met.

The PORV setpoints will be updated when the revised P/T limits conflict with the LTOP analysis limits. The P/T limits are periodically modified as the reactor vessel material toughness decreases due to neutron embrittlement caused by neutron irradiation. Revised limits are determined using neutron fluence projections and the results of examinations of the reactor vessel material irradiation surveillance specimens. The Bases for LCO 3.4.3, "RCS Pressure and Temperature (P/T) Limits," discuss these examinations.

The PORVs are considered active components. Thus, the failure of one PORV is assumed to represent the worst case, single active failure.

RCS Vent Performance With the RCS depressurized, analyses show a vent size of 2.75 square inches is capable of mitigating the allowed LTOP overpressure transient.

The capacity of a vent this size is greater than the flow of the limiting transient for the LTOP configuration, one centrifugal charging pump or one safety injection pump OPERABLE, maintaining RCS pressure less than the maximum pressure on the P/T limit curve.

The RCS vent size will be re-evaluated for compliance each time the P/T limit curves are revised based on the results of the vessel material surveillance.

The RCS vent is passive and is not subject to active failure.

The LTOP System satisfies Criterion 2 of 10 CFR 50.36 (Ref. 7).

McGuire Units 1 and 2 B 3.4.12-5 Revision No. 102

LTOP System B 3.4.12 BASES LCO This LCO requires that the LTOP System is OPERABLE. The LTOP System is OPERABLE when the minimum coolant input and pressure relief capabilities are OPERABLE. Violation of this LCO could lead to the loss of low temperature overpressure mitigation and violation of the Reference 1 limits as a result of an operational transient.

To limit the coolant input capability, the LCO permits a maximum of one centrifugal charging pump or one safety injection pump capable of injecting into the RCS and requires all accumulator discharge isolation valves closed and immobilized when accumulator pressure is greater than or equal to the maximum RCS pressure for the existing RCS cold leg temperature allowed in LCO 3.4.3.

The elements of the LCO that provide low temperature overpressure mitigation through pressure relief are:

a. Two OPERABLE PORVs (NC-32B and NC-34A); or A PORV is OPERABLE for LTOP when its block valve is open, its lift setpoint is set to the specified limit and testing proves its automatic ability to open at this setpoint, and motive power is available to the valve and its control circuit.

b. A depressurized RCS and an RCS vent.

An RCS vent is OPERABLE when open with an area of

_>2.75 square inches.

Each of these methods of overpressure prevention is capable of mitigating the limiting LTOP transient.

The LCO is modified with a note that specifies that a PORV secured in the open position may be used to meet the RCS vent requirement provided that its associated block valve is open and power removed.

With the PORV physically secured or locked in the open position with its associated block valve open and power removed, this vent path is passive and is not subject to active failure.

APPLICABILITY This LCO is applicable in MODE 4 when any RCS cold leg temperature is

< 300 0 F, in MODE 5, and in MODE 6 when the reactor vessel head is on.

The pressurizer safety valves provide overpressure protection that meets the Reference 1 P/T limits above 300 0 F. When the reactor vessel head is off, overpressurization cannot occur.

LCO 3.4.3 provides the operational P/T limits for~all MODES.

LCO 3.4.10, "Pressurizer Safety Valves," requires the OPERABILITY of McGuire Units 1 and 2 B 3.4.12-6 Revision No. 102

LTOP System B 3.4.12 BASES APPLICABILITY (continued) the pressurizer safety valves that provide overpressure protection during MODES 1, 2, and 3, and MODE 4 above 300 0 F.

Low temperature overpressure prevention is most critical during shutdown when the RCS is water solid, and a mass or heat input transient can cause a very rapid increase in RCS pressure when little or no time allows operator action to mitigate the event.

The Applicability is modified by a Note stating that accumulator isolation is only required when the accumulator pressure is more than or at the maximum RCS pressure for the existing temperature, as allowed by the P/T limit curves. This Note permits the accumulator discharge isolation valve Surveillance to be performed only under these pressure and temperature conditions.

ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable LTOP system. There is an increased risk associated with entering MODE 4 from MODE 5 with LTOP inoperable and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

A.1, A.2.1, A.2.2.1, A.2.2.2, A.3, A.4, A.5.1, and A.5.2 With two centrifugal charging pumps, safety injection pumps, or a combination of each, capable of injecting into the RCS, RCS overpressurization is possible.

To immediately initiate action to restore restricted coolant input capability to the RCS reflects the urgency of removing the RCS from this condition.

Two pumps may be capable of injecting into the RCs provided the RHR suction relief valve is OPERABLE with:

1. RCS cold leg temperature > 174°F (Unit 1), or

2. RCS cold leg temperature > 89°F (Unit 2), or

3. RCS cold leg temperature > 74°F and cooldown rate < 20°F/hr (Unit 1),

or

4. RCS cold leg temperature > 74°F and cooldown rate < 6 0 °F/hr (Unit 2),

or

5. two PORVs secured open with associated block valves open and power removed, or

6. a RCS vent of > 4.5 square inches, or McGuire Units 1 and 2 B 3.4.12-7 Revision No. 102

LTOP System B 3.4.12 BASES ACTIONS (continued)

7. a RCS vent of > 2.75 square inches and two OPERABLE PORVs (the RCS vent shall not be one of the two OPERABLE PORVs).

For cases where no reactor coolant pumps are in operation, RCS cold leg temperature limits are to be met by monitoring of BOTH the WR Cold Leg temperatures and Residual Heat Removal Heat Exchanger discharge temperature. With both PORVS and block valves secured open, or with an RCS vent of 4.5 square inches, there are no credible single failures to limit the flow relief capacity. For the RHR relief valve to be OPERABLE, the RHR suction isolation valves must be open and the relief valve setpoint at 450 psig consistent with the safety analysis. The RHR suction relief valves are spring loaded, bellows type water relief valves with pressure tolerances and accumulation limits established by Section III of the American Society of Mechanical Engineers (ASME) Code (Ref. 3) for Class 2 relief valves.

Required Action A.1 is modified by a Note that permits two centrifugal charging pumps capable of RCS injection for < 15 minutes to allow for pump swaps.

B.1, C.1, and C.2 An unisolated accumulator requires isolation within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . This is only required when the accumulator pressure is at or more than the maximum RCS pressure for the existing temperature allowed by the P/T limit curves.

If isolation is needed and cannot be accomplished in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , Required Action C.1 and Required Action C.2 provide two options, either of which must be performed in the next 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . By increasing the RCS temperature to > 300 0 F, an accumulator pressure of 639 psig cannot exceed the LTOP limits if the accur-iulators are fully injected.

Depressurizing the accumulators below the LTOP limit also gives this protection.

The Completion Times are based on operating experience that these activities can be accomplished in these time periods and on engineering evaluations indicating that an event requiring LTOP is not likely in the allowed times.

D.1 In MODE 4 when any RCS cold leg temperature is < 300 0 F, with one PORV inoperable, the PORV must be restored to OPERABLE status McGuire Units 1 and 2 B 3.4.12-8 Revision No. 102

LTOP System B 3.4.12 BASES ACTIONS (continued) within a Completion Time of 7 days. Two PORVS are required to provide low temperature overpressure mitigation while withstanding a single failure of an active component.

The Completion Time considers the facts that only one of the PORVs is required to mitigate an overpressure transient and that the likelihood of an active failure of the remaining valve path during this time period is very low.

E.1 and E.2 The consequences of operational events that will overpressurize the RCS are more severe at lower temperature (Ref. 8). Thus, with one of the two PORVs inoperable in MODE 5 or in MODE 6 with the head on, all operations which could lead to a water solid pressurizer must be suspended immediately and the Completion Time to restore two valves to OPERABLE status is 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months .

The Completion Time represents a reasonable time to investigate and repair several types of relief valve failures without exposure to a lengthy period with only one OPERABLE PORV to protect against overpressure events.

F.1 and F.2 If the Required Actions and associated Completion Times of Condition E are not met, then alternative actions are necessary to establish the required redundancy in relief capacity. This is accomplished by verifying that the RHR relief valve is OPERABLE and the RHR suction isolation valves open and the RCS cold leg temperature > 174 0 F (Unit 1) or > 89 0 F (Unit 2). For cases where no reactor coolant pumps are in operation, RCS cold leg temperature limits are to be met by monitoring of BOTH the WR Cold Leg temperatures and Residual Heat Removal Heat Exchanger discharge temperature. The Completion Time of 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months reflects the importance of restoring the required redundancy at lower RCS temperatures.

G.1 The RCS must be depressurized and a vent must be established within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months when:

McGuire Units 1 and 2 B 3.4.12-9 Revision No. 102

LTOP System B 3.4.12 BASES ACTIONS (continued)

a. Both required PORVs are inoperable; or

b. A Required Action and associated Completion Time of Condition C, D, E, or F is not met; or

c. The LTOP System is inoperable for any reason other than Condition A, B, C, D, E, or F.

The vent must be sized > 2.75 square inches to ensure that the flow capacity is greater than that required for the worst case mass input transient reasonable during the applicable MODES. This action is needed to protect the RCPB from a low temperature overpressure event and a possible brittle failure of the reactor vessel.

The Completion Time considers the time required to place the plant in this Condition and the relatively low probability of an overpressure event during this time period due to increased operator awareness of administrative control requirements.

SURVEILLANCE SR 3.4.12.1 and SR 3.4.12.2 REQUIREMENTS To minimize the potential for a low temperature overpressure event by limiting the mass input capability, all but one centrifugal charging pump or one safety injection pump are verified incapable of injecting into the RCS and the accumulator discharge isolation valves are verified closed and power removed (See Ref. 10).

The centrifugal charging pump and safety injection pump are rendered incapable of injecting into the RCS through removing the power from the pumps by racking the breakers out under administrative control. An alternate method of LTOP control may be employed using at least two independent means to prevent a pump start such that a single failure or single action will not result in an injection into the RCS. This may be accomplished through two valves in the discharge flow path being closed.

The Frequency of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is sufficient, considering other indications and alarms available to the operator in the control room, to verify the required status of the equipment.

SR 3.4.12.3 The RHR suction relief valve shall be demonstrated OPERABLE by verifying the RHR suction isolation valves are open and by testing it in McGuire Units 1 and 2 B 3.4.12-10 Revision No. 102

LTOP System B 3.4.12 BASES SURVEILLANCE REQUIREMENTS (continued) accordance with the Inservice Testing Program. This Surveillance is only required to be performed if the RHR suction relief valve is being used to meet the Required Actions of this LCO.

The RHR suction valves are verified to be opened every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The Frequency is considered adequate in view of other administrative controls such as valve status indications available to the operator in the control room that verify the RHR suction valves remain open.

The ASME OM Code (Ref. 9), test per Inservice Testing Program, verifies OPERABILITY by proving proper relief valve mechanical motion and by measuring and, if required, adjusting the lift setpoint.

SR 3.4.12.4 The RCS vent of _>2.75 square inches is proven OPERABLE by verifying its open condition either:

a. Once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months for a valve that cannot be locked.

b. Once every 31 days for a valve that is locked, sealed, or secured in position. A removed pressurizer safety valve fits this category.

The passive vent arrangement must only be open to be OPERABLE.

This Surveillance is required to be performed if the vent is being used to satisfy the pressure relief requirements of the LCO 3.4.12b.

SR 3.4.12.5 The PORV block valve must be verified open every 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months to provide the flow path for each required PORV to perform its function when actuated. The valve must be remotely verified open in the main control room. This Surveillance is performed if the PORV satisfies the LCO.

The block valve is a remotely controlled, motor operated valve. The power to the valve operator is not required removed, and the manual operator is not required locked in the inactive position. Thus, the block valve can be closed in the event the PORV develops excessive leakage or does not close (sticks open) after relieving an overpressure situation.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Frequency is considered adequate in view of other administrative controls available to the operator in the control room, such as valve position indication, that verify that the PORV block valve remains open.

McGuire Units 1 and 2 B 3.4.12-11 Revision No. 102

LTOP System B 3.4.12 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.4.12.6 Performance of a COT is required within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after decreasing RCS temperature to < 300OF and every 31 days on each required PORV to verify and, as necessary, adjust its lift setpoint. The COT will verify the setpoint is within the allowed maximum limits. PORV actuation could depressurize the RCS and is not required.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency considers the unlikelihood of a low temperature overpressure event during this time.

A Note has been added indicating that this SR is required to be met 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after decreasing RCS cold leg temperature to < 300 0 F. The test must be performed within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after entering the LTOP MODES.

SR 3.4.12.7 Performance of a CHANNEL CALIBRATION on each required PORV actuation channel is required every 18 months to adjust the whole channel so that it responds and the valve opens within the required range and accuracy to known input.

REFERENCES 1. 10 CFR 50, Appendix G.

2. Generic Letter 88-11.

3. ASME, Boiler and Pressure Vessel Code,Section III.

4. UFSAR, Section 5.2.

5. 10 CFR 50, Section 50.46.

6. 10 CFR 50, Appendix K.

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

8. Generic Letter 90-06.

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

10. Duke letter to NRC, "Cold Leg Accumulator Isolation Valves", dated September 8, 1987.

McGuire Units 1 and 2 B 3.4.12-12 Revision No. 102

RCS PIV Leakage B 3.4.14 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.14 RCS Pressure Isolation Valve (PIV) Leakage BASES BACKGROUND 10 CFR 50.2, 10 CFR 50.55a(c), and GDC 55 of 10 CFR 50, Appendix A (Refs. 1, 2, and 3), define RCS PIVs as any two normally closed valves in series within the reactor coolant pressure boundary (RCPB), which separate the high pressure RCS from an attached low pressure system.

During their lives, these valves can produce varying amounts of reactor coolant leakage through either normal operational wear or mechanical deterioration. The RCS PIV Leakage LCO allows RCS high pressure operation when leakage through these valves exists in amounts that do not compromise safety.

The PIV leakage limit applies to each individual valve. Leakage through two or more valves in series in a line will be measured during unit operation by the unidentified and total RCS LEAKAGE calculations, measured by a water inventory balance (SR 3.4.13.1).

Although this specification provides a limit on allowable PIV leakage rate, its main purpose is to prevent overpressure failure of the low pressure portions of connecting systems. The low pressure system interfaces (RHR and Safety Injection Systems) are provided with low capacity relief valves sufficient to relieve valve leakage considerably greater than allowed by this specification. The leakage limit is an indication that the PIVs between the RCS and the connecting systems are degraded or degrading. PIV leakage could lead to overpressure of the low pressure piping or components. Failure consequences could be a loss of coolant accident (LOCA) outside of containment, an unanalyzed accident, that could degrade the ability for low pressure injection.

The basis for this LCO is the 1975 NRC "Reactor Safety Study" (Ref. 4) that identified potential intersystem LOCAs as a significant contributor to the risk of core melt. A subsequent study (Ref. 5) evaluated various PIV configurations to determine the probability of intersystem LOCAs.

PIVs are provided to isolate the RCS from the following typically connected systems:

a. Residual Heat Removal (RHR) System;

b. Safety Injection System; and

c. Chemical and Volume Control System.

McGuire Units 1 and 2 B 3.4.14-1 Revision No. 102

RCS PIV Leakage B 3.4.14 BASES BACKGROUND (continued)

The PIVs are listed in the UFSAR, Table 5-50 (Ref. 6).

Violation of this LCO could result in continued degradation of a PIV, which could lead to overpressurization of a low pressure system and the loss of the integrity of a fission product barrier.

APPLICABLE Reference 4 identified potential intersystem LOCAs as a significant SAFETY ANALYSES contributor to the risk of core melt. The dominant accident sequence in the intersystem LOCA category is the failure of the low pressure portion of the RHR System outside of containment. The accident is the result of a postulated failure of the PIVs, which are part of the RCPB, and the subsequent pressurization of the RHR System downstream of the PIVs from the RCS. Because the low pressure portion of the RHR System is designed for 600 psig, overpressurization failure of the RHR low pressure line would result in a LOCA outside containment and subsequent risk of core melt.

Reference 5 evaluated various PIV configurations, leakage testing of the valves, and operational changes to determine the effect on the probability of intersystem LOCAs. This study concluded that periodic leakage testing of the PIVs can substantially reduce the probability of an intersystem LOCA.

RCS PIV leakage satisfies Criterion 2 of 10 CFR 50.36 (Ref. 7).

LCO RCS PIV leakage is unidentified LEAKAGE into closed systems connected to the RCS. Isolation valve leakage is usually on the order of drops per minute. Leakage that increases significantly suggests that something is operationally wrong and corrective action must be taken.

The LCO PIV leakage limit is 0.5 gpm per nominal inch of valve size with a maximum limit of 5 gpm. The previous criterion of 1 gpm for all valve sizes imposed an unjustified penalty on the larger valves without providing information on potential valve degradation and resulted in higher personnel radiation exposures. A study concluded a leakage rate limit based on valve size was superior to a single allowable value.

Reference 8 permits leakage testing at a lower pressure differential than between the specified maximum RCS pressure and the normal pressure of the connected system during RCS operation (the maximum pressure differential) in those types of valves in which the higher service pressure McGuire Units 1 and 2 B 3.4.14-2 Revision No. 102

RCS PIV Leakage O BASES B 3.4.14 LCO (continued) will tend to diminish the overall leakage channel opening. In such cases, the observed rate may be adjusted to the maximum pressure differential by assuming leakage is directly proportional to the pressure differential to the one half power.

APPLICABILITY In MODES 1, 2, 3, and 4, this LCO applies because the PIV leakage potential is greatest when the RCS is pressurized. In MODE 4, valves in the RHR flow path are not required to meet the requirements of this LCO when in, or during the transition to or from, the RHR mode of operation.

In MODES 5and 6, leakage limits are not provided because the lower reactor coolant pressure results in a reduced potential for leakage and for a LOCA outside the containment.

ACTIONS The Actions are modified by two Notes. Note 1 provides clarification that each flow path allows separate entry into a Condition. This is allowed based upon the functional independence of the flow path. Note 2 requires an evaluation of affected systems if a PIV is inoperable. The leakage may have affected system operability, or isolation of a leaking flow path with an alternate valve may have degraded the ability of the interconnected system to perform its safety function.

A.1 and A.2 The flow path must be isolated by two valves. Required Action A.1 is modified by a Note that the valves used for isolation must meet the same leakage requirements as the PIVs and must be within the RCPB or the high pressure portion of the system.

Required Action A.1 requires that the isolation with one valve must be performed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . Four hours provides time to reduce leakage in excess of the allowable limit and to isolate the affected system if leakage cannot be reduced. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time allows the actions and restricts the operation with leaking isolation valves.

Required Action A.2 specifies that the double isolation barrier of two valves be restored by restoring one leaking PIV. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time after exceeding the limit allows for the restoration of the leaking PIV to OPERABLE status. This timeframe considers the time required to complete this Action and the low probability of a second valve failing during this period.

McGuire Units 1 and 2 B 3.4.14-3 Revision No. 102

RCS PIV Leakage B 3.4.14 BASES ACTIONS (continued)

B.1 and B.2 If leakage cannot be reduced, or the other Required Actions accomplished, the plant must be brought to a MODE in which the requirement does not apply. To achieve this status, the plant must be brought to MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This Action may reduce the leakage and also reduces the potential for a LOCA outside the containment. 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.

C.1 The RHR interlock prevents the RHR suction isolation valves inadvertent opening at RCS pressures in excess of the RHR systems design pressure. If the RHR interlock is inoperable, operation may continue as long as the affected RHR suction penetration is closed by at least one closed manual or deactivated automatic valve within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . This Action accomplishes the purpose of the interlockfunction.

SURVEILLANCE SR 3.4.14.1 REQUIREMENTS Performance of leakage testing on each RCS PIV or isolation valve used to satisfy Required Action A.1 is required to verify that leakage is below the specified limit and to identify each leaking valve. The leakage limit of 0.5 gpm per inch of nominal valve diameter up to 5 gpm maximum applies to each valve. Leakage testing requires a stable pressure condition.

For the two PIVs in series, the leakage requirement applies to each valve individually and not to the combined leakage across both valves. If the PIVs are not individually leakage tested, one valve may have failed completely and not be detected if the other valve in series meets the leakage requirement. In this situation, the protection provided by redundant valves would be lost.

Testing is to be performed every 18 months, a typical refueling cycle, if the plant does not go into MODE 5 for at least 7 days. The 18 month Frequency is consistent with 10 CFR 50.55a(g) (Ref. 9) as contained in the Inservice Testing Program, is within frequency allowed by the American Society of Mechanical Engineers (ASME) OM Code McGuire Units 1 and 2 B 3.4.14-4 Revision No. 102

RCS PIV Leakage B 3.4.14 BASES SURVEILLANCE REQUIREMENTS (continued)

(Ref. 8), and is based on the need to perform such surveillances under the conditions that apply during an outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

In addition, testing must be performed once after the valve has been opened by flow or exercised to ensure tight reseating. PIVs disturbed in the performance of this Surveillance should also be tested unless documentation shows that an infinite testing loop cannot practically be avoided. Testing must be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after the valve has been reseated. Within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is a reasonable and practical time limit for performing this test after opening or reseating a valve.

The leakage limit is to be met at the RCS pressure associated with MODES 1 and 2. This permits leakage testing at high differential pressures with stable conditions not possible in the MODES with lower pressures.

Entry into MODES 3 and 4 is allowed to establish the necessary differential pressures and stable conditions to allow for performance of this Surveillance. The Note that allows this provision is complementary to the Frequency of prior to entry into MODE 2 whenever the unit has been in MODE 5 for 7 days or more, if leakage testing has not been performed in the previous 9 months. In addition, this Surveillance is not required to be performed on the RHR System when the RHR System is aligned to the RCS in the shutdown cooling mode of operation. PIVs contained in the RHR shutdown cooling flow path must be leakage rate tested after RHR is secured and stable unit conditions and the necessary differential pressures are established.

SR 3.4.14.2 Verifying that the RHR interlock is OPERABLE ensures that RCS pressure will not pressurize the RHR system beyond its design pressure of 600 psig. The interlock setpoint that prevents the valves from being opened is set so the actual RCS pressure must be < 425 psig to open the valves. This setpoint ensures the RHR design pressure will not be exceeded and the RHR relief valves will not lift. The 18 month Frequency is based on the need to perform the Surveillance under conditions that apply during a plant outage. The 18 month Frequency is also acceptable based on consideration of the design reliability (and confirming operating experience) of the equipment.

McGuire Units 1 and 2 B 3.4.14-5 Revision No. 102

RCS PIV Leakage B 3.4.14 BASES REFERENCES 1. 10 CFR 50.2.

2. 10 CFR 50.55a(c).

3. 10 CFR 50, Appendix A, Section V, GDC 55.

4. WASH-1400 (NUREG-75/014), Appendix V, October 1975.

5. NUREG-0677, May 1980.

6. UFSAR Table 5-50.

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

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

9. 10 CFR 50.55a(g).

McGuire Units 1 and 2 B 3.4.14-6 Revision No. 102

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. 102

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. 102

ECCS-Operating B 3.5.2 BASES O 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. Ifoffsite 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, "Refueling Water Storage Tank (RWST)," provide the cooling water necessary to meet GDC 35 (Ref. 1).

APPLICABLE The LeO 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 < 2200°F;

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. 102 McGuire McGu ire Units and 2 1 and Units 1 2 B 3.5.2-3 B 3.5.2-3 Revision No. 102

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.

Revision No. 102 McGuire Units and 22 Units 11 and BB 3.5.2-4 3.5.2-4 Revision No. 102

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. 102

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.

McGuire Units 1 and 2 B 3.5.2-6 Revision No. 102

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, McGuire Units 1 and 2 B 3.5.2-7 Revision No. 102

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 the ASME OM 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 the ASME OM Code. The ASME Code provides the activities and Frequencies necessary to satisfy the requirements.

Revision No. 102 and 22 Units 11 and McGuire Units B 3.5.2-8 B 3.5.2-8 Revision No. 102

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 ECCS containment sump strainer assembly (consisting of modular tophats, grating, plenums and waterboxes) and the associated enclosure (the stainless steel structure surrounding the strainer assembly located inside the crane wall) ensure they are unrestricted and stay in proper operating condition. Inspections will consist of a visual examination of the exterior surfaces of the strainer assembly and interior and exterior surfaces of the enclosure for any evidence of debris, structural distress, or abnormal corrosion. The intent of the surveillance is to ensure the absence of any condition which could adversely affect strainer functionality. Surveillance performance will not require removal of any tophat modules, but the strainer assembly exterior shall be visually inspected. This inspection will necessarily entail opening the top of the enclosure to allow access for inspection of the strainers, and to verify cleanliness of the enclosure interior space. A detailed inspection of the enclosure and exterior strainer assembly surfaces is required to establish a high confidence that no adverse conditions are present. The 18 month Frequency is based on the need to perform McGuire Units 1 and 2 B 3.5.2-9 Revision No. 102

ECCS-Operating B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued) 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.

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.

Revision No. 102 and 22 Units 11 and McGuire Units B 3.5.2-10 B 3.5.2-10 Revision No. 102

Containment Spray System B 3.6.6 B 3.6 CONTAINMENT SYSTEMS B 3.6.6 Containment Spray System BASES BACKGROUND The Containment Spray System provides containment atmosphere cooling to limit post accident pressure and temperature in containment to less than the design values. Reduction of containment pressure and the iodine removal capability of the spray reduce the release of fission product radioactivity from containment to the environment, in the event of a Design Basis Accident (DBA).

The Containment Spray System is designed to meet the requirements of 10 CFR 50, Appendix A, GDC 38, "Containment Heat Removal," GDC 39, "Inspection of Containment Heat Removal Systems," GDC 40, "Testing of Containment Heat Removal Systems," GDC 41, "Containment Atmosphere Cleanup," GDC 42, "Inspection of Containment Atmosphere Cleanup Systems,"

and GDC 43, "Testing of Containment Atmosphere Cleanup Systems" (Ref. 1).

The Containment Spray System consists of two separate trains of equal capacity, each capable of meeting the system design basis spray coverage. Each train includes a containment spray pump, one containment spray heat exchanger, spray headers, nozzles, valves, and piping. Each train is powered from a separate Engineered Safety Feature (ESF) bus. The refueling water storage tank (RWST) supplies borated water to the Containment Spray System during the injection phase of operation. In the recirculation mode of operation, containment spray pump suction is transferred from the RWST to the containment recirculation sump(s).

The diversion of a portion of the recirculation flow from each train of the Residual Heat Removal (RHR) System to additional redundant spray headers completes the Containment Spray System heat removal capability. Each RHR train is capable of supplying spray coverage, if required, to supplement the Containment Spray System.

The Containment Spray System and RHR System provide a spray of cold or subcooled borated water into the upper containment volume to limit the containment pressure and temperature during a DBA. The RWST solution temperature is an important factor in determining the heat removal capability of the Containment Spray System during the injection phase. In the recirculation mode of operation, heat is removed from the containment sump water by the Containment Spray System and RHR heat exchangers. Each train of the Containment Spray System, supplemented by a train of RHR spray, provides adequate spray coverage to meet the system design requirements for containment heat removal.

McGuire Units 1 and 2 B 3.6.6-1 Revision No. 102

Containment Spray System B 3.6.6 BASES BACKGROUND (continued)

For the hypothetical double-ended rupture of a Reactor Coolant System pipe, the pH of the sump solution (and, consequently, the spray solution) is raised to at least 8.0 within one hour of the onset of the LOCA. The resultant pH of the sump solution is based on the mixing of the RCS fluids, ECCS injection fluid, and the melted ice which are combined in the sump. The alkaline pH of the containment sump water minimizes the evolution of iodine and the occurrence of chloride and caustic stress corrosion on mechanical systems and components exposed to the fluid.

The Containment Spray System is actuated either automatically by a containment pressure high-high signal or manually. An automatic actuation opens the containment spray pump discharge valves, starts the two containment spray pumps, and begins the injection phase. A manual actuation of the Containment Spray System requires the operator to actuate two separate train related switches on the main control board to begin the same sequence of two train actuation. The injection phase continues until an RWST level Low-Low alarm is received. The Low-Low alarm for the RWST signals the operator to manually align the system to the recirculation mode. The Containment Spray System in the recirculation mode maintains an equilibrium temperature between the containment atmosphere and the recirculated sump water. Operation of the Containment Spray System in the recirculation mode is controlled by the operator in accordance with the emergency operation procedures.

The RHR spray operation is initiated manually, when required by the emergency operating procedures, after the Emergency Core Cooling System (ECCS) is operating in the recirculation mode. The RHR sprays are available to supplement the Containment Spray System, if required, in limiting containment pressure. This additional spray capacity would typically be used after the ice bed has been depleted and in the event that containment pressure rises above a predetermined limit. The Containment Spray System is an ESF system. It is designed to ensure that the heat removal capability required during the post accident period can be attained.

The operation of the Containment Spray System, together with the ice condenser, is adequate to assure pressure suppression subsequent to the initial blowdown of steam and water from a DBA. During the post blowdown period, the Air Return System (ARS) is automatically started.

The ARS returns upper compartment air through the divider barrier to the lower compartment. This serves to equalize pressures in containment and to continue circulating heated air and steam through the ice condenser, where heat is removed by the remaining ice.

McGuire Units 1 and 2 B 3.6.6-2 Revision No. 102

Containment Spray System B 3.6.6 BASES BACKGROUND (continued)

The Containment Spray System limits the temperature and pressure that could be expected following a DBA. Protection of containment integrity limits leakage of fission product radioactivity from containment to the environment.

APPLICABLE The limiting DBAs considered relative to containment OPERABILITY SAFETY ANALYSES are the loss of coolant accident (LOCA) and the steam line break (SLB).

The DBA LOCA and SLB are analyzed using computer codes designed to predict the resultant containment pressure and temperature transients.

No two DBAs are assumed to occur simultaneously or consecutively.

The postulated DBAs are analyzed, in regard to containment ESF systems, assuming the loss of one ESF bus, which is the worst case single active failure, resulting in one train of the Containment Spray System, the RHR System, and the ARS being rendered inoperable (Ref. 2).

The DBA analyses show that the maximum peak containment pressure results from the LOCA analysis, and is calculated to be less than the containment design pressure. The maximum peak containment atmosphere temperature results from the SLB analysis and was calculated to be within the containment environmental qualification temperature during the DBA SLB. The basis of the containment environmental qualification temperature is to ensure the OPERABILITY of safety related equipment inside containment (Ref. 3).

The modeled Containment Spray System actuation from the containment analysis is based on a response time associated with exceeding the containment pressure high-high signal setpoint to achieving full flow through the containment spray nozzles. A delayed response time initiation provides conservative analyses of peak calculated containment temperature and pressure responses. The Containment Spray System total response time of 120 seconds is composed of signal delay, diesel generator startup, system startup time, and time for the piping to fill.

For certain aspects of transient accident analyses, maximizing the calculated containment pressure is not conservative. In particular, the ECCS cooling effectiveness during the core reflood phase of a LOCA analysis increases with increasing containment backpressure. For these calculations, the containment backpressure is calculated in a manner designed to conservatively minimize, rather than maximize, the calculated transient containment pressures in accordance with 10 CFR 50, Appendix K (Ref. 4).

McGuire Units 1 and 2 B 3.6.6-3 Revision No. 102

Containment Spray System B 3.6.6 BASES APPLICABLE SAFETY ANALYSES (continued)

Inadvertent actuation is precluded by design features consisting of an additional set of containment pressure sensors which prevents operation when the containment pressure is below the containment pressure control system permissive.

The Containment Spray System satisfies Criterion 3 of 10 CFR 50.36 (Ref. 5).

LCO During a DBA, one train of Containment Spray System is required to provide the heat removal capability assumed in the safety analyses. To ensure that this requirement is met, two containment spray trains must be OPERABLE with power from two safety related, independent power supplies. Therefore, in the event of an accident, at least one train operates.

Each Containment Spray System includes a spray pump, headers, valves, heat exchangers, nozzles, piping, instruments, and controls to ensure an OPERABLE flow path capable of taking suction from the RWST upon an ESF actuation signal and manually transferring suction to the containment sump.

APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material to containment and an increase in containment pressure and temperature requiring the operation of the Containment Spray System.

In MODES 5 and 6, the probability and consequences of these events are reduced because of the pressure and temperature limitations of these MODES. Thus, the Containment Spray System is not required to be OPERABLE in MODE 5 or 6.

ACTIONS A.1 With one containment spray train inoperable, the affected train must be restored to OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The components in this degraded condition are capable of providing 100% of the heat removal after an accident. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time was developed taking into account the redundant heat removal and iodine removal capabilities afforded by the OPERABLE train and the low probability of a DBA occurring during this period.

McGuire Units 1 and 2 B 3.6.6-4 Revision No. 102

Containment Spray System B 3.6.6 BASES ACTIONS (continued)

B.1 and B.2 If the affected containment spray train cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and to MODE 5 within 84 hours9.722222e-4 days 0.0233 hours 1.388889e-4 weeks 3.1962e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems. The extended interval to reach MODE 5 allows additional time and is reasonable when considering that the driving force for a release of radioactive material from the Reactor Coolant System is reduced in MODE 3.

SURVEILLANCE SR 3.6.6.1 REQUIREMENTS Verifying the correct alignment of manual, power operated, and automatic valves, excluding check valves, in the Containment Spray System provides assurance that the proper flow path exists for Containment Spray System operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position since they were verified in the correct position prior to being secured. This SR does not require any testing or valve manipulation. Rather, it involves verification, through a system walkdown or computer status indication, that those valves outside containment and capable of potentially being mispositioned, are in the correct position.

SR 3.6.6.2 Verifying that each containment spray pump's developed head at the flow test point is greater than or equal to the required developed head ensures that spray pump performance has not degraded during the cycle. Flow and differential head are normal tests of centrifugal pump performance required by the ASME OM Code (Ref. 6). Since the containment spray pumps cannot be tested with flow through the spray headers, they are tested on bypass flow. This-test confirms one point on the pump design curve and is indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance.

The Frequency of this SR is in accordance with the Inservice Testing Program.

McGuire Units 1 and 2 B 3.6.6-5 Revision No. 102

Containment Spray System B 3.6.6 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.6.3 and SR 3.6.6.4 These SRs require verification that each automatic containment spray valve actuates to its correct position and each containment spray pump starts upon receipt of an actual or simulated Containment Pressure High-High 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 an unplanned transient if the Surveillances were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillances when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

The surveillance of containment sump isolation valves is also required by SR 3.6.6.3. A single surveillance may be used to satisfy both requirements.

SR 3.6.6.5 and SR 3.6.6.6 These SRs require verification that each containment spray pump discharge valve opens or is prevented from opening and each containment spray pump starts or is de-energized and prevented from starting upon receipt of Containment Pressure Control System start and terminate signals. The CPCS is described in the Bases for LCO 3.3.2, "ESFAS." The 18 month Frequency is based on the need to perform these Surveillances under the conditions that apply during a plant outage.

SR 3.6.6.7 With the containment spray inlet valves closed and the spray header drained of any solution, low pressure air or smoke can be blown through test connections. The spray nozzles can also be periodically tested using a vacuum blower to induce air flow through each nozzle to verify unobstructed flow. This SR ensures that each spray nozzle is unobstructed and that spray coverage of the containment during an accident is not degraded. Because of the passive design of the nozzle, a test at 10 year intervals is considered adequate to detect obstruction of the spray nozzles.

McGuire Units 1 and 2 B 3.6.6-6 Revision No. 102

Containment Spray System B 3.6.6 BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 38, GDC 39, GDC 40, GDC 41, GDC 42, and GDC 43.

2. UFSAR, Section 6.2.

3. 10 CFR 50.49.

4. 10 CFR 50, Appendix K.

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

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

McGuire Units 1 and 2 B 3.6.6-7 Revision No. 102

MSSVs B 3.7.1 B 3.7 PLANT SYSTEMS B 3.7.1 Main Steam Safety Valves (MSSVs)

BASES BACKGROUND The primary purpose of the MSSVs is to provide overpressure protection for the secondary system. The MSSVs also provide protection against overpressurizing the reactor coolant pressure boundary (RCPB) by providing a heat sink for the removal of energy from the Reactor Coolant System (RCS) if the preferred heat sink, provided by the Condenser and Circulating Water System, is not available.

Five MSSVs are located on each main steam header, outside containment, upstream of the main steam isolation valves, as described in the UFSAR, Section 10.3.1 (Ref. 1). The MSSV capacity criteria is 110% of rated steam flow at 110% of the steam generator design pressure. This meets the requirements of the ASME Code,Section III (Ref. 2). The MSSV design includes staggered setpoints, according to Table 3.7.1-2 in the accompanying LCO, so that only the needed valves will actuate. Each valve is orificed to a size of either 12.174 or 16.0 square inches. Staggered setpoints reduce the potential for valve chattering that is due to steam pressure insufficient to fully open all valves following a turbine reactor trip.

APPLICABLE The design basis for the MSSVs comes from Reference 2 and its SAFETY ANALYSES purpose is to limit the secondary system pressure to < 110% of design pressure when passing 100% of design steam flow. This design basis is sufficient to cope with any anticipated operational occurrence (AOO) or accident considered in the Design Basis Accident (DBA) and transient analysis.

The events that challenge the relieving capacity of the MSSVs, and thus RCS pressure, are those characterized as decreased heat removal events, which are presented in the UFSAR, Section 15.2 (Ref. 3). Of these, the full power turbine trip without steam dump is the limiting AOO.

The transient response for turbine trip without a direct reactor trip presents no hazard to the integrity of the RCS or the Main Steam System.

The reactor is tripped on high pressurizer pressure in the peak primary pressure case. In this case, the pressurizer safety valves open, and RCS pressure remains below 110% of the design value. The MSSVs also open to limit the secondary steam pressure.

McGuire Units 1 and 2 B 3.7.1 -1 Revision No. 102

MSSVs B 3.7.1 BASES APPLICABLE SAFETY ANALYSES (continued)

For the peak secondary pressure case, the reactor is tripped on overtemperature AT. Pressurizer relief valves and MSSVs are activated and prevent overpressurization in the primary and secondary systems.

The MSSVs satisfy Criterion 3 of 10 CFR 50.36 (Ref. 4).

LCO The accident analysis assumes five MSSVs per steam generator to provide overpressure protection for design basis transients occurring at 102% RTP. An MSSV will be considered inoperable if it fails to open on demand. The LCO requires that five MSSVs be OPERABLE in compliance with Reference 2, even though this is not a requirement of the DBA analysis. This is because operation with less than the full number of MSSVs requires limitations on allowable THERMAL POWER (to meet ASME Code requirements). These limitations are according to Table 3.7.1-1 in the accompanying LCO, and Required Action A.1 and A.2.

The OPERABILITY of the MSSVs is defined as the ability to open within the setpoint tolerances, relieve steam generator overpressure, and reseat when pressure has been reduced. The OPERABILITY of the MSSVs is determined by periodic surveillance testing in accordance with the Inservice Testing Program.

The lift settings, according to Table 3.7.1-2 in the accompanying LCO, correspond to ambient conditions of the valve at nominal operating temperature and pressure.

This LCO provides assurance that the MSSVs will perform their designed safety functions to mitigate the consequences of accidents that could result in a challenge to the RCPB.

APPLICABILITY In MODE 1, the number of MSSVs per steam generator required to be OPERABLE must be according to Table 3.7.1-1 in the accompanying LCO. In MODES 2 and 3, only two MSSVs per steam generator are required to be OPERABLE.

In MODES 4 and 5, there are no credible transients requiring the MSSVs.

The steam generators are not normally used for heat removal in MODES 5 and 6, and thus cannot be overpressurized; there is no requirement for the MSSVs to be OPERABLE in these MODES.

McGuire Units 1 and 2 B 3.7.1-2 Revision No. 102

MSSVs B 3.7.1 BASES ACTIONS The ACTIONS table is modified by a Note indicating that separate Condition entry is allowed for each MSSV.

A.1 and A.2 With one or more MSSVs inoperable, reduce power so that the available MSSV relieving capacity meets Reference 2 requirements for the applicable THERMAL POWER.

Operation with less than all five MSSVs OPERABLE for each steam generator is permissible, if THERMAL POWER is proportionally limited to the relief capacity of the remaining MSSVs. This is accomplished by restricting THERMAL POWER so that the energy transfer to the most limiting steam generator is not greater than the available relief capacity in that steam generator. For example, if one MSSV is inoperable in one steam generator, the relief capacity of that steam generator is reduced by approximately 20%. To offset this reduction in relief capacity, energy transfer to that steam generator must be similarly reduced. This is accomplished by reducing THERMAL POWER by the necessary amount to conservatively limit the energy transfer to all steam generators, consistent with the relief capacity of the most limiting steam generator.

The maximum power level specified for the power range neutron flux high trip setpoint with inoperable MSSVs must ensure that power is limited to less than the heat removal capacity of the remaining OPERABLE MSSVs. The reduced high flux trip setpoint also ensures that the reactor trip occurs early enough in the loss of load/turbine trip event to limit primary to secondary heat transfer and preclude overpressurization of the primary and secondary systems. To calculate this power level, the governing equation is the relationship q = m Ah, where q is the heat input from the primary side, m is the steam flow rate and Ah is the heat of vaporization at the steam relief pressure (assuming no subcooled feedwater). The algorithm use is consistent with the recommendations of the Westinghouse Nuclear Safety Advisory Letter, NSAL-94-001, dated January 20, 1994 (Ref. 6).

Additionally, the calculated values are reduced by 9% to account for instrument and channel uncertainties.

The allowed Completion Time of 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months provides an acceptable time to reach the required power level from full power operation without allowing the plant to remain in an unacceptable condition for an extended period of time and provides sufficient time to reduce the trip setpoints. The adjustment of the trip setpoints is a sensitive operation that may inadvertently trip the Reactor Protection System.

McGuire Units 1 and 2 B 3.7.1-3 Revision No. 102

MSSVs B 3.7.1 BASES ACTIONS (continued)

B.1 and B.2 If the MSSVs cannot be restored to OPERABLE status within the associated Completion Time, or if one or more steam generators have less than two MSSVs OPERABLE, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.1.1 REQUIREMENTS This SR verifies the OPERABILITY of the MSSVs by the verification of each MSSV lift setpoint in accordance with the Inservice Testing Program. The ASME OM Code (Ref. 5) requires that safety and relief valve tests be performed. According to Reference 5, the following tests are required:

a. Visual examination;

b. Seat tightness determination;

c. Setpoint pressure determination (lift setting);

d. Compliance with seat tightness criteria; and

e. Verification of the balancing device integrity on balanced valves.

The ASME Standard requires that all valves be tested every 5 years, and a minimum of 20% of the valves be tested every 24 months. The ASME OM Code specifies the activities and frequencies necessary to satisfy the requirements. Table 3.7.1-2 allows a + 3% setpoint tolerance for OPERABILITY; however, the valves are reset to + 1% during the Surveillance to allow for drift.

This SR is modified by a Note that allows entry into and operation in MODE 3 prior to performing the SR. The MSSVs may be either bench tested or tested in situ at hot conditions using an assist device to simulate lift pressure. If the MSSVs are not tested at hot conditions, the lift setting pressure shall be corrected to ambient conditions of the valve at operating temperature and pressure.

McGuire Units 1 and 2 B 3.7.1-4 Revision No. 102

MSSVs B 3.7.1 BASES REFERENCES 1. UFSAR, Section 10.3.1.

2. ASME, Boiler and Pressure Vessel Code,Section III, Article NC-7000, Class 2 Components.

3. UFSAR, Section 15.2.

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

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

6. Westinghouse Nuclear Safety Advisory Letter, NSAL-94-001, Dated January 20, 1994.

McGuire Units 1 and 2 B 3.7.1-5 Revision No. 102

MSIVs B 3.7.2 B 3.7 PLANT SYSTEMS B 3.7.2 Main Steam Isolation Valves (MSIVs)

BASES BACKGROUND The MSIVs isolate steam flow from the secondary side of the steam generators following a high energy line break (HELB). MSIV closure terminates flow from the unaffected (intact) steam generators.

One MSIV is located in each main steam line outside, but close to, containment. The MSIVs are downstream from the main steam safety valves (MSSVs) and auxiliary feedwater (AFW) pump turbine steam supply, to prevent MSSV and AFW isolation from the steam generators by MSIV closure. Closing the MSIVs isolates each steam generator from the others, and isolates the turbine, Steam Dump System, and other auxiliary steam supplies from the steam generators.

The MSIVs close on a main steam isolation signal generated by either low steam line pressure, high rate steam line pressure decrease, or high-high containment pressure.

The MSIV control circuits consist of both safety-related and non-safety control power. Non-safety control power is utilized in the manual open/close circuitry associated with each individual valve. The MSIVs will fail closed on a complete loss of A-Train and/or B-Train safety-related control power. Loss of the non-safety control power will not initiate closure of the MSIVs. Manual closure of the MSIVs is still available with a loss of non-safety control power by manually initiating the safety-related main steamline isolation signal.

The MSIVs close with spring force along with motive force provided by Instrument Air (VI). A safety-related VI accumulator for each MSIV will provide motive force and maintain valve control for approximately four hours following a loss of the non-safety instrument air system. The accumulator pressure must be > 60 psig to maintain valve operabillity.

Each MSIV has an MSIV bypass valve. Although these bypass valves are normally closed, they receive the same emergency closure signal as do their associated MSIVs. The MSIVs may also be actuated manually.

A description of the MSIVs is found in the UFSAR, Section 10.3 (Ref. 1).

McGuire Units 1 and 2 B 3.7.2-1 Revision 102

MSIVs B 3.7.2 BASES APPLICABLE The design basis of the MSIVs is established by the containment and SAFETY ANALYSES core response analyses for the large steam line break (SLB) events, discussed in the UFSAR, Section 6.2 (Ref. 2). The design precludes the blowdown of more than one steam generator.

The limiting case for the containment analysis is the SLB inside containment, with a loss of offsite power following turbine trip. At lower powers, the steam generator inventory and temperature are at their maximum, maximizing the analyzed mass and energy release to the containment. Due to reverse flow and failure of the MSIV to close, the additional mass and energy in the steam headers downstream from the other MSIV contribute to the total release. With the most reactive rod cluster control assembly assumed stuck in the fully withdrawn position, there is an increased possibility that the core will become critical and return to power. The core is ultimately shut down by the boric acid injection delivered by the Emergency Core Cooling System.

The accident analysis compares several different SLB events against different acceptance criteria. The large SLB outside containment upstream of the MSIV, is limiting for offsite dose, although a break in this short section of main steam header has a very low probability. The large SLB inside containment at hot zero power is the limiting case for a post trip return to power. The analysis includes scenarios with offsite power available, and with a loss of offsite power following turbine trip. With offsite power available, the reactor coolant pumps continue to circulate coolant through the steam generators, maximizing the Reactor Coolant System cooldown. With a loss of offsite power, the response of mitigating systems is delayed. Significant single failures considered include failure of an MSIV to close.

The MSIVs serve only a safety function and remain open during power operation. These valves operate under the following situations:

a. An HELB inside containment. In order to maximize the mass and energy release into containment, the analysis assumes quick closure of all MSIVs. For this accident scenario, steam is discharged into containment from all steam generators until the MSIVs close. After MSIV closure, steam is discharged into containment only from the affected steam generator and from the residual steam in the main steam header downstream of the closed MSIVs. Closure of the MSIVs isolates the break from the unaffected steam generators.

b. A break outside of containment and upstream from the MSIVs is not a containment pressurization concern. The uncontrolled blowdown of more than one steam generator must be prevented to limit the potential for uncontrolled RCS cooldown and positive.

McGuire Units 1 and 2 B 3.7.2-2 Revision 102

MSIVs B 3.7.2 BASES SAFETY ANALYSES (continued) reactivity addition. Closure of the MSIVs isolates the break and limits the blowdown to a single steam generator.

c. A break downstream of the MSIVs will be isolated by the closure of the MSIVs.

d. Following a steam generator tube rupture, closure of the MSIVs isolates the ruptured steam generator from the intact steam generators to minimize radiological releases.

e. The MSIVs are also utilized during other events such as a feedwater line break. This event is less limiting so far as MSIV OPERABILITY is concerned.

The MSIVs satisfy Criterion 3 of 10 CFR 50.36 (Ref. 3).

LCO This LCO requires that four MSIVs in the steam lines be OPERABLE.

The MSIVs are considered OPERABLE when the isolation times are within limits, and they close on an isolation actuation signal. The accumulator air pressure must also be > 60 psig.

This LCO provides assurance that the MSIVs will perform their design safety function to. mitigate the consequences of accidents that could result in offsite exposures comparable to the 10 CFR 100 (Ref. 4) limits or the NRC staff approved licensing basis.

APPLICABILITY The MSIVs must be OPERABLE in MODE 1, and in MODES 2 and 3 except when closed and de-activated, when there is significant mass and energy in the RCS and steam generators. When the MSIVs are closed, they are already performing the safety function.

In MODE 4, normally most of the MSIVs are closed, and the steam generator energy is low.

In MODE 5 or 6, the steam generators do not contain much energy because their temperature is below the boiling point of water; therefore, the MSIVs are not required for isolation of potential high energy secondary system pipe breaks in these MODES.

ACTIONS A.1 With one MSIV inoperable in MODE 1, action must be taken to restore OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . Some repairs to the MSIV can be made with the unit hot. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable, McGuire Units 1 and 2 B 3.7.2-3 Revision 102

MSIVs B 3.7.2 BASES ACTIONS (contd) considering the low probability of an accident occurring during this time period that would require a closure of the MSIVs.

The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is greater than that normally allowed for containment isolation valves because the MSIVs are valves that isolate a closed system penetrating containment. These valves differ from other containment isolation valves in that the closed system provides an additional means for containment isolation.

B.1 If the MSIV cannot be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in MODE 2 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and Condition C would be entered. The Completion Times are reasonable, based on operating experience, to reach MODE 2 and to close the MSIVs in an orderly manner and without challenging unit systems.

C.1 and C.2 Condition C is modified by a Note indicating that separate Condition entry is allowed for each MSIV.

Since the MSIVs are required to be OPERABLE in MODES 2 and 3, the inoperable MSIVs may either be restored to OPERABLE status or closed.

When closed, the MSIVs are already in the. position required by the assumptions in the safety analysis.

The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is consistent with that allowed in Condition A.

For inoperable MSIVs that cannot be restored to OPERABLE status within the specified Completion Time, but are closed, the inoperable MSIVs must be verified on a periodic basis to be closed. This is necessary to ensure that the assumptions in the safety analysis remain valid. The 7 day Completion Time is reasonable, based on engineering judgment, in view of MSIV status indications available in the control room, and other administrative controls, to ensure that these valves are in the closed position.

McGuire Units 1 and 2 B 3.7.2-4 Revision 102

MSIVs B 3.7.2 BASES ACTIONS (contd)

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

SURVEILLANCE SR 3.7.2.1 REQUIREMENTS This SR verifies that MSIV closure time is < 8.0 seconds on an actual or simulated actuation signal. The MSIV closure time is assumed in the accident and containment analyses. This Surveillance is normally performed upon returning the unit to operation following a refueling outage. The MSIVs should not be tested at power, since even a part stroke exercise increases the risk of a valve closure when the unit is generating power. As the MSIVs are not tested at power, they are exempt from the ASME OM Code (Ref. 5) requirements during operation in MODE 1 or 2.

The Frequency is in accordance with the Inservice Testing Program.

Testing shall be performed with both spring force and the motive force provided -by Instrument Air (VI) simultaneously. Leak-rate testing of the MSIV air control system shall be performed prior to returning the unit to operation following a refueling outage.

This test is conducied in MODE 3 with the unit at operating temperature and pressure, as discussed in Reference 5 exercising requirements. This SR is modified by a Note that allows entry into and operation in MODE 3 prior to performing the SR. This allows a delay of testing until MODE 3, to establish conditions consistent with those under which the acceptance criterion was generated.

REFERENCES 1. UFSAR, Section 10.3.

2. UFSAR, Section 6.2.

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

4. 10 CFR 100.11.

5. ASME Codelfor Operation and Maintenance of Nuclear Power Plants.

McGuire Units 1 and 2 B 3.7.2-5 Revision 102

MFIVs, MFCVs, MFCV's Bypass Valves, and MFW/AFW NBVs B 3.7.3 B 3.7 PLANT SYSTEMS B 3.7.3 Main Feedwater Isolation Valves; (MFIVs), Main Feedwater Control Valves (MFCVs),

MFCV's Bypass Valves and Main Feedwater (MFW) to Auxiliary Feedwater (AFW)

Nozzle Bypass Valves (MFW/AFW NBVs)

BASES BACKGROUND The MFIVs isolate main feedwater (MFW) flow to the secondary side of the steam generators following a high energy line break (HELB). The safety related function of the MFCVs is to provide the second isolation of MFW flow to the secondary side of the steam generators following an HELB. Closure of the MFIVs (CF 26, 28, 30, and 35), MFCVs (CF 17, 20, 23, and 32) and MFCV's bypass valves (CF 104, 105, 106, and 107), and MFW/AFW NBVs (CF 126, 127, 128, and 129) terminates flow to the steam generators, terminating the event for feedwater line breaks (FWLBs) occurring 'upstream of the MFIVs or MFCVs. The consequences of events occurring in the main steam lines or in the MFW lines downstream from the MFIVs will be mitigated by their closure.

Closure of the MFIVs, MFCVs and MFCV's bypass valves or MFW/AFW NBVs, effectively terminates the addition of feedwater to an affected steam generator, limiting the mass and energy release for steam line breaks (SLBs) or FWLBs inside containment, and reducing the cooldown effects for SLBs.

The MFIVs, MFCVs, and MFCV's bypass valves, and MFW/AFW NBVs isolate the nonsafety related portions from the safety related portions of the system. In the event of a secondary side pipe rupture inside containment, the valves limit the quantity of high energy fluid that enters containment through the break, and provide a pressure boundary for the controlled addition of AFW to the intact loops.

One MFIV, one MFCV, one MFCV's bypass valve, and one MFW/AFW NBV are located on each MFW line, outside containment. The MFIVs and MFCVs are located on different supply lines from the AFW injection line so that AFW mrIay be supplied to the steam generators following MFIV or MFCV closure. The piping volume from these valves to the steam generators must be accounted for in calculating mass and energy releases, and refilled prior to AFW reaching the steam generator following either an SLB or FWLB.

The MFIVs, MFCVs, MFCV's bypass valves, and MFW/AFW NBVs close on receipt of a safety injection signal, Tavg-Low coincident with reactor trip (P-4), or steam generator water level-high high signal. They may also be actuated manually. The check valve outside containment McGuire Units 1 and 2 B 3.7.3-1 Revision No. 102

MFIVs, MFCVs, MFCV's Bypass Valves, and MFW/AFW NBVs B 3.7.3 BASES BACKGROUND (continued) prevents multiple steam generator blowdown and overcooling in the event of a nonsafety related pipe failure or faulted steam generator concurrent with a single failure of a MFIV on an otherwise intact steam generator. A description of the MFIVs and MFCVs is found in the UFSAR, Section 10.4.7 (Ref.' 1).

APPLICABLE The design basis of the MFIVs and MFCVs is established by the analyses SAFETY ANALYSES for the large SLB. It is also influenced by the accident analysis for the large FWLB. Closure of the MFIVs, MFCVs and MFCV's bypass valves, or MFW/AFW NBVs, may also be relied on to terminate an SLB for core response analysis and excess feedwater event upon the receipt of a steam generator water level-high high signal or a feedwater isolation signal on high steam generator level.

Failure of a MFIV, MFCV, MFCV's bypass valve, or MFW/AFW NBV to close following an SLB or FWLB can result in additional mass and energy being delivered to the steam generators, contributing to cooldown. This failure also results in additional mass and energy releases following an SLB or FWLB event.

The MFIVs and MFCVs satisfy Criterion 3 of 10 CFR 50.36 (Ref. 2).

LCO This LCO ensures that the MFIVs, MFCVs, MFCV's bypass valves, and MFW/AFW NBVs will isolate MFW flow to the steam generators, following an FWLB or main steam line break. These valves will also isolate the nonsafety related portions from the safety related portions of the system.

This LCO requires that four MFIVs, four MFCVs, four MFCV's bypass valves, and four MFW/AFW NBVs be OPERABLE. The MFIVs, MFCVs, MFCV's bypass valves, and MFW/AFW NBVs are considered OPERABLE when isolation times are within limits and they close on an isolation actuation signal.

Failure to meet the LCO requirements can result in additional mass and energy being released to containment following an SLB or FWLB inside containment. If a feedwater isolation signal on high steam generator level is relied on to terminate an excess feedwater flow event, failure to meet the LCO may result in the introduction of water into the main steam lines.

McGuire Units 1 and 2 B 3.7.3-2 Revision No. 102

MFIVs, MFCVs, MFCV's Bypass Valves, and MFW/AFW NBVs B 3.7.3 BASES APPLICABILITY The MFIVs, MFCVs, MFCV's bypass valves, and MFW/AFW NBVs must be OPERABLE whenever there is significant mass and energy in the Reactor Coolant System and steam generators. This ensures that, in the event of an HELB, a single failure cannot result in the blowdown of more than one steam generator. In MODES 1, 2, and 3, the MFIVs, MFCVs, MFCV's bypass valves, and MFW/AFW NBVs are required to be OPERABLE to limit the amount of available fluid that could be added to containment in the case of a secondary system pipe break inside containment. When the valves are closed and de-activated or isolated by a closed manual valve, they are already performing their safety function.

In MODES 4, 5, and 6, steam generator energy is low. Therefore, the MFIVs, MFCVs, MFCV's bypass valves, and MFW/AFW NBVs are normally closed since MFW is not required.

ACTIONS The ACTIONS table is modified by a Note indicating that separate Condition entry is allowed for each valve.

A.1 and A.2 With one MFIV in one or more flow paths inoperable, action must be taken to restore the affected valves to OPERABLE status, or to close or isolate inoperable affected valves within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months by use of a closed and de-activated automatic valve, a closed manual valve, or blind flange.

When these valves are closed or isolated, they are performing their required safety function.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundancy afforded by the remaining OPERABLE valves and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on operating experience.

Inoperable MFIVs that are closed or isolated must be verified on a periodic basis that they are closed or isolated. This is necessary to ensure that the assumptions in the safety analysis remain valid. The 7 day Completion Time is reasonable, based on engineering judgment, in view of valve status indications available in the control room, and other administrative controls, to ensure that these valves are closed or isolated.

McGuire Units 1 and 2 B 3.7.3-3 Revision No. 102

MFIVs, MFCVs, MFCV's Bypass Valves, and MFW/AFW NBVs B 3.7.3 BASES ACTIONS (continued)

B.1 and B.2 With one MFCV in one or more flow paths inoperable, action must be taken to restore the affected valves to OPERABLE status, or to close or isolate inoperable affected valves within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months by use of a closed and de-activated automatic valve, a closed manual valve, or-blind flange.

When these valves 'are closed or isolated, they are performing their required safety function.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundancy afforded by the remaining OPERABLE valves and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is reasonable, based on operating experience.

Inoperable MFCVs,i that are closed or isolated, must be verified on a periodic basis that they are closed or isolated. This is necessary to ensure that the assumptions in the safety analysis remain valid. The 7 day Completion Time is reasonable, based on engineering judgment, in view of valve status indications available in the control room, and other administrative controls to ensure that the valves are closed or isolated.

C.1 and C.2 With one MFCV's bypass valve or MFW/AFW NBV in one or more flow paths inoperable, action must be taken to restore the affected valves to OPERABLE status, or to close or isolate inoperable affected valves within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months by use of a closed and de-activated automatic valve, a closed manual valve, or blind flange. When these valves are closed or isolated, they are performing their required safety function.

The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundancy afforded by the remaining OPERABLE valves and the low probability of an event occurring during this time period that would require isolation of the MFW flow paths. The 72: hour Completion Time is reasonable, based on operating experience.

Inoperable MFCV's bypass valves or MFW/AFW NBVs that are closed or isolated must be verified on a periodic basis that they are closed or isolated. This is necessary to ensure that the assumptions in the safety analysis remain valid. The 7 day Completion Time is reasonable, based on engineering judgment, in view of valve status indications available in the control room, and other administrative controls, to ensure that these valves are closed 6r isolated.

McGuire Units 1 and 2 B 3.7.3-4 Revision No. 102

MFIVs, MFCVs, MFCV's Bypass Valves, and MFW/AFW NBVs B 3.7.3 BASES ACTIONS (continued)

D.1 With two inoperable valves in the same flow path, there may be no redundant system to operate automatically and perform the required safety function. Under these conditions, affected valves in each flow path must be restored to OPERABLE status, or the affected flow path isolated within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . This action returns the system to the condition where at least one valve in each flow path is performing the required safety function. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable, based on operating experience, to complete the actions required to close the MFIV or MFCV, or otherwise isolate the affected flow path.

E.1 and E.2 If the MFIV(s), MFCV(s), MFCV's bypass valve(s), and MFW/AFW NBV(s) cannot be restored to OPERABLE status, or closed, or isolated within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , and in MODE 4 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE SR 3.7.3.1 REQUIREMENTS This SR verifies that the closure time of each MFIV, MFCV, MFCV's bypass valve, and MFW/AFW NBV is < 10 seconds on an actual or simulated actuation signal. The MFIV and MFCV closure times are assumed in the accident and containment analyses. This Surveillance is normally performed upon returning the unit to operation following a refueling outage. These valves should not be tested at power since even a part stroke exercise increases the risk of a valve closure with the unit generating power. This is consistent with the ASME OM Code (Ref. 3) quarterly stroke requirements during operation in MODES 1 and 2.

The Frequency for this SR is in accordance with the Inservice Testing Program.

McGuire Units 1 and 2 B,3.7.3-5 Revision No. 102

MFIVs, MFCVs, MFCV's Bypass Valves, and MFW/AFW NBVs B 3.7.3 BASES 0 REFERENCES 1. UFSAR, Section 10.4.7.

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

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

McGuire Units I and 2 3.7.3-6 Revision No. 102

AFW System B 3.7.5 B 3.7 PLANT SYSTEMS B 3.7.5 Auxiliary Feedwater (AFW) System BASES BACKGROUND The AFW System automatically supplies feedwater to the steam generators to remove decay heat from the Reactor Coolant System upon the loss of normal feedwater supply. The AFW pumps take suction from the non-safety related AFW Storage Tank (Water Tower). The assured source of water to the AFW System is the Nuclear Service Water (RN)

System. The turbine and motor driven pump discharge lines to each individual steam generator join into a single line outside containment.

These individual lines penetrate the containment and enter each steam generator through the auxiliary feedwater nozzle. The steam generators function as a heat sink for core decay heat. The heat load is dissipated by releasing steam to the atmosphere from the steam generators via the main steam safety valves (MSSVs) (LCO 3.7.1) or SG PORVs (LCO 3.7.4). If the main condenser is available, steam may be released via the steam dump valves and recirculated to the condensate storage system (CSS).

The AFW System consists of two motor driven AFW pumps and one steam turbine driven pump configured into three trains. Each of the motor driven pumps supply 100% of the flow requirements to two steam generators, although each pump has the capability to be realigned to feed other steam generators. The turbine driven pump provides 200% of the flow requirements and supplies water to all four steam generators. Travel stops are set on the steam generator flow control valves such that the pumps can supply the minimum flow required without exceeding the maximum flow allowed. The pumps are equipped with independent recirculation lines to prevent pump operation against a closed system.

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

The AFW System is capable of supplying feedwater to the steam generators during normal unit startup, shutdown, and hot standby McGuire Units I and 2 Br13.7.5-1 Revision No. 102

BASES AFW System B 3.

7.5 BACKGROUND

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

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

The motor driven AFW pumps actuate automatically on steam generator water level low-low in 1 out of 4 steam generators by the ESFAS (LCO 3.3.2). The motor driven pumps also actuates on loss of offsite power, safety injection, and trip of all MFW pumps. The turbine driven AFW pump actuates automatically on steam generator water level low-low in 2 out of 4 steam generators and on loss of offsite power.

The AFW System is discussed in the UFSAR, Section 10.4.7 (Ref. 1).

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

The design basis of the AFW System is to supply water to the steam generator to remove decay heat and other residual heat by delivering at least the minimum required flow rate to the steam generators.

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

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

a. Feedwater Line Break (FWLB);

b. Steam Generator Tube Rupture (SGTR);

McGuire Units 1 and 2 133.7.5-2 Revision No. 102

BASES AFW System B 3.7.5 APPLICABLE SAFETY ANALYSES (continued)

c. Main Steam Line Break (MSLB);

d. Small Break Loss of Coolant Accident (SBLOCA); and

e. Loss of Offsite AC Power.

The AFW System design is such that it can perform its function following a FWLB between the Steam Generator and the feedwater isolation valve, combined with a loss of offsite power following turbine trip, and a single active failure of the steam turbine driven AFW pump. In such a case, one motor driven AFW pump will deliver nearly all of its flow to the steam generator with the broken MFW header until flow to that steam generator can be terminated by the operator. Sufficient flow is delivered to the intact steam generators by the redundant AFW pump.

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

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

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

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

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

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

The turbine driven AFW pump is required to be OPERABLE with redundant steam supplies from two main steam lines upstream of the MSIVs, and shall be capable of supplying AFW to any of the steam generators. The piping, valves, instrumentation, and controls in the required flow paths also are required to be OPERABLE.

McGuire Units 1 and 2 B 3.7.5-3 Revision No. 102

BASES AFW System B 3.7.5 LCO (continued)

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

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

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

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

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

ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable AFW train when entering MODE 1. There is an increased risk associated with entering MODE 1 with an AFW train inoperable and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

A.1 If one of the two steam supplies to the turbine driven AFW train is inoperable, action must be taken to restore OPERABLE status within 7 days in MODES 1, 2, and 3. The 7 day Completion Time is reasonable, based on the following reasons:

a. The redundant OPERABLE steam supply to the turbine driven AFW pump;

b. The availability of redundant OPERABLE motor driven AFW pumps; and

c. The low probability of an event occurring that requires the inoperable steam supply to the turbine driven AFW pump.

McGuire Units 1 and 2 B 13.7.5-4 Revision No. 102

BASES AFW System B 3.7.5 ACTIONS (continued)

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

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

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

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

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

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

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

In MODE 4 with two AFW trains inoperable, operation is allowed to continue because only one motor driven pump AFW train is required in McGuire Units 1 and 2 B 3.7.5-5 Revision No. 102

BASES AFW System B 3.7.5 ACTIONS (continued) accordance with the Note that modifies the LCO. Although not required, the unit may continue to cool down and initiate RHR.

D.1 If all three AFW trains are inoperable in MODE 1, 2, or 3, the unit is in a seriously degraded condition with no safety related means for conducting a cooldown, and only limited means for conducting a cooldown with nonsafety related equipment. In such a condition, the unit should not be perturbed by any action, including a power change, that might result in a trip. The seriousness of this condition requires that action be started immediately to restore one AFW train to OPERABLE status.

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

E._1 In MODE 4, either the reactor coolant pumps or the RHR loops can be used to provide forced circulation. This is addressed in LCO 3.4.6, "RCS Loops-MODE 4." j With one required AFW train with a motor driven pump inoperable, action must be taken to immediately restore the inoperable train to OPERABLE status. The immediate Completion Time is consistent with LCO 3.4.6.

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

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

McGuire Units 1 and 2 B 3.7.5-6 Revision No. 102

BASES AFW System B 3.7.5 SURVEILLANCE REQUIREMENTS (continued)

The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

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

Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. Performance of inservice testing discussed in the ASME OM Code (Ref. 3) (only required at 3 month intervals) satisfies this requirement.

The Frequency for this SR is in accordance with the Inservice Testing Program.

This SR is modified by a Note indicating that the SR should be deferred until suitable test conditions are established. This deferral is required because there is insufficient steam pressure to perform the test. The test should be conducted within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of the steam pressure exceeding 900 psig.

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

This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls.

The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. The 18 month Frequency is acceptable based on operating experience and the design reliability of the equipment.

This SR is modified by a Note that states the SR is not required in MODE 4. In MODE 4, the required AFW train may already be aligned and operating.

McGuire Units 1 and 2 B -3.7.5-7 Revision No. 102

BASES AFW System B 3.7.5 SURVEILLANCE REQUIREMENTS (continued)

SR 3.7.5.4 This SR verifies that the AFW pumps will start in the event of any accident or transient that generates an ESFAS by demonstrating that each AFW pump starts automatically on an actual or simulated actuation signal in MODES 1, 2, and 3. In MODE 4, the required pump may already be operating and the autostart function is not required. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power.

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

The test should be conducted within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of the steam pressure exceeding 900 psig. Note 2 states that the SR is not required in MODE 4.

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

REFERENCES 1. UFSAR, Section 10.4.7.

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

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

McGuire Units I and 2 B 3.7.5-8 Revision No. 102

NSWS B 3.7.7 B 3.7 PLANT SYSTEMS B 3.7.7 Nuclear Service Water System (NSWS)

BASES BACKGROUND The NSWS provides a transfer mechanism for the removal of process and operating heat from safety related components during a Design Basis Accident (DBA) or.transient. During normal operation, and a normal shutdown, the NSWS also provides this function for various safety related and nonsafety related components. The safety related function is covered by this LCO.

The NSWS is normally supplied from Lake Norman as a non-seismic source, through a single supply line as shown in Figure B 3.7.7-1. An additional safety-related and seismic supply of water to the NSWS, in the event of a loss of Lake Norman, is the Standby Nuclear Service Water Pond (SNSWP). The supply line from Lake Norman separates into two supply headers, each header is capable of being isolated by two, independently powered, motor operated valves. The two supply headers feed into two separate supply trains. The "A" train supplies water to the "A" pump on each unit and the "B" train to the "B" pump on each unit.

During normal operation, only one pump, per unit, is in operation to supply NSWS flow to the essential and non-essential headers for each unit. The "B" train supply is automatically realigned to the SNSWP and supplies the "B" header on an SI signal from either unit. The "A" train supply is automatically realigned to the low-level supply from Lake Norman and supplies the "A" header on an SI signal from either unit.

Essential headers provide flow to the following safety related components and systems:

1. Component Cooling (CCW) Heat Exchangers and Pump Motor Coolers,

2. Containment Spray Heat Exchangers and Pump Motor Coolers,

3. Control Room Area Chiller Condensers,

4. Diesel Generator Heat Exchangers,

5. Centrifugal Charging Pump Motor, Bearing Oil and Gear Oil Coolers,

6. Nuclear Service Water Pump Motor Coolers,

7. Auxiliary Feedwater Pump Motor Coolers,

8. Safety Injection Pump Motor and Bearing Oil Coolers,

9. Residual Heat Removal Pump Motor Coolers,

10. Fuel Pool Pump Motor Coolers,

11. Assured Auxiliary Feedwater Supply,

12. Assured Component Cooling System Makeup,

13. Assured Fuel Pool Cooling System makeup, and

14. Assured Diesel Generator Engine Cooling System makeup.

McGuire Units 1 and 2 B33.7.7-1 Revision No. 101

NSWS B 3.7.7 BASES BACKGROUND (continued)

The non-essential channel supply comes from the "A" and "B" train crossover piping and isolates on an SI or Blackout signal.

The Reactor Coolant Pump Motor Air Coolers are not essential for safe shutdown, but are set up to receive cooling flow until the Containment, High-High signal is received. The pumps and valves are remote and manually aligned, except in the unlikely event of a loss of coolant accident (LOCA). The pumps aligned to the critical loops are, automatically started upon receipt of a safety injection or Station Blackout signal, and all essential valves are aligned to their post accident positions.

Additional information about the design and operation of the NSWS, along with a list of the components served, is presented in the UFSAR, Section 9.2 (Ref. 1). The principal safety related function of the NSWS is the removal of decay heat from the reactor via the CCW System.

APPLICABLE The design basis of the NSWS is for one NSWS train, in conjunction with SAFETY ANALYSES the CCW System and the Containment Spray system, to remove core decay heat following a design basis LOCA as discussed in the UFSAR, Section 6.2 (Ref. 2). This prevents the containment sump fluid from increasing in temperature during the recirculation phase following a LOCA and provides for a gradual reduction in the temperature of this fluid as it is supplied to the Reactor Coolant System by the ECCS pumps. The NSWS is designed to perform its function with a single failure of any active component, assuming the loss of offsite power.

The NSWS, in conjunction with the CCW System, also removes heat from the residual heat removal (RHR) system, as discussed in the UFSAR, Section 5.4 (Ref. 3), from RHR entry conditions to MODE 5 during normal and post accident operations. The time required for this evolution is a function of the number of CCW and RHR System trains that are operating. One NSWS train is sufficient to remove decay heat during subsequent, operations in MODES 5 and 6. This assumes a maximum NSWS inlet temperature-of 95 0 F is not exceeded.

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

LCO Two NSWS trains are required to be OPERABLE to provide the required redundancy to ensure that the system functions to remove post accident McGuire Units 1 and 2 B 3.7.7-2 Revision No. 101

NSWS B 3.7.7 BASES LCO (continued) heat loads, assuming that the worst case single active failure occurs coincident with the loss of offsite power.

An NSWS train is considered OPERABLE during MODES 1, 2, 3, and 4 when:

a. The associated unit's pump is OPERABLE; and

b. The associated piping, valves, and instrumentation and controls required to perform the safety related function are OPERABLE.

Portions of the NSWS system are shared between the two units. The shared portions of the system must be OPERABLE for each unit when that unit is in the MODE of Applicability. Additionally, both normal and emergency power for shared components must also be OPERABLE. If a shared NSWS component becomes inoperable, or normal or emergency power to shared components becomes inoperable, then the Required Actions of this LCO must be entered independently for each unit that is in the MODE of applicability of the LCO.

Figure B 3.7.7-1 "Nuclear Service Water System" shows the portions of system piping and ývalves that are shared and within the scope of General Design Criterion 5 (Ref: 5). The RN pump discharge crossover valves are normally locked closed and, as reflected on figure B 3.7.7-1, do not fall within the scope of General Design Criterion 5. Consequently, when the RN pump discharge crossover valves are opened the NSWS trains affected by the cross connected alignment shall be declared inoperable.

APPLICABILITY In MODES 1, 2, 3,' and 4, the NSWS is a normally operating system that is required to support the OPERABILITY of the equipment serviced by the NSWS and required to be OPERABLE in these MODES.

In MODES 5 and 6, the requirements of the NSWS are determined by the systems it supports.

ACTIONS A._1 If one NSWS trainý is inoperable, action must be taken to restore OPERABLE status within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . In this Condition, the remaining OPERABLE NSWS train is adequate to perform the heat removal function. However, the overall reliability is reduced because a single failure in the OPERABLE'NSWS train could result in loss of NSWS function. Required Action A.1 is modified by two Notes. The first Note McGuire Units 1 and 2 B 3.7.7-3 Revision No. 101

NSWS B 3.7.7 BASES ACTIONS (continued) indicates that the applicable Conditions and Required Actions of LCO 3.8.1, "AC Sources-Operating," should be entered if an inoperable NSWS train results in an inoperable emergency diesel generator. The second Note indicates that the applicable Conditions and Required Actions of LCO 3.4.6, "RCS Loops-MODE 4," should be entered if an inoperable NSWS train results in an inoperable decay heat removal train.

This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is based on the redundant capabilities afforded by the OPERABLE train, and the low probability of a DBA occurring during this time period.

B.1 and B.2 If the NSWS train Cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months and in MODE 5 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months .

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

SURVEILLANCE SR 3.7.7.1 REQUIREMENTS This SR is modified by a Note indicating that the isolation of the NSWS components or systems may render those components inoperable, but does 'not affect the OPERABILITY of the NSWS.

Verifying the correct alignment for manual, power operated, and automatic valves in the NSWS flow path provides assurance that the proper flow paths exist for NSWS operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since they are verified to be in the correct position prior to being locked, sealed, or secured. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot'be inadvertently misaligned, such as check valves.

The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

McGuire Units 1 and 2 B 3.7.7-4 Revision No. 101

NSWS B 3.7.7 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.7.7.2 This SR verifies proper automatic operation of the NSWS valves on an actual or simulated ,actuation safety injection signal. The NSWS is a normally operating system that cannot be fully actuated as part of normal testing. 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 this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

SR 3.7.7.3

'This SR verifies proper automatic operation of the NSWS pumps on an actual or simulated actuation signal. The NSWS is a normally operating system that cannot be fully actuated as part of normal testing during normal operation. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

REFERENCES 1. UFSAR, Section 9.2.

2. UFSAR, Section 6.2.

3. UFSAR, Section 5.4.

4. 10 CFR 50,36, Technical Specifications, (c)(2)(ii).

5. 10 CFR 50, Appendix A, GDC 5, "Sharing of Structures, Systems, and Components".

6. Generic Letter 91-13, "Request for Information related to the resolution of Generic Issue 130, Essential Service Water System Failures at Multi-Unit Sites".

McGuire-Units 1 and 2 B 3.7.7-5 Revision No. 101

NSWS B 3.7.7 BASES FIGURE B 3.7.7-1 NUCLEAR SERVICE WATER SYSTEM McGuire Units 1 and 2 B 3.7.7-6 Revision No. 101

ML093130164

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7.5 BACKGROUND

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