Text

Technical Specification Bases Changes
	ML17114A466
Person / Time
Site:	Cooper
Issue date:	04/07/2017
From:	Shaw J; Nebraska Public Power District (NPPD)
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	NLS2017033
	Download: ML17114A466 (112)
	v • d • e

r H

Nebraska Public Power District NLS2017033 Always there when you need us April 17, 2017 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 5.5.10.d, these changes are provided on a frequency consistent with 10 CFR 50.71(e). The enclosed Bases c4anges are for the time period from March 11, 2015, through February 24, 2017. 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 contact me at (402) 825-2788.

Sincerely,

~~

im Shaw*

Licensing Manager

/lb

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 68327-0098 Telephone: (402) 825-3877 /Fax: (402) 825-5277 www.nppd.com

NLS2017033 ENCLOSURE TECHNICAL SPECIFICATION BASES CHANGES

FILING INSTRUCTIONS TECHNICAL SPECIFICATION BASES REMOVE INSERT List of Effective Pages - Bases 1 through 7 (dated 11/13/14) 1 through 7 (dated 01/05/17)

Bases Pages i (Rev. 0) i (dated 02/09/16) ii (Rev. 0) ii (dated 02/22/16) iii (Rev. 0) iii (dated 02/22/16)

B 3.1-40 (dated 09/25/09) B 3 .1-40 (dated 04/10/15)

B 3.2-1 (dated 01/27/06) B 3.2-1 (dated 09/11/15)

B 3.2-2 (dated 6/10/99) B 3.2-2 (dated 09/11/15)

B 3.2-3 (dated 6/10/99) B 3.2-3 (dated 09/11/15)

B 3.2-4 (dated 4/12/00) B 3.2-4. (dated 09/11/15)

B 3.2-5 (dated 6/10/99) B 3.2-5 (dated 09/11/15)

B 3.2-6 (Rev. 0) B 3.2-6 (dated 09/11/15)

B 3.2-7 (Rev. 0) B 3 .2-7 (dated 09/11/15)

B 3.2-8 (Rev. 0) B 3.2-8 (dated 09/11/15)

B 3.2-9 (Rev. 0) B 3.2;.9 (dated 09/11/15)

B 3.2-10 (dated 4/12/00) B 3.2-10 (dated 09/11/15)

B 3.2-11 (dated 09/11/15)

B 3.3-89 (dated 11/25/12) B 3.3-89 (dated 02/22/16)

B 3.3-91 (dated 11/25/12) B 3.3-91 (dated 02/22/16)

B 3.3-92 (dated 11/25/12) B 3.3-92 (dated 02/22/16)

B 3.3-93 (dated 11125/12) B 3.3-93 (dated 02/22/16)

B 3.3-94 (dated 11/25/12) B 3.3-94 (dated 02/22/16)

B 3.3-95 (dated 11/25/12) B 3.3-95 (dated 02/22/16)

B 3.3-96 (dated 11/25/12) B 3.3-96 (dated 02/22/16)

B 3.3-97 (dated 11/25/12) B 3.3-97 (dated 02/22/16)

B 3.3-101 (dated 11/25/12) B 3.3-101 (dated 02/22/16)

B 3.3-102 (dated 11/25/12) B 3.3-102 (dated 02/22/16)

B 3.3-103 (dated 11/25/12) B 3.3-103 (dated 02/22/16)

B 3.3-104 (dated 11/25/12) B 3.3-104 (dated 02/22/16)

B 3.3-105 (dated 11/25/12) B 3.3-105 (dated 02/22/16)

B 3.3-106 (dated 11/25/12) B 3.3-106 (dated 02/22/16)

B 3.3-107 (dated 11/25/12) B 3.3-107 (dated 02/22/16)

FILING INSTRUCTIONS TECHNICAL SPECIFICATION BASES REMOVE INSERT B 3.3-108 (dated 11/25/12) B 3.3-108 (dated 02/22/16)

B 3.3-109 (dated 11/25/12) B 3.3-109 (dated 02/22/16)

B 3.3-110 (dated 11/25/12) B 3.3-110 (dated 02/22/16)

B 3.3-111 (dated 11/25/12) B 3.3-111 (dated 02/22/16)

B 3.3-112 (dated 11/25/12) B 3.3-112 (dated 02/22/16)

B 3.3-113 (dated 11/25/12) B 3.3-113 (dated 02/22/16)

B 3.3-114 (dated 11/25/12) B 3.3-114 (dated 02/22/16)

B 3.3-115 (dated 11/25/12) B 3.3-115 (dated 02/22/16)

B 3.3-119 (dated 11/25/12) B 3.3-119 (dated 02/22/16)

B 3.3-144 (dated 11/25/12) B 3.3-144 (dated 07/28/15)

B 3.3-149 (dated 11/25/12) B 3.3-149 (dated 11/22/16)

B 3.4-2 (Rev. 0) B 3.4-2 (dated 09/11/15)

B 3.4-3 (Rev. 0) B 3.4-3 (dated 09/11/15)

B 3.4-4 (dated 01/06/12) B 3.4-4 (dated 09/11/15)

B 3.4-5 (Rev. 0) B 3 .4-5 (dated 09/11/15)

B 3.4-6 (Rev. 0) B 3 .4-6 (dated 09/11/15)

B 3 .4-7 (dated 4/12/00) B 3.4-7 (dated 09/11/15)

B 3 .4-8 (Rev. 0) B 3.4-8 (dated 09/11/15)

B 3 .4-44 (dated 08/11/04) B 3.4-44 (dated 09/22/16)

B 3.4-45 (dated 08/11/04) B 3.4-45 (dated 09/22/16)

B 3.4-46 (dated 04/23/13) B 3.4-46 (dated 09/22/16)

B 3.4-49 (dated 08/11/04) B 3.4-49 (dated 09/22/16)

B 3.4-50 (dated 04/11/06) B 3.4-50 (dated 09/22/16)

B 3.5-1 (Rev. 1) B 3.5-1 (dated 10/21/15)

B 3.5-18 (dated 12/18/03) B 3.5-18 (dated 10/21/15)

B 3.5-21 (Rev. 0) B 3.5-21 (dated 10/21/15)

B 3.5-22 (Rev. 0) B 3.5-22 (dated 10/21/15)

B 3.5-23 (dated 12/18/03) B 3.5-23 (dated 10/21/15)

B 3.6-51 (Rev. 0) B 3.6-51 (dated 02/22/16)

B 3.6-52 (dated 8/13/02) B 3 .6-52 (dated 02/22/16)

B 3.6-53 (Rev. 0) B 3 .6-53 (dated 02/22/16)

B 3.6-54 (Rev. 0) B 3.6-54 (dated 02/22/16)

B 3.6-55 (dated 8/13/02) B 3.6-55 (dated 02/22/16)

B 3.6-56 (dated 8/13/02) B 3.6-56 (dated 02/22/16)

B 3.6-57 (Rev. 0) B 3.6-57 (dated 02/22/16)

B 3.6-58 (Rev. 0) B 3.6-58 (dated 02/22/16)

FILING INSTRUCTIONS TECHNICAL SPECIFICATION BASES REMOVE INSERT B 3.6-59 (Rev. 0) B 3.6-59 (dated 02/22/16)

B 3.6-60 (Rev. 0) B 3.6-60 (dated 02/22116)

B 3.6-61 (Rev. 0) B 3.6-61 (dated 02/22/16)

B 3.6-62 (Rev. 0) B 3.6-62 (dated 02/22/16)

B 3.6-63 (dated 04/28/10) B 3.6-63 (dated 02/22/16)

B 3.6-64 (Rev. 0) B 3 .6-64 (dated 02/22/16)

B 3.6-65 (Rev. 0) B 3.6-65 (dated 02/22/16)

B 3.6-66 (Rev. 0) B 3.6-66 (dated 02/22/16)

B 3.6-67 (dated 10/05/06) B 3.6-67 (dated 02/22116)

B 3.6-68 (dated 10/05/06) B 3 .6-68 (dated 02/22/16)

B 3.6-69 (dated 10/05/06) B 3.6-69 (dated 02/22/16)

B 3.6-70 (dated 10/05/06) B 3.6-70 (dated 02/22/16)

B 3.6-71(dated11/25/12) B 3.6-71(dated02/22/16)

B 3.6-72 (dated 10/05/06) B 3.6-72 (dated 02/22/16)

B 3 .6-73 (dated 10/05/06) B 3.6-73 (dated 02/22116)

B 3.6-74 (dated 10/05/06) B 3.6-74 (dated 02/22/16)

B 3.6-75 (dated 3/8/00) B 3.6-75 (dated 02/22/16)

B 3.6-76 (dated 10/05/06) B 3.6-76 (dated 02/22/16)

B 3.6-77 (dated 12/18/03) B 3 .6-77 (dated 02/22116)

B 3 .6-78 (dated 11/25/12) B 3.6-78 (dated 02/22116)

B 3.6-79 (dated 12/18/03) B 3 .6-79 (dated 02/22/16)

B 3.6-80 (dated 10/05/06) B 3.6-80 (dated 02/22/16)

B 3.6-81 (dated 10/05/06 B 3.6-81 (dated 02/22/16)

B 3.6-82 (dated 10/05/06) B 3.6-82 (dated 02/22116)

B 3.6-83 (datedl0/05/06). B 3.6-83 (dated 02/22/16)

B 3.6-84 (dated 11/25/12) B 3.6-84 (dated 02/22/16)

B 3.6-85 (dated 02/22116)

B 3.6-86 (dated 02/22/16)

B 3.6-87 (dated 02/22/16)

B 3.7-16 (dated 11125112) B 3.7-16 (dated 01/05/17)

B 3.7-31(dated11/25112 B 3.7-31(dated09/11/15)

B 3.7-32 (dated 11/25/12 B 3.7-32 (dated 09/11/15)

B 3.7-33 (dated 11/25/12 B 3.7-33 (dated 09/11/15)

B 3.7-34 (dated 11/25/12 B 3.7-34 (dated 09/11/15)

LIST OF EFFECTIVE PAGES - BASES

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Page No. Revision No./Date Page No. Revision No./Date 02/09/16 B 3.1-17 6/10/99 ii 02/22/16 B 3.1-18 07/16/08 iii 02/22/16 83.1-19 12/03/09 B 3.1-20 12/03/09 B 2.0-1 12/18/03 B 3.1-21 01/06/12 B 2.0-2 0 B 3.1-22 0 B 2.0-3 0 B 3.1-23 0 B 2.0-4 6/10/99 B 3.1-24 0 B 2.0-5 09/25/09 B 3.1-25 05/09/06 B 2.0-6 09/25/09 B 3.1-26 02/02/06 B 2.0-7 0 B 3.1-27 05/09/06 B 2.0-8 09/25/09 B 3.1-28 12/18/03 B 3.1-29 0 B 3.0-1 06/30/06 B 3.1-30 0 B 3.0-2 0 B 3.1-31 0 B 3.0-3 0 B 3.1-32 0 B 3.0-4 0 B 3.1-33 01/30/03 I B 3.0-5 09/18/09 B 3.1-34 07/16/08 B 3.0-6 09/18/09 B 3.1-35 07/16/08 B 3.0-7 09/18/09 B 3.1-36 07/16/08 B 3.0-8 09/18/09 B 3.1-37 07/16/08 B 3.0-9 09/18/09 B 3.1-38 07/16/08 B 3.0-10 09/18/09 B 3.1-39 09/25/09 B 3.0-11 09/18/09 B 3.1-40 04/10/15 B 3.0-12 09/18/09 B 3.1-41 09/25/09 B 3.0-13 09/18/09 B 3.1-42 09/25/09 B 3.0-14 09/18/09 B 3.1-43 09/25/09 B 3.0-15 09/18/09 B 3.1-44 11/25/12 B 3.0-16 09/18/09 B 3.1-45 09/25/09 B 3.0-17 09/18/09 B 3.1-46 09/25/09 B 3.0-18 09/18/09 B 3.1-47 09/25/09 B 3.1-48 0 H 3.1-1 6/10/99 B 3.1-49 0 B 3.1-2 6/10/99 B 3.1-50 11/25/12 B 3.1-3 6/10/99 83.1-51 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 09/11/15 B 3.1-8 12/18/03 B 3.2-4 09/11/15 B 3.1-9 6/10/99 B 3.2-5 09/11/15 B 3.1-10 6/10/99 B 3.2-6 09/11/15 83.1-11 6/10/99 B 3.2-7 09/11/15 83.1-12 12/18/03 B 3.2-8 09/11/15 B 3.1-13 12/18/03 B 3.2-9 09/11/15 83.1-14 6/10/99 B 3.2-10 09/11/15 B 3.1-15 6/10/99 B 3.2-11 09/11/15 B 3.1-16 12/03/09 I

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LIST OF EFFECTIVE PAGES- BASES (continued)

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Page No. Revision No./Date Page No. Revision No./Date

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I 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 11/25/12 B 3.3-3 11/25/12 B 3.3-51 11/25/12 B 3.3-4. 11/25/12 B 3.3-52 11/25/12 B 3.3-5 11/25/12 B 3.3-53 11/25/12 B 3.3-6 11/25/12 B 3.3-54 11/25/12 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 11/25/12 B 3.3-12 11/25/12 B 3.3-60 11/25/12 B 3.3-13 11/25/12 B 3.3-61 11/25/12 B 3.3-14 11/25/12 B 3.3-62 11/25/12 B 3.3-15 11/25/12 B 3.3-63 11/25/12 83.3-16 11/25/12 B 3.3-64 11/25/12 B 3.3-17 11/25/12 B 3.3-65 11/25/12 B 3.3-18 11/25/12 B 3.3-66 11/25/12 B 3.3-19 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 11/25/12 B 3.3-22 11/25/12 B 3.3-70 11/25/12 B 3.3-23 11/25/12 B 3.3-71 11/25/12 B 3.3-24 11/25/12 B 3.3-72 11/25/12 B 3.3-25 11/25/12 B 3.3-73 11/25/12 B 3.3-26 11/25/12 B 3.3-74 11/25/12 B 3~3-27 11/25/12 B 3.3-75 11/25/12 B 3.3-28 11/25/12 B 3.3-76 11/25/12 B 3.3-29 11/25/12 B 3.3-77 02/24/14 B 3.3-30 11/25/12 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 11/25/12 B 3.3-84 11/25/12 B 3.3-37 11/25/12 B 3.3-85 11/25/12 B 3.3-38 11/25/12 B 3.3-86 09/18/14 B 3.3-39 11/25/12 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 02/22/16 B 3.3-47 11/25/12 B 3.3-95 02/22/16 B 3.3-48 11/25/12 B 3.3-96 02/22/16

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LIST OF EFFECTIVE PAGES - BASES (continued)

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Page No. Revision No./Date Page No. Revision No./Date B 3.3-97 02/22/16 B 3.3-144 07/28/15 B 3.3-98 11/25/12 8 3.3-145 11/25/12 B 3.3-99 11/25/12 B 3.3-146 11/25/12 B 3.3-100 11/25/12 8 3.3-147 11/25/12 B 3.3-101 02/22/16 B 3.3-148 11/25/12 B 3.3-102 02/22/16 B 3.3-149 11/22/16 B 3.3-103 02/22/16 B 3.3-150 11/25/12 B 3.3-104 02/22/16 8 3.3-151 11/25/12 B 3.3-105 02/22/16 8 3.3-152 11/25/12 B 3.3-106 02/22/16 8 3.3-153 11/25/12 B 3.3-107 02/22/16 8 3.3-154 11/25/12 8 3.3-108 02/22/16 8 3.3-155 11/25/12 8 3.3-109 02/22/16 8 3.3-156 11/25/12 83.3-110 02/22/16 B 3.3-157 11/25/12 8 3.3-111 02/22/16 8 3.3-158 11/25/12 B 3.3-112 02/22/16 8 3.3-159 11/25/12 8 3.3-113 02/22/16 8 3.3-160 11/25/12 8 3.3-114 02/22/16 8 3.3-161 11/25/12 83.3-115 02/22/16 B 3.3-162 11/25/12 8 3.3-116 11/25/12 8 3.3-163 11/25/12 B 3.3-117 11/25/12 8 3.3-164 11/25/12 B 3.3-118 11/25/12 8 3.3-165 11/25/12 B 3.3-119 02/22/16 B 3.3-166 11/25/12 I 8 3.3-120 11/25/12 B 3.3-167 11/25/12

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8 3.3-121 11/25/12 8 3.3-168 11/25/12 8 3.3-122 11/25/12 8 3.3-169 11/25/12 8 3.3-123 11/25/12 8 3.3-170 11/25/12 B 3.3-124 11/25/12 B 3.3-171 11/25/12*

8 3.3-125 11/25/12 8 3.3-172 11/25/12 8 3.3-126 11/25/12 B 3.3-173 11/25/12 B 3.3-127 11/25/12 8 3.3-174 11/25/12 B 3.3-128 11/25/12 8 3.3-175 11/25/12 8 3.3-129 11/25/12 8 3.3-176 11/25/12 83.3-130 11/25/12 8 3.3-177 11/25/12 8 3.3-131 11/25/12 B 3.3-178 11/25/12 B 3.3-132 11/25/12 8 3.3-179 11/25/12 8 3.3-133 11/25/12 8 3.3-180 11/25/12 8 3.3-134 11/25/12 8 3.3-181 11/25/12 B 3.3-135 11/25/12 B 3.3-182 11/25/12 8 3.3-136 11/25/12 8 3.3-183 11/25/12 8 3.3-137 11/25/12 8 3.3-184 11/25/12 8 3.3-138 11/25/12 B 3.3-185 11/25/12 8 3.3-139 11/25/12 B 3.3-186 11/25/12 B 3.3-140 11/25/12 B 3.3-187 11/25/12 8 3.3-141 11/25/12 B 3.3-188 11/25/12 8 3.3-142 11/25/12 B 3.3-189 11/25/12 B 3.3-143 11/25/12 8 3.3-190 11/25/12

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LIST OF EFFECTIVE PAGES- BASES (continued)

Page No. Revision No./Date Page No. Revision No./Date

1 B 3.3-191 11/25/12 B 3.4-40 0 B 3.3-192 11/25/12 B 3.4-41 0 B 3.3-193 11/25/12 B 3.4-42 0 B 3.3-194 11/25/12 B 3.4-43 0 B 3.3-195 11/25/12 B 3.4-44 09/22/16 B 3.3-196 11/25/12 B 3.4-45 09/22/16 B 3.3-197 11/25/12 B 3.4-46 09/22/16 B 3.3-198 11/25/12 B 3.4-47 0 B 3.4-48 0 B 3.4-1 0 B 3.4-49 09/22/16 B 3.4-2 09/11/15 B 3.4-50 09/22/16 B 3.4-3 09/11/15 B 3.4-51 04/23/13 B 3.4-4 09/11/15 B 3.4-52 04/23/13 B 3.4-5 09/11/15 B 3.4-53 0 B 3.4-6 09/11/15 B 3.4-54 0 B 3.4-7 09/11/15 B 3.4-55 *O B 3.4-8 09/11/15 B 3.4-9 0 B 3.5-1 10/21/15 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 1 B 3.5-4 0 B 3.4-13 4/12/00 B 3.5-5 04/26/04 B 3.4-14 0 B 3.5-6 09/18/09 B 3.4-15 03/05/12 B 3.5-7 04/26/04 B 3.4-16 03/05/12 B 3.5-8 04/26/04 B 3.4-17 11/25/12 B 3.5-9 1 B 3.4-18 03/05/12 B 3.5-10 0 B 3.4-19 0 B 3.5-11 0 B 3.4-20 0 B 3.5-12 04/28/10 B 3.4-21 0 B 3.5-13 11/25/12 B 3.4-22 0 B 3.5-14 11/25/12 B 3.4-23 0 B 3.5-15 11/25/12 B 3.4-24 0 B 3.5-16 11/25/12 B 3.4-25 0 B 3.5-17 11/23/99 B 3.4-26 09/18/09 B 3.5-18 10/21/15 B 3.4-27 09/18/09 B 3.5-19 0 B 3.4-28 6/28/01 B 3.5-20 0 B 3.4-29 11/13/14 B 3.5-21 10/21/15 B 3.4-30 0 B 3.5-22 10/21/15 B 3.4-31 09/18/09 B 3.5-23 10/21/15 B 3.4~32 09/25/09 B 3.5-24 0 B 3.4-33 1 B 3.5-25 1 B 3.4-34 0 B 3.5-26 09/18/09 B 3.4-35 09/18/09 B 3.5-27 09/18/09 B 3.4-36 0 B 3.5-28 09/18/09 B 3.4-37 0 B 3.5-29 11/25/12 B 3.4-38 0 B 3.5-30 12/18/03 B 3.4-39 1

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Page No. Revision No./Date Page No. Revision No./Date B 3.6-1 3/8/00 B 3.6-49 0 B 3.6-2 09/30/08 B 3.6-50 11/25/12 B 3.6-3 3/8/00 B 3.6-51 02/22/16 8 3.6-4 11/06/06 8 3.6-52 02/22/16 8 3.6-5 11/25/12 8 3.6-53 02/22/16 8 3.6-6 0 B 3.6-54 02/22/16 8 3.6-7 09/30/08 8 3.6-55 02/22/16 8 3.6-8 0 8 3.6-56 02/22/16 8 3.6-9 0 8 3.6-57 02/22/16 8 3.6-10 0 8 3.q-58 02/22/16 8 3.6-11 0 8 3.6-59 02/22/16 8 3.6-12 318100 B 3.6-60 02/22/16 83.6-13 09/30/08 8 3.6-61 02/22/16 8 3.6-14 318100 8 3.6-62 02/22/16 83.6-15 0 8 3.6-63 02/22/16 8 3.6-16 1 8 3.6-64 02/22/16 8 3.6-17 0 8 3.6-65 02/22/16 8 3.6-18 0 8 3.6-66 02/22/16 8 3.6-19 11/28/01 B 3.6-67 02/22/16 8 3.6-20 11/28/01 8 3.6-68 02/22/16 8 3.6-21 11/28/01 8 3.6-69 02/22/16 8 3.6-22 11/28/01 8 3.6-70 02/22/16 8 3.6-23 11/28/01 8 3.6-71 02/22/16 8 3.6-24 1 8 3.6-72 02/22/16 8 3.6-25 1 8 3.6-73 02/22/16 8 3.6-26 3/8/00 8 3.6-74 02/22/16 8 3.6-27 11/25/12 8 3.6-75 02/22/16 8 3.6-28 11/25/12 8 3.6-76 02/22/16 8 3.6-29 09/25/09 8 3.6-77 02/22/16 8 3.6-30 09/30/08 8 3.6-78 02/22/16 8 3.6-31 09/30/08 8 3.6-79 02/22/16 B 3.6-32 12/27/02 B 3.6-80 02/22/16 8 3.6-33 12/27/02 8 3.6-81 02/22/16 8 3.6-34 12/14/01 8 3.6-82 02/22/16 8 3.6-35 0 8 3.6-83 02/22/16 8 3.6-36 0 8 3.6-84 02/22/16 8 3.6-37 11/25/12 8 3.6-85 02/22/16 8 3.6-38 11/25/12 8 3.6-86 02/22/16 8 3.6-39 0 8 3.6-87 02/22/16 8 3.6-40 0 8 3.6-41 0 8 3.7-1 11/25/12 8 3.6-42 0 8 3.7-2 11/25/12 8 3.6-43 0 8 3.7-3 11/25/12 8 3.6-44 11/25/12 8 3.7-4 11/25/12 8 3.6-45 0 8 3.7-5 11/25/12 B 3.6-46 6/10/99 B 3.7-6 11/25/12 B 3.6-47 0 8 3.7-7 12/21/12 B 3.6-48 0 B 3.7-8 11/25/12 Cooper 5 01/05/17

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B 3.7-9 11/25/12 B 3.8-22 02/07/13 B 3.7-10 09/18/14 B 3.8-23 02/07/13 B 3.7-11 11/25/12 B 3.8-24 02/07/13 B 3.7-12 11/25/12 B 3.8-25 02/07/13 B 3.7-13 11/25/12 B 3.8-26 02/07/13 B 3.7-14 11/25/12 B 3.8-27 02/07/13 B 3.7-15 11/25/12 B 3.8-28 02/07/13 B 3.7-16 01/05/17 B 3.8-29 02/07/13 B 3.7-17 11/25/12 B 3.8-30 02/07/13 B 3.7-18 11/25/12 B 3.8-31 02/07/13 B 3.7-19 11/25/12 B 3.8-32 02/07/13 B 3.7-20 11/25/12 B 3.8-33 02/07/13 B 3.7-21 11/25/12 B 3.8-34 02/07/13 B 3.7-22 11/25/12 B 3.8-35 02/07/13 B 3.7-23 11/25/12 B 3.8-36 02/07/13 B 3.7-24 11/25/12 B 3.8-37 02/07/13 B 3.7-25 11/25/12 B 3.8-38 02/07/13 B 3.7-26 11/25/12 B 3.8-39 02/07/13 B 3.7-27 11/25/12 B 3.8-40 02/07/13 B 3.7-28 11/25/12 B 3.8-41 02/07/13 B 3.7-29 11/25/12 B 3.8-42 02/07/13 B 3.7-30 11/25/12 B 3.8-43 02/07/13 B 3.7-31 09/11/15 B 3.8-44 02/07/13 B 3.7-32 09/11/15 B 3.8-45 07/10/13

) B 3.7-33 09/11/15 B 3.8-46 02/07/13 B 3.7-34 09/11/15 B 3.8-47 02/07/13 B 3.8-48 02/07/13 B 3.8-1 02/07/13 B 3.8-49 02/07/13 B 3.8-2 02/07/13 B 3.8-50 02/07/13 B 3.8-3 02/07/13 B 3.8-51 02/07/13 B 3.8-4 02/07/13 B 3.8-52 02/07/13 B 3.8-5 02/07/13 B 3.8-53 02/07/13 B 3.8-6 02/07/13 B 3.8-54 02/07/13 B 3.8-7 02/07/13 B 3.8-55 02/07/13 B 3.8-8 02/07/13 B 3.8-56 02/07/13 B 3.8-9 02/07/13 B 3.8-57 02/07/13 B 3.8-10 02/07/13 B 3.8-58 02/07/13 B 3.8-11 02/07/13 B 3.8-59 02/07/13 B 3.8-12 02/07/13 B 3.8-60 02/07/13 B 3.8-13 02/07/13 B 3.8-61 02/07/13 B 3.8-14 02/07/13 B 3.8-62 02/07/13 B 3.8-15 02/07/13 B 3.8-63 02/07/13 B 3.8-16 02/07/13 B 3.8-64 02/07/13 B 3.8-17 02/07/13 B 3.8-65 02/07/13 a 3.8-18 02/07/13 B 3.8-66 02/07/13 B 3.8-19 02/07/13 B 3.8-20 02/07/13 B 3.9-1 12/18/03 B 3.8-21 02/07/13 B 3.9-2 0 Cooper 6 01/05/17

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Cooper 7 01/05/17

/--- TABLE OF CONTENTS B 2.0 SAFETY LIMITS (SLs) .............................................................................. B 2.0-1 B 2.1.1 Reactor Core SLs .......................................................................... B 2.0-1 B 2.1.2 Reactor Coolant System (RCS) Pressure SL ................................ B 2.0-6 B 3.0 LIMITING CONDITION FOR OPERATION (LCO) APPLICABILITY .......... B 3.0-1 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY ....................... 8 3.0-13 B 3.1 REACTIVITY CONTROL SYSTEMS ........................................................ B 3.1-1 B 3.1.1 SHUTDOWN MARGIN (SOM) ....................................................... B 3.1-1 B 3.1.2 Reactivity Anomalies ..................................................................... B 3.1-8 B 3.1.3 Control Rod OPERABILITY .......................................................... B 3.1-13 B 3.1.4 Control Rod Scram Times ............................................................ 8 3.1-22 B 3.1.5 Control Rod Scram Accumulators ................................................ 8 3.1-29 B 3.1.6 Rod Pattern Control ..................................................................... 8 3.1-34 B 3.1.7 Standby Liquid Control (SLC) System .......................................... 8 3.1-39 B 3.1.8 Scram Discharge Volume (SDV) Vent and Drain Valves .............. 8 3.1-46 B 3.2 POWER DISTRIBUTION LIMITS .............................................................. B 3.2-1 B 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR) ..................................................................... B 3.2-1 B 3.2.2 MINIMUM CRITICAL POWER RATIO (MCPR) ............................. B 3.2-4 B 3.2.3 LINEAR HEAT GENERATION RATE (LHGR) ............................... B 3.2-8 B 3.3 INSTRUMENTATION ............................................................................... B 3.3-1 B 3.3.1.1 Reactor Protection System (RPS) Instrumentation ........................ B 3.3-1 B 3.3.1.2 Source Range Monitor (SRM) Instrumentation ............................. 8 3.3-32 B 3.3.2.1 Control Rod Block Instrumentation ............................................... 8 3.3-40 B 3.3.2.2 Feedwater and Main Turbine High Water Level Trip Instrumentation .......................................................................8 3.3-55 B 3.3.3.1 Post Accident Monitoring (PAM) Instrumentation ......................... 8 3.'3-61 B 3.3.3.2 Alternate Shutdown System ......................................................... 8 3.3-72 B 3.3.4.1 Anticipated Transient Without Scram Recirculation Pump Trip (ATWS-RPT) lnstrumentation ................................ 8 3.3-79 B 3.3.5.1 Emergency Core Cooling System (ECCS) lnstrumentation ....................................................................... 8 3.3-87 B 3.3.5.2 Reactor Core Isolation Cooling (RCIC) System lnstrumentation ..................................................................... B 3.3-120 B 3.3.6.1 Primary Containment Isolation Instrumentation .......................... 8 3.3-132 B 3.3.6.2 Secondary Containment Isolation Instrumentation ..................... 8 3.3-158 B 3.3.6.3 Low-Low Set (LLS) Instrumentation ........ :.................................. 8 3.3-168 B 3.3.7.1 Control Room Emergency Filter (CREF) System

'._) Instrumentation ..................................................................... B 3.3-174 Cooper 02/09/16

TABLE OF CONTENTS 8 3.3 INSTRUMENTATION (continued) 8 3.3.8.1 Loss of Power (LOP) lnstrumentation ......................................... B 3.3-183 8 3.3.8.2 Reactor Protection System (RPS) Electric Power Monitoring ................................................................. 8 3.3-193 8 3.4 REACTOR COOLANT SYSTEM (RCS) .................................................... 8 3.4-1 8 3.4.1 Recirculation Loops Operating ...................................................... 8 3.4-1 8 3.4.2 Jet Pumps ..................................................................................... 8 3.4-9 8 3.4.3 Safety/Relief Valves (SRVs) and Safety Valves (SVs) ................. 8 3.4-14 8 3.4.4 RCS Operational LEAKAGE. ........................................................ 8 3.4-19 8 3.4.5 RCS Leakage Detection Instrumentation ..................................... 8 3.4-24 8 3.4.6 RCS Specific Activity ....................................................................8 3.4-29 8 3.4.7 Residual Heat Removal (RHR) Shutdown Cooling System - Hot Shutdown **********'**********************************************8 3.4-33 8 3.4.8 Residual Heat Removal (RHR) Shutdown Cooling System - Cold Shutdown .. ; .................................................... 8 3.4-39 B 3.4.9 RCS Pressure and Temperature (PIT) Limits ............................... 8 3.4-44 8 3.4.10 Reactor Steam Dome Pressure .................................................... 8 3.4-53 8_3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM ........................... 8 3.5-1 8 3.5.1 ECCS- Operating ........................................................................ 8 3.5-1 8 3.5.2 ECCS - Shutdown ........................................................................ 8 3.5-18 8 3.5.3 RCIC System ...............................................................................8 3.5-24 8 3.6 CONTAINMENT SYSTEMS************.********************************************************* B 3.6-1 8 3.6.1.1 Primary Containment .................................................................... 8 3.6-1 8 3.6.1.2 Primary Containment Air Lock ....................................................... B 3.6-6 8 3.6.1.3 Primary Containment Isolation Valves (PCIVs) ............................ 8 3.6-15 8 3.6.1.4 Drywell Pressure ..........................................................................B 3.6-30 8 3.6.1.5 Drywell Air Temperature ............................................................... 8 3.6-32 8 3.6.1.6 Low-Low Set (LLS) Valves ........................................................... 8 3.6-35 8 3.6.1.7 Reactor Building-to-Suppression Chamber Vacuum Breakers .................................................................................B 3.6-39 8 3.6.1.8 Suppression Chamber-to-Drywell Vacuum Breakers .................... 8 3.6-45 8 3.6.1.9 Residual Heat Removal (RHR) Containment Spray ..................... 8 3.6-51 8 3.6.2.1 Suppression Pool Average Temperature ...................................... 8 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 ........... 8 3.6-63 8 3.6.3.1 Primary Containment Oxygen Concentration ............................... 8 3.6-67 8 3.6.4.1 Secondary Containment. .............................................................. 8 3.6-70

) 8 3.6.4.2 Secondary Containment Isolation Valves (SCIVs) ........................ B 3.6-75 Cooper ii 02/22/16

TABLE OF CONTENTS B 3.6.4.3 Standby Gas Treatment (SGT) System ........................................ B 3.6-82 B 3.7 PLANT SYSTEMS .................................................................................... B 3.7-1 B 3.7.1 Residual Heat Removal Service Water Booster (RHRSWB) System ................................................................. B 3.7-1 B 3.7.2 Service Water (SW) System and Ultimate Heat Sink (UHS) .......... B 3.7-6 B 3.7.3 Reactor Equipment Cooling (REC) System .................................. B 3.7-11 B 3.7.4 Control Room Emergency Filter System ...................................... B 3.7-17 B 3.7.5 Air Ejector Offgas ................................................................... ~ ..... B 3.7-25 B 3.7.6 Spent Fuel Storage Pool Water Level .......................................... B 3.7-28 B 3.7.7 Main Turbine Bypass System ....................................................... B 3.7-31 B 3.8 ELECTRICAL POWER SYSTEMS ........................................................... B 3.8-1 B 3.8.1 AC Sources - Operating ............................................................... 8 3.8-1 B 3.8.2 AC Sources -Shutdown .............................................................. B 3.8-23 B 3.8.3 Diesel Fuel Oil, Lube Oil, and Starting Air .................................... B 3.8-29 B 3.8.4 DC Sources - Operating ..............................................................B. 3.8-38

.B 3.8.5 DC Sources - Shutdown ..............................................................B 3.8-47 B 3.8.6 Battery Cell Parameters ...............................................................B 3.8-50 B 3.8.7 Distribution Systems - Operating ................................................. B 3.8-56 B 3.8.8 Distribution Systems - Shutdown ................................................. B 3.8-63 B 3.9 REFUELING OPERATIONS ..................................................................... B 3.9-1 B 3.9.1 Refueling Equipment Interlocks ..................................................... B 3.9-1 B 3.9.2 Refuel Position One-Rod-Out Interlock ......................................... B 3.9-6 B 3.9.3 Control Rod Position ..................................................................... B 3.9-9 B 3.9.4 Control Rod Position Indication .................................................... B 3.9-12 B 3.9.5 Control Rod OPERABILITY- Refueling ....................................... B 3.9-16 8 3.9.6 Reactor Pressure Vessel (RPV) Water Level ............................... 8 3.9-19 8 3.9.7 Residual Heat Removal (RHR) - High Water Level.. .................... B 3.9-22 B 3.9.8 Residual Heat Removal (RHR) - Low Water Level ...................... B 3.9-27 B 3.10 SPECIAL OPERATIONS .........................................................................B 3.10-1 B 3.10.1 lnservice Leak and Hydrostatic Testing Operation ....................... B 3.10-1 B 3.10.2 Reactor Mode Switch Interlock Testing ................................... :.... B 3.10-6 B 3.10.3 Single Control Rod Withdrawal - Hot Shutdown ......................... B 3.10-11 B 3.10.4 Single Control Rod Withdrawal - Cold Shutdown ....................... B 3.10-16 8 3.10.5 Single Control Rod Drive (CRD) Removal - Refueling ............... 8 3.10-21 B 3.10.6 Multiple Control Rod Withdrawal - Refueling ............................. B 3.10-26 8 3.10.7 Control Rod Testing - Operating ................................................ B 3.10-30 8 3.10.8 SHUTDOWN MARGIN (SOM) Test- Refueling ......................... B 3.10-34

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Cooper iii 02/22/16

SLC System B 3.1.7 BASES APPLICABLE SAFETY ANALYSES (continued) produces a concentration of 660 ppm of natural boron. To allow for potential leakage and imperfect mixing in the reactor system, an amount of boron equal to 25% of the amount cited above is added (Ref. 2). The volume versus concentration limits in Figure 3.1.7-1 and the temperature versus concentration limits in Figure 3.1. 7-2 are calculated such that the required concentration is achieved accounting for dilution in the RPV with normal water level and including the water volume in the residual heat removal shutdown cooling piping and in the recirculation loop piping. This quantity of borated solution is the amount that is above the pump suction shutoff level in the boron solution storage tank. No credit is taken for the portion of the tank volume that cannot be injected.

The Alternative Source Term LOCA analysis methodology (Ref. 4) credits the use of the SLC System for injecting sodium pentaborate solution into the RPV following a LOCA with fuel damage to maintain the pH of the water in the Suppression Chamber above 7.0. By maintaining the pH of the water above 7.0 following a LOCA with fuel damage, the majority of the iodine released from a damaged core will be retained in,solution in the water and not released as elemental iodine in gaseous form. This will ensure that the radiological consequences from the LOCA will remain

) within the limits of 10 CFR 50.67 (Ref. 5). Credit for the SLC System in the radiological analyses is based on operation of one SLC pump, initiated 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months after start of the LOCA, with injection completed within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . (Ref. 2)

The SLC System satisfies Criterion 4 of 10 CFR 50.36 ( c )(2)(ii) (Ref. 3).

LCO The OPEMJ31LITY of the SLC System provides backup capability for reactivity control independent of normal reactivity control provisions provided by the control rods. Additionally, an OPERABLE SLC System allows the injection of the sodium pentaborate solution into the RPV following a LOCA with core damage in order to maintain the pH of the water in the Suppression Chamber at or above 7.0. The OPERABILITY of the SLC System is based on the conditions of the borated solution in the storage tank and the availability of a flow path to the RPV, including the OPERABILITY of the pumps and valves. Two SLC subsystems are required to be OPERABLE; each contains an OPERABLE pump, an explosive valve, and associated piping, valves, and instruments and controls to ensure an OPERABLE flow path.

Cooper B 3.1-40 04/10/15

APLHGR B 3.2.1 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.1 AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)

BASES BACKGROUND The APLHGR is a measure of the average LHGR of all the fuel rods in a fuel assembly at any axial location. Limits on the APLHGR are specified to ensure that the peak cladding temperature (PCT} during the postulated design basis loss of coolant accident (LOCA) does not exceed the limits specified in 10 CFR 50.46.

APPLICABLE SAFETY ANALYSIS The analytical methods and assumptions used in evaluating a LOCA, abnormal operational transients, and normal operation that determine the APLHGR limits are presented in References 1, 3, 4, 5, 6, and 10.

APLHGR limits are developed as a function of exposure and the various operating core flow and power states to ensure adherence to 10 CFR 50.46 during the limiting LOCA (Refs. 5 and 6).

) LOCA analyses are performed to ensure that the above determined APLHGR limits are adequate to meet the PCT and maximum oxidation limits of 10 CFR 50.46. The analysis is performed using calculational models that are consistent with the requirements of 10 CFR 50, Appendix K. A complete discussion of the analysis code is provided in References 9 and 10. The PCT following a postulated LOCA is a function of the average heat generation rate of all the rods of a fuel assembly at any axial location and is not strongly influenced by the rod to rod power distribution within an assembly. The APLHGR limitS specified are equivalent to the LHGR of the highest powered fuel rod assumed in the LOCA analysis divided by its local peaking factor.

The exposure dependent APLHGR limits are reduced by MAPFACt and MAPFACp at various operating conditions to ensure that all fuel design criteria are met for normal operation and LOCA.

For single recirculation loop operation, the MAPFAC multiplier is contained in the COLR. This maximum limit is due to the conservative analysis assumption of an earlier departure from nucleate boiling with one recirculation loop available, resulting in a more severe cladding heatup during a LOCA (Refs. 5 and 9).

The APLHGR satisfies Criterion 2of10 CFR 50.36(c)(2)(ii) (Ref. 12).

Cooper B 3.2-1 09/11/15

APLHGR B 3.2.1 BASES LCO The APLHGR limits (for each type of fuel as a function of average planar exposure) specified in the COLR are the result of the LOCA analyses.

For two recirculation loops operating, the limit is determined by multiplying the smaller of the MAPFACp and MAPFACt factors times the exposure dependent APLHGR limits. With only one recirculation loop in operation, in conformance with the requirements of LCO 3.4.1, "Recirculation Loops Operating," the limit is determined by multiplying the exposure dependent APLHGR limit by the one recirculation loop operation multiplier contained in the COLR.

APPLICABILITY The APLHGR limits are primarily derived from fuel design evaluations and LOCA analyses that are assumed to occur at high power levels.

Design calculations (Ref. 6) and operating experience have shown that as power is reduced, the margin to the required APLHGR limits increases.

This trend continues down to the power range of 5% to 15% RTP when entry into MODE 2 occurs. When in MODE 2, the intermediate range monitor scram function provides prompt scram initiation during any significant transient, thereby effectively removing any APLHGR limit compliance concern in MODE 2. Therefore, at THERMAL POWER levels

~ 25% RTP, the reactor is operating with substantial margin to the APLHGR limits; thus, this LCO is not required.

ACTIONS A.1 If any APLHGR exceeds the required limits, an assumption regarding an initial condition of the LOCA analyses may not be met. Therefore, prompt action should be taken to restore the APLHGR(s) to within the required limits such that the plant operates within analyzed conditions and within design limits of the fuel rods. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is sufficient to restore the APLHGR(s) to within its limits and is acceptable based on the low probability of a LOCA occurring simultaneously with the APLHGR out of specification.

B.1 If the APLHGR 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.

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Cooper B 3.2-2 09/11/15

APLHGR B 3.2.1 BASES SURVEILLANCE REQUIREMENTS SR 3.2.1.1 APLHGRs are 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 2: 25% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months thereafter.

They are compared to the specified limits in the COLR to ensure that the reactor is operating within the assumptions of the safety analysis. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER 2: 25% RTP is achieved is acceptable given the large inherent margin to operating limits at low power levels.

REFERENCES 1. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel," (Revision specified in the COLR).

2. Deleted.

3. USAR,Section VI.

4. USAR,Section XIV.

5. NED0-24258, "Cooper Nuclear Station Single-Loop Operation,"

May 1980.

6. NEDC-32914P, "Maximum Extended Load Line Limit and Increased Core Flow for Cooper Nuclear Station," Revision 0, January 2000.

7. Deleted.

8. Deleted.

9. NEDC-32687P, Revision 1, "Cooper Nuclear Station SAFER/

GESTR-LOCA Loss-of-Coolant Accident Analysis," March 1997.

10. NEDE-23785-1-PA, "The GESTR-LOCA and SAFER Models for the Evaluation of Loss-of-Coolant Accident," Volume Ill, Revision 1, October 1984.

11. Deleted.

12. 10 CFR 50.36(c)(2)(ii).

Cooper B 3.2-3 09/11/15

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 9f boiling transition to the actual fuel assembly power. The MCPR Safety Limit (SL) is set such that 99.9% of the fuel rods avoid boiling transition if the limit is not violated (refer to the Bases for SL 2.1.1.2). The operating limit MCPR is established to ensure that no fuel damage results during abnormal operational transients. 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 (tiCPR). When the largest fiCPR is added to the MCPR SL, the required operating limit MCPR is obtained.

Cooper B 3.2-4 09/11/15

MCPR B 3.2.2 BASES APPLICABLE SAFETY ANALYSIS (continued)

The MCPR operating limits derived from the transient analysis are dependent on the operating core flow and power state (MCPRt 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 mainly by the one dimensional transient code (Ref. 9). Due to the sensitivity of the transient response to initial core flow levels at power levels below those ~t 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 (for each type of fuel at rated power and flow) specified in the COLR 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.

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 for any significant power increase transient, which effectively eliminates

) any MCPR compliance concern. Therefore, at THERMAL POWER levels

-_/

Cooper B 3.2-5 09111115 I

MCPR B 3.2.2 BASES APPLICABILITY (continued)

< 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.

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 then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slowness of changes in power distribution during normal operation. 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.

Cooper B 3.2-6 09111115 I

MPCR B 3.2.2

---"""'\

I BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.2.2.2 Because the transient analysis takes credit for conservatism in the scram speed performance, it must be demonstrated that the specific scram speed distribution is consistent with that used in the transient analysis.

SR 3.2.2.2 determines the value of T, which is a measure of the actual scram speed distribution compared with the assumed distribution. The MCPR operating limit is then determined based on an interpolation between the applicable limits for Option A (scram times of LCO 3.1.4, "Control Rod Scram Times") and Option B (realistic scram times) analyses. The parameter r must be determined once within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months after each set of scram time tests required by SR 3.1.4.1 and SR 3.1.4.2 pecause the effective scram speed distribution may change during the cycle. The 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Completion Time is acceptable due to the relatively minor changes in r expected during the fuel cycle.

REFERENCES 1. NUREG-0562, June 1979.

2. NEDE-24011-P-A-10, "General Electric Standard Application for

_)

Reactor Fuel," (Revision specified in the COLR).

3. USAR, Section Ill.

4. USAR,Section VI.

5. USAR,Section XIV.

6. NED0-24258, "Cooper Nuclear Station Single-Loop Operation,"

May 1980.

7. NEDC-32914P, "Maximum Extended Load Line Limit and Increased Core Flow for Cooper Nuclear Station," Revision 0, January 2000.

8. NED0-30130-A, "Steady State Nuclear Methods," May 1985.

9. NED0-24154, "Qualification of the One-Dimensional Core Transient Model for Boiling Water Reactors," October 1978.

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

, ____ )

Cooper B 3.2-7 09111115 I

LHGR B 3.2.3 B 3.2 POWER DISTRIBUTION LIMITS B 3.2.3 LINEAR HEAT GENERATION RATE (LHGR)

BASES BACKGROUND The LHGR is a measure of the heat generation rate of a fuel rod in a fuel assembly at any axial location. Limits on LHGR are specified to ensure that fuel design limits are not exceeded anywhere in the core during normal operation, including anticipated operational occurrences (AOOs),

and to ensure that the peak clad temperature (PCT) during postulated design basis loss of coolant accident (LOCA) does not exceed the limits specified in 10 CFR 50.46. Exceeding the LHGR limit could potentially result in fuel damage and subsequent release of radioactive materials.

Fuel design limits are specified to ensure that fuel system damage, fuel rod failure, or inability to cool the fuel does not occur during the anticipated operating conditions identified in References 1 and 2.

APPLICABLE SAFETY ANALYSIS The analytical methods and assumptions used in evaluating the fuel system design limits are presented in Reference 1. The analytical methods and assumptions used in evaluating AOOs and normal operation that determine the LHGR limits are presented in Reference 2.

The fuel assembly is designed to ensure (in conjunction with the core nuclear and thermal hydraulic design, plant equipment, instrumentation, and protection system) that fuel damage will not result in the release of radioactive materials in excess of the guidelines of 10 CFR, Parts 20, 50, and 100. The mechanisms that could cause fuel damage during operational transients and that are considered in fuel evaluations are:

a. Rupture of the fuel rod and cladding caused by strain from the relative pellet and expansion of the U02 *

b. Severe overheating of the fuel rod cladding caused by inadequate cooling.

A value of 1 % plastic strain of the fuel cladding has been defined as the limit below which fuel damage caused by overstraining of the fuel cladding is not expected to occur (Ref. 3).

Fuel design evaluations have been performed and demonstrate that the 1% fuel cladding plastic strain design limit is not exceeded during continuous operation with LHGRs up to the operating limit specified in the COLR. The analysis also includes allowances for short-term transient operation above the operating limit to account for AOOs, plus an allowance for densification power spiking.

Cooper B 3.2-8 09/11/15

LHGR B 3.2.3

')

BASES APPLICABLE SAFETY ANALYSIS (continued)

LHGR limits are developed as a function of exposure and the various operating core flow and power states to ensure adherence to fuel design limits during the limiting AOOs (Refs. 4 and 5). Flow dependent LHGR limits are determined (Ref. 5) using the three dimensional BWR simulator code (Ref. 6) to analyze slow flow runout transients. The flow dependent multiplier, LHGRFACt, is dependent on the maximum core flow runout capability. The maximum runout flow is dependent on the existing setting of the core flow limiter in the Recirculation Flow Control System.

Based on analyses of limiting plant transients (other than core flow increases) over a range of power and flow conditions, power dependent multipliers, LHGRFACp. also are generated. Due to the sensitivity of the transient response to initial core flow levels at power levels below those at which turbine stop valve closure and turbine control valve fast closure scram trips are bypassed, both high and low core flow LHGRFACp limits are provided for operation at power levels between 25% RTP and the previously mentioned bypass power level.

The exposure dependent LHGR limits are reduced by LHGRFACp and LHGRFACt at various operating conditions to ensure that all fuel design

) criteria are met for normal operation and AOOs. A complete discussion of the analysis code is provided in Reference 7.

For single recirculation loop operation, the LHGRFAC multiplier is limited to a maximum of 0.75 (Refs. 8 and 10). This maximum limit is due to the conservative analysis assumption of an earlier departure from nucleate boiling with one recirculation loop available, resulting in a more severe cladding heatup during a LOCA.

The LHGR satisfies Criterion 2 of the NRC Policy Statement (Ref. 9).

LCO The LHGR is a basic assumption in the fuel design analysis. The fuel has been designed to operate at rated core power with sufficient design margin to the LHGR limit calculated to cause a 1% fuel cladding plastic strain. For two recirculation loops operating, the limit is determined by multiplying the smaller of the LHGRFACf and LHGRFACp factors times the exposure dependent LHGR limits. With only one recirculation loop in operation, in conformance with the requirements of LCO 3.4.1, "Recirculation Loops Operating," the limit is determined by multiplying the exposure dependent LHGR limit by the smaller of either LHGRFACt.

LHGRFACp. and 0.75, where 0.75 has been determined by a specific single recirculation loop analysis (Refs. 8 and 10).

Cooper B 3.2-9 09/11/15

LHGR B 3.2.3

,,.-~

') BASES APPLICABILITY The LHGR limits are derived from fuel design analysis that is limiting at high power level conditions. At core thermal power levels< 25% RTP, the reactor is operating with a substantial margin to the LHGR limits and, therefore, the Specification is only required when the reactor is operating at 2: 25% RTP.

ACTIONS If any LHGR exceeds its required limit, an assumption regarding an initial condition of the fuel design analysis is not met. Therefore, prompt action should be taken to restore the LHGR(s) to within its required limits such that the plant is operating within analyzed conditions and within the design limits of the fuel rods. 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 LHGR( s) to within its limits and is acceptable based on the low probability of a transient or LOCA occurring simultaneously with the LHGR out of specification.

If the LHGR 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 is 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 3.2.3.1 The LHGR 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 2: 25% RTP and then every 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months 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 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on both engineering judgment and recognition of the slow changes in power distribution during normal operation. The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months allowance after THERMAL POWER 2: 25% RTP is achieved is acceptable given the large inherent margin to operating limits at lower power levels.

,___)

Cooper B 3.2-10 09/11/15

LHGR B 3.2.3 BASES REFERENCES 1. NEDE-24011-P-A, "General Electric Standard Application for Reactor Fuel" version specified in COLR.

2. Current Cycle COLR.

3. NUREG-0800, Section ll.A.2(g), Revision 2, July 1981.

4. NEDC-32914P, "Maximum Extended Load Line Limit and Increased Core Flow for Cooper Nuclear Station," Revision 0, January 2000.

5. NEDC-31892P, "Extended Load Line Limit ARTS Improvement Program Analysis for Cooper Nuclear Station Cycle 14,"

Revision 1.

6. NRC approval of "Amendment 26 to GE Licensing Topical Report NEDE-24011-P-A, "GESTAR II" - Implementing Improved GE Steady-State Methods (TAC No. MA6481)," November 10, 1999.

7. NED0-24154-A, "Qualification of the One-Dimensional Core Transient Model (ODYN) for Boiling Water Reactors," August

\

1986, and NEDE-24154-P-A, Supplement 1, Volume 4,

) Revision 1, February 2000.

8. NED0-24258, "Cooper Nuclear Station Single Loop Operation,"

May 1980.

9. NRC No.93-102, "Final Policy Statement on Technical Specification Improvements," July 23, 1993.

10. NEDC-32687P, Revision 1, "Cooper Nuclear Station SAFER/GESTR-LOCA Loss-of-Coolant Accident Analysis,"

March 1997.

Cooper B 3.2-11 09/11/15

ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued) the next surveillance, then the channel is OPERABLE and can be restored to service at the completion of the surveillance. After the surveillance is completed, the channel as-found condition will be entered into the Corrective Action Program for further evaluation.

For most abnormal operational transients and Design Basis Accidents (DBAs ), a wide range of dependent and independent parameters are monitored.

The ECCS instrumentation actuates core spray (CS), low pressure coolant injection (LPCI), containment spray, high pressure coolant injection (HPCI), Automatic Depressurization System (ADS), and the diesel generators (DGs). The equipment involved with each of these systems is described in the Bases for LCO 3.5.1, "EGGS-Operating" and

,LCO 3.6.1.9, "RHR Containment Spray."

Core Spray System The CS System may be initiated by either automatic or manual means.

) Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low Low (Level 1) or Drywell Pressure-High. Each of these diverse variables is monitored by four redundant switches, which are connected to relays which send signals to two trip systems, with each trip system arranged in a one-out-of-two taken twice logic. Each trip system initiates one of the two CS pumps.

Upon receipt of an initiation signal, if normal AC power is available, both CS pumps start after an approximate 10 second time delay. If a core spray initiation signal is received when normal AC power is not available, the CS pumps start approximately 10 seconds after the bus is energized by the DGs.

The CS test line isolation valve, which is also a primary containment isolation valve (PCIV), is closed on a CS initiation signal to allow full system flow assumed in the accident analyses and maintain primary containment isolated in the event CS is not operating.

The CS pump discharge flow is monitored by a flow transmitter and trip unit. When the pump is running and discharge flow is low enough .so that pump overheating may occur, the minimum flow return line valve is opened. The valve is automatically closed if flow is above the minimum flow setpoint. It is not necessary for the minimum flow valve to close to achieve adequate system flow assumed in the accident analysis (Ref. 2) .

. _)

Cooper . B 3.3-89 02/22/16

ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued)

The LPCI System monitors the pressure in the reactor to ensure that, before an injection valve opens, the reactor pressure has fallen to a value below the LPCI System's maximum design pressure. The variable is monitored by four redundant pressure switches, which are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic. Additionally, instruments are provided to close the recirculation pump discharge valves to ensure that LPCI flow does not bypass the core when it injects into the recirculation lines. The variable is monitored by four redundant pressure switches, which are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic.

Low reactor water level in the shroud is detected by two additional instruments. When level is greater than the low level setpoint, LPCI may no longer be required, therefore other modes of RHR (e.g., suppression pool cooling) are allowed. Manual overrides for the isolations below the low level setpoint are provided.

Containment high pressure is detected by four instruments to preclude inadvertent diversion of LPCI flow unless containment overpressurization is indicated. This variable is monitored by four pressure switches, whose contacts provide input to two trip systems. The outputs of the contacts are arranged in a one-out-of-two taken twice logic for each trip system.

Each trip system provides an input to the associated subsystem's containment spray valves. The four instruments also provide an isolation of the containment spray mode of RHR on decreasing containment pressure following manual actuation of the system. This isolation function is not credited in accident analysis for mitigating excessive depressurization of the containment, therefore is not a TS function.

High Pressure Coolant Injection System The HPCI System may be initiated by either automatic or manual means.

Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low (Level 2) or Drywell Pressure-High. Each of these variables is monitored by four redundant switches, which are connected to relays whose contacts are arranged in a one-out-of-two taken twice logic for each Function.

The HPCI pump discharge flow is monitored by a flow switch (only one trip system). When the pump is running and discharge flow is low enough so that pump overheating may occur, the minimum flow return line valve is opened. The valve is automatically closed if flow is above the minimum flow setpoint. It is not necessary for the minimum flow valve to close to

) achieve adequate system flow assumed in the accident analysis (Ref. 4).

~.J Cooper B 3.3-91 02/22/16

ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued)

The HPCI test line isolation valves are closed upon receipt of a HPCI initiation signal to allow the full system flow assumed in the accident analysis.

The HPCI System also monitors the water levels in the emergency condensate storage tanks (ECSTs) and the suppression pool because these are the two sources of water for HPCI operation. Reactor grade water in the ECSTs is the normal source. The ECST suction source consists of two ECSTs connected in parallel to the HPC! pump suction.

Upon receipt of a HPCi initiation signal, the ECST suction valve is automatically signaled to open (it is normally in the open position) unless the suppression pool suction valve is open. if the water level in the ECSTs falls below a preselected level, first the suppression pool suction valve automatically opens, and then the ECST suction valve automatically closes. Two level switches are used to detect low water level in the ECST. Either switch can cause the suppression pool suction valve to open and the ECST suction valve to close. The suppression pool suction valve also automatically opens and the ECST suction valve closes if high water level is detected in the suppression pool. Two level switches monitor the suppression pool water level. To prevent losing suction to the pump, the suction valves are interlocked so that one suction path must be full open before the other automatically closes.

The HPCI provides makeup water to the reactor until the reactor vessel water level reaches the Reactor Vessel Water Level-High (Level 8) setting, at which time the HPCI turbine trips, which causes the turbine's stop valve to close. The logic is two-out-of-two to provide high reliability of the HPCI System (only one trip system). The HPCI System automatically restarts if a Reactor Vessel Water Level-Low Low (Level 2) signal is subsequently received.

Automatic Depressurization System The ADS is initiated by automatic means. Automatic initiation occurs when signals indicating Reactor Vessel Water Level-Low Low Low (Level 1 ); confirmed Reactor Vessel Water Level-Low (Level 3); and CS or LPCI Pump Discharge Pressure-High are all present and the ADS Initiation Timer has timed out There are two level switches each for Reactor Vessel Water Level-Low Low Low (Level 1), and one level switch for confirmed Reactor Vessel Water Level-Low (Level 3) in each of the two ADS trip systems. Each of these switches connects to a relay whose contacts form the initiation logic.

Cooper B 3.3-92 02122116 I

ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued)

Each ADS trip system includes a time delay between satisfying the initiation logic and the actuation of the ADS valves. The ADS Initiation Timer time delay setpoint chosen is long enough that the HPCI has sufficient operating time to recover to a level above Level 1, yet not so long that the LPCI and CS Systems are unable to adequately cool the fuel if the HPCI fails to maintain that level. An alarm in the control room is annunciated when either of the timers is timing. Resetting the ADS initiation signals resets the ADS Initiation Timers.

The ADS also monitors the discharge pressures of the four LPCI pumps and the two CS pumps. Each ADS trip system includes two discharge pressure permissive switches from one CS and from two LPCI pumps in the associated Division (i.e., Division 1 CS subsystem A and LPCI subsystems A and C input to ADS trip system A, and Division 2 CS subsystem B and LPCI subsystems B and D input to ADS trip system B).

The signals are used as a permissive for ADS actuation, indicating that there is a source of core coolant available once the ADS has depressurized the vessel. Any one of the six low pressure pumps is sufficient to permit automatic depressurization. The switches associated with one ADS trip system also provide signals to the other ADS trip system, but these signals are not required for the other ADS trip system to be considered OPERABLE.

The ADS logic in each trip system is arranged in two strings. Each string has a contact from Reactor Vessel Water Level-Low Low Low (Level 1).

One of the two strings in each trip system must have a confirmed Reactor Vessel Water Level-Low (Level 3). The ADS initiation timer must time out and a CS or LPCI pump discharge pressure signal mµst also be present to initiate an ADS trip system. Either the A or B trip system will cause all the ADS relief valves to open .. Once the ADS Low Water Level Actuation Timer or the ADS initiation signal is present, it is individually sealed in until manually reset.

Manual inhibit switches are provided in the control room for the ADS; however, their function is not required for ADS OPERABILITY (provided ADS is not inhibited when required to be OPERABLE).

Diesel Generators The DGs may be initiated by either automatic or manual means.

Automatic initiation occurs for conditions of Reactor Vessel Water Level-Low Low Low (Level 1) or Drywell Pressure-High. Each of these diverse variables is monitored by four redundant switches, which are connected to relays whose contacts are connected to a one-out-of-two taken twice logic to initiate both DGs (DG-1 and DG-2). The DGs are also initiated upon loss of voltage signals. (Refer to the Bases for LCO 3.3.8.1, "Loss Cooper B 3.3-93 02/22/16

ECCS Instrumentation B 3.3.5.1 BASES BACKGROUND (continued) of Power (LOP) Instrumentation," for a discussion of these signals.) The DGs receive their initiation signals from the CS System initiation logic.

The DGs can also be started manually from the control room and locally from the associated DG room. The DG initiation signal is a sealed in signal and must be manually reset. The DG initiation logic is reset by resetting the associated ECCS initiation logic. Upon receipt of a loss of coolant accident (LOCA) initiation signal, each DG is automatically started, is ready to load in approximately 14 seconds, and will run in standby conditions (rated voltage and speed, with the DG output breaker open). The DGs will only energize their respective Engineered Safety Feature buses if a loss of offsite power occurs. (Refer to Bases for LCO 3.3.8.1.)

APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY The actions of the ECCS are explicitly assumed in the safety analyses of References 6, 7, and 8. The ECCS is initiated to preserve the integrity of the fuel cladding by limiting the post LOCA peak cladding temperature to less than the 10 CFR 50.46 limits.

ECCS instrumentation satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref.

5). Certain instrumentation Functions are retained for other reasons and are described below in the individual Functions discussion.

Permissive and interlock setpoints allow the blocking of trips during plant startups, and restoration of trips when the permissive conditions are not satisfied, but they are not explicitly modeled in the Safety Analysis.

These permissives and interlocks ensure that the starting conditions are consistent with the safety analysis, before preventive or mitigating actions occur. Because these permissives or interlocks are only one of multiple conservative starting assumptions for the accident analysis, they are .

generally considered as nominal values without regard to measurement accuracy.

The OPERABILITY of the ECCS instrumentation is dependent upon the OPERABILITY of the individual instrumentation channel Functions specified in Table 3.3.5.1-1. Each Function must have a required number of OPERABLE channels, with their setpoints set within the setting tolerance of the specified LTSPs, where appropriate. The actual setpoint is calibrated consistent with applicable setpoint methodology assumptions. Table 3.3.5.1-1 contains several footnotes. Footnote (a) clarifies that the associated functions are required to be OPERABLE in MODES 4 and 5 only when their supported ECCS are required to be OPERABLE per LCO 3.5.2, ECCS-Shutdown. Footnote (b), is added to show that certain ECCS instrumentation Functions also perform DG initiation.

Cooper B 3.3-94 02/22/16

ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued)

Allowable Values are specified for each ECCS Function specified in Table 3.3.5.1-1. LTSPs and the methodologies for calculation of the as-found and as-left tolerances are described in the Technical Requirements Manual. The LTSPs are selected to ensure that the setpqints remain conservative with respect to the as-found tolerance band between CHANNEL CALIBRATIONS. After each calibration the trip setpoint shall be left within the as-left band around the LTSP. LTSPs are those predetermined values of output at which an action should take place. The setpoints are compared to the actual process parameter (e.g., reactor vessel water level), and when the measured output value of the process parameter exceeds the setpoint, the associated device (e.g., switch) changes state. The analytical limits are derived from the limiting values of the process parameters obtained from the safety analysis or other appropriate document. The Allowable Values are derived from the analytical limits, corrected for calibration, process, and some of the instrument errors. The LTSPs are then determined, accounting for the

.remaining instrument errors (e.g., drift). The LTSPs derived in this manner provide adequate protection because instrumentation uncertainties, process effects, calibration tolerances, instrument drift, and severe environment errors (for channels that must function in harsh environments as defined by 10 CFR 50.49) are accounted for. For some Functions, the Allowable Values and the LTSPs are determined from historically accepted practice relative to the intended functions of the channels. Such is the case for the Core Spray Pump Start-Time Delay Relay and for the LPCI Pump Start-Time Delay Relay.

In general, the individual Functions are required to be OPERABLE in the MODES or other specified conditions that may require ECCS (or DG) initiation to mitigate the consequences of a design basis transient or accident.. To ensure reliable ECCS and DG function, a combination of Functions is required to provide primary and secondary initiation signals.

The specific Applicable Safety Analyses, LCO, and Applicability discussions are listed below on a Function by Function basis.

Core Spray and Low Pressure Coolant Injection Systems 1.a, 2.a. Reactor Vessel Water Level-Low Low Low (Level 1)

Low reactor pressure vessel (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. The low pressure ECCS and associated DGs are initiated at Reactor Vessel Water Level-Low Low Low (Level 1) to ensure that core spray and flooding functions are available to prevent or minimize fuel damage. The DGs are initiated from Function 1.a signals. The Reactor Vessel Water Level-Low Low Low Cooper B 3.3-95 02/22/16

ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued)

(Level 1) is one of the Functions assumed to be OPERABLE and capable of initiating the ECCS during the transients analyzed in References 6 and

8. In addition, the Reactor Vessel Water Level-Low Low Low (Level 1)

Function is directly assumed in the analysis of the recirculation line break (Ref. 7). The core cooling function of the ECCS, along with the scram action of the Reactor Protection System (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 the actual water level (variable leg) in the vessel.

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 activate and provide adequate cooling.

Four channels of Reactor Vessel Water Level-Low Low Low (Level 1)

Function are only required to be OPERABLE when the ECCS are required to be OPERABLE to ensure that no single instrument failure can

) preclude ECCS initiation. Per Footnote (a) to Table 3.3.5.1-1, this ECCS function is only required to be OPERABLE in MODES 4 and 5 whenever the associated ECCS is required to be OPERABLE per LCO 3.5.2. Refer to LCO 3.5.1 and LCO 3.5.2, "EGGS-Shutdown," for Applicability Bases for the low pressure ECCS subsystems; LCO 3.8.1, "AC Sources-Operating"; and LCO 3.8.2, "AC Sources-Shutdown,"

for Applicability Bases for the DGs.

1.b, 2.b. Drywell Pressure-High High pressure in the drywell could indicate a break in the reactor coolant pressure boundary (RCPB). The low pressure ECCS and associated DGs are initiated upon receipt of the Drywell Pressure-High Function in order to minimize the possibility of fuel damage.* The DGs are initiated from Function 1.b signals. The Drywell Pressure-High Function, along with the Reactor Water Level-Low Low Low (Level 1) Function, is directly assumed in the analysis of the recirculation line break (Ref. 8). 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.

High drywell pressure signals are initiated from four pressure switches that sense drywell pressure. The Allowable Value was selected to be as

. ____, / )

\

low as possible and be indicative of a LOCA inside primary containment.

Cooper B 3.3-96 02122116 I

ECCS Instrumentation B 3.3.5.1

---~)

BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued)

The Drywell Pressure-High Function is required to be OPERABLE when the ECCS or DG is required to be OPERABLE in conjunction with times when the primary containment is required to be OPERABLE. Thus, four channels of the CS and LPCI Drywell Pressure-High Function are required to be OPERABLE in MODES 1, 2, and 3 to ensure that no single instrument failure can preclude ECCS and DG initiation. In MODES 4 and 5, the Drywell Pressure-High Function is not required, since there is insufficient energy in the reactor to pressurize the primary containment to Drywell Pressure-High setpoint. Refer to LCO 3.5.1 for Applicability Bases for the low pressure ECCS subsystems and to LCO 3.8.1 for Applicability Bases for the DGs.

1.c. 2.c. Reactor Pressure-Low (Injection Permissive)

Low reactor pressure signals are used as permissives for the low pressure ECCS subsystems. This ensures that, prior to opening the injection valves of the low pressure ECCS subsystems, the reactor pressure has fallen to a value below these subsystems' maximum design pressure and a break in the RCPB has occurred, respectively. The

) Reactor Pressure-Low is one of the Functions assumed to be OPERABLE and capable of permitting initiation of the ECCS during the transients analyzed in References 6 and 8. In addition, the Reactor Pressure-Low Function is directly assumed in the analysis of the recirculation line break (Ref. 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.

The Reactor Pressure-Low signals are initiated from four pressure switches that sense the reactor dome pressure.

The Allowable Value is low enough to prevent overpressuring the equipment in the low pressure ECCS, but high enough to ensure that the ECCS injection prevents the fuel peak cladding temperature from exceeding the limits of 10 CFR 50.46.

Four channels of Reactor Pressure-Low Function are only required to be OPERABLE when the ECCS is required to be OPERABLE to ensure that no single instrument failure can preclude ECCS initiation. Per Footnote (a) to Table 3.3.5.1-1, this ECCS function is only required to be OPERABLE in MODES 4 and 5 whenever the associated ECCS is required to be OPERABLE per LCO 3.5.2. Refer to LCO 3.5.1 and LCO 3.5.2 for Applicability Bases for the low pressure ECCS subsystems.

Cooper B 3.3-97 02122116 I

ECCS Instrumentation B 3.3.5.1

/--, I

! BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued) are assumed to be OPERABLE in the accident analyses requiring ECCS initiation. That is, the analyses assume that the pumps will initiate when required and excess loading will not cause failure of the power sources.

There are four LPCI Pump Start-Time Delay Relays, one in each of the RHR pump start logic circuits. While each time delay relay is dedicated to a single pump start logic, a single failure of a LPCI Pump Start-Time Delay Relay could result in the failure of the two low pressure ECCS pumps, powered for the same ESF bus, to perform their intended function (e.g., as in the case where both ECCS pumps on one ESF bus start simultaneously due to an inoperable time delay relay). This still leaves four of the six low pressure ECCS pumps OPERABLE; thus, the single failure criterion is met (i.e., loss of one instrument does not preclude ECCS initiation). The Allowable Value for the LPCI Pump Start-Time Delay Relays is chosen to be long enough so that most of the starting transient of the first pump is complete before starting the second pump on the same 4.16 kV emergency bus and short enough so that ECCS operation is not degraded.

Each LPCI Pump Start-Time Delay Relay Function is required to be OPERABLE only when the associated LPCI subsystem is required to be OPERABLE. Per Footnote (a) to Table 3.3.5.1-1, this ECCS function is only required to be OPERABLE in MODES 4 and 5 whenever the associated ECCS is required to be OPERABLE per LCO 3.5.2. Refer to LCO 3.5.1 and LCO 3.5.2 for Applicability Bases for the LPCI subsystems.

2.h Containment Pressure - High The Containment Pressure - High Function serves as an interlock permissive to allow the RHR System to be manually aligned from the LPCI mode to the containment spray mode after containment pressure has exceeded the trip setting. The permissive ensures that containment pressure is elevated before the manual transfer is allowed. This ensures that LPCI is available to prevent or minimize fuel damage until such time that the operator determines that containment pressure control is needed.

The Containment Pressure - High Function is implicitly assumed in the analysis of LOCAs inside containment (Ref. 10) since the analysis assumes that containment spray is manually initiated when containment pressure is high. Containment Pressure - High signals are initiated from four pressure switches that sense drywell pressure. The four instruments also provide an isolation of the containment spray mode of RHR on decreasing containment pressure following manual actuation of the system. This isolation function is not credited in accident analysis for mitigating excessive depressurization of the containment, therefore is not a TS function.

Cooper B 3.3-101 02/22/16

ECCS Instrumentation 8 3.3.5.1 I

I BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued)

Four channels of the Containment Pressure - High Function are only required to be OPERABLE in MODES 1, 2, and 3. In MODES 4 and 5, containment spray is not assumed to be initiated.

High Pressure Coolant Injection (HPCI) System 3.a. Reactor Vessel Water Level-Low Low (Level 2)

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, the HPCI System is initiated at Level 2 to maintain level above fuel zone zero. The Reactor Vessel Water Level-Low Low (Level

2) is one of the Functions assumed to be OPERABLE and capable of initiating HPCI during the transients analyzed in References 6 and 8.

Additionally, the Reactor Vessel Water Level-Low Low (Level 2) Function associated with HPCI is directly assumed in the analysis of the recirculation line break (Ref. 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 (Level 2) 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 the actual water level (variable leg) in the vessel.

The Reactor Vessel Water Level-Low Low (Level 2) Allowable Value is high enough such that for complete loss of feedwater flow, the Reactor Core Isolation Cooling (RCIC) System flow with HPCI assumed to fail will be sufficient to avoid initiation of low pressure ECCS at Reactor Vessel Water Level-Low Low Low (Level 1).

Four channels of Reactor Vessel Water Level-Low Low (Level 2) Function are required to be OPERABLE only when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI initiation. Refer to LCO 3.5.1 for HPCI Applicability Bases.

3.b. Drywall Pressure-High High pressure in the drywall could indicate a break in the RCPB. The HPCI System is initiated upon receiptof the Drywall Pressure-High Function in order to minimize the possibility of fuel damage. While HPCI is not assumed to be OPERABLE in any OBA or transient analysis, the

) Drywall Pressure-High Function, along with the Reactor Water Level-Low

/

Low (Level 2) Function, is capable of initiating HPCI during a LOCA (Ref.

8). The core cooling function of the ECCS, along with the scram action of Cooper B 3.3-102 02/22/16

ECCS Instrumentation B 3.3.5.1 APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued) the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46.

High drywell pressure signals are initiated from four pressure switches that sense drywell pressure. The Allowable Value was selected to be as low as possible to be indicative of a LOCA inside primary containment.

Four channels of the Drywell Pressure-High Function are required to be OPERABLE when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI initiation. Refer to LCO 3.5.1 for the Applicability Bases for the HPCI System.

3.c. Reactor Vessel Water Level-High (Level 8)

High RPV water level indicates that sufficient cooling water inventory exists in the reactor vessel such that there is no danger to the fuel.

Therefore, the Level 8 signal is used to trip the HPCI turbine to prevent overflow into the main steam lines (MSLs). The Reactor Vessel Water Level-High (Level 8) Function is not assumed in the accident and transient analyses. It was retained since it is a potentially significant contributor to risk.

Reactor Vessel Water Level-High (Level 8) signals for HPCI are initiated from two level transmitters from the narrow range water level measurement instrumentation. Both Level 8 signals are required in order to trip the HPCI turbine. This ensures that no single instrument failure can preclude HPCI initiation. The Reactor Vessel Water Level-High (Level 8) Allowable Value is chosen to prevent flow from the HPCI System from overflowing into the MSLs.

Two channels of Reactor Vessel Water Level-High (Level 8) Function are required to be OPERABLE only when HPCI is required to be OPERABLE.

Refer to LCO 3:5.1 and LCO 3.5.2 for HPCI Applicability Bases.

3.d. Emergency Condensate Storage Tank Level-Low Low level in the ECSTs indicates the unavailability of an adequate supply of makeup water from this normal source. Normally the suction valves between HPCI and the ECSTs is open and, upon receiving a HPCI initiation signal, water for HPCI injection would be taken from the ECSTs.

However, if the water level in the ECSTs falls below a preselected level, first the suppression pool suction valve automatically opens, and then the

.. ) ECST suction valve automatically closes. This ensures that an adequate supply of makeup water is available to the HPCI pump. To prevent losing suction to the pump, the suction valves are interlocked so that the Cooper B 3.3-103 02/22/16

ECCS Instrumentation B 3.3.5.1

/--.,\

.I BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued) suppression pool suction valve must be full open before the ECST suction valve automatically closes. The Function is implicitly assumed in the transient analyses (which take credit for HPCI) since the analyses assume that the HPCI suction source is the suppression pool.

Emergency Condensate Storage Tank Level-Low signals are initiated from two level switches. The logic is arranged such that either level switch can cause the suppression pool suction valve to open and the ECST suction valve to close. The Emergency Condensate Storage Tank Level-Low Function Allowable Value is high enough to ensure adequate pump suction head while water is being taken from the ECSTs.

Two channels of the Emergency Condensate Storage Tank Level-Low Function are required to be OPERABLE only when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI swap to suppression pool source. Refer to LCO 3.5.1 for HPCI Applicability Bases.

3.e. Suppression Pool Water Level-High Excessively high suppression pool water could result in the loads on the suppression pool exceeding design values should there be a blowdown of the reactorvessel pressure through the safety/relief valves. Therefore, signals indicating high suppression pool water level are used to transfer the suction source of HPCI from the ECSTs to the suppression pool to eliminate the possibility of HPCI continuing to provide additional water from a source outside containment. To prevent losing suction to the pump, the suction valves are interlocked so that the suppression pool suction valve must be open before the ECST suction valve automatically closes.

This Function is implicitly assumed in the transient analyses {which take credit for HPCI) since the analyses assume that the HPCI suction source is the suppression pool.

Suppression Pool Water Level-High signals are initiated from two level switches. The logic is arranged such that either switch can cause the suppression pool suction valves to open and the ECST suction valve to close. The Allowable Value for the Suppression Pool Water Level-High Function is chosen to ensure that HPCI will be aligned for suction from the suppression pool to prevent HPCI from contributing any further increase in the suppression pool level.

Two channels of Suppression Pool Water Level-High Function are required to be OPERABLE only when HPCI is required to be OPERABLE to ensure that no single instrument failure can preclude HPCI swap to Cooper B 3.3-104 02/22/16

ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued) suppression pool source. Refer to LCO 3.5.1 for HPCI Applicability Bases.

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 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.

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.

Cooper B 3.3-105 02122116 I

ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued)

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 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 anc;j 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.

,_/

)

Cooper B 3.3-106 02122116 I

ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued) 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 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 B. 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 B3.3-107 02/22/16

ECCS Instrumentation B 3.3.5.1 BASES APPLICABLE SAFETY ANALYSIS, LCO, and APPLICABILITY (continued) pump is operating in a full flow mode and high enough to avoid any condition that results in a discharge pressure permissive when the CS and LPCI pumps are aligned for injection and the pumps are not running. The actual operating point of this function is not assumed in any transient or accident analysis. However, this function is indirectly assumed to operate (in Reference 6) to provide the ADS permissive to depressurize the RCS to allow the ECCS low pressure systems to operate.

Twelve channels of Core Spray and Low Pressure Coolant Injection Pump Discharge Pressure-High 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. Two CS channels associated with CS pump A and four LPCI channels associated with LPCI pumps A and C are required for trip system A. Two CS channels associated with CS pump B and four LPCI channels associate.d with LPCI pumps B and D are required for trip system B. Refer to LCO 3.5.1 for ADS Applicability Bases.

) ACTIONS A Note has been provided to modify the ACTIONS related to ECCS instrumentation channels. Section 1.3, Completion Times, specifies that 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 that 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 ECCS instrumentation channels provide appropriate compensatory measures for separate inoperable Condition entry for each inoperable ECCS instrumentation channel.

Required Action A.1 directs entry into the appropriate Condition referenced in Table 3.3.5.1-1. The applicable Condition referenced in the table is Function dependent. Each time a channel is discovered inoperable, Condition A is entered for that channel and provides for transfer to the appropriate subsequent Condition.

B.1. B.2, and B.3 Required Actions B.1 and B.2 are intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in redundant automatic initiation capability being lost Cooper 83.3-108 02/22/16

ECCS Instrumentation B 3.3.5.1 ACTIONS (continued) for the feature(s). Required Action 8.1 features would be those that are initiated by Functions 1.a, 1.b, 2.a, 2.b, and 2.h (e.g., low pressure ECCS). The Required Action B.2 system would be HPCI. For Required Action B.1, redundant automatic initiation capability is lost if (a) two or more Function 1.a channels are inoperable and untripped such that both trip systems lose initiation capability, (b) two or more Function 2.a channels are inoperable and untripped such that both trip systems lose initiation capability, (c) two or more Function 1.b channels are inoperable and untripped such that both trip systems lose initiation capability, (d) two or more Function 2.b channels are inoperable and untripped such that both trip systems lose initiation capability, or (e), two or more Function 2.h channels are inoperable and untripped such that both trip systems lose initiation capability. For low pressure ECCS, since each inoperable channel would have Required Action B.1 applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associated system of low pressure ECCS and DGs to be declared inoperable. However, since channels in both associated low pressure ECCS subsystems (e.g., both CS subsystems) are inoperable and untripped, and the Completion Times started concurrently for the channels in both subsystems, this results in the affected portions in the associated low pressure ECCS and DGs being concurrently declared inoperable.

For Required Action B.2, automatic initiation capability is lost if the combination of Function 3.a or Function 3.b channels that are inoperable and untripped result in the inability to energize the Function's trip relay; i.e., parallel pair logic channels are untrippable. In this situation (loss of automatic initiation capability), the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance of Required Action B.3 is not appropriate and the HPCI System must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . As noted (Note 1 to Required Action 8.1 ), Required Action 8.1 is only applicable in MODES 1, 2, and 3. In MODES 4 and 5, the specific initiation time of the low pressure ECCS is not assumed and the probability of a LOCA is lower. Thus, a total loss of initiation capability for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (as allowed by Required Action 8.3) is allowed during MODES 4 and 5. There is no similar Note provided for Required Action B.2 since HPCI instrumentation is not required in MODES 4 and 5; thus, a Note is not necessary.

Notes are also provided (Note 2 to Required Action 8.1 and the Note to Required Action 8.2) to delineate which Required Action is applicable for each Function that requires entry into Condition 8 if an associated channel is inoperable. This ensures that the proper loss of initiation capability check is performed. Required Action B.1 (the Required Action

~ for certain inoperable channels in the low pressure ECCS subsystems) is not applicable to Function 2.e, since this Function provides backup to administrative controls ensuring that operators do not divert LPCI flow from injecting into the core when needed. Thus, a total loss of Function Cooper B 3.3-109 02/22/16

ECCS Instrumentation B 3.3.5.1

\

J BASES ACTIONS (continued) 2.e capability for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months is allowed, since the LPCI subsystems remain capable of performing their intended function.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action B.1, the Completion Time only begins upon discovery that a redundant feature in the same system (e.g., both CS subsystems) cannot be automatically initiated due to inoperable, untripped channels within the same Function as described in the paragraph above. For Required Action B.2, the Completion Time only begins upon discovery that the HPCI System cannot be automatically initiated due to two inoperable, untripped channels for the associated Function in the same trip system. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months has been shown to be acceptable (Ref. 9) to permit

) restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action B.3. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.

Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition H must be entered and its Required Action taken.

C.1 and C.2 Required Action C.1 is intended to ensure that appropriate actions are taken if multiple, inoperable channels within the same Function result in redundant automatic initiation capability being lost for the feature(s).

Required Action C.1 features would be those that are initiated by Functions 1.c, 1.e, 2.c, 2.d, and 2.f (i.e., low pressure ECCS). Redundant automatic initiation capability is lost if either (a) two Function 1.c channels are inoperable such that both trip systems lose initiation capability, (b) two Function 1.e channels are inoperable, (c) two Function 2.c channels are inoperable such that both trip systems lose initiation capability, (d) two Function 2.d channels are inoperable such that both trip systems lose initiation capability, or (e) two or more Function 2.f channels are

) inoperable. In this situation (loss of redundant automatic initiation

*.. ,.-/

capability), the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance of Required Action C.2 is not appropriate and the feature(s) associated with the inoperable channels Cooper B 3.3-110 02/22/16

ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued) must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . Since each inoperable channel would have Required Action C.1 applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected portion of the associated system to be declared inoperable. However, since channels for both low pressure ECCS subsystems are inoperable (e.g., both CS subsystems), and the Completion Times started concurrently for the channels in both subsystems, this results in the affected portions in both subsystems being concurrently declared inoperable. For Functions 1.c, 1.e, 2.d, and 2.f, the affected portions are the associated low pressure ECCS pumps. As noted (Note 1), Required Action C.1 is only applicable in MODES 1, 2, and 3. In MODES 4 and 5, the specific initiation time of the ECCS is not assumed and the probability of a LOCA is lower. Thus, a total loss of automatic initiation capability for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months (as allowed by Required Action C.2) is allowed during MODES 4 and 5.

Note 2 states that Required Action C.1 is only applicable for Functions 1.c, 1.e, 2.c, 2.d, 2.f and 2.h. Required Action C.1 is not applicable to Function 3.c (which also requires entry into this Condition if a channel in this Function is inoperable), since the loss of one channel results in a loss

, of the Function (two-out-of-two logic). This loss was considered during

}

the development of Reference 9 and considered acceptable for the 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowed by Required Action C.2.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time a1$o allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action C.1, the Completion Time only begins upon discovery that the same feature in both subsystems (e.g., both CS subsystems) cannot be automatically initiated due to inoperable channels within the same Function as described in the paragraph above. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels.

Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months has been shown to be acceptable (Ref. 9) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition H must be entered and its Required Action taken. The Required Actions do not allow placing the channel in trip since this action would either cause the initiation or it would not necessarily result in a safe state for the channel in all events.

Cooper B3.3-111 02/22/16

ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued)

D.1, D.2.1, and D.2.2 Required Action D.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within the same Function result in a complete loss of automatic component initiation capability for the HPCI System. Automatic component initiation capability is lost if two Function 3.d channels or two Function 3.e channels are inoperable and untripped. In this situation (loss of automatic suction swap), the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months allowance of Required Actions D.2.1 and D.2.2 is not appropriate and the HPCI System must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after discovery of loss of HPCI initiation capability. As noted, Required Action D.1 is only applicable if the HPCI pump suction is not aligned to the suppression pool, since, if aligned, the Function is already performed.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action D.1, the Completion Time only begins upon discovery that the HPCI System cannot be automatically aligned to the suppression pool due to two inoperable,

\

.J untripped channels in the same Function. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months has been shown to be acceptable (Ref. 9) to permit restoration of any inoperable channel to OPERABLE status. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action D.2.1 or the suction source must be aligned to the suppression pool per Required Action D.2.2. Placing the inoperable channel in trip performs the intended function of the channel (shifting the suction source to the suppression pool). Performance of either of these two Required Actions will allow operation to continue. If Required Action D.2.1 or D.2.2 is performed, measures should be taken to ensure that the HPCI System piping remains filled with water.

Alternately, if it is not desired to perform Required Actions D.2.1 and D.2.2 (e.g., as in the case where shifting the suction source could drain down the HPCI suction piping), Condition H must be entered and its Required Action taken.

E.1 and E.2 Required Action E.1 is intended to ensure that appropriate actions are taken if multiple, inoperable ch~nnels within the Core Spray and Low Cooper B3.3-112 02/22/16

ECCS Instrumentation B 3.3.5.1 ACTIONS (continued)

Pressure Coolant Injection Pump Discharge Flow-Low Bypass Functions result in redundant automatic initiation capability being lost for the feature(s). For Required Action E.1, the features would be those that are initiated by Functions 1.d and 2.g (e.g., low pressure ECCS). Redundant automatic initiation capability is lost if (a) two Function 1.d channels are inoperable or (b) two *Function 2.g channels are inoperable. Since each inoperable channel would have Required Action E.1 applied separately (refer to ACTIONS Note), each inoperable channel would only require the affected low pressure ECCS pump to be declared inoperable. However, since channels for more than one low pressure ECCS pump are inoperable, and the Completion Times started concurrently for the channels of the low pressure ECCS pumps, this results in the affected low pressure ECCS pumps being concurrently declared inoperable.

In this situation (loss of redundant automatic initiation capability), the 7 day allowance of Required Action E.2 is not appropriate and the subsystem associated with each inoperable channel must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . As noted (Note 1 to Required Action E.1 ),

Required Action E.1 is only applicable in MODES 1, 2, and 3. In MODES 4 and 5, the specific initiation time of the ECCS is not assumed and the

)

/ probability of a LOCA is lower. Thus, a total loss of initiation capability for 7 days (as allowed by Required Action E.2) is allowed during MODES 4 and 5. A Note is also provided (Note 2 to Required Action E.1) to delineate that Required Action E.1 is only applicable to low pressure ECCS Functions. Required Action E.1 is not applicable to HPCI Function 3.f since the loss of one chan.nel results in a loss of the Function (one-out-of-one logic). This loss was considered during the development of Reference 9 and considered acceptable for the 7 days allowed by Required Action E.2.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock."

For Required Action E.1, the Completion Time only begins upon discovery that a redundant feature in the same system (e.g., both CS subsystems) cannot be automatically initiated due to inoperable channels within the same Function as described in the paragraph above. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration of channels.

If the instrumentation that controls the pump minimum flow valve is

) inoperable, such that the valve will not automatically open, extended

.. __ . /

pump operation with no injection path available could lead to pump overheating and failure. If there were a failure of the instrumentation, Cooper B 3.3-113 02/22/16

ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued) such that the valve would not automatically close, a portion of the pump flow could be diverted from the reactor vessel injection path. These consequences can be averted by the operator's manual control of the valve, which would be adequate to maintain ECCS pump protection and required flow. Furthermore, other ECCS pumps would be sufficient to complete the assumed safety function if no additional single failure were to occur. The 7 day Completion Time of Required Action E.2 to restore the inoperable channel to OPERABLE status is reasonable based on the remaining capability of the associated ECCS subsystems, the redundancy available in the ECCS design, and the low probability of a OBA occurring during the allowed out of service time. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, Condition H must be entered and its Required Action taken. The Required Actions do not allow placing the channel in trip since this action would not necessarily result in a safe state for the channel in all events.

F.1 and F.2 Required Action F.1 is intended to ensure that appropriate actions are taken if multiple, inoperable, untripped channels within similar ADS trip system A and B Functions result in redundant automatic initiation capability being lost for the ADS. Redundant automatic initiation capability is lost if either (a) one Function 4.a channel and one Function 5.a channel are inoperable and untripped or (b) one Function 4.c channel and one Function 5.c channel are inoperable and untripped.

In this situation (loss of automatic initiation capability), the 96 hour0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months or 8 day allowance, as applicable, of Required Action F.2 is not appropriate and all ADS valves must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after discovery of loss of ADS initiation capability.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action F.1, the Completion Time only begins upon discovery that the ADS cannot be automatically initiated due to inoperable, untripped channels within similar ADS trip system Functions as described in the paragraph above. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 8 days has been shown to be acceptable (Ref. 9) to permit restoration Cooper B 3.3-114 02/22/16

ECCS Instrumentation B 3.3.5.1 BASES ACTIONS (continued) of any inoperable channel to OPERABLE status if both HPCI and RCIC are OPERABLE. If either HPCI or RCIC is inoperable, the time is shortened to 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months . If the status of HPCI or RCIC changes such that the Completion Time changes from 8 days to 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months , the 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months begins upon discovery of HPCI or RCIC inoperability. However, the total time for an inoperable, untripped channel cannot exceed 8 days. If the status of HPCI or RCIC changes such that the Completion Time changes from 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months to 8 days, the "time zero" for beginning the 8 day "clock" begins upon discovery of the inoperable, untripped channel. If the inoperable channel cannot be restored to OPERABLE status within the allowable out of service time, the channel must be placed in the tripped condition per Required Action F.2. Placing the inoperable channel in trip would conservatively compensate for the inoperability, restore capability to accommodate a single failure, and allow operation to continue.

Alternately, if it is not desired to place the channel in trip (e.g., as in the case where placing the inoperable channel in trip would result in an initiation), Condition H must be entered and its Required Action taken.

G.1 and G.2 Required Action G.1 is intended to ensure that appropriate actions are taken if multiple, inoperable channels within similar ADS trip system Functions result in automatic initiation capability being lost for the ADS.

Automatic initiation capability is lost if either (a) one Function 4.b channel and one Function 5.b channel are inoperable, (b) a combination of Function 4.d, 4.e, 5.d, and 5.e channels are inoperable such that channels associated with five or more low pressure ECCS pumps are inoperable. In this situation (loss of automatic initiation capability), the 96 hour0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months or 8 day allowance, as applicable, of Required Action G.2 is not appropriate, and all ADS valves must be declared inoperable within 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months after discovery of loss of ADS initiation capability.

The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." For Required Action G.1, the Completion Time only begins upon discovery that the ADS cannot be automatically initiated due to inoperable channels within similar ADS trip system Functions as described in the paragraph above: The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time from discovery of loss of initiation capability is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

Because of the diversity of sensors available to provide initiation signals and the redundancy of the ECCS design, an allowable out of service time of 8 days has been shown to be acceptable (Ref. 9) to permit restoration Cooper B3.3-115 021221rn I

ECCS Instrumentation B 3.3.5.1 SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.5.1.5 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required initiation logic and simulated automatic actuation for a specific channel. The system functional testing performed in LCO 3.5.1, LCO 3.5.2, LCO 3.8.1, and LCO 3.8.2 overlaps this Surveillance to complete testing of the assumed safety function.

The 24 month Frequency is based on the need to perform some of the surveillance procedures which satisfy this SR under the conditions that apply during a plant outage and the potential for an unplanned transient if those particular procedures were performed with the reactor at power.

Operating experience has shown that these components usually pass the Surveillance when performed at the 24 month Frequency.

REFERENCES 1. Regulatory Guide 1.105, "Setpoints for Safety-Related Instrumentation," Revision 3.

2. Amendment No. 7 to Facility License No DPR-46 for the Cooper Nuclear Station, February 6, 1975.

3. Cooper Nuclear Station Design Change 94-332, December 1994.

4. NEDC 97-023, "HPCI Minimum Flow Line Analysis."

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

6. USAR, Section V-2.4.

7. USAR, Section Vl-5.0.

8. USAR, Chapter XIV.

9. NEDC-30936-P-A, "BWR Owners' Group Technical Specification Improvement Analyses for ECCS Actuation Instrumentation, Part 2," December 1988.

10. EE 01-035, EQ Temperature Profile in Containment based on Small Steam Line Break arid DBA-LOCA Analysis.

)

--~/

Cooper B 3.3-119 02/22/16

Primary Containment Isolation Instrumentation B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Reactor Vessel Water Level-Low Low Low (Level 1) Allowable Value is chosen to be the same as the ECCS Level 1 Allowable Value (LCO 3.3.5.1) to ensure that the recirculation sample valves will isolate on a potential LOCA to prevent offsite doses from exceeding 10 CFR 50.67 limits.

This Function isolates the recirculation sample valves. It may be bypassed using a key-locked switch during accident conditions to obtain a sample for core damage assessment capability.

High Pressure Coolant Injection and Reactor Core Isolation Cooling Systems Isolation 3.a., 3.b., 4.a., 4.b. HPCI and RCIC Steam Line Flow-High and Time Delay Relays

) Steam Line Flow-High Functions are provided to detect a break of the RCIC or HPCI steam lines and initiate closure of the steam line isolation valves of the appropriate system. If the steam is allowed to continue flowing out of the break, the reactor will depressurize and the core can uncover. Therefore, the isolations are initiated on high flow to prevent or minimize core damage. The isolation action, along with the scram function of the RPS, ensures that the fuel peak cladding temperature remains below the limits of 10 CFR 50.46. Specific credit for these Functions is not assumed in any USAR accident analyses since the bounding analysis is performed for large breaks such as recirculation and MSL breaks. However, these instruments prevent the RCIC or HPCI steam line breaks from becoming bounding.

The HPCI and RCIC Steam Line Flow-High signals are initiated from differential pressure switches (two for HPCI and two for RCIC) that are connected to the system steam lines. A time delay is provided to prevent HPCI or RCIC isolation due to high flow transients during HPCI or RCIC startup with one Time Delay Relay channel associated with each Steam Line Flow-High channel. Two channels of both HPCI and RCIC Steam Line Flow-High Functions and the associated Time Delay Relays are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

Cooper B 3.3-144 07/28/15

Primary Containment Isolation Instrumentation

. B 3.3.6.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) switches that sense reactor dome pressure. Two channels of Reactor Pressure-High Function are available and are required to be OPERABLE*

to ensure that no single instrument failure can preclude the isolation function. The Function is only required to be OPERABLE in MODES 1, 2, and 3, since these are the only MODES in which the reactor can be pressurized; thus, equipment protection is needed. The Allowable Value was chosen to be low enough to protect the system equipment from overpressurization.

This Function isolates both RHR shutdown cooling pump suction valves.

6.b. Reactor Vessel Water Level-Low (Level 3)

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, isolation of some reactor vessel interfaces occurs to begin isolating the potential sources of a break. The Reactor Vessel Water Level-Low (Level 3) Function associated with RHR Shutdown Cooling System isolation is not directly assumed in safety analyses because a break of the RHR Shutdown Cooling System is bounded by breaks of the recirculation and MSL. The RHR Shutdown Cooling System isolation on Level 3 supports actions to ensure that the RPV water level does not drop below fuel zorie zero during a vessel draindown event caused by a leak (e.g., pipe break or inadvertent valve opening) in the RHR Shutdown Cooling System.

Reactor Vessel Water Level-Low (Level 3) 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 the actual water level (variable leg) in the vessel. Four channels (two channels per trip system) of the Reactor Vessel Water Level-Low (Level

. 3) Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. As noted (footnote (b) to Table 3.3.6.1-1 ), only one trip system of the Reactor Vessel Water Level-Low (Level 3) Function is required to be OPERABLE in MODES 4 and 5, provided the RHR Shutdown Cooling System integrity is maintained. System integrity is maintained provided the piping is intact and no maintenance is being performed that has the potential for draining the reactor vessel through the system.

The Reactor Vessel Water Level-Low (Level 3) Allowable Value was chosen to be the same as the RPS Reactor Vessel Water Level-Low (Level 3) Allowable Value (LCO 3.3.1.1 ), since the capability to cool the fuel may be threatened.

Cooper B 3.3-149 11/22/16

Recirculation Loops Operating B 3.4.1 BASES BACKGROUND (continued) is transferred to the coolant. As it rises, the coolant begins to boil, creating steam voids within the fuel channel that continue until the coolant exits the core. Because of reduced moderation, the steam voiding introduces negative reactivity that must be compensated for to maintain or to increase reactor power. The recirculation flow control allows operators to increase recirculation flow and sweep some qf the voids from the fuel channel, overcoming the negative reactivity void effect. Thus, the reason for having variable recirculation flow is to compensate for reactivity effects of boiling over a wide range of power generation (i.e., 55 to 100% of RTP) without having to move control rods and disturb desirable flux patterns.

Each recirculation loop is manually started from the control room. The MG set provides regulation of individual recirculation loop drive flows.

The flow in each loop is manually controlled.

APPLICABLE SAFETY ANALYSES The operation of the Reactor Recirculation System is an initial condition assumed in the design basis loss of coolant accident (LOCA) (Ref. 1).

During a LOCA caused by a recirculation loop pipe break, the intact loop is assumed to provide coolant flow during the first few seconds of the accident. The initial core flow decrease is rapid because the recirculation pump in the broken loop ceases to pump reactor coolant to the vessel almost immediately. The pump in the intact loop coasts down relatively slowly. This pump coastdown governs the core flow response for the next several seconds until the jet pump suction is uncovered (Ref. 1).

The analyses assume that both loops are operating at the same flow prior to the accident. However, the LOCA analysis was reviewed for the case with a flow mismatch between the two loops, with the pipe break assumed to be in the loop with the higher flow. While the flow coastdown and core response are potentially more severe in this assumed case (since the intact loop starts at a lower flow rate and the core response is the same as if both loops were operating at a lower flow rate), a small mismatch has been determined to be acceptable based oil engineering judgement. The recirculation system is also assumed to have sufficient flow coastdown characteristics to maintain fuel thermal margins during abnormal operational occurrences (AOOs) (Ref. 2), which are analyzed in Section XIV of the USAR.

Cooper B 3.4-2 09/11/15

Recirculation Loops Operating B 3.4.1 BASES APPLICABLE SAFETY ANALYSES (continued)

A plant specific LOCA analysis (Ref. 6) has been performed assuming only one operating recirculation loop. This analysis has demonstrated that, in the event of a LOCA caused by a pipe break in the operating recirculation loop, the Emergency Core Cooling System response will provide adequate core cooling, provided the APLHGR requirements are modified accordingly (Ref. 3 and 4).

The transient analyses of Section XIV of the USAR have also been performed for single recirculation loop operation (Ref. 3) and demonstrate sufficient flow coastdown characteristics to maintain fuel thermal margins during the abnormal operational transients analyzed provided the MCPR requirements are modified. During single recirculation loop operation, modification to the Reactor Protection System (RPS) average power range monitor (APRM) instrument Allowable Values is also required to account for the different relationships between recirculation drive flow and reactor core flow. The APLHGR and MCPR limits for single loop operation are specified in the COLR. The APRM Neutron Flux-High (Flow Biased) Allowable Value is in LCO 3.3.1.1, "Reactor Protection System (RPS) Instrumentation."

The reactor is designed such that thermal hydraulic oscillations are prevented or can be readily detected and suppressed without exceeding specified fuel design limits. To minimize the likelihood of a thermal hydraulic instability, a Stability Exclusion Region, to be avoided during normal power operation, is calculated using approved methodology.

Since the Stability Exclusion Region may change each fuel cycle, the Stability Exclusion Region is contained in the COLR. Specific directions are provided to avoid operation in this region and to immediately exit upon entry. Entries into the Stability Exclusion Region are not part of normal operation. An entry may occur as the result of an abnormal event, such as a single recirculation pump trip. In these events, operation in the Stability Exclusion Region may be needed to prevent equipment damage, but actual time spent inside the Region is minimized. Although operator action can prevent the occurrence of and protect the reactor from an instability, the APRM Neutron Flux-High (Flow Biased) scram function will suppress oscillations prior to exceeding the Safety Limit MCPR. While core-wide reactor instability is the predominate mode and regional mode oscillations are not expected to occur, the reactor is protected from regional mode oscillations through avoidance of the Stability Exclusion Region and administrative controls on reactor conditions which are primary factors affecting reactor stability.

)

Cooper B 3.4-3 09/11/15

Recirculation Loops Operating B 3.4.1

\

i BASES APPLICABLE SAFETY ANALYSES (continued)

Recirculation loops operating satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 4).

LCO Two recirculation loops are required to be in operation with their flows matched within the limits specified in SR 3.4.1.1 to ensure that during a LOCA caused by a break of the piping of one recirculation loop the assumptions of the LOCA analysis are satisfied. Alternatively, with only one recirculation loop in operation, modifications to the required APLHGR limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), MCPR limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), LHGR limits (LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)"), and APRM Neutron Flux-High (Flow Biased) setpoint (LCO 3.3.1.1) must be applied to allow continued operation consistent with the assumptions of References 3 and 4. During single recirculation loop operation, the recirculation system controls are placed in the manual flow control mode. In addition, during two loop or single loop operation, core flow as a function of core THERMAL POWER must not be in the Stability Exclusion Region of the power/flow map specified in the COLR.

APPLICABILITY In MODES 1 and 2, requirements for operation of the Reactor Coolant Recirculation System are necessary since there is considerable energy in the reactor core and the limiting design basis transients and accidents are assumed to occur.

In MODES 3, 4, and 5, the consequences of an accident or AOO are reduced and the coastdown characteristics of the recirculation loops are not important.

Cooper B 3.4-4 09/11/15

Recirculation Loops Operating B 3.4.1 BASES ACTIONS Because of thermal hydraulic stability concerns, operation of the plant is controlled by restricting core flow and power to the unrestricted region of the power/flow map specified in the COLR. If core flow as a function of core THERMAL POWER is in the Stability Exclusion Region of the power/flow map, action must be initiated immediately to restore the power/flow combination to outside the Stability Exclusion Region. The operator must either insert control rods to reduce THERMAL POWER, or increase the speed of the operating recirculation pump(s). Action must continue until the Stability Exclusion Region has been exited.

With the requirements of the LCO not met for reasons other than Condition A, the recirculation loops must be restored to operation with matched flows within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . A recirculation loop is considered not in operation when the pump in that loop is idle or when the mismatch between total jet pump flows of the two loops is greater than required limits. The loop with the lower flow must be considered not in operation.

Should a LOCA or AOO occur with one recirculation loop not in operation, the core flow coastdown and resultant core response may not be bounded by the LOCA analyses or the AOO analysis. Therefore, only a limited time is allowed to restore the inoperable loop to operating status.

In addition, following one recirculation pump operation, the discharge valve of the low speed pump may not be opened unless the speed of the faster pump is :::; 50% of its rated speed. This provides assurance that excessive vibration of the reactor vessel internals will not occur.

Alternatively, if the single loop requirements of the LCO are applied to operating limits and RPS setpoints, operation with only one recirculation loop would satisfy the requirements of the LCO and the initial conditions of the accident or AOO sequence.

The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is based on the low probability of an accident occurring during this time period, on a reasonable time to complete the Required Action, and on frequent core monitoring by operators allowing abrupt changes in core flow conditions to be quickly detected.

Cooper B 3.4-5 09/11/15

Recirculation Loops Operating B 3.4.1

- ~

\

" BASES ACTIONS (continued)

This Required Action does not require tripping the recirculation pump in the lowest flow loop when the mismatch between total jet pump flows of the two loops is greater than the required limits. However, in cases where large flow mismatches occur, low flow or reverse flow can occur in the low flow loop jet pumps, causing vibration of the jet pumps. If zero or reverse flow is detected, the condition should be alleviated by changing pump speeds to re-establish forward flow or by tripping the pump.

With any Required Action and associated Completion Time of Condition B not met, or if no recirculation loops are in operation, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . In this condition, the recirculation loops are not required to be operating because of the reduced severity of design basis accidents and the minimal dependence on the recirculation loop coastdown characteristics.

Additionally, a recirculation pump shall not be restarted while the reactor is in natural circulation flow and reactor power is greater than 1% of rated THERMAL POWER This ensures that a reactivity insertion transient in excess of the most severe coolant flow increase currently analyzed does not occur. The allowed Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is reasonable, based on operating experience, to reach MODE 3 in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS SR 3.4.1.1 This SR ensures the recirculation loops are within the allowable limits for mismatch. At low core flow (i.e.,< 70% of rated core flow), the MCPR requirements provide larger margins to the fuel cladding integrity Safety Limit such that the potential adverse effect of early boiling transition during a LOCA is reduced. A larger flow mismatch can therefore be allowed when core flow is < 70% of rated core flow. The recirculation loop flow, as used in this Surveillance, can be either the summation of the flows from all of the jet pumps associated with a single recirculation loop, or the drive flow associated with each recirculation loop.

Cooper B 3.4-6 09111115 I

Recirculation Loops Operating B 3.4.1 BASES SURVEILLANCE REQUIRMENTS (continued)

The mismatch is measured in terms of percent of rated core flow. If the flow mismatch exceeds the specified limits, the loop with the lower flow is considered inoperable. The SR is not required when both loops are not in operation since the mismatch limits are meaningless during single loop or natural circulation operation. The Surveillance must be performed within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after both loops are in operation. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is consistent with the Surveillance Frequency for jet pump OPERABILITY verification and has been shown by operating experience to be adequate to detect off normal loop flows in a timely manner.

SR 3.4.1.2 This SR ensures the core flow, *as a function of core THERMAL POWER, is within the appropriate limits to prevent uncontrolled thermal hydraulic oscillations. At low flows and high power levels the reactor exhibits increased susceptibility to thermal hydraulic instability. The power/flow map is based on the guidance provided in Reference 5. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is based on operating experience and the operator's inherent knowledge of reactor status, including significant changes in core

)

THERMAL POWER and flow.

REFERENCES 1. NEDE-24011-P-A (Revision specified in the COLR).

2. USAR, Section IV-3.6.

3. NEDE-24258, "Cooper Nuclear Station Single-Loop Operation,"

May, 1980.

4. 10 CFR 50.36(c){2)(ii).

Cooper B 3.4-7 0911111s I

Recirculation Loops Operating B 3.4.1 BASES REFERENCES (continued)

5. GENE-A 13-00395-01, "Application of the Regional Exclusion with Flow-Biased APRM Neutron Flux Scram Stability Solution (Option 1-D) to the Cooper Nuclear Station," November 1996.

6. NEDC-32687P, Revision 1, "Cooper Nuclear Station SAFER/

GESTR-LOCA Loss-of-Coolant Accident Analysis," March 1997.

Cooper B 3.4-8 09/11/15

RCS PIT Limits B 3.4.9 B 3.4 REACTOR COOLANT SYSTEM (RCS)

B 3.4.9 RCS Pressure and Temperature (PIT) Limits BASES BACKGROUND All components of the RCS are designed to withstand effects of cyclic loads due to system pressure and temperature changes. These loads are introduced by startup (heatup) and shutdown (cooldown) operations, power transients, and reactor trips. This LCO limits the pressure and temperature changes during RCS heatup and cooldown, within the design assumptions and the stress limits for cyclic operation.

The PRESSURE AND TEMPERATURE LIMITS REPORT {PTLR) contains PIT limit curves for heatup, cooldown, and inservice leakage and hydrostatic testing, criticality, and data for the maximum rate of change of reactor coolant temperature.

Each PIT limit curve defines an acceptable region for normal operation.

The usual use of the curves is operational guidance during heatup or cooldown maneuvering, when pressure and temperature indications are monitored and compared to the applicable curve to determine that operation is within the allowable region.

The PIT limit curves apply to the reactor pressure vessel, since the vessel is the component most subject to brittle failure, and is bounding over other SSCs that comprise the reactor coolant pressure boundary. The fluid temperatures of an idle recirculation loop are not representative of reactor vessel conditions and therefore the PIT limit curves do not apply to an idle recirculation loop.

The LCO establishes operating limits that provide a margin to brittle failure of the reactor vessel and piping of the reactor coolant pressure boundary (RCPB). The vessel is the component most subject to brittle failure. Therefore, the LCO limits apply mainly to the vessel.

10 CFR 50, Appendix G (Ref. 1), requires the establishment of PIT limits for material fracture toughness requirements of the RCPB materials.

Reference 1 requires an adequate margin to brittle failure during normal operation, abnormal operational transients, and system hydrostatic tests.

It mandates the use of the ASME Code, Section Ill, Appendix G (Ref. 2).

The NRC has also approved the use of alternate fracture toughness curves for establishing these limits (Ref. 10).

Cooper B 3.4-44 09/22/16

RCS PIT Limits B 3.4.9 BASES BACKGROUND (continued)

The actual shift in the RTNDT of the vessel material will be established periodically by removing and evaluating the irradiated reactor vessel material specimens, in accordance with BWRVIP-86-A (Ref. 3) and Appendix H of 10 CFR 50 (Ref. 4). The operating P!T limit curves will be adjusted, as necessary, based on the evaluation findings and the recommendations of Reference 5.

The P!T limit curves are composite curves established by superimposing limits derived from stress analyses ofthose portions of the reactor vessel and head that are the most restrictive. At any specific pressure, temperature, and temperature rate of change, one location within the reactor vessel will dictate the most restrictive limit. Across the span of the PIT limit curves, different locations are more restrictive, and, thus, the curves are composites of the most restrictive regions.

The heatup curve represents a different set of restrictions than the cooldown curve because the directions of the thermal gradients through the vessel wall are reversed. The thermal gradient reversal alters the location of the tensile stress between the outer and inner walls.

The criticality limits include the Reference 1 requirement that they be at least 40°F above the heatup curve or the cooldown curve and at least 60°F above the adjusted reference temperature of the reactor vessel material in the region that is controlling (reactor vessel flange region)

(Ref. 6).

The consequence of violating the LCO limits is that the RCS has been operated under conditions that can result in brittle failure of the reactor pressure vessel, possibly leading to a nonisolable leak or loss of coolant accident. In the event these limits are exceeded, an evaluation must be performed to determine the effect on the structural integrity of the RCPB components. ASME Code,Section XI, Appendix E (Ref. 7), provides a recommended methodology for evaluating an operating event that causes an excursion outside the limits.

APPLICABLE SAFETY ANALYSES The P!T limits are not derived from Design Basis Accident (OBA) analyses. They are prescribed during normal operation to avoid encountering pressure, temperature, and temperature rate of change conditions that might cause undetected flaws to propagate and cause nonductile failure of the reactor pressure vessel, a condition that is Cooper B 3.4-45 09122116 I

.. RCS PIT Limits B 3.4.9 BASES APPLICABLE SAFETY ANALYSES (continued) unanalyzed. Since the PIT limits are not derived from any OBA, there are no acceptance limits related to the PIT limits. Rather, the PIT limits are acceptance limits themselves since they preclude operation in an unanalyzed condition.

RCS PIT limits satisfy Criterion 2of10 CFR 50.36(c)(2)(ii) (Ref. 8).

LCO The elements of this LCO are:

a. RCS pressure and temperature (Beltline, Bottom Head, and Upper Vessel) are within limits specified in the PTLR, and heatup or cooldown rates are within limits specified in the PTLR during RCS heatup, cooldown, and inservice leak and hydrostatic testing (The Adjusted Reference Temperature (ART) beltline region must be determined from the PTLR. During RCS heatup and cooldown operation (i.e., not critical and not performing inservice leak or hydrostatic testing) verify RCS pressure and temperature are within limits specified in the PTLR. During RCS inservice leak and hydrostatic testing verify RCS pressure and temperature are

) within limits specified in the PTLR;

b. The temperature difference between the reactor vessel bottom head coolant and the reactor pressure vessel (RPV) coolant is within limits specified in the PTLR during recirculation pump startup;

c. The temperature difference between the reactor coolant in the respective recirculation loop and in the reactor vessel is within limits specified in the PTLR during recirculation pump startup;

d. RCS pressure and temperature are within the criticality limits specified in the PTLR, prior to achieving criticality; and

e. The reactor vessel flange and the head flange temperatures are within limits of the PTLR when tensioning the reactor vessel head bolting studs.

These limits define allowable operating regions and permit a large number of operating cycles while also providing a wide margin to nonductile failure .

. _)

Cooper B 3.4-46 09/22/16

RCS Prr Limits B 3.4.9 BASES ACTIONS (continued) 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 conditions in an orderly manner and without challenging plant systems.

C.1 and C.2 Operation outside the Prr limits in other than MODES 1, 2, and 3 (including defueled conditions) must be corrected so that the RCPB is returned to a condition that has been verified by stress analyses. The Required Action must be initiated without delay and continued until the limits are restored.

Besides restoring the Prr limit parameters to within limits, an evaluation is required to determine if RCS operation is allowed. This evaluation must verify that the RCPB integrity is acceptable and must be completed before approaching criticality or heating up to > 212°F. Several methods may be used, including comparison with pre-analyzed transients, new analyses, or inspection of the components. ASME Code,Section XI, Appendix E (Ref. 7), may be used to support the evaluation; however, its use is restricted to evaluation of the beltline.

Condition C is modified by a Note requiring Required Action C.2 be completed whenever the Condition is entered. The Note emphasizes the need to perform the evaluation of the effects of the excursion outside the allowable limits. Restoration alone per Required Action C.1 is insufficient because higher than analyzed stresses may have occurred and may have affected the reactor pressure vessel integrity.

SURVEILLANCE REQUIREMENTS SR 3.4.9.1 Verification that operation is within the PTLR limits is required every 30 minutes when RCS pressure and temperature conditions are undergoing planned changes. This Frequency is considered reasonable in view of the control room indication available to monitor RCS status. Also, since temperature rate of change limits are specified in hourly increments, 30 minutes permits a reasonable time for assessment and correction of minor deviations.

Cooper 8 3.4-49 09/22/16

RCS PIT Limits B 3.4.9

\

/ BASES SURVEILLANCE REQUIREMENTS (continued)

Surveillance for heatup, cooldown, or inservice leakage and hydrostatic testing may be discontinued when the criteria given in the relevant plant procedure for ending the activity are satisfied.

This SR has been modified with a Note that requires this Surveillance to be performed only during system heatup and cooldown operations and inservice leakage and hydrostatic testing. During RCS heatup and cooldown operation (i.e., not critical and not performing inservice leak or hydrostatic testing) verify RCS pressure and temperature are within limits specified in the PTLR. During RCS inservice leak and hydrostatic testing verify RCS pressure and temperature are within limits specified in the PTLR.

SR 3.4.9.2 A separate limit is used when the reactor is approaching criticality.

Consequently, the RCS pressure and temperature must be verified within the appropriate limits before withdrawing control rods that will make the reactor critical.

Performing the Surveillance within 15 minutes before control rod withdrawal for the purpose of achieving criticality provides adequate assurance that the limits will not be exceeded between the time of the Surveillance and the time of the control rod withdrawal.

SR 3.4.9.3 and SR 3.4.9.4 Differential temperatures within the specified limits ensure that thermal stresses resulting from the startup of an idle recirculation pump will not exceed design allowances. In addition, compliance with these limits ensures that the assumptions of the analysis for the startup of an idle recirculation loop (Ref. 9) are satisfied.

Cooper B 3.4-50 09/22/16

ECCS - Operating B 3.5.1 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.1 ECCS - Operating BASES BACKGROUND The ECCS is designed, in conjunction with the primary and secondary containment, to limit the release of radioactive materials to the environment following a loss of coolant accident (LOCA). The ECCS uses two independent methods (flooding and spraying) to cool the core during a LOCA. The ECCS network consists of the High Pressure Coolant Injection (HPCI) System, the Core Spray (CS) System, the low pressure coolant injection (LPCI) mode of the Residual Heat Removal (RHR) System, and the Automatic Depressurization System (ADS). The suppression pool provides the required source of water for the ECCS.

The emergency condensate storage tanks (ECSTs) are capable of providing a source of water for the HPCI System.

On receipt of an initiation signal, ECCS pumps automatically start; simultaneously, the system aligns and the pumps inject water, taken either from the ECSTs or suppression pool, into the Reactor Coolant System (RCS) as RCS pressure is overcome by the discharge pressure of the ECCS pumps. Although the system is initiated, ADS action is delayed, allowing the operator to interrupt the timed sequence if the system is not needed. The HPCI pump discharge pressure almost immediately exceeds that of the RCS, and the pump injects coolant into the vessel to cool the core. If the break is small, the HPCI System will maintain coolant inventory as well as vessel level while the RCS is still pressurized. If HPCI fails, it is backed up by ADS in combination with LPCI and CS. In this event, if the ADS timed sequence is allowed to time out, the selected safety/relief valves (SRVs) would open, depressurizing the RCS, thus allowing the LPCI and CS to overcome RCS pressure and inject coolant into the vessel. If the break is large, RCS pressure initially drops rapidly and the LPCI and CS cool the core.

Cooper B 3.5-1 10/21/15

ECCS - Shutdown B 3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.2 ECCS - Shutdown BASES BACKGROUND A description of the Core Spray (CS) System and the low pressure coolant injection (LPCI) mode of the Residual Heat Removal (RHR)

System is provided in the Bases for LCO 3.5.1, "ECCS - Operating."

APPLICABLE SAFETY ANALYSES The ECCS performance is evaluated for the entire spectrum of break sizes for a postulated loss of coolant accident (LOCA). The long term cooling analysis following a design basis LOCA (Ref. 1) demonstrates that only one low pressure ECCS spray subsystem is required, post LOCA, to provide sufficient heat removal and maintain adequate reactor vessel water level. It is reasonable to assume, based on engineering judgement, that while in MODES 4 and 5, one low pressure ECCS injection/spray subsystem can maintain adequate reactor vessel water level in the event of an inadvertant vessel draindown. To provide

1 redundancy, a minimum of two low pressure ECCS injection/spray subsystems are required to be OPERABLE in MODES 4 and 5.

The low pressure ECCS subsystems satisfy Criterion 3 of 10 CFR 50.36 (c)(2)(ii) (Ref. 2).

LCO Two low pressure ECCS injection/spray subsystems are required to be OPERABLE. The low pressure ECCS injection/spray subsystems consist of two CS subsystems and two LPCI subsystems. Each CS subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool to the reactor pressure vessel (RPV). Each LPCI subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV. Only a single LPCI pump is required per subsystem because of the larger injection capacity in relation to a CS subsystem. In MODES 4 and 5, the RHR System cross tie shutoff valve is not required to be closed. The necessary portions of the

.__ )

Cooper B 3.5-18 10/21/15

ECCS - Shutdown B 3.5.2

,--~

) BASES ACTIONS (continued)

If at least one low pressure ECCS injection/spray subsystem is not restored to OPERABLE status within the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time, 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 radioactivity 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 a dedicated 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 isolation is indicated). OPERABILITY may be verified by an administrative check, or by examining logs or other information, to determine whether the components are out of service for maintenance or other reasons. It is not necessary to perform the Surveillances needed to demonstrate the OPERABILITY of the components. If, however, any required component is inoperable, then it must be restored to OPERABLE status. In this case,

) the Surveillance may need to be performed to restore the component to OPERABLE status. Actions must continue until all required components are OPERABLE.

SURVEILLANCE REQUIREMENTS SR 3.5.2.1 The minimum water level of 12 ft 7 inches required for the suppression pool is periodically verified to ensure that the suppression pool will provide adequate net positive suction head (NPSH) for the CS System and LPCI subsystem pumps, recirculation volume, and vortex prevention.

With the suppression pool water level less than the required limit, all ECCS injection/spray subsystems are inoperable.

__ )

Cooper B 3.5-21 10/21/15

ECCS - Shutdown B 3.5.2

\ BASES SURVEILLANCE REQUIREMENTS (continued)

A verification that suppression pool water level is ~ 12 ft 7 inches ensures that the CS System and LPCI subsystems can supply suffiCient makeup water to the RPV with an excess supplementary volume to ensure adequate ECCS pump NPSH.

The 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency of these SRs was developed considering operating experience related to suppression pool water level variations and instrument drift during the applicable MODES. Furthermore, the 12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool water level condition.

SR 3.5.2.2, SR 3.5.2.4. and SR 3.5.2.5 The Bases provided for SR 3.5.1.1, SR 3.5.1.6, and SR 3.5.1.9 are applicable to SR 3.5.2.2, SR 3.5.2.4, and SR 3.5.2.5, respectively.

SR 3.5.2.3

)

Verifying the correct alignment for manual, power operated, and automatic valves in the ECCS flow paths provides assurance that the proper flow paths will exist for ECCS operation. This SR applies only to valves affecting the direct flow path. This SR excluded valves that, if mispositioned, would not affect system or subsystem OPERABILITY.

Also, 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 that receives an initiation signal is allowed to be in a nonaccident position provided the valve will automatically reposition in the proper stroke time.

This SR does not require any testing or valve manipulation; rather, it involves verification that those valves capable of potentially being mispositioned are in the correct position. This SR does not apply to valves that cannot be inadvertently misaligned, such as check valves.

The 31 day Frequency is appropriate because the valves are operated under procedural control and the probability of their being mispositioned during this time period is low.

.. )

Cooper B 3.5-22 10/21/15

EGGS - Shutdown B 3.5.2 BASES SURVEILLANCE REQUIREMENTS (continued)

In MODES 4 and 5, the RHR System may be required to operate in the shutdown cooling mode to remove decay heat and sensible heat from the reactor. Therefore, this SR is modified by a Note that allows one LPCI subsystem to be considered OPERABLE during alignment and operation for decay heat removal if capable of being manually realigned (remote or local) to the LPCI mode and not otherwise inoperable. Alignment and operation for decay heat removal includes when the required RHR pump is not operating or when the system is being realigned from or to the RHR shutdown cooling mode. Because of the low pressure and low temperature conditions in MODES 4 and 5 sufficient time will be available to manually align and initiate LPCI subsystem operation to provide core cooling prior to postulated fuel uncovery. This will ensure adequate core cooling if an inadvertent RPV draindown should occur .

.REFERENCES 1. NED0-20566A, "General Electric Company Analytical Model for Loss-of-Coolant Analysis In Accordance With 10CFR50 Appendix K," September 1986.

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

__ )

Cooper B 3.5-23 10/21/15

RHR Containment Spray B 3.6.1.9 B 3.6 CONTAINMENT SYSTEMS B 3.6.1.9 Residual Heat Removal (RHR) Containment Spray BASES BACKGROUND Following a Design Basis Accident (DBA), the RHR Containment Spray System removes heat from the drywell and suppression chamber airspace. The drywell is designed to absorb the sudden input of heat from the primary system from a DBA. The heat addition results in increased steam in the drywell, which increases primary containment temperature and pressure. Steam blowdown from a DBA can also bypass the suppression pool and end up in the suppression chamber airspace. Removal of heat from the suppression chamber and drywell so that the pressure and temperature inside primary containment remain within analyzed design limits is provided by two redundant RHR containment spray subsystems. The purpose of this LCO is to ensure that both subsystems are OPERABLE in applicable MODES.

Each of the two RHR containment spray subsystems contain two pumps, (one divisionally powered pump and one non-divisionally powered pump) and one heat exchanger, which are manually initiated and independently controlled. The two subsystems perform the containment spray function by circulating water from the suppression pool through the RHR heat exchangers and returning it to the drywell and suppression pool spray spargers. Thus, both suppression pool cooling and containment spray functions are performed when the RHR Containment Spray System is initiated. RHR service water, circulating through the tube side of the heat exchangers, exchanges heat with the suppression pool water and discharges this heat to the external heat sink. Either RHR containment spray subsystem is sufficient to condense the steam in both the drywell and the suppression chamber airspace during the postulated DBA.

APPLICABLE SAFETY ANALYSES References 1 and 2 contain the results of analyses used to predict primary containment pressure and temperature following the design basis loss of coolant accident. The analyses demonstrate that the temperature and pressure reduction capacity of the RHR Containment Spray System is adequate to maintain the primary containment conditions within design limits. The time history for primary containment pressure is calculated to demonstrate that the maximum pressure remains below the design limit.

Cooper B 3.6-51 02/22/16

RHR Containment Spray B 3.6.1.9 BASES APPLICABLE SAFETY ANALYSES (continued)

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

LCO In the event of a small break loss of coolant accident, a minimum of one RHR containment spray subsystem is required to maintain the primary containment peak temperature and pressure below the design limits (Ref.

1). To ensure that these requirements are met, two RHR containment spray subsystems must be OPERABLE. Therefore, in the event of an accident, at least one subsystem is OPERABLE assuming the worst case single active failure. An RHR containment spray subsystem is OPERABLE when the divisionally associated RHR pump, the heat exchanger, and associated piping, valves, instrumentation, and controls are OPERABLE.

APPLICABILITY In MODES 1, 2, and 3, a OBA could cause pressurization of primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining RHR containment spray subsystems OPERABLE is not required in MODE 4 or 5.

ACTIONS A.1 With one RHR containment spray subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this Condition, the remaining OPERABLE RHR containment spray subsystem is adequate to perform the primary containment temperature and pressure mitigation function. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced primary containment temperature and pressure mitigation capability. The 7 day Completion Time was chosen in light of the redundant RHR containment spray capabilities afforded by the OPERABLE subsystem and the low probability of a OBA occurring during this period.

Cooper B 3.6-52 02/22/16

RHR Containment Spray B 3.6.1.9 ACTIONS (continued)

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 conditions 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.

The Frequency of 31 days is justified because the valves are operated under procedural control, improper valve position would affect only a single subsystem, the probability of an event requiring initiation of the

) system is low, and the subsystem is a manually initiated system. This Frequency has been shown to be acceptable based on operating experience.

Cooper B 3.6-53 02/22/16

RHR Containment Spray B 3.6.1.9 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.1.9.2 Verifying each required RHR pump develops a flow rate > 7700 gpm while operating in the suppression pool cooling mode with flow through the associated heat exchanger ensures that pump performance has not degraded during the cycle. It is tested in the pool cooling mode to demonstrate pump OPERABILITY without spraying down equipment in the drywall. Flow is a normal test of centrifugal pump performance required by the ASME Code,Section XI (Ref. 4). This test confirms one point on the pump performance curve and is indicative of overall performance. Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this SR is in accordance with the

lriservice Testing Program.

SR 3.6.1.9.3 This Surveillance is performed following maintenance which could result in nozzle blockage by introduction of air to verify that the spray nozzles are not obstructed and that flow will be provided when required. The Frequency is adequate to detect degradation in performance due to the passive nozzle design and its normally dry state and has been shown to be acceptable through operating experience.

REFERENCES 1. USAR, Chapter XIV, Section 6.3.

2. USAR, Chapter V, Section 2.

3. EE 01-035, EQ Temperature Profile in Containment based on*

Small Steam Line Break and DBA-LOCA Analysis.

4. ASME, Boiler and Pressure Vessel Code,Section XI.

Cooper B 3.6-54 02/22/16

Suppression Pool Average Temperature B 3.6.2.1

'**-,\

1 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.1 Suppression Pool Average Temperature BASES BACKGROUND The suppression chamber is a toroidal shaped, steel pressure vessel containing a volume of water called the suppression pool. The suppression pool is designed to absorb the decay heat and sensible energy released during a reactor blowdown from safety/relief valve

discharges or from Design Basis Accidents (DBAs). The suppression pool must quench all the steam released through the downcomer lines during a loss of coolant accident (LOCA). This is the essential mitigative feature of a pressure suppression containment that ensures that the peak containment pressure is maintained below the maximum allowable pressure for DBAs (62 psig). The suppression pool must also condense steam from steam exhaust lines in the turbine driven systems (i.e., the High Pressure Coolant Injection System and Reactor Core Isolation Cooling System). Suppression pool average temperature (along with LCO 3.6.2.2, "Suppression Pool Water Level") is a key indication of the capacity of the suppression pool to fulfill these requirements.

The technical concerns that lead to the development of suppression pool average temperature limits are as follows:

a. Complete steam condensation;

b. Primary containment peak pressure and temperature;

c. Condensation oscillation loads; and

d. Chugging loads.

APPLICABLE SAFETY ANALYSES The postulated DBA against which the primary containment performance is evaluated is the entire spectrum of postulated pipe breaks within the primary containment. Inputs to the safety analyses include initial suppression pool water volume and suppression pool temperature (References 1 and 2). An initial pool temperature of 95°F is assumed for the Reference 1 and Reference 2 analyses. Reactor shutdown at a pool temperature of 110°F and vessel depressurization at a pool temperature of 120°F are assumed for the Reference 3 and 4 analyses. The limit of 105°F, at which testing is terminated, is not used in the safety analyses because DBAs are assumed to not initiate during unit testing.

Cooper B 3.6-55 02122116 I

Suppression Pool Average Temperature B 3.6.2.1 BASES APPLICABLE SAFETY ANALYSES (continued)

Suppression pool average temperature satisfies Criteria 2 and 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 5).

LCO A limitation on the suppression pool average temperature is required to provide assurance that the containment conditions assumed for the safety analyses are met. This limitation subsequently ensures that peak primary containment pressures and temperatures do not exceed maximum allowable values during a postulated OBA or any transient resulting in heatup of the suppression pool. The LCO requirements are:

a. Average temperature ::;; 95°F when THERMAL POWER is > 1%

RTP and no testing that adds heat to the suppression pool is being performed. This requirement ensures that licensing bases initial conditions are met.

b. Average temperature ::;; 105°F when THERMAL POWER is > 1%

RTP and testing that adds heat to the suppression pool is being performed. This required value ensures that the unit has testing flexibility, and was selected to provide margin below the 110°F limit at which reactor shutdown is required. When testing ends, temperature must be restored to ::;; 95°F within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months according to Required Action A.2. Therefore, the time period that the temperature is> 95°F is short enough not to cause a significant increase in unit risk.

c. Average temperature ::;; 110°F when THERMAL POWER is ::;; 1%

RTP. This requirement ensures that the unit will be shut down at

> 110°F. The pool is designed to absorb decay heat and sensible heat but could be heated beyond design limits by the steam generated if the reactor is not shut down.

Note that 12.5/40 divisions of full scale on IRM Range 7 is a convenient measure of when the reactor is producing power essentially equivalent to 1% RTP. At this power level, heat input is approximately equal to normc:ll system heat losses.

APPLICABILITY In MODES 1, 2, and 3, a OBA could cause significant heatup of the suppression pool. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining suppression pool average temperature within limits is not required in MODE 4 or 5.

)

Cooper B 3.6-56 02122116 I

Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS A.1 and A.2 With the suppression pool average temperature above the specified limit when not performing testing that adds heat to the suppression pool and when above the specified power indication, the initial conditions exceed the conditions assumed for the Reference 1, 2, 3, and 4 analyses.

However, primary containment cooling capability still exists, and the primary containment pressure suppression function will occur at temperatures well above those assumed for safety analyses. Therefore, continued operation is allowed for a limited time. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is adequate to allow the suppression pool average temperature to be restored below the limit. Additionally, when suppression pool temperature is > 95°F, increased monitoring of the suppression pool temperature is required to ensure that it remains s 110°F. The once per hour Completion Time is adequate based on past experience, which has shown that pool temperature increases relatively slowly except when testing that adds heat to the suppression pool is being performed.

Furthermore, the once per hour Completion Time is considered adequate in view of other indications in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

If the suppression pool average temperature cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, THERMAL POWER must be reduced to s 1% RTP within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months . 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 reduce power from full power conditions in an orderly manner and without challenging plant systems.

Suppression pool average temperature is allowed to be> 95°F when THERMAL POWER> 1% RTP, and when testing that adds heat to the suppression pool is being performed. However, if temperature is > 105°F, all testing must be immediately suspended to preserve the heat absorption capability of the suppression pool. With the testing suspended, Condition A is entered and the Required Actions and associated Completion Times are applicable.

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Cooper B 3.6-57 02122116 I

Suppression Pool Average Temperature B 3.6.2.1 BASES ACTIONS (continued)

D.1. D.2, and D.3 Suppression pool average temperature > 110°F requires that the reactor be shut down immediately. This is accomplished by placing the reactor mode switch in the shutdown position. Further cooldown to Mode 4 within 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months is required at normal cooldown rates (provided pool temperature remains s 120°F). Additionally, when suppression pool temperature is

> 110°F, increased monitoring of pool temperature is required to ensure that it remains s 120°F. The once per 30 minute Completion Time is adequate, based on operating experience. Given the high suppression pool average temperature in this Condition, the monitoring Frequency is increased to twice that of Condition A. Furthermore, the 30 minute Completion Time is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

E.1 and E.2 If suppression pool average temperature cannot be maintained at

)

s 120°F, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the reactor pressure must be reduced to

< 200 psig within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months , and the plant must be brought to at least 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 conditions in an orderly manner and without challenging plant systems.

Continued addition of heat to the suppression pool with suppression pool temperature > 120°F could result in exceeding the design basis maximum allowable values for primary containment temperature or pressure.

Furthermore, if a blowdown were to occur when the temperature was

> 120°F, the maximum allowable bulk temperature could be exceeded very quickly.

SURVEILLANCE REQUIREMENTS SR 3.6.2.1.1 The suppression pool average temperature is regularly monitored to ensure that the required limits are satisfied. The average temperature is determined by taking an arithmetic average of OPERABLE suppression pool water temperature channels. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency has been shown, based on operating experience, to be acceptable. When heat is Cooper B 3.6-58 02122116 I

Suppression Pool Average Temperature B 3.6.2.1

.~--.._

, ') BASES SURVEILLANCE REQUIREMENTS (continued) being added to the suppression pool by testing, however, it is necessary to monitor suppression pool temperature more frequently. The 5 minute Frequency during testing is justified by the rates at which tests will heat up the suppression pool, has been shown to be acceptable based on operating experience, and provides assurance that allowable pool temperatures are not exceeqed. The Frequencies are further justified in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool average temperature condition.

REFERENCES 1. USAR, Section V-2.

2. USAR, Section XIV-6.

3. USAR, Section XIV-5.

4. NEDC 94-0340.

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

Cooper B 3.6-59 02122116 I

Suppression Pool Water Level B 3.6.2.2 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.2 Suppression Pool Water Level BASES BACKGROUND The suppression chamber is a toroidal shaped, steel pressure vessel containing a volume of water called the suppression pool. The suppression pool is designed to absorb the energy associated with decay heat and sensible heat released during a reactor blowdown from safety/relief valve (SRV) discharges or from a Design Basis Accident (OBA). The suppression pool must quench all the steam released through the downcomer lines during a loss of coolant accident (LOCA).

This is the essential mitigative feature of a pressure suppression containment, which ensures that the peak containment pressure is maintained below the maximum allowable pressure for DBAs (62 psig).

The suppression pool must also condense steam from the steam exhaust lines in the turbine driven systems (i.e., High Pressure Coolant Injection (HPCI) System and Reactor Core Isolation Cooling (RCIC) System) and provides the main emergency water supply source for the reactor vessel.

The suppression pool volume ranges between 87,650 ft3 at the low water level limit of 12 ft 7 inches and 91, 100 ft3 at the high water level limit of 12 ft 11 inches.

If the suppression pool water level is too low, an insufficient amount of water would be available to adequately condense the steam from the SRV quenchers, drywell vents, or HPCI and RCIC turbine exhaust lines .

Low suppression pool water level could also result in an inadequate emergency makeup water source to the Emergency Core Cooling System. The lower volume would also absorb less steam energy before heating up excessively. Therefore, a minimum suppression pool water level is specified.

If the suppression pool water level is too high, it could result in excessive, clearing loads from SRV discharges and excessive pool swell loads during a OBA LOCA. Therefore, a maximum pool water level is specified.

This LCO specifies an acceptable range to prevent the suppression pool water level from being either too high or too low.

APPLICABLE SAFETY ANALYSES Initial suppression pool water level affects suppression pool temperature response calculations, calculated drywell pressure during vent clearing for a OBA, calculated pool swell loads for a OBA LOCA, and calculated loads due to SRV discharges. Suppression pool water level must be maintained within the limits specified so that the safety analysis of Reference 1 remains valid.

Cooper B 3.6-60 02122116 I

Suppression Pool Water Level B 3.6.2.2 BASES APPLICABLE SAFETY ANALYSES (continued)

Suppression pool water level satisfies Criteria 2 and 3 of 10 CFR 50.36 (c)(2)(ii) (Ref. 2).

LCO A limit that suppression pool water level be ~ 12 ft 7 inches and :::;; 12 ft 11 inches is required to ensure that the primary containment conditions assumed for the safety analyses are met. These limits equate to narrow range level instrument readings of -2" and +2", respectively. Either the high or low water level limits were used in the safety analyses, depending upon which is more conservative for a particular calculation.

APPLICABILITY In MODES 1, 2, and 3, a OBA would cause significant loads on the primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. The requirement for maintaining suppression pool water level within limits in MODE 4 or 5 is addressed in LCO 3.5.2, "EGGS-Shutdown."

ACTIONS With suppression pool water level outside the limits, the conditions assumed for the safety analyses are not met. If water level is below the minimum level, the pressure suppression function still exists as long as drywell vents are covered, HPCI and RCIC turbine exhausts are covered, and SRV quenchers are covered. If suppression pool water level is above the maximum level, protection against overpressurization still exists due to the margin in the peak containment pressure analysis and the capability of the Suppression Pool Spray System. Therefore, continued operation for a limited time is allowed. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is sufficient to restore suppression pool water level to within limits.

Also, it takes into account the low probability of an event impacting the suppression pool water level occurring during this interval.

B.1 and B.2 If suppression pool water level cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to 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 conditions in an orderly manner and without challenging plant systems.

Cooper B 3.6-61 02122116 I

Suppression Pool Water Level B 3.6.2.2 BASES SURVEILLANCE REQUIREMENTS SR 3.6.2.2.1 Verification of the suppression pool water level is to ensure that the required limits are satisfied. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency has been shown to be acceptable based on operating experience. Furthermore, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal suppression pool water level condition.

REFERENCES 1. USAR, Section V-2.

2. 10 CFR 36(c)(2)(ii).

Cooper B 3.6-62 02122116 I

RHR Suppression Pool Cooling B 3.6.2.3 B 3.6 CONTAINMENT SYSTEMS B 3.6.2.3 Residual Heat Removal (RHR) Suppression Pool Cooling BASES BACKGROUND Following a Design Basis Accident (OBA), the RHR Suppression Pool Cooling System removes heat from the suppression pool. The suppression pool is designed to absorb the sudden input of heat from the primary system. In the long term, the pool continues to absorb residual heat generated by fuel in the reactor core. Some means must be provided to remove heat from the suppression pool so that the temperature inside the primary containment remains within design limits.

This function is provided by two redundant RHR suppression pool cooling subsystems. The purpose of this LCO is to ensure that both subsystems are OPERABLE in applicable MODES.

Each RHR subsystem contains two pumps and one heat exchanger and is manually initiated and independently controlled. The two subsystems perform the suppression pool cooling function by circulating water from the suppression pool through the RHR heat exchangers and returning it to the suppression pool. RHR service water, circulating through the tube side of the heat exchangers, exchanges heat with the suppression pool

) water and discharges this heat to the ultimate heat sink.

The heat removal capability of one RHR pump in one subsystem is sufficient to meet the overall OBA pool cooling requirement for loss of coolant accidents (LOCAs) and transient events such as a turbine trip or stuck open safety/relief valve (SRV). SRV leakage, and High Pressure Coolant Injection System and Reactor Core Isolation Cooling System testing increase suppression pool temperature more slowly. The RHR Suppression Pool Cooling System is also used to lower the suppression pool water bulk temperature following such events.

APPLICABLE SAFETY ANALYSES Reference 1 contains the results of analyses used to predict primary containment pressure and temperature following large and small break LOCAs. The intent of the analyses is to demonstrate that the heat removal capacity of the RHR Suppression Pool Cooling System is adequate to maintain the primary containment conditions within design limits. The suppression pool temperature is calculated to remain below the design limit.

The RHR Suppression Pool Cooling System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 2).

Cooper B 3.6-63 02122116 I

RHR Suppression Pool Cooling B 3.6.2.3 BASES LCO During a OBA, a minimum of one RHR suppression pool cooling subsystem is required to maintain the primary containment peak pressure and temperature below design limits (Ref. 3). To ensure that these requirements are met, two RHR suppression pool cooling subsystems must be OPERABLE with power from two safety related independent power supplies. Therefore, in the event of an accident, at least one subsystem is OPERABLE assuming the worst case single active failure.

An RHR suppression pool cooling subsystem is OPERABLE when one of the pumps, the heat exchanger, and associated piping, valves, instrumentation, and controls are OPERABLE.

APPLICABILITY In MODES 1, 2, and 3, a OBA could cause a release of radioactive material to primary containment and cause a heatup and pressurization of primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, the RHR Suppression Pool Cooling System is not required to be OPERABLE in MODE4or5.

) ACTIONS A.'1 j

With one RHR suppression pool cooling subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status within 7 days. In this Condition, the remaining RHR suppression pool cooling subsystem is adequate to perform the primary containment cooling function. However, the overall reliability is reduced because a single failure in the OPERABLE subsystem could result in reduced primary containment cooling capability. The 7 day Completion Time is acceptable in light of the redundant RHR suppression pool cooling capabilities afforded by the OPERABLE subsystem and the low probability of a OBA occurring during this period.

With two RHR suppression pool cooling subsystems inoperable, 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 pressure and temperature 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 OBA and because alternative methods to remove heat from primary containment are available.

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Cooper B 3.6-64 02122116 I

RHR Suppression Pool Cooling B 3.6.2.3 BASES ACTIONS (continued)

C.1 and C.2 If any Required Action and associated Completion Time 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 to 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 conditions in an orderly manner and without challenging plant systems.

SURVEILLANCE REQUIREMENTS SR 3.6.2.3.1 Verifying the correct alignment for manual, power operated, and automatic valves in the RHR suppression pool cooling mode flow path provides assurance that the proper flow path exists 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 suppression pool 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.

The Frequency of 31 days is justified because the valves are operated under procedural control, improper valve position would affect only a single subsystem, the probability of an event requiring initiation of the system is low, and the system is a manually initiated system. This Frequency has been shown to be acceptable based on operating experience.

Cooper B 3.6-65 02122116 I

RHR Suppression Pool Cooling B 3.6.2.3 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.2.3.2 Verifying that each RHR pump develops a flow rate ;:::: 7700 gpm while operating in the suppression pool cooling mode with flow through the associated heat exchanger ensures that pump performance has not degraded during the cycle. Flow is a normal test of centrifugal pump performance required by ASME Code (Ref. 4). This test confirms one point on the pump design curve, and the results are indicative of overall performance. Such inservice inspections confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance. The Frequency of this SR is in accordance with the lnservice Testing Program.

REFERENCES 1. USAR, Section XIV-6.

2. 10 CFR 36(c)(2)(ii).

3. NEDC 94-0348, C & D

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

Cooper B 3.6-66 02122116 I

Primary Containment Oxygen Concentration B 3.6.3.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.3.1 Primary Containment Oxygen Concentration BASES BACKGROUND The primary containment is designed to withstand events that generate hydrogen either due to the zirconium metal water reaction in the core or due to radiolysis. The primary method to control hydrogen is to inert the primary containment with nitrogen gas. With the primary containment inert, that is, oxygen concentration< 4.0 volume percent (v/o), a combustible mixture cannot be present in the primary containment for any hydrogen concentration. The capability to inert the primary containment and maintain oxygen < 4.0 v/o works to mitigate events that produce hydrogen and oxygen. For example, an event that rapidly generates hydrogen from zirconium metal water reaction will result in excessive hydrogen in primary containment, but oxygen concentration will remain

< 4.0 v/o and no combustion can occur. Long term generation of both hydrogen and oxygen from radiolytic decomposition of water may be controlled by the Standby Nitrogen Injection (SBNI) System and by containment venting, if necessary. This LCO ensures that oxygen concentration does not exceed 4.0 v/o during operation in the applicable conditions.

APPLICABLE SAFETY ANALYSES The Reference 1 calculations assume that the primary containment is inerted when a Design Basis Accident loss of coolant accident occurs.

Thus, the hydrogen assumed to be released to the primary containment as a result of metal water reaction in the reactor core will not produce combustible gas mixtures in the primary containment. The assumption that primary containment is inerted when the DBA occurs also ensures peak primary containment oxygen concentration will not exceed the flammability limit.

Primary containment oxygen concentration satisfies Criterion 2 of 10 CFR 50.36(c)(2)(ii) (Ref. 2).

LCO The primary containment oxygen concentration is maintained < 4.0 v/o to ensure that an event that produces any amount of hydrogen does not result in a combustible mixture inside primary containment.

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Cooper B 3.6-67 02122116 I

Primary Containment Oxygen Concentration B 3.6.3.1 BASES APPLICABILITY The primary containment oxygen concentration must be within the specified limit when primary containment is inerted, except as allowed by the relaxations during startup and shutdown addressed below. The primary containment must be inert in MODE 1, since this is the condition with the highest probability of an event that could produce hydrogen.

lnerting the primary containment is an operational problem because it prevents containment access without an appropriate breathing apparatus.

Therefore, the primary containment is inerted as late as possible in the plant startup and de-inerted as soon as possible in the plant shutdown.

As long as reactor power is < 15% RTP, the potential for an event that generates significant hydrogen is low and the primary containment need not be inert. Furthermore, the probability of an event that generates hydrogen occurring within the first 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of a startup, or within the last 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months before a shutdown, is low enough that these "windows," when the primary containment is not inerted, are also justified. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months time period is a reasonable amount of time to allow plant personnel to perform inerting or de-inerting.

ACTIONS

) If oxygen concentration is ;;:: 4.0 v/o at any time while operating in MODE 1, with the exception of the relaxations allowed during startup and shutdown, oxygen concentration must be restored to < 4.0 v/o within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months . The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time is allowed when oxygen concentration is ;;:: 4.0 v/o because of the availability of other hydrogen mitigating systems (e.g., the SBNI System) and the low probability and long duration of an event that would generate significant amounts of hydrogen occurring during this period.

If oxygen concentration cannot be restored to within limits within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, power must be reduced to ::> 15% RTP within 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months . The 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time is reasonable, based on operating experience, to reduce reactor power from full power conditions in an orderly manner and without challenging plant systems.

Cooper B 3.6-68 02122116 I

Primary Containment Oxygen Concentration B 3.6.3.1 BASES SURVEILLANCE REQUIREMENTS SR 3.6.3.1.1 The primary containment must be determined to be inert by verifying that oxygen concentration is < 4.0 v/o. The 7 day Frequency is based on the slow rate at which oxygen concentration can change and on other indications .of abnormal conditions (which would lead to more frequent checking by operators in accordance with plant procedures). Also, this Frequency has been shown to be acceptable through operating experience.

REFERENCES 1. USAR, Section XIV-6.3.

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

Cooper . B 3.6-69 02122116 I

Secondary Containment B 3.6.4.1

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1 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.1 Secondary Containment BASES BACKGROUND The function of the secondary containment is to contain, dilute, and hold up fission products that may leak from primary containment following a Design Basis Accident (DBA) to limit fission product release to the environment. In conjunction with operation of the Standby Gas Treatment (SGT) System and closure of certain valves whose lines penetrate the secondary containment, the secondary containment is designed to reduce the activity level of the fission products released to the environment and to limit fission products that are released during certain operations that take place inside primary containment, when primary containment is not required to be OPERABLE, or that take place outside primary containment.

The secondary containment is a structure that completely encloses the primary containment and those components that may be postulated to contain primary system fluid. This structure forms a control volume that serves to hold up and dilute the fission products. It is possible for the pressure in the control volume to rise relative to the environmental pressure (e.g., due to pump and motor heat load additions). To prevent ground level exfiltration while allowing the secondary containment to be designed as a conventional structure, the secondary containment requires support systems to maintain the control volume pressure at less than the external pressure. Requirements for these systems are specified separately in LCO 3.6.4.2, "Secondary Containment Isolation Valves (SCIVs)," and LCO 3.6.4.3, "Standby Gas Treatment (SGT) System."

APPLICABLE SAFETY ANALYSIS There are two principal accidents for which credit is taken for secondary containment OPERABILITY. These are a loss of coolant accident (LOCA) (Ref. 1) and a fuel handling accident involving handling recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ) inside secondary containment (Ref. 2). The secondary containment performs no active function in response to each of these limiting events; however, its leak tightness is required to ensure

that fission products entrapped within the secondary containment structure following secondary containment isolation will be treated by the SGT System prior to discharge to the environment.

._)

Cooper B 3.6-70 02122116 I

Secondary Containment B 3.6.4.1

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1 BASES APPLICABLE SAFETY ANALYSES (continued)

Secondary containment satisfies Criterion 3of10 CFR 50.36(c)(2)(ii)

(Ref. 3).

LCO An OPERABLE secondary containment provides a control volume into which fission products that leak from primary containment, or are released from the reactor coolant pressure boundary components located in secondary containment, following secondary containment isolation can be processed prior to release to the environment. For the secondary containment to be considered OPERABLE, it must have adequate leak tightness to ensure that the required vacuum can be established and maintained.

APPLICABILITY In MODES 1, 2, and 3, a LOCA could lead to a fission product release to primary containment that leaks to secondary containment. Therefore, secondary containment OPERABILITY is required during the same operating conditions that require primary containment OPERABILITY.

In MODES 4 and 5, the probability and consequences of the LOCA are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining secondary containment OPERABLE is not required in MODE 4 or 5 to ensure a control volume, except for other situations for which significant releases of radioactive material can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs), or during movement of recently irradiated fuel assemblies in the secondary containment. Due to radioactive decay, secondary containment is only required to be OPERABLE during fuel handling involving handling recently irradiated fuel (i.e., fuel that has occupied part of critical reactor core within the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ).

ACTIONS A.1 If secondary containment is inoperable, it must be restored to OPERABLE status within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time provides a period of time to correct the problem that is commensurate with the importance of maintaining secondary containment during MODES 1, 2, and 3. This time period also ensures that the probability of an accident (requiring secondary containment OPERABILITY) occurring during periods where secondary containment is inoperable is minimal.

Cooper B 3.6-71 02/22/16

Secondary Containment B 3.6.4.1

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1 BASES ACTIONS (continued)

B.1 and B.2 If secondary containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months and to 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 conditions in an orderly manner and without challenging plant systems.

C.1 and C.2 Movement of recently irradiated fuel assemblies in the secondary

containment and OPDRVs can be postulated to cause significant fission product release to the secondary containment. In such cases, the secondary containment is the only barrier to release of fission products to the environment. Therefore, movement of recently irradiated fuel assemblies must be immediately suspended if the secondary containment is inoperable.

Suspension of these activities shall not preclude completing an action that involves moving a component to a safe position. Also, action must be immediately initiated to suspend OPDRVs to minimize the probability of a vessel draindown and subsequent potential for fission product release.

Actions must continue until OPDRVs are suspended.

Required Action C.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving recently irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving recently irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of recently irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

Cooper B 3.6-72 02/22/16 ,.

Secondary Containment B 3.6.4.1 BASES SURVEILLANCE REQUIREMENTS SR 3.6.4.1.1 This SR ensures that the secondary containment boundary is sufficiently leak tight to preclude exfiltration under expected wind conditions.

Momentary transients on installed instrumentation due to gusty wind conditions are considered acceptable and are not cause for failure to meet this SR. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency of this SR was developed based on operating experience related to secondary containment vacuum variations during the applicable MODES and the low probability of a OBA occurring between surveillances.

Furthermore, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Frequency is considered adequate in view of other indications available in the control room, including alarms, to alert the operator to an abnormal secondary containment vacuum condition.

SR 3.6.4.1.2 and SR 3.6.4.1.3 Verifying that secondary containment equipment hatches and one access door in each access opening are closed ensures that the infiltration of

)

_I outside air of such a magnitude as to prevent maintaining the desired negative pressure does not occur. Verifying that.all such openings are closed provides adequate assurance that exfiltration from the secondary containment will not occur. SR 3.6.4.1.2 also requires equipment hatches to be sealed. In this application, the term "sealed" has no connotation of leak tightness. Maintaining secondary containment OPERABILITY requires verifying one door in the access opening is closed. However, each secondary containment access door is normally kept closed, except when the access opening is being used for normal transient entry and exit or when maintenance is being performed on an access. The 31 day Frequency for these SRs has been shown to be adequate, based on operating experience, and is considered adequate in view of the other indications of door and hatch status that are available to the operator.

SR 3.6.4.1.4 The SGT System exhausts the secondary containment atmosphere to the environment through appropriate treatment equipment. SR 3.6.4.1.4 demonstrates that one SGT subsystem can maintain ~ 0.25 inches of vacuum water gauge for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months at a flow rate =::;; 1780 cfm. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months test period allows secondary containment to be in thermal equilibrium at steady state conditions. Therefore, this test is used to ensure secondary containment boundary integrity. Since this SR is a secondary

) containment test, it need not be performed with each SGT subsystem.

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Cooper B 3.6-73 02122116 I

Secondary Containment B 3.6.4.1

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) BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.4.1.4 The SGT subsystems are tested on a STAGGERED TEST BASIS, however, to ensure that in addition to the requirements of LCO 3.6.4.3, either SGT subsystem will perform this test. Operating experience has

.. shown these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. USAR, Section XIV-6.3.

2. USAR, Section XIV-6.4.

3. 10 CFR 50.36( c)(2)(ii).

I l

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Cooper B 3.6-74 02122116 I

SC IVs B 3.6.4.2

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1 B 3.6 CONTAINMENT SYSTEMS B 3.6.4.2 Secondary Containment Isolation Valves (SCIVs)

BASES BACKGROUND The function of the SC IVs, in combination with other accident mitigation systems, is to limit fission product release during and following postulated Design Basis Accidents (DBAs) (Refs. 1 and 2) .. Secondary containment isolation within the time limits specified for those isolation valves designed to close automatically ensures that fission products that leak from primary containment following a OBA, or that are released during certain .

operations when primary containment is not required to be OPERABLE or take place outside primary containment, are maintained within the secondary containment boundary.

The OPERABILITY requirements for SCIVs help ensure that an adequate secondary containment boundary is maintained during and after an accident by minimizing potential paths to the environment. These isolation devices consist of either passive devices or active (automatic) devices. Manual valves, de-activated automatic valves secured in their closed position (including check valves with flow through the valve secured), and blind flanges are considered passive devices.

Automatic SCIVs close on a secondary containment isolation signal to establish a boundary for untreated radioactive material within secondary containment following a OBA or other accidents.

Other penetrations are isolated by the use of valves in the closed position or blind flanges.

APPLICABLE SAFETY ANALYSES The SCIVs must be OPERABLE to ensure the secondary containment barrier to fission product releases is established. The principal accidents for which the secondary containment boundary is required are a loss of coolant accident (Ref. 3) and a fuel handling accident involving handling recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ) (Ref. 4). The secondary containment performs no active function in response to either of these limiting events, but the boundary established by SCIVs is required to ensure that leakage from the primary containment is processed by the Standby Gas Treatment System (SGT) System following secondary containment isolation, before being released to the environment.

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SC IVs B 3.6.4.2 BASES APPLICABLE SAFETY ANALYSES (continued)

Maintaining SCIVs OPERABLE with isolation times within limits ensures that fission products will remain trapped inside secondary containment following secondary containment isolation so that they can be treated by the SGT System prior to discharge to the environment.

SCIVs satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 5).

LCO SCIVs form a part of the secondary containment boundary. The SCIV safety function is related to control of offsite radiation releases resulting from DBAs.

The power operated automatic isolation valves are considered OPERABLE when their isolation times are within limits and the valves actuate on an automatic isolation signal. The valves covered by this LCO are listed in Reference 6.

The normally closed isolation valves or blind flanges are considered OPERABLE when manual valves are closed or open in accordance with appropriate administrative controls, automatic SCIVs are de-activated and secured in their closed position, and blind flanges are in place. These passive isolation valves or devices are listed in Reference 6.

APPLICABILITY In MODES 1, 2, and 3, a OBA could lead to a fission product release to the primary containment that leaks to the secondary containment.

Therefore, the OPERABILITY of SCIVs is required.

In MODES 4 and 5, the probability and consequences of these events are reduced due to pressure and temperature limitations in these MODES.

Therefore, maintaining SCIVs OPERABLE is not required in MODE 4 or 5, except for other situations under which significant radioactive releases can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs) or during movement of recently irradiated fuel assemblies in the secondary containment. Moving recently irradiated fuel assemblies in the secondary containment may also occur in MODES 1, 2, and 3. Due to radioactive decay, SCIVs are only required to be OPERABLE during fuel handling involving handling recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ).

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SC IVs B 3.6.4.2 BASES ACTIONS The ACTIONS are modified by three Notes. The first Note allows penetration flow paths to be unisolated intermittently under administrative controls. These controls consist of stationing a dedicated 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 isolation is indicated.

The second Note provides clarification that, for the purpose of this LCO, separate Condition entry is allowed for each penetration flow path. This is acceptable, since the Required Actions for each Condition provide appropriate compensatory actions for each inoperable SCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable SCIVs are governed by subsequent Condition entry and application of associated Required Actions.

The third Note ensures appropriate remedial actions are taken, if necessary, if the affected system(s) are rendered inoperable by an inoperable SCIV.

A.1 andA.2 In the event that there are one or more penetration flow paths with one SCIV inoperable, the affected penetration flow path(s) must be isolated.

The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure.

Isolation barriers that meet this criterion are a closed and de-activated automatic SCIV, a closed manual valve, and a blind flange. For penetrations isolated in accordance with Required Action A.1, the device used to isolate the penetration should be the closest available device to secondary containment. The Required Action must be completed within the 8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months Completion Time. The specified time period is reasonable considering the time required to isolate the penetration, and the probability of a OBA, which requires the SCIVs to close, occurring during this short time is very low.

For affected penetrations that have been isolated in accordance with Required Action A.1, the affected penetration must be verified to be isolated on a periodic basis. This is necessary to ensure that [secondary]

containment penetrations required to be isolated following an accident, but no longer capable of being automatically isolated, will be in the isolation position should an event occur. The Completion Time of once per 31 days is appropriate because the isolation devices are operated under administrative controls and the probability of their misalignment is low. This Required Action does not require any testing or device manipulation. Rather, it involves verification that the affected penetration remains isolated.

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SC IVs B 3.6.4.2 BASES ACTIONS (continued)

Required Action A.2 is modified by two Notes. Note 1 applies to devices located in high radiation areas and allows them to be verified closed by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted. Note*2 applies to isolation devices that are locked, sealed, or otherwise secured in position and allows these devices to be verified closed by use of administrative means. Allowing verification by administrative means is considered acceptable, since the function of locking, sealing, or securing components is to ensure that these devices are not inadvertently repositioned. Therefore, the probability of misalignment, once they have been verified to be in the proper position, is low.

With two SCIVs in one or more penetration flow paths inoperable, the affected penetration flow path must be isolated within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The method of isolation must include the use of at least one isolation barrier that cannot be adversely affected by a single active failure. Isolation barriers that meet this criterion are a closed and de-activated automatic valve, a closed manual valve, and a blind flange. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable considering the time required to isolate the penetration and the probability of a OBA, which requires the SCIVs to close, occurring during this short time, is very low. The Condition has been modified by a Note stating that Condition B is only applicable to penetration flow paths with two isolation valves. This clarifies that only Condition A is entered if one SCIV is inoperable in multiple penetrations.

C.1 and C.2 If any Required Action and associated Completion Time 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 to 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 conditions in an orderly manner and without challenging plant systems .

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Cooper 8 3.6-78 02122116 I.

SC IVs 8 3.6.4.2 ACTIONS (continued)

D.1. D.2, and D.3 If any Required Action and associated Completion Time are not met, the plant must be placed in a condition in which the LCO does not apply. If applicable, the movement of recently irradiated fuel assemblies in the secondary containment must be immediately suspended. Suspension of these activities shall not preclude completion of movement of a component to a safe position. Also, if applicable, actions must be immediately initiated to suspend OPDRVs in order to minimize the probability of a vessel draindown and the subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.

Required Action D.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving recently irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving fuel while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

SURVEILLANCE REQUIREMENTS SR 3.6.4.2.1 This SR verifies that each secondary containment manual isolation valve and blind flange that is not locked, sealed, or otherwise secured and is required to be closed during accident conditions is closed. The SR helps to ensure that post accident leakage of radioactive fluids or gases outside of the secondary containment boundary is within design limits. This SR does not require any testing' or valve manipulation. Rather, it involves verification that those SCIVs in secondary Gontainment that are capable of being mispositioned are in the correct position.

Since these SCIVs are readily accessible to personnel during normal operation and verification of their position is relatively easy, the 31 day Frequency was chosen to provide added assurance that the SCIVs are in the correct positions. This SR does not apply to valves and blind flanges that are locked, sealed, or otherwise secured in the closed position, since these were verified to be in the correct position upon locking, sealing, or securing.

Two Notes have been added to this SR. The first Note applies to valves and blind flanges located in high radiation areas and allows them to be

) verified by use of administrative controls. Allowing verification by administrative controls is considered acceptable, since access to these areas is typically restricted during MODES 1, 2, and 3 for ALARA Cooper 8 3.6-79 02/22/16

SC IVs B 3.6.4.2 BASES SURVEILLANCE REQUIREMENTS (continued) reasons. Therefore, the probability of misalignment of these isolation devices, once they have been verified to be in the proper position, is low. ,

A second Note has been included to clarify that SCIVs that are open under administrative controls are not required to meet the SR during the time the SCIVs are open. These controls consist of stationing a dedicated operator at the controls of the valve, who is in continuous communication with the control room. In this way, the penetration can be rapidly isolated when a need for secondary containment isolation is indicated.

SR 3.6.4.2.2 Verifying that the isolation time of each power operated automatic SCIV is within limits is required to demonstrate OPERABILITY. The isolation time test ensures that the SCIV will isolate in a time period less than or equal to that assumed in the safety analyses. The isolation time and Frequency of this SR are in accordance with the lnservice Testing Program.

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SR 3.6.4.2.3

Verifying that each automatic SCIV closes on a secondary containment isolation signal is required to minimize leakage of radioactive material from secondary containment following a DBA or other accidents. This SR ensures that each automatic SCIV will actuate to the isolation position on a secondary containment isolation signal. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage and the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating experience has shown these components usually pass the Surveillance when performed at the 24 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.

REFERENCES 1. USAR, Section V-3.0.

2. USAR, Section XIV-6.0.

) 3. USAR, Section XIV-6.3.

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SC IVs B 3.6.4.2 BASES REFERENCES (continued)

4. USAR, Section XIV-6.4

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

6. Technical Requirements Manual.

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SGT System B 3.6.4.3

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B 3.6 CONTAINMENT SYSTEMS B 3.6.4.3 Standby Gas Treatment (SGT) System BASES BACKGROUND The SGT System is described in the USAR, (Ref. 2). The function of the SGT System is to ensure that radioactive materials that leak from the primary containment into the secondary containment following a Design Basis Accident (OBA) and secondary containment isolation are filtered and adsorbed prior to exhausting to the environment.

The SGT System consists of two fully redundant subsystems, each with its own set of ductwork, dampers, charcoal filter train, and controls. Both SGT subsystems share a common inlet plenum. This inlet plenum is connected to the reactor building exhaust plenum, the primary containment, and the HPCI turbine gland seal exhauster. Both SGT subsystems exhaust to the elevated release point (ERP) tower through a common exhaust duct served by two 100% capacity system fans. Both fans automatically start on a secondary containment isolation signal.

The SGT subsystem fan suctions are cross connected by a single duct and a throttled and locked manual cross tie valve to accommodate decay heat removal from the shutdown SGT subsystem. SGT room air enters the train suction through a check valve and air operated damper, is drawn through the filter removing decay heat from the shutdown SGT subsystem, passes through the cross tie ductwork to the operating SGT subsystem fan, and is exhausted to the ERP tower.

Each charcoal filter train consists of (components listed in order of the direction of the air flow):

a.

A demister or moisture separator;

b. A rough prefilter;

c. An electric heater;

d. *A high efficiency particulate air (HEPA) filter;

e. A charcoal adsorber;

f. A second HEPA filter; and

g. A centrifugal fan.

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02122116 I

SGT System B 3.6.

4.3 BACKGROUND

(continued)

The capacity of the SGT System is sufficient to reduce and maintain the reactor building at a subatmospheric pressure of -0.25 inches water gauge (under neutral wind conditions of greater than 2 mph but less than 5 mph) with an air infiltration rate of no more than 100% of the reactor building volume per day.

The demister is provided to remove entrained water in the air, while the electric heater reduces the relative humidity of the airstream to less than 70% (Ref. 2). The prefilter removes large particulate matter, while the HEPA filter removes fine particulate matter and protects the charcoal from fouling. The charcoal adsorber removes gaseous elemental iodine and organic iodides, and the final HEPA filter collects any carbon fines exhausted from the charcoal adsorber.

The SGT System automatically starts and operates in response to actuation signals indicative of conditions or an accident that could require operation of the system. Following initiation, both charcoal filter train fans start. Upon verification that both subsystems are operating, the redundant subsystem is normally shut down.

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APPLICABLE SAFETY ANALYSES The design basis for the SGT System is to mitigate the consequences of a loss of coolant accident and fuel handling accidents involving handling recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ) (Ref. 2). For all events analyzed, the SGT System is shown to be automatically initiated to reduce, via filtration and adsorption, the radioactive material released to the environment.

The SGT System satisfies Criterion 3of10 CFR 50.36(c)(2)(ii) (Ref. 3).

LCO Following a DBA, a minimum of one SGT subsystem is required to maintain the secondary containment at a negative pressure with respect to the environment and to process gaseous releases. Meeting the LCO requirements for two OPERABLE subsystems ensures operation of at least one SGT subsystem in the event of a single active failure. An OPERABLE SGT subsystem consists of a demister, prefilter, an electric heater, HEPA filter, charcoal adsorber, a final HEPA filter, exhaust fan, and associated ductwork, dampers, valves and controls.

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SGT System B 3.6.4.3

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I BASES LCO (continued)

When the required decay heat removal flow through the cross tie damper is not met, only ONE SGT subsystem may be considered OPERABLE.

APPLICABILITY In MODES 1, 2, and 3, a OBA could lead to a fission product release to primary containment that leaks to secondary containment. Therefore, SGT System OPERABILITY is required during these MODES.

In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations in these MODES. Therefore, maintaining the SGT System in OPERABLE status is not required in MODE 4 or 5, except for other situations under which significant releases of radioactive material can be postulated, such as during operations with a potential for draining the reactor vessel (OPDRVs) or during movement of recently irradiated fuel assemblies in the secondary containment. Due to radioactive decay, the SGT System is only required to be OPERABLE during fuel handling involving handling recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ).

ACTIONS With one SGT subsystem inoperable, the inoperable subsystem must be restored to OPERABLE status in 7 days. In this Condition, the remaining OPERABLE SGT subsystem is adequate to perform the required radioactivity release control function. However, the overall system reliability is reduced because a single failure in the OPERABLE subsystem could result in the radioactivity release control function not being adequately performed. The 7 day Completion Time is based on consideration of such factors as the availability of the OPERABLE redundant SGT subsystem and the low probability of a OBA occurring during this period.

B.1 and B.2 If the SGT subsystem cannot be restored to OPERABLE status within the required Completion Time in MODE 1, 2, or 3, 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 to 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 conditions in an orderly manner and without challenging plant systems.

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SGT System B 3.6.4.3 BASES ACTIONS (continued)

C.1, C.2.1, and C.2.2 During movement of recently irradiated fuel assemblies, in the secondary containment or during OPDRVs, when Required Action A.1 cannot be

completed within the required Completion Time, the OPERABLE SGT subsystem should immediately be placed in operation. This action ensures that the remaining subsystem is OPERABLE, that no failures that could prevent automatic actuation have occurred, and that any other failure would be readily detected.

An alternative to Required Action C.1 is to immediately suspend activities that represent a potential for releasing a significant amount of radioactive material to the secondary containment, thus placing the plant in a condition that minimizes risk. If applicable, movement of recently irradiated fuel assemblies must immediately be suspended. Suspension of these activities must not preclude completion of movement of a component to a safe position. Also, if applicable, actions must immediately be initiated to suspend OPDRVs in order to minimize the probability of a vessel draindown and subsequent potential for fission product release. Actions must continue until OPDRVs are suspended.

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Required Actions of Condition C have been modified by a Note stating that LCO 3.0.3 is not applicable. If moving recently irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving recently irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown. -

If both SGTS subsystems are inoperable in MODE 1, 2, or 3, the SGT system may not be capable of supporting the required radioactivity release control function. Therefore, actions are required to enter LCO 3.0.3 immediately. *

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SGT System B 3.6.4.3 ACTIONS (continued)

E.1 and E.2 When two SGT subsystems are inoperable, if applicable, movement of recently irradiated fuel assemblies in secondary containment must immediately be suspended. Suspension of these activities shall not preclude completion of movement of a component to a safe position.

Also, if applicable, actions must immediately be initiated to suspend OPDRVs in order to minimize the probability of a vessel draindown and subsequent potential for fission product release. -Actions must continue until OPDRVs are suspended.

Required Action E.1 has been modified by a Note stating that LCO 3.0.3 is not applicable. If moving recently irradiated fuel assemblies while in MODE 4 or 5, LCO 3.0.3 would not specify any action. If moving recently irradiated fuel assemblies while in MODE 1, 2, or 3, the fuel movement is independent of reactor operations. Therefore, in either case, inability to suspend movement of recently irradiated fuel assemblies would not be a sufficient reason to require a reactor shutdown.

) SURVEILLANCE REQUIREMENTS SR 3.6.4.3.1 Operating each SGT subsystem, including each filter train fan, for;;::: 10 continuous hours ensures that both subsystems are OPERABLE and that all associated controls are functioning properly. It also ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action. Operation with the heaters on for;;::: 10 continuous hours every 31 days eliminates moisture on the adsorbers and HEPA filters. The 31 day Frequency was developed in consideration of the known reliability of fan motors and controls and the redundancy available in the system.

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SGT System B 3.6.4.3 BASES SURVEILLANCE REQUIREMENTS (continued)

SR 3.6.4.3.2 This SR verifies that the required SGT filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The VFTP includes testing HEPA filter performance, charcoal adsorber efficiency, minimum system flow rate, and the physical properties of the activated charcoal (general use and following specific operations).

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

SR 3.6.4.3.3 This SR verifies that each SGT subsystem starts on receipt of an actual or simulated initiation signal. While this Surveillance can be performed with the reactor at power, operating experience has shown that these components will pass the Surveillance when performed at the 24 month Frequency. The LOGIC SYSTEM FUNCTIONAL TEST in LCO 3.3.6.2, "Secondary Containment Isolation Instrumentation," overlaps this SR to provide complete testing of the safety function. Therefore, the Frequency

) was found to be acceptable from a reliability standpoint.

SR 3.6.4.3.4 This SR verifies that the SGT units cross tie damper is in the correct position, and that each SGT room air supply check valve and each air operated SGT dilution air shutoff valve open when required. This ensures that the decay heat removal function of SGT System operation is available. While this Surveillance can be performed with the reactor at power, operating experience has shown that these components will pass the Surveillance when performed at the 24 month Frequency, which is based on the refueling cycle. Therefore, the Frequency was found to be acceptable from a reliability standpoint.

REFERENCES 1. (Deleted)

2. USAR, Section V-3.3.4.

3. 10 CFR 50.36(c)(2){ii).

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Cooper B 3.6-87 02122116 I

REC System B 3.7.3 SURVEILLANCE REQUIREMENTS (continued) heat exchanger service water outlet valves and the REC critical loop supply valves to provide cooling water to essential components.

However, operability of the REC system is unrelated to the Group VI Isolation signal associated with the Reactor Building Ventilation Exhaust Plenum Radiation High condition, as this signal is not credited in the station safety analysis to ensure this function is accomplished under accident or transient conditions.

Operating experience has shown that these components usually pass the SR when performed at the 24 month Frequency. Therefore, this Frequency is concluded to be acceptable from a reliability standpoint.

REFERENCES 1. USAR, Section X-6.

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

3. DC 93-057

4. NEDC 92-050X and NEDC 97-087

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Cooper B 3.7-16 01/05/17

Main Turbine Bypass System B 3.7.7

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} B 3. 7 PLANT SYSTEMS B 3.7.7 Main Turbine Bypass System BASES BACKGROUND The Main Turbine Bypass System is designed to control steam pressure when reactor steam generation exceeds turbine requirements during unit startup, sudden load reduction, and cooldown. It allows excess steam flow from the reactor to the condenser without going through the turbine.

The bypass capacity of the system is 25% of the Nuclear Steam Supply System rated steam flow. Sudden load reductions within the capacity of the steam bypass can be accommodated without safety relief valves opening or a reactor scram. The Main Turbine Bypass System consists of three valves connected to the main steam lines between the main steam isolation valves and the turbine stop valves. Each of these three valves is operated by hydraulic cylinders. The bypass valves are controlled by the pressure regulation function of the Turbine Digital Electro Hydraulic (DEH) Control System, as discussed in the USAR, Section Vll-11.3 (Ref. 1). The bypass valves are normally closed, and the DEH Control System controls the turbine control valves that direct all steam flow to the turbine. If the speed governor or the load limiter restricts steam flow to the turbine, the DEH Control System controls the system pressure by opening the bypass valves. When the bypass valves open, the steam flows from the bypass chest, through connecting piping, to the pressure breakdown assemblies used to further reduce the steam pressure before the steam enters the condenser.

APPLICABLE SAFETY ANALYSES The Main Turbine Bypass System is assumed to function during the high energy line break analysis, as discussed in References 2 and 3, and the feedwater controller failure maximum demand transient, as discussed in Reference 4. However, the feedwater controller failure maximum demand transient defines the MCPR operating limits if one Main Turbine Bypass Valve is inoperable. An inoperable Main Turbine Bypass Valve may result in APLHGR, LHGR, or MCPR penalties.

The Main Turbine Bypass System satisfies Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 5).

Cooper B 3.7-31 09/11/15

Main Turbine Bypass System B 3.7.7 BASES LCO The Main Turbine Bypass System is required to be OPERABLE to limit peak pressure in the main steam lines and maintain reactor pressure within acceptable limits during events that cause rapid pressurization, so that the Safety Limit MCPR is not exceeded. With one Main Turbine Bypass Valve inoperable, modifications to the MCPR operating limits (LCO 3.2.2, "MINIMUM CRITICAL POWER RATIO (MCPR)"), the APLHGR limits (LCO 3.2.1, "AVERAGE PLANAR LINEAR HEAT GENERATION RATE (APLHGR)"), and the LHGR limits (LCO 3.2.3, "LINEAR HEAT GENERATION RATE (LHGR)") may be applied to allow this LCO to be met. The MCPR operating limits, the APLHGR limit, and LHGR limit for one inoperable Main Turbine Bypass Valve are specified in the COLR. An OPERABLE Main Turbine Bypass System requires all three bypass valves to open in response to increasing main steam line pressure. This response is within the assumptions of the applicable analyses (Ref. 4 ).

APPLICABILITY The Main Turbine Bypass System is required to be OPERABLE at;;::: 25%

RTP to ensure that the fuel cladding integrity Safety Limit and the cladding 1% plastic strain limit are not violated during the Applicable Safety Analyses transients. As discussed in the Bases for LCO 3.2.1, LCO 3.2.2, and LCO 3.2.3, sufficient margin to these limits exists at

< 25% RTP. Therefore, these requirements are only necessary when operating at or above this power level.

ACTIONS If one Main Turbine Bypass Valve is inoperable, and the APLHGR limit, LHGR limit and MCPR operating limits for one inoperable Main Turbine Bypass Valve, as specified in the COLR, are not applied, the assumptions of the design basis transient analyses may not be met. Under such circumstances, prompt action should be taken to restore the inoperable Main Turbine Bypass Valve to OPERABLE status or adjust the APLHGR limit, LHGR limit and MCPR operating limits accordingly. The 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months Completion Time is reasonable, based on the time to complete the Required Action and the low probability of an event occurring during this period requiring the Main Turbine Bypass System.

B.1 If the inoperable Main Turbine Bypass Valve cannot be restored to OPERABLE status and the APLHGR limit, LHGR limit and MCPR operating limits for one inoperable Main Turbine Bypass Valve are not applied within 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months , or two or more Main Turbine Bypass Valves are inoperable, THERMAL POWER must be reduced to < 25% RTP. As discussed in the Applicability section, operation at < 25% RTP results in Cooper B 3.7-32 09/11/15

Main Turbine Bypass System B 3.7.7

\ BASES ACTIONS (continued) sufficient margin to the required limits, and the Main Turbine Bypass System is not required to protect fuel integrity during the Applicable Safety Analyses transients. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

SURVEILLANCE REQUIREMENTS SR 3.7.7.1 Cycling each main turbine bypass valve through at least half of one cycle of full travel (50% open) demonstrates that the valves are mechanically OPERABLE and will function when required. The 31 day Frequency is based on engineering judgment, is consistent with the procedural controls governing valve operation, and ensures correct valve positions.

Operating experience has shown that these components usually pass the SR when performed at the 31 day Frequency. Therefore, the Frequency is acceptable from a reliability standpoint.

SR 3.7.7.2 The Main Turbine Bypass System is required to actuate automatically to perform its design function. This SR demonstrates that, with the required system initiation signals, the valves will actuate to their required position.

The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and because of the potential for an unplanned transient if the Surveillance were performed with the reactor at power. Operating. experience has shown the 24 month Frequency, which is based on the refueling cycle, is acceptable from a reliability standpoint.

Cycling open a bypass valve at slightly above 29.5 RTP may affect the RPS Turbine Stop and Control Valve functions.

SR 3.7.7.3 This SR ensures that the TURBINE BYPASS SYSTEM RESPONSE TIME is in compliance with the assumptions of the appropriate safety analyses. The response time limits are spedfied in the COLR. The 24 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a unit outage and because of the potential for an unplanned transient if the Surveillance were performed Cooper B 3.7-33 09111115 I

Main Turbine Bypass System B 3.7.7 BASES SURVEILLANCE REQUIREMENTS (continued) with the reactor at power. Operating experience has shown the 24 month Frequency, which is based on the refueling cycle, is acceptable from a reliability standpoint.

REFERENCES 1. USAR, Section Vll-11.3.

2. Amendment 25 to the FSAR.

3. NEDC 96-006, "Estimate of Steam Tunnel's HELB," March 3, 1996.

4. USAR, Section XIV-5.8.1.

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

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NLS2017033, Technical Specification Bases Changes

Contents

Text

Subject:

Dear Sir or Madam:

Enclosure:

4.3 BACKGROUND

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NLS2017033, Technical Specification Bases Changes

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