Text

Changes to Technical Specification Bases - Revisions 80 and 81
	ML20070L982
Person / Time
Site:	Wolf Creek
Issue date:	03/02/2020
From:	Benham R; Wolf Creek
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	RA 20-0011
	Download: ML20070L982 (115)
	v • d • e

W8LFCREEK 'NUCLEAR OPERATING CORPORATION Ron Benham Manager Nuclear and Regulatory Affairs March 2, 2020 RA 20-0011 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555

Subject:

Docket No. 50-482: Wolf Creek Generating Station Changes to Technical Specification Bases - Revisions 80 and 81 To Whom It May Concern:

The Wolf Creek Generating Station (WCGS) Unit 1 Technical Specifications (TS), Section 5.5.14, "Technical Specifications (TS) Bases Control Program," provides the means for making changes to the Bases without prior Nuclear Regulatory Commission (NRC) approval. In addition, TS Section 5.5.14 requires that changes made without NRC approval be provided to the NRC on a frequency consistent with 10 CFR 50.71(e). The Enclosure provides those changes made to the WCGS TS Bases (Revisions 80 and 81) under the provisions to TS Section 5.5.14 and a List of Effective Pages. This submittal reflects changes from January 1, 2019, through December 31, 2019.

This letter contains no commitments. If you have any questions concerning this matter, please contact me at (620) 364-4204.

Sincerely,

~Ron Benham RDB/rlt Enclosure cc: S. A. Morris (NRC), w/e N. O'Keefe (NRC), w/e B. K Singal (NRC), w/e Senior Resident Inspector (NRC), w/e P.O. Box 411 / Burlington, KS 66839 / Phone: (620) 364-8831 An Equal Opportunity Employer M/F/HCNET

Enclosure to RA 20:..0011 Wolf Creek Generating Station Changes to the Technical Specification Bases (113 pages)

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES 1

PAGE <) REVISION NO. <2l CHANGE DOCUMENT <3l DATE EFFECTIVE/

IMPLEMENTED <4l TAB - Title Page Technical Specification Cover Page Title Page TAB - Table of Contents 34 ORR 07-1057 7/10/07 ii 29 ORR 06-1984 10/17/06 iii 44 ORR 09-1744 10/28/09 TAB - B 2.0 SAFETY LIMITS (SLs)

B 2.1.1-1 0 Amend. No. 123 12/18/99 B 2.1.1-2 14 ORR 03-0102 2/12/03 B 2.1.1-3 14 ORR 03-0102 2/12/03 B 2.1.1-4 O. Amend. No. 123 2/12/03 B 2.1.2-1 0 Amend. No. 123 12/18/99 B 2.1.2-2 12 ORR 02-1062 9/26/02 B 2.1.2-3 0 Amend. No. 123 12/18/99 TAB - B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILTY B 3.0-1 . 34 ORR 07-1057 7/10/07 B 3.0-2 0 Amend. No. 123 12/18/99 B 3.0-3 0 Amend. No. 123 12/18/99 B 3.0-4 19 ORR 04-1414 10/12/04 B 3.0-5 19 ORR 04-1414 10/12/04 B 3.0-6 19 ORR 04-1414 10/12/04 B 3.0-7 19 ORR 04-1414 10/12/04 B 3.0-8 19 ORR 04-1414 10/12/04 B 3.0-9 42 ORR 09-1009 7/16/09 B 3.0-10 42 ORR 09-1009 7/16/09 B 3.0-11 34 ORR 07-1057 7/10/07 B 3.0-12 34 ORR 07-1057 7/10/07 B 3.0-13 34 ORR 07-1057 7/10/07 B 3.0-14 34 ORR 07-1057 7/10/07 B 3.0-15 34 ORR 07-1057 7/10/07 B 3.0-16 34 ORR 07-1057 7/10/07 TAB- B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.1-1 0 Amend. No. 123 12/18/99 B 3.1.1-2 0 Amend. No. 123 12/18/99 B 3.1.1-3 0 Amend. No. 123 12/18/99 B 3.1.1-4 19 ORR 04-1414 10/12/04 B 3.1.1-5 0 Amend. No. 123 12/18/99 B 3.1.2-1 0 Amend. No. 123 12/18/99 B 3.1.2-2 0 Amend. No. 123 12/18/99 B 3.1.2-3 0 Amend. No. 123 12/18/99 B 3.1.2-4 0 Amend. No. 123 12/18/99 B 3.1.2-5 0 Amend. No. 123 12/18/99 B 3.1.3-1 0 Amend. No. 123 12/18/99 83.1.3-2 0 Amend. No. 123 12/18/99 B 3.1.3-3 0 Amend. No. 123 12/18/99 B 3.1.3-4 . 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 Revision SO

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE<1J REVISION NO. <2> CHANGE DOCUMENT <3J DATE EFFECTIVE/

IMPLEMENTED <4J TAB - B 3.1 REACTIVITY CONTROL SYSTEMS (continued}

B3.1.3-5 0 Amend. No. 123 12/18/99 B 3.1.3-6 0 Amend. No. 123 12/18/99 B3.1.4-1 0 Amend. No. 123 12/18/99 B 3.1.4-2 0 Amend. No. 123 12/18/99 B 3.1.4-3 48 ORR 10-3740 12/28/10 B 3.1.4-4 0 Amend. No. 123 12/18/99 B 3.1.4-5 0 Amend. No. 123 12/18/99 B 3.1.4-6 48 ORR 10-3740 12/28/10 B 3.1.4-7 0 Amend. No. 123 12/18/99 B 3.1.4-8 0 Amend. No. 123 12/18/99 B 3.1.4-9 0 Amend. No. 123 12/18/99 B3.1.5-1 0 Amend. No. 123 12/18/99 83.1.5-2 0 Amend. No. 123 12/18/99 B 3.1.5-3 0 Amend. No. 123 12/18/99 B 3.1.5-4 0 Amend. No. 123 12/18/99 83.1.6-1 0 Amend. No. 123 12/18/99 B 3.1.6-2 0 Amend. No. 123 12/18/99 B 3.1.6-3 0 Amend. No. 123 12/18/99 B 3.1.6-4 0 Amend. No. 123 12/18/99 B 3.1.6-5 0 Amend. No. 123 12/18/99 B 3.1.6-6 0 Amend. No. 123 12/18/99 B 3.1.7-1 0 Amend. No. 123 12/18/99 B 3.1.7-2 0 Amend. No. 123 12/18/99 83.1.7-3 48 ORR 10-3740 12/28/10 B 3.1.7-4 48 ORR 10-3740 12/28/10 B 3.1.7-5 48 ORR 10-3740 12/28/10 B 3.1.7-6 0 Amend. No. 123 12/18/99 83.1.8-1 0 Amend. No. 123 12/18/99 B 3.1.8-2 0 Amend. No. 123 12/18/99 B 3.1.8-3 15 ORR 03-0860 7/10/03 B 3.1.8-4 15 ORR 03-0860 7/10/03 B 3.1.8-5 0 Amend. No. 123 12/18/99 83.1.8-6 5 ORR 00-1427 10/12/00 TAB - B 3.2 POWER DISTRIBUTION LIMITS B 3.2.1-1 48 ORR 10-3740 12/28/10 B 3.2.1-2 0 Amend. No. 123 12/18/99 B 3.2.1-3 48 ORR 10-3740 12/28/10 B 3.2.1-4 48 ORR 10-3740 12/28/10 B 3.2.1-5 48 ORR 10-3740 12/28/10 B 3.2.1-6 48 ORR 10-3740 12/28/10 B 3.2.1-7 48 ORR 10-3740 12/28/10 B 3.2.1-8 48 ORR 10-3740 12/28/10 B 3.2.1-9 29 ORR 06-1984 10/17/06 B 3.2.1-10 70 ORR 15-0944 4/28/15 B 3.2.2-1 48 ORR 10-3740 12/28/10 B 3.2.2-2 0 Amend. No. 123 12/18/99 B 3.2.2-3 48 ORR 10-3740 12/28/10 B 3.2.2-4 48 ORR 10-3740 12/28/10 B 3.2.2-5 48 ORR 10-3740 12/28/10 B 3.2.2-6 70 ORR 15-0944 4/28/15 Wolf Creek - Unit 1 ii Revision SO

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE< 1> REVISION NO. <2> CHANGE DOCUMENT < >

3 DATE EFFECTIVE/

IMPLEMENTED <4>

TAB- B 3.2 POWER DISTRIBUTION LIMITS (continued)

B 3.2.3-1 0 Amend. No. 123 12/18/99 B 3.2.3-2 0 Amend. No. 123 12/18/99 B 3.2.3-3 0 Amend. No. 123 12/18/99 B 3.2.4-1 0 Amend. No. 123 12/18/99 B 3.2.4-2 0 Amend. No. 123 12/18/99 B 3.2.4-3 48 ORR 10-3740 12/28/10 B 3.2.4-4 O Amend. No. 123 12/18/99 B 3.2.4-5 48 ORR 10-3740 12/28/10 B 3.2.4-6 0 Amend. No. 123 12/18/99 B 3.2.4-7 48 ORR 10-3740 12/28/10 TAB - B 3.3 INSTRUMENTATION B 3.3.1-1 0 Amer:id. No. 123 12/18/99 B 3.3.1-2 0 Amend. No. 123 12/18/99 B 3.3.1-3 0 Amend. No. 123 12/18/99 B 3.3.1-4 0 Amend. No. 123 12/18/99 B 3.3.1-5 0 Amend. No. 123 12/18/99 B 3.3.1-6 0 Amend. No. 123 12/18/99 B 3.3.1-7 5 ORR 00-1427 10/12/00 B 3.3.1-8 o* Amend. No. 123 12/18/99 B 3.3.1-9 0 Amend. No. 123 12/18/99 B3.3.1-10 29 ORR 06-1984 10/17/06 B 3.3.1-11 0 Amend. No. 123 12/18/99 B 3.3.1-12 0 Amend. No. 123 12/18/99 B3.3.1-13 0 Amend. No. 123 12/18/99 B3.3.1-14 0 Amend. No. 123 12/18/99 B 3.3.1-15 0 Amend. No. 123 12/18/99 B 3.3.1-16 0 Amend. No. 123 12/18/99 B3.3.1-17 0 Amend. No. 123 12/18/99 B 3.3.1-18 0 Amend. No. 123 12/18/99 B 3.3.1-19 66 ORR 14-2329 11/6/14 B 3.3.1-20 66 ORR 14-2329 11/6/14 B 3.3.1-21 0 Amend. No. 123 12/18/99 B 3.3.1-22 0 Amend. No. 123 12/18/99 B 3.3.1-23 9 ORR 02-0123 2/28/02 B 3.3.1-24 78 ORR 18-0443 5/8/18 B 3.3.1-25 78 ORR 18-0443 5/8/18 B 3.3.1-26 78 ORR 18-0443 5/8/18 B 3.3.1-27 78 ORR 18-0443 5/8/18 B 3.3.1-28 2 ORR 00-0147 4/24/00 B 3.3.1-29 1 ORR 99-1624 12/18/99 B 3.3.1-30 1 ORR 99-1624 12/18/99 B 3.3.1-31 0 Amend. No. 123 12/18/99 B 3.3.1-32 20 ORR 04-1533 2/16/05 B 3.3.1-33 48 ORR 10-3740 12/28/10 B 3.3.1-34 20 ORR 04-1533 2/16/05 B 3.3.1-35 19 ORR 04-1414 10/13/04 B 3.3.1-36 20 ORR 04-1533 2/16/05 B 3.3.1-37 20 ORR 04-1533 2/16/05 B 3.3.1-38 20 ORR 04-1533 2/16/05 B 3.3.1-39 25 ORR 06-0800 5/18/06 Wolf Creek - Unit 1 iii Revision SO

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE( 1> REVISION NO. (2> CHANGE DOCUMENT (3) DATE EFFECTIVE/

IMPLEMENTED (4 l TAB- B 3.3 INSTRUMENTATION {continued}

B 3.3.1-40 20 ORR 04-1533 2/16/05 B 3.3.1-41 20 ORR 04-1533 2/16/05 B 3.3.1-42 20 ORR 04-1533 2/16/05 B 3.3.1-43 20 ORR 04-1533 2/16/05 B 3.3.1-44 20 ORR 04-1533 2/16/05 B 3.3.1-45 20 ORR 04-1533 2/16/05 B 3.3.1-46 48 ORR 10-3740 12/28/10 B 3.3.1-47 20 ORR 04-1533 2/16/05 B 3.3.1-48 48 ORR 10-3740 12/28/10 B 3.3.1-49 20 ORR 04-1533 2/16/05 B 3.3.1-50 20 ORR 04-1533 2/16/05 B 3.3.1-51 21 ORR 05-0707 4/20/05 B 3.3.1-52 20 ORR 04-1533 2/16/05 B 3.3.1-53 20 ORR 04-1533 2/16/05 B 3.3.1-54 20 ORR 04-1533 2/16/05 B 3.3.1-55 25 ORR 06-0800 5/18/06 B 3.3.1-56 66 ORR 14-2329 11/6/14 B 3.3.1-57 20 ORR 04-1533 2/16/05 B 3.3.1-58 29 ORR 06-1984 10/17/06 B 3.3.1-59 20 ORR 04-1533 2/16/05 B 3.3.2-1 0 Amend. No. 123 12/18/99 B 3.3.2-2 0 Amend. No. 123 12/18/99 B 3.3.2-3 0 Amend. No. 123 12/18/99 B 3.3.2-4 0 Amend. No. 123 12/18/99 B 3.3.2-5 0 Amend. No. 123 12/18/99 B 3.3.2-6 7 ORR 01-0474 5/1/01 B 3.3.2-7 0 Amend. No. 123 12/18/99 B 3.3.2-8 0 Amend. No. 123 12/18/99 B 3.3.2-9 0 r Amend. No. 123 12/18/99 B 3.3.2-10 0 Amend. No. 123 12/18/99 B 3.3.2-11 0 Amend. No. 123 12/18/99 B 3.3.2-12 0 Amend. No. 123 12/18/99 B 3.3.2-13 0 Amend. No. 123 12/18/99 B 3.3.2-14 2 ORR 00-0147 4/24/00 B 3.3.2-15 0 Amend. No. 123 12/18/99 B 3.3.2-16 0 Amend. No. 123 12/18/99 B 3.3.2-17 0 Amend. No. 123 12/18/99 B 3.3.2-18 0 Amend. No. 123 12/18/99 B 3.3.2-19 37 ORR 08-0503 4/8/08 B 3.3.2-20 37 ORR 08-0503 4/8/08 B 3.3.2-21 37 ORR 08-0503 4/8/08 B 3.3.2-22 37 ORR 08-0503 4/8/08 B 3.3.2-23 37 ORR 08-0503 4/8/08 B 3.3.2-24 39 ORR 08-1096 8/28/08 B 3.3.2-25 39 ORR 08-1096 8/28/08 B 3.3.2-26 39 ORR 08-1096 8/28/08 B 3.3.2-27 37 ORR 08-0503 4/8/08 B 3.3.2-28 37 ORR 08-0503 4/8/08 B 3.3.2-29 0 Amend. No. 123 12/18/99 B 3.3.2-30 0 Amend. No. 123 12/18/99 B 3.3.2-31 52 ORR 11-0724 4/11 /11 Wolf Creek - Unit 1 iv Revision SO

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE<1> REVISION NO. <2> CHANGE DOCUMENT <3> DATE EFFECTIVE/

IMPLEMENTED <4>

TAB - B 3.3 INSTRUMENTATION (continued)

B 3.3.2-32 52 DRR 11-0724 4/11/11 B 3.3.2-33 0 Amend. No. 123 12/18/99 B 3.3.2-34 0 Amend. No. 123 12/18/99 B 3.3.2-35 20 ORR 04-1533 2/16/05 B 3.3.2-36 20 ORR 04-1533 2/16/05 B 3.3.2-37 20 DRR 04-1533 2/16/05 B 3.3.2-38 20 ORR 04-1533 2/16/05 B 3.3.2-39 25 ORR 06-0800 5/18/06 B 3.3.2-40 20 DRR 04-1533 2/16/05 B 3.3.2-41 45 Amend. No. 187 (ETS) 3/5/10 B 3.3.2-42 45 Amend. No. 187 (ETS) 3/5/10 B 3.3.2-43 20 ORR 04-1533 2/16/05 B 3.3.2-44 20 ORR 04-1533 2/16/05 B 3.3.2-45 20 ORR 04-1533 2/16/05 B 3.3.2-46 54 ORR 11-2394 11/16/11 B 3.3.2-47 43 ORR 09-1416 9/2/09 B 3.3.2-48 37 ORR 08-0503 4/8/08 B 3.3.2-49 20 DRR 04-1533 2/16/05 B 3.3.2-50 20 ORR 04-1533 2/16/05 B 3.3.2-51 43 ORR 09-1416 9/2/09 B 3.3.2-52 43 DRR 09-1416 9/2/09 B 3.3.2-53 43 ORR 09-1416 9/2/09 B 3.3.2-54 43 ORR 09-1416 9/2/09 B 3.3.2-55 43 ORR 09-1416 9/2/09 B 3.3.2-56 43 ORR 09-1416 9/2/09 B 3.3.2-57 43 ORR 09-1416 9/2/09 B 3.3.3-1 0 Amend. No. 123 12/18/99 B3.3.3~ 5 DRR 00-1427 10/12/00 B 3.3.3-3 0 Amend. No. 123 12/18/99 B 3.3.3-4 0 , Amend. No. 123 12/18/99 B 3.3.3-5 0 Amend. No. 123 12/18/99 B 3.3.3-6 8 DRR 01-1235 9/19/01 B 3.3.3-7 21 ORR 05-0707 4/20/05 B 3.3.3-8 8 DRR 01-1235 9/19/01 B 3.3.3-9 8 ORR 01-1235 9/19/01 B 3.3.3-10 19 ORR 04-1414 10/12/04 B3.3.3-11 19 ORR 04-1414 10/12/04 B 3.3.3-12 21 ORR 05-0707 4/20/05

, B3.3.3-13 21 ORR 05-0707 4/20/05 B 3.3.3-14 8 ORR 01-1235 9/19/01 B3.3.3-15 8 DRR 01-1235 9/19/01 B 3.3.4-1 0 Amend. No. 123 12/18/99 B 3.3.4-2 9 ORR 02-1023 2/28/02 B 3.3.4-3 15 ORR 03-0860 7/10/03 B 3.3.4-4 19 ORR 04-1414 10/12/04 B 3.3.4-5 1 ORR 99-1624 12/18/99 B 3.3.4-6 9 DRR 02-0123 2/28/02 B 3.3.5-1 0 Amend. No. 123 12/18/99 B 3.3.5-2 1 ORR 99-1624 12/18/99 B 3.3.5-3 1 ORR 99-1624 12/18/99 Wolf Creek - Unit 1 V Revision80

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE<1> REVISION NO. <2> CHANGE DOCUMENT <3> DATE EFFECTIVE/

4 IMPLEMENTED <>

TAB- B 3.3 INSTRUMENTATION (continued)

B 3.3.5-4 1 ORR 99-1624 12/18/99 B 3.3.5-5 0 Amend. No. 123 12/18/99 B 3.3.5-6 22 ORR 05-1375 6/28/05 B 3.3.5-7 22 ORR 05-1375 6/28/05 B 3.3.6-1 0 Amend. No. 123 12/18/99 B 3.3.6-2 0 Amend. No. 123 12/18/99 B 3.3.6-3 0 Amend. No. 123 12/18/99 B 3.3.6-4 0 Amend. No. 123 12/18/99 B 3.3.6-5 0 Amend. No. 123 12/18/99 B 3.3.6-6 0 Amend. No. 123 12/18/99 B 3.3.6-7 0 Amend. No. 123 12/18/99 B 3.3.7-1 0 Amend. No. 123 12/18/99 B 3.3.7-2 57 ORR 13-0006 1/16/13 B 3.3.7-3 57 ORR 13-0006 1/16/13 B 3.3.7-4 0 Amend. No. 123 12/18/99 B 3.3.7-5 0 Amend. No. 123 12/18/99 B 3.3.7-6 57 ORR 13-0006 1/16/13 B 3.3.7-7 0 Amend. No. 123 12/18/99 B 3.3.7-8 0 Amend. No. 123 12/18/99 B 3.3.8-1 0 ,-

,, Amend. No. 123 12/18/99 B 3.3.8-2 0 Amend. No. 123 12/18/99 B 3.3.8-3 57 ORR 13-0006 1/16/13 B 3.3.8-4 57 ORR 13-0006 1/16/13 B 3.3.8-5 0 Amend. No. 123 12/18/99 B 3.3.8-6 24 ORR 06-0051 2/28/06 B 3.3.8-7 0 Amend. No. 123 12/18/99 TAB- B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.1-1 0 Amend. No. 123 12/18/99 B3.4.1-2 10 ORR 02-0411 4/5/02 B3.4.1-3 10 ORR 02-0411 4/5/02 B 3.4.1-4 0 Amend. No. 123 12/18/99 B 3.4.1-5 0 Amend. No. 123 12/18/99 B 3.4.1-6 0 Amend. No. 123 12/18/99 B 3.4.2-1 0 Amend. No. 123 12/18/99 B 3.4.2-2 0 Amend. No. 123 12/18/99 B 3.4.2-3 0 Amend. No. 123 12/18/99 B 3.4.3-1 67 ORR 15-0116 2/10/15 B 3.4.3-2 0 Amend. No. 123 12/18/99 B 3.4.3-3 0 Amend. No. 123 12/18/99 B 3.4.3-4 0 Amend. No. 123 12/18/99 B 3.4.3-5 0 Amend. No. 123 12/18/99 B 3.4.3-6 0 Amend. No. 123 12/18/99 B 3.4.3-7 0 Amend. No. 123 12/18/99 B 3.4.4-1 0 Amend. No. 123 12/18/99 B 3.4.4-2 29 ORR 06-1984 10/17/06 B 3.4.4-3 0 Amend. No. 123 12/18/99 B 3.4.5-1 0 Amend. No. 123 12/18/99 B 3.4.5-2 53 ORR 11-1513 7/18/11 B 3.4.5-3 29 ORR 06-1984 10/17/06 B 3.4.5-4 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 vi Revision80

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IMPLEMENTED <4>

TAB- B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued)

B 3.4.5-5 12 DRR 02-1062 9/26/02 B 3.4.5-6 12 ORR 02-1062 9/26/02 B 3.4.6-1 53 DRR 11-1513 7/18/11 B 3.4.6-2 72 ORR 15-1918 10/26/15 B 3.4.6-3 12 DRR 02-1062 9/26/02 B 3.4.6-4 72 DRR 15-1918 10/26/15 B 3.4.6-5 75 DRR 16-1909 10/26/16 B 3.4.6-6 75 DRR 16-1909 10/26/16 B 3.4.7-1 12 DRR 02-1062 9/26/02 B 3.4.7-2 17 DRR 04-0453 5/26/04 B 3.4.7-3 72 DRR 15-1918 10/26/15 B 3.4.7-4 42 DRR 09-1009 7/16/09 B 3.4.7-5 72 ORR 15-1918 10/26/15 B3.4.7-6 75 DRR16-1909 10/26/16 B 3.4.8-1 53 ORR 11-1513 7/18/11 B 3.4.8-2 72 DRR 15-1918 10/26/15 B 3.4.8-3 42 ORR 09-1009 7/16/09 B 3.4.8-4 75 DRR 16-1909 10/26/16 B 3.4.8-5 72 DRR 15-1918 10/26/15 B 3.4.9-1 0 Amend. No. 123 12/18/99 B 3.4.9-2 0 Amend. No. 123 12/18/99 B 3.4.9-3 0 Amend. No. 123 12/18/99 B 3.4.9-4 0 Amend. No. 123 12/18/99 B 3.4.10-1 5 ORR 00-1427 10/12/00 B 3.4.10-2 5 DRR 00-1427 10/12iOO B 3.4.10-3 0 Amend. No. 123 12/18/99 B 3.4.10-4 32 DRR 07-0139 2/7/07 B 3.4.11-1 0 Amend. No. 123 12/18/99 B 3.4.11-2 1 DRR 99-1624 12/18/99 B3.4.11-3 19 DRR04-1414 10/12/04 B 3.4.11-4 0 Amend. No. 123 12/18/99 B3.4.11-5 1 DRR99-1624 12/18/99 B 3.4.11-6 0 Amend. No. 123 12/18/99 B 3.4.11-7 32 ORR 07-0139 2/7/07 B 3.4.12-1 61 DRR 14-0346 2/27/14 B 3.4.12-2 61 DRR 14-0346 2/27/14 B 3.4.12-3 0 Amend. No. 123 12/18/99 B 3.4.12-4 61 DRR 14-0346 2/27/14 B 3.4.12-5 61 DRR 14-0346 2/27/14 B 3.4.12-6 56 DRR 12-1792 11/7/12 B 3.4.12-7 61 DRR 14-0346 2/27/14 B 3.4.12-8 1 DRR 99-1624 12/18/99 B 3.4.12-9 56 DRR 12-1792 11/7/12 B 3.4.12-10 0 Amend. No. 123 12/18/99 B 3.4.12-11 61 DRR 14-0346 2/27/14 B3.4.12-12 32 DRR07-0139 2/7/07 B 3.4.12-13 0 Amend. No. 123 12/18/99 83.4.12-14 32 DRR07-0139 2/7/07 B 3.4.13-1 0 Amend. No. 123 12/18/99 B 3.4.13-2 29 DRR 06-1984 10/17/06 B 3.4.13-3 29 ORR 06-1984 10/17/06 Wolf Creek - Unit 1 vii Revision SO

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IMPLEMENTED (4>

TAB- B 3.4 REACTOR COOLANT SYSTEM {RCS} {continued}

B 3.4.13-4 35 ORR 07-1553 9/28/07 B 3.4.13-5 35 ORR 07-1553 9/28/07 B 3.4.13-6 29 ORR 06-1984 10/17/06 B 3.4.14-1 0 Amend. No. 123 12/18/99 B 3.4.14-2 0 Amend. No. 123 12/18/99 B 3.4.14-3 0 Amend. No. 123 12/18/99 B 3.4.14-4 0 Amend. No. 123 12/18/99 B 3.4.14-5 32 ORR 07-0139 217107 B 3.4.14-6 32 ORR 07-0139 2/7/07 B 3.4.15-1 31 ORR 06-2494 12/13/06 B 3.4.15-2 31 ORR 06-2494 12/13/06 B 3.4.15-3 33 ORR 07-0656 5/1/07 B 3.4.15-4 33 ORR 07-0656 5/1/07 B 3.4.15-5 65 ORR 14-2146 9/30/14 B 3.4.15-6 31 ORR 06-2494 12/13/06 B 3.4.15-7 31 ORR 06-2494 12/13/06 B 3.4.15-8 31 ORR 06-2494 12/13/06 B 3.4.16-1 31 ORR 06-2494 12/13/06 B 3.4.16-2 31 ORR 06-2494 12/31/06 B 3.4.16-3 31 ORR 06-2494 12/13/06 B 3.4.16-4 31 ORR 06-2494 12/13/06

'B 3.4.16-5 31 ORR 06-2494 12/13/06 B 3.4.17-1 29 ORR 06-1984 10/17/06 B 3.4.17-2 58 ORR 13-0369 02/26/13 B 3.4.17-3 52 ORR 11-0724 4/11/11 83.4.17-4 57 ORR 13-0006 1/16/13 83.4.17-5 57 ORR 13-0006 1/16/13 B 3.4.17-6 57 ORR 13-0006 1/16/13 83.4.17-7 58 ORR 13-0369 02/26/13 TAB - B 3.5 EMERGENCY CORE COOLING SYSTEMS {ECCS}

B 3.5.1-1 0 Amend. No. 123 12/18/99 B 3.5.1-2 0 Amend. No. 123 12/18/99 B 3.5.1-3 73 ORR 15-2135 11/17/15 B 3.5.1-4 73 ORR 15-2135 11/17/15 B 3.5.1-5 1 ORR 99-1624 12/18/99 B 3.5.1-6 1 ORR 99-1624 12/18/99 B 3.5.1-7 71 ORR 15-1528 7/30/15 B 3.5.1-8 1 ORR 99-1624 12/18/99 B 3.5.2-1 0 Amend. No. 123 12/18/99 B 3.5.2-2 0 Amend. No. 123 12/18/99 B 3.5.2-3 0 Amend. No. 123 12/18/99 B 3.5.2-4 0 Amend. No. 123 12/18/99 B 3.5.2-5 72 ORR 15-1918 10/26/15 B 3.5.2-6 42 ORR 09-1009 7/16/09 B 3.5.2-7 42 ORR 09-1009 7/16/09 B 3.5.2-8 72 ORR 15-1918 10/26/15 B 3.5.2-9 75 ORR 16-1909 10/26/16 B 3.5.2-10 80 ORR 19-0524 5/30/19 B 3.5.2-11 72 ORR 15-1918 10/26/15 B 3.5.2-12 72 ORR 15-1918 10/26/15 Wolf Creek - Unit 1 viii Revision SO

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IMPLEMENTED <4l TAB- B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) (continued)

B 3.5.3-1 56 DRR 12-1792 11/7/12 B 3.5.3-2 72 DRR 15-1918 10/26/15 B 3.5.3-3 56 DRR 12-1792 11/7/12 B 3.5.3-4 56 DRR 12-1792 11/7/12 B 3.5.4-1 0 Amend. No. 123 12/18/99 B 3.5.4-2 0 Amend. No. 123 12/18/99 B 3.5.4-3 0 Amend. No. 123 12/18/99 B 3.5.4-4 0 Amend. No. 123 12/18/99 B 3.5.4-5 0 Amend. No. 123 12/18/99 B 3.5.4-6 26 DRR 06-1350 7/24/06 B 3.5.5-1 21 DRR 05-0707 4/20/05 B 3.5.5-2 21 DRR 05-0707 4/20/05 B 3.5.5-3 2 Amend. No. 132 4/24/00 B 3.5.5-4 21 DRR 05-0707 4/20/05 TAB - B 3.6 CONTAINMENT SYSTEMS B3.6.1-1 0 Amend. No. 123 12/18/99 B 3.6.1-2 0 Amend. No. 123 12/18/99 B 3.6.1-3 0 Amend. No. 123 12/18/99 B 3.6.1-4 17 DRR 04-0453 5/26/04 B 3.6.2-1 0 Amend. No. 123 12/18/99 B 3.6.2-2 0 Amend. No. 123 12/18/99 B 3.6.2-3 0 Amend. No. 123 12/18/99 B 3.6.2-4 0 Amend. No. 123 12/18/99 B 3.6.2-5 0 Amend. No. 123 12/18/99 B 3.6.2-6 0 Amend. No. 123 12/18/99 B 3.6.2-7 0 Amend. No. 123 12/18/99 B 3.6.3-1 0 Amend. No. 123 12/18/99 B 3.6.3-2 0 Amend. No. 123 12/18/99 B 3.6.3-3 0 Amend. No. 123 12/18/99 B 3.6.3-4 49 DRR 11-0014 1/31/11 B 3.6.3-5 49 DRR 11-0014 1/31/11 B 3.6.3-6 49 DRR 11-0014 1/31/11 B 3.6.3-7 41 DRR 09-0288 3/20/09 B 3.6.3-8 36 DRR 08-0255 3/11/08 B 3.6.3-9 36 DRR 08-0255 3/11/08 B 3.6.3-10 8 DRR 01-1235 9/19/01 B 3.6.3-11 36 DRR 08-0255 3/11/08 B 3.6.3-12 36 ORR 08-0255 3/11/08 B 3.6.3-13 50 ORR 11-0449 3/9/11 B 3.6.3-14 36 DRR 08-0255 3/11/08 B3.6.3-15 39 DRR 08-1096 8/28/08 B 3.6.3-16 39 DRR 08-1096 8/28/08 B 3.6.3-17 36 DRR 08-0255 3/11/08 B 3.6.3-18 36 DRR 08-0255 3/11/08 B 3.6.3-19 36 DRR 08-0255 3/11/08 B 3.6.4-1 39 DRR 08-1096 8/28/08 B 3.6.4-2 0 Amend. No. 123 12/18/99 B 3.6.4-3 0 Amend. No. 123 12/18/99 B 3.6.5-1 0 Amend. No. 123 12/18/99 B 3.6.5-2 37 DRR 08-0503 4/8/08 Wolf Creek - Unit 1 ix Revision BO

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TAB - B 3.6 CONTAINMENT SYSTEMS (continued)

B 3.6.5-3 13 ORR 02-1458 12/03/02 B 3.6.5-4 0 Amend. No. 123 12/18/99 B 3.6.6-1 42 ORR 09-1009 7/16/09 B 3.6.6-2 63 ORR 14-1572 7/1/14 B 3.6.6-3 37 ORR 08-0503 4/8/08 B 3.6.6-4 72 ORR 15-1918 10/26/15 B 3.6.6-5 0 Amend. No. 123 12/18/99 B 3.6.6-6 18 ORR 04-1018 9/1/04 B 3.6.6-7 72 ORR 15-1918 10/26/15 B 3.6.6-8 80 ORR 19-0524 5/30/19 B 3.6.6-9 72 ORR 15-1918 10/26/15 B 3.6.6-10 75 ORR 16-1909 10/26/16 B 3.6.6.11 80 ORR 19-0524 5/30/19 B 3.6.7-1 0 Amend. No. 123 12/18/99 B 3.6.7-2 42 ORR 09-1009 7/16/09 B 3.6.7-3 0 Amend. No. 123 12/18/99 B 3.6.7-4 29 ORR 06-1984 10/17/06 B 3.6.7-5 42 ORR 09-1009 7/16/09 TAB- B 3.7 PLANT SYSTEMS 83.7.1-1 0 Amend. No. 123 12/18/99 83.7.1-2 0 Amend. No. 123 12/18/99 B 3.7.1-3 0 Amend. No. 123 12/18/99 83.7.1-4 0 Amend. No. 123 12/18/99 B 3.7.1-5 32 ORR 07-0139 2/7/07 B 3.7.1-6 32 ORR 07-0139 2/7/07 B 3.7.2-1 44 ORR 09-1744 10/28/09 B 3.7.2-2 44 ORR 09-1744 10/28/09 B 3.7.2-3 44 ORR 09-1744 10/28/09 B 3.7.2-4 44 ORR 09-1744 10/28/09 B 3.7.2-5 44 ORR 09-1744 10/28/09 B 3.7.2-6 44 ORR 09-1744 10/28/09 B 3.7.2-7 44 ORR 09-1744 10/28/09 B 3.7.2-8 44 ORR 09-1744 10/28/09 B 3.7.2-9 44 ORR 09-1744 10/28/09 B 3.7.2-10 44 ORR 09-1744 10/28/09 B3.7.2-11 44 ORR 09-1744 10/28/09 B 3.7.3-1 37 ORR 08-0503 4/8/08 B 3.7.3-2 50 ORR 11-0449 3/9/11 B 3.7.3-3 37 ORR 08-0503 4/8/08 B 3.7.3-4 37 ORR 08-0503 4/8/08 B 3.7.3-5 37 ORR 08-0503 4/8/08 B 3.7.3-6 37 ORR 08-0503 4/8/08 B 3.7.3-7 37 ORR 08-0503 4/8/08 B 3.7.3-8 37 ORR 08-0503 4/8/08 B 3.7.3-9 66 ORR 14-2329 11/6/14 B 3.7.3-10 66 ORR 14-2329 11/6/14 B3.7.3-11 37 ORR 08-0503 4/8/08 B 3.7.4-1 1 ORR 99-1624 12/18/99 B 3.7.4-2 1 ORR 99-1624 12/18/99 B3.7.4-3 19 ORR 04-1414 10/12/04 Wolf Creek - Unit 1 X Revision SO

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TAB - B 3.7 PLANT SYSTEMS (continued)

B 3.7.4-4 19 ORR 04-1414 10/12/04 B 3.7.4-5 1 ORR 99-1624 12/18/99 B 3.7.5-1 54 ORR 11-2394 11/16/11 B 3.7.5-2 54 ORR 11-2394 11/16/11 B 3.7.5-3 0 Amend. No. 123 12/18/99 B 3.7.5-4 76 ORR 17-0343 2/21/17 B 3.7.5-5 76 ORR 17-0343 2/21/17 B 3.7.5-6 76 ORR 17-0343 2/21/17 B 3.7.5-7 76 ORR 17-0343 2/21/17 B 3.7.5-8 76 ORR 17-0343 2/21/17 B 3.7.5-9 76 ORR 17-0343 2/21/17 B 3.7.6-1 0 Amend. No. 123 12/18/99 B 3.7.6-2 0 Amend. No. 123 12/18/99 B 3.7.6-3 0 Amend. No. 123 12/18/99 B 3.7.7-1 0 Amend. No. 123 12/18/99 B 3.7.7-2 0 Amend. No. 123 12/18/99 B 3.7.7-3 0 Amend. No. 123 12/18/99 B 3.7.7-4 1 ORR 99-1624 12/18/99 B 3.7.8-1 0 Amend. No. 123 12/18/99 B 3.7.8-2 0 Amend. No. 123 12/18/99 B 3.7.8-3 0 Amend. No. 123 12/18/99 B 3.7.8-4 0 Amend. No. 123 12/18/99 B 3.7.8-5 0 Amend. No. 123 12/18/99 B 3.7.9-1 3 Amend. No. 134 7/14/00 B 3.7.9-2 3 Amend. No. 134 7/14/00 B 3.7.9-3 3 Amend. No. 134 7/14/00 B 3.7.9-4 3 Amend. No. 134 7/14/00 B 3.7.10-1 64 ORR 14-1822 8/28/14 B 3.7.10-2 41 ORR 09-0288 3/20/09 B 3.7.10-3 41 ORR 09-0288 3/20/09 B 3.7.10-4 41 ORR 09-0288 3/20/09 B 3.7.10-5 57 ORR 13-0006 1/16/13 B 3.7.10-6 57 ORR 13-0006 1/16/13 B3.7.10-7 64 ORR 14-1822 8/28/14 B 3.7.10-8 41 ORR 09-0288 3/20/09 B 3.7.10-9 64 ORR 14-1822 8/28/14 B 3.7.11-1 0 Amend. No. 123 12/18/99 B 3.7.11-2 57 ORR 13-0006 1/16/13 83.7.11-3 63 ORR 14-1572 7/1/14 B3.7.11-4 63 ORR 14-1572 7/1/14 B 3.7.12-1 0 Amend. No. 123 12/18/99 B 3.7.13-1 24 ORR 06-0051 2/28/06 B3.7.13-2 1 ORR 99-1624 12/18/99 B 3.7.13-3 75 ORR 16-1909 7/16/09 B 3.7.13-4 57 ORR 13-0006 1/16/13 B 3.7.13-5 57 ORR 13-0006 1/16/13 B 3.7.13-6 64 ORR 14-1822 8/28/14 B 3.7.13-7 64 ORR 14-1822 8/28/14 B 3.7.13-8 64 ORR 14-1822 8/28/14 B3.7.14-1 0 Amend. No. 123 12/18/99 B 3.7.15-1 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 xi Revision SO

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IMPLEMENTED <4l TAB- B 3.7 PLANT SYSTEMS (continued}

B 3.7.15-2 0 Amend. No. 123 12/18/99 B 3.7.15-3 0 Amend. No. 123 12/18/99 83.7.16-1 5 DRR 00-1427 10/12/00 B 3.7.16-2 23 ORR 05-1995 9/28/05 B 3.7.16-3 5 ORR 00-1427 10/12/00 B 3.7.17-1 7 DRR 01-0474 5/1/01 B 3.7.17-2 7 DRR 01-0474 5/1/01 B 3.7.17-3 5 DRR 00-1427 10/12/00 B 3.7.18-1 0 Amend. No. 123 12/18/99 B 3.7.18-2 0 Amend. No. 123 12/18/99 B 3.7.18-3 0 Amend. No. 123 12/18/99 B 3.7.19-1 44 DRR 09-1744 10/28/09 B 3.7.19-2 54 ORR 11-2394 11/16/11 B 3.7.19-3 54 ORR 11-2394 11/16/11 B 3.7.19-4 61 ORR 14-0346 2/27/14 B 3.7.19-5 61 ORR 14-0346 2/27/14 B 3.7.19-6 54 ORR 11-2394 11/16/11 B 3.7.19-7 54 DRR 11-2394 11/16/11 B 3.7.20-1 79 ORR 18-1579 10/22/18 B 3.7.20-2 79 ORR 18-1579 10/22/18 B 3.7.20-3 79 DRR 18-1579 10/22/18 B 3.7.20-4 79 DRR 18-1579 10/22/18 B 3.7.20-5 79 ORR 18-1579 10/22/18 TAB- B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1-1 54 ORR 11-2394 11/16/11 B 3.8.1-2 0 Amend. No. 123 12/18/99 B 3.8.1-3 75 ORR 16-1909 10/26/16 B 3.8.1-4 71 ORR 15-1528 7/30/15 B 3.8.1-5 59 ORR 13-1524 6/26/13 B 3.8.1-6 25 ORR 06-0800 5/18/06 83.8.1-7 26 DRR 06-1350 7/24/06 B 3.8.1-8 35 ORR 07-1553 9/28/07 B 3.8.1-9 42 ORR 09-1009 7/16/09 B3.8.1-10 39 ORR 08-1096 8/28/08 B 3.8.1-11 36 ORR 08-0255 3/11/08 B 3.8.1-12 75 ORR 16-1909 10/26/16 B 3.8.1-13 47 DRR 10-1089 6/16/10 83.8.1-14 47 ORR 10-1089 6/16/10 B 3.8.1-15 47 ORR 10-1089 6/16/10 83.8.1-16 26 ORR 06-1350 7/24/06 83.8.1-17 26 ORR 06-1350 7/24/06 B 3.8.1-18 59 ORR 13-1524 6/26/13 B 3.8.1-19 26 DRR 06-1350 7/24/06 B 3.8.1-20 26 ORR 06-1350 7/24/06 B 3.8.1-21 33 DRR 07-0656 5/1/07 B 3.8.1-22 33 DRR 07-0656 5/1/07 B 3.8.1-23 74 ORR 16-1182 7/7/16 B 3.8.1-24 74 ORR 16-1182 7/7/16 B 3.8.1-25 74 ORR 16-1182 7/7/16 B 3.8.1-26 74 ORR 16-1182 7/7/16 Wolf Creek - Unit 1 xii Revision SO

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IMPLEMENTED <4l TAB- B 3.8 ELECTRICAL POWER SYSTEMS (continued)

B3.8.1-27 74 ORR 16-1182 7/7/16 B3.8.1-28 74 DRR16-1182 7/7/16 B 3.8.1-29 74 ORR 16-1182 7/7/16 B 3.8.1-30 74 ORR 16-1182 7/7/16 B 3.8.1-31 74 ORR 16-1182 7/7/16 B 3.8.1-32 74 ORR 16-1182 7/7/16 B 3.8.1-33 74 ORR 16-1182 7/7/16 B 3.8.1-34 74 ORR 16-1182 7/7/16 B 3.8.2-1 57 ORR 13-0006 1/16/13 B 3.8.2-2 0 Amend. No. 123 12/18/99 B 3.8.2-3 80 ORR 19-0524 5/30/19 B 3.8.2-4 57 ORR 13-0006 1/16/13 B 3.8.2-5 57 ORR 13-0006 1/16/13 B 3.8.2-6 57 ORR 13-0006 1/16/13 B 3.8.2-7 57 ORR 13-0006 1/16/13 B 3.8.3-1 1 ORR 99-1624 12/18/99 B 3.8.3-2 0 Amend. No. 123 12/18/99 B 3.8.3-3 O Amend. No. 123 12/18/99 B 3.8.3-4 1 ORR 99-1624 12/18/99 B 3.8.3-5 0 Amend. No. 123 12/18/99 B 3.8.3-6 0 Amend. No. 123 12/18/99 B 3.8.3-7 12 ORR 02-1062 9/26/02 B 3.8.3-8 1 ORR 99-1624 12/18/99 B 3.8.3-9 0 Amend. No. 123 12/18/99 B 3.8.4-1 0 Amend. No. 123 12/18/99 B 3.8.4-2 0 Amend. No. 123 12/18/99 B 3.8.4-3 0 Amend. No. 123 12/18/99 B 3.8.4-4 0 Amend. No. 123 12/18/99 B3.8.4-5 50 DRR11-0449 3/9/11 B 3.8.4-6 50 ORR 11-0449 3/9/11 B 3.8.4-7 6 ORR 00-1541 3/13/01 B 3.8.4-8 0 Amend. No. 123 12/18/99 B 3.8.4-9 2 ORR 00-0147 4/24/00 B 3.8.5-1 57 ORR 13-0006 1/16/13 B 3.8.5-2 0 Amend. No. 123 12/18/99 B 3.8.5-3 57 ORR 13-0006 1/16/13 B 3.8.5-4 57 ORR 13-0006 1/16/13 B 3.8.5-5 57 ORR 13-0006 1/16/13 B 3.8.6-1 0 Amend. No. 123 12/18/99 B 3.8.6-2 0 Amend. No. 123 12/18/99 B 3.8.6-3 0 Amend. No. 123 12/18/99 B 3.8.6-4 0 Amend. No. 123 12/18/99 B 3.8.6-5 0 Amend. No. 123 12/18/99 B 3.8.6-6 0 Amend. No. 123 12/18/99 B 3.8. 7-1 69 ORR 15-0493 3/26/15 B 3.8.7-2 69 ORR 15-0493 3/26/15 B 3.8.7-3 69 ORR 15-0493 3/26/15 B 3.8.7-4 0 Amend. No. 123 12/18/99 B 3.8.8-1 57 ORR 13-0006 1/16/13 B 3.8.8-2 0 Amend. No. 123 12/18/99 B 3.8.8-3 69 ORR 15-0493 3/26/15 Wolf Creek - Unit 1 xiii Revision SO

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TAB- B 3.8 ELECTRICAL POWER SYSTEMS (continued)

B 3.8.8-4 57 DRR 13-0006 1/16/13 B 3.8.8-5 69 DRR 15-0493 3/26/15 B 3.8.9-1 54 DRR 11-2394 11/16/11 B 3.8.9-2 69 DRR 15-0493 3/26/15 B 3.8.9-3 54 DRR 11-2394 11/16/11 B 3.8.9-4 0 Amend. No. 123 12/18/99 B 3.8.9-5 69 DRR 15-0493 3/26/15 B 3.8.9-6 0 Amend. No. 123 12/18/99 B 3.8.9-7 O Amend. No. 123 12/18/99 B 3.8.9-8 1 DRR 99-1624 12/18/99 B 3.8.9-9 0 Amend. No. 123 12/18/99 B 3.8.10-1 57 DRR 13-0006 1/16/13 B 3.8.10-2 0 Amend. No. 123 12/18/99 B 3.8.10-3 0 Amend. No. 123 12/18/99 B 3.8.10-4 57 DRR 13-0006 1/16/13 B 3.8.10-5 57 DRR 13-0006 1/16/13 B 3.8.10-6 57 DRR 13-0006 1/16/13 TAB- B 3.9 REFUELING OPERATIONS B 3.9.1-1 0 Amend. No. 123 12/18/99 B 3.9.1-2 19 DRR 04-1414 10/12/04 B 3.9.1-3 19 DRR 04-1414 10/12/04 B 3.9.1-4 19 DRR 04-1414 10/12/04 B 3.9.2-1 0 Amend. No. 123 12/18/99 B 3.9.2-2 0 Amend. No. 123 12/18/99 B 3.9.2-3 0 Amend. No. 123 12/18/99 B 3.9.3-1 68 DRR 15-0248 2/26/15 B 3.9.3-2 68 DRR 15-0248 2/26/15 B 3.9.3-3 51 DRR 11-0664 3/21/11 B 3.9.3-4 68 DRR 15-0248 2/26/15 B 3.9.4-1 23 DRR 05-1995 9/28/05 B 3.9.4-2 13 DRR 02-1458 12/03/02 B 3.9.4-3 25 DRR 06-0800 5/18/06 B 3.9.4-4 23 DRR 05-1995 9/28/05 B 3.9.4-5 33 DRR 07-0656 5/1/07 B 3.9.4-6 23 DRR 05-1995 9/28/05 B 3.9.5-1 0 Amend. No. 123 12/18/99 B 3.9.5-2 72 DRR 15-1918 10/26/15 B 3.9.5-3 32 DRR 07-0139 217107 B 3.9.5-4 75 DRR 16-1909 10/26/16 B 3.9.5-5 75 DRR 16-1909 10/26/16 B 3.9.6-1 0 Amend. No. 123 12/18/99 B 3.9.6-2 72 DRR 15-1918 10/26/15 B 3.9.6-3 42 DRR 09-1009 7/16/09 B 3.9.6-4 72 DRR 15-1918 10/26/15 B 3.9.6-5 75 DRR 16-1909 10/26/16 B 3.9.7-1 25 DRR 06-0800 5/18/06 B 3.9.7-2 0 Amend. No. 123 12/18/99 B 3.9.7-3 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 xiv Revision SO

LIST OF EFFECTIVE PAGES - TECHNICAL SPECIFICATION BASES PAGE<1> REVISION NO. <2> CHANGE DOCUMENT <>

3 DATE EFFECTIVE/

4 IMPLEMENTED <>

Note 1 The page number is listed on the center of the bottom of each page.

Note 2 The revision number is listed in the lower right hand corner of each page. The Revision number will be page specific.

Note 3 The change document will be the document requesting the change. Amendment No.

123 issued the improved Technical Specifications and associated Bases which affected each page. The NRG has indicated that Bases changes will not be issued with License Amendments. Therefore, the change document should be a ORR number in accordance with AP 26A-002.

Note 4 The date effective or implemented is the date the Bases pages are issued by Document Control.

Wolf Creek - Unit 1 xv Revision SO

ECCS - Operating B 3.5.2 BASES SURVEILLANCE SR 3.5.2.4 REQUIREMENTS (continued) 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 Code. This type of testing may be accomplished by measuring the pump developed head at only one point of the pump characteristic curve. The following ECCS pumps are required to develop the indicated differential pressure on recirculation flow:

Centrifugal Charging Pump ~ 2490 psid Safety Injection Pump ~ 1453.8 psid RHR Pump ~ 183.6 psid 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 applicable portions of the lnservice Testing Program, which encompasses the ASME Code. The ASME Code provides the activities and Frequencies necessary to satisfy the requirements.

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 on an actual or simulated RWST Level Low-Low 1 Automatic Transfer signal coincident with an 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 lnservice Testing Program.

Wolf Creek - Unit 1 B 3.5.2-10 Revision 80

Containment Spray and Cooling Systems B 3.6.6 BASES SURVEILLANCE SR 3.6.6.4 REQUIREMENTS (continued) Verifying 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 pressure are normal tests of centrifugal pump performance required by the ASME Code (Ref. 5). Since the containment spray pumps cannot be tested with flow through the spray headers, they are tested 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 abnormal performance. The Frequency of the SR is in accordance with the lnservice Testing Program.

This test ensures that each pump develops a differential pressure of greater than or equal to 209 psid at a nominal flow of 300 gpm when on recirculation (Ref. 6).

SR 3.6.6.5 and SR 3.6.6.6 These SRs require verification that each automatic containment spray valve actuates to its correct position and that each containment spray pump starts upon receipt of an actual or simulated actuation of a containment High-3 pressure 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 that 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 3.5.2.5. A single surveillance may be used to satisfy both requirements.

SR 3.6.6.7 This SR requires verification that each containment cooling train actuates upon receipt of an actual or simulated safety injection signal. Upon actuation, each fan in the train starts in slow speed or, if operating, shifts to slow speed and the cooling water flow rate increases to ;::,: 2000 gpm to each cooler train. The 18 month Frequency is based on engineering judgment and has been shown to be acceptable through operating experience. See SR 3.6.6.5 and SR 3.6.6.6, above, for further discussion of the basis for the 18 month Frequency.

Wolf Creek - Unit 1 B 3.6.6-8 Revision 80

Containment Spray and Cooling Systems B 3.

6.6 REFERENCES

1. 10 CFR 50, Appendix A, GDC 38, GDC 39, GDC 40, GDC 41. GDC 42, and GDC 43, and GDC 50.

2. 10 CFR 50, Appendix K.

3. USAR, Section 6.2.1.

4. USAR, Section 6.2.2.

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

6. Calculation EN-M-026.

Wolf Creek - Unit 1 B 3.6.6-11 Revision 80

AC Sources - Shutdown B 3.8.2 BASES APPLICABLE The AC sources satisfy Criterion 3 of the 10 CFR 50.36(c)(2)(ii).

SAFETY ANALYSES (continued)

LCO One offsite circuit capable of supplying the onsite Class 1E power distribution subsystem of LCO 3.8.10, "Distribution Systems - Shutdown,"

ensures that one train of required loads are powered from offsite power.

An OPERABLE DG, associated with the distribution system train required to be OPERABLE by LCO 3.8.10, ensures a diverse power source is available to provide electrical power support, assuming a loss of the offsite circuit. Together, OPERABILITY of the required offsite circuit and DG ensures the availability of sufficient AC sources to operate the unit in a safe manner and to mitigate the consequences of postulated events during shutdown (e.g., fuel handling accidents).

The DG must be supporting the train of AC electrical distribution required to be OPERABLE per LCO 3.8.10. The offsite circuit must also support the train of AC electrical distribution required to be OPERABLE per LCO 3.8.10. When the second AC electrical power distribution train (subsystem) is needed to support redundant required systems, equipment and components, the second train may be energized from any available source. The available source must be Class 1E or another reliable source. The available source must be capable of supplying sufficient AC electrical power such that the redundant components are capable of performing their specified safety function(s) (implicitly required by the definition of OPERABILITY). Otherwise, the supported components must be declared inoperable and the appropriate conditions of the LCOs for the redundant components must be entered.

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

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

One offsite circuit consists of the #7 transformer feeding through the 13-48 breaker power the ESF transformer XNB01, which, in turn powers the NB01 bus through its normal feeder breaker. Transformer XNB01 may also be powered from the SL-7 supply through the 13-8 breaker provided that no offsite load is connected to the 69 KV system. Another offsite circuit consists of the startup transformer feeding through breaker PA201 powering the ESF transformer XNB02, which, in turn powers the NB02 bus through its normal feeder breaker.

Wolf Creek - Unit 1 B 3.8.2-3 Revision 80

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TAB - Title Page Technical Specification Cover Page Title Page TAB - Table of Contents 34 ORR 07-1057 7/10/07 ii 29 ORR 06-1984 10/17/06 iii 44 ORR 09-1744 10/28/09 TAB - B 2.0 SAFETY LIMITS (SLs)

B 2.1.1-1 0 Amend. No. 123 12/18/99 B 2.1.1-2 14 ORR 03-0102 2/12/03 B 2.1.1-3 14 ORR 03-0102 2/12/03 B 2.1.1-4 0 Amend. No. 123 2/12/03 B 2.1.2-1 81 ORR 19-1027 10/28/19 B 2.1.2-2 12 ORR 02-1062 9/26/02 B 2.1.2-3 81 ORR 19-1027 10/28/19 TAB - B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABIL TY B 3.0-1 81 DRR1~1~7 10/28/19 B 3.0-2 0 Amend. No. 123 12/18/99 B 3.0-3 81 DRR1~1~7 10/28/19 B 3.0-4 81

ORR 19-1027 10/28/19 B 3.0-5 81 DRR1~1~7 10/28/19 B 3.0-6 81 DRR1~1~7 10/28/19 B 3.0-7 81 DRR1~1~7 10/28/19 B 3.0-8 81 ORR 19-1027 10/28/19 B 3.0-9 81 DRR1~1~7 10/28/19 B 3.0-10 81 ORR 19-1027 10/28/19 B 3.0-11 81 DRR1~1~7 10/28/19 B 3.0-12 81 ORR 19-1027 10/28/19 B 3.0-13 81 ORR 19-1027 10/28/19 B 3.0-14 81 ORR 19-1027 10/28/19 B3.0-15 81 ORR 19-1027 10/28/19 B 3.0-16 81 DRR1~1~7 10/28/19 B 3.0-17 81 DRR1~1~7 10/28/19 TAB- B 3.1 REACTIVITY CONTROL SYSTEMS B3.1.1-1 0 Amend. No. 123 12/18/99 B 3.1.1-2 0 Amend. No. 123 12/18/99 B 3.1.1-3 0 Amend. No. 123 12/18/99 B 3.1.1-4 81 ORR 19-1027 10/28/19 B 3.1.1-5 81 ORR 19-1027 10/28/19 B 3.1.2-1 0 Amend. No. 123 12/18/99 B 3.1.2-2 0 Amend. No. 123 12/18/99 B 3.1.2-3 0 Amend. No. 123 12/18/99 B 3.1.2-4 0 Amend. No. 123 12/18/99 B 3.1.2-5 0 Amend. No. 123 12/18/99 B 3.1.3-1 0 Amend. No. 123 12/18/99 B 3.1.3-2 0 Amend. No. 123 12/18/99 B 3.1.3-3 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 i l Revision81

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B 3.1.3-4 0 Amend. No. 123 12/18/99 B 3.1.3-5 0 Amend. No. 123 12/18/99 B 3.1.3-6 0 Amend. No. 123 12/18/99 B 3.1.4-1 0 Amend. No. 123 12/18/99 B 3.1.4-2 0 Amend. No. 123 12/18/99 B 3.1 .4-3 48 ORR 10-3740 12/28/10 B 3.1.4-4 0 Amend. No. 123 12/18/99 B 3.1.4-5 0 Amend. No. 123 12/18/99 B3.1.4-6 48 DRR10-3740 12/28/10 B3.1.4-7 O Amend.No.123 12/18/99 B 3.1.4-8 0 Amend. No. 123 12/18/99 B 3.1.4-9 0 Amend. No. 123 12/18/99 B 3.1.5-1 0 Amend. No. 123 12/18/99 B 3.1.5-2 0 Amend. No. 123 12/18/99 B 3.1.5-3 O Amend. No. 123 12/18/99 B 3.1.5-4 0 Amend. No. 123 12/18/99 B 3.1.6-1 0 Amend. No. 123 12/18/99 B 3.1.6-2 0 Amend. No. 123 12/18/99 B 3.1.6-3 0 Amend. No. 123 12/18/99 B 3.1.6-4 0 Amend. No. 123 12/18/99 B 3.1.6-5 0 Amend. No. 123 12/18/99 B 3.1.6-6 0 Amend. No. 123 12/18/99 B 3.1.7-1 0 Amend. No. 123 12/18/99 B 3.1.7-2 0 Amend. No. 123 12/18/99 B3.1.7-3 48 DRR10-3740 12/28/10 B3.1.7-4 48 DRR10-3740 12/28/10 B3.1.7-5 48 DRR10-3740 12/28/10 B 3.1.7-6 0 Amend. No. 123 12/18/99 B 3.1.8-1 0 Amend. No. 123 12/18/99 B 3.1.8-2 0 Amend. No. 123 12/18/99 B 3.1.8-3 15 ORR 03-0860 7/10/03 H 3.1.8-4 15 ORR 03-0860 7/10/03 B 3.1.8-5 0 Amend. No. 123 12/18/99 B 3.1.8-6 5 ORR 00-1427 10/12/00 B 3.1.9-1 81 ORR 19-1027 10/28/19 B 3.1.9-2 81 ORR 19-1027 10/28/19 B 3.1.9-3 81 ORR 19-1027 10/28/19 B 3.1.9-4 81 ORR 19-1027 10/28/19 TAB - B 3.2 POWER DISTRIBUTION LIMITS B 3.2.1-1 48 ORR 10-3740 12/28/10 B3.2.1~ 0 Amend. No. 123 12/18/99 B 3.2.1-3 48 ORR 10-3740 12/28/10 B 3.2.1-4 48 ORR 10-3740 12/28/10 B3.2.1~ ~ ORR 10-3740 12/28/10 B 3.2.1-6 48 ORR 10-3740 12/28/10 B 3.2.1-7 48 ORR 10-3740 12/28/10 B 3.2.1-8 : 48 ORR 10-3740 12/28/10 B 3.2.1-9 29 ORR 06-1984 10/17/06 B 3.2.1-10 70 ORR 15-0944 4/28/15 B 3.2.2-1 48 ORR 10-3740 12/28/10 Wolf Creek - Unit 1 ii Revision81

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TAB - B 3.2 POWER DISTRIBUTION LIMITS (continued)

B 3.2.2-2 0 Amend. No. 123 12/18/99 B 3.2.2-3 48 ORR 10-3740 12/28/10 B 3.2.2-4 48 ORR 10-3740 12/28/10 B 3.2.2-5 48 DRR 10-3740 12/28/10 B 3.2.2-6 70 DRR 15-0944 4/28/15 B 3.2.3-1 0 Amend. No. 123 12/18/99 B 3.2.3-2 0 Amend. No. 123 12/18/99 B 3.2.3-3 0 Amend. No. 123 12/18/99 B 3.2.4-1 0 Amend. No. 123 12/18/99 B 3.2.4-2 0 Amend. No. 123 12/18/99 B 3.2.4-3 48 DRR 10-3740 12/28/10 B 3.2.4-4 0 Amend. No. 123 12/18/99 B 3.2.4-5 48 ORR 10-3740 12/28/10 B 3.2.4-6 0 Amend. No. 123 12/18/99 B 3.2.4-7 48 ORR 10-3740 12/28/10 TAB- B 3.3 INSTRUMENTATION B 3.3.1-1 81 ORR 19-1027 10/28/19 B 3.3.1-2 0 Amend. No. 123 12/18/99 I I B 3.3.1-3 0 Amend. No. 123 12/18/99 B 3.3.1-4 0 Amend. No. 123 12/18/99 B 3.3.1-5 0 Amend. No. 123 12/18/99 B 3.3.1-6 0 Amend. No. 123 12/18/99 83.3.1-7 5 DRR 00-1427 10/12/00 83.3.1-8 0 Amend. No. 123 12/18/99 B 3.3.1-9 0 Amend. No. 123 12/18/99 B 3.3.1-10 29 ORR 06-1984 10/17/06 B 3.3.1-11 0 Amend. No. 123 12/18/99 B 3.3.1-12 0 Amend. No. 123 12/18/99 B 3.3.1-13 0 Amend. No. 123 12/18/99 B 3.3.1-14 0 Amend. No. 123 12/18/99 B 3.3.1-15 0 Amend. No. 123 12/18/99 B 3.3.1-16 0 Amend. No. 123 12/18/99 B 3.3.1-17 0 Amend. No. 123 12/18/99 B 3.3.1-18 0 Amend. No. 123 12/18/99 83.3.1-19 66 DRR 14-2329 11/6/14 B 3.3.1-20 66 ORR 14-2329 11/6/14 83.3.1-21 0 Amend. No. 123 12/18/99 B 3.3.1-22 0 Amend. No. 123 12/18/99 B 3.3.1-23 9 ORR 02-0123 2/28/02 B 3.3.1-24 78 ORR 18-0443 5/8/18 B 3.3.1-25 78 ORR 18-0443 5/8/18 B 3.3.1-26 78 ORR 18-0443 5/8/18 B 3.3.1-27 78 ORR 18-0443 5/8/18 B 3.3.1-28 2 DRR 00-0147 4/24/00 B 3.3.1-29 1 ORR 99-1624 12/18/99 B 3.3.1-30 1 ORR 99-1624 12/18/99 B 3.3.1-31 0 Amend. No. 123 12/18/99 B 3.3.1-32 20 ORR 04-1533 2/16/05 B 3.3.1-33 48 ORR 10-3740 12/28/10 B 3.3.1-34 20 ORR 04-1533 2/16/05 Wolf Creek - Unit 1 iii Revision81

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B 3.3.1-35 19 ORR 04-1414 10/13/04 B 3.3.1-36 20 ORR 04-1533 2/16/05 B 3.3.1-37 20 ORR 04-1533 2/16/05 B 3.3.1-38 20 ORR 04-1533 2/16/05 B 3.3.1-39 25 ORR 06-0800 5/18/06 B 3.3.1-40 20 ORR 04-1533 2/16/05 B 3.3.1-41 20 ORR 04-1533 2/16/05 B 3.3.1-42 20 ORR 04-1533 2/16/05 B 3.3.1-43 20 ORR 04-1533 2/16/05 B 3.3.1-44 20 ORR 04-1533 2/16/05 B 3.3.1-45 20 ORR 04-1533 2/16/05 B 3.3.1-46 48 ORR 10-3740 12/28/10 B 3.3.1-47 20 ORR 04-1533 2/16/05 B 3.3.1-48 48 ORR 10-3740 12/28/10 B 3.3.1-49 20 ORR 04-1533 2/16/05 B 3.3.1-50 20 ORR 04-1533 2/16/05 B 3.3.1-51 21 ORR 05-0707 4/20/05 B 3.3.1-52 20 ORR 04-1533 2/16/05 B 3.3.1-53 20 ORR 04-1533 2/16/05 B 3.3.1-54 20 ORR 04-1533 2/16/05 B 3.3.1-55 25 ORR 06-0800 5/18/06 B 3.3.1-56 66 ORR 14-2329 11/6/14 B3.3.1-57 20 ORR 04-1533 2/16/05 B 3.3.1-58 29 ORR 06-1984 10/17/06 B 3.3.1-59 20 ORR 04-1533 2/16/05 B 3.3.2-1 0 Amend. No. 123 12/18/99 B 3.3.2-2 0 Amend. No. 123 12/18/99 B 3.3.2-3 0 Amend. No. 123 12/18/99 B 3.3.2-4 0 Amend. No. 123 12/18/99 B 3.3.2-5 0 Amend. No. 123 12/18/99 B 3.3.2-6 7 ORR 01-0474 5/1/01 B 3.3.2-7 0 Amend. No. 123 12/18/99 B 3.3.2-8 0 Amend. No. 123 12/18/99 B 3.3.2-9 0 Amend. No. 123 12/18/99 B 3.3.2-10 0 Amend. No. 123 12/18/99 B 3.3.2-11 0 Amend. No. 123 12/18/99 B 3.3.2-12 81 ORR 19-1027 10/28/19 B 3.3.2-13 0 Amend. No. 123 12/18/99 B 3.3.2-14 2 ORR 00-0147 4/24/00 B 3.3.2-15 0 Amend. No. 123 12/18/99 B 3.3.2-16 0 Amend. No. 123 12/18/99 B 3.3.2-17 0 Amend. No. 123 12/18/99 B 3.3.2-18 0 Amend. No. 123 12/18/99 B 3.3.2-19 37 ORR 08-0503 4/8/08 B 3.3.2-20 37 ORR 08-0503 4/8/08 B 3.3.2-21 37 ORR 08-0503 4/8/08 B 3.3.2-22 37 ORR 08-0503 4/8/08 B 3.3.2-23 37 ORR 08-0503 4/8/08 B 3.3.2-24 39 ORR 08-1096 8/28/08 B 3.3.2-25 39 ORR 08-1096 8/28/08 B 3.3.2-26 39 ORR 08-1096 8/28/08 Wolf Creek - Unit 1 iv Revision81

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TAB - B 3.3 INSTRUMENTATION (continued)

B 3.3.2-27 37 DRR 08-0503 4/8/08 B 3.3.2-28 37 DRR 08-0503 4/8/08 B 3.3.2-29 0 Amend. No. 123 12/18/99 B 3.3.2-30 0 Amend. No. 123 12/18/99 B 3.3.2-31 52 DRR 11-0724 4/11/11 B 3.3.2-32 52 DRR 11-0724 4/11/11 B 3.3.2-33 0 Amend. No. 123 12/18/99 B 3.3.2-34 0 Amend. No. 123 12/18/99 B 3.3.2-35 20 DRR 04-1533 2/16/05 B 3.3.2-36 20 DRR 04-1533 2/16/05 B 3.3.2-37 20 DRR 04-1533 2/16/05 B 3.3.2-38 20 DRR 04-1533 2/16/05 B 3.3.2-39 25 DRR 06-0800 5/18/06 B 3.3.2-40 20 DRR 04-1533 2/16/05 B 3.3.2-41 45 Amend. No. 187 (ETS) 3/5/10 B 3.3.2-42 45 Amend. No. 187 (ETS) 3/5/10 B 3.3.2-43 20 DRR 04-1533 2/16/05 B 3.3.2-44 20 DRR 04-1533 2/16/05 B 3.3.2-45 20 DRR 04-1533 2/16/05 B 3.3.2-46 54 DRR 11-2394 11/16/11 B 3.3.2-47 43 DRR 09-1416 9/2/09 B 3.3.2-48 37 DRR 08-0503 4/8/08 B 3.3.2-49 20 DRR 04-1533 2/16/05 B 3.3.2-50 20 DRR 04-1533 2/16/05 B 3.3.2-51 43 DRR 09-1416 9/2/09 B 3.3.2-52 43 DRR 09-1416 9/2/09 B 3.3.2-53 43 DRR 09-1416 9/2/09 B 3.3.2-54 43 DRR 09-1416 9/2/09 B 3.3.2-55 43 DRR 09-1416 9/2/09 B 3.3.2-56 43 DRR 09-1416 9/2/09 B 3.3.2-57 43 DRR 09-1416 9/2/09 B 3.3.3-1 0 Amend. No. 123 12/18/99 B 3.3.3-2 5 DRR 00-1427 10/12/00 B 3.3.3-3 0 Amend. No. 123 12/18/99 B 3.3.3-4 0 Amend. No. 123 12/18/99 B 3.3.3-5 0 Amend. No. 123 12/18/99 B 3.3.3-6 8 DRR 01-1235 9/19/01 B 3.3.3-7 21 DRR 05-0707 4/20/05 B 3.3.3-8 81 DRR 19-1027 10/28/19 B 3.3.3-9 8 DRR 01-1235 9/19/01 B 3.3.3-10 19 DRR 04-1414 10/12/04 83.3.3-11 19 DRR 04-1414 10/12/04 B 3.3.3-12 21 DRR 05-0707 4/20/05 83.3.3-13 21 DRR 05-0707 4/20/05 B 3.3.3-14 8 DRR 01-1235 9/19/01 83.3.3-15 8 DRR 01-1235 9/19/01 B 3.3.4-1 0 Amend. No. 123 12/18/99 B 3.3.4-2 9 DRR 02-1023 2/28/02 B 3.3.4-3 15 DRR 03-0860 7/10/03 B 3.3.4-4 19 DRR 04-1414 10/12/04 B 3.3.4-5 1 DRR 99-1624 12/18/99 Wolf Creek - Unit 1 V Revision81

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TAB- B 3.3 INSTRUMENTATION (continued)

B 3.3.4-6 9 ORR 02-0123 2/28/02 B 3.3.5-1 0 Amend. No. 123 12/18/99 B 3.3.5-2 1 ORR 99-1624 12/18/99 B 3.3.5-3 1 ORR 99-1624 12/18/99 B 3.3.5-4 1 ORR 99-1624 12/18/99 B 3.3.5-5 0 Amend. No. 123 12/18/99 B 3.3.5-6 22 ORR 05-1375 6/28/05 B 3.3.5-7 22 ORR 05-1375 6/28/05 B 3.3.6-1 81 ORR 19-1027 10/28/19 B 3.3.6-2 81 ORR 19-1027 10/28/19 B 3.3.6-3 0 Amend. No. 123 12/18/99 B 3.3.6-4 0 Amend. No. 123 12/18/99 B 3.3.6-5 0 Amend. No. 123 12/18/99 B 3.3.6-6 0 Amend. No. 123 12/18/99 B 3.3.6-7 81 ORR 19-1027 10/28/19 B 3.3.7-1 81 ORR 19-1027 10/28/19 B 3.3.7-2 81 ORR 19-1027 10/28/19 B 3.3.7-3 57 ORR 13-0006 1/16/13 B 3.3.7-4 0 Amend. No. 123 12/18/99 B 3.3.7-5 0 Amend. No. 123 12/18/99 B 3.3.7-6 57 ORR 13-0006 1/16/13 B 3.3.7-7 0 Amend. No. 123 12/18/99 B 3.3.7-8 81 ORR 19-1027 10/28/19 B 3.3.8-1 81 ORR 19-1027 10/28/19 B 3.3.8-2 0 Amend. No. 123 12/18/99 B 3.3.8-3 57 ORR 13-0006 1/16/13 B 3.3.8-4 57 ORR 13-0006 1/16/13 B 3.3.8-5 0 Amend. No. 123 12/18/99 B 3.3.8-6 24 ORR 06-0051 2/28/06 B 3.3.8-7 81 ORR 19-1027 10/28/19 TAB- B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.1-1 0 Amend. No. 123 12/18/99 B 3.4.1-2 10 ORR 02-0411 4/5/02 B 3.4.1-3 10 ORR 02-0411 4/5/02 B 3.4.1-4 0 Amend. No. 123 12/18/99 B 3.4.1-5 0 Amend. No. 123 12/18/99 83.4.1~ 0 Amend. No. 123 12/18/99 B 3.4.2-1 0 Amend. No. 123 12/18/99 B 3.4.2-2 0 Amend. No. 123 12/18/99 B 3.4.2-3 0 Amend. No. 123 12/18/99 B 3.4.3-1 67 ORR 15-0116 2/10/15 B 3.4.3-2 0 Amend. No. 123 12/18/99 B 3.4.3-3 0 Amend. No. 123 12/18/99 B 3.4.3-4 0 Amend. No. 123 12/18/99 B 3.4.3-5 0 Amend. No. 123 12/18/99 B 3.4.3-6 0 Amend. No. 123 12/18/99 B 3.4.3-7 0 Amend. No. 123 12/18/99 B 3.4.4-1 0 Amend. No. 123 12/18/99 B 3.4.4-2 29 ORR 06-1984 10/17/06 B 3.4.4-3 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 vi Revision81

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TAB - B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued)

B 3.4.5-1 0 Amend. No. 123 12/18/99 B 3.4.5-2 53 ORR 11-1513 7/18/11 B 3.4.5-3 29 ORR 06-1984 10/17/06 B 3.4.5-4 0 Amend. No. 123 12/18/99 B 3.4.5-5 12 ORR 02-1062 9/26/02 B 3.4.5-6 12 ORR 02-1062 9/26/02 B 3.4.6-1 53 ORR 11-1513 7/18/11 B 3.4.6-2 72 ORR 15-1918 10/26/15 B 3.4.6-3 12 ORR 02-1062 9/26/02 B 3.4.6-4 72 ORR 15-1918 10/26/15 B 3.4.6-5 75 ORR 16-1909 10/26/16 B 3.4.6-6 75 ORR 16-1909 10/26/16 B 3.4.7-1 12 ORR 02-1062 9/26/02 B 3.4.7-2 17 ORR 04-0453 5/26/04 B 3.4.7-3 72 ORR 15-1918 10/26/15 B 3.4.7-4 42 ORR 09-1009 7/16/09 B 3.4.7-5 72 ORR 15-1918 10/26/15 B 3.4.7-6 75 ORR 16-1909 10/26/16 B 3.4.8-1 53 ORR 11-1513 7/18/11 B 3.4.8-2 72 ORR 15-1918 10/26/15 B 3.4.8-3 42 ORR 09-1009 7/16/09 B 3.4.8-4 75 ORR 16-1909 10/26/16 B 3.4.8-5 72 ORR 15-1918 10/26/15 B 3.4.9-1 0 Amend. No. 123 12/18/99 B 3.4.9-2 0 Amend. No. 123 12/18/99 B 3.4.9-3 0 Amend. No. 123 12/18/99 B 3.4.9-4 0 Amend. No. 123 12/18/99 B 3.4.10-1 5 ORR 00-1427 10/12/00 B 3.4.10-2 5 ORR 00-1427 10/12/00 B 3.4.10-3 0 Amend. No. 123 12/18/99 B 3.4.10-4 32 ORR 07-0139 2/7/07 B 3.4.11-1 0 Amend. No. 123 12/18/99 B 3.4.11-2 1 ORR 99-1624 12/18/99 B3.4.11-3 19 DRR04-1414 10/12/04 B 3.4.11-4 0 Amend. No. 123 12/18/99 B3.4.11-5 1 DRR99-1624 12/18/99 B 3.4.11-6 0 Amend. No. 123 12/18/99 B3.4.11-7 32 DRR07-0139 2/7/07 B 3.4.12-1 61 ORR 14-0346 2/27/14 B 3.4.12-2 61 ORR 14-0346 2/27/14 B 3.4.12-3 0 Amend. No. 123 12/18/99 B 3.4.12-4 61 ORR 14-0346 2/27/14 B 3.4.12-5 61 ORR 14-0346 2/27/14 B 3.4.12-6 56 ORR 12-1792 11/7/12 B 3.4.12-7 61 ORR 14-0346 2/27/14 B 3.4.12-8 1 ORR 99-1624 12/18/99 B 3.4.12-9 56 ORR 12-1792 11/7/12 B 3.4.12-10 0 Amend. No. 123 12/18/99 B3.4.12-11 61 DRR14-0346 2/27/14 B 3.4.12-12 32 ORR 07-0139 2/7/07 B 3.4.12-13 0 Amend. No. 123 12/18/99 Wolf Creek - Unit 1 vii Revision81

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TAB - B 3.4 REACTOR COOLANT SYSTEM (RCS) (continued)

B 3.4.12-14 32 ORR 07-0139 2/7/07 B 3.4.13-1 0 Amend. No. 123 12/18/99 B 3.4.13-2 81 ORR 19-1027 10/28/19 B 3.4.13-3 29 ORR 06-1984 10/17/06 B 3.4.13-4 35 ORR 07-1553 9/28/07 B 3.4.13-5 35 ORR 07-1553 9/28/07 B 3.4.13-6 81 ORR 19-1027 10/28/19 B3.4.14-1 0 Amend. No. 123 12/18/99 B 3.4.14-2 0 Amend. No. 123 12/18/99 B 3.4.14-3 0 Amend. No. 123 12/18/99 B 3.4.14-4 0 Amend. No. 123 12/18/99 B 3.4.14-5 32 ORR 07-0139 217107 B 3.4.14-6 32 ORR 07-0139 217/07 B3.4.15-1 31 ORR 06-2494 12/13/06 B 3.4.15-2 31 ORR 06-2494 12/13/06 B 3.4.15-3 33 ORR 07-0656 5/1/07 B 3.4.15-4 33 ORR 07-0656 5/1/07 B 3.4.15-5 65 ORR 14-2146 9/30/14 B 3.4.15-6 31 ORR 06-2494 12/13/06 B 3.4.15-7 31 ORR 06-2494 12/13/06 B 3.4.15-8 31 ORR 06-2494 12/13/06 B3.4.16-1 81 ORR 19-1027 10/28/19 B 3.4.16-2 81 ORR 19-1027 10/28/19 B 3.4.16-3 31 ORR 06-2494 12/13/06 B 3.4.16-4 31 ORR 06-2494 12/13/06 B 3.4.16-5 81 ORR 19-1027 10/28/19 B 3.4.17-1 29 ORR 06-1984 10/17/06 B 3.4.17-2 81 ORR 19-1027 10/28/19 B 3.4.17-3 52 ORR 11-0724 4/11/11 B 3.4.17-4 81 ORR 19-1027 10/28/19 B 3.4.17-5 57 ORR 13-0006 1/16/13 B 3.4.17-6 57 ORR 13-0006 1/16/13 B 3.4.17-7 81 ORR 19-1027 10/28/19 TAB - B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS)

B 3.5.1-1 0 Amend. No. 123 12/18/99 B 3.5.1-2 0 Amend. No. 123 12/18/99 B 3.5.1-3 73 ORR 15-2135 11/17/15 B 3.5.1-4 73 ORR 15-2135 11/17/15 B 3.5.1-5 1 ORR 99-1624 12/18/99 B 3.5.1-6 1 ORR 99-1624 12/18/99 B 3.5.1-7 71 ORR 15-1528 7/30/15 B 3.5.1-8 1 ORR 99-1624 12/18/99 B 3.5.2-1 0 Amend. No. 123 12/18/99 B 3.5.2-2 0 Amend. No. 123 12/18/99 B 3.5.2-3 0 Amend. No. 123 12/18/99 B 3.5.2-4 0 Amend. No. 123 12/18/99 B 3.5.2-5 72 ORR 15~1918 10/26/15 B 3.5.2-6 42 ORR 09-1009 7/16/09 B 3.5.2-7 42 ORR 09-1009 7/16/09 B 3.5.2-8 72 ORR 15-1918 10/26/15 Wolf Creek - Unit 1 viii Revision81

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TAB - B 3.5 EMERGENCY CORE COOLING SYSTEMS {ECCS) {continued)

B 3.5.2-9 75 ORR 16-1909 10/26/16 B 3.5.2-10 80 ORR 19-0524 5/30/19 B 3.5.2-11 72 ORR 15-1918 10/26/15 B 3.5.2-12 72 ORR 15-1918 10/26/15 B 3.5.3-1 56 ORR 12-1792 11/7/12 B 3.5.3-2 72 ORR 15-1918 10/26/15 B 3.5.3-3 56 ORR 12-1792 1117/12 B 3.5.3-4 56 ORR 12-1792 1117/12 B 3.5.4-1 0 Amend. No. 123 12/18/99 B 3.5.4-2 0 Amend. No. 123 12/18/99 B 3.5.4-3 0 Amend. No. 123 12/18/99 B 3.5.4-4 0 Amend. No. 123 12/18/99 B 3.5.4-5

0 Amend. No. 123 12/18/99 B 3.5.4-6 26 ORR 06-1350 7/24/06 B 3.5.5-1 21 ORR 05-0707 4/20/05 B 3.5.5-2 21 ORR 05-0707 4/20/05 B 3.5.5-3 2 Amend. No. 132 4/24/00 B 3.5.5-4 21 ORR 05-0707 4/20/05 TAB- B 3.6 CONTAINMENT SYSTEMS B 3.6.1-1 0 Amend. No. 123 12/18/99 B 3.6.1-2 81 ORR 19-1027 10/28/19 B 3.6.1-3 0 Amend. No. 123 12/18/99 B 3.6.1-4 17 ORR 04-0453 5/26/04 B 3.6.2-1 81 ORR 19-1027 10/28/19 B 3.6.2-2 0 Amend. No. 123 12/18/99 B 3.6.2-3 0 Amend. No. 123 12/18/99 B 3.6.2-4 0 Amend. No. 123 12/18/99 B 3.6.2-5 0 Amend. No. 123 12/18/99 B 3.6.2-6 0 Amend. No. 123 12/18/99 B 3.6.2-7 0 Amend. No. 123 12/18/99 B 3.6.3-1 0 Amend. No. 123 12/18/99 B 3.6.3-2 81 ORR 19-1027 10/28/19 B 3.6.3-3 81 ORR 19-1027 10/28/19 B 3.6.3-4 49 ORR 11-0014 1/31/11 B 3.6.3-5 49 ORR 11-0014 1/31/11 B 3.6.3-6 49 ORR 11-0014 1/31/11 B 3.6.3-7 41 ORR 09-0288 3/20/09 B 3.6.3-8 36 ORR 08-0255 3/11/08 B 3.6.3-9 36 ORR 08-0255 3/11/08 B 3.6.3-10 8 ORR 01-1235 9/19/01 B 3.6.3-11 36 ORR 08-0255 3/11/08 B 3.6.3-12 36 ORR 08-0255 3/11/08 B 3.6.3-13 50 ORR 11-0449 3/9/11 B 3.6.3-14 36 ORR 08-0255 3/11/08 B 3.6.3-15 39 ORR 08-1096 8/28/08 B 3.6.3-16 39 ORR 08-1096 8/28/08 B 3.6.3-17 36 ORR 08-0255 3/11/08 B 3.6.3-18 36 ORR 08-0255 3/11/08 B 3.6.3-19 36r ORR 08-0255 3/11/08 B 3.6.4-1 39 ORR 08-1096 8/28/08 Wolf Creek - Unit 1 ix Revision81

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TAB- B 3.6 CONTAINMENT SYSTEMS (continued)

B 3.6.4-2 0 Amend. No. 123 12/18/99 B 3.6.4-3 0 Amend. No. 123 12/18/99 B 3.6.5-1 0 Amend. No. 123 12/18/99 B 3.6.5-2 37 ORR 08-0503 4/8/08 B 3.6.5-3 13 ORR 02-1458 12/03/02 B 3.6.5-4 0 Amend. No. 123 12/18/99 B 3.6.6-1 81 ORR 19-1027 10/28/19 B 3.6.6-2 63 ORR 14-1572 7/1/14 B 3.6.6-3 37 ORR 08-0503 4/8/08 B 3.6.6-4 81 ORR 19-1027 10/28/19 B 3.6.6-5 0 Amend. No. 123 12/18/99 B 3.6.6-6 18 ORR 04-1018 9/1/04 B 3.6.6-7 72 ORR 15-1918 10/26/15 B 3.6.6-8 80 ORR 19-0524 5/30/19 B 3.6.6-9 72 ORR 15-1918 10/26/15 B 3.6.6-10 75 ORR 16-1909 10/26/16 B 3.6.6.11 80 ORR 19-0524 5/30/19 B 3.6.7-1 0 Amend. No. 123 12/18/99 B 3.6.7-2 81 ORR 19-1027 10/28/19 B 3.6.7-3 81 ORR 19-1027 10/28/19 B 3.6.7-4 81 ORR 19-1027 10/28/19 B 3.6.7-5 42 ORR 09-1009 7/16/09 TAB- B 3.7 PLANT SYSTEMS B 3.7.1-1 0 Amend. No. 123 12/18/99 B 3.7.1-2 0 Amend. No. 123 12/18/99 B 3.7.1-3 0 Amend. No. 123 12/18/99 B 3.7.1-4 0 Amend. No. 123 12/18/99 B 3.7.1-5 32 ORR 07-0139 2/7/07 B 3.7.1-6 32 ORR 07-0139 2/7/07 B 3.7.2-1 44 ORR 09-1744 10/28/09 B 3.7.2-2 44 ORR 09-1744 10/28/09 B 3.7.2-3 44 ORR 09-1744 10/28/09 B 3.7.2-4 81 ORR 19-1027 10/28/19 B 3.7.2-5 44 ORR 09-1744 10/28/09 B 3.7.2-6 44 ORR 09-1744 10/28/09 B 3.7.2-7 44 ORR 09-1744 10/28/09 B 3.7.2-8 44 ORR 09-1744 10/28/09 B 3.7.2-9 44 ORR 09-1744 10/28/09 B 3.7.2-10 81 ORR 19-1027 10/28/19 B 3.7.2-11 44 ORR 09-1744 10/28/09 B 3.7.3-1 37 ORR 08-0503 4/8/08 B 3.7.3-2 50 ORR 11-0449 3/9/11 B 3.7.3-3 37 ORR 08-0503 4/8/08 B 3.7.3-4 37 ORR 08-0503 4/8/08 B 3.7.3-5 37 ORR 08-0503 4/8/08 B 3.7.3-6 37 ORR 08-0503 4/8/08 B 3.7.3-7 37 ORR 08-0503 4/8/08 B 3.7.3-8 37 ORR 08-0503 4/8/08 B 3.7.3-9 66 ORR 14-2329 11/6/14 B 3.7.3-10 66 ORR 14-2329 11/6/14 Wolf Creek - Unit 1 X Revision81

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TAB- B 3.7 PLANT SYSTEMS (continued) 83.7.3-11 37 DRR 08-0503 4/8/08 B 3.7.4-1 1 DRR 99-1624 12/18/99 B 3.7.4-2 81 DRR 19-1027 10/28/19 B 3.7.4-3 19 DRR 04-1414 10/12/04 B 3.7.4-4 19 DRR 04-1414 10/12/04 B 3.7.4-5 1 DRR 99-1624 12/18/99 B 3.7.5-1 54 DRR 11-2394 11/16/11 B 3.7.5-2 54 DRR 11-2394 11/16/11 B 3.7.5-3 0 Amend. No. 123 12/18/99 B 3.7.5-4 76 DRR 17-0343 2/21/17 B 3.7.5-5 76 DRR 17-0343 2/21/17 B 3.7.5-6 76 DRR 17-0343 2/21/17 B 3.7.5-7 76 DRR 17-0343 2/21/17 B 3.7.5-8 76 DRR 17-0343 2/21/17 B 3.7.5-9 76 DRR 17-0343 2/21/17 B 3.7.6-1 0 Amend. No. 123 12/18/99 B 3.7.6-2 0 Amend. No. 123 12/18/99 B 3.7.6-3 0 Amend. No. 123 12/18/99 B 3.7.7-1 0 Amend. No. 123 12/18/99 B 3.7.7-2 0 Amend. No. 123 12/18/99 B 3.7.7-3 0 Amend. No. 123 12/18/99 B 3.7.7-4 1 DRR 99-1624 12/18/99 B 3.7.8-1 0 Amend. No. 123 12/18/99 B 3.7.8-2 0 Amend. No. 123 12/18/99 B 3.7.8-3 0 Amend. No. 123 12/18/99 B 3.7.8-4 0 Amend. No. 123 12/18/99 B 3.7.8-5 0 Amend. No. 123 12/18/99 B 3.7.9-1 3 Amend. No. 134 7/14/00 B 3.7.9-2 3 Amend. No. 134 7/14/00 B 3.7.9-3 3 Amend. No. 134 7/14/00 B 3.7.9-4 3 Amend. No. 134 7/14/00 B 3.7.10-1 64 DRR 14-1822 8/28/14 B3.7.10-2 81 DRR 19-1027 10/28/19 B 3.7.10-3 81 DRR 19-1027 10/28/19 B 3.7.10-4 81 DRR 19-1027 10/28/19 B 3.7.10-5 81 DRR 19-1027 10/28/19 B 3.7.10-6 57 DRR 13-0006 1/16/13 B 3.7.10-7 64 DRR 14-1822 8/28/14 B 3.7.10-8 81 DRR 19-1027 10/28/19 B 3.7.10-9 81 DRR 19-1027 10/28/19 B 3.7.11-1 0 Amend. No. 123 12/18/99 B 3.7.11-2 57 DRR 13-0006 1/16/13 B 3.7.11-3 63 DRR 14-1572 7/1/14 B 3.7.11-4 63 DRR 14-1572 7/1/14 B 3.7.12-1 0 Amend. No. 123 12/18/99 B 3.7.13-1 24 DRR 06-0051 2/28/06 B 3.7.13-2 81 DRR 19-1027 10/28/19 B 3.7.13-3 81 DRR 19-1027 10/28/19 B 3.7.13-4 81 DRR 19-1027 10/28/19 B 3.7.13-5 81 DRR 19-1027 10/28/19 B 3.7.13-6 81 DRR 19-1027 10/28/19 Wolf Creek - Unit 1 xi Revision81

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B3.7.13-7 81 DRR 19-1027 10/28/19 B 3.7.13-8 81 DRR 19-1027 10/28/19 B 3.7.14-1 0 Amend. No. 123 12/18/99 B 3.7.15-1 81 DRR 19-1027 10/28/19 B 3.7.15-2 81 DRR 19-1027 10/28/19 B 3.7.15-3 81 DRR 19-1027 10/28/19 B 3.7.16-1 5 DRR 00-1427 10/12/00 B 3.7.16-2 23 DRR 05-1995 9/28/05 B 3.7.16-3 5 DRR 00-1427 10/12/00 B 3.7.17-1 7 DRR 01-0474 5/1/01 B 3.7.17-2 7 DRR 01-0474 5/1/01 B3.7.17-3 5 DRR 00-1427 10/12/00 B 3.7.18-1 81 DRR 19-1027 10/28/19 B 3.7.18-2 81 DRR 19-1027 10/28/19 B 3.7.18-3 81 DRR 19-1027 10/28/19 B 3.7.19-1 44 DRR 09-1744 10/28/09 B 3.7.19-2 54 DRR 11-2394 11/16/11 B 3.7.19-3 54 DRR 11-2394 11/16/11 B 3.7.19-4 61 DRR 14-0346 2/27/14 B 3.7.19-5 61 DRR 14-0346 2/27/14 B 3.7.19-6 54 DRR 11-2394 11/16/11 B 3.7.19-7 54 DRR 11-2394 11/16/11 B 3.7.20-1 79 DRR 18-1579 10/22/18 B 3.7.20-2 79 DRR 18-1579 10/22/18 B 3.7.20-3 79 DRR 18-1579 10/22/18 B 3.7.20-4 79 DRR 18-1579 10/22/18 B 3.7.20-5 79 DRR 18-1579 10/22/18 TAB- B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1-1 54 DRR 11-2394 11/16/11 B 3.8.1-2 0 Amend. No. 123 12/18/99 B 3.8.1-3 75 DRR 16-1909 10/26/16 B 3.8.1-4 71 DRR 15-1528 7/30/15 B3.8.1-5 59 DRR 13-1524 6/26/13 B 3.8.1-6 25 DRR 06-0800 5/18/06 B 3.8.1-7 26 DRR 06-1350 7/24/06 B 3.8.1-8 35 DRR 07-1553 9/28/07 B 3.8.1-9 42 DRR 09-1009 7/16/09 B 3.8.1-10 39 DRR 08-1096 8/28/08 B 3.8.1-11 36 DRR 08-0255 3/11/08 B 3.8.1-12 75 DRR 16-1909 10/26/16 B 3.8.1-13 47 DRR 10-1089 6/16/10 B 3.8.1-14 47 DRR 10-1089 6/16/10 B 3.8.1-15 47 DRR 10-1089 6/16/10 B 3.8.1-16 26 *, DRR 06-1350 7/24/06 B 3.8.1-17 26 DRR 06-1350 7/24/06 B 3.8.1-18 59 DRR 13-1524 6/26/13 B 3.8.1-19 26 DRR 06-1350 7/24/06 B 3.8.1-20 26 DRR 06-1350 7/24/06 B 3.8.1-21 33 DRR 07-0656 5/1/07 B 3.8.1-22 33 DRR 07-0656 5/1/07 Wolf Creek - Unit 1 xii Revision81

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TAB - B 3.8 ELECTRICAL POWER SYSTEMS (continued)

B 3.8.1-23 74 ORR 16-1182 7/7/16 B 3.8.1-24 74 ORR 16-1182 7/7/16 B 3.8.1-25 74 ORR 16-1182 7/7/16 B 3.8.1-26 74 ORR 16-1182 7/7/16 B 3.8.1-27 74 ORR 16-1182 7/7/16 B 3.8.1-28 74 ORR 16-1182 7/7/16 B 3.8.1-29 74 ORR 16-1182 7/7/16 B 3.8.1-30 74 DRR 16-1182 7/7/16 B 3.8.1-31 74 ORR 16-1182 7/7/16 B 3.8.1-32 74 ORR 16-1182 7/7/16 B 3.8.1-33 74 ORR 16-1182 7/7/16 B 3.8.1-34 74 ORR 16-1182 7/7/16 B 3.8.2-1 57 ORR 13-0006 1/16/13 B 3.8.2-2 0 Amend. No. 123 12/18/99 B 3.8.2-3 80 ORR 19-0524 5/30/19 B 3.8.2-4 57 ORR 13-0006 1/16/13 B 3.8.2-5 57 ORR 13-0006 1/16/13 B 3.8.2-6 57 ORR 13-0006 1/16/13 B 3.8.2-7 57 DRR 13-0006 1/16/13 B 3.8.3-1 1 DRR 99-1624 12/18/99 B 3.8.3-2 0 Amend. No. 123 12/18/99 B 3.8.3-3 0 Amend. No. 123 12/18/99 B 3.8.3-4 1 DRR 99-1624 12/18/99 B 3.8.3-5 0 Amend. No. 123 12/18/99 B 3.8.3-6 0 Amend. No. 123 12/18/99 B 3.8.3-7 12 ORR 02-1062 9/26/02 B 3.8.3-8 1 ORR 99-1624 12/18/99 B 3.8.3-9 0 Amend. No. 123 12/18/99 B 3.8.4-1 0 Amend. No. 123 12/18/99 B 3.8.4-2 0 Amend. No. 123 12/18/99 B 3.8.4-3 0 Amend. No. 123 12/18/99 B 3.8.4-4 0 Amend. No. 123 12/18/99 B 3.8.4-5 50 ORR 11-0449 3/9/11 B 3.8.4-6 50 ORR 11-0449 3/9/11 B 3.8.4-7 6 DRR 00-1541 3/13/01 B 3.8.4-8 0 Amend. No. 123 12/18/99 B 3.8.4-9 2 ORR 00-0147 4/24/00 B 3.8.5-1 57 ORR 13-0006 1/16/13 B 3.8.5-2 0 Amend. No. 123 12/18/99 B 3.8.5-3 57 ORR 13-0006 1/16/13 B 3.8.5-4 57 ORR 13-0006 1/16/13 B 3.8.5-5 57 DRR 13-0006 1/16/13 B 3.8.6-1 0 Amend. No. 123 12/18/99 B 3.8.6-2 0 Amend. No. 123 12/18/99 B 3.8.6-3 0 Amend. No. 123 12/18/99 B 3.8.6-4 0 Amend. No. 123 12/18/99 B 3.8.6-5 0 Amend. No. 123 12/18/99 B 3.8.6-6 0 Amend. No. 123 12/18/99 B 3.8.7-1 69 ORR 15-0493 3/26/15 B 3.8.7-2 69 ORR 15-0493 3/26/15 B 3.8.7-3 69 ORR 15-0493 3/26/15 Wolf Creek - Unit 1 xiii Revision81

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IMPLEMENTED <4>

TAB- B 3.8 ELECTRICAL POWER SYSTEMS {continued}

B 3.8.7-4 0 Amend. No. 123 12/18/99 B 3.8.8-1 57 DRR 13-0006 1/16/13 B 3.8.8-2 0 Amend. No. 123 12/18/99 B 3.8.8-3 69 DRR 15-0493 3/26/15 B 3.8.8-4 57 DRR 13-0006 1/16/13 B 3.8.8-5 69 DRR 15-0493 3/26/15 B 3.8.9-1 54 DRR 11-2394 11/16/11 B 3.8.9-2 69 DRR 15-0493 3/26/15 B 3.8.9-3 54 DRR 11-2394 11/16/11 B 3.8.9-4 0 Amend. No. 123 12/18/99 B 3.8.9-5 69 DRR 15-0493 3/26/15 B 3.8.9-6 0 Amend. No. 123 12/18/99 B 3.8.9-7 0 Amend. No. 123 12/18/99 B 3.8.9-8 1 DRR 99-1624 12/18/99 B 3.8.9-9 0 Amend. No. 123 12/18/99 B3.8.10-1 57 DRR 13-0006 1/16/13 B 3.8.10-2 0 Amend. No. 123 12/18/99 B 3.8.10-3 0 Amend. No. 123 12/18/99 B 3.8.10-4 57 DRR 13-0006 1/16/13 B 3.8.10-5 57 DRR 13-0006 1/16/13 B 3.8.10-6 57 DRR 13-0006 1/16/13 TAB- B 3.9 REFUELING OPERATIONS B3.9.1-1 0 Amend. No. 123 12/18/99 B3.9.1-2 19 DRR 04-1414 10/12/04 B 3.9.1-3 19 DRR 04-1414 10/12/04 B3.9.1-4 19 DRR 04-1414 10/12/04 B 3.9.2-1 0 Amend. No. 123 12/18/99 B 3.9.2-2 0 Amend. No. 123 12/18/99 B 3.9.2-3 0 Amend. No. 123 12/18/99 B 3.9.3-1 68 DRR 15-0248 2/26/15 B 3.9.3-2 68 DRR 15-0248 2/26/15 B 3.9.3-3 51 DRR 11-0664 3/21 /11 B 3.9.3-4 68 DRR 15-0248 2/26/15 B 3.9.4-1 81 DRR 19-1027 10/28/19 B 3.9.4-2 13 DRR 02-1458 12/03/02 B 3.9.4-3 81 DRR 19-1027 10/28/19 B 3.9.4-4 23 DRR 05-1995 9/28/05 B 3.9.4-5 33 DRR 07-0656 5/1/07 B 3.9.4-6 23 DRR 05-1995 9/28/05 B 3.9.5-1 0 Amend. No. 123 12/18/99 B 3.9.5-2 72 DRR 15-1918 10/26/15 B 3.9.5-3 32 DRR 07-0139 2/7/07 B 3.9.5-4 75 DRR 16-1909 10/26/16 B 3.9.5-5 75 DRR 16-1909 10/26/16 B 3.9.6-1 0 Amend. No. 123 12/18/99 B 3.9.6-2 72 DRR 15-1918 10/26/15 B 3.9.6-3 42 DRR 09-1009 7/16/09 B 3.9.6-4 72 DRR 15-1918 10/26/15 B 3.9.6-5 75 DRR 16-1909 10/26/16 B 3.9.7-1 81 DRR 19-1027 10/28/19 Wolf Creek - Unit 1 xiv Revision81

LIST OF EFFECTIVE PAGES -TECHNICAL SPECIFICATION BASES PAGE<1> REVISION NO. c2J CHANGE DOCUMENT <3> DATE EFFECTIVE/

IMPLEMENTED C4l TAB- B 3.9 REFUELING OPERATIONS (continued)

B 3.9.7-2 81 DRR 19-1027 10/28/19 B 3.9.7-3 81 DRR 19-1027 10/28/19 Note 1 The page number is listed on the center of the bottom of each page.

Note 2 The revision number is listed in the lower right hand corner of each page. The Revision number will be page specific.

Note 3 The change document will be the document requesting the change. Amendment No.

123 issued the improved Technical Specifications and associated Bases which affected each page. The NRC has indicated that Bases changes will not be issued with License Amendments. Therefore, the change document should be a ORR number in accordance with AP 26A-002.

Note 4 The date effective or implemented is the date the Bases pages are issued by Document Control.

Wolf Creek - Unit 1 xv Revision81

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 claddin9\fai,lure, 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 pressure coolant boundary (RCPB) design conditions are not to be exceeded during normal operation and anticipated operational occurrences (AOOs).

Also, in accordance with GOC 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 Ill 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 ASME Code,Section XI (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 50.67 (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 Ill of the ASME Code for Nuclear Power Plant Components (Ref. 2). The transient that establishes the required relief capacity, and Wolf Creek - Unit 1 82.1.2-1 Revision 81

RCS Pressure SL B 2.1.2 BASES SAFETY LIMIT The following SL violations are applicable to the RCS pressure SL.

VIOLATIONS 2.2.2.1 If the RCS pressure SL is violated when the reactor is in MODE 1 or 2, 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 50.67 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.

2.2.2.2 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 severe than 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 Ill, Article NB-7000.

3. ASME, Boiler and Pressure Vessel Code,Section XI, Article IWX-5000.

4. 10 CFR 50.67.

Wolf Creek - Unit 1 B 2.1.2-3 Revision 81

LCO Applicability B 3.0 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABIL TY BASES LCOs LCO 3.0.1 through LCO 3.0.8 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated.

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

LCO 3.0.2 LCO 3.0.2 establishes that upon discovery of a failure to meet an LCO, the associated ACTIONS shall be met. The Completion Time of each Required Action for an ACTIONS Condition is applicable from the point in time that an ACTIONS Condition is entered, unless otherwise specified.

The Required Actions establish those remedial measures that must be taken within specified Completion Times when the requirements of an LCO are not met. This Specification establishes that:

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

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

There are two basic types of Required Actions. The first type of Required Action specifies a time limit in which the LCO must be met. This time limit is the Completion Time to restore an inoperable system or component to OPERABLE status or to restore variables to within specified limits. If this type of Required Action is not completed within the specified Completion Time, a shutdown may be required to place the unit in a MODE or condition in which the Specification is not applicable. (Whether stated as a Required Action or not, correction of the entered Condition is an action that may always be considered upon entering ACTIONS.) The second type of Required Action specifies the remedial measures that permit continued operation of the unit that is not further restricted by the Completion Time. In this case, compliance with the Required Actions provides an acceptable level of safety for continued operation.

Wolf Creek - Unit 1 B 3.0-1 Revision 81

LCO Applicability B 3.0 BASES LCO 3.0.3 b. The condition of the unit is not specifically addressed by the (continued) associated ACTIONS. This means that no combination of Conditions stated in the ACTIONS can be made that exactly corresponds to the actual condition of the unit. Sometimes, possible combinations of Conditions are such that entering LCO 3.0.3 is warranted; in such cases, the ACTIONS specifically state a Condition corresponding to such combinations and also that LCO 3.0.3 be entered immediately.

This Specification delineates the time limits for placing the unit in a safe MODE or other specified condition when operation cannot b& maintained

,within the limits for safe operation as defined by the LCO and its ACTIONS. It is not intended to be used as an operational convenience that permits routine voluntary removal of redundant systems or components from service in lieu of other alternatives that would not result in redundant systems or components being inoperable.

Upon entering LCO 3.0.3, 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to prepare for an orderly shutdown before initiating a change in unit operation. This includes time to permit the operator to coordinate the reduction in electrical generation with the load dispatcher to ensure the stability and availability of the electrical grid. The time limits specified to enter lower MODES of operation permit the shutdown to proceed in a controlled and orderly manner that is well within the specified maximum cooldown rate and within the capabilities of the unit, assuming that only the minimum required equipment is OPERABLE. This reduces thermal stresses on components of the Reactor Coolant System and the potential for a plant upset that could challenge safety systems under conditions to which this Specification applies. The use and interpretation of specified times to complete the actions of LCO 3.0.3 are consistent with the discussion of Section 1.3, Completion Times.

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

a. The LCO is now met. .

b. The LCO is no longer applicable.

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

d. ACTIONS exist that do not have expired Completion Times.

These Completion Times are applicable from the point in time that the Condition is initially entered and not from the time LCO 3.0.3 is exited.

Wolf Creek - Unit 1 B 3.0-3 Revision 81

LCO Applicability B 3.0 BASES LCO 3.0.3 The time limits of Specification 3.0.3 allow 37 hours4.282407e-4 days 0.0103 hours 6.117725e-5 weeks 1.40785e-5 months for the unit to be in (continued) MODE 5 when a shutdown is required during MODE 1 operation. If the unit is in a lower MODE of operation when a shutdown is required, the time limit for entering the next lower MODE applies. If a lower MODE is entered in less time than allowed, however, the total allowable time to enter MODE 5, or other applicable MODE, is not reduced. For example, if MODE 3 is entered in 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , then the time allowed for entering MODE 4 is the next 11 hours1.273148e-4 days 0.00306 hours 1.818783e-5 weeks 4.1855e-6 months , because the total time for entering MODE 4 is not reduced from the allowable limit of 13 hours1.50463e-4 days 0.00361 hours 2.149471e-5 weeks 4.9465e-6 months . Therefore, if remedial measures are completed that would permit a return to MODE 1, a penalty is not incurred by having to enter a lower MODE of operation in less than the total time allowed.

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

Exceptions to LCO 3.0.3 are provided in instances where requiring a unit shutdown, in accordance with LCO 3.0.3, would not provide appropriate remedial measures for the associated condition of the unit. An example of this is in LCO 3.7.15, '.' Fuel Storage Pool Water Level." LCO 3.7.15 has an Applicability of "During movement of irradiated fuel assemblies in the fuel storage pool." Therefore, this LCO can be applicable in any or all MODES. If the LCO and the Required Actions of LCO 3.7.15 are not met while in MODE 1, 2, 3, or 4, there is no safety benefit to be gained by placing the unit in a shutdown condition. The Required Action of LCO 3. 7 .15 of "Suspend movement of irradiated fuel assemblies in the fuel storage pool" is the appropriate Required Action to complete in lieu of the actions of LCO 3.0.3. These exceptions are addressed in the individual Specifications.

LCO 3.0.4 LCO 3.0.4 establishes limitations on changes in MODES or other specified conditions in the Applicability when an LCO is not met. It allows placing the unit in a MODE or other specified condition stated in that Applicability (e.g.,

the Applicability desired to be entered) when unit conditions are such that the requirements of the LCO would not be met, in accordance with LCO either 3.0.4a., LCO 3.0.4b., or LCO 3.0.4c.

Wolf Creek - Unit 1 B 3.0-4 Revision 81

LCO Applicability B 3.0 BASES LCO 3.0.4 LCO 3.0.4a. allows entry into a MODE or other specified condition in the (continued) Applicability with the LCO not met when the associated ACTIONS to be entered following entry into the MODE or other specified condition in the Applicability will permit continued operation within the MODE or other specified condition for an unlimited period of time. Compliance with Actions that permit continued operation of the unit for an unlimited period of time in a MODE or other specified condition provides an acceptable level of safety for continued operation. This is without regard to the status of the unit before or after the MODE change. Therefore, in such cases, entry into a MODE or other specified condition in the Applicability may be made and the Required Actions followed after entry into the Applicability.

For example, LCO 3.0.4.a may be used when the Required Action to be entered states that an inoperable instrument channel must be placed in the trip condition within the Completion Time. Transition into a MODE or other specified condition in the Applicability may be made in accordance with LCO 3.0.4 and the channel is subsequently placed in the tripped condition within the Completion Time, which begins when the Applicability is entered.

If the instrument channel cannot be placed in the tripped condition and the subsequent default ACTION ("Required Action and associated Completion Time not met") allows the OPERABLE train to be placed in operation, use of LCO 3.0.4.a is acceptable because the subsequent ACTIONS to be entered following entry into the MODE include ACTIONS (place the OPERABLE train in operation) that permit safe plant operation for an unlimited period of time in the MODE or other specified condition to be entered.

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

The risk assessment may use quantitative, qualitative, or blended approaches, and the risk assessment will be conducted using the plant program, procedures, and criteria in place to implement 10 CFR 50.65(a)(4), which requires that risk impacts of maintenance activities to be assessed and managed. The risk assessment, for the purposes of LCO 3.0.4b., must take into account all inoperable Technical Specification equipment regardless of whether the equipment is included in the normal 10 CFR 50.65(a)(4) risk assessment scope. The risk assessments will be conducted using the procedures and guidance endorsed by Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." Regulatory Guide 1.182 endorses the guidance in Section 11 of NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants."

These documents address general guidance for conduct of the risk Wolf Creek - Unit 1 B 3.0-5 Revision 81

LCO Applicability B 3.0 BASES LCO 3.0.4 assessment, quantitative and qualitative guidelines for establishing risk (continued) management actions, and example risk management actions. These include actions to plan and conduct other activities in a manner that controls overall risk, increased risk awareness by shift and management personnel, actions to reduce the duration of the condition, actions to minimize the magnitude of risk increases (establishment of backup success paths or compensatory measures), and determination that the proposed MODE change is acceptable. Consideration should also be given to the probability of completing restoration such that the requirements of the LCO would be met prior to the expiration of ACTIONS Completion Times that would require exiting the Applicability.

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

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

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

LCO 3.0.4c. allows entry into a MODE or other specified condition in the Applicability with the LCO not met based on a Note in the Specification which states LCO 3.0.4c. is applicable. These specific allowances permit entry into MODES or other specified conditions in the Applicability when the associated ACTIONS to be entered do not provide for continued operation for an unlimited period of time and a risk assessment has not been performed. This allowance may apply to all the ACTIONS or to a specific Required Action of a Specification. The risk assessments performed to justify the use of LCO 3.0.4b. usually only consider systems and components. For this reason, LCO 3.0.4c. is typically applied to Specifications which describe values and parameters (e.g., Containment Air Temperature, Containment Pressure, Moderator Temperature Coefficient), and may be applied to other Specifications based on NRC plant-specific approval.

Wolf Creek - Unit 1 B 3.0-6 Revision 81

LCO Applicability B 3.0 BASES LCO 3.0.4 The provisions of this Specification should not be interpreted as endorsing (continued) the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability.

The provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of LCO 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, MODE 3 to MODE 4, MODE 4 to MODE 5, and MODE 5 to MODE 6.

Upon entry into a MODE or other specified condition in the Applicability

with the LCO not met, LCO 3.0.1 and LCO 3.0.2 require entry into the applicable Conditions and Required Actions until the Condition is resolved, until the LCO is met, or until the unit is not within the Applicability of the Technical Specification.

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

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

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

b. The OPERABILITY of other equipment.

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

Wolf Creek - Unit 1 B 3.0-7 Revision 81

LCO Applicability B 3.0 BASES LCO 3.0.5 LCO 3.0.5 should not be used in lieu of other practicable alternatives that (continued) comply with Required Actions and that do not require changing the MODE or other specified conditions in the Applicability in order to demonstrate equipment is OPERABLE. LCO 3.0.5 is not intended to be used repeatedly.

An example of demonstrating equipment is OPERABLE with the Required Actions not met is opening a manual valve that was closed to comply with Required Actions to isolate a flowpath with excessive Reactor Coolant System (RCS) Pressure Isolation Valve (PIV) leakage in order to perform testing to demonstrate that RCS PIV leakage is now within limit Examples of demonstrating equipment OPERABILITY include instances in which it is necessary to take an inoperable channel or trip system out of a tripped condition that was directed by a Required Action, if there is no Required Action Note for this purpose. An example of verifying OPERABILITY of equipment removed from service is taking a tripped channel out of the tripped condition to permit the logic to function and indicate the appropriate response during performance of required testing on the inoperable channel.

Examples of demonstrating the OPERABILITY of other equipment are taking an inoperable channel or trip system out of the tripped condition

1) to prevent the trip function from occurring during the performance of required testing on another channel in the other trip system, or 2) to permit the logic to function and indicate the appropriate response during the performance of required testing on another channel in the same trip system.

The administrative controls in LCO 3.0.5 apply in all cases to systems or components in Chapter 3 of the Technical Specifications, as long as the testing could not be conducted while complying with the Required Actions.

This includes the realignment or repositioning of redundant or alternate equipment or trains previously manipulated to comply with ACTIONS, as well as equipment removed from service or declared inoperable to comply with ACTIONS.

LCO 3.0.6 LCO 3.0.6 establishes an exception to LCO 3.0.2 for support systems that have an LCO specified in the Technical Specifications (TS). This exception is provided because LCO 3.0.2 would require that the Conditions and Required Actions of the associated inoperable supported system LCO be entered solely due to the inoperability of the support system. This exception is justified because the actions that are required to ensure the unit is maintained in a safe condition are specified in the support system LCO's Required Actions. These Required Actions may include entering the supported system's Conditions and Required Actions or may specify other Required Actions. When a support system is Wolf Creek - Unit 1 B 3.0-8 Revision 81

l I

LCO Applicability B 3.0 BASES LCO 3.0.6 inoperable and there is an LCO specified for it in the TS, the supported (continued) system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' LCOs' Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the unit is maintained in a safe condition in the support system's Required Actions.

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

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

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

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

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

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

LCO 3.0.7 There are certain special tests and operations required to be performed at various times over the life of the unit. These special tests and operations are necessary to demonstrate select unit performance characteristics, to perform special maintenance activities, and to perform special evolutions.

Test Exception LCO 3.1.8 allows specified Technical Specification (TS) requirements to be changed to permit performances of these special tests and operations, which otherwise could not be performed if required to comply with the requirements of these TS. Unless otherwise specified, all Wolf Creek - Unit 1 B 3.0-9 Revision 81

LCO Applicability B 3.0 BASES LCO 3.0.7 the other TS requirements remain unchanged. This will ensure all (continued) appropriate requirements of the MODE or other specified condition not directly associated with or required to be changed to perform the special test or operation will remain in effect.

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

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

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

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

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

Wolf Creek - Unit 1 B 3.0-10 Revision 81

LCO Applicability B 3.0 BASES LCO 3.0.8 LCO 3.0.8.b applies when one or more snubbers are not capable of (continued) providing their associated support function(s) to more than one train or subsystem of a multiple train or subsystem supported system. LCO 3.0.8.b allows 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to restore the snubber(s) before declaring the supported system inoperable. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable based on the low probability of a seismic event concurrent with an event that would require operation of the supported system occurring while the snubber(s) are not capable of performing their associated support function.

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

Wolf Creek - Unit 1 B 3.0-11 Revision 81

SR Applicability B 3.0 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY BASES SRs SR 3.0.1 through SR 3.0.4 establish the general requirements applicable to all Specifications and apply at all times, unless otherwise stated.

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

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

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

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

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

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

Surveillances, including Surveillances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with SR 3.0.2, prior to returning equipment to OPERABLE status. Upon completion of maintenance, appropriate post maintenance testing is required to declare equipment OPERABLE. This includes ensuring applicable Surveillances are not failed and their most recent performance is in accordance with SR 3.0.2.

Post maintenance testing may not be possible in the current MODE or Wolf Creek - Unit 1 83.0-12 Revision 81

SR Applicability B 3.0 BASES SR 3.0.1 other specified conditions in the Applicability due to the necessary unit (continued) parameters not having been established. In these situations, the equipment may be considered OPERABLE provided testing has been satisfactorily completed to the extent possible and the equipment is not otherwise believed to be incapable of performing its function. This will allow operation to proceed to a MODE or other specified condition where other necessary post maintenance tests can be completed.

SR 3.0.2 SR 3.0.2 establishes the requirements for meeting the specified Frequency for Surveillances and any Required Action with a Completion Time that requires the periodic performance of the Required Action on a "once per ... " intervaL SR 3.0.2 permits a 25% extension of the interval specified in the Frequency. This extension facilitates Surveillance scheduling and considers plant operating conditions that may not be suitable for conducting the Surveillance (e.g., transient conditions or other ongoing Surveillance or maintenance activities).

The 25% extension does not significantly degrade the reliability that results from performing the Surveillance at its specified Frequency. This is based on the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the SRs. The exceptions to SR 3.0.2 are those Surveillances for which the 25% extension of the interval specified in the Frequency does not apply.

These exceptions are stated in the individual Specifications. The requirements of regulations take precedence over the TS. Therefore, when a test interval is specified in the regulations, the test interval cannot be extended by the TS, and the SRs include a Note in the Frequency stating, "SR 3.0.2 is not applicable." An example of an exception when the test interval is not specified in the regulations is the Note in the Containment Leakage Rate Testing Program, "SR 3.0.2 is not applicable." This exception is provided because the program already includes extension of test intervals.

As stated in SR 3.0.2, the 25% extension also does not apply to the initial portion of a periodic Completion Time that requires performance on a "once per ... " basis. The 25% extension applies to each performance after the initial performance. The initial performance of the Required Action, whether it is a particular Surveillance or some other remedial action, is considered a single action with a single Completion Time. One reason for not allowing the 25% extension to this Completion Time is that such an action usually verifies that no loss of function has occurred by checking the status of redundant or diverse components or accomplishes Wolf Creek - Unit 1 B 3.0-13 Revision 81

SR Applicability B 3.0 BASES SR 3.0.2 the function of the inoperable equipment in an alternative manner.

(continued)

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

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

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

The basis for this delay period includes consideration of unit conditions, adequate planning, availability of personnel, the time required to perform the Surveillance, the safety,significance of the delay in completing the required Surveillance, and the recognition that the most probable result of any particular Surveillance being performed is the verification of conformance with the requirements. When a Surveillance with a Frequency based not on time intervals, but upon specified unit conditions, operating situations, or requirements of regulations (e.g., prior to entering MODE 1 after each fuel loading, or in accordance with 10 CFR 50, Appendix J, as modified by approved exemptions, etc.) is discovered to not have been performed when specified, SR 3.0.3 allows for the full delay period of up to the specified Frequency to perform the Surveillance.

However, since there is not a time interval specified, the missed Surveillance should be performed at the first reasonable opportunity.

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

SR 3.0.3 is only applicable if there is a reasonable expectation the associated equipment is OPERABLE or that variables are within limits, and it is expected that the Surveillance will be met when performed. Many factors should be considered, such as the period of time since the Surveillance was last performed, or whether the Surveillance, or a portion thereof, has ever been performed, and any other indications, tests, or Wolf Creek - Unit 1 B 3.0-14 Revision 81

SR Applicability B 3.0 BASES SR 3.0.3 activities that might support the expectation that the Surveillance will be (continued) met when performed. An example of the use of SR 3.0.3 would be a relay contact that was not tested as required in accordance with a particular SR, but previous successful performances of the SR included the relay contact; the adjacent, physically connected relay contacts were tested during the SR performance; the subject relay contact has been tested by another SR; or historical operation of the subject relay contact has been successful. It is not sufficient to infer the behavior of the associated equipment from the performance of similar equipment. The rigor of determining whether there is a reasonable expectation a Surveillance will be met when performed should increase based on the length of time since the last performance of the Surveillance. If the Surveillance has been performed recently, a review of the Surveillance history and equipment performance may be sufficient to support a reasonable expectation that the Surveillance will be met when performed. For Surveillances that have not been performed for a long period or that have never been performed, a rigorous evaluation based on objective evidence should provide a high degree of confidence that the equipment is OPERABLE. The evaluation should be documented in sufficient detail to allow a knowledgeable individual to understand the basis for the determination.

Failure to comply with specified Frequencies for SRs is expected to be an infrequent occurrence. Use of the delay period established by SR 3.0.3 is a flexibility which is not intended to be used repeatedly to extend Surveillance intervals. While up to 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months or the limit of the specified Frequency is provided to perform the missed Surveillance, it is expected that the missed Surveillance will be performed at the first reasonable opportunity. The determination of the first reasonable opportunity should include consideration of the impact on plant risk (from delaying the Surveillance as well as any plant configuration changes required or shutting the plant down to perform the Surveillance) and impact on any analysis assumptions, in addition to unit conditions, planning, availability of personnel, and the time required to perform the Surveillance. This risk impact should be managed through the program in place to implement 10 CFR 50.65(a)(4) and its implementation guidance, NRC Regulatory Guide 1.182, "Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants." This Regulatory Guide addresses consideration of temporary and aggregate risk impacts, determination of risk management action thresholds, and risk management action up to and including plant shutdown. The missed Surveillance should be treated as an emergent condition as discussed in the Regulatory Guide. The risk evaluation may use quantitative, qualitative, or blended methods. The degree of depth and rigor of the evaluation should be commensurate with the importance of the component. Missed Surveillances for important components should be analyzed quantitatively. If the results of the risk evaluation determine the risk increase is significant, this evaluation should Wolf Creek - Unit 1 B3.0-15 Revision 81

SR Applicability B 3.0 BASES SR 3.0.3 be used to determine the safest course of action. All missed (continued) Surveillances will be placed in the Corrective Action Program.

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

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

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

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

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

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

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

When a system, subsystem, division, component, device, or variable is inoperable or outside its specified limits, the associated SR(s) are not required to be performed, per SR 3.0.1, which states that surveillances do not have to be performed on inoperable equipment. When equipment is inoperable, SR 3.0.4 does not apply to the associated SR(s) since the requirement for the SR(s) to be performed is removed. Therefore, failing to perform the Surveillance(s) within the specified Frequency does not result in an SR 3.0.4 restriction to changing MODES or other specified conditions of the Applicability. However, since the LCO is not met in this instance, LCO 3.0.4 will govern any restrictions that may (or may not)

Wolf Creek - Unit 1 B 3.0-16 Revision 81

SR Applicability B 3.0 BASES SR 3.0.4 apply to MODE or other specified condition changes. SR 3.0.4 does not (continued) restrict changing MODES or other specified conditions of the Applicability when a Surveillance has not been performed within the specified Frequency, provided the requirement to declare the LCO not met has been delayed in accordance with SR 3.0.3.

The provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that are required to comply with ACTIONS. In addition, the provisions of SR 3.0.4 shall not prevent changes in MODES or other specified conditions in the Applicability that result from any unit shutdown. In this context, a unit shutdown is defined as a change in MODE or other specified condition in the Applicability associated with transitioning from MODE 1 to MODE 2, MODE 2 to MODE 3, MODE 3 to MODE 4, MODE 4 to MODE 5, and MODE 5 to MODE 6.

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

Alternately, the Surveillance may be stated in the form of a Note as not required (to be met or performed) until a particular event, condition, or time has been reached. Further discussion of the specific formats of SRs' annotation is found I

in Section 1.4, Frequency.

Wolf Creek - Unit 1 83.0-17 Revision 81

SOM B 3.1.1 BASES LCO SOM is a core design condition that can be ensured during operation through control rod positioning (control and shutdown banks) and through the soluble boron concentration.

The MSLB (Ref. 2) and the boron dilution (Ref. 3) accidents are the most limiting analyses that establish the SOM value of the LCO. For MSLB accidents, if the LCO is violated, there is a potential to exceed the DNBR limit and to exceed 10 CFR 50.67 limits (Ref. 4 ). For the boron dilution accident, if the LCO is violated, the minimum required time assumed for operator action to terminate dilution may no longer be sufficient. The required SOM limit is specified in the COLR.

APPLICABILITY In MODE 2 with kett < 1.0 and in MODES 3, 4, and 5, the SOM requirements are applicable to provide sufficient negative reactivity to meet the assumptions of the safety analyses discussed above. In MODE 6, the shutdown reactivity requirements are given in LCO 3.9.1, "Boron Concentration." In MODES 1 and 2, SOM is ensured by complying with LCO 3.1.5, "Shutdown Bank Insertion Limits," and LCO 3.1.6, "Control Bank Insertion Limits."

The risk assessments of LCO 3.0.4b. may only be utilized for systems and components, not Criterion 2 values or parameters such as SOM.

Therefore, a risk assessment per LCO 3.0.4b. to allow MODE changes with single or multiple system/equipment inoperabilities may not be used to allow a MODE change into or within this LCO while not meeting the SOM limits, even if risk assessment specifically includes consideration of SOM.

ACTIONS If the SOM requirements are not met, boration must be initiated promptly.

A Completion Time of 15 minutes is adequate for an operator to correctly

' align and start the required systems and components. It is assumed that boration will be continued until the SOM requirements are met.

In the determination of the required combination of boration flow rate and boron concentration, there is no unique requirement that must be satisfied. Since it is imperative to raise the boron concentration of the RCS as soon as possible, the borated water source should be a highly concentrated solution, such as that normally found in the boric acid storage tank, or the refueling water storage tank. The operator should borate with the best source available for the plant conditions.

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SOM B 3.1.1 BASES SURVEILLANCE SR 3.1.1.1 REQUIREMENTS In MODES 1 and 2, SOM is verified by observing that the requirements of LCO 3.1.5 and LCO 3.1.6 are met. In the event that a rod is known to be untrippable, however, SOM verification must account for the worth of the untrippable rod as well as another rod of maximum worth.

In MODES 2 (with kett < 1.0), 3, 4, and 5, the SOM is verified by performing a reactivity balance calculation, considering the listed reactivity effects:

a. RCS boron concentration;

b. Control and shutdown rod position;

c. RCS average temperature;

d. Fuel burnup based on gross thermal energy generation;

e. Xenon concentration;

f. Samarium concentration; and

g. Isothermal temperature coefficient (ITC).

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

The Frequency of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is based on the generally slow change in required boron concentration and the low probability of an accident occurring without the required SOM. This allows time for the operator to collect the required data, which includes performing a boron concentration analysis, and complete the calculation.

REFERENCES 1. 10 CFR 50, Appendix A, GDC 26.

2. USAR, Section 15.1.5.

3. USAR, Section 15.4.6.

4. 10 CFR 50.67.

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RCS Boron Limitations < 500°F B 3.1.9 B 3.1 REACTIVITY CONTROL SYSTEMS B 3.1.9 RCS Boron Limitations < 500°F BASES BACKGROUND The control rod drive mechanisms (CRDMs) are wired into pre-selected RCCA banks, such that the RCCA banks can only be withdrawn in their proper withdrawal sequence. The control of the power supplied to the RCCA banks is such that no more than two RCCA banks can be withdrawn at any time.

When the RCCA banks are capable of being withdrawn from the core, i.e.,

power supplied to the CRDMs during an approach to criticality for reactor startup, or during maintenance and surveillance testing, there is the potential for an inadvertent RCCA bank withdrawal due to a malfunction of the control rod drive system.

Westinghouse NSAL-00-016 (Ref. 1) discussed the reactor trip functions assumed in the Uncontrolled RCCA Bank Withdrawal from a Low Power or Subcritical Condition event (RWFS) (Ref. 2). The primary protection for a RWFS is provided by the Power Range Neutron Flux-Low trip Function.

The Source Range Neutron Flux trip Function is implicitly credited as the primary reactor trip function for a RWFS event in MODES 3, 4, or 5, since the Power Range Neutron Flux-Low trip Function is not required to be OPERABLE in these MODES. However, the Source Range Neutron Flux trip Function response time is listed as not applicable, and is therefore not response time tested per SR 3.3.1.16, and therefore cannot be considered to be OPERABLE to provide protection for a RWFS event in MODES 3, 4, and 5. NSAL-00-016 also identified that the Power Range Neutron Flux-Low trip Function may not be OPERABLE at RCS temperatures significantly below the hot zero power Tavg due to calibration issues associated with shielding caused by the cold water in the downcomer region of the reactor vessel. Therefore, the Power Range Neutron Flux-Low trip Function would not provide protection in MODE 3 when RCS Tavg is~ 500°F.

Borating the RCS to an all rods out (ARO) boron concentration when the RCCA banks are capable of rod withdrawal provides sufficient SHUTDOWN MARGIN in the event of an uncontrolled RCCA bank withdrawal event fr:om a subcritical condition, when Tavg is <-500°F .

. Wolf Creek - Unit 1 83.1.9-1 Revision 81

RCS Boron Limitations < 500°F B 3.1.9 BASES APPLICABLE A RCCA bank withdrawal event is analyzed from both a subcritical and SAFETY ANALYSES power startup condition. The event is terminated by the Power Range Neutron Flux-Low trip Function. The Source Range Neutron Flux and Intermediate Range Neutron Flux trip Functions are also available to terminate an RCCA bank withdrawal from subcritical, but are not explicitly credited in the safety analyses to terminate the event.

The Power Range Neutron Flux-Low trip Function is only capable of providing protection for an RCCA bank withdrawal event when the RCS temperature is e=: 500°F, due to calibration issues associated with shielding caused by cold water in the downcomer region of the reactor vessel.

Additionally, although not explicitly analyzed, in MODE 3 when the RCS temperature is < 500°F and in MODES 4 and 5, the Source Range Neutron Flux trip Function is implicitly credited to provide protection for an RCCA bank withdrawal event.

Therefore, since there is no explicit RCCA bank withdrawal analysis that is performed in MODE 3 when the RCS temperature is < 500°F and in MODES 4 and 5, the RCS is borated to an ARO boron concentration to provide sufficient SHUTDOWN MARGIN if the rods are capable of withdrawal or one or more rods are not fully inserted in these MODES.

LCO This LCO requires that the RCS be borated to an ARO boron concentration to provide adequate SHUTDOWN MARGIN in the event of an RCCA bank withdrawal event.

APPLICABILITY In the event of an RCCA bank withdrawal, the LCO must be applicable to provide adequate SHUTDOWN MARGIN in the following MODES and specified conditions:

In MODE 2 with kett < 1.0 with any RCS cold leg temperature < 500°F and with the Rod Control System capable of rod withdrawal, or one or more rods not fully inserted.

In MODE 3 with any RCS cold leg temperature < 500°F and with the Rod Control System capable of rod withdrawal, or one or more rods not fully inserted.

In MODES 4 and 5 with the Rod Control System capable of rod withdrawal, or one or more rods not fully inserted.

Wolf Creek - Unit 1 B 3.1.9-2 Revision 81

RCS Boron Limitations < 500°F B 3.1.9 BASES ACTIONS If the RCS boron concentration is not within limit, action must be taken to restore the boron concentration to within limit. Borating the RCS to an ARO boron concentration would provide sufficient SHUTDOWN MARGIN, if an uncontrolled RCCA bank withdrawal accident were to occur.

If the RCS boron concentration is not within limit, action must be taken to make the rods incapable of rod withdrawal. This action would preclude an uncontrolled RCCA bank withdrawal accident from occurring with an inadequate SHUTDOWN MARGIN.

If the RCS boron concentration is not with in limit, another alternate action is to restore all RCS cold leg temperatures to~ S00°F. At this RCS temperature the Power Range Neutron Flux-Low trip Function would be OPERABLE if an uncontrolled RCCA bank withdrawal accident were to occur.

Required.Action A.3 has been modified by a Note that states that it is not applicable in MODES 4 and 5. This action would or;ily be taken during a unit startup when RCS T avg < 500°F and ensures that the Power Range Neutron Flux-Low trip Function would be OPERABLE to mitigate an uncontrolled RCCA bank withdrawal accident.

SURVEILLANCE SR3.1.9.1 I REQUIREMENTS This SR ensures that the RCS boron concentration is within limit. The boron concentration is determined periodically by chemical analysis.

A Frequency of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is adequate based on the time required to dilute the RCS, the various alarms available in the control room, and the heightened awareness in the control room when the rods are capable of being withdrawn.

Wolf Creek - Unit 1 B 3.1.9-3 Revision 81

RCS Boron Limitations < 500°F B 3.1.9 BASES REFERENCES 1. Westinghouse Nuclear Safety Advisory Letter NSAL-00-016, "Rod Withdrawal from Subcritical Protection in Lower Modes,"

December 4, 2000.

2. USAR, Section 15.4.1.

Wolf Creek - Unit 1 B 3.1.9-4 Revision 81

RTS Instrumentation B 3.3.1 B 3.3 INSTRUMENTATION B 3.3.1 Reactor Trip System (RTS) Instrumentation BASES BACKGROUND The RTS initiates a unit shutdown, based on the values of selected unit parameters, to protect against violating the core fuel design limits and Reactor Coolant System (RCS) pressure boundary during Anticipated Operational Occurrences (AOOs) and to assist the Engineered Safety Features (ESF) Systems in mitigating accidents.

The protection and monitoring systems have been designed to assure safe operation of the reactor. This is achieved by specifying Limiting Safety System Settings (LSSS) in terms of parameters directly monitored by the RTS, as well as specifying LCOs on other reactor system parameters and equipment performance.

The LSSS, defined in this specification as the Allowable Values, in conjunction with the LCOs, establish the threshold for protective system action to prevent exceeding acceptable limits during Design Basis Accidents (DBAs).

During AOOs, which are those events expected to occur one or more times during the unit life, the acceptable limits are:

1. The Departure from Nucleate Boiling Ratio (DNBR) shall be maintained above the (DNBR) limit;

2. Fuel centerline melt shall not occur; and

3. The RCS pressure Safety Limit of 2735 psig shall not be exceeded.

Operation within the limits of Specification 2.0, "Safety Limits (Sls)," also maintains the above values and assures that offsite dose will be within the 10 CFR 20 and 10 CFR 50.67 criteria during AOOs.

Accidents are events that are analyzed even though they are not expected to occur during the unit life. The acceptable limit during accidents is that offsite dose shall be maintained within an acceptable fraction of 10 CFR 50.67 limits. Different accident categories are allowed a different fraction of these limits, based on probability of occurrence.

Meeting the acceptable dose limit for an accident category is considered having acceptable consequences for that event.

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ESFAS Instrumentation B 3.3.2 BASES APPLICABLE e. Safety Injection - Steam Line Pressure - Low (continued)

SAFETY ANALYSES, LCO, and environment instrument uncertainties. The Trip Setpoint is APPLICABILITY ~ 615 psig.

This Function is anticipatory in nature and has a lead/lag ratio of 50/5.

Steam Line Pressure - Low must be OPERABLE in MODES 1, 2, and 3 (above P-11 and below P-11 unless the Safe Injection - Steam Line Pressure - Low Function is blocked) when a secondary side break or stuck open valve could result in the rapid depressurization of the steam lines. This signal may be manually blocked by the operator below the P-11 setpoint. Below P-11, feed line break is not a concern. Inside containment SLB will be terminated by automatic SI actuation via Containment Pressure - High 1, and outside containment SLB will be terminated by the Steam Line Pressure - Negative Rate - High signal for steam line isolation. This Function is not required to be OPERABLE in MODE 4, 5, or 6 because there is insufficient energy in the secondary side of the unit to have a significant effect on required plant equipment.

2. Containment Spray Containment Spray provides three primary functions:

1. Lowers containment pressure and temperature after an HELB in containment;

2. Reduces the amount of radioactive iodine and particulates in the containment atmosphere; and

3. Adjusts the pH of the water in the containment recirculation sumps after a large break LOCA.

These functions are necessary to:

Ensure the pressure boundary integrity of the containment structure;

Limit the release of radioactive iodine and particulates to the environment; and Wolf Creek - Unit 1 B 3.3.2-12 Revision 81

PAM Instrumentation B 3.3.3 BASES LCO 12. Steam Generator Water Level (Wide Range) (continued) used to determine whether adequate core cooling is provided in the absence of wide range level indication for a steam generator.

The design limitation of having one wide range level indicator in conjunction with one AFW flow indicator per steam generator is consistent with NUREG-0737, Item 11.E.1.2 (Reference 8). Wide range steam generator level is not a Type A variable.

SG Water Level (Wide Range) is used to:

verify that the intact SGs are an adequate heat sink for the reactor;

determine the nature of the accident in progress (e.g.,

verify SGTR); and

verify unit conditions for termination of SI during secondary unit HELBs outside containment.

13. Steam Generator Water Level (Narrow Range)

Steam Generator Water Level (Narrow Range) is a Type A, Category 1 variable for Steam Generator Tube Rupture event diagnosis and SI termination.

SG Water Level (Narrow Range) is used to:

identify the affected SG following a tube rupture;

determine the nature of the accident in progress (e.g.,

verify an SGTR); and

verify unit conditions for termination of SI during secondary unit HELBs outside containment.

14, 15, 16, 17. Core Exit Temperature Core exit temperature is a Category 1 variable which provides for verification and long term surveillance of core cooling.

An evaluation was made in support of Reference 2 of the minimum number of valid core exit thermocouples (GET) necessary for measuring core cooling. The evaluation determined the reduced complement of CETs necessary to detect initial core recovery and Wolf Creek - Unit 1 B 3.3.3-8 Revision 81

Containment Purge Isolation Instrumentation B 3.3.6 B 3.3 INSTRUMENTATION B 3.3.6 Containment Purge Isolation Instrumentation BASES BACKGROUND Containment purge isolation instrumentation closes the containment isolation valves in the Mini Purge System and the Shutdown Purge System. This action isolates the containment atmosphere from the environment to minimize releases of radioactivity in the event of an accident. The Mini Purge System may be in use during reactor operation and the Shutdown Purge System will be in use with the reactor shutdown.

Containment Purge Isolation initiates on an automatic or manual safety injection (SI) signal through the Containment Isolation - Phase A Function, or by manual actuation of Phase A Isolation. The Bases for LCO 3.3.2, "Engineered Safety Feature Actuation System (ESFAS) Instrumentation,"

discuss these modes of initiation.

Four safety related radiation monitoring channels are also provided as input to the containment purge isolation. The requirement for one Containment Atmosphere Gaseous Radioactivity monitor (GT RE-31 or

32) is addressed by Function 3 of Table 3.3.6-1. The requirement for one Containment Purge Radiation monitor (GT RE-22 or 33) is addressed in the Offsite Dose Calculation Manual (ODCM). Since the containment atmosphere monitors constitute a sampling system, various components such as sample line valves and sample pumps are required to support monitor OPERABILITY. Containment Purge Isolation can also be initiated by manual push buttons in the control room.

Each of the purge systems has inner and outer containment isolation valves in its supply and exhaust ducts. A high radiation signal from any one of the four radiation monitoring channels initiates containment purge isolation, which closes both inner and outer Containment Isolation Valves in the Mini Purge System and the Shutdown Purge System. These systems are described in the Bases for LCO 3.6.3, "Containment Isolation Valves."

APPLICABLE The safety analyses assume that the containment remains intact with SAFETY ANALYSES penetrations unnecessary for core cooling isolated early in the event. The isolation of the purge valves has not been analyzed mechanistically in the dose calculations, other than for the loss of coolant accident (isolation within 1O seconds of accident initiation).

Wolf Creek - Unit 1 B 3.3.6-1 Revision 81

Containment Purge Isolation Instrumentation B 3.3.6 BASES APPLICABLE The containment atmosphere radiation monitors act as backup to the SAFETY ANALYSES Phase A Isolation signal to ensure closing of the containment purge (continued) valves. They are also the primary means for automatically isolating containment in the event of a fuel handling accident during shutdown.

Containment isolation in turn ensures meeting the containment leakage rate assumptions of the safety analyses, and ensures that the calculated accidental offsite radiological doses are below 10 CFR 50.67 (Ref. 1) limits.

The containment purge isolation instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requirements ensure that the instrumentation necessary to initiate Containment Purge Isolation, listed in Table 3.3.6-1, is OPERABLE.

1. Manual Initiation The LCO requires two channels OPERABLE. The operator can initiate Containment Purge Isolation at any time by using either of two push buttons in the control room. Either push button actuates both trains. This action will cause actuation of all components in the same manner as any of the automatic actuation signals.

The LCO for Manual Initiation ensures the proper amount of redundancy is maintained in the manual actuation circuitry to ensure the operator has manual initiation capability.

Each channel consists of one push button and the interconnecting wiring to the actuation logic cabinet.

2. Automatic Actuation Logic and Actuation Relays (BOP ES FAS)

The LCO requires two trains of Automatic Actuation Logic and Actuation Relays OPERABLE to ensure that no single random failure can prevent automatic actuation of Containment Purge Isolation.

Automatic actuation logic and actuation relays consist of the same features and operate in the same manner as described for BOP ESFAS in the Bases Background for 3.3.2.

Wolf Creek - Unit 1 B 3.3.6-2 Revision 81

Containment Purge Isolation Instrumentation B 3.3.6 BASES SURVEILLANCE SR 3.3.6.5 REQUIREMENTS (continued) A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy. The Frequency is based on operating experience and is consistent with the typical industry refueling cycle.

SR 3.3.6.6 SR 3.3.6.6 is the performance of the required response time verification every 18 months on a STAGGERED TEST BASIS. Response time verification acceptance criteria for the containment purge isolation instrumentation is :<=::: 2 seconds. This response time acceptance criteria does not include valve closure time. Each verification shall include at least one train such that both trains are verified at least once per 36 months.

REFERENCES 1. 10 CFR 50.67.

2. NUREG-1366, July 22, 1993.

Wolf Creek - Unit 1 B 3.3.6-7 Revision 81

CREVS Actuation Instrumentation B 3.3.7 B 3.3 INSTRUMENTATION B 3.3.7 Control Room Emergency Ventilation System (CREVS) Actuation Instrumentation BASES BACKGROUND The CREVS provides an enclosed control room environment from which the unit can be operated following an uncontrolled release of radioactivity.

During normal operation, the Control Building Ventilation System provides control room ventilation. Upon receipt of an actuation signal, the CREVS initiates filtered ventilation and pressurization of the control room. This system is described in the Bases for LCO 3.7.10, "Control Room Emergency Ventilation System (CREVS)."

The actuation instrumentation consists of two radiation monitors in the control room air intake and four radiation monitors in the containment purge isolation system (refer to B 3.3.6 "Containment Purge Isolation Instrumentation" Background). A high radiation signal from any of these gaseous detectors will initiate both trains of the CREVS. The Containment Purge Isolation Instrumentation, however, is not listed as a Function for CREVS because appropriate actions are taken in LCO 3.3.6.

The control room operator can also initiate CREVS trains by manual push buttons in the control room. The CREVS is also actuated by a Phase A Isolation signal and a Fuel Building Ventilation Isolation signal. The Phase A Isolation Function is discussed in LCO 3.3.2, "Engineered Safety Feature Actuation System (ES FAS) Instrumentation." The Fuel Building Ventilation Isolation is not listed as a Function for CREVS because appropriate actions are taken in LCO 3.3.8, "EES Actuation Instrumentation."

APPLICABLE The control room must be kept habitable for the operators stationed SAFETY ANALYSES there during accident recovery and post accident operations.

The CREVS acts to terminate the supply of unfiltered outside air to the control room, initiate filtration, and pressurize the control room. These actions are necessary to ensure the control room is kept habitable for the operators stationed there during accident recovery and post accident operations by minimizing the radiation exposure of control room personnel.

In Modes 1, 2, 3, and 4, for a LOCA, a rod ejection with a breached reactor vessel head, and a main steamline break, a safety injection (SI) signal initiates a Phase A isolation actuation, which initiates a control room ventilation isolation signal (CRVIS). For these events, actuation of CREVS by the Control Room Air Gaseous Intake Radiation Monitors is a backup for the Phase A isolation signal acuation.

Wolf Creek - Unit 1 B 3.3.7-1 Revision 81

CREVS Actuation Instrumentation B 3.3.7 BASES APPLICABLE For a rod ejection without a breached reactor vessel head, a locked rotor, SAFETY ANALYSES and a steam generator tube rupture (SGTR), the Control Room Air (continued) Gaseous Intake Radiation Monitors are credited for initiating a CRVIS.

For the SGTR, the SI signal is a backup for the Control Room Air Gaseous Intake Radiation Monitors actuation. The analyses for the listed events assumes a response time of 60 seconds which accounts for the Control Room Ventilation Isolation ESF RESPONSE TIMES.

During movement of irradiated fuel assemblies, the radiation monitor actuatlbn of the CREVS is the primary means to ensure control room habitability in the event of a fuel handling accident. No control room habitability mitigation is required for the waste gas decay tank rupture accident.

The CREVS actuation instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requirements ensure that instrumentation necessary to initiate the CREVS is OPERABLE.

1. Manual Initiation The LCO requires two channels OPERABLE. The operator can initiate the CREVS at any time by using either of two push buttons in the control room. This action will cause actuation of all components in the same manner as any of the automatic actuation signals.

The LCO for Manual Initiation ensures the proper amount of redundancy is maintained in the manual actuation circuitry to ensure the operator has manual initiation capability.

Each channel consists of one push button and the interconnecting wiring to the actuation logic cabinet.

2. Automatic Actuation Logic and Actuation Relays (BOP ES FAS)

The LCO requires two trains of Actuation Logic and Relays OPERABLE to ensure that no single random failure can prevent automatic actuation of a control room ventilation isolation signal (CRVIS).

Automatic actuation logic and actuation relays consist of the same features and operate in the same manner as described for BOP ESFAS in the Bases Background for 3.3.2.

Wolf Creek - Unit 1 B 3.3.7-2 Revision 81

CREVS Actuation Instrumentation B 3.3.7 BASES SURVEILLANCE SR 3.3.7.6 REQUIREMENTS (continued) SR 3.3.7.6 is the performance of the required response time verification every 18 months on a STAGGERED TEST BASIS. Response time verification acceptance criteria for the CREVS actuation instrumentation is

. 60 seconds. Each verification shall include at least one train/channel such that both trains/channels are verified at least once per 36 months.

The 18-month Frequency is consistent with the typical refueling cycle and is based on unit operating experience, which shows that random failures of instrumentation components causing serious response degradation, but not channel failure, are infrequent occurrences.

SR 3.3.7.6 is modified by a Note stating that the radiation monitor detectors are excluded from ESF RESPONSE TIME testing. The Note is necessary because of the difficulty associated with generating an appropriate radiation monitor detector input signal. Excluding the detectors is acceptable because the principles of detector operation ensure a virtually instantaneous response. Response time of the channel shall be verified from the detector output or input to the first electronic component in the channel.

REFERENCES 1. USAR Section 7.3.4 and Table 7.3-8.

Wolf Creek - Unit 1 B 3.3.7-8 Revision 81

EES Actuation Instrumentation B 3.3.8 B 3.3 INSTRUMENTATION B 3.3.8 Emergency Exhaust System (EES) Actuation Instrumentation BASES BACKGROUND The EES ensures that radioactive materials in the fuel building atmosphere following a fuel handling accident are filtered and absorbed prior to exhausting to the environment. The EES is described in the Bases for LCO 3.7.13, "Emergency Exhaust System." The system initiates filtered exhaust from the fuel building following receipt of a fuel building ventilation isolation signal (FBVIS), initiated manually or automatically upon a high radiation signal (gaseous). Initiation may also be performed manually as needed from the main control room and the fuel building.

High gaseous radiation, monitored by two monitors (GGRE-27 and 28),

provides a FBVIS. Both EES trains are initiated by high radiation detected by either channel. Each channel contains a gaseous monitor.

High radiation detected by either monitor initiates fuel building isolation and starts the EES in the FBVIS mode of operation. These actions function to prevent exfiltration of contaminated air by initiating filtered exhaust, which imposes a negative pressure on the fuel building. Since the radiation monitors include an air sampling system, various components such as sample line valves, sample line heaters, and sample pumps are required to support monitor OPERABILITY.

APPLICABLE The EES ensures that radioactive materials in the fuel building SAFETY ANALYSES atmosphere following a fuel handling accident are filtered and absorbed prior to being exhausted to the environment. This action reduces the radioactive content in the fuel building exhaust following a fuel handling accident so that offsite doses remain well within the limits specified in 10 CFR 50.67 (Ref. 1). However, filtration through the EES was not credited for the fuel handling accident analysis (Ref. 4).

The EES actuation instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requirements ensure that instrumentation necessary to initiate the EES is OPERABLE.

Wolf Creek - Unit 1 B 3.3.8-1 Revision 81

EES Actuation Instrumentation B 3.3.8 BASES SURVEILLANCE SR 3.3.8.5 REQUIREMENTS (continued) A CHANNEL CALIBRATION is performed every 18 months, or approximately at every refueling. CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measure parameter within the necessary range and accuracy. The Frequency is based on operating experience and is consistent with the typical industry refueling cycle.

REFERENCES 1. 10 CFR 50.67.

/

2. Calculation J-G-SA02.

3. USAR Section 7.3.3 and Table 7.3-5.

4. USAR Section 15.7.4.

Wolf Creek - Unit 1 B 3.3.8-7 Revision 81

\

RCS Operational LEAKAGE B 3.4.13 BASES APPLICABLE Except for primary to secondary LEAKAGE, the safety analyses do not SAFETY ANALYSES address RCS operational LEAKAGE. However, the other forms of operational LEAKAGE are related to the safety analyses for LOCA; the amount of leakage can affect the probability of such an event. The safety analyses for events resulting in steam discharge to the atmosphere assume that primary to secondary LEAKAGE from all steam generators (SGs) is one gallon per minute as a result of accident induced conditions.

The LCO requirement to limit primary to secondary LEAKAGE through any one SG to less than or equal to 150 gallons per day is significantly less than the conditions assumed in the safety analysis.

Primary to secondary LEAKAGE is a factor in the dose releases outside containment resulting from a steam line break (SLB) accident. Other accidents or transients involving secondary steam release to the atmosphere, include the steam generator tube rupture (SGTR). The leakage contaminates the secondary flu.id.

The USAR (Ref. 3) analysis for SGTR assumes some of the contaminated secondary fluid is released via atmospheric relief valves.

The safety analysis for the SLB accident assumes the entire 1 gpm primary to secondary LEAKAGE is through the affected generator as an initial condition. The dose consequences resulting from the SLB and accidents involving secondary steam release to the atmosphere are within the limits defined in 10 CFR 50.67 (Ref. 5) and the Standard Review Plan (Ref. 8).

The safety analysis for RCS main loop piping for GDC-4 (Ref. 1) assumes 1 gpm unidentified leakage and monitoring per Regulatory Guide 1.45 (Ref. 2) are maintained (Ref. 4).

The RCS operational LEAKAGE satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO RCS operational LEAKAGE shall be limited to:

a. Pressure Boundary LEAKAGE No pressure boundary LEAKAGE is allowed, being indicative of material deterioration. LEAKAGE of this type is unacceptable as the leak itself could cause further deterioration, resulting in higher LEAKAGE. Violation of this LCO could result in continued degradation of the RCPB. LEAKAGE past seals and gaskets is not pressure boundary LEAKAGE.

Wolf Creek - Unit 1 B 3.4.13-2 Revision 81

RCS Operational LEAKAGE B 3.4.13 BASES SURVEILLANCE SR 3.4.13.2 (continued)

REQUIREMENTS secondary LEAKAGE limit ensures that the operational LEAKAGE performance criterion in the Steam Generator Program is met. If this SR is not met, compliance with LCO 3.4.17, "Steam Generator Tube Integrity," should be evaluated. The 150 gallons per day limit is measured at room temperature as described in Reference 7. The operational LEAKAGE rate limit applies to LEAKAGE through any one SG. If it is not practical to assign the LEAKAGE to an individual SG, all the primary to secondary LEAKAGE should be conservatively assumed to be from one SG.The Surveillance is modified by a Note which states that the Surveillance is not required to be performed until 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after establishment of steady state operation. For RCS primary to secondary LEAKAGE determination, steady state is defined as stable RCS pressure, temperature, power level, pressurizer and makeup tank levels, makeup and letdown, and RCP seal injection and return flows.

The Surveillance Frequency of 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months is a reasonable interval to trend primary to secondary LEAKAGE and recognizes the importance of early leakage detection in the prevention of accidents. The primary to secondary LEAKAGE is determined using continuous process radiation monitors or radiochemical grab sampling in accordance with the EPRI guidelines (Ref. 7).

REFERENCES 1. 10 CFR 50, Appendix A, GDC 4 and 30.

2. Regulatory Guide 1.45, May 1973.

3. USAR, Chapter 15.

4. NUREG-1061, Volume 3, November 1984.

5. 10 CFR 50.67.

6. NEI 97-06, "Steam Generator Guidelines."

7. EPRI, "Pressurized Water Reactor Primary-to-Secondary Leak Guidelines."

8. Standard Review Plan (SRP), Section 15.0.1.

Wolf Creek - Unit 1 B 3.4.13-6 Revision 81

RCS Specific Activity B3.4.16 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.16 RCS Specific Activity BASES BACKGROUND The maximum dose that an individual at the exclusion area boundary can receive for any 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months following an accident, or at the low population zone outer boundary for the radiological release duration, is specified in 10 CFR 50.67 (Ref. 1). Doses to control room operators must be limited per GDC 19. The limits on specific activity ensure that the offsite and control room doses are appropriately limited during analyzed transients -

and accidents.

The RCS specific activity LCO limits the allowable concentration level of radionuclides in the reactor coolant. The LCO limits are established to minimize the dose consequences in the event of a steam line break (SLB) or steam generator tube rupture (SGTR) accident.

The LCO contains specific activity limits for both DOSE EQUIVALENT 1-131 and DOSE EQUIVALENT XE-133. The allowable levels are intended to ensure that offsite and control room doses meet the appropriate acceptance criteria in the Standard Review Plan (Ref. 2).

APPLICABLE The LCO limits on the specific activity of the reactor coolant ensure that SAFETY ANALYSES the resulting offsite and control room doses meet the appropriate Standard Review Plan acceptance criteria following a SLB or SGTR accident. The safety analyses (Refs. 3 and 4) assume the specific activity of the reactor coolant is at or more conservative than the LCO limits, and a reactor coolant steam generator (SG) tube leakage rate of 1 gpm exists or results from accident induced conditions. The safety analyses assume the specific activity of the secondary coolant is at its limit of 0.1 µCi/gm DOSE EQUIVALENT 1-131 from LCO 3.7.18, "Secondary Specific Activity."

The analysis for the SLB and SGTR accidents establish the acceptance limits for RCS specific activity. Reference to these analyses is used to assess changes to the unit that could affect RCS specific activity, as they relate to the acceptance limits.

The analyse*s consider two cases of reactor coolant specific activity. One case assumes specific activity at 1.0 µCi/gm DOSE EQUIVALENT 1-131 with a concurrent large iodine spike that increases, by a factor of 500 for SLB and 335 for SGTR, the rate of release of iodine from the fuel rods containing cladding defects to the primary coolant immediately after a SLB or SGTR. The second case assumes the initial reactor coolant iodine I*

activity at 60 µCi/gm DOSE EQUIVALENT 1-131 due to a pre-accident Wolf Creek - Unit 1 B 3.4.16-1 Revision 81

RCS Specific Activity 83.4.16 BASES APPLICABLE iodine spike caused by an RCS transient. In both cases, the noble gas SAFETY ANALYSES activity is assumed to be equal to or greater than 500 µCi/gm DOSE (continued) EQUIVALENT XE-133.

The SGTR analysis also assumes a loss of offsite power at the same time as the reactor trip. The SGTR causes a reduction in reactor coolant inventory. The reduction initiates a reactor trip from an Overtemperature Ll T signal.

The loss of offsite power causes the steam dump valves to close to protect the condenser. The rise in pressure in the ruptured SG discharges radioactively contaminated steam to the atmosphere through the SG atmospheric relief valves. The unaffected SGs remove core decay heat by venting steam to the atmosphere until the cooldown ends and the Residual Heat Removal (RHR) System is placed into service.

The SLB radiological analysis assumes that offsite power is lost at the same time as the pipe break occurs outside containment. Reactor trip occurs after the generation of an SI signal on low steam line pressure.

The affected SG blows down completely and steam is vented directly to the atmosphere. The unaffected SGs remove core decay heat by venting steam to the atmosphere until the cooldown ends and the RHR System is placed in service.

Operation with iodine specific activity levels greater than the LCO limit is permissible if the activity levels do not exceed 60 µCi/gm for more than 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

The limits on RCS specific activity are also used for establishing standardization in radiation shielding and plant personnel radiation protection practices.

RCS specific activity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

Wolf Creek - Unit 1 B 3.4.16-2 Revision 81

RCS Specific Activity B 3.4.16 BASES SURVEILLANCE SR 3.4.16.1 (continued)

REQUIREMENTS The Note modifies this SR to allow entry into and operating in MODE 4, MODE 3, and MODE 2 prior to performing the SR. This allows the Surveillance to be performed in those MODES, prior to entering MODE 1.

SR 3.4.16.2 This Surveillance is performed to ensure iodine specific activity remains within the LCO limit during normal operation and following fast power changes when iodine spiking is more apt to occur. The 14 day Frequency is adequate to trend changes in the iodine activity level, considering noble gas activity is monitored every 7 days. The Frequency, between 2 and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after a power change ~ 15% RTP within a 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months period, is established because the iodine levels peak during this time following iodine spiking information; samples at other times would provide inaccurate results.

The Note modifies this SR to allow entry into and operation in MODE 4, MODE. 3, and MODE 2 prior to performing the SR. This allows the Surveillance to be performed in those MODES, prior to entering MODE 1.

REFERENCES 1. 10 CFR 50.67.

2. Standard Review Plan (SRP), Section 15.0.1.

3. USAR Section 15.1.5.

4. USAR, Section 15.6.3.

Wolf Creek - Unit 1 B 3.4.16-5 Revision 81 I.

I

SG Tube Integrity B 3.4.17 BASES APPLICABLE The steam generator tube rupture (SGTR) accident is the limiting design SAFETY .basis event for SG tubes and avoiding an SGTR is the basis for this ANALYSES Specification. The analysis of an SGTR event assumes a bounding primary to secondary LEAKAGE rate from all SGs of 1 gpm, plus the leakage rate associated with a double-ended rupture of a single tube.

The accident analysis for an SGTR assumes some of the contaminated secondary fluid is released to the atmosphere via SG atmospheric relief valves and safety valves.

The analysis for design basis accidents and transients other than an SGTR assume the SG tubes retain their structural integrity (i.e., they are assumed not to rupture.) In these analyses, the discharge to the atmosphere is based on the total primary to secondary LEAKAGE from all SGs of 1 gallon per minute as a result of accident induced conditions. For accidents that do not involve fuel damage, the primary coolant activity level of DOSE EQUIVALENT 1-131 is assumed to be equal to the LCO 3.4.16, "RCS Specific Activity," limits. For accidents that assume fuel damage, the primary coolant activity is a function of the amount of activity released from the damaged fuel. The dose consequences of these events are within the limits of GDC 19 (Ref. 2), 10 CFR 50.67 (Ref. 3) and the Standard Review Plan (Ref. 8).

Steam generator tube integrity satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO The LCO requires that SG tube integrity be maintained. The LCO also requires that all SG tubes that satisfy the plugging criteria be plugged in accordance with the Steam Generator Program.

During a SG inspection, any inspected tube that satisfies the Steam Generator Program plugging criteria is removed from service by plugging.

If a tube was determined to satisfy the plugging criteria but was not plugged, the tube may still have tube integrity.

In the context of this Specification, a SG tube is defined as the entire length of the tube, including the tube* wall, between the tube-to-tubesheet weld at the tube inlet and the tube-to-tubesheet weld at the tube outlet. A permanent alternate plugging criterion for the portion of the tube below 15.21 inches from the top of the tubesheet is specified in TS 5.5.9c.1.

(Ref. 7) The tube-to-tubesheet weld is not considered part of the tube.

Wolf Creek - Unit 1 B 3.4.17-2 Revision 81

I SG Tube Integrity B 3.4.17 BASES LCO The accident induced leakage performance criterion ensures that the (continued) primary to secondary LEAKAGE caused by a design basis accident, other than a SGTR, is within the accident analysis assumptions. The a.ccident analysis assumes that accident induced leakage does not exceed 1 gpm total to all SGs. The accident induced leakage rate includes any primary to secondary LEAKAGE existing prior to the accident in addition to primary to secondary LEAKAGE induced during the accident.

The operational LEAKAGE performance criterion provides an observable indication of SG tube conditions during plant operation. The limit on

operational LEAKAGE is contained in LCO 3.4.13, "RCS Operational LEAKAGE," and limits primary to secondary LEAKAGE through any one SG to 150 gallons per day. This limit is based on the assumption that a single crack leaking this amount would not propagate to an SGTR under the stress conditions of a LOCA or a main steam line break. If this amount of LEAKAGE is due to more than one crack, the cracks are very small, and the above assumption is conservative.

APPLICABILITY Steam generator tube integrity is challenged when the pressure differential across the tubes is large. Large differential pressures across SG tubes can only be experienced in MODE 1, 2, 3, or 4.

RCS conditions are far less challenging in MODES 5 and 6 than during MODES 1, 2, 3, and 4. In MODES 5 and 6, primary to secondary differential pressure is low, resulting in lower stresses and reduced potential for LEAKAGE.

ACTIONS The ACTIONS are modified by a Note clarifying that the Conditions may be entered independently for each SG tube. This is acceptable because the Required Actions provide appropriate compensatory actions for each affected SG tube. Complying with the Required Actions may allow for continued operation, and subsequent affected SG tubes are governed by subsequent Condition entry and application of associated Required Actions.

A.1 and A.2 Condition A applies if it is discovered that one or more SG tubes examined in an inservice inspection satisfy the tube plugging criteria but were not plugged in accordance with the Steam Generator Program as required by SR 3.4.17.2. An evaluation of SG tube integrity of the affected tube(s) must be made. Steam generator tube integrity is Wolf Creek - Unit 1 83.4.17-4 Revision 81

SG Tube Integrity B 3.4.17 BASES SURVEILLANCE SR 3.4.17.2 (continued)

REQUIREMENTS The Frequency of prior to entering MODE 4 following a SG inspection ensures that the Surveillance has been completed and all tubes meeting the plugging criteria are plugged prior to subjecting the SG tubes to significant primary to secondary pressure differential.

REFERENCES 1. NEI 97-06, "Steam Generator Program Guidelines."

2. 10 CFR 50 Appendix A, GDC 19.

3. 10 CFR 50.67.

4. ASME Boiler and Pressure Vessel Code, Section 111, Subsection NB. /

5. Draft Regulatory Guide 1.121, "Basis for Plugging Degraded Steam Generator Tubes," August 1976.

6. EPRI, "Pressurized Water Reactor Steam Generator Examination Guidelines."

7. License Amendment No. 201, December 11, 2012.

8. Standard Review Plan (SRP), Section 15.0.1.

Wolf Creek - Unit 1 B 3.4.17-7 Revision 81

Containment B 3.6.1 BASES BACKGROUND 2. closed by manual valves, blind flanges, or de-activated (continued) automatic valves secured in their closed positions, except as provided in LCO 3.6.3, "Containment Isolation Valves"

b. Each air lock is OPERABLE, except as provided in LCO 3.6.2, "Containment Air Locks";

c. All equipment hatches are closed and sealed; and

d. The sealing mechanism associated with a penetration (e.g. welds, bellows, or 0-rings) is OPERABLE.

APPLICABLE The safety design basis for the containment is that the containment must SAFETY ANALYSES withstand the pressures and temperatures of the limiting OBA without exceeding the design leakage rate.

The DBAs that result in a challenge to containment OPERABILITY from high pressures and temperatures are a loss of coolant accident (LOCA) and a steam line break (Ref. 2). In addition, release of significant fission product radioactivity within containment can occur from a LOCA or Rod Ejection Accident (REA). In the OBA analyses, it is assumed that the containment is OPERABLE such that, for the DBAs involving release of fission product radioactivity, release to the environment is controlled by the rate of containment leakage. The containment was designed with an allowable leakage rate of 0.20% of containment air weight per day for the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months and 0.10% thereafter (Ref. 3). This leakage rate, used to evaluate offsite and control room doses resulting from accidents, is defined in 10 CFR 50, Appendix J, Option B (Ref. 1), as La: the maximum allowable containment leakage rate at the calculated peak containment internal pressure (Pa) resulting from the limiting design bases LOCA. The allowable leakage rate represented by La forms the basis for the acceptance criteria imposed on all containment leakage rate testing. La is assumed to be 0.20% of containment air weight per day in the safety analysis at Pa= 48 psig (Ref. 3).

Satisfactory leakage rate test results are a requirement for the establishment of containment OPERABILITY.

The containment satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO Containment OPERABILITY is maintained by limiting leakage to:-;:; 1.0 La, except prior to the first startup after performing a required Containment Wolf Creek - Unit 1 B 3.6.1-2 Revision 81

Containment Air Locks B 3.6.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.2 Containment Air Locks BASES BACKGROUND Containment air locks form part of the containment pressure boundary and provide a means for personnel access during all MODES of operation.

The personnel air lock is nominally a right circular cylinder, approximately 10 ft in diameter, with a door at each end. The emergency air lock is approximately 5 ft inside diameter with a 2 ft 6 inch door at each end. On both air locks, doors are interlocked to prevent simultaneous opening.

During periods when containment is not required to be OPERABLE, the door interlock mechanism may be disabled, allowing both doors of an air lock to remain open for extended periods when frequent containment entry is necessary. Each air lock door has been designed and tested to certify its ability to withstand a pressure in excess of the maximum expected pressure following a Design Basis Accident (OBA) in containment. As such, closure of a single door supports containment OPERABILITY. Each of the doors contains double gasketed seals and local leakage rate testing capability to ensure pressure integrity. To effect a leak tight seal, the air lock design uses pressure seated doors (i.e., an increase in containment internal pressure results in increased sealing force on each door).

Each air lock is provided with limit switches on both doors that provide local indication of door position.

The containment air locks form part of the containment pressure boundary. As such, air lock integrity and leak tightness is essential for maintaining the containment leakage rate within limit in the event of a OBA. Not maintaining air lock integrity or leak tightness may result in a leakage rate in excess of that assumed in the safety analyses.

APPLICABLE The DBAs that result in a release of radioactive material within SAFETY ANALYSES containment are a loss of coolant accident and rod ejection accident (Ref. 2). In the analysis of this accident, it is assumed that containment is OPERABLE such that release of fission products to the environment is controlled by the rate of containment leakage. The containment was designed with an allowable leakage rate of 0.20% of containment air weight per day (Ref. 2). This leakage rate is defined in 10 CFR 50, Appendix J, Option B, (Ref. 1), as La = 0.20% of containment air weight per day, the maximum allowable Wolf Creek - Unit 1 B 3.6.2-1 Revision 81

Containment Isolation Valves B 3.6.3 BASES BACKGROUND within containment prior to and during personnel access. The supply and (continued) exhaust lines each contain two isolation valves. Because of their large size, the 36 inch containment purge supply and exhaust valves are not qualified for automatic closure from their open position under DBA conditions. Therefore, the 36 inch containment purge supply and exhaust isolation valves are normally maintained closed and blind flange installed or sealed closed in MODES 1, 2, 3, and 4 to ensure the containment boundary is maintained.

Mini-Purge System (18 inch purge valves)

The Mini-purge System operates to:

a. Reduce the concentration of noble gases within containment prior to and during personnel access, and

b. Equalize containment internal and external pressures.

Since the 18 inch valves used in the Mini-purge System are designed to meet the requirements for automatic containment isolation valves, these valves may be opened as needed, for a limited time as specified in procedures, in MODES 1, 2, 3, and 4.

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

The DBAs that result in a release of radioactive material within containment are a loss of coolant accident (LOCA) and a rod ejection accident (Ref. 1). In the analyses for each of these accidents, it is assumed that containment isolation valves are either closed or function to close within the required isolation time following event initiation. This ensures that potential paths to the environment through containment isolation valves (including containment purge valves) are minimized. The safety analyses assume that the 36 inch. shutdown purge valves are closed at event initiation.

The DBA analysis assumes that, after the accident, isolation of the containment is complete and leakage terminated except for the design leakage rate, La-Wolf Creek - Unit 1 B 3.6.3-2 Revision 81

Containment Isolation Valves B 3.6.3 BASES APPLICABLE The LOCA and rod ejection offsite dose analyses assumes leakage from SAFETY ANALYSES the containment at a maximum leak rate of 0.20 percent of the (continued) containment volume per day for the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months , and at 0.10 percent of the containment volume per day for the duration of the accident.

The single failure criterion required to be imposed in the conduct of plant safety analyses was considered in the original design of the 18 inch containment mini-purge valves. Two valves in series on each purge line provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred. The inboard and outboard isolation valves on each line are provided with independent electrical power sources to solenoids that open the pneumatically operated spring closed actuators. The actuators fail closed on the loss of power or air.

This arrangement was designed to preclude common mode failures from disabling both valves on a purge line.

The 36 inch purge valves may be unable to close against the buildup of pressure following a LOCA. Therefore, each of the purge valves is required to remain sealed closed or closed and blind flange installed during MODES 1, 2, 3, and 4. The Containment Shutdown Purge System valve design precludes a single failure from compromising the containment boundary as long as the system is operated in accordance with the subject LCO.

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

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

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

The automatic power operated isolation valves are required to have isolation times within limits and to actuate on an automatic isolation signal.

The 36 inch containment purge supply and exhaust valves must be maintained sealed closed or closed and blind flange installed. The valves covered by this LCO are listed along with their associated stroke times in the USAR (Ref. 2).

The normally closed containment isolation valves are considered OPERABLE when manual valves are closed, automatic valves are de-activated and secured in their closed position, blind flanges are in place, and closed systems are intact. These passive isolation valves/devices are those listed in Reference 2.

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Containment Spray and Cooling Systems B 3.6.6 B 3.6 CONTAINMENT SYSTEMS B 3.6.6 Containment Spray and Cooling Systems BASES BACKGROUND The Containment Spray and Containment Cooling 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 fission product removal capability of the spray reduces the release of fission product radioactivity from containment to the environment, in the event of a Design Basis Accident (OBA), to within limits. The Containment Spray and Containment Cooling 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," and GDC 50, "Containment Design Bases" (Ref. 1).

The Containment Cooling System and Containment Spray System are Engineered Safety Feature (ESF) systems. They are designed to ensure that the heat removal capability required during the post accident period can be attained. The Containment Spray System and the Containment Cooling System provides a redundant method to limit and maintain post accident conditions to less than the containment design values.

Containment Spray System The Containment Spray System consists of two separate trains of equal capacity, each capable of meeting the design bases. Each train includes a containment spray pump, spray headers, nozzles, valves, and piping.

Each train is powered from a separate 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 sumps.

The Containment Spray System provides a spray of borated water mixed with sodium hydroxide (NaOH) from the Spray Additive System into the upper regions of containment to reduce the containment pressure and temperature and to reduce fission products from the containment atmosphere during a OBA. 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 recirculation sump water by the residual heat removal heat exchangers.

Each train of the Containment Spray System provides adequate spray Wolf Creek - Unit 1 B 3.6.6-1 Revision 81

Containment Spray and Cooling Systems B 3.6.6 BASES APPLICABLE The modeled Containment Spray System actuation from the containment SAFETY ANALYSES analysis is based on a response time associated with exceeding the (continued) containment High-3 pressure setpoint to achieving full flow through the containment spray nozzles.

The Containment Spray System total response time includes diesel generator (DG) startup (for loss of offsite power), sequenced loading of equipment, containment spray pump startup, and spray line filling (Ref. 4).

Containment cooling train performance for post accident conditions is given in Reference 4. The result of the analysis is that each train can provide 100% of the required peak cooling capacity during the post accident condition. The train post accident cooling capacity under varying containment ambient conditions, required to perform the accident analyses, is also shown in Reference 4.

The modeled Containment Cooling System actuation from the containment analysis is based upon a response time associated with receipt of an SI signal to achieving full Containment Cooling System air and safety grade cooling water flow. The Containment Cooling System total response time of 70 seconds, includes signal delay, DG startup (for loss of offsite power), and Essential Service Water pump startup times and line refill (Ref. 4).

The Containment Spray System and the Containment Cooling System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO During a DBA, a minimum of one containment cooling train and one containment spray train is required to maintain the containment peak pressure and temperature below the design limits (Ref. 3). Additionally, one containment spray train is also required to remove fission products from the containment atmosphere and maintain concentrations below those assumed in the safety analysis. With ~he Spray Additive System inoperable, a containment spray train is still available and would remove some fission products from the containment atmosphere in the event of a DBA. To ensure that these requirements are met, two containment spray trains and two containment cooling trains must be OPERABLE.

Therefore, in the event of an accident, at least one train in each system operates, assuming the worst case single active failure occurs.

i Each Containment Spray System typically includes a spray pump, spray

' i headers, eductor, nozzles, valves, piping, instruments, and controls to I ensure an OPERABLE flow path capable of taking suction from the RWST upon an ESF actuation signal and manually transferring to the containment sump. Management of gas voids is important to Containment Spray System OPERABILITY.

A containment cooling train typically includes cooling coils, dampers, two fans, instruments, and controls to ensure an OPERABLE flow path.

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Spray Additive System B 3.6.7 BASES APPLICABLE The Spray Additive System is essential to the removal of airborne iodine SAFETY ANALYSES within containment following a OBA and the retention of that iodine in the containment sump.

Following the assumed release of radioactive materials into containment, the containment is assumed to leak at its design value volume following the accident. The analysis assumes that 85% of the containment free volume is covered by the spray (Ref. 1).

The OBA analysis credit for iodine removal by Containment Spray System is taken, starting at two minutes and continuing until five hours have elapsed.

The OBA analyses assume that one train of the Containment Spray System/Spray Additive System is inoperable and that the entire spray additive tank volume is added to the remaining Containment Spray System flow path.

The Spray Additive System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO The Spray Additive System is necessary to reduce the release of radioactive material to the environment in the event of a OBA. To be considered OPERABLE, the volume and concentration of the spray additive solution must be sufficient to provide NaOH injection into the spray flow to raise the average long term containment sump solution pH to a level conducive to iodine removal and retention, namely, to between 8.5 and 11.0. This pH range maximizes the effectiveness of the iodine removal and retention mechanism without introducing conditions that may induce caustic stress corrosion cracking of mechanical system components.

The Spray Additive System typically includes a spray additive tank, eductors, valves, instrumentation, and connected piping to ensure OPERABLE flow paths. In addition, it is essential that valves in the Spray Additive System flow paths are properly positioned and that automatic valves are capable of activating to their correct positions.

APPLICABILITY In MODES 1, 2, 3, and 4, a OBA could cause a release of radioactive material to containment requiring the operation of the Spray Additive System. The Spray Additive System assists in reducing the iodine fission product inventory prior to release to the environment.

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

Wolf Creek - Unit 1 B 3.6.7-2 Revision 81

Spray Additive System B 3.6.7 BASES ACTIONS If the Spray Additive System is inoperable, it must be restored to OPERABLE within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months . The pH adjustment of the Containment Spray System flow for corrosion protection and iodine removal enhancement is reduced in this condition. The Containment Spray System would still be available and would remove some fission products from the containment atmosphere in the event of a DBA. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time takes into account the redundant flow path capabilities and the low probability of the worst case DBA occurring during this period.

B.1 and B.2 If the Spray Additive System 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 Time of 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging plant systems. The extended interval to reach MODE 5 allows 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months for restoration of the Spray Additive System in MODE 3 and 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months to reach MODE 5. This is reasonable when considering the reduced pressure and temperature conditions in MODE 3 for the release of radioactive material from the Reactor Coolant System.

SURVEILLANCE SR 3.6.7.1 REQUIREMENTS Verifying the correct alignment of Spray Additive System manual, power operated, and automatic valves in the spray additive flow path provides assurance that the system is able to provide additive to the Containment Spray System in the event of a DBA. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves were verified to be in the correct position prior to locking, sealing, or securing. This SR does not apply to manual vent/drain valves, and to valves that cannot be inadvertently misaligned such as check valves.

This SR does not require any testing or valve manipulation. Rather, it involves verification, through a system walkdown (which may include the use of local or remote indicators), that those valves outside containment and capable of potentially being mispositioned are in the correct position.

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

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Spray Additive System B 3.6.7 BASES SURVEILLANCE SR 3.6.7.2 REQUIREMENTS (continued) To provide effective iodine removal and retention, the containment spray must be an alkaline solution. Since the RWST contents are normally acidic, the volume of the spray additive tank must provide a sufficient volume of spray additive to adjust pH for all water injected. This SR is performed to verify the availability of sufficient NaOH solution in the Spray Additive System. The spray additive tank site glass (ENLG0022) is utilized for meeting the SR since the control room level indicators do not provide conservative indication (Ref. 2). The 184 day Frequency was developed based on the low probability of an undetected change in tank volume occurring during the SR interval (the tank is isolated during normal unit operations). (Ref. 3).

SR 3.6.7.3 This SR provides verification of the NaOH concentration in the spray additive tank and is sufficient to ensure that the spray solution being injected into containment is at the correct pH level. The 184 day Frequency is sufficient to ensure that the concentration level of NaOH in the spray additive tank remains within the established limits. This is based on the low likelihood of an uncontrolled change in concentration (the tank is normally isolated) and the probability that any substantial variance in tank volume will be detected.

SR 3.6.7.4 This SR provides verification that each automatic valve in the Spray Additive System flow path actuates to its correct position upon receipt of an actual or simulated actuation of a containment High-3 pressure 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 plant 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 was concluded to be acceptable from a reliability standpoint.

SR 3.6.7.5 To ensure correct pH level is established in the borated water solution provided by the Containment Spray System, the flow rate in the Spray Additive System is verified once every 5 years. Flow of~ 52 gpm through the eductor test loops (supplied from the RWST) is throttled to 17 psig at Wolf Creek - Unit 1 B 3.6.7-4 Revision 81

MSIVs and MSIV Bypass Valves B 3.7.2 BASES LCO sources must be removed from the actuation solenoids on all four MSIVs (continued)

and a drain or vent path must be available from the lower piston chamber.

Note 2 allows one or more MSIV bypass valve to be inoperable when closed and de-activated, closed and isolated by a closed manual valve, or isolated by two closed manual valves. When one or more MSIV bypass valves are closed and de-activated, closed and isolated by a closed manual valve, or isolated by two closed manual valves, they are performing their specified safety function. When the valve is de-activated,

. power and air are removed from both actuation solenoid valves and the valve is spring closed. Requiring the MSIV bypass valve to be closed and isolated by a closed manual valve or isolated by two closed manual valves also provides the dual assurance that the specified safety function is being performed.

This LCO provides assurance that the MSIVs and MSIV bypass valves will perform their design safety function to mitigate the consequences of accidents that could result in offsite exposures comparable to the 10 CFR 50.67 (Ref. 4) limits or the NRC staff approved licensing basis.

APPLICABILITY The MSIVs and MSIV bypass valves must be OPERABLE in MODE 1, and in MODES 2 and 3 due to significant mass and energy in the RCS and steam generators. When the MSIVs and MSIV bypass valves are closed, they are already performing the safety function. The MSIV actuator trains must be OPERABLE in MODES 1, 2, and 3 to support operation of the MSIV.

In MODE 4, 5 or 6, the steam generator energy is low. Therefore, the MSIVs and MSIV bypass valves are not required for isolation of potential high energy secondary system pipe breaks in these MODES.

ACTIONS The LCO specifies OPERABILITY requirements for the MS IVs as well as for their associated actuator trains. The Conditions and Required Actions for TS 3.7.2 separately address inoperability of the MSIV actuator trains and inoperability of the MS IVs themselves.

With a single actuator train inoperable on one MSIV, action must be taken to restore the inoperable actuator train to OPERABLE status within 7 days. The 7-day Completion Time is reasonable in light of the dual-redundant actuator train design such that with one actuator train inoperable, the affected MSIV is still capable of closing on demand via the Wolf Creek - Unit 1 B 3.7.2-4 Revision 81

MSIVs and MSIV Bypass Valves B 3.7.2 BASES REFERENCES 1. USAR, Section 10.3.

2. USAR, Section 6.2.

3. USAR, Section 15.1.5.

4. 10 CFR 50.67.

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ARVs B 3.7.4 BASES APPLICABLE In the accident analysis presented in Reference 2, the ARVs are assumed SAFETY ANALYSES to be used by the operator to cool down the unit to RHR entry conditions (continued) for accidents accompanied by a loss of offsite power. The main steam safety valves (MSSVs) are assumed to operate automatically to relieve steam and maintain the steam generator pressure below the design value.

For the recovery from a steam generator tube rupture (SGTR) event in Reference 3, the operator is required to perform an RCS cooldown using all available intact steam generators to establish adequate subcooling as a necessary step to terminate the primary to secondary break flow into the ruptured steam generator. The time required to terminate the primary to secondary break flow for an SGTR is more critical than the time required to cool down to RHR conditions for this event and also for other accidents.

Thus, the SGTR is the limiting event for the ARVs. The number of ARVs required to be OPERABLE to satisfy the SGTR accident analysis requirements is four. If a single failure of one occurs and another is associated with the ruptured SG, two ARVs would remain OPERABLE for heat removal and RCS cooldown. This failure is less limiting than the failure considered in Reference 3.

The ARVs are equipped with block valves in the event an ARV spuriously fails open or fails to close during use.

The ARVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

-I LCO Four ARV lines are required to be OPERABLE. One ARV line is required from each of four steam generators to ensure that at least two ARV lines are available to conduct a RCS cooldown following an SGTR, in which one steam generator becomes unavailable due to a SGTR, accompanied by a single, active failure of a second ARV line on an unaffected steam generator. The block valves must be OPERABLE to isolate a failed open ARV line.

Failure to meet the LCO can result in the inability to achieve subcooling, consistent with the assumptions used in the steam generator tube rupture analysis, to facilitate equalizing pressures between the Reactor Coolant System and the ruptured steam generator.

An ARV is considered OPERABLE when it is capable of providing controlled relief of the main steam flow and capable of fully opening and closing on demand and not experiencing excessive seat leakage.

Excessive seat leakage, although not associated with a specific Wolf Creek - Unit 1 B 3.7.4-2 Revision 81

CREVS B3.7.10 BASES BACKGROUND Outside air is filtered, diluted with air from the electrical equipment and (continued) cable spreading rooms, and added to the air being recirculated from the CRE. Pressurization of the CRE prevents infiltration of unfiltered air from the surrounding areas of the building.

The air entering the CBE during normal operation is continuously monitored by radiation and smoke detectors. A high radiation signal initiates the CRVIS; the smoke detectors provide an alarm in the control room. A CRVIS is initiated by the radiation monitors (GKRE0004 and GKRE0005), fuel building ventilation isolation signal, containment isolation phase A, containment atmosphere radiation monitors (GTRE0031 and GTRE0032), containment purge exhaust radiation monitors (GTRE0022 and GTRE0033), or manually.

A single CREVS train operating in the CREVS alignment established by surveillance procedures will pressurize the control room to ~ 0.25 inches water gauge. The CREVS operation in maintaining the CRE habitable is discussed in the USAR, Section 6.4 and 9.4 (Ref. 1).

Either of the pressurization and recirculation trains provide the required filtration and pressurization to the CRE. Normally open isolation dampers are arranged in series pairs so that the failure of one damper to shut will not result in a breach of isolation. The CREVS is designed in accordance with Seismic Category I requirements.

The CREVS is designed to maintain a habitable environment in the CRE for 30 days of continuous occupancy after a Design Basis Accident (OBA)

(Ref. 2) without exceeding a dose of 5 rem total effective dose equivalent (Ref. 10).

By operation of the control room pressurization trains and the control room filtration units, the CREVS pressurizes, recirculates and filters air within the CRE as well as the CBE that generally surrounds the CRE. The boundaries of these two distinct but related volumes are credited in the analysis of record for limiting the inleakage of unfiltered outside air.

The station CRE design is unique. The Control Building by and large surrounds the CRE. The Control Building is also designed to be at a positive pressure with respect to its surrounding environment although not positive with respect to the CRE. In the emergency pressurization and filtration mode, the control room air volume receives air through a filtration system that takes a suction on the Control Building. The Control Building in turn receives filtered air from the outside environment.

Wolf Creek - Unit 1 B3.7.10-2 Revision 81

CREVS B 3.7.10 BASES BACKGROUND The CRE is the area within the confines of the CRE boundary that (continued) contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions. This area encompasses the control room, and may encompass other non-critical areas to which frequent personnel access or continuous occupancy is not necessary in the event of an accident. The CRE is protected during normal operation, natural events, and accident conditions. The CRE boundary is the combination of walls, floor, roof, ducting, doors, penetrations and equipment that physically form the CRE. The CRE boundary must be maintained to ensure that the inleakage of unfiltered air into the CRE will not exceed the inleakage assumed in the licensing basis analysis of design basis accident (OBA) consequences to CRE occupants. The CRE and its boundary are defined in the Control Room Envelope Habitability Program.

The CBE is an area that largely surrounds the CRE. Occupancy of the CBE is not required to control the unit during normal and accident conditions. The CBE boundary is the combination of walls, floor, roof, ducting, doors, penetrations and equipment that physically form the CBE.

The CBE boundary must be maintained to ensure that the inleakage of unfiltered air into the CBE will not exceed the inleakage assumed in the licensing basis analysis of OBA consequences to CRE occupants. The CBE and its boundary are defined in the Control Room Envelope Habitability Program.

APPLICABLE The CREVS components are arranged in redundant, safety related SAFETY ANALYSES ventilation trains. The location of components and ducting within the CRE ensures an adequate supply of filtered air to all areas requiring access.

The CREVS provides airborne radiological protection for the CRE occupants, as demonstrated by the CRE occupant dose analyses for the most limiting design basis accident, fission product release presented in the USAR, Chapter 15 (Ref. 2).

(

The CREVS provides protection from smoke and hazardous chemicals to the CRE occupants. The analysis of hazardous chemical releases (Ref.

7) determined that hazardous chemicals are not stored or used onsite in quantities sufficient to necessitate CRE protection as required by Regulatory Guide 1.78 (Ref. 8). The evaluation of a smoke challenge demonstrates that it will not result in the inability of the CRE occupants to control the reactor either from the control room or from the remote shutdown panels (Ref. 1). The analysis for smoke and hazardous chemicals has determined no CREVS actuation for such events.

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

The CREVS satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

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CREVS B 3.7.10 BASES LCO Two independent and redundant CREVS trains are required to be OPERABLE to ensure that at least one is available if a single active failure disables the other train. Total system failure, such as from a loss of both ventilation trains or from an inoperable CRE or CBE boundary, could result in exceeding a dose of 5 rem total effective dose equivalent to the CRE occupants in the event of a large radioactive release.

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

a. Recirculation and pressurization fans are OPERABLE;

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

c. Heater, moisture separator, ductwork, valves, and dampers are OPERABLE, and air circulation can be maintained; and

d. Control Room Air Conditioning flow path integrity is maintained.

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

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

Note that the Control Room Air Conditioning System (CRACS) forms a subsystem to the CREVS. The CREVS remains capable of performing its safety function provided the CRACS air flow path is intact and air circulation can be maintained. Isolation or breach of the CRACS air flow path can also render the CREVS flow path inoperable. In these situations LCOs 3.7.10 and 3.7.11 may be applicable.

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CREVS B 3.7.10 BASES APPLICABILITY lri MODES 1, 2, 3, and 4, and during movement of irradiated fuel assemblies, the CREVS must be OPERABLE to ensure that the CRE will remain habitable during and following a OBA.

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

ACTIONS When one CREVS train is inoperable for reasons other than an inoperable CRE or CBE boundary, action must be taken to restore OPERABLE status within 7 days. In this Condition, the remaining OPERABLE CREVS train is adequate to perform the CRE occupant protection function. However, the overall reliability is reduced because a failure in the OPERABLE CREVS train could result in loss of CREVS function. The 7 day Completion Time is based on the low probability of a OBA occurring during this time period, and ability of the remaining train to provide the required capability.

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

During the period that the CRE or CBE boundary is considered inoperable, action must be initiated to implement mitigating actions to lessen the effect on CRE occupants from the potential hazards of a radiological or chemical event or a challenge from smoke. Actions must be taken within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months to verify that in the event of a OBA, the mitigating actions will ensure that CRE occupant radiological exposures will not exceed the calculated dose of the licensing basis analyses of OBA consequences, and that CRE occupants are protected from hazardous Wolf Creek - Unit 1 B 3.7.10-5 Revision 81

CREVS B 3.7.10 BASES SURVEILLANCE SR 3.7.10.2 REQUIREMENTS (continued) This SR verifies that the required CREVS testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The CREVS filter tests use the procedure guidance in Regulatory Guide 1.52, Rev. 2 (Ref. 3) in accordance with the VFTP. The VFTP includes testing the performance of the HEPA filter, charcoal absorber efficiency, minimum flow rate, and the physical properties of the activated charcoal.

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

SR 3.7.10.3 This SR verifies that each CREVS train starts and operates on an actual or simulated CRVIS. The actuation signal includes Control Room Ventilation or High Gaseous Radioactivity. The CREVS train automatically switches on an actual or simulated CRVIS into a CRVIS mode of operation with flow through the HEPA filters and charcoal adsorber banks. The Frequency of 18 months is consistent with a typical operating cycle. 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 3.7.10.4 This SR verifies the OPERABILITY of the CRE and CBE boundaries credited in the accident analysis by testing for unfiltered air inleakage past the credited envelope boundaries and into the CRE. The details of the testing are specified in the Control Room Envelope Habitability Program.

The CRE is considered habitable when the radiological dose to CRE occupants calculated in the licensing basis analyses of OBA consequences is no more than 5 rem total effective dose equivalent and the CRE occupants are protected from hazardous chemicals and smoke.

For WCGS, there is no CREVS actuation for hazardous chemical releases or smoke and there are no Surveillance Requirements that verify OPERABILITY for hazardous chemicals or smoke. This SR verifies that the unfiltered air inleakage into the CRE and CBE boundaries is no greater than the flow rate assumed in the licensing basis analyses of OBA consequences. When unfiltered air in leakage is greater than the assumed flow rate, Condition B must be entered. Required Action 8.3 allows time to restore the CRE or CBE Wolf Creek - Unit 1 B 3.7.10-8 Revision 81

CREVS B 3.7.10 BASES SURVEILLANCE SR 3.7.10.4 (continued)

REQUIREMENTS boundary to OPERABLE status provided mitigating actions can ensure that the CRE remains within the licensing basis habitability limits for the occupants following an accident. Compensatory measures are discussed in Regulatory Guide 1.196, Section C.2.7.3, (Ref. 4) which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F (Ref. 5). These compensatory measures may also be used as mitigating actions as required by Required Action B.2. Temporary analytical methods may also be used as compensatory measures to restore OPERABILITY (Ref. 6).

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

REFERENCES 1. USAR, Section 6.4 and 9.4.

I I I

2. USAR, Chapter 15.

3. Regulatory Guide 1.52, Rev. 2.

4. Regulatory Guide 1.196.

I

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

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

7. USAR Section 2.2.

8. Regulatory Guide 1.78, Rev. 0.

9. Regulatory Guide 1.52, Rev. 3.

10. 10 CFR 50, Appendix A, GDC 19.

I Wolf Creek - Unit 1 B 3.7.10-9 Revision 81 I

EES B 3.7.13 BASES BACKGROUND The Emergency Exhaust System is discussed in the USAR, Sections (continued) 6.5.1, 9.4.2, 9.4.3, and 15.6.5.4 (Refs. 1, 2, and 3, respectively) because it may be used for normal, as well as post accident, atmospheric cleanup functions.

APPLICABLE The Emergency Exhaust System design basis is established by the SAFETY ANALYSES consequences of the limiting Design Basis Accidents (DBAs), which are a loss of coolant accident (LOCA) and a fuel handling accident (FHA). The analysis of the LOCA (Ref. 3) assumes that radioactive materials leaked from the ECCS and Containment Spray System during the recirculation mode are filtered and adsorbed by the Emergency Exhaust System. For the fuel handling accident (FHA) the Emergency Exhaust System is credited as the release point but no credit is taken for filtration of the release. The analyses follow the guidance provided in Regulatory Guide 1.183 (Ref. 4).

The Emergency Exhaust System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO Two independent and redundant trains of the Emergency Exhaust System are required to be OPERABLE to ensure that at least one train is available, assuming a single failure that disables the other train, coincident with a loss of offsite power. Total system failure could result in the atmospheric release from the auxiliary building exceeding the guideline limits of 10 CFR 50.67 (Ref. 5) in the event of a LOCA or fuel handling accident.

The Emergency Exhaust System is considered OPERABLE when the individual components necessary to control releases from the auxiliary or fuel building are OPERABLE in both trains. An Emergency Exhaust System train is considered OPERABLE when its associated:

a. Fan is OPERABLE;

b. HEPA filter and charcoal absorber are not excessively restricting flow, and are capable of performing their filtration function; and

c. Heater, ductwork, and dampers are OPERABLE, and air circulation can be maintained.

Wolf Creek - Unit 1 B 3.7.13-2 Revision 81

EES B 3.7.13 BASES LCO The LCO is modified by a Note allowing the auxiliary or fuel building (continued) boundary to be opened intermittently under administrative controls. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings these controls consist of stationing a dedicated individual at the opening who is in continuous communication with the control room. This individual will have a method to rapidly close the opening when a need for auxiliary building or fuel building isolation is indicated.

APPLICABILITY In MODE 1, 2, 3, or 4, the Emergency Exhaust System is required to be OPERABLE in the SIS mode of operation to provide fission product removal associated with potential radioactivity leaks during the post-LOCA recirculation phase of ECCS operation.

In MODE 5 or 6, when not moving irradiated fuel the Emergency Exhaust System is not required to be OPERABLE since the ECCS is not required to be OPERABLE.

During movement of irradiated fuel in the fuel building, the Emergency Exhaust System is required to be OPERABLE to support the FBVIS mode of operation to alleviate the consequences of a fuel handling accident.

The Applicability is modified by a Note. The Note clarifies the Applicability for the two safety related modes of operation of the Emergency Exhaust System, i.e., the Safety Injection Signal (SIS) mode and the Fuel Building Ventilation Isolation Signal (FBVIS) mode. The SIS mode which aligns the system to the auxiliary building is applicable when the ECCS is required to be OPERABLE. In the FBVIS mode the system is aligned to the fuel building. This mode is applicable while handling irradiated fuel in the fuel building.

ACTIONS LCO 3.0.3 is not applicable while in MODE 5 or 6. However, since irradiated fuel assembly movement can occur in MODE 1, 2, 3, or 4, the ACTIONS have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving irradiated fuel assemblies while in MODE 5 or 6, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODE 1, 2, 3, or 4, the fuel movement is independent of reactor operations. Entering LCO 3.0.3, while in MODE 1, 2, 3, or 4 would require the unit to be shutdown unnecessarily.

Wolf Creek - Unit 1 B 3.7.13-3 Revision 81

EES B 3.7.13 BASES ACTIONS A.1 (continued)

With one Emergency Exhaust System train inoperable, action must be taken to restore OPERABLE status within 7 days. During this period, the remaining OPERABLE train is adequate to perform the Emergency Exhaust System function. The 7 day Completion Time is based on the risk from an event occurring requiring the inoperable Emergency Exhaust System train, and the remaining Emergency Exhaust System train providing the required protection.

If the auxiliary building boundary is inoperable such that a train of the Emergency Exhaust System operating in the SIS mode cannot establish or maintain the required negative pressure, action must be taken to restore an OPERABLE auxiliary building boundary within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is reasonable based on the low probability of a OBA occurring during this time period and the availability of the Emergency Exhaust System to provide a filtered release (albeit with potential for some unfiltered auxiliary building leakage).

C.1 and C.2 In MODE 1, 2, 3, or 4, when Required Action A.1 or B.1 cannot be completed within the associated Completion Time or when both Emergency Exhaust System trains are inoperable for reasons other than an inoperable auxiliary building boundary (i.e., Condition B}, 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 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 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.

Wolf Creek - Unit 1 B 3.7.13-4 Revision 81

EES B 3.7.13 BASES ACTIONS D.1 and D.2 (continued)

When Required Action A.1 cannot be completed within the associated Completion Time during movement of irradiated fuel assemblies in the fuel building, the OPERABLE Emergency Exhaust System train must be started in the FBVIS mode immediately or fuel movement suspended.

This action ensures that the remaining train is OPERABLE, that no undetected failures preventing system operation will occur, and that any active failure will be readily detected.

If the system is not placed in operation, this action requires suspension of fuel movement, which precludes a fuel handling accident. This does not preclude the movement of fuel assemblies to a safe position.

If the fuel building boundary is inoperable such that a train of the Emergency Exhaust System operating in the FBVIS mode cannot establish or maintain the required negative pressure, action must be taken immediately to suspend movement of irradiated fuel assemblies in the fuel building. This does not preclude the movement of fuel assemblies to a safe position.

SURVEILLANCE SR 3.7.13.1 REQUIREMENTS Standby systems should be checked periodically to ensure that they function properly. As the environmental and normal operating conditions on this system are not severe, testing each train once every month, by initiating from the control room flow through the HEPA filters and charcoal adsorbers, provides an adequate check on this system.

Monthly heater operation dries out any moisture accumulated in the charcoal from humidity in the ambient air. Systems with heaters must be operated for 2 15 continuous minutes with the heaters energized.

Operating heaters would not necessarily have the heating elements energized continuously for 15 minutes, but will cycle depending on the temperature. The 31 day Frequency is based on the known reliability of the equipment and the two train redundancy available. This SR can be satisfied with the Emergency Exhaust System in the SIS or FBVIS lineup during testing. The 15-minute run time is based on Position C.6.1 of Reference 10.

Wolf Creek - Unit 1 B 3.7.13-5 Revision 81

EES B3.7.13 BASES SURVEILLANCE SR 3.7.13.2 REQUIREMENTS (continued) This SR verifies that the required Emergency Exhaust System filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The Emergency Exhaust System filter tests are based on the guidance in References 6 and 7 in accordance with the VFTP. The VFTP includes testing HEPA filter performance, charcoal absorber efficiency, minimum system flow rate, and the physical properties of the activated charcoal. Specific test frequencies and additional information are discussed in detail in the VFTP.

SR 3.7.13.3 This SR verifies that each Emergency Exhaust System train starts and operates on an actual or simulated actuation signal. The 18 month Frequency is consistent with References 6 and 7. Proper completion of this SR requires testing the system in both the SIS (auxiliary building exhaust) and the FBVIS (fuel building exhaust) modes of operation.

During emergency operations the Emergency Exhaust System will automatically start in either the SIS or FBVIS lineup depending on the initiating signal. In the SIS lineup, the fans operate with dampers aligned to exhaust from the auxiliary building and prevent unfiltered leakage. In this SIS lineup, each train is capable of maintaining the auxiliary building at a negative pressure at least 0.25 inches water gauge relative to the outside atmosphere. In the FBVIS lineup, which is initiated upon detection of high radioactivity by the fuel building exhaust gaseous radioactivity monitors, the fans operate with the dampers aligned to exhaust from the fuel building to prevent unfiltered leakage. In the FBVIS lineup, each train is capable of maintaining the fuel building at a negative pressure at least 0.25 inches water gauge relative to the outside atmosphere. Normal exhaust air from the fuel building is continuously monitored by radiation detectors. One detector output will automatically align the Emergency Exhaust System in the FBVIS mode of operation.

This surveillance requirement demonstrates that each Emergency Exhaust System unit can be automatically started and properly configured to the FBVIS or SIS alignment, as applicable, upon receipt of an actual or simulated SIS signal and an FBVIS signal. It is not required that each Emergency Exhaust System unit be started from both actuation signals during the same surveillance test provided each actuation signal is tested independently within the 18 month test frequency.

Wolf Creek - Unit 1 B 3.7.13-6 Revision 81

EES B 3.7.13 BASES SURVEILLANCE SR 3.7.13.4 REQUIREMENTS (continued) This SR verifies the integrity of the auxiliary building enclosure. The ability of the auxiliary building to maintain negative pressure with respect to potentially uncontaminated adjacent areas is periodically tested to verify proper function of the Emergency Exhaust System. During the SIS mode of operation, the Emergency Exhaust System is designed to maintain a slight negative pressure in the auxiliary building, to prevent unfiltered leakage. The Emergency Exhaust System is designed to maintain a negative pressure 2 0.25 inches water gauge with respect to atmospheric pressure at a flow rate specified in the VFTP. The Frequency of 18 months is consistent with the guidance provided in NUREG-0800, Section 6.5.1 (Ref.8).

An 18 month Frequency (on a STAGGERED TEST BASIS) is consistent with Reference 9.

SR 3.7.13.5 This SR verifies the integrity of the fuel building enclosure. The ability of the fuel building to maintain negative pressure with respect to potentially uncontaminated adjacent areas is periodically tested to verify proper function of the Emergency Exhaust System. During the FBVIS mode of operation, the Emergency Exhaust System is designed to maintain a slight negative pressure in the fuel building, to prevent unfiltered leakage.

The Emergency Exhaust System is designed to maintain a negative pressure 2 0.25 inches water gauge with respect to atmospheric pressure at a flow rate specified in the VFTP. The Frequency of 18 months is consistent with the guidance provided in NUREG-0800, Section 6.5.1 (Ref.8).

An 18 month Frequency (on a STAGGERED TEST BASIS) is consistent with Reference 9.

Wolf Creek - Unit 1 B 3.7.13-7 Revision 81

EES B 3.7.13 BASES REFERENCES 1. USAR, Section 6.5.1.

2. USAR, Section 9.4.2 and 9.4.3.

3. USAR, Section 15.6.5.4.

4. Regulatory Guide 1.183, Rev. 0.

5. 10 CFR 50.67.

6. ASTM D 3803-1989.

7. ANSI N510-1980.

8. NUREG-0800, Section 6.5.1, Rev. 2, July 1981.

9. Regulatory Guide 1.52, Rev. 2.

10. Regulatory Guide 1.52, Rev. 3.

Wolf Creek - Unit 1 B 3.7.13-8 Revision 81

Fuel Storage Pool Water Level B 3.7.15 B 3.7 PLANT SYSTEMS B 3.7.15 Fuel Storage Pool Water Level BASES BACKGROUND The minimum water level in the fuel storage pool meets the assumptions of iodine decontamination factors following a fuel handling accident. The specified water level shields and minimizes the general area dose when the storage racks are filled to their maximum capacity. The water also provides shielding during the movement of spent fuel.

A general description of the fuel storage pool design is given in the USAR, Section 9.1.2 (Ref. 1). A description of the Spent Fuel Pool Cooling and Cleanup System is given in the USAR, Section 9.1.3 (Ref. 2). The assumptions of the fuel handling accident are given in the USAR, Section 15.7.4 (Ref. 3).

APPLICABLE The minimum water level in the fuel storage pool meets the assumptions SAFETY ANALYSES of the fuel handling accident described in Regulatory Guide 1.183 (Ref. 4).

The resultant 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months dose per person at the exclusion area boundary is well within the 10 CFR 50.67 (Ref. 5) limit.

According to Reference 4, there is 23 ft of water between the top of the damaged fuel bundle and the fuel pool surface during a fuel handling accident. This minimum water depth provides the basis for supporting an overall effective decontamination factor of 200 for iodine. With 23 ft of water, the assumptions of Reference 4 can be used directly.

The fuel storage pool water level satisfies Criteria 2 and 3 of 10 CFR 50.36(c)(2)(ii).

LCO The fuel storage pool water level is required to be ~ 23 ft over the top of irradiated fuel assemblies seated in the storage racks. The fuel storage pool consists of the spent fuel pool and cask loading pool (with racks installed). The specified water level preserves the assumptions of the fuel handling accident analysis (Ref. 3). As such, it is the minimum required for fuel storage and movement within the fuel storage pool.

APPLICABILITY This LCO applies during movement of irradiated fuel assemblies in the fuel storage pool, since the potential for a release of fission products exists.

Wolf Creek - Unit 1 B 3.7.15-1 Revision 81

Fuel Storage Pool Water Level B 3.7.15 BASES ACTIONS Required Action A.1 is modified by a Note indicating that LCO 3.0.3 does not apply.

When the initial conditions for prevention of an accident cannot be met, steps should be taken to preclude the accident from occurring. When the fuel storage pool water level is lower than the required level, the movement of irradiated fuel assemblies in the fuel storage pool is immediately suspended to a safe position. This action effectively precludes the occurrence of a fuel handling accident. This does not preclude movement of a fuel assembly to a safe position.

If moving irradiated fuel assemblies while in MODE 5 or 6, LCO 3.0.3 would not specify any action. If moving irradiated fuel assemblies while in MODES 1, 2, 3, and 4, the fuel movement is independent of reactor operations. Therefore, inability to suspend movement of irradiated fuel assemblies is not sufficient reason to require a reactor shutdown.

SURVEILLANCE SR 3.7.15.1 REQUIREMENTS This SR verifies sufficient fuel storage pool water is available in the event of a fuel handling accident. The water level in the fuel storage pool must be checked periodically. The 7 day Frequency is appropriate because the volume in the pool is normally stable. Water level changes are controlled by plant procedures and are acceptable based on operating experience.

During refueling operations, the level in the fuel storage pool is in equilibrium with the refueling pool, and the level in the refueling pool is checked daily in accordance with SR 3.9.7.1.

Wolf Creek - Unit 1 B 3.7.15-2 Revision 81

Fuel Storage Pool Water Level B 3.7.15 BASES REFERENCES 1. USAR, Section 9.1.2.

2. USAR, Section 9.1.3.

3. USAR, Section 15.7.4.

4. Regulatory Guide 1.183, Rev. 0.

5. 10 CFR 50.67.

Wolf Creek - Unit 1 B 3.7.15-3 Revision 81

Secondary Specific Activity B 3.7.18 B 3.7 PLANT SYSTEMS B 3. 7 .18 Secondary Specific Activity BASES BACKGROUND Activity in the secondary coolant results from steam generator tube outleakage from the Reactor Coolant System (RCS). Under steady state conditions, the activity is primarily iodines with relatively short half lives and, thus, indicates current conditions. During transients, 1-131 spikes have been observed as well as increased releases of some noble gases.

Other fission product isotopes, as well as activated corrosion products in lesser amounts, may also be found in the secondary coolant.

A limit on secondary coolant specific activity during power operation minimizes releases to the environment because of normal operation, anticipated operatiqnal occurrences, and accidents.

This limit is lower than the activity value that might be expected from a 150 gpd/SG tube leak (LCO 3.4.13, "RCS Operational LEAKAGE") of primary coolant at the limit of 1.0 µCi/gm (LCO 3.4.16, "RCS Specific Activity"). A steam line failure is assumed to result in the release of the activity contained in the steam generator inventory and the reactor coolant LEAKAGE.

Operating a unit at the allowable secondary coolant specific activity will assure that the potential 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months exclusion area boundary (EAB) exposure is limited to the limits of 10 CFR 50.67 (Ref. 1) and the Standard Review Plan (Ref. 3).

APPLICABLE The accident analysis of the main steam line break (MSLB),

SAFETY ANALYSES as discussed in the USAR, Chapter 15 (Ref. 2) assumes the initial secondary coolant specific activity to have a radioactive isotope

concentration of0.10 µCi/gm DOSE EQUIVALENT 1-131. This assumption is used in the analysis for determining the radiological consequences of the postulated accident. The accident analysis, based on this and other assumptions, shows that the radiological consequences of an MSLB do not exceed the unit EAB limits (Ref. 3) for total effective dose equivalent.

With the loss of offsite power, the remaining steam generators are available for core decay heat dissipation by venting steam to the atmosphere through the MSSVs and steam generator atmospheric relief valves (ARVs). The Auxiliary Feedwater System supplies the necessary Wolf Creek - Unit 1 B 3.7.18-1 Revision 81

Secondary Specific Activity B 3.7.18 BASES APPLICABLE makeup to the steam generators. Venting continues until the reactor SAFETY ANALYSES coolant temperature and pressure have decreased sufficiently for the (continued) Residual Heat Removal System to complete the cooldown.

In the evaluation of the radiological consequences of this accident, the activity released from the steam generator connected to the failed steam line is assumed to be released directly to the environment. The unaffected steam generators are assumed to discharge steam and any entrained activity through the MSSVs and ARVs during the event. Since no credit is taken in the analysis for activity plateout or retention, the resultant radiological consequences represent a conservative estimate of the potential integrated dose due to the postulated steam line failure.

Secondary specific activity limits satisfy Criterion 2 of 10 CFR 50.36(c)(2)(ii).

LCO As indicated in the Applicable Safety Analyses, the specific activity of the secondary coolant is required to be:-::; 0.10 µCi/gm DOSE EQUIVALENT 1-131 to limit the radiological consequences of a Design Basis Accident (OBA) to the required limit (Ref. 3).

Monitoring the specific activity of the secondary coolant ensures that when secondary specific activity limits are exceeded, appropriate actions are taken in a timely manner to place the unit in an operational MODE that would minimize the radiological consequences of a OBA.

APPLICABILITY In MODES 1, 2, 3, and 4, the limits on secondary specific activity apply due to the potential for secondary steam releases to the atmosphere.

In MODES 5 and 6, the steam generators are not being used for heat removal. Both the RCS and steam generators are depressurized, and primary to secondary LEAKAGE is minimal. Therefore, monitoring of secondary specific activity is not required.

ACTIONS A.1 and A.2 DOSE EQUIVALENT 1-131 exceeding the allowable value in the secondary coolant, is an indication of a problem in the RCS and contributes to increased post accident doses. If the secondary specific activity cannot be restored to within limits within the associated Completion Time, the unit must be placed in a MODE in which the LCO Wolf Creek - Unit 1 B3.7.18-2 Revision 81

Secondary Specific Activity B 3.7.18 BASES ACTIONS A.1 and A.2 (continued) 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 3.7.18.1 REQUIREMENTS This SR verifies that the secondary specific activity is within the limits of the accident analysis. A gamma isotopic analysis of the secondary coolant, which determines DOSE EQUIVALENT 1-131, confirms the validity of the safety analysis assumptions as to the source terms in post accident releases. It also serves to identify and trend any unusual isotopic concentrations that might indicate changes in reactor coolant activity or LEAKAGE. The 31 day Frequency is based on the detection of increasing trends of the level of DOSE EQUIVALENT 1-131, and allows for appropriate action to be taken to maintain levels below the LCO limit.

REFERENCES 1. 10 CFR 50.67.

2. USAR, Chapter 15.

3. Standard Review Plan (SRP), Section 15.0.1.

Wolf Creek - Unit 1 B 3.7.18-3 Revision 81

- _ __J

Containment Penetrations B 3.9.4 B 3.9 REFUELING OPERATIONS B 3.9.4 Containment Penetrations BASES BACKGROUND During CORE ALTERATIONS or movement of irradiated fuel assemblies within containment, a release of fission product radioactivity within containment will be restricted from escaping to the environment when the LCO requirements are met. In MODES 1, 2, 3, and 4, this is accomplished by maintaining containment OPERABLE as described in LCO 3.6.1, "Containment." In MODE 6, the potential for containment pressurization as a result of an accident is not likely; therefore, requirements to isolate the containment from the outside atmosphere can be less stringent. The LCO requirements are referred to as "containment penetration closure" rather than "containment OPERABILITY." Containment penetration closure means that all potential escape paths are closed or capable of being closed within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . Since there is no potential for containment pressurization, the 10 CFR 50, Appendix J leakage criteria and tests are not required.

The containment serves to contain fission product radioactivity that may be released from the reactor core following an accident, such that offsite radiation exposures are maintained within the requirements of 10 CFR 50.67. Additionally, the containment provides radiation shielding from the fission products that may be present in the containment atmosphere following accident conditions.

The containment equipment hatch, which is part of the containment pressure boundary, provides a means for moving large equipment and components into and out of containment. If closed, the equipment hatch must be held in place by at least four bolts. Good engineering practice dictates that the bolts required by this LCO be approximately equally spaced. The equipment hatch may be open during CORE ALTERATIONS or movement of irradiated fuel assemblies within containment, provided it can be installed with a minimum of four bolts holding it in place. During shutdown conditions, adequate missile protection for safety related equipment in containment is provided with the equipment hatch held in place with 6 bolts. Administrative controls ensure the equipment hatch is in place during the threat of severe weather that could result in the generation of tornado driven missiles.

(Ref. 5).

The containment air locks, which are also part of the containment pressure boundary, provide a means for personnel access during Wolf Creek - Unit 1 B 3.9.4-1 Revision 81

Containment Penetrations B 3.9.4 BASES BACKGROUND least one side. Isolation may be achieved by an OPERABLE automatic (continued) isolation valve, or by a manual isolation valve, blind flange, or equivalent. Equivalent isolation methods must be approved and may include use of a material that can provide a temporary, atmospheric pressure, ventilation barrier for the other containment penetrations and the emergency personnel escape lock during fuel movements (Ref. 1).

APPLICABLE During CORE ALTERATIONS or movement of irradiated fuel SAFETY ANALYSES assemblies within containment, the most severe radiological consequences result from a fuel handling accident. The fuel handling accident is a postulated event that involves damage to irradiated fuel (Ref. 2). Fuel handling accident, analyzed in Reference 2, assumes dropping a single irradiated fuel assembly. The time to close containment penetrations under administrative controls is assumed to be not more than a 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months period, consistent with the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months period of release assumed in the accident analysis (Ref. 6). The requirements of LCO 3.9.7, "Refueling Pool Water Level," and the minimum decay time of 76 hours8.796296e-4 days 0.0211 hours 1.256614e-4 weeks 2.8918e-5 months prior to CORE AL TERA TIONS ensure that the release of fission product radioactivity, subsequent to a fuel handling accident, results in doses that are well within the guideline values specified in 10 CFR 50.67. Per Standard Review Plan 15.0.1, the acceptance limits for offsite radiation exposure are 25% of 10 CFR 50.67 values.

Containment penetrations satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii).

LCO This LCO limits the consequences of a fuel handling accident in containment by limiting the potential escape paths for fission product radioactivity released within containment. The LCO requires any penetration providing direct access from the containment atmosphere to the outside atmosphere to be closed except for the OPERABLE containment purge penetrations, the personnel airlock, and the equipment hatch (which must be capable of being closed). For the OPERABLE containment purge penetrations, this LCO ensures that each penetration is isolable by the Containment Purge Isolation System to ensure that releases through the valves are terminated.

One door in the emergency air lock must be closed and one door in the personnel air lock must be capable of being closed. Both containment personnel air lock doors may be open during movement of irradiated fuel or CORE ALTERATIONS, provided an air lock door is capable of being closed and the water level in the refueling pool is maintained as required. Administrative controls ensure that 1) appropriate personnel are aware ofthe open status of the containment during movement of Wolf Creek - Unit 1 B 3.9.4-3 Revision 81

Refueling Pool Water Level B 3.9.7 B 3.9 REFUELING OPERATIONS B 3.9.7 Refueling Pool Water Level BASES BACKGROUND The movement of irradiated fuel assemblies, within containment requires a minimum water level of 23 ft above the top of the reactor vessel flange. During refueling, this maintains sufficient water level in the fuel transfer canal, refueling pool, and spent fuel pool. Sufficient water is necessary to retain iodine fission product activity in the water in the event of a fuel handling accident (Refs. 1 and 2). Sufficient iodine activity would be retained to limit offsite doses from the accident to

< 25% of 10 CFR 50.67 limits, as provided by the guidance of Reference 1.

APPLICABLE During movement of irradiated fuel assemblies, the water level in the SAFETY ANALYSES refueling pool is an initial condition design parameter in the analysis of a fuel handling accident, as postulated by Regulatory Guide 1.183 (Ref. 1). The reactor is assumed to have been subcritical for 76 hours8.796296e-4 days 0.0211 hours 1.256614e-4 weeks 2.8918e-5 months prior to movement of irradiated fuel in the reactor vessel. A minimum water level of 23 ft allows a decontamination factor of 200 (Appendix B, Assumption 2 of Ref. 1) to be used in the accident analysis for iodine.

This relates to the assumption that 99.5% of the total iodine released from the pellet to cladding gap of all the dropped fuel assembly rods is retained by the refueling pool water. For the analyses the dropped assembly is assumed to damage 20 percent of the rods of an additional assembly.

The fuel handling accident analysis is described in Reference 2. With a minimum water level of 23 ft and a minimum decay time of 76 hours8.796296e-4 days 0.0211 hours 1.256614e-4 weeks 2.8918e-5 months prior to fuel handling, the analysis and test programs demonstrate that the iodine release due to a postulated fuel handling accident is adequately captured by the water and offsite doses are maintained well within allowable limits (Refs. 2 and 3).

Refueling pool water level satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii).

Wolf Creek - Unit 1 B 3.9.7-1 Revision 81

Refueling Pool Water Level B 3.9.7 BASES LCO A minimum refueling pool water level of 23 ft above the reactor vessel flange is required to ensure that the radiological consequences of a postulated fuel handling accident inside containment are within acceptable limits, as provided by the guidance of Reference 1.

APPLICABILITY LCO 3.9.7 is applicable when moving irradiated fuel assemblies within containment. The LCO minimizes the possibility of a fuel handling accident in containment that is beyond the assumptions of the safety analysis. If irradiated fuel assemblies are not present in containment, there can be no significant radioactivity release as a result of a postulated fuel handling accident. Requirements for fuel handling accidents in the spent fuel pool are covered by LCO 3.7.15, "Fuel Storage Pool Water Level."

ACTIONS With a water level of< 23 ft above the top of the reactor vessel flange, movement of irradiated fuel assemblies within the containment shall be suspended immediately to ensure that a fuel handling accident cannot occur.

The suspension of fuel movement shall not preclude completion of movement of a component to a safe position.

SURVEILLANCE SR 3.9.7.1 REQUIREMENTS Verification of a minimum water level of 23 ft above the top of the reactor vessel flange ensures that the design basis for the analysis of the postulated fuel handling accident during refueling operations is met.

Water at the required level above the top of the reactor vessel flange limits the consequences of damaged fuel rods that are postulated to result from a fuel handling accident inside containment (Ref. 2).

The Frequency of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is based on engineering judgment and is considered adequate in view of the large volume of water and the normal procedural controls of valve positions, which make significant unplanned level changes unlikely.

Wolf Creek - Unit 1 B 3.9.7-2 Revision 81 L __

Refueling Pool Water Level B 3.9.7 BASES REFERENCES

,- 1. Reg.ulatory Guide 1.183, July 2000.

2. USAR, Section 15.7.4.

3. Malinowski, D. D., Bell, M. J., Duhn, E., and Locante, J., WCAP-7828, Radiological Consequences of a Fuel Handling Accident, December 1971.

Wolf Creek - Unit 1 . B 3.9.7-3 Revision 81

ML20070L982

Text

Subject:

6.6 REFERENCES

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