Text

(CNS) - Technical Specification Bases Changes
	ML21106A122
Person / Time
Site:	Cooper
Issue date:	04/16/2021
From:	Dewhirst L; Nebraska Public Power District (NPPD)
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NLS2021015
	Download: ML21106A122 (80)
	v • d • e

H Nebraska Public Power District Always there when you need us NLS2021015 April 16, 2021 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555-0001

Subject:

Technical Specification Bases Changes Cooper Nuclear Station, Docket No. 50-298, DPR-46

Dear Sir or Madam:

The purpose of this letter is to provide changes to the Cooper Nuclear Station (CNS) Technical Specification Bases implemented without prior Nuclear Regulatory Commission approval. In accordance with the requirements of CNS Technical Specification 5.5.1 0.d, these changes are provided on a frequency consistent with 10 CFR 50.71(e). The enclosed Bases changes are for the time period from February 23, 2019 through February 22, 2021. Also enclosed are filing instructions and an updated List of Effective Pages for the CNS Technical Specification Bases.

This letter contains no commitments. If you have any questions regarding this submittal, please co t me at (402) 825-5416.

inda ewhirst Regulatory Affairs and Compliance Manager

/bk

Enclosure:

Technical Specification Bases Changes cc: Regional Administrator, w/enclosure USNRC - Region IV Cooper Project Manager, w/enclosure USNRC - NRR Plant Licensing Branch IV Senior Resident Inspector, w/enclosure (per controlled document distribution)

USNRC-CNS NPG Distribution, w/o enclosure CNS Records, w/enclosure COOPER NUCLEAR STATION P.O. Box 98 / Brownville, NE 68321-0098 Telephone: (402) 825-3811 / Fax: (402) 825-5211 www. nppd.com

NLS2021015 Enclosure Page 1 of79 TECHNICAL SPECIFICATION BASES CHANGES

FILING INSTRUCTIONS TECHNICAL SPECIFICATION BASES REMOVE INSERT List of Effective Pages 1 through 7 (dated 02/22/19) 1 through 7 (dated 01/06/21)

Bases Pages ii (dated 09/21/18) ii (dated 12/19/19)

B 2.0-1 (dated 12/18/03) B 2.0-1 (dated 07/01/20)

B 2.0-2 (Revision 0) B 2.0-2 (dated 07/01/20)

B 2.0-3 (Revision 0) B 2.0-3 (dated 07/01/20)

B 2.0-4 (dated 06/10/99) B 2.0-4 (dated 07/01/20)

B 2.0-5 (dated 09/25/09) B 2.0-5 (dated 07/01/20)

B 2.0-6 (dated 09/25/09) B 2.0-6 (dated 07/01/20)

B 2.0-7 (Revision 0) B 2.0-7 (dated 07/01/20)

B 3.0-1 (dated 06/30/06) B 3.0-1 (dated 12/09/20)

B 3.0-2 (Revision 0) B 3.0-2 (dated 10/15/19)

B 3.0-3 (Revision 0) B 3.0-3 (dated 12/09/20)

B 3.0-4 (Revision 0) B 3.0-4 (dated 12/09/20)

B 3.0-5 (dated 09/18/09) B 3.0-5 (dated 12/09/20)

B 3.0-6 (dated 09/18/09) B 3.0-6 (dated 12/09/20)

B 3.0-7 (dated 09/18/09) B 3.0-7 (dated 12/09/20)

B 3.0-8 (dated 09/18/09) B 3.0-8 (dated 12/09/20)

B 3.0-9 (dated 09/18/09) B 3.0-9 (dated 12/09/20)

B 3.0-10 (dated 09/18/09) B 3.0-10 (dated 12/09/20)

B 3.0-11 (dated 09/18/09) B 3.0-11 (dated 12/09/20)

B 3.0-15 (dated 08/09/17) B 3.0-15 (dated 12/09/20)

B 3.0-16 (dated 08/09/17) B 3.0-16 (dated 12/09/20)

B 3.0-17 (dated 08/09/17) B 3.0-17 (dated 12/09/20)

B 3.0-18 (dated 08/09/17) B 3.0-18 (dated 12/09/20)

B 3.0-19 (dated 12/09/20)

B 3.2-4 (dated 09/11/15) B 3.2-4 (dated 07/01/20)

B 3 .2-5 (dated 09/11/15) B 3.2-5 (dated 07/01/20)

B 3.2-6 (dated 05/17/17) B 3 .2-6 (dated 07/01/20)

B 3.3-16 (dated 11/25/12) B 3.3-16 (dated 04/10/19)

B 3.3-17 (dated 11/25/12) B 3 .3-17 (dated 04/10/19)

B 3.3-29 (dated 05/17/17) B 3.3-29 (dated 04/10/19)

B 3.3-37 (dated 05/17/17) B 3.3-37 (dated 10/15/19)

B 3.3-65 (dated 11/25/12) B 3.3-65 (dated 03/18/20)

FILING INSTRUCTIONS TECHNICAL SPECIFICATION BASES REMOVE INSERT B 3.3-66 (dated 11/25/12) B 3.3-66 (dated 03/18/20)

B 3.3-69 (dated 05/17/17) B 3.3-69 (dated 03/18/20)

B 3.3-70 (dated 05/29/18) B 3.3-70 (dated 03/18/20)

B 3.3-105 (dated 09/19/18) B 3.3-105 (dated 08/19/19)

B 3.3-106 (dated 09/19/18) B 3.3-106 (dated 08/19/19)

B 3.3-107 (dated 09/19/18) B 3.3-107 (dated 08/19/19)

B 3.4-24 (dated 11/08/18) B 3 .4-24 (dated 12/19/19)

B 3.4-25 (dated 11/08/18) B 3.4-25 (dated 12/19/19)

B 3.4-26 (dated 12/20/18) B 3.4-26 (dated 12/19/19)

B 3.4-27 (dated 05/17/17) B 3.4-27 (dated 12/19/19)

B 3.4-28 (dated 05/17 /l 7) B 3.4-28 (dated 12/19/19)

B 3.4-29 (dated 11/13/14) B 3.4-29 (dated 12/19/19)

B 3.4-30 (Revision 0) B 3.4-30 (dated 12/19/19)

B 3.4-31 (dated 09/18/09) B 3.4-31 (dated 12/19/19)

B 3.4-32 (dated 05/17/17) B 3.4-32 (dated 12/19/19)

B 3.4-33 (Revision 1) B 3.4-33 (dated 12/19/19)

B 3.4-34 (Revision 0) B 3.4-34 (dated 12/19/19)

B 3.4-35 (dated 09/18/09) B 3.4-35 (dated 12/19/19)

B 3.4-36 (dated Revision 0) B 3.4-36 (dated 01/06/21)

B 3.4-37 (dated 05/17/17) B 3.4-37 (dated 01/06/21)

B 3.4-38 (Revision 0) B 3.4-38 (dated 01/06/21)

B 3.4-42 (Revision 0) B 3.4-42 (dated 01/06/21)

B 3.4-43 (dated 05/17/17) B 3.4-43 (dated 01/06/21)

B 3.6-53 (dated 02/22/16) B 3.6-53 (dated 08/19/20)

B 3.8-10 (dated 02/07/13) B 3.8-10 (dated 05/13/20)

B 3.8-17 (dated 05/17/17) B 3.8-17 (dated 04/03/19)

B 3.8-20 (dated 05/17/17) B 3.8-20 (dated 10/15/19)

B 3.8-29 (dated 01/17/18) B 3.8-29 (dated 04/03/19)

B 3.8-31 (dated 02/07/13) B 3.8-31 (dated 04/03/19)

B 3.8-33 (dated 01/17/18) B 3.8-33 (dated 04/03/19)

B 3.8-34 (dated 05/17/17) B 3.8-34 (dated 04/03/19)

B 3.8-35 (dated 02/07/13) B 3.8-35 (dated 04/03/19)

B 3.8-36 (dated 05/17/17) B 3.8-36 (dated 04/03/19)

B 3.8-65 (dated 09/19/18) B 3.8-65 (dated 07/12/19)

B 3.9-24 (Revision 0) B 3.9-24 (dated 01/06/21)

B 3.9-29 (Revision 0) B 3.9-29 (dated 01/06/21)

B 3.10-28 (dated 05/17/17) B 3.10-28 (dated 05/13/20)

LIST OF EFFECTIVE PAGES - BASES Page No. Revision No./Date Page No. Revision No./Date i 09/21/18 B3.1-15 6/10/99 ii 12/19/19 B 3.1-16 12/03/09 iii 09/21/18 B 3.1-17 6/10/99 iv 09/21/18 B3.1-18 07/16/08 B 3.1-19 05/17/17 B 2.0-1 07/01/20 B 3.1-20 05/17/17 B 2.0-2 07/01/20 B3.1-21 01/06/12 B 2.0-3 07/01/20 B 3.1-22 0 B 2.0-4 07/01/20 B 3.1-23 0 B 2.0-5 07/01/20 B 3.1-24 0 B 2.0-6 07/01/20 B 3.1-25 05/09/06 B 2.0-7 07/01/20 B 3.1-26 05/17/17 B 2.0-8 09/25/09 B 3.1-27 05/09/06 B 3.1-28 12/18/03 B 3.0-1 12/09/20 B 3.1-29 0 B 3.0-2 10/15/19 B 3.1-30 0 B 3.0-3 12/09/20 B 3.1-31 0 B 3.0-4 12/09/20 B 3.1-32 0 B 3.0-5 12/09/20 B 3.1-33 05/17/17 B 3.0-6 12/09/20 B 3.1-34 07/16/08 B 3.0-7 12/09/20 B 3.1-35 07/16/08 B 3.0-8 12/09/20 B 3.1-36 07/16/08 B 3.0-9 12/09/20 B 3.1-37 05/17/17 B 3.0-10 12/09/20 B 3.1-38 07/16/08 B 3.0-11 12/09/20 B 3.1-39 09/25/09 B 3.0-12 09/18/09 B 3.1-40 04/10/15 B 3.0-13 08/09/17 B 3.1-41 09/25/09 B3.0-14 09/18/09 B 3.1-42 05/17/17 B 3.0-15 12/09/20 B 3.1-43 05/17/17 B 3.0-16 12/09/20 B 3.1-44 08/09/17 B 3.0-17 12/09/20 B 3.1-45 05/17/17 B3.0-18 12/09/20 B 3.1-46 09/25/09 B3.0-19 12/09/20 B 3.1-47 09/25/09 B 3.1-48 0 B 3.1-1 6/10/99 B 3.1-49 05/17/17 B 3.1-2 6/10/99 B 3.1-50 05/17/17 B 3.1-3 6/10/99 B 3.1-51 09/25/09 B 3.1-4 6/10/99 B 3.1-5 6/10/99 B 3.2-1 09/11/15 B 3.1-6 6/10/99 B 3.2-2 09/11/15 B 3.1-7 12/18/03 B 3.2-3 05/17/17 B 3.1-8 12/18/03 B 3.2-4 07/01/20 B 3.1-9 6/10/99 B 3.2-5 07/01/20 B 3.1-10 6/10/99 B 3.2-6 07/01/20 B 3.1-11 6/10/99 B 3.2-7 09/11/15 B3.1-12 12/18/03 B 3.2-8 09/11/15 B3.1-13 12/18/03 B 3.2-9 09/11/15 B3.1-14 6/10/99 B3.2-10 05/17/17 Cooper 1 01/06/21

LIST OF EFFECTIVE PAGES - BASES Page No. Revision No./Date Page No. Revision No./Date B 3.2-11 09/11/15 B 3.3-47 11/25/12 B 3.3-48 11/25/12 B 3.3-1 11/25/12 B 3.3-49 11/25/12 B 3.3-2 11/25/12 B 3.3-50 05/17/17 B 3.3-3 11/25/12 B 3.3-51 05/17/17 B 3.3-4 11/25/12 B 3.3-52 05/17/17 B 3.3-5 11/25/12 B 3.3-53 05/17/17 B 3.3-6 11/25/12 B 3.3-54 05/17/17 B 3.3-7 11/25/12 B 3.3-55 11/25/12 B 3.3-8 11/25/12 B 3.3-56 11/25/12 B 3.3-9 11/25/12 B 3.3-57 11/25/12 B 3.3-10 11/25/12 B 3.3-58 11/25/12 B 3.3-11 11/25/12 B 3.3-59 05/17/17 B 3.3-12 11/25/12 B 3.3-60 05/17/17 B 3.3-13 11/25/12 B 3.3-61 11/25/12 B3.3-14 11/25/12 B 3.3-62 11/25/12 B 3.3-15 11/25/12 B 3.3-63 11/25/12 B3.3-16 04/10/19 B 3.3-64 11/25/12 B 3.3-17 04/10/19 B 3.3-65 03/18/20 B3.3-18 11/25/12 B 3.3-66 03/18/20 B3.3-19 11/25/12 B 3.3-67 11/25/12 B 3.3-20 11/25/12 B 3.3-68 11/25/12 B 3.3-21 11/25/12 B 3.3-69 03/18/20 B 3.3-22 11/25/12 B 3.3-70 03/18/20 B 3.3-23 05/17/17 B 3.3-71 11/25/12 B 3.3-24 05/17/17 B 3.3-72 11/25/12 B 3.3-25 05/17/17 B 3.3-73 11/25/12 B 3.3-26 05/17/17 B 3.3-74 05/17/17 B 3.3-27 05/17/17 B 3.3-75 05/17/17 B 3.3-28 05/17/17 B 3.3-76 11/25/12 B 3.3-29 04/10/19 B 3.3-77 02/24/14 B 3.3-30 05/17/17 B 3.3-78 02/24/14 B 3.3-31 11/25/12 B 3.3-79 11/25/12 B 3.3-32 11/25/12 B 3.3-80 11/25/12 B 3.3-33 11/25/12 B 3.3-81 11/25/12 B 3.3-34 11/25/12 B 3.3-82 11/25/12 B 3.3-35 11/25/12 B 3.3-83 11/25/12 B 3.3-36 05/17/17 B 3.3-84 11/25/12 B 3.3-37 10/15/19 B 3.3-85 05/17/17 B 3.3-38 05/17/17 B 3.3-86 05/17/17 B 3.3-39 05/17/17 B 3.3-87 11/25/12 B 3.3-40 11/25/12 B 3.3-88 11/25/12 B 3.3-41 11/25/12 B 3.3-89 02/22/16 B 3.3-42 11/25/12 B 3.3-90 11/25/12 B 3.3-43 11/25/12 B 3.3-91 02/22/16 B 3.3-44 11/25/12 B 3.3-92 02/22/16 B 3.3-45 11/25/12 B 3.3-93 02/22/16 B 3.3-46 11/25/12 B 3.3-94 09/19/18 Cooper 2 01/06/21

LIST OF EFFECTIVE PAGES - BASES Page No. Revision No./Date Page No. Revision No./Date B 3.3-95 02/22/16 B 3.3-143 09/19/18 B 3.3-96 09/19/18 B3.3-144 09/19/18 B 3.3-97 09/19/18 B3.3-145 09/19/18 B 3.3-98 09/19/18 B 3.3-146 09/19/18 B 3.3-99 09/19/18 B 3.3-147 09/19/18 B 3.3-100 09/19/18 B3.3-148 09/19/18 B3.3-101 09/19/18 B 3.3-149 09/19/18 B 3.3-102 09/19/18 B3.3-150 09/19/18 B 3.3-103 09/19/18 B 3.3-151 09/19/18 B 3.3-104 09/19/18 B 3.3-152 09/19/18 B 3.3-105 08/19/19 B 3.3-153 09/19/18 B 3.3-106 08/19/19 B 3.3-154 09/19/18 B 3.3-107 08/19/19 B 3.3-155 09/19/18 B 3.3-108 02/22/16 B 3.3-156 09/19/18 B 3.3-109 09/19/18 B 3.3-157 09/19/18 B 3.3-110 02/22/16 B 3.3-158 09/19/18 B3.3-111 09/19/18 B 3.3-159 09/19/18 B3.3-112 02/22/16 B3.3-160 09/19/18 B3.3-113 09/19/18 B 3.3-161 09/19/18 B3.3-114 09/19/18 B 3.3-162 09/19/18 B3.3-115 09/19/18 B3.3-163 09/19/18 B 3.3-116 11/25/12 B3.3-164 09/19/18 B 3.3-117 05/17/17 B 3.3-165 09/19/18 B 3.3-118 05/17/17 B 3.3-166 09/19/18 B3.3-119 05/17/17 B 3.3-167 09/19/18 B 3.3-120 11/25/12 B3.3-168 09/19/18 B 3.3-121 11/25/12 B3.3-169 09/19/18 B 3.3-122 07/20/17 B 3.3-170 09/19/18 B 3.3-123 11/25/12 B 3.3-171 09/19/18 B 3.3-124 11/25/12 B3.3-172 09/19/18 B 3.3-125 11/25/12 B 3.3-173 09/19/18 B3.3-126 11/25/12 B 3.3-174 09/19/18 B 3.3-127 11/25/12 B 3.3-175 09/19/18 B 3.3-128 11/25/12 B 3.3-176 09/19/18 B 3.3-129 05/17/17 B 3.3-177 09/19/18 B3.3-130 05/17/17 B 3.3-178 09/19/18 B 3.3-131 05/17/17 B3.3-179 09/19/18 B3.3-132 11/08/18 B3.3-180 09/19/18 B 3.3-133 09/19/18 B 3.3-181 09/19/18 B 3.3-134 09/19/18 B 3.3-182 09/19/18 B 3.3-135 09/19/18 B3.3-183 09/19/18 B 3.3-136 09/19/18 B 3.3-184 09/19/18 B 3.3-137 09/19/18 B3.3-185 09/19/18 B3.3-138 02/22/19 B 3.3-186 09/19/18 B 3.3-139 02/22/19 B3.3-187 09/19/18 B3.3-140 09/19/18 B3.3-188 09/19/18 B 3.3-141 09/19/18 B 3.3-189 09/19/18 B 3.3-142 09/19/18 B3.3-190 09/19/18 Cooper 3 01/06/21

LIST OF EFFECTIVE PAGES - BASES Page No. Revision No./Date Page No. Revision No./Date B 3.3-191 09/19/18 B 3.4-34 12/19/19 B3.3-192 09/19/18 B 3.4-35 12/19/19 B 3.3-193 09/19/18 B 3.4-36 01/06/21 B 3.3-194 09/19/18 B 3.4-37 01/06/21 B3.3-195 09/19/18 B 3.4-38 01/06/21 B3.3-196 09/19/18 B 3.4-39 1 B 3.3-197 09/19/18 B 3.4-40 0 B 3.3-198 09/19/18 B 3.4-41 0 B3.3-199 09/19/18 B 3.4-42 01/06/21 B 3.3-200 09/19/18 B 3.4-43 01/06/21 B 3.3-201 09/19/18 B 3.4-44 09/22/16 B 3.3-202 09/19/18 B 3.4-45 09/22/16 B 3.3-203 09/19/18 B 3.4-46 09/22/16 B 3.3-204 09/19/18 B 3.4-47 0 B 3.4-48 0 B 3.4-1 0 B 3.4-49 05/17/17 8 3.4-2 09/11/15 B 3.4-50 09/22/16 B 3.4-3 09/11/15 B 3.4-51 05/17/17 B 3.4-4 09/11/15 B 3.4-52 04/23/13 8 3.4-5 09/11/15 B 3.4-53 0 B 3.4-6 09/11/15 B 3.4-54 05/17/17 B 3.4-7 05/17/17 B 3.4-55 0 B 3.4-8 09/11/15 B 3.4-9 0 B 3.5-1 09/19/18 B 3.4-10 0 B 3.5-2 11/24/03 B 3.4-11 1 B 3.5-3 0 B 3.4-12 05/17/17 B 3.5-4 0 B 3.4-13 04/12/00 B 3.5-5 04/26/04 B 3.4-14 0 B 3.5-6 09/19/18 B 3.4-15 03/05/12 B 3.5-7 04/26/04 B 3.4-16 08/09/17 B 3.5-8 04/26/04 B 3.4-17 05/17/17 B 3.5-9 05/17/17 B 3.4-18 03/05/12 8 3.5-10 05/17/17 B 3.4-19 0 8 3.5-11 05/17/17 8 3.4-20 0 B 3.5-12 08/09/17 8 3.4-21 0 B3.5-13 08/09/17 8 3.4-22 0 8 3.5-14 05/17/17 8 3.4-23 05/17/17 83.5-15 05/17/17 8 3.4-24 12/19/19 8 3.5-16 05/17/17 8 3.4-25 12/19/19 B3.5-17 11/23/99 B 3.4-26 12/19/19 B 3.5-18 09/19/18 B 3.4-27 12/19/19 83.5-19 09/19/18 8 3.4-28 12/19/19 8 3.5-20 09/19/18 8 3.4-29 12/19/19 B 3.5-21 09/19/18 B 3.4-30 12/19/19 8 3.5-22 09/19/18 8 3.4-31 12/19/19 B 3.5-23 09/19/18 B 3.4-32 12/19/19 B 3.5-24 09/19/18 B 3.4-33 12/19/19 B 3.5-25 02/22/19 Cooper 4 01/06/21

LIST OF EFFECTIVE PAGES - BASES Page No. Revision No./Date Page No. Revision No./Date B 3.5-26 02/22/19 B 3.6-41 0 B 3.5-27 09/19/18 B 3.6-42 0 B 3.5-28 09/19/18 B 3.6-43 05/17/17 B 3.5-29 09/19/18 B 3.6-44 05/17/17 B 3.5-30 09/19/18 B 3.6-45 0 B 3.5-31 09/19/18 B 3.6-46 06/10/99 B 3.5-32 09/19/18 B 3.6-47 0 B 3.6-48 0 B 3.6-1 03/08/00 B 3.6-49 05/17/17 B 3.6-2 09/30/08 B 3.6-50 05/17/17 B 3.6-3 03/08/00 B 3.6-51 02/22/16 B 3.6-4 11/06/06 B 3.6-52 02/22/16 B 3.6-5 05/17/17 B 3.6-53 08/19/20 B 3.6-6 0 B 3.6-54 08/09/17 B 3.6-7 09/30/08 B 3.6-55 02/22/16 B 3.6-8 0 B 3.6-56 02/22/16 B 3.6-9 0 B 3.6-57 02/22/16 B 3.6-10 0 B 3.6-58 05/17/17 B 3.6-11 0 B 3.6-59 05/17/17 B3.6-12 03/08/00 B 3.6-60 02/22/16 B3.6-13 05/17/17 B 3.6-61 09/19/18 B 3.6-14 03/08/00 B 3.6-62 05/17/17 B 3.6-15 0 B 3.6-63 11/02/17 B 3.6-16 1 B 3.6-64 11/02/17 B 3.6-17 0 B 3.6-65 05/17/17 B3.6-18 09/19/18 B 3.6-66 08/09/17 B3.6-19 11/28/01 B 3.6-67 02/22/16 B 3.6-20 11/28/01 B 3.6-68 02/22/16 B 3.6-21 11 /28/01 B 3.6-69 05/17/17 B 3.6-22 11/28/01 B 3.6-70 02/22/16 B 3.6-23 09/19/18 B 3.6-71 09/19/18 B 3.6-24 05/17/17 B 3.6-72 09/19/18 B 3.6-25 1 B 3.6-73 05/17/17 B 3.6-26 08/09/17 B 3.6-74 05/17/17 B 3.6-27 05/17/17 B 3.6-75 02/22/16 B 3.6-28 05/17/17 B 3.6-76 09/19/18 B 3.6-29 09/25/09 B 3.6-77 02/22/16 B 3.6-30 09/30/08 B 3.6-78 02/22/16 B 3.6-31 05/17/17 B 3.6-79 09/19/18 B 3.6-32 12/27/02 B 3.6-80 08/09/17 B 3.6-33 12/27/02 B 3.6-81 02/22/16 B 3.6-34 05/17/17 B 3.6-82 02/22/16 B 3.6-35 0 B 3.6-83 02/22/16 B 3.6-36 0 B 3.6-84 09/19/18 B 3.6-37 05/17/17 B 3.6-85 09/19/18 B 3.6-38 05/17/17 B 3.6-86 09/19/18 B 3.6-39 0 B 3.6-87 05/17/17 B 3.6-40 0 Cooper 5 01 /06/21

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TABLE OF CONTENTS 8 3.3 INSTRUMENTATION (continued)

B 3.3.7.1 Control Room Emergency Filter (CREF) System lnstrumentation .. ....................... ....... ....... ... .. .... .................... . B 3.3-180 B 3.3.8.1 Loss of Power (LOP) lnstrumentation ... ........ .............................. B 3.3-189 B 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring .......................... ... ...... ... ........ ........ ........... 8 3.3-199 8 3.4 REACTOR COOLANT SYSTEM (RCS) .. .... .... ............................. .. ........... B 3.4-1 B 3.4.1 Recirculation Loops Operating ... ................................................... B 3.4-1 B 3.4.2 Jet Pumps .............................. ...... .................. ... ........... ................. B 3.4-9 8 3.4.3 Safety/Relief Valves (SRVs) and Safety Valves (SVs) ................. B 3.4-14 B 3.4.4 RCS Operational LEAKAGE. ......... ......... ............... ..... .. .......... ...... B 3.4-19 B 3.4.5 RCS Leakage Detection Instrumentation .................................. ... 8 3.4-24 B 3.4.6 RCS Specific Activity ...... ................ .. ...... ........ ............ .................. B 3.4-30 B 3.4.7 Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown ...... .. ....... ... ... .. ... ............. ................ .. 8 3.4-34 B 3.4.8 Residual Heat Removal (RHR) Shutdown Cooling System - Cold Shutdown ....................................................... B 3.4-39 B 3.4.9 RCS Pressure and Temperature (PIT) Limits .. ............................. 8 3.4-44 B 3.4.10 Reactor Steam Dome Pressure ............. ............... ... ........... .... .... .. B 3.4-53 8 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC)

SYSTEM ........... .. ............... ........................................................ ... ............ B 3.5-1 B 3.5.1 ECCS - Operating .......................................... ................. ......... .... B 3.5-1 8 3.5.2 Reactor Pressure Vessel (RPV) Water Inventory Control. ............ 8 3.5-18 B 3.5.3 RCIC System .................................................. .......................... ... 8 3.5-27 B 3.6 CONTAINMENT SYSTEMS ...... ....... .. ........... .. ........................... .. ............ B 3.6-1 8 3.6.1.1 Primary Containment ............... ..... .. ... .......... ................ ................. B 3.6-1 B 3.6.1.2 Primary Containment Air Lock .... ..... ............. ... .............................. 8 3.6-6 8 3.6.1.3 Primary Containment Isolation Valves (PCIVs) ............................ 8 3.6-15 8 3.6.1.4 Drywall Pressure ................ .................. ... .. .. .. .... .... .... ................... 8 3.6-30 B 3.6.1.5 Drywell Air Temperature .................. ........ ....... .............. ................ B 3.6-32 8 3.6.1.6 Low-Low Set (LLS) Valves ..... ........ ....... .. ..................................... B 3.6-35 B 3.6.1.7 Reactor Building-to-Suppression Chamber Vacuum Breakers ........... ................ ........ .. ............................... ............. 8 3.6-39 B 3.6.1 .8 Suppression Chamber-to-Drywall Vacuum Breakers .... .. .............. B 3.6-45 B 3.6.1.9 Residual Heat Removal (RHR) Containment Spray ...... ............... B 3.6-51 B 3.6.2.1 Suppression Pool Average Temperature .. ................................. ... B 3.6-55 8 3.6.2.2 Suppression Pool Water Level ..... ................................ .. .. ..... ... .... 8 3.6-60 8 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling ........... B 3.6-63 Cooper ii 12/19/19

Reactor Core Sls B 2.1.1 B 2.0 SAFETY LIMITS (Sls)

B 2.1.1 Reactor Core SLs BASES BACKGROUND USAR, Appendix F (Ref. 1) establishes, and SLs ensure, that specified acceptable fuel design limits are not exceeded during steady state operation, normal operational transients, and abnormal operational transients.

The fuel cladding integrity SL is set such that no significant fuel damage is calculated to occur if the limit is not violated. Because fuel damage is not directly observable, a stepback approach is used to establish an SL, such that the MCPR is not less than the limit specified in Specification 2.1.1.2 for General Electric Company (GE) fuel. MCPR greater than the specified limit represents a conservative margin relative to the conditions required to maintain fuel cladding integrity.

The fuel cladding is one of the physical barriers that separate the radioactive materials from the environs. The integrity of this cladding barrier is related to its relative freedom from perforations or cracking .

Although some corrosion or use related cracking may occur during the life of the cladding, fission product migration from this source is incrementally cumulative and continuously measurable. Fuel cladding perforations, however, can result from thermal stresses, which occur from reactor operation significantly above design conditions.

While fission product migration from cladding perforation is just as measurable as that from use related cracking, the thermally caused cladding perforations signal a threshold beyond which still greater thermal stresses may cause gross, rather than incremental, cladding deterioration. Therefore, the fuel cladding SL is defined with a margin to the conditions that would produce onset of transition boiling (i.e.,

MCPR = 1.00). These conditions represent a significant departure from the condition intended by design for planned operation. This is accomplished by having a Safety Limit Minimum Critical Power Ratio (SLMCPR) design basis, referred to as SLMCPR9s19s, which corresponds to a 95% probability at a 95% confidence level (the 95/95 MCPR criterion) that transition boiling will not occur.

Operation above the boundary of the nucleate boiling regime could result in excessive cladding temperature because of the onset of transition boiling and the resultant sharp reduction in heat transfer coefficient. Inside the steam film, high cladding temperatures are reached, and a cladding water (zirconium water) reaction may take place. This chemical reaction results in oxidation of the fuel cladding to a structurally weaker form. This weaker form may lose its integrity, resulting in an uncontrolled release of activity to the reactor coolant.

Cooper B 2.0-1 07/01/20

Reactor Core SLs B 2.1.1 BASES BACKGROUND (continued)

The reactor vessel water level SL ensures that adequate core cooling capability is maintained during all MODES of reactor operation.

Sufficient reactor vessel water level ensures adequate margin for effective action in the event of a level drop.

APPLICABLE SAFETY ANALYSES The fuel cladding must not sustain damage as a result of normal operation and abnormal operational transients. The Tech Spec SL is set generically on a fuel product MCPR correlation basis as the MCPR which corresponds to a 95% probability at a 95% confidence level that transition boiling will not occur, referred to as SLMCPR95/95.

The Reactor Protection System setpoints (LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation"), in combination with the other LCOs, are designed to prevent any anticipated combination of transient conditions for Reactor Coolant System water level, pressure, and THERMAL POWER level that would result in reaching the MCPR limit.

2.1.1.1 Fuel Cladding Integrity General Electric Company {GE)

Fuel GE critical power correlations are applicable for all critical power calculations at pressures~ 785 psig and core flows ~ 10% of rated flow.

For operation at low pressures or low flows, another basis is used, as follows:

Since the pressure drop in the bypass region is essentially all elevation head, the core pressure drop at low power and flows will always be> 4.5 psi. Analyses (Ref. 2) show that with a bundle flow of 28 x 103 lb/hr, bundle pressure drop is nearly independent of bundle power and has a value of 3.5 psi. Thus, the bundle flow with a 4.5 psi driving head will be > 28 x 103 lb/hr. Full scale ATLAS test data taken at pressures from 14. 7 psia to 800 psia indicate that the fuel assembly critical power at this flow is approximately 3.35 MWt. With the design peaking factors, this corresponds to a THERMAL POWER> 50 % RTP. Thus, a THERMAL POWER limit of 25% RTP for reactor pressure

< 785 psig is conservative.

Cooper B 2.0-2 07/01/20

Reactor Core SLs B 2.1.1 BASES APPLICABLE SAFETY ANALYSES (continued) 2.1 .1.2 MCPR GE Fuel The fuel cladding integrity SL is set such that no significant fuel damage is calculated to occur if the limit is not violated. Since the parameters that result in fuel damage are not directly observable during reactor operation, the thermal and hydraulic conditions that result in the onset of transition boiling have been used to mark the beginning of the region in which fuel damage could occur. Although it is recognized that the onset of transition boiling would not result in damage to BWR fuel rods, the critical power at which boiling transition is calculated to occur has been adopted as a convenient limit. The Technical Specifications SL value is dependent on the fuel product line and the corresponding MCPR correlation, which is cycle independent. The value is based on the Critical Power Ratio (CPR) data statistics and a 95% probability with 95% confidence that rods are not susceptible to boiling transition ,

referred to as SLMCPR95195.

The SL is based on GNF2 fuel. For cores loaded with a single fuel product line, the SLMCPR95195 is the MCPR95195 for the fuel type. For cores loaded with a mix of applicable fuel types, the SLMCPR95J95 is based on the largest (i.e., most limiting) of the MCPR values for the fuel product lines that are fresh or once-burnt at the start of the cycle.

2.1.1 .3 Reactor Vessel Water Level During MODES 1 and 2 the reactor vessel water level is required to be above the top of the active irradiated fuel to provide core cooling capability. With fuel in the reactor vessel during periods when the reactor is shut down, consideration must be given to water level requirements due to the effect of decay heat. If the water level should drop below the top of the active irradiated fuel during this period, the ability to remove decay heat is reduced. This reduction in cooling capability could lead to elevated cladding temperatures and clad perforation in the event that the water level becomes < 2/3 of the core height. The reactor vessel water level SL has been established at the top of the active irradiated fuel to provide a point that can be monitored and to also provide adequate margin for effective action. Fuel zone zero (FZZ) is used as a reference point which corresponds to at or above top of the active irradiated fuel.

Cooper B 2.0-3 07/01/20

Reactor Core SLs B 2.1.1 BASES (continued)

SAFETY LIMITS The reactor core SLs are established to protect the integrity of the fuel clad barrier to prevent the release of radioactive materials to the environs. SL 2.1.1.1 and SL 2.1.1.2 ensure that the core operates within the fuel design criteria. SL 2.1.1 .3 ensures that the reactor vessel water level is greater than the top of the active irradiated fuel in order to prevent elevated clad temperatures and resultant clad perforations.

APPLICABILITY SLs 2.1.1.1, 2.1.1.2, and 2.1.1.3 are applicable in all MODES.

SAFETY LIMIT VIOLATIONS Exceeding an SL may cause fuel damage and create a potential for radioactive releases in excess of 10 CFR 100, "Reactor Site Criteria,"

limits (Ref. 3) for the Control Rod Drop and Main Steam Line Break accidents, and 10 CFR 50.67, "Accident Source Term," limits (Ref. 4) for the Fuel Handling and Loss-of-Coolant accidents. Therefore, it is required to insert all insertable control rods and restore compliance with the SLs within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time ensures that the operators take prompt remedial action and also ensures that the probability of an accident occurring during this period is minimal.

REFERENCES 1. USAR, Appendix F, Section F-2.2.1.

2. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel," (Revision specified in the COLR).

3. 10 CFR 100.

4. 10 CFR 50.67.

Cooper B 2.0-4 07/01/20

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 reactor steam dome pressure protects the RCS against overpressurization. In the event of fuel cladding failure, fission products are released into the reactor coolant. The RCS then serves as the primary barrier in preventing the release of fission products into the atmosphere. Establishing an upper limit on reactor steam dome pressure ensures continued RCS integrity. According to the USAR, Appendix F (Ref. 1), the reactor coolant pressure boundary (RCPB) shall be capable of accommodating without rupture, and with only limited allowance for energy absorption through plastic deformation, the static and dynamic loads imposed on any boundary component as a result of any inadvertent and sudden release of energy to the coolant.

As a design reference, this sudden release shall be taken as that which would result from a sudden reactivity insertion such as rod ejection (unless prevented by positive mechanical means), rod dropout, or cold water addition.

During normal operation and abnormal operational transients, 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, in accordance with ASME Code requirements, prior to initial operation when there is no fuel in the core.

Any further hydrostatic testing with fuel in the core may be done under LCO 3.10.1, "lnservice Leak and Hydrostatic Testing Operation."

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, reducing the number of protective barriers designed to prevent radioactive releases from exceeding the limits specified in 10 CFR 50.67, "Accident Source Term" (Ref. 4). If this occurred in conjunction with a fuel cladding failure, fission products could enter the containment atmosphere.

Cooper B 2.0-5 07/01/20

RCS Pressure SL B 2.1.2 BASES (continued)

APPLICABLE SAFETY ANALYSES The RCS safety/relief valves and the Reactor Protection System Reactor Vessel Steam Dome Pressure- High Function have settings established to ensure that the RCS pressure SL will not be exceeded.

The RCS pressure SL has been selected such that it is at a pressure below which it can be shown that the integrity of the system is not endangered. The reactor pressure vessel is designed to Section Ill of the ASME, Boiler and Pressure Vessel Code, 1965 Edition, including Addenda through the winter of 1966 (Ref. 5), which permits a maximum pressure transient of 110%, 1375 psig, of design pressure 1250 psig.

The SL of 1337 psig, as measured in the reactor steam dome, is equivalent to 1375 psig at the lowest elevation of the RCS . The RCS is designed to the USAS Nuclear Power Piping Code, Section 831.1, 1967 Edition (Ref. 6), and Section Ill of the ASME, Boiler and Pressure Vessel Code, 1983 Edition (Ref. 7), for the reactor recirculation piping, which permits a maximum pressure transient of 120% of design pressures of 1148 psig for suction piping and 1274 psig for discharge piping. The RCS pressure SL is selected to be the lowest transient overpressure allowed by the applicable codes.

SAFETY LIMITS The maximum transient pressure allowable in the RCS pressure vessel under the ASME Code, Section 111, is 110% of design pressure. The maximum transient pressure allowable in the RCS piping, valves, and fittings is 120% of design pressures of 1148 psig for suction piping and 1274 psig for discharge piping. The most limiting of these allowances is the 110% of the RCS pressure vessel design pressures; therefore, the SL on maximum allowable RCS pressure is established at 1337 psig as measured at the reactor steam dome.

APPLICABILITY SL 2.1.2 applies in all MODES.

SAFETY LIMIT VIOLATIONS Exceeding the RCS pressure SL may cause immediate RCS failure and create a potential for radioactive releases in excess of 10 CFR 50.67, "Accident Source Term," limits (Ref. 4). Therefore, it is required to insert all insertable control rods and restore compliance with the SL within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months . The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time ensures that the operators take prompt remedial action and also assures that the probability of an accident occurring during this period is minimal.

Cooper B 2.0-6 07/01/20

RCS Pressure SL B 2.1.2 BASES (continued)

REFERENCES 1. USAR, Appendix F, Section F-2.6.1.

2. ASME, Boiler and Pressure Vessel Code, Section Ill, Article NB-7000.

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

4. 10 CFR 50.67.

5. ASME, Boiler and Pressure Vessel Code, Section 111, 1965 Edition, Addenda winter of 1966.

6. ASME, USAS, Nuclear Power Piping Code, Section 831.1 , 1967 Edition.

7. ASME, Boiler and Pressure Vessel Code, Section 111, 1983 Edition.

Cooper B 2.0-7 07/01/20

LCO Applicability B 3.0 B 3.0 LIMITING CONDITION FOR OPERATION (LCO} APPLICABILITY BASES LCOs LCO 3.0.1 through LCO 3.0.8 establish the general requirements applicable to all Specifications in Sections 3.1 through 3.10 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 Acti_on 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 Cooper B 3.0-1 12/09/20

LCO Applicability B 3.0 BASES LCO 3.0.2 (continued)

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.

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

The nature of some Required Actions of some Conditions necessitates that, once the Condition is entered, the Required Actions must be completed even though the associated Condition no longer exists. The individual LCO's ACTIONS specify the Required Actions where this is the case. An example of this is in LCO 3.4.9, "RCS Pressure and Temperature (PIT) Limits."

The Completion Times of the Required Actions are also applicable when a system or component is removed from service intentionally. The ACTIONS for not meeting a single LCO adequately manage any increase in plant risk, provided any unusual external conditions (e.g., severe weather, offsite power instability) are considered . In addition, the increased risk associated with simultaneous removal of multiple structures, systems, trains, or components from service is assessed and managed in accordance with 10 CFR 50.65(a)(4). Individual Specifications may specify a time limit for performing an SR when equipment is removed from service or bypassed for testing . In this case, the Completion Times of the Required Actions are applicable when this time limit expires, if the equipment remains removed from service or bypassed.

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

Cooper B 3.0-2 10/15/19

LCO Applicability B 3.0 BASES LCO 3.0.3 (continued)

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

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

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

This Specification delineates the time limits for placing the unit in a safe MODE or other specified condition when operation cannot be maintained within the limits for safe operation as defined by the LCO and its ACTIONS. Planned entry into LCO 3.0.3 should be avoided. If it is not practicable to avoid planned entry into LCO 3.0.3, plant risk should be assessed and managed in accordance with 10 CFR 50.65(a)(4), and the planned entry into LCO 3.0.3 should have less effect on plant safety than other practicable alternatives.

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.

Cooper B 3.0-3 12/09/20

LCO Applicability B 3.0 BASES LCO 3.0.3 (continued)

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

a. The LCO is now met.

b. 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.

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 MOOE 4 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 4, or other applicable MODE, is not reduced. For example, if MODE 2 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 3 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 3 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, and 3, 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 4 and 5 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, or 3) 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 3.7.6, "Spent Fuel Storage Pool Water Level." LCO 3.7.6 has an Applicability of "During movement of irradiated fuel Cooper B 3.0-4 12/09/20

LCO Applicability B 3.0 BASES LCO 3.0.3 (continued) assemblies in the spent fuel storage pool." Therefore, this LCO can be applicable in any or all MODES. If the LCO and the Required Actions of LCO 3.7.6 are not met while in MODE 1, 2, or 3, there is no safety benefit to be gained by placing the unit in a shutdown condition . The Required Action of LCO 3.7.6 to "Suspend movement of irradiated fuel assemblies in the spent 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 requ irements of the LCO would not be met, in accordance with either LCO 3.0.4.a, LCO 3.0.4.b, or LCO 3.0.4.c.

LCO 3.0.4.a allows entry into a MODE or other specified condition in the Applicability with the LCO not met when the associated ACTIONS to be entered following entry into in 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 Actions 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.

Cooper B 3.0-5 12/09/20

LCO Applicability B 3.0 BASES LCO 3.0.4 (continued)

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

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

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

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

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

Cooper B 3.0-6 12/09/20

LCO Applicability B 3.0 BASES LCO 3.0.4 (continued)

The Technical Specifications allow continued operation with equipment unavailable in MODE 1 for the duration of the Completion Time. Since this is allowable, and since in general the risk impact in that particular MODE bounds the risk of transitioning into and through the applicable MODES or other specified conditions in the Applicability of the LCO, the use of the LCO 3.0.4.b allowance should be generally acceptable, as long as the risk is assessed and managed as stated above . However, there is a small subset of systems and components that have been determined to be more important to risk and use of the LCO 3.0 .4.b allowance is prohibited. The LCOs governing these systems and components contain Notes prohibiting the use of LCO 3.0.4.b by stating that LCO 3.0.4.b is not applicable.

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

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

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

Cooper B 3.0-7 12/09/20

LCO Applicability B 3.0 BASES LCO 3.0.4 {continued)

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

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

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

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

b. The OPERABILITY of other equipment.

The administrative controls ensure the time the equipment is returned to service in conflict with the requirements of the ACTIONS is limited to the time absolutely necessary to perform the allowed SRs. This Specification does not provide time to perform any other preventive or corrective maintenance. LCO 3.0.5 should not be used in lieu of other practicable alternatives that 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 Require 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 the RCS PIV leakage is now within limit.

Cooper B 3.0-8 12/09/20

LCO Applicability B 3.0 BASES LCO 3.0.5 (continued)

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 an SR 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 an SR 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 plant is maintained in a safe condition are specified in the support systems' LCO's Required Actions. These Required Actions may include entering the supported system's Conditions and Required Actions or may specify other Required Actions.

When a support system is inoperable and there is an LCO specified for it in the TS , the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' LCO Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the Cooper B 3.0-9 12/09/20

LCO Applicability B 3.0 BASES LCO 3.0.6 (continued) plant 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 5.5.11, "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 division checks to identify a loss of safety function for those support systems that support safety systems are required. The cross division 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.

Special Operations LCOs in Section 3.10 allow specified TS requirements to be changed to permit performances of these special tests and operations, which otherwise could not be performed if required to comply with the requirements of these TS. Unless otherwise specified, all the other TS requirements remain unchanged. This will ensure all appropriate requirements of the MODE or other specified condition not directly associated with or required to be changed to perform the special test or operation will remain in effect.

Cooper 8 3.0-10 12/09/20

LCO Applicability B 3.0 BASES LCO 3.0.7 (continued)

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

Compliance with Special Operations LCOs is optional. A special operation may be performed either under the provisions of the appropriate Special Operations LCO or under the other applicable TS requirements. If it is desired to perform the special operation under the provisions of the Special Operations LCO, the requirements of the Special Operations LCO shall be followed. When a Special Operations LCO requires another LCO to be met, only the requirements of the LCO statement are required to be met regardless of that LCO's Applicability (i.e., should the requirements of this other LCO not be met, the ACTIONS of the Special Operations LCO apply, not the ACTIONS of the other LCO). However, there are instances where the Special Operations LCO ACTIONS may direct the other LCO ACTIONS be met. The Surveillances of the other LCO are not required to be met, unless specified in the Special Operations LCO. If conditions exist such that the Applicability of any other LCO is met, all the other LCO's requirements (ACTIONS and SRs) are required to be met concurrent with the requirements of the Special Operations LCO.

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 in the snubber requirements, which are located outside of the Technical Specifications (TS) under licensee control. The snubber requirements do not meet the criteria in 10 CFR 50.36(c)(2)(ii), and, as such, are appropriate for control by the licensee.

If the allowed time expires and the 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 can be used only if one of the following two means of heat removal is available:

Cooper B 3.0-11 12/09/20

SR Applicability B 3.0 BASES SR 3.0.2 (continued)

When a Section 5.5, "Programs and Manuals," Specification states that the provisions of SR 3.0.2 are applicable, a 25% extension of the testing interval, whether stated in the Specification or incorporated by reference, is permitted.

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. Examples of where SR 3.0.2 does not apply are the Containment Leakage Rate Testing Program required by 10 CFR 50, Appendix J, and the inservice testing of pumps and valves in accordance with applicable American Society of Mechanical Engineers Operation and Maintenance Code, as required by 10 CFR 50.55a. These programs establish testing requirements and Frequencies in accordance with the requirements of the regulations. The TS cannot in and of themselves extend a test interval specified in the regulations, directly or by reference.

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 the function of the inoperable equipment in an alternative manner.

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 Cooper B 3.0-15 12/09/20

SR Applicability B 3.0 BASES SR 3.0.3 (continued) with SR 3.0.2, and not at the time that the specified Frequency was not met.

When a Section 5.5, "Programs and Manuals," Specification states that the provisions of SR 3.0.3 are applicable, it permits the flexibility to defer declaring the testing requirement not met in accordance with SR 3.0.3 when the testing has not been completed within the testing interval (including the allowance of SR 3.0.2 if invoked by the Section 5.5 Specification).

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 to have been performed when specified, SR 3.0.3 allows 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 activities that might support the expectation that the Surveillance will be 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 Cooper B 3.0-16 12/09/20

SR Applicability B 3.0 BASES SR 3.0.3 (continued) particular SR, but previous successful performances of the SR included in 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.

Fai lure 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 Cooper B 3.0-17 12/09/20

SR Applicability B 3.0 BASES SR 3.0.3 (continued) determine the risk increase is significant, this evaluation should be used to determine the safest course of action. All missed Surveillances will be placed in the licensee's Corrective Action Program.

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.

However, 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 an SR not being met if the entry is made in accordance with LCO 3.0.4.

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

The provisions of this Specification should not be interpreted as endorsing the failure to exercise the good practice of restoring systems or components to OPERABLE status before entering an associated MODE or other specified condition in the Applicability. 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 Surveillarces 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, on equipment that is inoperable, 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 Cooper B 3.0-18 12/09/20

SR Applicability B 3.0 BASES SR 3.0.3 (continued)

(or may not) apply to MODE or other specified condition changes. SR 3.0.4 does not restrict changing MODES or other specified conditions of the Applicability 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, and MODE 3 to MODE 4.

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 Applicability would have its Frequency specified such that it is not "due" until the specific conditions needed are met.

Alternately, the Surveillance may be stated in the form of a Note as not required (to be met or performed) until a particular event, condition, or time has been reached. Further discussion of the specific formats of SRs' annotation is found in Section 1.4, Frequency.

I Cooper B 3.0-19 12/09/20

MCPR B 3.2.2 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR)

BASES BACKGROUND MCPR is a ratio of the fuel assembly power that would result in the onset of boiling transition to the actual fuel assembly power. The operating limit MCPR is established to ensure that no fuel damage results during abnormal operational transients, and that 99.9% of the fuel rods are not susceptible to boiling transition if the limit is not violated. Although fuel damage does not necessarily occur if a fuel rod actually experienced boiling transition (Ref. 1), the critical power at which boiling transition is calculated to occur has been adopted as a fuel design criterion.

The onset of transition boiling is a phenomenon that is readily detected during the testing of various fuel bundle designs. Based on these experimental data, correlations have been developed to predict critical bundle power (i.e., the bundle power level at the onset of transition boiling) for a given set of plant parameters (e.g., reactor vessel pressure, flow, and subcooling). Because plant operating conditions and bundle power levels are monitored and determined relatively easily, monitoring the MCPR is a convenient way of ensuring that fuel failures due to inadequate cooling do not occur.

APPLICABLE SAFETY ANALYSES The analytical methods and assumptions used in evaluating the abnormal operational transients to establish the operating limit MCPR are presented in References 2, 3, 4, 5, 6, and 7. To ensure that the MCPR SL is not exceeded during any transient event that occurs with moderate frequency, limiting transients have been analyzed to determine the largest reduction in critical power ratio (CPR). The types of transients evaluated are loss of flow, increase in pressure and power, positive reactivity insertion, and coolant temperature decrease. The limiting transient yields the largest change in CPR (~CPR). When the largest ~CPR is combined with the SLMCPR99.9%, the required operating limit MCPR is obtained.

MCPR99.9% is determined to ensure more than 99.9% of the fuel rods in the core are not susceptible to boiling transition using a statistical model that combines all the uncertainties in operating parameters and the procedures used to calculate critical power. The probability of the occurrence of boiling transition is determined using the approved Critical Power correlations. Details of the MCPR99.9% calculation are given in Reference 2. Reference 2 also includes a tabulation of the uncertainties and the nominal values of the parameters used in the MCPRgg_go;.

statistical analysis.

Cooper B 3.2-4 07/01/20

MCPR B 3.2.2 BASES APPLICABLE SAFETY ANALYSIS (continued)

The MCPR operating limits are derived from the MCPR99.9% value and the transient analysis, and are dependent on the operating core flow and power state (MCPRr and MCPRp, respectively) to ensure adherence to fuel design limits during the worst transient that occurs with moderate frequency (Refs. 6 and 7). Flow dependent MCPR limits are determined by steady state thermal hydraulic methods with key physics response inputs benchmarked using the three dimensional BWR simulator code (Ref. 8) to analyze slow flow runout transients. The operating limit is dependent on the maximum core flow limiter setting in the Recirculation Flow Control System.

Power dependent MCPR limits (MCPRp) are determined by approved transient analysis (Ref. 9). Due to the sensitivity of the transient response to initial core flow levels at power levels below those at which the turbine stop valve closure and turbine control valve fast closure scrams are bypassed, high and low flow MCPRP operating limits are provided for operating between 25% RTP and the previously mentioned bypass power level.

The MCPR satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 10).

LCO The MCPR operating limits specified in the COLR (MCPR99.9% value, MCPR, values, and MCPRp values) are the result of the Design Basis Accident (OBA) and transient analysis. The operating limit MCPR is determined by the larger of the MCPRt and MCPRp limits, which are based on the MCPR99.9% limit specified in the COLR.

APPLICABILITY The MCPR operating limits are primarily derived from transient analyses that are assumed to occur at high power levels. Below 25% RTP, the reactor is operating at a minimum recirculation pump speed and the moderator void ratio is small. Surveillance of thermal limits below 25%

RTP is unnecessary due to the large inherent margin that ensures that the MCPR SL is not exceeded even if a limiting transient occurs.

Statistical analyses indicate that the nominal value of the initial MCPR expected at 25% RTP is> 3.5. Studies of the variation of limiting transient behavior have been performed over the range of power and flow conditions. These studies encompass the range of key actual plant parameter values important to typically limiting transients. The results of these studies demonstrate that a margin is expected between performance and the MCPR requirements, and that margins increase as power is reduced to 25% RTP. This trend is expected to continue to the 5% to 15% power range when entry into MODE 2 occurs. When in MODE 2, the intermediate range monitor provides rapid scram initiation Cooper B 3.2-5 07/01/20

MCPR B 3.2.2 BASES APPLICABILITY (continued) for any significant power increase transient, which effectively eliminates any MCPR compliance concern. Therefore, at THERMAL POWER levels

< 25% RTP, the reactor is operating with substantial margin to the MCPR limits and this LCO is not required.

ACTIONS A.1 If any MCPR is outside the required limits, an assumption regarding an initial condition of the design basis transient analyses may not be met.

Therefore, prompt action should be taken to restore the MCPR(s) to within the required limits such that the plant remains operating within analyzed conditions. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is normally sufficient to restore the MCPR(s) to within its limits and is acceptable based on the low probability of a transient or OBA occurring simultaneously with the MCPR out of specification.

B.1 If the MCPR cannot be restored to within its required limits within the associated Completion Time, the plant must be brought to a MODE or other specified condition in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to < 25% RTP within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The allowed Completion Time is reasonable, based on operating experience, to reduce THERMAL POWER to< 25% RTP in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS SR 3.2.2.1 The MCPR is required to be initially calculated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months after THERMAL POWER is~ 25% RTP and periodically thereafter. It is compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER ~ 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Cooper B 3.2-6 07/01/20

RPS Instrumentation B 3.3.1.1 BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued) channels per trip system for both SDVs, a total of two required channels of each type per trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from these Functions on a valid signal. These Functions are required in MODES 1 and 2, and in MODE 5 with any control rod withdrawn from a core cell containing one or more fuel assemblies, since these are the MODES and other specified conditions when control rods are withdrawn. At all other times, this Function may be bypassed.

8. Turbine Stop Valve-Closure Closure of the TSVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated at the start of TSV closure in anticipation of the transients that would result from the closure of these valves. The Turbine Stop Valve-Closure Function is the primary scram signal for the turbine trip and feedwater controller failure maximum demand events analyzed in Reference 3. For this event, the reactor scram reduces the amount of energy required to be absorbed and ensures that the MCPR SL is not exceeded.

Turbine Stop Valve-Closure signals are initiated from position switches located on each of the two TSVs. Two independent position switches are associated with each stop valve. Both of the switches from one TSV provide input to RPS trip system A; the two switches from the other TSV provide input to RPS trip system B. Thus, each RPS trip system receives two Turbine Stop Valve-Closure channel inputs from a TSV, each consisting of one position switch assembly with two contacts, each inputting to a relay. The relays provide a parallel logic input to an RPS trip logic channel. The logic for the Turbine Stop Valve-Closure Function is such that both TSVs must be closed to produce a scram. Single valve closure will produce a half scram. This Function must be enabled at THERMAL POWER:.!: 29.5% RTP as measured by turbine supply pressure. This is accomplished automatically by pressure switches sensing turbine supply pressure; therefore, opening the turbine bypass valves may affect this Function.

The Turbine Stop Valve-Closure Allowable Value is selected to detect imminent TSV closure, thereby reducing the severity of the subsequent pressure transient.

Four channels of Turbine Stop Valve-Closure Function, with two channels in each trip system, are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function if both Cooper B 3.3-16 04/10/19

RPS Instrumentation B 3.3.1 .1 BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued)

TSVs should close. This Function is required, consistent with analysis assumptions, whenever THERMAL POWER is 2: 29.5% RTP. This Function is not required when THERMAL POWER is< 29.5% RTP since the Reactor Vessel Pressure-High and the Average Power Range Monitor Neutron Flux-High (Fixed) Functions are adequate to maintain the necessary safety margins.

9. Turbine Control Valve Fast Closure, DEH Trip Oil Pressure-Low Fast closure of the TCVs results in the loss of a heat sink that produces reactor pressure, neutron flux, and heat flux transients that must be limited. Therefore, a reactor scram is initiated on TCV fast closure in anticipation of the transients that would result from the closure of these valves. The Turbine Control Valve Fast Closure, DEH Trip Oil Pressure-Low Function is the primary scram signal for the generator load rejection event analyzed in Reference 3. For this event, the reactor scram reduces the amount of energy required to be absorbed and ensures that the MCPR SL is not exceeded.

Turbine Control Valve Fast Closure, DEH Trip Oil Pressure-Low signals are initiated by low digital-electrohydraulic control (DEHC) fluid pressure in the emergency trip header for the control valves. There are four pressure switches which sense off the common header, with one pressure switch assigned to each separate RPS logic channel. This Function must be enabled at THERMAL POWER 2: 29.5% RTP as measured by turbine supply pressure. This is accomplished automatically by pressure switches sensing turbine supply pressure; therefore, opening the turbine bypass valves may affect this Function.

The Turbine Control Valve Fast Closure, DEH Trip Oil Pressure-Low Allowable Value is selected high enough to detect imminent TCV fast closure.

Four channels of Turbine Control Valve Fast Closure, DEH Trip Oil Pressure-Low Function with two channels in each trip system arranged in a one-out-of-two logic are required to be OPERABLE to ensure that no single instrument failure will preclude a scram from this Function on a valid signal. This Function is required, consistent with the analysis assumptions, whenever THERMAL POWER is 2: 29.5% RTP. This Function is not required when THERMAL POWER is < 29.5% RTP, since the Reactor Vessel Pressure-High and the Average Power Range Monitor Neutron Flux-High (Fixed) Functions are adequate to maintain the necessary safety margins.

Cooper B 3.3-17 04/10/19

RPS Instrumentation B 3.3.1.1 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.1.1.14 This SR ensures that scrams initiated from the Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions will not be inadvertently bypassed when THERMAL POWER is c!:: 29.5% RTP. This involves calibration of the bypass channels.

Adequate margins for the instrument setpoint methodologies are incorporated into the actual setpoint. Because main turbine bypass flow can affect this setpoint nonconservatively (THERMAL POWER is derived from turbine supply pressure), the main turbine bypass valves must remain closed during an in-service calibration at THERMAL POWER

~ 29.5% RTP to ensure that the calibration is valid .

If any bypass channel's setpoint is nonconservative (i.e., the Functions are bypassed at~ 29.5% RTP, then the affected Turbine Stop Valve-Closure and Turbine Control Valve Fast Closure, Trip Oil Pressure-Low Functions are considered inoperable. Open main turbine bypass valve(s) can also affect these two functions. Alternatively, the bypass channel can be placed in the conservative condition (nonbypass). If placed in the nonbypass condition, this SR is met and the channel is considered OPERABLE.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.1.15 This SR ensures that the individual channel response times are less than or equal to the maximum values assumed in the accident analysis. This test may be performed in one measurement or in overlapping segments, with verification that all components are tested. The RPS RESPONSE TIME acceptance criteria are included in Reference 13.

As noted, neutron detectors are excluded from RPS RESPONSE TIME testing because the principles of detector operation virtually ensure an instantaneous response time.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Cooper B 3.3-29 04/10/19

SRM Instrumentation B 3.3.1.2 BASES SURVEILLANCE REQUIREMENTS (continued) by the same OPERABLE 'SRM. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.2.4 This Surveillance consists of a verification of the SRM instrument readout to ensure that the SRM reading is greater than a specified minimum count rate with the detector full-in, which ensures that the detectors are indicating count rates indicative of neutron flux levels within the core.

With few fuel assemblies loaded, the SRMs will not have a high enough count rate to satisfy the SR Therefore, allowances are made for loading sufficient "source" material, in the form of irradiated fuel assemblies, to establish the minimum count rate.

To accomplish this, the SR is modified by a Note that states that the count rate is not required to be met on an SRM that has less than or equal to four fuel assemblies adjacent to the SRM and no other fuel assemblies are in the associated core quadrant. With four or less fuel assemblies loaded around each SRM and no other fuel assemblies in the associated core quadrant, even with a control rod withdrawn, the configuration will not be critical. This SR does not require determination of the signal to noise ratio as SR 3.3.1.2.5 and SR 3.3.1.2.6 are credited for verifying the signal to noise requirement remains met.

The Frequency is based upon channel redundancy and other information available in the control room, and ensures that the required channels are frequently monitored while core reactivity changes are occurring. When no reactivity changes are in progress, the Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.2.5 and SR 3.3.1.2.6 Performance of a CHANNEL FUNCTIONAL TEST demonstrates the associated channel will function properly. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay.

This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests at least once per refueling interval with applicable extensions. SR 3.3.1.2.5 is required in MODE 5 and ensures that the channels are OPERABLE while core reactivity changes could be in progress. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Cooper B 3.3-37 10/15/19

PAM Instrumentation B 3.3.3.1 BASES LCO {continued) flow path with two active valves. For containment penetrations with only one active PCIV having control room indication, Note (b) requires a single channel of valve position indication to be OPERABLE. This is sufficient to redundantly verify the isolation status of each isolable penetration via indicated status of the active valve, as applicable, and prior knowledge of passive valve or system boundary status. If a penetration flow path is isolated, position indication for the PCIV(s) in the associated penetration flow path is not needed to determine status. Therefore, the position indication for valves in an isolated penetration flow path is not required to be OPERABLE.

The PCIV position PAM instrumentation consists of position switches, associated wiring and control room indicating lamps for active PCIVs (check valves and manual valves are not required to have position indication). Therefore, the PAM Specification deals specifically with these instrument channels.

6. [DELETED)

Cooper B 3.3-65 03/18/20

PAM Instrumentation B 3.3.3.1 BASES LCO (continued)

7. Primary Containment Pressure Primary containment pressure is a Category I variable provided to verify RCS and containment integrity and to verify the effectiveness of ECCS actions taken to prevent containment breach. Two drywell narrow range channels monitor a range of -5 psig to + 70 psig. Two drywall wide range channels monitor a range of O psig to 250 psig. Two suppression chamber wide range channels monitor a range of -5 psig to + 70 psig.

Each of the six channels has a separate transmitter. The six transmitters display their signals on recorders in the control room. These transmitters and recorders are the primary indication used by the operator during an accident. Therefore, the PAM Specification deals specifically with these portions of the instrument channel.

8. Suppression Pool Water Temperature Suppression pool water temperature is a Category I variable provided to detect a condition that could potentially lead to containment breach and to verify the effectiveness of ECCS actions taken to prevent containment breach. The suppression pool water temperature instrumentation allows operators to detect trends in suppression pool water temperature.

Suppression chamber water temperature is monitored by two redundant channels. Each channel consists of a multipoint recorder with inputs from 8 resistance temperature detectors (RTDs) that monitor temperature over a range of 0°F to 250°F. The RTDs are mounted in thermowells installed in the suppression chamber shell below the minimum water level. A channel is considered OPERABLE with up to 4 RTDs inoperable, provided no 2 adjacent RTDs are inoperable. This minimum requirement maintains temperature monitoring in each quadrant of the suppression chamber. This is acceptable based on engineering judgement considering the temperature response profile of the suppression chamber water volume for previously analyzed events and the most challenged RTDs inoperable.

Cooper B 3.3-66 03/18/20

PAM Instrumentation B 3.3.3.1 BASES ACTIONS (continued)

For the majority of Functions in Table 3.3.3.1-1, if any Required Action and associated Completion Time of Condition C is not met, the plant must be brought to a MODE in which the LCD not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

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

E1 Since alternate means of monitoring primary containment area radiation have been developed and tested, the Required Action is not to shut down the plant, but rather to follow the directions of Specification 5.6.6. These alternate means may be temporarily installed if the normal PAM channel cannot be restored to OPERABLE status within the allotted time. The report provided to the NRC should discuss the alternate means used, describe the degree to which the alternate means are equivalent to the installed PAM channels, justify the areas in which they are not equivalent, and provide a schedule for restoring the normal PAM channels.

SURVEILLANCE REQUIREMENTS SR 3.3.3.1.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel against a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

The high radiation instrumentation should be compared to similar plant instruments located throughout the plant.

Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including isolation, Cooper B 3.3-69 03/18/20

PAM Instrumentation B 3.3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) indication, and readability. If a channel is outside the criteria, it may be an indication that the sensor or the signal processing equipment has drifted outside its limit.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.3.3.1.2 [DELETED]

SR 3.3.3.1.3 This SR requires a CHANNEL CALIBRATION to be performed.

CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies the channel responds to measured parameter with the necessary range and accuracy. There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found settings are consistent with those established by the setpoint methodology. For the Primary Containment Gross Radiation Monitors, the CHANNEL CALIBRATION consists of an electronic calibration of the channel, excluding the detector, for range decades c? 10 R/hour and a one point calibration check of the detector with an installed or portable gamma source for range decades

< 10 R/hour. For the PCIV Position Function, the CHANNEL CALIBRATION consists of verifying the remote indication conforms to actual value position.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. Regulatory Guide 1.97, "Instrumentation for Light Water Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident, Revision 2," December 1980.

2. Letter from G. A. Trevors (NPPD) to U.S. NRC dated April 12, 1990, "NUREG-0737, Supplement 1-Regulatory Guide 1.97 Response, Revision IX."

Cooper B 3.3-70 03/18/20

ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) 3.f. High Pressure Coolant Injection Pump Discharge Flow-Low (Bypass)

The minimum flow instrument is provided to protect the HPCI pump from overheating when the pump is operating at reduced flow. The minimum flow line valve is opened when low flow is sensed and either 1 ) the pump is on, or 2) the system has initiated; and the valve is automatically closed when the flow rate is adequate to protect the pump. The High Pressure Coolant Injection Pump Discharge Flow-Low Function is assumed to be OPERABLE. The minimum flow valve for HPCI is required to close to meet TS required injection flow, but is not required to close to ensure that the ECCS flow assumed during the transients analyzed in References 6, 7, and 8 are met. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

One flow switch is used to detect the HPCI System's flow rate. The logic is arranged such that the switch causes the minimum flow valve to open .

The logic will close the minimum flow valve once the closure setpoint is exceeded.

The High Pressure Coolant Injection Pump Discharge Flow-Low Allowable Value is high enough to ensure that pump flow rate is sufficient to protect the pump, yet low enough to ensure that the closure of the minimum flow valve is initiated to allow full flow into the core.

One channel is required to be OPERABLE when the HPCI is required to be OPERABLE. Refer to LCO 3.5.1 for HPCI Applicability Bases.

Automatic Depressurization System 4.a, 5.a. Reactor Vessel Water Level-Low Low Low (Level 1)

Low RPV water level indicates that the capability to cool the fuel may be threatened. Should RPV water level decrease too far, fuel damage could result. Therefore, ADS receives one of the signals necessary for initiation from this Function. The Reactor Vessel Water Level-Low Low Low (Level

1) is one of the Functions assumed to be OPERABLE and capable of initiating the ADS during the accident analyzed in Reference 7. The core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

Reactor Vessel Water Level-Low Low Low (Level 1) signals are initiated from four level switches that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to Cooper B 3.3-105 08/19/19

ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) the actual water level (variable leg) in the vessel. Four channels of Reactor Vessel Water Level-Low Low Low {Level 1) Function are required to be OPERABLE only when ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation.

Two channels input to ADS trip system A, while the other two channels input to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases.

The Reactor Vessel Water Level-Low Low Low (Level 1) Allowable Value is chosen to allow time for the low pressure core flooding systems to initiate and provide adequate cooling.

4.b, 5.b. Automatic Depressurization System Initiation Timer The purpose of the Automatic Depressurization System Initiation Timer is to delay depressurization of the reactor vessel to allow the HPCI System time to maintain reactor vessel water level. Since the rapid depressurization caused by ADS operation is one of the most severe transients on the reactor vessel, its occurrence should be limited. By delaying initiation of the ADS Function, the operator is given the chance to monitor the success or failure of the HPCI System to maintain water level, and then to decide whether or not to allow ADS to initiate, to delay initiation further by recycling the timer, or to inhibit initiation permanently. The Automatic Depressurization System Initiation Timer Function is assumed to be OPERABLE for the accident analysis of Reference 7 that requires ECCS initiation and assumes failure of the HPCI System.

There are two Automatic Depressurization System Initiation Timer relays, one in each of the two ADS trip systems. The Allowable Value for the Automatic Depressurization System Initiation Timer is chosen so that there is still time after depressurization for the low pressure ECCS subsystems to provide adequate core cooling.

Two channels of the Automatic Depressurization System Initiation Timer Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. (One channel inputs to ADS trip system A, while the other channel inputs to ADS trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases.

4.c, 5.c. Reactor Vessel Water Level-Low (Level 3)

The Reactor Vessel Water Level-Low (Level 3) Function is used by the ADS only as a confirmatory low water level signal. ADS receives one of Cooper B 3.3-106 08/19/19

ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) the signals necessary for initiation from Reactor Vessel Water Level-Low Low Low (Level 1) signals. In order to prevent spurious initiation of the ADS due to spurious Level 1 signals, a Level 3 signal must also be received before ADS initiation commences.

Reactor Vessel Water Level-Low (Level 3) signals are initiated from two level switches that sense the difference between the pressure due to a constant column of water (reference leg) and the pressure due to the actual water level (variable leg) in the vessel. The Allowable Value for Reactor Vessel Water Level-Low (Level 3) is selected to be above the RPS Level 3 scram Allowable Value for convenience. Refer to LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation," for the Bases discussion of this Function.

Two channels of Reactor Vessel Water Level-Low (Level 3) Function are only required to be OPERABLE when the ADS is required to be OPERABLE to ensure that no single instrument failure can preclude ADS initiation. One channel inputs to ADS trip system A, while the other channel inputs to ADS trip system 8. Refer to LCO 3.5.1 for ADS Applicability Bases.

4.d, 4.e, 5.d. 5.e. Core Spray and Low Pressure Coolant Injection Pump Discharge Pressure-High The Pump Discharge Pressure-High signals from the CS and LPCI pumps are used as permissives for ADS initiation, indicating that there is a source of low pressure cooling water available once the ADS has depressurized the vessel. Pump Discharge Pressure-High is one of the Functions assumed to be OPERABLE and capable of permitting ADS initiation during the events analyzed in Reference 7 with an assumed HPCI failure. For these events the ADS depressurizes the reactor vessel so that the low pressure ECCS can perform the core cooling functions.

This core cooling function of the ECCS, along with the scram action of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

Pump discharge pressure signals are initiated from twelve pressure switches, two on the discharge side of each of the six low pressure ECCS pumps. In order to generate an ADS permissive in one trip system, it is necessary that only one pump (both channels for the pump) indicate the high discharge pressure condition. The Pump Discharge Pressure-High Allowable Value is less than the pump discharge pressure when the Cooper B 3.3-107 os,19119 I

RCS Leakage Detection Instrumentation B 3.4.5 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.5 RCS Leakage Detection Instrumentation BASES BACKGROUND USAR Safety Design Basis (Ref. 1) requires means for detecting and, to the extent practical, identifying the location of the source of RCS LEAKAGE. Regulatory Guide 1.45, Revision 0, (Ref. 2) describes acceptable methods for selecting leakage detection systems.

Limits on LEAKAGE from the reactor coolant pressure boundary (RCPB) are required so that appropriate action can be taken before the integrity of the RCPB is impaired (Ref. 2). Leakage detection systems for the RCS are provided to alert the operators when leakage rates above normal background levels are detected and also to supply quantitative measurement of leakage rates. In addition to meeting the OPERABILITY requirements, the monitors are typically set to provide the most sensitive response without causing an excessive number of spurious alarms. The Bases for LCO 3.4.4, "RCS Operational LEAKAGE," discuss the limits on RCS LEAKAGE rates.

Systems for separating the LEAKAGE of an identified source from an unidentified source are necessary to provide prompt and quantitative information to the operators to permit them to take immediate corrective action.

LEAKAGE from the RCPB inside the drywell is detected by at least one of two independently monitored variables, such as sump flow and drywell gaseous (noble gas) and particulate radioactivity levels. The primary means of quantifying LEAKAGE in the drywell is the drywell floor drain sump flow monitoring system.

The drywall floor drain sump flow monitoring system monitors the LEAKAGE collected in the floor drain sump. This unidentified LEAKAGE consists of LEAKAGE from control rod drives, valve flanges or packings, floor drains, the Reactor Equipment Cooling System, and drywell air cooling unit condensate drains, and any LEAKAGE not collected in the drywall equipment drain sump.

A flow transmitter in the discharge line of the drywell floor drain sump pumps provides flow indication in the control room. The pumps can also be started from the control room.

The 2-channel, drywell air monitoring system continuously monitors the primary containment atmosphere for airborne particulate and gaseous (noble gas) radioactivity. A sudden increase of radioactivity, which may Cooper B 3.4-24 12/19/19

RCS Leakage Detection Instrumentation B 3.4.5 BASES BACKGROUND (continued) be attributed to RCPB steam or reactor water LEAKAGE, is annunciated in the control room.

APPLICABLE SAFETY ANALYSIS A threat of significant compromise to the RCPB exists if the barrier contains a crack that is large enough to propagate rapidly. LEAKAGE rate limits are set low enough to detect the LEAKAGE emitted from a single crack in the RCPB (Refs. 3 and 4 ).

A control room alarm allows the operators to evaluate the significance of the indicated LEAKAGE and, if necessary, shut down the reactor for further investigation and corrective action. The allowed LEAKAGE rates are well below the rates predicted for the critical crack sizes (Ref. 5).

Therefore, these actions provide adequate response before a significant break in the RCPB can occur.

RCS leakage detection instrumentation satisfies Criterion 1 of 10 CFR 50.36( c)(2)(ii).

LCO This LCO requires instruments of diverse monitoring principles to be OPERABLE to provide confidence that small amounts of unidentified LEAKAGE are detected in time to allow actions to place the plant in a safe condition, when RCS LEAKAGE indicates possible RCPB degradation.

This LCO requires two leakage detection instruments to be OPERABLE.

The drywell floor drain sump flow monitoring system is required to quantify the unidentified LEAKAGE rate from the RCS. Thus, for the system to be considered OPERABLE, the flow monitoring portion must be OPERABLE and capable of determining the leakage rate. The identification of an increase in unidentified LEAKAGE will be delayed by the time required for the unidentified LEAKAGE to travel to the drywell floor drain sump and it may take longer than one hour to detect a 1 gpm increase in unidentified LEAKAGE, depending on the origin and magnitude of the LEAKAGE. This sensitivity is acceptable for drywall sump motor OPERABILITY.

Cooper 8 3.4-25 12/19/19

RCS Leakage Detection Instrumentation B 3.4.5 BASES LCO (continued)

The reactor coolant contains radioactive material that, when released to the primary containment, can be detected by the gaseous or particulate drywell atmospheric radioactivity monitor. Only one of the two detectors is required to be OPERABLE. Radioactivity detection systems are included for monitoring both portable and gaseous activities because of their sensitivities and rapid responses to RCS LEAKAGE, but have recognized limitations. Reactor coolant radioactivity levels will be low during initial reactor startup and for a few weeks thereafter, until activated corrosion products have been formed and fission products appear from fuel element cladding contamination and cladding defects. If there are few fuel element cladding defects and low levels of activation products, it may not be possible for the gaseous or particulate drywall radioactivity monitors to detect a 1 gpm increase within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months during normal operation. However, the particulate drywall radioactivity monitor is OPERABLE when it is capable of detecting a 1 gpm increase in unidentified LEAKAGE within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months given an RCS activity equivalent to that assumed in the design calculations for the monitors. Additionally, the gaseous drywall radioactivity monitor is OPERABLE when it is capable of detecting a LEAKAGE rate of less than the LEAKAGE rate limits within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months given an RCS activity equivalent to that assumed in the design calculations for the monitors (Reference 6).

This LCO is satisfied when monitors of diverse measurement means are OPERABLE. Thus, the drywell floor drain sump monitoring system, in combination with a gaseous or particulate drywall atmospheric radioactivity monitor, provides an acceptable minimum.

APPLICABILITY In MODES 1, 2, and 3, leakage detection systems are required to be OPERABLE to support LCO 3.4.4. This Applicability is consistent with that for LCO 3.4.4.

ACTIONS A.1 With the drywell floor drain sump flow monitoring system inoperable, no other form of sampling can provide the equivalent information to quantify leakage. However, the drywell atmospheric activity monitor will provide indication of changes in leakage.

With the drywall floor drain sump flow monitoring system inoperable, but with RCS unidentified and total LEAKAGE being determined every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months (SR 3.4.4.1 ), operation may continue for 30 days. The 30 day Completion Time of Required Action A.1 is acceptable, based on Cooper B 3.4-26 12/19/19

RCS Leakage Detection Instrumentation B 3.4.5 BASES ACTIONS (continued) operating experience, considering the multiple forms of leakage detection that are still available.

8.1 and 8.2 With both gaseous and particulate drywell atmospheric monitoring channels inoperable, grab samples of the drywell atmosphere must be taken and analyzed to provide periodic leakage information. Provided a sample is obtained and analyzed once every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , the plant may be operated for up to 30 days to allow restoration of at least one of the required monitors.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months interval provides periodic information that is adequate to detect LEAKAGE. The 30 day Completion Time for restoration recognizes that at least one other form of leakage detection is available.

C.1, C.2, and C.3 With the drywall floor drain sump flow monitoring system inoperable, and the drywell atmospheric particulate monitor inoperable, the only means of detecting LEAKAGE is the drywall atmospheric gaseous radiation monitor. A Note clarifies this applicability of the Condition. The drywall atmospheric gaseous radiation monitor typically cannot detect a 1 gpm leak within one hour when RCS activity is low. In addition this configuration does not provide the required diverse means of leakage detection. Indirect methods of monitoring RCS leakage must be implemented. Grab samples of the primary containment atmosphere must be taken and analyzed and monitoring of RCS leakage by administrative means must be performed every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months to provide alternate periodic information.

Administrative means of monitoring RCS leakage include monitoring and trending parameters that may indicate an increase in RCS leakage.

There are diverse alternative mechanisms from which appropriate indicators may be selected based on plant conditions. It is not necessary to utilize all of these methods, but a method or methods should be selected considering the current plant conditions and historical or expected sources of unidentified leakage. Some administrative methods available are drywall equipment sump temperature, suppression pool water level, primary containment pressure, and primary containment temperature. These indications, coupled with the atmospheric grab samples, are sufficient to alert the operating staff to an unexpected increase in unidentified LEAKAGE.

Cooper B 3.4-27 12/19/19

RCS Leakage Detection Instrumentation B 3.4.5 BASES ACTIONS (continued)

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months interval is sufficient to detect increasing RCS leakage. The Required Action provides 7 days to restore another RCS leakage monitor to OPERABLE status to regain the intended leakage detection diversity.

The 7 day Completion Time ensures that the plant will not be operated in a degraded configuration for a lengthy time period.

D.1 and D.2 If any Required Action and associated Completion Time of Condition A, B, or C cannot be met, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and MODE 4 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 perform the actions in an orderly manner and without challenging plant systems.

With all required monitors inoperable, no required automatic means of monitoring LEAKAGE are available, and immediate plant shutdown in accordance with LCO 3.0.3 is required.

SURVEILLANCE REQUIREMENTS SR 3.4.5.1 This SR is for the performance of a CHANNEL CHECK of the required drywall atmospheric monitoring system. The check gives reasonable confidence that the channel is operating properly. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.4.5.2 This SR is for the performance of a CHANNEL FUNCTIONAL TEST of the required RCS leakage detection instrumentation. The test ensures that the monitors can perform their function in the desired manner. The test also verifies the alarm setpoint and relative accuracy of the instrument string. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable Cooper B 3.4-28 12/19/19

RCS Leakage Detection Instrumentation B 3.4.5 BASES SURVEILLANCE REQUIREMENTS (continued)

CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .

SR 3.4.5.3 This SR is for the performance of a CHANNEL CALIBRATION of required leakage detection instrumentation channels. The calibration verifies the accuracy of the instrument string. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Section IV-10.2.

2. Regulatory Guide 1.45, Revision 0, "Reactor Coolant Pressure Boundary Leakage Detection Systems," May 1973.

3. GEAP-5620, "Failure Behavior in ASTM A 1068 Pipes Containing Axial Through-Wall Flaws," April 1968.

4. NUREG-75/067, "Investigation and Evalµation of Cracking in Austetic Stainless Steel Piping of Boiling Water Reactors,"

October 1975.

5. USAR, Section IV-10.3.2.

6. USAR, Section IV-10.3.

Cooper B 3.4-29 12/19/19

RCS Specific Activity B 3.4.6 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.6 RCS Specific Activity BASES BACKGROUND During circulation, the reactor coolant acquires radioactive materials due to release of fission products from fuel leaks into the reactor coolant and activation of corrosion products in the reactor coolant. These radioactive materials in the reactor coolant can plate out in the RCS, and, at times, an accumulation will break away to spike the normal level of radioactivity.

The release of coolant during a Design Basis Accident (OBA) could send radioactive materials into the environment.

Limits on the maximum allowable level of radioactivity in the reactor coolant are established to ensure that in the event of a release of any radioactive material to the environment during a DBA, radiation doses are maintained within the limits of 10 CFR 100 (Ref. 1) for the Control Rod Drop and Main Steam Line Break accidents, and 10 CFR 50.67, "Accident Source Term," (Ref. 6) for the Fuel Handling and Loss-of-Coolant accidents.

This LCO contains iodine specific activity limits. The iodine isotopic activities per gram of reactor coolant are expressed in terms of a DOSE EQUIVALENT 1-131 . The allowable levels are intended to limit the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months radiation dose to an individual at the site boundary to a small fraction of the 10 CFR 100 limit for the Control Rod Drop and Main Steam Line Break accidents, and within the 10 CFR 50.67, "Accident Source Term,"

(Ref. 6) limit for the Fuel Handling and Loss-of-Coolant accidents.

APPLICABLE SAFETY ANALYSES Analytical methods and assumptions involving radioactive material in the primary coolant are presented in the USAR (Ref. 2). The specific activity in the reactor coolant (the source term) is an initial condition for evaluation of the consequences of an accident due to a main steam line break (MSLB) outside containment. No fuel damage is postulated in the MSLB accident, and the release of radioactive material to the environment is assumed to end when the main steam isolation valves (MSIVs) close completely.

This MSLB release forms the basis for determining offsite and control room doses (Refs. 2 and 3). The limits on the specific activity of the primary coolant ensure that the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months thyroid and whole body doses at the site boundary, resulting from an MSLB outside containment during steady state operation, will not exceed 10% of the dose guidelines of 10 CFR 100.

Cooper B 3.4-30 12119119 I

RCS Specific Activity B 3.4.6 BASES APPLICABLE SAFETY ANALYSES (continued)

The limits on the specific activity of the primary coolant also ensure the thyroid dose to the control room operators resulting from an MSLB outside containment during steady state operation will not exceed the limits specified in GDC 19 of 10 CFR 50, Appendix A (Ref. 4).

The limits on specific activity are values from a parametric evaluation of typical site locations, as well as from a site specific evaluation for control room dose (Ref. 3). These limits are conservative because the evaluation considered more restrictive parameters than for a specific site, such as the location of the site boundary and the meteorological conditions of the site.

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

5).

LCO The specific Iodine activity is limited to s 0.2 µCi/gm DOSE EQUIVALENT 1-131. This limit ensures the source term assumed in the safety analysis for the MSLB is not exceeded, so any release of radioactivity to the environment during an MSLB is less than a small fraction of the 10 CFR 100 limits.

APPLICABILITY In MODE 1, and MODES 2 and 3 with any main steam line not isolated, limits on the primary coolant radioactivity are applicable since there is an escape path for release of radioactive material from the primary coolant to the environment in the event of an MSLB outside of primary containment.

In MODES 2 and 3 with the main steam lines isolated, such limits do not apply since an escape path does not exist. In MODES 4 and 5, no limits are required since the reactor is not pressurized and the potential for leakage is reduced .

ACTIONS A.1 and A.2 When the reactor coolant specific activity exceeds the LCO DOSE EQUIVALENT 1-131 limit, but is s 4.0 µCi/gm, samples must be analyzed for DOSE EQUIVALENT 1-131 at least once every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . In addition, the specific activity must be restored to the LCO limit within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months .

The Completion Time of once every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is based on the time needed to take and analyze a sample. The 48 hour5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months Completion Time to restore the activity level provides a reasonable time for temporary coolant activity increases (iodine spikes or crud bursts) to be cleaned up with the normal processing systems.

Cooper B 3.4-31 12119119 I

RCS Specific Activity B 3.4.6 BASES ACTIONS (continued)

A Note permits the use of the provisions of LCO 3.0.4.c. This allowance permits entry into the applicable MODE(S) while relying on the ACTIONS.

This allowance is acceptable due to the significant conservatism incorporated into the specific activity limit, the low probability of an event which is limiting due to exceeding this limit, and the ability to restore transient specific activity excursions while the plant remains at, or proceeds to power operation.

B.1, 8 .2.1, B.2.2.1, and 8 .2.2.2 If the DOSE EQUIVALENT 1-131 cannot be restored to s 0.2 µCi/gm within 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months , or if at any time it is > 4.0 µCi/gm, it must be determined at least once every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months and all the main steam lines must be isolated within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . Isolating the main steam lines precludes the possibility of releasing radioactive material to the environment in an amount that is more than a small fraction of the requirements of 10 CFR 100 during a postulated MSLB accident.

Alternatively, the plant can be placed in MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and in MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . This option is provided for those instances when isolation of main steam lines is not desired (e .g., due to the decay heat loads). In MODE 4, the requirements of the LCO are no longer applicable.

The Completion Time of once every 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is the time needed to take and analyze a sample. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Completion Time is reasonable, based on operating experience, to isolate the main steam lines in an orderly manner and without challenging plant systems. Also, the allowed Completion Times for Required Actions 8.2.2.1 and B.2.2.2 for placing the unit in MODES 3 and 4 are reasonable, based on operating experience, to achieve the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS SR 3.4.6.1 This Surveillance is performed to ensure iodine remains within limit during normal operation. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Cooper B 3.4-32 12119119 I

RCS Specific Activity B 3.4.6 BASES SURVEILLANCE REQUIREMENTS (continued)

This SR is modified by a Note that requires this Surveillance to be performed only in MODE 1 because the level of fission products generated in other MODES is much less.

REFERENCES 1. 10CFR 100.11, 1973.

2. USAR, Section XIV-8.1.

3. USAR, Section XIV-6.5.

4. 10 CFR 50, Appendix A, GDC 19.

5. 10 CFR 50.36(c)(2)(ii).

6. 10 CFR 50.67.

Cooper B 3.4-33 12/19/19

RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4. 7 Residual Heat Removal (RHR) Shutdown Cooling System-Hot Shutdown BASES BACKGROUND Irradiated fuel in the shutdown reactor core generates heat during the decay of fission products and increases the temperature of the reactor coolant. This decay heat must be removed to reduce the temperature of the reactor coolant to s 212°F in preparation for performing Refueling or Cold Shutdown maintenance operations, or the decay heat must be removed for maintaining the reactor in the Hot Shutdown condition.

The two redundant, manually controlled shutdown cooling loops of the RHR System provide decay heat removal. Each loop consists of two motor driven pumps, a heat exchanger, and associated piping and valves.

Both loops have a common suction from the same recirculation loop.

Each pump discharges the reactor coolant, after circulation through the respective heat exchanger, to the reactor via the associated recirculation loop. The RHR heat exchangers transfer heat to the RHR Service Water System (LCO 3. 7 .1, "Residual Heat Removal Service Water Booster (RHRSWB) System").

APPLICABLE SAFETY ANALYSES Decay heat removal by operation of the RHR System in the shutdown cooling mode is not required for mitigation of any event or accident evaluated in the safety analyses (Ref. 1). Decay heat removal is, however, an important safety function that must be accomplished or core damage could result. The RHR Shutdown Cooling System meets Criterion 4 of 10 CFR 50.36(c)(2)(ii) (Ref. 2).

LCO Two RHR shutdown cooling subsystems are required to be OPERABLE, and when no recirculation pump is in operation, one shutdown cooling subsystem must be in operation. An OPERABLE RHR shutdown cooling subsystem consists of one OPERABLE RHR pump, one heat exchanger, and the associated piping and valves. The two subsystems have a common suction source and are allowed to have a common heat exchanger and common discharge piping. Thus, to meet the LCO, both pumps in one loop or one pump in each of the two loops must be OPERABLE. Since the piping and heat exchangers are passive components that are assumed not to fail, they are allowed to be common to both subsystems. Each shutdown cooling subsystem is considered OPERABLE if it can be manually aligned (remote or local) in the shutdown cooling mode for removal of decay heat. In MODE 3, one RHR shutdown cooling subsystem can provide the required cooling, but two Cooper B 3.4-34 12119119 I

RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 BASES LCO (continued) subsystems are required to be OPERABLE to provide redundancy.

Operation of one subsystem can maintain or reduce the reactor coolant temperature as required. However, to ensure adequate core flow to allow for accurate average reactor coolant temperature monitoring, nearly continuous operation is required.

Note 1 permits both required RHR shutdown cooling subsystems and recirculation pumps to be shut down for a period of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months in an 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months period. Note 2 allows one RHR shutdown cooling subsystem to be inoperable for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for the performance of Surveillance tests.

These tests may be on the affected RHR System or on some other plant system or component that necessitates placing the RHR System in an inoperable status during the performance. This is permitted because the core heat generation can be low enough and the heatup rate slow enough to allow some changes to the RHR subsystems or other operations requiring RHR flow interruption and loss of redundancy.

APPLICABILITY In MODE 3 with reactor steam dome pressure below the shutdown cooling permissive pressure (i.e., the actual pressure at which the interlock resets) the RHR Shutdown Cooling System must be OPERABLE and one loop must be operated in the shutdown cooling mode to remove decay heat to reduce or maintain coolant temperature. Otherwise, a recirculation pump is required to be in operation.

In MODES 1 and 2, and in MODE 3 with reactor steam dome pressure greater than or equal to the shutdown cooling permissive pressure, this LCO is not applicable. Operation of the RHR System in the shutdown cooling mode is not allowed above this pressure because the RCS pressure may exceed the design pressure of the shutdown cooling piping, Decay heat removal at reactor pressures greater than or equal to the shutdown cooling permissive pressure is typically accomplished by condensing the steam in the main condenser. Additionally, in MODE 2 below this pressure, the OPERABILITY requirements for the Emergency Core Cooling Systems (ECCS) (LCO 3.5.1, "ECCS-Operating") do not allow placing the RHR shutdown cooling subsystem into operation.

The requirements for decay heat removal in MODES 4 and 5 are discussed in LCO 3.4.8, "Residual Heat Removal (RHR) Shutdown Cooling System-Cold Shutdown"; LCO 3.9.7, "Residual Heat Removal (RHR)-High Water Level"; and LCO 3.9.8, "Residual Heat Removal (RHR)-Low Water Level."

Cooper B 3.4-35 12119119 I

RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 BASES ACTIONS A Note has been provided to modify the ACTIONS related to RHR shutdown cooling subsystems. Section 1.3, Completion Times, specifies once a Condition has been entered, subsequent divisions, subsystems, components or variables expressed in the Condition, discovered to be inoperable or not within limits, will not result in separate entry into the Condition. Section 1.3 also specifies Required Actions of the Condition continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable shutdown cooling subsystems provide appropriate compensatory measures for separate inoperable shutdown cooling subsystems. As such, a Note has been provided that allows separate Condition entry for each inoperable RHR shutdown cooling subsystem.

With one required RHR shutdown cooling subsystem inoperable for decay heat removal, except as permitted by LCO Note 2, the overall reliability is reduced, because a single failure in the OPERABLE subsystem could result in reduced RHR shutdown cooling capability.

Therefore, an alternate method of decay heat removal must be provided.

With both RHR shutdown cooling subsystems inoperable, an alternate method of decay heat removal must be provided in addition to that provided for the initial RHR shutdown cooling subsystem inoperability.

This re-establishes backup decay heat removal capabilities, similar to the requirements of the LCO. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is based on the decay heat removal function and the probability of a loss of the available decay heat removal capabilities. Furthermore, verification of the functional availability of these alternate method(s) must be reconfirmed every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter. This will provide assurance of continued heat removal capability.

The required cooling capacity of the alternate method should be sufficient to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability. Alternate methods that can be used include (but are not limited to) the Condensate/Main Steam Systems, the Reactor Water Cleanup System, a combination of an ECCS pump and a safety/relief valve, or an inoperable but functional RHR shutdown cooling system.

Cooper 8 3.4-36 01/06/21

RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 BASES ACTIONS (continued)

B.1 If the required alternate method(s) of decay heat removal cannot be verified within one hour, immediate action must be taken to restore the inoperable RHR shutdown cooling subsystem(s) to operable status. The Required Action will restore redundant decay heat removal paths. The immediate Completion Time reflects the importance of maintaining the availability of two paths for heat removal.

C.1, C.2, and C.3 With no RHR shutdown cooling subsystem and no recirculation pump in operation, except as permitted by LCO Note 1, reactor coolant circulation by the RHR shutdown cooling subsystem or recirculation pump must be restored without delay.

Until RHR or recirculation pump operation is re-established, an alternate method of reactor coolant circulation must be placed into service. This will provide the necessary circulation for monitoring coolant temperature.

The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is based on the coolant circulation function and is modified such that the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is applicable separately for each occurrence involving a loss of coolant circulation. Furthermore, verification of the functioning of the alternate method must be reconfirmed every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter. This will provide assurance of continued temperature monitoring capability.

During the period when the reactor coolant is being circulated by an alternate method (other than by the required RHR shutdown cooling subsystem or recirculation pump), the reactor coolant temperature and pressure must be periodically monitored to ensure proper function of the alternate method. The once per hour Completion Time is deemed appropriate.

SURVEILLANCE REQUIREMENTS SR 3.4.7.1 This Surveillance verifies that one RHR shutdown cooling subsystem or recirculation pump is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program .

Cooper B 3.4-37 01/06/21

RHR Shutdown Cooling System-Hot Shutdown B 3.4.7 BASES SURVEILLANCE REQUIREMENTS (continued)

This Surveillance is modified by a Note allowing sufficient time to align the RHR System for shutdown cooling operation after clearing the pressure interlock that isolates the system, or for placing a recirculation pump in operation. The Note takes exception to the requirements of the Surveillance being met (i.e., forced coolant circulation is not required for this initial 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months period), which also allows entry into the Applicability of this Specification in accordance with SR 3.0.4 since the Surveillance will not be "not met" at the time of entry into the Applicability.

REFERENCES 1. USAR, Appendix G.

2. 10 CFR 50.36(c)(2)(ii).

Cooper B 3.4-38 01/06/21

RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 BASES ACTIONS (continued)

Therefore, an alternate method of decay heat removal must be provided.

With both RHR shutdown cooling subsystems inoperable, an alternate method of decay heat removal must be provided in addition to that provided for the initial RHR shutdown cooling subsystem inoperability.

This re-establishes backup decay heat removal capabilities, similar to the requirements of the LCO. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is based on the decay heat removal function and the probability of a loss of the available decay heat removal capabilities. Furthermore, verification of the functional availability of these alternate method(s) must be reconfirmed every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter. This will provide assurance of continued heat removal capability.

The required cooling capacity of the alternate method should be sufficient to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability. Alternate methods that can be used include (but are not limited to) the Reactor Water Cleanup System, a combination of an ECCS pump and a safety/relief valve, or an inoperable but functional RHR shutdown cooling subsystem.

B.1 If the required alternate method(s) of decay heat removal cannot be verified within one hour, immediate action must be taken to restore the inoperable RHR shutdown cooling subsystem(s) to operable status. The Required Action will restore redundant decay heat removal paths. The immediate Completion Time reflects the importance of maintaining the availability of two paths for heat removal.

C.1 and C.2 With no RHR shutdown cooling subsystem and no recirculation pump in operation, except as permitted by LCO Note 1, and until RHR or recirculation pump operation is re-established, an alternate method of reactor coolant circulation must be placed into service. This will provide the necessary circulation for monitoring coolant temperature. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is based on the coolant circulation function and is modified such that the 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is applicable separately for each occurrence involving a loss of coolant circulation. Furthermore, verification of the functioning of the alternate method must be reconfirmed every 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months thereafter. This will provide assurance of continued temperature monitoring capability.

Cooper B 3.4-42 01/06/21

RHR Shutdown Cooling System-Cold Shutdown B 3.4.8 BASES ACTIONS (continued)

During the period when the reactor coolant is being circulated by an alternate method {other than by the required RHR shutdown cooling subsystem or recirculation pump), the reactor coolant temperature and pressure must be periodically monitored to ensure proper functioning of the alternate method. The once per hour Completion Time is deemed appropriate.

SURVEILLANCE REQUIREMENTS SR 3.4.8.1 This Surveillance verifies that one RHR shutdown cooling subsystem or recirculation pump is in operation and circulating reactor coolant. The required flow rate is determined by the flow rate necessary to provide sufficient decay heat removal capability. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

REFERENCES 1. USAR, Appendix G.

2. 10 CFR 50.36(c)(2)(ii).

Cooper B 3.4-43 01/06/21

RHR Containment Spray B 3.6.1.9 BASES (continued)

ACTIONS 8.1 With both RHR containment spray subsystems inoperable, at least one subsystem must be restored to OPERABLE status within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . In this Condition, there is a substantial loss of the primary containment temperature and pressure mitigation function. The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is based on this loss of function and is considered acceptable due to the low probability of a DBA and because alternative methods to remove heat from primary containment are available.

C.1 and C.2 If the inoperable RHR containment spray subsystem cannot be restored to OPERABLE status within the associated Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and MODE 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power cond itions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS SR 3.6.1.9.1 Verifying the correct alignment for manual, power operated, and automatic valves in the RHR containment spray mode flow path provides assurance that the proper flow paths will exist for system operation. 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. A valve is also allowed to be in the nonaccident position provided it can be aligned to the accident position within the time assumed in the accident analysis. This is acceptable since the RHR containment cooling mode is manually initiated. This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

Cooper B 3.6-53 08/19/20

AC Sources - Operating B 3.8.1 BASES ACTIONS (continued)

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

If while a DG is inoperable, a new problem with the DG is discovered that would have prevented the DG from performing its specified safety function, a separate entry into Condition B is not required. The new DG problem should be addressed in accordance with the plant corrective action program.

According to Generic Letter 84-15 (Ref. 7), 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is a reasonable time to confirm that the OPERABLE DG is not affected by the same problem as the inoperable DG.

In Condition B, the remaining OPERABLE DG and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System . The 7 day Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and low probability of a OBA occurring during this period.

The second Completion Time for Required Action 8.4 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition B is entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 7 days.

This situation could lead to a total of 14 days, since initial failure of the LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 7 days (for a total of 21 days) allowed prior to complete restoration of the LCO. The 14 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 7 day and 14 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive must be met.

Similar to Required Action 8.2, the second Completion Time of Required Action B.4 allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time that the LCO was initially not met, instead of the time that Condition B was entered.

Cooper B 3.8-10 05/13/20

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

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

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Note 1 modifies this Surveillance to indicate that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized.

Note 2 modifies this Surveillance by stating that momentary transients because of changing bus loads do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test.

Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite circuit or grid perturbations.

Note 4 stipulates a prerequisite requirement for performance of this SR.

A successful DG start must precede this test to credit satisfactory performance.

SR 3.8.1.4 This SR provides verification that the level of fuel oil in the day tank is at or above the level at which fuel oil is automatically added. The level is selected to ensure adequate fuel oil for approximately 3.9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months of DG operation at full load.

The volume of fuel oil equivalent to 3.9 hours1.041667e-4 days 0.0025 hours 1.488095e-5 weeks 3.4245e-6 months supply is 1500 gallons.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.1.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Periodic removal of water from the fuel oil day tanks eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water Cooper B 3.8-17 04/03/19

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

SR 3.8.1.10 Under LOCA conditions and loss of offsite power, loads are sequentially connected to the bus by a timed logic sequence. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents. The 10%

load sequence time interval tolerance ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated. Reference 13 provides a summary of the automatic loading of ESF buses.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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

Credit may be taken for unplanned events that satisfy this SR.

SR 3.8.1 .11 In the event of a OBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

This Surveillance demonstrates DG operation during a loss of offsite power actuation test signal in conjunction with an ECCS initiation signal.

This test verifies all actions encountered from the loss of offsite power and loss of coolant accident, including shedding of the nonessential loads and energization of the emergency buses and respective loads from the DG. It further demonstrates the capability of the DG to automatically maintain the required voltage and frequency.

The DG auto-start time of 14 seconds is derived from requirements of the accident analysis for responding to a design basis large break LOCA.

The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability has been achieved.

The requirement to verify the connection and power supply of permanent and auto-connected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or Cooper B 3.8-20 10/15/19

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air BASES BACKGROUND The two diesel generators (DGs) are provided with two storage tanks having a fuel oil capacity sufficient to operate a single DG for a period of 7 days while that DG is operating at full load which bounds post loss of coolant accident (LOCA) load demand discussed in USAR, Section Vlll-5.2 (Ref. 1) and Regulatory Guide 1.137 (Ref. 2). The maximum load demand is calculated using the assumption that only one DG is available.

This onsite fuel oil capacity is sufficient to operate the DGs for longer than the time to replenish the onsite supply from outside sources.

Fuel oil is transferred from storage tanks to the day tanks by either of two transfer pumps associated with each storage tank. Redundancy of pumps and piping precludes the failure of one pump, or the rupture of any pipe or valve to result in the loss of more than one DG. The outside tanks, pumps, and piping are located underground .

For proper operation of the standby DGs, it is necessary to ensure the proper quality of the fuel oil. Regulatory Guide 1.137 (Ref. 2) addresses the recommended fuel oil practices as supplemented by ANSI N195 (Ref.

3). The fuel oil properties governed by these SRs are the water and sediment content, the kinematic viscosity, specific gravity (or API gravity or absolute specific gravity), and impurity level.

The DG lubrication system is designed to provide sufficient lubrication to permit proper operation of its associated DG under all loading conditions .

The system is required to circulate the lube oil to the diesel engine working surfaces and to remove excess heat generated by friction during operation. The useable volume in each engine oil sump and onsite lube oil storage contain an inventory capable of supporting a minimum of 7 days of operation. The onsite storage in addition to the useable volume in the engine oil sump is sufficient to ensure 7 days' continuous operation.

This supply is sufficient to allow the operator to replenish lube oil from outside sources.

Each DG has an air start subsystem that includes two starting air receivers, each with adequate capacity for multiple start attempts on the DG without recharging the air start receiver(s).

Cooper B 3.8-29 04/03/19

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES ACTIONS The ACTIONS Table is modified by a Note indicating that separate Condition entry is allowed for each DG except for Conditions A, C, and D.

This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable DG subsystem.

Complying with the Required Actions for one inoperable DG subsystem may allow for continued operation, and subsequent inoperable DG subsystem(s) governed by separate Condition entry and application of associated Required Actions. The Note does not apply to Conditions A, C and D since the CNS design has two fuel oil storage tanks that supply fuel oil to both DGs.

A.1 In this Condition, the 7 day fuel oil supply for both DGs is not available.

The 49,500 gallon limit is a conservative estimate of the required fuel oil based on worst case fuel consumption. However, the Condition is restricted to fuel oil level reductions that maintain at least a 6 day supply.

The fuel oil level equivalent to a 6 day supply is 42,800 gallons. These circumstances may be caused by events such as:

a. Full load operation required for an inadvertent start while at minimum required level; or

b. Feed and bleed operations that may be necessitated by increasing particulate levels or any number of other oil quality degradations.

This restriction allows sufficient time for obtaining the requisite replacement volume and performing the analyses required prior to addition of the fuel oil to the tank. A period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is considered sufficient to complete restoration of the required level prior to declaring the DGs inoperable. This period is acceptable based on the remaining capacity (> 6 days), the fact that action will be initiated to obtain replenishment, and the low probability of an event during this brief period.

fU In this Condition, the 7 day lube oil inventory, i.e., sufficient lube oil to support 7 days of continuous DG operation at full load conditions, is not available. However, the Condition is restricted to lube oil volume reductions that maintain at least a 6 day supply. The lube oil inventory equivalent to a 6 day supply is 432 gallons. This restriction allows sufficient time for obtaining the requisite replacement volume. A period of 48 hours5.555556e-4 days 0.0133 hours 7.936508e-5 weeks 1.8264e-5 months is considered sufficient to complete restoration of the required volume prior to declaring the DG inoperable. This period is acceptable based on the remaining capacity(> 6 days), the low rate of usage, the fact that action Cooper B 3.8-31 04/03/19

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES ACTIONS (continued) prior to declaring the DG inoperable. This period is acceptable based on the remaining air start capacity, the fact that most DG starts are accomplished on the first attempt, and the low probability of an event during this brief period.

F.1 With a Required Action and associated Completion Time of Condition A, B, C, D, or E not met, or the stored diesel fuel oil, lube oil, or starting air subsystem not within limits for reasons other than addressed by Conditions A, B, C, D, or E, the associated DG(s) may be incapable of performing its intended function and must be immediately declared inoperable.

SURVEILLANCE REQUIREMENTS SR 3.8.3.1 This SR provides verification that there is an adequate inventory of fuel oil in the storage tanks to support a single DG's operation for 7 days at full load. The fuel oil level equivalent to a 7 day supply is 49,500 gallons when calculated in accordance with References 2 and 3. The required fuel storage volume is determined using the most limiting energy content of the stored fuel. Using the known correlation of diesel fuel oil absolute specific gravity or API gravity to energy content, the required diesel generator output, and the corresponding fuel consumption rate, the onsite fuel storage volume required for 7 days of operation can be determined.

SR 3.8.3.3 requires new fuel to be tested to verify that the absolute specific gravity or API gravity is within the range assumed in the diesel fuel oil consumption calculations. The 7 day period is sufficient time to place the unit in a safe shutdown condition and to bring in replenishment fuel from an offsite location.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.3.2 This Surveillance ensures that sufficient lubricating oil inventory (combined inventory in the DG tube oil sump and in the warehouse) is available to support at least 7 days of operation for one DG. The lube oil Cooper B 3.8-33 04/03/19

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE REQUIREMENTS (continued) inventory equivalent to a 7 day supply is 504 gallons and is based on a 3 gallon per hour consumption value for the run time of the DG. Implicit in this SR is the requirement to verify that adequate DG lube oil is stored onsite to ensure that sump level does not drop below the manufacturer's recommended minimum level.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.3.3 The tests of new fuel oil prior to addition to the storage tanks are a means of determining whether new fuel oil is of the appropriate grade and has not been contaminated with substances that would have an immediate detrimental impact on diesel engine combustion. If results from these tests are within acceptable limits, the fuel oil may be added to the storage tanks without concern for contaminating the entire volume of fuel oil in the storage tanks. These tests are to be conducted prior to adding the new fuel to the storage tank(s), but in no case is the time between the sample (and corresponding test results) including receipt of new fuel and addition of new fuel oil to the storage tanks to exceed 31 days. The tests, limits, and applicable ASTM Standards are as follows:

a. Sample the new fuel oil in accordance with ASTM D4057-1988 (Ref. 8);

b. Verify in accordance with the tests specified in ASTM D975-1989a (Ref. 8) that: (1) the sample has an API gravity of within 0.3° at 60°F or a specific gravity of within 0.0016 at 60/60°F, when compared to the supplier's certificate, or the sample has an absolute specific gravity at 60/60°F of~ 0.83 ands 0.89 or an API gravity at 60°F of~ 26° and s 38°; (2) a kinematic viscosity at 40°C of~ 1.9 centistokes and s 4.1 centistokes, or a Saybolt viscosity at 100°F of~ 32.6 and s 40.1 if gravity was not determined by comparison with the supplier's certification; and (3) a flash point of~ 125°F; and

c. Verify that the new fuel oil has a clear and bright appearance with proper color when tested in accordance with ASTM D4176-1991 (Ref. 8) or a water and sediment content of s 0.05% volume when tested in accordance with ASTM D1796-1983 (Ref. 8).

Cooper B 3.8-34 04/03/19

Diesel Fuel Oil, Lube Oil, and Starting Air B 3.8.3 BASES SURVEILLANCE REQUIREMENTS (continued)

Failure to meet any of the above limits is cause for rejecting the new fuel oil, but does not represent a failure to meet the LCO concern since the fuel oil is not added to the storage tanks.

Following the initial new fuel oil sample, the new fuel oil is analyzed to establish that the other properties specified in Table 1 of ASTM D975-1989a (Ref. 8) are met for new fuel oil when tested in accordance with ASTM D975-1989a (Ref. 8), except that the analysis for sulfur may be performed in accordance with ASTM D1552-1990 (Ref. 8) or ASTM D2622-1992 (Ref. 8). These additional analyses are required, by Specification 5.5.9, "Diesel Fuel Oil Testing Program," to be performed within 31 days following addition of new fuel oil. This 31 day requirement is intended to assure that:

a. The new fuel oil sample is taken no more than 31 days old at the time of adding the new fuel oil to the DG storage tank; and

b. The results of the new fuel oil sample are obtained within 31 days after addition of the new fuel oil to the DG storage tank.

The 31 day period is acceptable because the fuel oil properties of interest, even if they were not within stated limits, would not have an immediate effect on DG operation. This Surveillance ensures the availability of high quality fuel oil for the DGs.

Fuel oil degradation during long term storage shows up as an increase in particulate, mostly due to oxidation. The presence of particulate does not mean that the fuel oil will not burn properly in a diesel engine. The particulate can cause fouling of filters and fuel oil injection equipment, however, which can cause engine failure.

Particulate concentrations should be determined in accordance with ASTM D2276-1989 (Ref. 8), Method A. This method involves a gravimetric determination of total particulate concentration in the fuel oil and has a limit of 10 mg/I. It is acceptable to obtain a field sample for subsequent laboratory testing in lieu of field testing . For the Cooper Nuclear Station design in which the total volume of stored fuel oil is contained in two interconnected tanks, each tank must be considered and tested separately.

The Frequency of this test takes into consideration fuel oil degradation trends that indicate that particulate concentration is unlikely to change significantly between Frequency intervals.

Cooper B 3.8-35 04103119 I

Diesel Fuel Oil, Lube Oil, and Starting Air 8 3.8.3 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.3.4 This Surveillance ensures that, without the aid of the refill compressor, sufficient air start capacity for each DG is available. The system design requirements provide for multiple engine start cycles without recharging.

The pressure specified in this SR is intended to reflect the lowest value at which the requirements of Reference 7 can be satisfied.

The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

SR 3.8.3.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Periodic removal of water from the fuel storage tanks eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and from breakdown of the fuel oil by bacteria.

Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program. The presence of water does not necessarily represent failure of this SR, provided the accumulated water is removed

to the extent possible during performance of the Surveillance.

REFERENCES 1. USAR, Section Vlll-5.2.

2. Regulatory Guide 1.137, Revision 1, October 1979.

3. ANSI N195, 1976.

4. USAR, Chapter VI.

5. USAR, Chapter XIV.

6. 10 CFR 50.36(c)(2)(ii).

7. USAR, Section Vlll-5.3.3.

Cooper 8 3.8-36 04/03/19

Distribution Systems - Shutdown B 3.8.8 BASES ACTIONS (continued)

A.1, A.2.1, A.2.2, A.2.3, and, A.2.4 Although redundant required features may require redundant divisions of electrical power distribution subsystems to be OPERABLE, one OPERABLE distribution subsystem division may be capable of supporting sufficient required features to allow continuation of CORE ALTERATIONS and fuel movement. By allowing the option to declare required features associated with an inoperable distribution subsystem inoperable, appropriate restrictions are implemented in accordance with the affected distribution subsystem LCO's Required Actions. In many instances this option may involve undesired administrative efforts. Therefore, the allowance for sufficiently conservative actions is made, (i.e., to suspend CORE AL TERATIONS and movement of irradiated fuel assemblies in the secondary containment).

Suspension of these activities shall not preclude completion of actions to establish a safe conservative condition. These actions minimize the probability of the occurrence of postulated events. It is further required to immediately initiate action to restore the required AC and DC electrical power distribution subsystems and to continue this action until restoration is accomplished in order to provide the necessary power to the plant safety systems.

Notwithstanding performance of the above conservative Required Actions, a required residual heat removal-shutdown cooling (RHR-SDC) subsystem may be inoperable. In this case, Required Actions A.2.1 through A.2.3 do not adequately address the concerns relating to coolant circulation and heat removal. Pursuant to LCO 3.0.6, the RHR-SDC ACTIONS would not be entered. Therefore, Required Action A.2.4 is provided to direct declaring RHR-SDC inoperable, which results in taking the appropriate RHR-SDC ACTIONS.

The Completion Time of immediately is consistent with the required times for actions requiring prompt attention. The restoration of the required distribution subsystems should be completed as quickly as possible in order to minimize the time the plant safety systems may be without power.

Cooper B 3.8-65 07/12/19

RPV - High Water Level B 3.9.7 BASES ACTIONS (continued) heat from the reactor core. However, the overall reliability is reduced because loss of water level could result in reduced decay heat removal capability. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is based on decay heat removal function and the probability of a loss of the available decay heat removal capabilities. Furthermore, verification of the functional availability of the alternate method must be reconfirmed every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter. This will ensure continued heat removal capability.

Alternate decay heat removal methods are available to the operators for review and preplanning in the unit Operating Procedures. The required cooling capacity of the alternate method should be sufficient to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability.

Alternate methods that can be used include (but are not limited to) the Spent Fuel Pool Cooling System, the Reactor Water Cleanup System, or an inoperable but functional RHR shutdown cooling subsystem. The method used to remove the decay heat should be the most prudent choice based on station conditions.

8 .1, B.2, B.3, and B.4 If no RHR shutdown cooling subsystem is OPERABLE and an alternate method of decay heat removal is not available in accordance with Required Action A.1, actions shall be taken immediately to suspend operations involving an increase in reactor decay heat load by suspending loading of irradiated fuel assemblies into the RPV.

Additional actions are required to minimize any potential fission product release to the environment. This includes ensuring secondary containment is OPERABLE; one standby gas treatment subsystem is OPERABLE; and secondary containment isolation capability is available in each associated penetration flow path not isolated that is assumed to be isolated to mitigate radioactive releases (i.e., one secondary containment isolation valve and associated instrumentation are OPERABLE or other acceptable administrative controls to assure isolation capability. These administrative controls consist of stationing an Cooper B 3.9-24 01/06/21

RPV - Low Water Level B 3.9.8 BASES ACTIONS (continued)

LCO. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is based on the decay heat removal function and the probability of a loss of the available decay heat removal capabilities. Furthermore, verification of the functional availability of this alternate method must be reconfirmed every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter. This will ensure continued heat removal capability.

Alternate decay heat removal methods are available to the operators for review and preplanning in the unit Operating Procedures. The required cooling capacity of the alternate method should be sufficient to maintain or reduce temperature. Decay heat removal by ambient losses can be considered as, or contributing to, the alternate method capability.

Alternate methods that can be used include (but are not limited to) the Spent Fuel Pool Cooling System, the Reactor Water Cleanup System, or an inoperable but functional RHR shutdown cooling subsystem. The method used to remove decay heat should be the most prudent choice based on station conditions.

B.1, B.2, and B.3 With the required decay heat removal subsystem(s) inoperable and the required alternate method(s) of decay heat removal not available in accordance with Required Action A.1, additional actions are required to minimize any potential fission product release to the environment. This includes ensuring secondary containment is OPERABLE; one standby gas treatment subsystem is OPERABLE; and secondary containment isolation capability is available in each associated penetration flow path not isolated that is assumed to be isolated to mitigate radioactive releases (i.e., one secondary containment isolation valve and associated instrumentation are OPERABLE or other acceptable administrative controls to assure isolation capability. These administrative controls consist of stationing an operator, who is in continuous communication with the control room, at the controls of the isolation device. In this way, the penetration can be rapidly isolated when a need for secondary containment is indicated.) This may be performed as an administrative check, by examining logs or Cooper B 3.9-29 01/06/21

Multiple Control Rod Withdrawal - Refueling B 3.10.6 BASES LCO (continued) room operator and a licensed operator on the refueling floor shall verify that the control rod is inserted in the core cell to be loaded. Otherwise, all control rods must be fully inserted before loading fuel.

APPLICABILITY Operation in MODE 5 is controlled by existing LCOs. The exceptions from other LCO requirements (e.g., the ACTIONS of LCO 3.9.3, LCO 3.9.4, or LCO 3.9.5) allowed by this Special Operations LCO are appropriately controlled by requiring all fuel to be removed from cells whose "full-in" indications are allowed to be bypassed. This bypassing must be verified by two licensed operators (Reactor Operator or Senior Reactor Operator).

ACTIONS A.1, A.2. A.3 .1. and A.3.2 If one or more of the requirements of this Special Operations LCO are not met, the immediate implementation of these Required Actions restores operation consistent with the normal requirements for refueling (i.e., all control rods inserted in core cells containing one or more fuel assemblies) or with the exceptions granted by this Special Operations LCO. The Completion Times for Required Action A.1 , Required Action A.2, Required Action A.3.1, and Required Action A.3.2 are intended to require that these Required Actions be implemented in a very short time and carried through in an expeditious manner to either initiate action to restore the affected CRDs and insert their control rods, or initiate action to restore compliance with this Special Operations LCO.

SURVEILLANCE REQUIREMENTS SR 3.10.6.1, SR 3.10.6.2, and SR 3. 10.6.3 Periodic verification of the administrative controls established by this Special Operations LCO is prudent to preclude the possibility of an inadvertent criticality. In addition, SR 3.10.6.1 must be verified by one licensed operator (Reactor Operator or Senior Reactor Operator). The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

Cooper B 3.10-28 05/13/20

NLS2021015, (CNS) - Technical Specification Bases Changes

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NLS2021015, (CNS) - Technical Specification Bases Changes

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