Text

Technical Specification Bases Changes
	ML23107A124
Person / Time
Site:	Cooper
Issue date:	04/17/2023
From:	Dewhirst L; Nebraska Public Power District (NPPD)
To:	; Office of Nuclear Reactor Regulation, Document Control Desk
References
	NLS2023007
	Download: ML23107A124 (1)
	v • d • e

Nebraska Public Power District Al.ways there when you need us NLS2023007 April 1 7, 2023 U.S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555-0001

Subject:

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

Dear Sir or Madam:

The purpose of this letter is to provide changes to the Cooper Nuclear Station (CNS) Technical Specification Bases implemented without prior Nuclear Regulatory Commission approval. In accordance with the requirements of CNS Technical Specification 5.5.1 0.d, these changes are provided on a frequency consistent with 10 CFR 50.71(e). The enclosed Bases changes are for the time period from February 23, 2021, through February 22, 2023. 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 conta me at (402) 825-5416.

/

~*

L l__.1ifida D whirst Regula ory Affairs and Compliance Manager

/bk

Enclosure:

Technical Specification Bases Changes cc:

Regional Administrator, w/enclosure USNRC - Region IV Cooper Project Manager, w/enclosure USNRC - NRR Plant Licensing Branch IV Senior Resident Inspector, w/enclosure USNRC-CNS NPG Distribution, w/o enclosure CNS Records, w/enclosure COOPER NUCLEAR STATION P.O. Box 98 / Brownville, NE 68321-0098 Telephone: (402) 825-3811 / Fax: (402) 825-5211 www.nppd.com

NLS2023007 Enclosure Page 1 of 65 TECHNICAL SPECIFICATION BASES CHANGES

FILING INSTRUCTIONS Technical Specifications Bases REMOVE INSERT List of Effective Pages List of Effective Pages (Al I 7 pages) dated 0 1/06/21 (All 7 pages) dated 0 1/18/23 Page B 3.0-9 dated 12/09/20 Page B 3.0-9 dated 03/31/21 Page B 3.0-13 dated 08/09/17 Page B 3.0-13 dated 03/31/21 Page B 3.3-68 dated 11/25/12 Paqe B 3. 3-68 dated 03/31/21 Page B 3.3-132 dated 11/08/18 Page B 3.3-132 dated 02/02/22 Page B 3.3-133 dated 09/19/18 Page B 3.3-133 dated 02/02/22 Page B 3.3-134 dated 09/19/18 Page B 3.3-134 dated 02/02/22 Page B 3.3-135 dated 09/19/18 Paqe B 3.3-135 dated 02/02/22 Page B 3.3-136 dated 09/19/18 Page B 3.3-136 dated 02/02/22 Page B 3.3-137 dated 09/19/18 Page B 3.3-137 dated 02/02/22 Page B 3.3-138 dated 02/22/19 Paqe B 3.3-138 dated 02/02/22 Page B 3.3-139 dated 02/22/19 Page B 3.3-139 dated 02/02/22 Page B 3.3-153 dated 09/19/18 Page B 3. 3-153 dated 03/31/21 Page B 3.3-154 dated 09/19/18 Page B 3.3-154 dated 03/31/21 Page B 3.3-192 dated 09/19/18 Page B 3.3-192 dated 02/02/22 Page B 3.3-193 dated 09/19/18 Page B 3.3-193 dated 02/02/22 Page B 3.3-194 dated 09/19/18 Page B 3.3-194 dated 02/02/22 Page B 3.3-195 dated 09/19/18 Page B 3.3-195 dated 02/02/22 Page B 3.3-196 dated 09/19/18 Page B 3.3-196 dated 02/02/22 Page B 3.3-197 dated 09/19/18 Page B 3.3-197 dated 02/02/22 Page B 3.4-20 Revision 0 Page B 3.4-20 dated 01/18/23 Page B 3.4-21 Revision 0 Page B 3.4-21 dated 0 1/18/23 Page B 3.4-22 Revision 0 Page B 3.4-22 dated 01/18/23 Page B 3.4-23 dated 05/17 /17 Paqe B 3.4-23 dated 01/18/23 Page B 3.5-18 dated 09/19/18 Page B 3.5-18 dated 02/02/22 Page B 3.5-19 dated 09/19/18 Page B 3.5-19 dated 02/02/22 Page B 3.5-20 dated 09/19/18 Page B 3.5-20 dated 02/02/22 Page B 3.5-21 dated 09/19/18 Page B 3.5-21 dated 02/02/22 Page B 3.5-22 dated 09/19/18 Page B 3.5-22 dated 02/02/22 Page B 3.5-23 dated 09/19/18 Page B 3.5-23 dated 02/02/22 Paqe B 3.5-24 dated 09/19/18 Paqe B 3.5-24 dated 02/02/22 Page B 3.5-25 dated 02/22/19 Paqe B 3.5-25 dated 02/02/22 Page B 3.5-26 dated 02/22/19 Page B 3.5-26 dated 02/02/22

REMOVE INSERT Page B 3.6-17 Revision 0 Page B 3.6-17 dated 03/31/21 Paqe B 3.6-18 dated 09/19/18 Paqe B 3.6-18 dated 02/02/22 Page B 3.6-23 dated 09/19/18 Page B 3.6-23 dated 02/02/22 Page B 3.8-6 dated 02/07 /13 Page B 3.8-6 dated 03/31/21 Page B 3.8-7 dated 02/07 /13 Page B 3.8-7 dated 03/31/21 Page B 3.8-8 dated 02/07 /13 Page B 3.8-8 dated 03/31/21 Page B 3.8-9 dated 02/07 /13 Page B 3.8-9 dated 03/31/21 Page B 3.8-10 dated 05/13/20 Page B 3.8-10 dated 03/31/21 Page B 3.8-11 dated 02/07 /13 Page B 3.8-11 dated 03/31/21 Page B 3.8-12 dated 02/07 /13 Page B 3.8-12 dated 03/31/21 Page B 3.8-13 dated 02/07 /13 Page B 3.8-13 dated 03/31/21 Page B 3.8-14 dated 02/07 /13 Page B 3.8-14 dated 03/31/21 Page B 3.8-15 dated 05/17 /17 Page B 3.8-15 dated 03/31/21 Page B 3.8-16 dated 05/17 /17 Page B 3.8-16 dated 03/31/21 Page B 3.8-17 dated 04/03/19 Page B 3.8-17 dated 03/31/21 Page B 3.8-18 dated 05/17 /17 Page B 3.8-18 dated 03/31/21 Page B 3.8-19 dated 05/17 /17 Page B 3.8-19 dated 03/31/21 Page B 3.8-20 dated 10/15/19 Page B 3.8-20 dated 03/31/21 Page B 3.8-21 dated 05/17 /17 Page B 3.8-21 dated 03/31/21 Page B 3.8-24 dated 09/19/18 Page B 3.8-24 dated 02/02/22 Page B 3.8-25 dated 09/19/18 Page B 3.8-25 dated 02/02/22 Page B 3.8-27 dated 09/19/18 Page B 3.8-27 dated 02/02/22 Page B 3.8-28 dated 09/19/18 Page B 3.8-28 dated 02/02/22

LIST OF EFFECTIVE PAGES - BASES Page No.

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Revision No./Date 09/21/18 B 3.1-15 6/10/99 ii 12/19/19 B 3.1-16 12/03/09 iii 09/21/18 B 3.1-17 6/10/99 iv 09/21/18 B 3.1-18 07/16/08 B3.1-19 05/17/17 B 2.0-1 07/01 /20 B 3.1-20 05/17/17 B 2.0-2 07/01/20 B 3.1-21 01/06/12 B 2.0-3 07/01/20 B 3.1-22 0

B 2.0-4 07/01 /20 B 3.1-23 0

B 2.0-5 07/01/20 B 3.1-24 0

B 2.0-6 07/01/20 B 3.1-25 05/09/06 B 2.0-7 07/01/20 B 3.1-26 05/17/17 B 2.0-8 09/25/09 B 3.1-27 05/09/06 B 3.1-28 12/18/03 B 3.0-1 12/09/20 B 3.1-29 0

B 3.0-2 10/15/19 B 3.1-30 0

B 3.0-3 12/09/20 B 3.1-31 0

B 3.0-4 12/09/20 B 3.1-32 0

B 3.0-5 12/09/20 B 3.1-33 05/17/17 B 3.0-6 12/09/20 B 3.1-34 07/16/08 B 3.0-7 12/09/20 B 3.1-35 07/16/08 B 3.0-8 12/09/20 B 3.1-36 07/16/08 B 3.0-9 03/31/21 B 3.1-37 05/17/17 B 3.0-10 12/09/20 B 3.1-38 07/16/08 B 3.0-11 12/09/20 B 3.1-39 09/25/09 B 3.0-12 09/18/09 B 3.1-40 04/10/15 B 3.0-13 03/31/21 B 3.1-41 09/25/09 B 3.0-14 09/18/09 B 3.1-42 05/17/17 B 3.0-15 12/09/20 B 3.1-43 05/17/17 B 3.0-16 12/09/20 B 3.1-44 08/09/17 B 3.0-17 12/09/20 B 3.1-45 05/17/17 B 3.0-18 12/09/20 B 3.1-46 09/25/09 B 3.0-19 12/09/20 B 3.1-47 09/25/09 B 3.1-48 0

B 3.1-1 6/10/99 B 3.1-49 05/17/17 B 3.1-2 6/10/99 B 3.1-50 05/17/17 B 3.1-3 6/10/99 B 3.1-51 09/25/09 B 3.1-4 6/10/99 B 3.1-5 6/10/99 B 3.2-1 09/11/15 B 3.1-6 6/10/99 B 3.2-2 09/11/15 B 3.1-7 12/18/03 B 3.2-3 05/17/17 B 3.1-8 12/18/03 B 3.2-4 07/01/20 B 3.1-9 6/10/99 B 3.2-5 07/01/20 83.1-10 6/10/99 B 3.2-6 07/01/20 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 83.1-13 12/18/03 B 3.2-9 09/11/15 B3.1-14 6/10/99 B 3.2-10 05/17/17 Cooper 1

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Revision No./Date B 3.3-95 02/22/16 B 3.3-143 09/19/18 B 3.3-96 09/19/18 B 3.3-144 09/19/18 B 3.3-97 09/19/18 B 3.3-145 09/19/18 B 3.3-98 09/19/18 B 3.3-146 09/19/18 B 3.3-99 09/19/18 B 3.3-147 09/19/18 B 3.3-100 09/19/18 B 3.3-148 09/19/18 B 3.3-101 09/19/18 B 3.3-149 09/19/18 B 3.3-102 09/19/18 B 3.3-150 09/19/18 B 3.3-103 09/19/18 B 3.3-151 09/19/18 B 3.3-104 09/19/18 B 3.3-152 09/19/18 B 3.3-105 08/19/19 B 3.3-153 03/31/21 B 3.3-106 08/19/19 B 3.3-154 03/31/21 B 3.3-107 08/19/19 B 3.3-155 09/19/18 B 3.3-108 02/22/16 B 3.3-156 09/19/18 B 3.3-109 09/19/18 B 3.3-157 09/19/18 B 3.3-110 02/22/16 B 3.3-158 09/19/18 B 3.3-111 09/19/18 B 3.3-159 09/19/18 B 3.3-112 02/22/16 B 3.3-160 09/19/18 B 3.3-113 09/19/18 B 3.3-161 09/19/18 B 3.3-114 09/19/18 B 3.3-162 09/19/18 B 3.3-115 09/19/18 B 3.3-163 09/19/18 B 3.3-116 11/25/12 B 3.3-164 09/19/18 B 3.3-117 05/17/17 B 3.3-165 09/19/18 B 3.3-118 05/17/17 B 3.3-166 09/19/18 B3.3-119 05/17/17 B 3.3-167 09/19/18 B 3.3-120 11/25/12 B 3.3-168 09/19/18 B 3.3-121 11/25/12 B 3.3-169 09/19/18 B 3.3-122 07/20/17 B 3.3-170 09/19/18 B 3.3-123 11/25/12 B 3.3-171 09/19/18 B 3.3-124 11/25/12 B 3.3-172 09/19/18 B 3.3-125 11/25/12 B 3.3-173 09/19/18 B 3.3-126 11/25/12 B 3.3-174 09/19/18 B 3.3-127 11/25/12 B 3.3-175 09/19/18 B 3.3-128 11/25/12 B 3.3-176 09/19/18 B 3.3-129 05/17/17 B 3.3-177 09/19/18 B 3.3-130 05/17/17 B 3.3-178 09/19/18 B 3.3-131 05/17/17 B 3.3-179 09/19/18 B 3.3-132 02/02/22 B 3.3-180 09/19/18 B 3.3-133 02/02/22 B 3.3-181 09/19/18 B 3.3-134 02/02/22 B 3.3-182 09/19/18 B 3.3-135 02/02/22 B 3.3-183 09/19/18 B 3.3-136 02/02/22 B 3.3-184 09/19/18 B 3.3-137 02/02/22 B 3.3-185 09/19/18 B 3.3-138 02/02/22 B 3.3-186 09/19/18 B 3.3-139 02/02/22 B 3.3-187 09/19/18 B 3.3-140 09/19/18 B 3.3-188 09/19/18 B 3.3-141 09/19/18 B 3.3-189 09/19/18 B 3.3-142 09/19/18 83.3-190 09/19/18 Cooper 3

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Revision No./Date B 3.3-191 09/19/18 8 3.4-34 12/19/19 8 3.3-192 02/02/22 8 3.4-35 12/19/19 B 3.3-193 02/02/22 8 3.4-36 01/06/21 8 3.3-194 02/02/22 8 3.4-37 01/06/21 8 3.3-195 02/02/22 8 3.4-38 01/06/21 B 3.3-196 02/02/22 B 3.4-39 1

8 3.3-197 02/02/22 8 3.4-40 0

8 3.3-198 09/19/18 8 3.4-41 0

B 3.3-199 09/19/18 8 3.4-42 01/06/21 B 3.3-200 09/19/18 8 3.4-43 01/06/21 8 3.3-201 09/19/18 8 3.4-44 09/22/16 B 3.3-202 09/19/18 8 3.4-45 09/22/16 B 3.3-203 09/19/18 B 3.4-46 09/22/16 8 3.3-204 09/19/18 8 3.4-47 0

8 3.4-48 0

B 3.4-1 0

8 3.4-49 05/17/17 B 3.4-2 09/11/15 B 3.4-50 09/22/16 B 3.4-3 09/11/15 8 3.4-51 05/17/17 8 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 8 3.4-54 05/17/17 8 3.4-7 05/17/17 B 3.4-55 0

B 3.4-8 09/11/15 B 3.4-9 0

8 3.5-1 09/19/18 8 3.4-10 0

8 3.5-2 11/24/03 8 3.4-11 1

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8 3.4-13 04/12/00 B 3.5-5 04/26/04 B 3.4-14 0

8 3.5-6 09/19/18 B 3.4-15 03/05/12 8 3.5-7 04/26/04 8 3.4-16 08/09/17 8 3.5-8 04/26/04 B 3.4-17 05/17/17 B 3.5-9 05/17/17 8 3.4-18 03/05/12 B 3.5-10 05/17/17 B 3.4-19 0

B 3.5-11 05/17/17 8 3.4-20 01/18/23 B 3.5-12 08/09/17 B 3.4-21 01/18/23 B 3.5-13 08/09/17 B 3.4-22 01/18/23 8 3.5-14 05/17/17 B 3.4-23 01/18/23 B 3.5-15 05/17/17 B 3.4-24 12/19/19 B 3.5-16 05/17/17 B 3.4-25 12/19/19 B 3.5-17 11/23/99 B 3.4-26 12/19/19 83.5-18 02/02/22 B 3.4-27 12/19/19 B 3.5-19 02/02/22 B 3.4-28 12/19/19 B 3.5-20 02/02/22 B 3.4-29 12/19/19 B 3.5-21 02/02/22 8 3.4-30 12/19/19 B 3.5-22 02/02/22 B 3.4-31 12/19/19 B 3.5-23 02/02/22 B 3.4-32 12/19/19 B 3.5-24 02/02/22 B 3.4-33 12/19/19 8 3.5-25 02/02/22 Cooper 4

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B 3.5-28 09/19/18 B 3.6-43 05/17/17 B 3.5-29 09/19/18 B 3.6-44 05/17/17 B 3.5-30 09/19/18 B 3.6-45 0

B 3.5-31 09/19/18 B 3.6-46 06/10/99 B 3.5-32 09/19/18 B 3.6-47 0

B 3.6-48 0

B 3.6-1 03/08/00 B 3.6-49 05/17/17 B 3.6-2 09/30/08 B 3.6-50 05/17/17 B 3.6-3 03/08/00 B 3.6-51 02/22/16 B 3.6-4 11/06/06 B 3.6-52 02/22/16 B 3.6-5 05/17/17 B 3.6-53 08/19/20 B 3.6-6 0

B 3.6-54 08/09/17 B 3.6-7 09/30/08 B 3.6-55 02/22/16 B 3.6-8 0

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B 3.6-57 02/22/16 B 3.6-10 0

B 3.6-58 05/17/17 B 3.6-11 0

B 3.6-59 05/17/17 B 3.6-12 03/08/00 B 3.6-60 02/22/16 B 3.6-13 05/17/17 B 3.6-61 09/19/18 B 3.6-14 03/08/00 B 3.6-62 05/17/17 B 3.6-15 0

B 3.6-63 11/02/17 B 3.6-16 1

B 3.6-64 11/02/17 B 3.6-17 03/31/21 B 3.6-65 05/17/17 B 3.6-18 02/02/22 B 3.6-66 08/09/17 B 3.6-19 11/28/01 B 3.6-67 02/22/16 B 3.6-20 11/28/01 B 3.6-68 02/22/16 B 3.6-21 11/28/01 B 3.6-69 05/17/17 B 3.6-22 11 /28/01 B 3.6-70 02/22/16 B 3.6-23 02/02/22 B 3.6-71 09/19/18 B 3.6-24 05/17/17 B 3.6-72 09/19/18 B 3.6-25 1

B 3.6-73 05/17/17 B 3.6-26 08/09/17 B 3.6-74 05/17/17 B 3.6-27 05/17/17 B 3.6-75 02/22/16 B 3.6-28 05/17/17 B 3.6-76 09/19/18 B 3.6-29 09/25/09 B 3.6-77 02/22/16 B 3.6-30 09/30/08 B 3.6-78 02/22/16 B 3.6-31 05/17/17 B 3.6-79 09/19/18 B 3.6-32 12/27/02 B 3.6-80 08/09/17 B 3.6-33 12/27/02 B 3.6-81 02/22/16 B 3.6-34 05/17/17 B 3.6-82 02/22/16 B 3.6-35 0

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Cooper 7

01/18/23

BASES LCO Applicability B 3.0 LCO 3.0.5 (continued)

LCO 3.0.6 Cooper Examples of demonstrating equipment OPERABILITY include instances in which it is necessary to take an inoperable channel or trip system out of a tripped condition that was directed by a Required Action, if there is no Required Action Note for this purpose. An example of verifying OPERABILITY of equipment removed from service is taking a tripped channel out of the tripped condition to permit the logic to function and indicate the appropriate response during performance of required testing on the inoperable channel. Examples of demonstrating the OPERABILITY of other equipment are taking an inoperable channel or trip system out of the tripped condition 1) to prevent the trip function from occurring during the performance of an SR on another channel in the other trip system, or 2) to permit the logic to function and indicate the appropriate response during the performance of an SR on another channel in the same trip system.

The administrative controls in LCO 3.0.5 apply in all cases to systems or components in Chapter 3 of the Technical Specifications, as long as the testing could not be conducted while complying with the Required Actions. This includes the realignment or repositioning of redundant or alternate equipment or trains previously manipulated to comply with ACTIONS, as well as equipment removed from service or declared inoperable to comply with ACTIONS.

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

When a support system is inoperable and there is an LCO specified for it in the TS, the supported system(s) are required to be declared inoperable if determined to be inoperable as a result of the support system inoperability. However, it is not necessary to enter into the supported systems' Conditions and Required Actions unless directed to do so by the support system's Required Actions. The potential confusion and inconsistency of requirements related to the entry into multiple support and supported systems' LCO Conditions and Required Actions are eliminated by providing all the actions that are necessary to ensure the B 3.0-9 03/31/21

SR Applicability B 3.0 B 3.0 SURVEILLANCE REQUIREMENT (SR) APPLICABILITY BASES SRs SR 3.0.1 Cooper SR 3.0.1 through SR 3.0.4 establish the general requirements applicable to all Specifications in Sections 3.1 through 3.10 and apply at all times, unless otherwise stated. SR 3.0.2 and SR 3.0.3 apply in Chapter 5 when invoked by a Chapter 5 Specification.

SR 3.0.1 establishes the requirement that SRs must be met during the MODES or other specified conditions in the Applicability for which the requirements of the LCO apply, unless otherwise specified in the individual SRs. This Specification is to ensure that Surveillances are performed to verify the OPERABILITY of systems and components, and that variables are within specified limits. Failure to meet a Surveillance within the specified Frequency, in accordance with SR 3.0.2, constitutes a failure to meet an LCO. Surveillances may be performed by means of any series of sequential, overlapping, or total steps provided the entire Surveillance is performed within the specified Frequency. Additionally, the definitions related to instrument testing (e.g. CHANNEL CALIBRATION) specify that these tests are performed by means of any series of sequential overlapping, or total steps.

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

a.

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

b.

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

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

Surveillances, including Surveillances invoked by Required Actions, do not have to be performed on inoperable equipment because the ACTIONS define the remedial measures that apply. Surveillances have to be met and performed in accordance with SR 3.0.2, prior to returning equipment to OPERABLE status.

B 3.0-13 03/31/21

BASES ACTIONS ( continued)

Cooper PAM Instrumentation B 3.3.3.1 If a channel has not been restored to OPERABLE status in 30 days, this Required Action specifies initiation of action in accordance with Specification 5.6.6, which requires a written report to be submitted to the NRC. This report discusses the cause of the inoperability and identifies proposed restorative actions. This action is appropriate in lieu of a shutdown requirement, since alternative actions are identified before loss of functional capability, and given the likelihood of plant conditions that would require information provided by this instrumentation.

C.1 When one or more Functions have two required channels that are inoperable (i.e., two channels inoperable in the same Function) or when one Function 2.c (Reactor Vessel Water Level-Steam Nozzle) channel is inoperable, one channel in the Function should be restored to OPERABLE status within 7 days. The Completion Time of 7 days is based on the relatively low probability of an event requiring PAM instrument operation and the availability of alternate means to obtain the required information. Continuous operation with two required channels inoperable in a Function or the one required channel inoperable in Function 2.c is not acceptable because the alternate indications may not fully meet all performance qualification requirements applied to the PAM instrumentation. Therefore, requiring restoration of one inoperable channel of the Function limits the risk that the PAM Function will be in a degraded condition should an accident occur.

D.1 This Required Action directs entry into the appropriate Condition referenced in Table 3.3.3.1-1. The applicable Condition referenced in the Table is Function dependent. Each time an inoperable channel has not met the Required Action of Condition C, and the associated Completion Time has expired, Condition D is entered for that channel and provides for transfer to the appropriate subsequent Condition.

B 3.3-68 03/31/21

RPV Water Inventory Control Instrumentation B 3.3.5.3 B 3.3 INSTRUMENTATION B 3.3.5.3 Reactor Pressure Vessel (RPV) Water Inventory Control Instrumentation BASES BACKGROUND Cooper The RPV contains penetrations below the top of the active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF.

If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of the active irradiated fuel at all times to prevent such elevated cladding temperatures.

Technical Specifications are required by 10 CFR 50.36 to include limiting safety system settings (LSSS) for variables that have significant safety functions. LSSS are defined by the regulation as "Where a LSSS is specified for a variable on which a safety limit has been placed, the setting must be chosen so that automatic protective actions will correct the abnormal situation before a Safety Limit (SL) is exceeded." The Analytical Limit is the limit of the process variable at which a safety action is initiated to ensure that a SL is not exceeded. Any automatic protection action that occurs on reaching the Analytical Limit therefore ensures that the SL is not exceeded. However, in practice, the actual settings for automatic protection channels must be chosen to be more conservative than the Analytical Limit to account for instrument loop uncertainties related to the setting at which the automatic protective action would actually occur. The actual settings for the automatic isolation channels are the same as those established for the same functions in MODES 1, 2, and 3 in LCO 3.3.6.1, "Primary Containment Isolation Instrumentation".

With the unit in MODE 4 or 5, RPV water inventory control is not required to mitigate any events or accidents evaluated in the safety analyses.

RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur. Under the definition of DRAIN TIME, some penetration flow paths may be excluded from the DRAIN TIME calculation if they will be isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation.

B 3.3-132 02/02/22

BASES RPV Water Inventory Control Instrumentation B 3.3.

5.3 BACKGROUND

(continued)

The purpose of the RPV Water Inventory Control Instrumentation is to support the requirements of LCO 3.5.2, "Reactor Pressure Vessel (RPV)

Water Inventory Control," and the definition of DRAIN TIME. There are functions that support automatic isolation of Residual Heat Removal subsystem and Reactor Water Cleanup system penetration flow path(s) on low RPV water level.

APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY Cooper With the unit in MODE 4 or 5, RPV water inventory control is not required to mitigate any events or accidents evaluated in the safety analyses.

RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material should a draining event occur.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not considered in MODES 4 and 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is considered in which an initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure. It is assumed based on engineering judgement, that while in MODES 4 and 5, one low pressure ECCS injection/spray subsystem can be manually initiated to maintain adequate reactor vessel water level.

As discussed in References 1, 2, 3, 4 and 5, operating experience has shown RPV water inventory to be significant to public health and safety.

Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36( c)(2)(ii).

Permissive and interlock setpoints are generally considered as nominal values without regard to measurement accuracy.

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. [DELETED]

1.b, 2.b.. (DELETED]

B 3.3-133 02/02/22

BASES RPV Water Inventory Control Instrumentation B 3.3.5.3 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

RHR System Isolation Cooper 3.a. Reactor Vessel Water Level - Low. Level 3 The definition of DRAIN TIME allows crediting the closing of penetration flow paths that are capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation. The Reactor Vessel Water Level - Low, Level 3 Function associated with RHR System isolation may be credited for automatic isolation of penetration flow paths associated with the RHR System.

Reactor Vessel Water Level - Low, Level 3 signals are initiated from four level transmitters 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. While four channels (two channels per trip system) of the Reactor Vessel Water Level - Low, Level 3 Function are available, only two channels (both in the same trip system) are required to be OPERABLE.

The Reactor Vessel Water Level - Low, Level 3 Allowable Value was chosen to be the same as the Primary Containment Isolation Instrumentation Reactor Vessel Water Level - Low, Level 3 Allowable Value (LCO 3.3.6.1 ), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level - Low, Level 3 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME.

This Function isolates the Shutdown Cooling Isolation Valves.

B 3.3-134 02/02/22

BASES RPV Water Inventory Control Instrumentation B 3.3.5.3 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Reactor Water Cleanup (RWCU) System Isolation ACTIONS Cooper 4.a. Reactor Vessel Water Level - Low Low. Level 2 The definition of DRAIN TIME allows crediting the closing of penetration flow paths that are capable of being isolated by valves that will close automatically without offsite power prior to the RPV water level being equal to the TAF when actuated by RPV water level isolation instrumentation. The Reactor Vessel Water Level - Low Low, Level 2 Function associated with RWCU System isolation may be credited for automatic isolation of penetration flow paths associated with the RWCU System.

Reactor Vessel Water Level - Low, Low, Level 2 signals are initiated from four level transmitters 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. While four channels (two channels per trip system) of the Reactor Vessel Water Level - Low Low, Level 2 Function are available, only two channels (both in the same trip system) are required to be OPERABLE.

The Reactor Vessel Water Level - Low Low, Level 2 Allowable Value was chosen to be the same as the ECCS Reactor Vessel Water Level - Low Low, Level 2 Allowable Value (LCO 3.3.5.1 ), since the capability to cool the fuel may be threatened.

The Reactor Vessel Water Level - Low Low, Level 2 Function is only required to be OPERABLE when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME.

This Function isolates the Group 3 valves.

A Note has been provided to modify the ACTIONS related to RPV Water Inventory Control 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 continue to apply for each additional failure, with Completion Times based on initial entry into the Condition. However, the Required Actions for inoperable RPV Water Inventory Control instrumentation channels provide appropriate compensatory measures for separate inoperable Condition entry for each inoperable RPV Water Inventory Control instrumentation channels.

B 3.3-135 02/02/22

BASES ACTIONS (continued)

A.1. A.2.1. and A.2.2 RPV Water Inventory Control Instrumentation B 3.3.5.3 RHR System Isolation, Reactor Vessel Water Level - Low Level 3, and Reactor Water Cleanup System, Reactor Vessel Water Level - Low Low, Level 2 functions are applicable when automatic isolation of the associated penetration flow path is credited in calculating DRAIN TIME. If the instrumentation is inoperable, Required Action A.1 directs immediate action to place the channel in trip. With the inoperable channel in the tripped condition, the remaining channel will isolate the penetration flow path on low water level. If both channels are inoperable and placed in trip, the penetration flow path will be isolated. Alternatively, Required Action A.2.1 requires the associated penetration flow path(s) to be immediately declared incapable of automatic isolation. Required Action A.2.2 directs initiating action to calculate DRAIN TIME. The calculation cannot credit automatic isolation of the affected penetration flow paths.

SURVEILLANCE REQUIREMENTS Cooper The following SRs apply to each RPV Water Inventory Control instrument Function in Table 3.3.5.3-1.

Amendment 260 did not include SRs to verify or adjust the instrument setpoint derived from the allowable value using a channel calibration or a surveillance to calibrate the trip unit. This is because a draining event in MODES 4 or 5 is not an analyzed accident and, therefore, there is no accident analysis on which to base the calculation or a setpoint. As noted in the safety evaluation, the purpose of the functions is to allow ECCS manual initiation or to automatically isolate a penetration flow path, but no specific RPV water level is assumed for those actions. Therefore, the MODE 3 allowable value was chosen for use in MODES 4 and 5, as it will perform the desired function. Calibrating the functions in MODES 4 and 5 is not necessary, as TSs 3.3.5.1 and 3.3.6.1 continue to require the functions to be calibrated on an established interval. Also, there are no accident analysis assumptions on response time. (Reference 6)

B 3.3-136 02/02/22

BASES RPV Water Inventory Control Instrumentation B 3.3.5.3 SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.5.3.1 Cooper Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel to a similar parameter on other channels. It is based on the assumption that instrument channels monitoring the same parameter should read approximately the same value. Significant deviations between the instrument channels could be an indication of excessive instrument drift in one of the channels or something even more serious. A CHANNEL CHECK guarantees that undetected outright channel failure is limited; thus, it is key to verifying the instrumentation continues to operate properly between each CHANNEL FUNCTIONAL TEST.

Agreement criteria are determined by the plant staff, based on a combination of the channel instrument uncertainties, including indication and readability. If a channel is outside the criteria, it may be an indication that the instrument has drifted outside its limit.

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

The CHANNEL CHECK supplements less formal, but more frequent checks of channels during normal operational use of the displays associated with the channels required by the LCO.

B 3.3-137 02/02/22

BASES RPV Water Inventory Control Instrumentation B 3.3.5.3 SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.5.3.2 Cooper A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the entire channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications tests.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

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

B 3.3-138 02/02/22

BASES REFERENCES Cooper RPV Water Inventory Control Instrumentation B 3.3.5.3

1.

Information Notice 84-81 "Inadvertent Reduction in Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup," November 1984.

2.

Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.

3.

Generic Letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(F)," August 1992.

4.

NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," May 1993.

5.

Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994.

6.

Cooper Nuclear Station - Issuance of Amendment RE: Revision to Technical Specifications to Adopt Technical Specifications Task Force (TSTF) Traveler TSTF-542, Revision 2, "Reactor Pressure Vessel Water Inventory Control."

B 3.3-139 02/02/22

BASES Primary Containment Isolation Instrumentation 8 3.3.6.1 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Cooper The Allowable Values for the Steam Line Flow-High Function and associated Time Delay Relay Function are chosen to be low enough to ensure that the trip occurs to prevent fuel damage and maintains the MSLB event as the bounding event.

These Functions isolate the Group 4 and 5 valves, as appropriate, as listed in Reference 1.

3.c, 4.c. HPCI and RCIC Steam Supply Line Pressure-Low Low MSL pressure indicates that the pressure of the steam in the HPCI or RCIC turbine may be too low to continue operation of the associated system's turbine. In addition to protecting the equipment from the low pressure steam conditions, these isolations ensure that the systems are isolated following a OBA LOCA thereby minimizing containment leakage through the RCIC or HPCI system. The isolations also provide a diverse signal to indicate a possible system break. These instruments are included in Technical Specifications (TS) because the accident analysis implicitly assumes that the penetration is closed during a OBA LOCA and because of the potential for risk due to possible failure of the instruments preventing HPCI and RCIC initiations (Ref. 8).

The HPCI and RCIC Steam Supply Line Pressure-Low signals are initiated from pressure switches (four for HPCI and four for RCIC) that are connected to the system steam line. Four channels of both HPCI and RCIC Steam Supply Line Pressure-Low Functions are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The Allowable Values are selected to be low enough to ensure that the HPCI and RCIC systems operate as long as possible following an accident and high enough to prevent damage to the system's turbine.

These Functions isolate the Group 4 and 5 valves, as appropriate, as listed in Reference 1.

3.d, 4.d. HPCI and RCIC Steam Line Space Temperature-High HPCI and RCIC Steam Line Space temperatures are provided to detect a leak from the associated system steam piping. The isolation occurs when a very small leak has occurred and is diverse to the high flow instrumentation. If the small leak is allowed to continue without isolation, offsite dose limits may be reached. These Functions are not assumed in 83.3-153 03/31/21

BASES Primary Containment Isolation Instrumentation B 3.3.6.1 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Cooper any USAR transient or accident analysis, since bounding analyses are performed for large breaks such as recirculation or MSL breaks.

HPCI and RCIC Steam Line Space Temperature-High signals are initiated from temperature switches that are appropriately located to protect the system that is being monitored. For each physical location of eight channels, only two channels per trip system are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function. Since the logic configuration for a trip system is one-out-of-two taken twice, the two required OPERABLE channels per trip system must be in different trip strings; i.e., they must be connected such that isolation occurs when both required channels actuate (one of two parallel logic pairs of switch channels in one trip string must trip in combination with the tripping of one of two additional parallel logic switch channels in the other trip string in order to actuate the trip system).

The Allowable Values are set low enough to provide timely detection of a RCIC or HPCI turbine steam line break.

These Functions isolate the Group 4 and 5 valves, as appropriate, as listed in Reference 1.

Reactor Water Cleanup System Isolation 5.a.

RWCU Flow-High The high flow signal is provided to detect a break in the RWCU System.

Should the reactor coolant continue to flow out of the break, offsite dose limits may be exceeded. Therefore, isolation of the RWCU System is initiated when high flow is sensed to prevent exceeding offsite doses.

This Function is not assumed in any USAR transient or accident analysis, since bounding analyses are performed for large breaks such as MSLBs.

The high RWCU flow signals are initiated from differential pressure switches that are connected to an annubar on the inlet pump suction line of the RWCU System. Two channels of RWCU Flow-High Function are available and are required to be OPERABLE to ensure that no single instrument failure can preclude the isolation function.

The RWCU Flow-High Allowable Value ensures that a break of the RWCU piping is detected.

This Function isolates the Group 3 valves, as listed in Reference 1.

B 3.3-154 03/31/21

BASES LOP Instrumentation B 3.3.8.1 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Cooper supply sufficient power for proper operation of the applicable equipment.

Therefore, the power supply to the bus is transferred from offsite power to DG power when the voltage on the bus drops below the Loss of Voltage Function Allowable Values (loss of voltage with a short time delay). This ensures that adequate power will be available to the required equipment.

Upon loss of voltage, relay 27/1 F1 (27/1 G1) will initiate a start signal to DG 1 (DG2), load shedding of all motors on 4.16 kV Emergency Bus 1 F (1 G), and load shedding of the non-essential Motor Control Centers (MCCs) and non-essential motors fed from critical 480 V Bus 1 F (1 G).

The 4.16 kV Emergency Bus Undervoltage (Loss of Voltage) Allowable Value is low enough to prevent inadvertent power supply transfer, but high enough to ensure that power is available to the required equipment.

The Time Delay Allowable Values are long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that power is available to the required equipment.

One channel of 4.16 kV Emergency Bus Undervoltage (Loss of Voltage)

Function and Time Delay Function per associated 4.16 kV emergency bus is available and is only required to be OPERABLE when the associated DG is required to be OPERABLE in MODES 1, 2 and 3. Refer to LCO 3.8.1, "AC Sources-Operating," for Applicability Bases for the DGs.

2.a, 2.b 4.16 kV Emergency Bus Normal Supply Undervoltage (Loss of Voltage}

Loss of voltage on the SWGR 1 A to 1 F ( 1 B to 1 G) bus tie indicates that offsite power is not available from the normal source (NSST or SSST).

Therefore, in order to allow the emergency bus to be powered from the alternate offsite power source (ESST) or the DG, relay 27/1 FA-1 (27 /1 GB-1) will cause the normal supply breaker to the 4.16 kV emergency bus, 1 FA (1 GB) to trip following the actuation of the Function 1 channels following a short time delay.

The 4.16 kV Emergency Bus Normal Supply Undervoltage (Loss of Voltage) Allowable Value is low enough to prevent inadvertent power supply transfer, but high enough to ensure that power is available to the required equipment. The Time Delay Allowable Values are chosen to assure timely operation for a loss of voltage condition, but not allow spurious operation during momentary voltage dips created by motor starts.

B 3.3-192 02/02/22

BASES LOP Instrumentation B 3.3.8.1 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Cooper One channel of 4.16 kV Emergency Bus Normal Supply Undervoltage (Loss of Voltage) Function and Time Delay Function per associated 4.16 kV emergency bus is available and is only required to be OPERABLE when the associated DG is required to be OPERABLE in MODES 1, 2, and 3. Refer to LCO 3.8.1, "AC Sources-Operating," for Applicability Bases for the DGs.

3.a. 3.b 4.16 kV Emergency Bus ESST Supply Undervoltage

( Loss of Voltage)

Loss of voltage on the ESST-1 F (1G) bus tie indicates that offsite power is not available from the alternate offsite source (ESST). Therefore, in order to allow the 4.16 kV emergency bus to be powered from the DG following loss of the alternate offsite source, relay 27/ET-1 (27/ET-2) will cause the ESST-1F (1G) breaker 1FS (1GS) to trip following a short time delay, which in turn will allow the DG output breaker to close.

The 4.16 kV Emergency Bus ESST Supply Undervoltage (Loss of Voltage) Allowable Value is low enough to prevent inadvertent power supply transfer, but high enough to ensure that power is available to the required equipment. The Time Delay Allowable Values are long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that power is available to the required equipment.

One channel of 4.16 kV Emergency Bus ESST Supply Undervoltage (Loss of Voltage) Function and Time Delay Function per associated 4.16 kV emergency bus is available and is only required to be OPERABLE when the associated DG is required to be OPERABLE in MODES 1, 2, and 3. Refer to LCO 3.8.1, "AC Sources-Operating," for Applicability Bases for the DGs.

4.a 1 4. b, 4.c 4.16 kV Emergency Bus Undervoltaqe (Degraded Voltage)

A reduced voltage condition on a 4.16 kV emergency bus indicates that, while offsite power may not be completely lost to the respective emergency bus, available power may be insufficient for starting large ECCS motors without risking damage to the motors that could disable the ECCS function. Therefore, power supply to the bus is transferred from normal offsite power to alternate offsite power or to onsite DG power when the voltage on the bus drops below the Degraded Voltage Function Allowable Value ( degraded voltage with a time delay).

8 3.3-193 02/02/22

BASES LOP Instrumentation B 3.3.8.1 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

Cooper This ensures that adequate power will be available to the required equipment.

A degraded voltage condition on 4.16 kV Emergency Bus 1F (1G) is monitored by relays 27/1 F2 (27/1 G2) and 27/1 FA2 (27/1 GB2). Any momentary voltage dips caused by starting of large motors will not operate undervoltage relays. When 4.16 kV Emergency Bus 1 F ( 1 G) is powered from either the SSST or NSST, a degraded voltage on 4.16 kV Emergency Bus 1 F (1G) below a nominal value of 3,880 V for approximately 12.5 seconds sensed by both relays 27/1 F2 (27/1 G2) and 27/1FA2 (27/1GB2) will trip the tie breaker 1FA (1GB) unless a LOCA seal-in signal is present, in which case time delay relay 27X7 /1 F (27X7/1G) will be bypassed and breaker 1 FA (1GB) will trip if voltage on 4.16 kV Emergency Bus 1 F (1 G) is below a nominal value of 3,880 V for 7.5 seconds.

The Bus Undervoltage Allowable Value is low enough to prevent inadvertent power supply transfer, but high enough to ensure that sufficient power is available to the required equipment. The Time Delay Allowable Value is long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that sufficient power is available to the required equipment.

Two channels of 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) Function and Time Delay Function per associated bus are available and are required to be OPERABLE when the associated DG is required to be OPERABLE in MODES 1, 2, and 3. Refer to LCO 3.8.1 for Applicability Bases for the DGs.

5.a, 5.b 4. 16 kV Emergency Bus ESST Supply Undervoltage (Degraded Voltage)

A reduced voltage condition on a 4.16 kV emergency bus indicates that, while offsite power may not be completely lost to the respective emergency bus, available power may be insufficient for starting large ECCS motors without risking damage to the motors that could disable the ECCS function. Therefore, power supply to the bus is transferred from the alternate offsite power source to onsite DG power when the voltage on the bus drops below the Degraded Voltage Function Allowable Value (degraded voltage with a time delay). This ensures that adequate power will be available to the required equipment.

When 4.16 kV Emergency Bus 1 F (1 G) is energized from the ESST, degraded voltages will be sensed by only one relay 27/1 F2 (27/1 G2).

B 3.3-194 02/02/22

BASES LOP Instrumentation B 3.3.8.1 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)

ACTIONS Cooper Any momentary voltage dips caused by starting of large motors will not operate undervoltage relays. When 4.16 kV Emergency Bus 1 F (1G) is powered from the ESST, a degraded voltage on 4.16 kV Emergency Bus 1F (1G) for approximately 15 seconds will trip breaker 1FS (1GS). The nominal 15 second time delay consists of the nominal 7.5 second time delay from relay 27/1 F2 (27/1 G2) plus a nominal 7.5 second time delay from time delay relay 27X15/1 F (27X15/1 G). After the ESST breaker 1 FS (1 GS) trips, the Loss of Voltage protection system will start the associated DG and will trip all 4,000 volt motor breakers and non-essential MCC breakers. The 4.16 kV Emergency Bus Undervoltage (Degraded Voltage)

Allowable Value is low enough to prevent inadvertent power supply transfer, but high enough to ensure that sufficient power is available to the required equipment. The Time Delay Allowable Value is long enough to provide time for the offsite power supply to recover to normal voltages, but short enough to ensure that sufficient power is available to the required equipment.

One channel of 4.16 kV Emergency Bus Undervoltage (Degraded Voltage) Function and Time Delay Function per associated bus is available and is only required to be OPERABLE when the associated DG is required to be OPERABLE in MODES 1, 2, and 3. Refer to LCO 3.8.1 for Applicability Bases for the Gs.

A Note has been provided to modify the ACTIONS related to LOP 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 LOP instrumentation channels provide appropriate compensatory measures for separate inoperable channels. As such, a Note has been provided that allows separate Condition entry for each inoperable LOP instrumentation channel.

With one or more channels of a Function inoperable, the Function is not capable of performing the intended function. Therefore, only 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months is allowed to restore the inoperable channel to OPERABLE status. If the channel is not restored to OPERABLE status in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , Condition B must be entered and its Required Action taken.

B 3.3-195 02/02/22

BASES ACTIONS (continued)

LOP Instrumentation B 3.3.8.1 The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. The 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months Completion Time is acceptable because it minimizes risk while allowing time for restoration or tripping of channels.

8.1 If any Required Action and associated Completion Time are not met, the associated Function is not capable of performing the intended function.

Therefore, the associated DG(s) is declared inoperable immediately. This requires entry into applicable Conditions and Required Actions of LCO 3.8.1, which provide appropriate actions for the inoperable DG(s).

SURVEILLANCE REQUIREMENTS Cooper As noted at the beginning of the SRs (Note 1 ), the SRs for each LOP instrumentation Function are located in the SRs column of Table 3.3.8.1-

1.

The Surveillances are further modified by a Note (Note 2) to indicate that when a channel is placed in an inoperable status solely for performance of required Surveillances, entry into associated Conditions and Required Actions may be delayed for up to 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months provided the associated Function maintains initiation capability. Initiation capability is maintained provided that the following can be initiated by the Function for one DG or emergency bus as applicable (if part of that Function): DG start, disconnect from offsite power source, DG output breaker closure, and load shed. Upon completion of the Surveillance, or expiration of the 2 hour2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months allowance, the channel must be returned to OPERABLE status or the applicable Condition entered and Required Actions taken.

SR 3.3.8.1.1 A CHANNEL FUNCTIONAL TEST is performed on each required channel to ensure that the channel will perform the intended function. A successful test of the required contact(s) of a channel relay may be performed by the verification of the change of state of a single contact of the relay. This clarifies what is an acceptable CHANNEL FUNCTIONAL TEST of a relay. This is acceptable because all of the other required contacts of the relay are verified by other Technical Specifications and non-Technical Specifications. Any setpoint adjustment shall be B 3.3-196 02/02/22

BASES LOP Instrumentation B 3.3.8.1 SURVEILLANCE REQUIREMENTS (continued)

Cooper consistent with the assumptions of the current plant specific setpoint methodology.

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

SR 3.3.8.1.2 A CHANNEL CALIBRATION is a complete check of the relay circuitry and associated time delay relays. This test verifies the channel responds to the measured parameter within the necessary range and accuracy.

There is a plant specific program which verifies that the instrument channel functions as required by verifying the as-left and as-found settings are consistent with those established by the setpoint methodology. CHANNEL CALIBRATION leaves the channel adjusted to account for instrument drifts between successive calibrations consistent with the plant specific setpoint methodology.

Any setpoint adjustment shall be consistent with the assumptions of the current plant specific setpoint methodology.

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

SR 3.3.8.1.3 The LOGIC SYSTEM FUNCTIONAL TEST demonstrates the OPERABILITY of the required actuation logic for a specific channel. The system functional testing performed in LCO 3.8.1 overlaps this Surveillance to provide complete testing of the assumed safety functions.

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

B 3.3-197 02/02/22

BASES RCS Operational LEAKAGE B 3.4.4 APPLICABLE SAFETY ANALYSES LCO Cooper The allowable RCS operational LEAKAGE limits are based on the predicted and experimentally observed behavior of pipe cracks. The normally expected background LEAKAGE due to equipment design and the detection capability of the instrumentation for determining system LEAKAGE were also considered. The evidence from experiments suggests that, for LEAKAGE even greater than the specified unidentified LEAKAGE limits, the probability is small that the imperfection or crack associated with such LEAKAGE would grow rapidly.

The unidentified LEAKAGE flow limit allows time for corrective action before the RCPB could be significantly compromised. The 5 gpm limit is a small fraction of the calculated flow from a critical crack in the primary system piping. Crack behavior from experimental programs (Refs. 4 and

5) shows that leakage rates of hundreds of gallons per minute will precede crack instability.

The low limit on increase in unidentified LEAKAGE assumes a failure mechanism of intergranular stress corrosion cracking (IGSCC) in service sensitive type 304 and type 316 austenitic stainless steel that produces tight cracks. This flow increase limit is capable of providing an early warning of such deterioration.

No applicable safety analysis assumes the total LEAKAGE limit. The total LEAKAGE limit considers RCS inventory makeup capability and drywell floor sump capacity.

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

(Ref. 6).

RCS operational LEAKAGE shall be limited to:

a.

Pressure Boundary LEAKAGE Pressure boundary LEAKAGE is prohibited as the leak itself could cause further RCPB deterioration, resulting in higher LEAKAGE.

B 3.4-20 01/18/23

BASES LCO (continued)

APPLICABILITY Cooper

b.

Unidentified LEAKAGE RCS Operational LEAKAGE B 3.4.4 The 5 gpm of unidentified LEAKAGE is allowed as a reasonable minimum detectable amount that the drywell atmospheric monitoring and drywell floor drain sump monitoring equipment can detect within a reasonable time period. Separating the sources of leakage (i.e., leakage from an identified source versus leakage from an unidentified source) is necessary for prompt identification of potentially adverse conditions, assessment of the safety significance, and corrective actions.

c.

Total LEAKAGE The total LEAKAGE limit is based on a reasonable minimum detectable amount. The limit also accounts for LEAKAGE from known sources (identified LEAKAGE). Violation of this LCO indicates an unexpected amount of LEAKAGE and, therefore, could indicate new or additional degradation in an RCPB component or system.

d.

Unidentified LEAKAGE Increase An unidentified LEAKAGE increase of> 2 gpm within the previous 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period indicates a potential flaw in the RCPB and must be quickly evaluated to determine the source and extent of the LEAKAGE. The increase is measured relative to the steady state value; temporary changes in LEAKAGE rate as a result of transient conditions (e.g., startup) are not considered. As such, the 2 gpm increase limit is only applicable in MODE 1 when operating pressures and temperatures are established.

In MODES 1, 2, and 3, the RCS operational LEAKAGE LCO applies, because the potential for RCPB LEAKAGE is greatest when the reactor is pressurized.

In MODES 4 and 5, RCS operational LEAKAGE limits are not required since the reactor is not pressurized and stresses in the RCPB materials and potential for LEAKAGE are reduced.

B 3.4-21 01/18/23

BASES ACTIONS Cooper A.1 RCS Operational LEAKAGE B 3.4.4 If pressure boundary LEAKAGE exists, the affected component, pipe or vessel must be isolated from the RCS by a closed manual valve, closed and de-activated automatic valve, blink flange, or check valve within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . While in this condition, structural integrity of the system should be considered because the structural integrity of the part of the system within the isolation boundary must be maintained under all licensing basis conditions, including consideration of the potential for further degradation of the isolated location. Normal LEAKAGE past the isolation device is acceptable as it will limit RCS LEAKAGE and is included in identified or unidentified LEAKAGE. This action is necessary to prevent further deterioration of the RCPB.

!Ll With RCS unidentified or total LEAKAGE greater than the limits, actions must be taken to reduce the leak. Because the LEAKAGE limits are conservatively below the LEAKAGE that would constitute a critical crack size, 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months is allowed to reduce the LEAKAGE rates before the reactor must be shut down. If an unidentified LEAKAGE has been identified and quantified, it may be reclassified and considered as identified LEAKAGE; however, the total LEAKAGE limit would remain unchanged.

C.1 and C.2 An unidentified LEAKAGE increase of> 2 gpm within a 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months period is an indication of a potential flaw in the RCPB and must be quickly evaluated. Although the increase does not necessarily violate the absolute unidentified LEAKAGE limit, certain susceptible components must be determined not to be the source of the LEAKAGE increase within the required Completion Time. For an unidentified LEAKAGE increase greater than required limits, an alternative to reducing LEAKAGE increase to within limits (i.e., reducing the LEAKAGE rate such that the current rate is less than the "2 gpm increase in the previous 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months " limit; either by isolating the source or other possible methods) is to evaluate service sensitive type 304 and type 316 austenitic stainless steel piping that is subject to high stress or that contains relatively stagnant or intermittent flow fluids and determine it is not the source of the increased LEAKAGE.

This type piping is very susceptible to IGSCC.

The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time is reasonable to properly reduce the LEAKAGE increase or verify the source before the reactor must be shut down without unduly jeopardizing plant safety.

B 3.4-22 01/18/23

BASES ACTIONS (continued)

D.1 and D.2 RCS Operational LEAKAGE 8 3.4.4 If any Required Action and associated Completion Time is not 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 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 safety systems.

SURVEILLANCE REQUIREMENTS SR 3.4.

4.1 REFERENCES

Cooper The RCS LEAKAGE is monitored by a variety of instruments designed to provide alarms when LEAKAGE is indicated and to quantify the various types of LEAKAGE. Leakage detection instrumentation is discussed in more detail in the Bases for LCO 3.4.5, "RCS Leakage Detection I nstrumentation.

11 Sump level and flow rate are typically monitored to determine actual LEAKAGE rates; however, any method may be used to quantify LEAKAGE within the guidelines of Reference 7. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

1.

10 CFR 50.2.

2.

10 CFR 50.55a(c).

3.

USAR, Section IV-10.

4.

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

5.

NUREG-76/067, "Investigation and Evaluation of Cracking in Austenitic Stainless Steel Piping in Boiling Water Reactors,"

October 1975.

6.

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

7.

Regulatory Guide 1.45, May 1973.

8.

Deleted B 3.4-23 01/18/23

RPV Water Inventory Control B 3.5.2 B 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS), RPV WATER INVENTORY CONTROL, AND REACTOR CORE ISOLATION COOLING (RCIC) SYSTEM B 3.5.2 Reactor Pressure Vessel (RPV) Water Inventory Control BASES BACKGROUND The RPV contains penetrations below the top of active fuel (TAF) that have the potential to drain the reactor coolant inventory to below the TAF.

If the water level should drop below the TAF, the ability to remove decay heat is reduced, which could lead to elevated cladding temperatures and clad perforation. Safety Limit 2.1.1.3 requires the RPV water level to be above the top of active irradiated fuel at all times to prevent such elevated cladding temperatures.

APPLICABLE SAFETY ANALYSES LCO Cooper With the unit in MODE 4 or 5, RPV water inventory control is not required to mitigate any events or accidents evaluated in the safety analyses.

RPV water inventory control is required in MODES 4 and 5 to protect Safety Limit 2.1.1.3 and the fuel cladding barrier to prevent the release of radioactive material to the environment should an unexpected draining event occur.

A double-ended guillotine break of the Reactor Coolant System (RCS) is not considered in MODES 4 or 5 due to the reduced RCS pressure, reduced piping stresses, and ductile piping systems. Instead, an event is considered in which an initiating event allows draining of the RPV water inventory through a single penetration flow path with the highest flow rate, or the sum of the drain rates through multiple penetration flow paths susceptible to a common mode failure (an event that creates a drain path through multiple vessel penetrations located below top of active fuel, such as loss of normal power or a single human error). It is assumed, 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.

As discussed in References 1, 2, 3, 4, and 5, operating experience has shown RPV water inventory to be significant to public health and safety.

Therefore, RPV Water Inventory Control satisfies Criterion 4 of 10 CFR 50.36(c)(2)(ii).

The RPV water level must be controlled in MODES 4 and 5 to ensure that if an unexpected draining event should occur, the reactor coolant water level remains above the top of the active irradiated fuel as required by Safety Limit 2.1.1.3.

B 3.5-18 02/02/22

BASES LCO ( continued)

APPLICABILITY ACTIONS Cooper RPV Water Inventory Control B 3.5.2 The Limiting Condition for Operation (LCO) requires the DRAIN TIME of RPV water inventory to the TAF to be~ 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . A DRAIN TIME of 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months is considered reasonable to identify and initiate action to mitigate unexpected draining of reactor coolant. An event that could cause loss of RPV water inventory and result in the RPV water level reaching the T AF in greater than 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months does not represent a significant challenge to Safety Limit 2.1.1.3 and can be managed as part of normal plant operation.

One low pressure ECCS injection/spray subsystems is required to be OPERABLE and capable of being manually aligned and started from the control room to provide defense-in-depth should an unexpected draining event occur. OPERABILITY of the ECCS injection/spray subsystem includes any necessary valves, instrumentation, or controls needed to manually align and start subsystem from the control room. A low pressure ECCS injection/spray subsystem consists of either one Core Spray (CS) subsystem or one Low Pressure Coolant Injection (LPCI) subsystem. Each CS subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV.

Each LPCI subsystem consists of one motor driven pump, piping, and valves to transfer water from the suppression pool to the RPV. In MODES 4 and 5, the RHR System cross tie shutoff valve is not required to be closed.

RPV water inventory control is required in MODES 4 and 5.

Requirements on water inventory control in other MODES are contained in LCOs in Section 3.3, "Instrumentation", and other LCOs in Section 3.5, "ECCS, RPV Water Inventory Control, and RCIC System". RPV water inventory control is required to protect Safety Limit 2.1.1.3 which is applicable whenever irradiated fuel is in the reactor vessel.

A.1 and B.1 If the required low pressure ECCS injection/spray subsystem 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 . In this Condition, the LCO controls on DRAIN TIME minimize the possibility that an unexpected draining event could necessitate the use of the ECCS injection/spray subsystem, however, the defense-in-depth provided by the ECCS injection/spray subsystem is lost. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time for restoring the required low pressure ECCS injection/spray subsystem to OPERABLE status is based on engineering judgment that considers the B 3.5-19 02/02/22

BASES ACTIONS ( continued)

Cooper RPV Water Inventory Control B 3.5.2 LCO controls on DRAIN TIME and the low probability of an unexpected draining event that would result in loss of RPV water inventory.

If the inoperable ECCS injection/spray subsystem is not restored to OPERABLE status within the required Completion Time, action must be initiated immediately to establish a method of water injection capable of operating without offsite electrical power. The method of water injection includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur. The method of water injection may be manually initiated and may consist of one or more systems or subsystems, and must be able to access water inventory capable of maintaining RPV water level above the TAF for~ 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . If recirculation of injected water would occur, it may be credited in determining the necessary water volume.

C.1, C.2. and C.3 With the DRAIN TIME less than 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months but greater than or equal to 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , compensatory measures should be taken to ensure the ability to implement mitigating actions should an unexpected draining event occur.

Should a draining event lower the reactor coolant level to below the TAF, there is potential for damage to the reactor fuel cladding and release of radioactive material. Additional actions are taken to ensure that radioactive material will be contained, diluted, and processed prior to being released to the environment.

The secondary containment provides a controlled volume in which fission products can be contained, diluted, and processed prior to release to the environment. Required Action C.1 requires verification of the capability to establish the secondary containment boundary in less than the DRAIN TIME. The required verification confirms actions to establish the secondary containment boundary are preplanned and necessary materials are available. The secondary containment boundary is considered established when one Standby Gas Treatment (SGT) subsystem is capable of maintaining a negative pressure in the secondary containment with respect to the environment. Verification that the secondary containment boundary can be established must be performed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The required verification is an administrative activity and does not require manipulation or testing of equipment.

Secondary containment penetration flow paths form a part of the secondary containment boundary. Required Action C.2 requires verification of the capability to isolate each secondary containment penetration flow path in less than the DRAIN TIME. The required B 3.5-20 02/02/22

BASES ACTIONS (continued)

Cooper RPV Water Inventory Control B 3.5.2 verification confirms actions to isolate the secondary containment penetration flow paths are preplanned and necessary materials are available. Power operated valves are not required to receive automatic isolation signals if they can be closed manually within the required time.

Verification that the secondary containment penetration flow paths can be isolated must be performed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The required verification is an administrative activity and does not require manipulation or testing of equipment.

One SGT subsystem is capable of maintaining the secondary containment at a negative pressure with respect to the environment and filter gaseous releases. Required Action C.3 requires verification of the capability to place one SGT subsystem in operation in less than the DRAIN TIME. The required verification confirms actions to place a SGT subsystem in operation are preplanned and necessary materials are available. Verification that a SGT subsystem can be placed in operation must be performed within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . The required verification is an administrative activity and does not require manipulation or testing of equipment.

D.1, D.2. D.3, and D.4 With the DRAIN TIME less than 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months , mitigating actions are implemented in case an unexpected draining event should occur. Note that if the DRAIN TIME is less than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , Required Action E.1 is also applicable.

Required Action D.1 requires immediate action to establish an additional method of water injection augmenting the ECCS injection/spray subsystem required by the LCO. The additional method of water injection includes the necessary instrumentation and controls, water sources, and pumps and valves needed to add water to the RPV or refueling cavity should an unexpected draining event occur. The Note to Refueling Action D.1 states that either the ECCS injection/spray subsystem or the additional method of water injection must be capable of operating without offsite electrical power. The additional method of water injection may be manually initiated and may consist of one or more systems or subsystems. The additional method of water injection must be able to access water inventory capable of being injected to maintain the RPV water level above the TAF for~ 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The additional method of water injection and the ECCS injection/spray subsystem may share all or part of the same water sources. If recirculation of injected water would occur, it may be credited in determining the required water volume.

B 3.5-21 02/02/22

BASES ACTIONS (continued)

RPV Water Inventory Control B 3.5.2 Should a draining event lower the reactor coolant level to below the TAF, there is a potential for damage to the reactor fuel cladding and release of radioactive material. Additional actions are taken to ensure that radioactive material will be contained, diluted, and processed prior to being released to the environment.

The secondary containment provides a control volume in which fission products can be contained, diluted, and processed prior to release to the environment. Required Action D.2 requires that actions be immediately initiated to establish the secondary containment boundary. With the secondary containment boundary established, one SGT subsystem is capable of maintaining a negative pressure in the secondary containment with respect to the environment.

The secondary containment penetrations form a part of the secondary containment boundary. Required Action D.3 requires that actions be immediately initiated to verify that each secondary containment penetration flow path is isolated or to verify that it can be manually isolated from the control room.

One SGT subsystem is capable of maintaining the secondary containment at a negative pressure with respect to the environment and filter gaseous releases. Required Action D.4 requires that actions be immediately initiated to verify that at least one SGT subsystem is capable of being placed in operation. The required verification is an administrative activity and does not require manipulation or testing of equipment.

If the Required Actions and associated Completion times of Conditions C and D are not met or if the DRAIN TIME is less than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months , actions must be initiated immediately to restore the DRAIN TIME to~ 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . In this condition, there may be insufficient time to respond to an unexpected draining event to prevent the RPV water inventory from reaching the TAF.

Note that Required Actions D.1, D.2, D.3, and D.4 are also applicable when DRAIN TIME is less than 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months .

SURVEILLANCE REQUIREMENTS SR 3.5.2.1 Cooper This Surveillance verifies that the DRAIN TIME of RPV water inventory to the TAF is ~ 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months . The period of 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months is considered reasonable B 3.5-22 02/02/22

BASES RPV Water Inventory Control B 3.5.2 SURVEILLANCE REQUIREMENTS (continued)

Cooper to identify and initiate action to mitigate draining of reactor coolant. Loss of RPV water inventory that would result in the RPV water level reaching the TAF in greater than 36 hours4.166667e-4 days 0.01 hours 5.952381e-5 weeks 1.3698e-5 months does not represent a significant challenge to Safety Limit 2.1.1.3 and can be managed as part of normal plant operation.

The definition of DRAIN TIME states that realistic cross-sectional areas and drain rates are used in the calculation. A realistic drain rate may be determined using a single, step-wise, or integrated calculation considering the changing RPV water level during a draining event. For a Control Rod RPV penetration flow path with the Control Rod Drive Mechanism removed and not replaced with a blank flange, the realistic cross-sectional area is based on the control rod blade seated in the control rod guide tube. If the control rod blade will be raised from the penetration to adjust or verify sealing of the blade, the exposed cross-sectional area of the RPV penetration flow path is used.

The definition of DRAIN TIME excludes from the calculation those penetration flow paths connected to an intact closed system, or isolated by manual or automatic valves that are closed and administratively controlled, blank flanges, or other devices that prevent flow of reactor coolant through the penetration flow paths. A blank flange or other bolted device must be connected with a sufficient number of bolts to prevent draining. Normal or expected leakage from closed systems or past isolation devices is permitted. Determination that a system is intact and closed or isolated must consider the status of branch lines.

The Residual Heat Removal (RHR) Shutdown Cooling System is only considered an intact closed system when misalignment issues (Reference 6) have been precluded by functional valve interlocks or by isolation devices, such that redirection of RPV water out of an RHR subsystem is precluded. Further, RHR Shutdown Cooling System is only considered an intact closed system if its controls have not been transferred to Alternate Shutdown, which disables the interlocks and isolation signals.

The exclusion of a single penetration flow path, or multiple penetration flow paths susceptible to a common mode failure, from the determination of DRAIN TIME should consider the effects of temporary alterations in support of maintenance (rigging, scaffolding, temporary shielding, piping plugs, freeze seals, etc.). If reasonable controls are implemented to prevent such temporary alterations from causing a draining event from a closed system or between the RPV and the isolation device, the effect of the temporary alterations on DRAIN TIME need not be considered.

Reasonable controls include, but are not limited to, controls consistent with the guidance in NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," Revision 4, B 3.5-23 02/02/22

BASES RPV Water Inventory Control B 3.5.2 SURVEILLANCE REQUIREMENTS (continued)

Cooper NUMARC 91-06, "Guidelines for Industry Actions to Assess Shutdown Management," or commitments to NUREG 0612, "Control of Heavy Loads at Nuclear Power Plants."

Surveillance Requirement 3.0.1 requires SRs to be met between performances. Therefore, any changes in plant conditions that would change the DRAIN TIME requires that a new DRAIN TIME be determined.

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

SR 3.5.2.2 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 subsystem or LPCI subsystem pump, recirculation volume, and vortex prevention.

With the suppression pool water level less than the required limit, the required ECCS injection/spray subsystem is inoperable.

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

SR 3.5.2.3 The flow path piping has the potential to develop voids and pockets of entrained air. Maintaining the pump discharge lines of the required ECCS injection/spray subsystems full of water ensures that the ECCS subsystem will perform properly. This may also prevent a water hammer following an ECCS actuation. One acceptable method of ensuring that the lines are full is to vent at the high points.

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

SR 3.5.2.4

[DELETED]

B 3.5-24 02/02/22

BASES RPV Water Inventory Control B 3.5.2 SURVEILLANCE REQUIREMENTS ( continued)

SR 3.5.2.5 Cooper Verifying that the required ECCS injection/spray subsystem can be manually aligned, and the pump started and operated for at least 10 minutes demonstrates that the subsystem is available to mitigate a draining event. This SR is modified by two Notes. Note 1 states that testing the ECCS injection/spray subsystem may be done through the test return line to avoid overfilling the refueling cavity. Note 2 states that credit for meeting the SR may be taken for normal system operation that satisfies the SR, such as using the RHR mode of LPCI for~ 10 minutes.

The minimum operating time of 10 minutes was based on engineering judgement.

TS 3.5.1, "ECCS - Operating," which is applicable in MODES 1, 2, and 3, contains SR 3.5.1. 7, SR 3.5.1.8, and SR 3.5.1.9, which require verification that the ECCS pumps develop the specified flow rate. It is not necessary to perform similar flow rate tests during the relatively small fraction of an operating cycle when the plant is in MODES 4 and 5 to ensure the pumps are capable of maintaining water level above the TAF.

Most RPV penetration flow paths would only permit a drain rate of tens or hundreds of gallons per minute. Therefore, the thousands of gallons a minute flow rates specified in the TS 3.5.1 SRs are not needed to mitigate an unexpected draining event. There are no safety analyses which establish a minimum pump flow needed to respond to an unexpected draining event. Therefore, there is no basis for establishing a minimum flow rate for the SR that is consistent with the specified safety function in MODES 4 and 5. (Reference 7)

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

SR 3.5.2.6 Verifying that each valve credited for automatically isolating a penetration flow path (e.g., RHR, RWCU) actuates to the isolation position on an actual or simulate RPV water level isolation signal is required to prevent RPV water inventory from dropping below the TAF should an unexpected draining event occur.

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

B 3.5-25 02/02/22

BASES RPV Water Inventory Control B 3.5.2 SURVEILLANCE REQUIREMENTS (continued)

SR 3.5.

2.7 REFERENCES

Cooper This Surveillance verifies that a required CS or LPCI subsystem can be manually aligned and started from the control room, including any necessary valve alignment, instrumentation, or controls, to transfer water from the suppression pool to the RPV.

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

Information Notice 84-81, "Inadvertent Reduction in Primary Coolant Inventory in Boiling Water Reactors During Shutdown and Startup," November 1984.

2.

Information Notice 86-74, "Reduction of Reactor Coolant Inventory Because of Misalignment of RHR Valves," August 1986.

3.

Generic Letter 92-04, "Resolution of the Issues Related to Reactor Vessel Water Level Instrumentation in BWRs Pursuant to 10 CFR 50.54(F)," August 1992.

4.

NRC Bulletin 93-03, "Resolution of Issues Related to Reactor Vessel Water Level Instrumentation in BWRs," May 1993.

5.

Information Notice 94-52, "Inadvertent Containment Spray and Reactor Vessel Draindown at Millstone 1," July 1994.

6.

General Electric Service Information Letter No. 388, "RHR Valve Misalignment During Shutdown Cooling Operation for BWR 3/4/5/6," February 1983.

7.

TSTF-542, Revision 2, "Reactor Pressure Vessel Water Inventory Control," December 20, 2016.

B 3.5-26 02/02/22

BASES PCIVs B 3.6.1.3 APPLICABLE SAFETY ANALYSES (continued)

LCO Cooper 5 second closure time is conservative with respect to the 5.5 second closure time assumed in the High Energy Line Break analysis (Refs. 2 and 3). The 3 second closure time is assumed in the MSIV closure (the most severe overpressurization transient) analysis (Ref. 4). Likewise, it is assumed that the primary containment is isolated such that release of fission products to the environment is controlled.

The single failure criterion required to be imposed in the conduct of unit safety analyses was considered in the original design of the primary containment purge and vent valves. Two valves in series on each purge and vent line provide assurance that both the supply and exhaust lines could be isolated even if a single failure occurred.

PCIVs satisfy Criterion 3 of 1 O CFR 50.36 (c)(2)(ii) (Ref. 5).

PCIVs form a part of the primary containment boundary. The PCIV safety function is related to minimizing the loss of reactor coolant inventory and establishing the primary containment boundary during a OBA.

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

The inboard 24 inch purge and vent valves are blocked to prevent full opening. While the reactor building-to-suppression chamber vacuum breakers isolate primary containment penetrations, they are excluded from this Specification. Controls on their isolation function are adequately addressed in LCO 3.6.1. 7, "Reactor Building-to-Suppression Chamber Vacuum Breakers." The valves covered by this LCO are listed with their associated stroke times in Reference 6.

The normally closed PCIVs are considered OPERABLE when manual valves are closed or open in accordance with appropriate administrative controls, automatic valves are de-activated and secured in their closed position, and blind flanges are in place. These passive isolation valves and devices are those listed in Reference 7.

B 3.6-17 03/31/21

BASES LCO (continued)

APPLICABILITY ACTIONS Cooper SGT System B 3.6.4.3 MSIVs must meet additional leakage rate requirements. Other PCIV leakage rates are addressed by LCO 3.6.1.1, "Primary Containment," as Type B or C testing.

This LCO provides assurance that the PCIVs will perform their designed safety functions to minimize the loss of reactor coolant inventory and establish the primary containment boundary during accidents.

In MODES 1, 2, and 3, a DBA could cause a release of radioactive material to primary containment. In MODES 4 and 5, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, PCIVs are not required to be OPERABLE and the primary containment purge and vent valves are not required to be normally closed in MODES 4 and 5.

The ACTIONS are modified by a Note allowing penetration flow path(s) to be unisolated intermittently under administrative controls. 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 primary containment isolation is indicated.

A second Note has been added to provide 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 PCIV. Complying with the Required Actions may allow for continued operation, and subsequent inoperable PCIVs are governed by subsequent Condition entry and application of associated Required Actions.

B 3.6-18 02/02/22

BASES ACTIONS (continued)

E.1 and E.2 PCIVs B 3.6.1.3 If any Required Action and associated Completion Time cannot be met the plant must be brought to 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 3.6.1.3.1 Cooper This SR ensures that the 24 inch primary containment purge and vent valves are closed as required or, if open, open for an allowable reason. If a purge or vent valve is open in violation of this SR, the valve is considered inoperable. The SR is modified by Note 1 stating that the SR is not required to be met when the purge and vent valves are open for the stated reasons. Note 1 states that these valves may be opened in one supply line and one exhaust line for inerting, de-inerting, pressure control, ALARA or air quality considerations for personnel entry, or Surveillances that require the valves to be open. Note 2 modifies the SR by requiring both Standby Gas Treatment (SGT) subsystems OPERABLE and only one SGT subsystem operating when these purge and vent valves are open in accordance with Note 1.

B 3.6-23 02/02/22

BASES ACTIONS Cooper AC Sources - Operating B 3.8.1 A Note prohibits the application of LCO 3.0.4.b to an inoperable DG.

There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.

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

Required Action A.2, which only applies if the division cannot be powered from an offsite source, is intended to provide assurance that an event with a coincident single failure of the associated DG does not result in a complete loss of safety function of critical redundant required systems.

These redundant required features are those that are assumed to function to mitigate an accident, coincident with a loss of offsite power, in the safety analyses, such as the Emergency Core Cooling System.

These redundant required features do not include monitoring requirements, such as Post Accident Monitoring and Remote Shutdown.

These features are designed with redundant safety related divisions (i.e.,

single division systems are not included). Redundant required features failures consist of inoperable features associated with a division redundant to the division that has no offsite power.

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

a.

The division has no offsite power supplying its loads; and

b.

A redundant required feature on the other division is inoperable.

B 3.8-6 03/31/21

BASES ACTIONS (continued)

Cooper AC Sources - Operating B 3.8.1 If, at any time during the existence of this Condition (one offsite circuit inoperable) a redundant required feature subsequently becomes inoperable, this Completion Time would begin to be tracked.

Discovering no offsite power to one 4.16 kV critical bus of the onsite Class 1 E Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with any other Class 1 E bus that has offsite power, results in starting the Completion Times for the Required Action. Twenty-four hours is acceptable because it minimizes risk while allowing time for restoration before the unit is subjected to transients associated with shutdown.

The remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System. Thus, on a component basis. single failure protection may have been lost for the required feature's function; however, function is not lost. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a OBA occurring during this period.

The 4.16 kV critical bus design and loading is sufficient to allow operation to continue in Condition A for a period that should not exceed 7 days.

With one offsite circuit inoperable. the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the plant safety systems. In this condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1 E Distribution System.

The 7 day Completion Time takes into account the redundancy, capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a DBA occurring during this period.

The second Completion Time for Required Action A.3 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition A is entered while, for instance, a DG is inoperable, and that DG is subsequently returned OPERABLE, the LCO may already have been not met for up to 7 days. This situation could lead to a total of 14 days, since initial failure to meet the LCO, to B 3.8-7 03/31/21

BASES ACTIONS (continued)

Cooper AC Sources - Operating 8 3.8.1 restore the offsite circuit. At this time, a DG could again become inoperable, the circuit restored OPERABLE, and an additional 7 days (for a total of 21 days) allowed prior to complete restoration of the LCO. The 14 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and 8 are entered concurrently. The "AND" connector between the 7 day and 14 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive Completion Time must be met.

Similar to Required Action A.2, the second Completion Time of Required Action A.3 allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time the LCO was initially not met, instead of at the time that Condition A was entered.

8.1 To ensure a highly reliable power source remains with one DG inoperable, it is necessary to verify the availability of the offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions must then be entered.

8.2 Required Action 8.2 is intended to provide assurance that a loss of offsite power, during the period that a DG is inoperable, does not result in a complete loss of safety function of critical redundant required features.

These redundant required features are those that are assumed to function to mitigate an accident, coincident with a loss of offsite power, in the safety analyses, such as the Emergency Core Cooling System.

These redundant required features do not include monitoring requirements, such as Post Accident Monitoring and Remote Shutdown.

Redundant required features failures consist of inoperable features associated with a division redundant to the division that has an inoperable DG.

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 8 3.8-8 03/31/21

BASES AC Sources ~ Operating B 3.8.1 ACTIONS ( continued)

Cooper allowed outage time "clock." In this Required Action the Completion Time only begins on discovery that both:

a.

An inoperable DG exists; and

b.

A redundant required feature on the other division is inoperable.

If, at any time during the existence of this Condition (one DG inoperable),

a redundant required feature subsequently becomes inoperable, this Completion Time begins to be tracked.

The Control Room Emergency Filter System (CREFS) is a single train system that has required redundant features consisting of a supply fan, and a manual transfer switch for aligning the emergency booster fan and the exhaust booster fan to one energized critical bus capable of being powered from an OPERABLE diesel generator. Compliance with B.2 requires ensuring the redundant supply fan is in service, and manual transfer switch alignment of the other fans to the redundant critical bus within the 4-hour Completion Time.

Discovering one DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DG results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing time for restoration before subjecting the station to transients associated with shutdown.

The remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1 E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature.

Additionally, the 4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources1 reasonable time for repairs, and low probability of a OBA occurring during this period.

B.3.1 and B.3.2 Required Action B.3.1 provides an allowance to avoid unnecessary testing of OPERABLE DGs. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on other B 3.8-9 03/31/21

BASES ACTIONS (continued)

Cooper AC Sources - Operating B 3.8.1 DG(s), they are declared inoperable upon discovery, and Condition E of LCO 3.8.1 is entered. Once the failure is repaired, and the common cause failure no longer exists, Required Action 8.3.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG, performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of the remaining DG. In the event the inoperable DG is restored to OPERABLE status prior to completing either 8.3.1 or B.3.2, the plant corrective action program will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months constraint imposed while in Condition B.

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

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

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

The second Completion Time for Required Action B.4 establishes a limit on the maximum time allowed for any combination of required AC power sources to be inoperable during any single contiguous occurrence of failing to meet the LCO. If Condition Bis entered while, for instance, an offsite circuit is inoperable and that circuit is subsequently restored OPERABLE, the LCO may already have been not met for up to 7 days.

This situation could lead to a total of 14 days, since initial failure of the LCO, to restore the DG. At this time, an offsite circuit could again become inoperable, the DG restored OPERABLE, and an additional 7 days (for a total of 21 days) allowed prior to complete restoration of the LCO. The 14 day Completion Time provides a limit on the time allowed in a specified condition after discovery of failure to meet the LCO. This limit is considered reasonable for situations in which Conditions A and B are entered concurrently. The "AND" connector between the 7 day and 14 B 3.8-10 03/31/21

BASES ACTIONS (continued)

Cooper AC Sources - Operating B 3.8.1 day Completion Times means that both Completion Times apply simultaneously, and the more restrictive must be met.

Similar to Required Action B.2, the second Completion Time of Required Action B.4 allows for an exception to the normal '1time zero" for beginning the allowed outage time "clock." This exception results in establishing the "time zero" at the time that the LCO was initially not met, instead of the time that Condition B was entered.

C.1 and C.2 Required Action C.1, which applies when two offsite circuits are inoperable, is intended to provide assurance that an event with a coincident single failure will not result in a complete loss of critical redundant required features. These redundant required features are those that are assumed to function to mitigate an accident, coincident with a loss of offsite power, in the safety analyses, such as the Emergency Core Cooling System. These redundant required features do not include monitoring requirements, such as Post Accident Monitoring and Remote Shutdown. These features are designed with redundant safety related divisions, (i.e., single division systems are not included in the list). Redundant required features failures consist of any of these features that are inoperable because any inoperability is on a division redundant to a division with inoperable offsite circuits. The Completion Time for taking these actions is reduced to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months from that allowed with one division without offsite power (Required Action A.2). The rationale for the reduction to 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is that Regulatory Guide 1.93 (Ref.

8) allows a Completion Time of 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months for two required offsite circuits inoperable, based upon the assumption that two complete safety divisions are OPERABLE. When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months is appropriate.

The Completion Time for Required Action C.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:

a.

Both offsite circuits are inoperable; and

b.

A redundant required feature is inoperable.

B 3.8-11 03/31/21

BASES ACTIONS (continued)

Cooper AC Sources - Operating B 3.8.1 If, at any time during the existence of this Condition (both offsite circuits inoperable), a redundant required feature subsequently becomes inoperable, this Completion Time begins to be tracked.

According to the recommendations in Regulatory Guide 1.93 (Ref. 8),

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

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

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

a.

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

b.

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

With both of the offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a DBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time in Required Action C.2 provides a period of time to effect restoration of one of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria.

According to the recommendations in Regulatory Guide 1.93 (Ref. 8),

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

B 3.8-12 03/31/21

BASES ACTIONS (continued)

Cooper D.1 and D.2 AC Sources - Operating 8 3.8.1 Pursuant to LCO 3.0.6, the Distribution Systems - Operating ACTIONS would not be entered even if all AC sources to it were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition D are modified by a Note to indicate that when Condition D is entered with no AC source to any 4.16 kV critical bus, ACTIONS for LCO 3.8. 7, "Distribution Systems - Operating," must be immediately entered. This allows Condition D to provide requirements for the loss of the offsite circuit and one DG without regard to whether a division is de-energized.

LCO 3.8.7 provides the appropriate restrictions for a de-energized 4.16 kV critical bus.

In Condition D, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the reliability of the power systems in this Condition may appear higher than that in Condition C (loss of both offsite circuits). This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months Completion Time takes into account the capacity and capability of the remaining AC sources, reasonable time for repairs, and the low probability of a DBA occurring during this period.

With two DGs inoperable, there is no remaining standby AC source.

Thus, with an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions.

Since the offsite electrical power system is the only source of AC power for the majority of ESF equipment at this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown. (The immediate shutdown could cause grid instability, which could result in a total loss of AC power.) Since any inadvertent unit generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted. The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation. According to the recommendations in Regulatory Guide 1.93 (Ref. 8), with both DGs inoperable, operation may continue for a period that should not exceed 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months .

B 3.8-13 03/31/21

BASES AC Sources - Operating 8 3.8.1 ACTIONS (continued)

F.1 and F.2 If the inoperable AC electrical power sources cannot be restored to OPERABLE status within the associated Completion Time, the unit must be brought to a MODE in which the LCO does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 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.

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

SURVEILLANCE REQUIREMENTS Cooper The AC sources are designed to permit inspection and testing of all important areas and features, especially those that have a standby function. Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulated accident conditions). The SRs for demonstrating the OPERABILITY of the DGs are in general conformance with the recommendations of Regulatory Guide 1.9 (Ref. 9), Regulatory Guide 1.108 (Ref. 10), and Regulatory Guide 1.137 (Ref. 11 ).

The minimum steady state output voltage of 3950 V is approximately 95%

of the nominal 4160 V output voltage. This value, which is consistent with ANSI C84.1 (Ref. 12), allows for voltage drop to the terminals of 4000 V motors whose minimum operating voltage is specified as 90% or 3600 V.

It also allows for voltage drops to motors and other equipment down through the 120 V level where minimum operating voltage is also usually specified as 90% of name plate rating. The specified maximum steady state output voltage of 4400 V is equal to the maximum operating voltage specified for 4000 V motors. It ensures that for a lightly loaded distribution system, the voltage at the terminals of 4000 V motors is no more than the maximum rated operating voltages. The specified minimum and maximum frequencies of the DG are 58.8 Hz and 61.2 Hz, B 3.8-14 03/31/21

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

Cooper respectively. These values are equal to +/- 2% of the 60 Hz nominal frequency and are derived from the recommendations found in Safety Guide 9 (Ref. 3).

SR 3.8.1.1 This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to their preferred power source and that appropriate independence of offsite circuits is maintained. This can be accomplished by verifying that a critical bus is energized and that the status of offsite supply breakers displayed in the control room is correct. The Surveillance Frequency is controlled under the Surveillance Frequency Control Program.

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

To minimize the wear on moving parts that do not get lubricated when the engine is not running, these SRs have been modified by a Note (Note 2 for SR 3.8.1.2 and Note 1 for SR 3.8.1.7) to indicate that all DG starts for these Surveillances may be preceded by an engine prelube period and (only for SR 3.8.1.2) followed by a warmup prior to loading.

For the purposes of this testing, the DGs are manually started from standby conditions. Standby condiUons for a DG mean that the diesel engine coolant and oil are being periodically circulated and temperature is being maintained consistent with manufacturer recommendations.

In order to reduce stress and wear on diesel enginesJ the manufacturer recommends a modified start in which the starting speed of DGs is limited, warmup is limited to this lower speed, and the DGs are gradually accelerated to synchronous speed prior to loading. These start procedures are the intent of Note 3 to SR 3.8.1.2, which is only applicable when such modified start procedures are recommended by the manufacturer.

B 3.8-15 03/31/21

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

Cooper SR 3.8.1.7 requires that the DG starts from standby conditions and achieves required voltage and frequency within 14 seconds. The minimum voltage and frequency stated in the SR are those necessary to ensure the DG can accept DBA loading while maintaining acceptable voltage and frequency levels. Stable operation at the nominal voltage and frequency values is also essential to establishing DG OPERABILITY, but a time constraint is not imposed. This is because a typical DG will experience a period of voltage and frequency oscillations prior to reaching steady state operation if these oscillations are not dampened by load application. This period may be extended beyond the 14 second acceptance criterion and could be cause for failing the SR. In lieu of a time constraint in the SR, monitoring and trending of the actual time to reach steady state operation will be performed as a means of ensuring there is no voltage regulator or governor degradation which could cause a DG to become inoperable. The 14 second start requirement supports the assumptions in the design basis LOCA analysis of USAR, Section Vlll-5.2 (Ref. 13). The 14 second start requirement is not applicable to SR 3.8.1.2 (see Note 3 of SR 3.8.1.2), when a modified start procedure as described above is used. If a modified start is not used, the 14 second start requirement of SR 3.8.1. 7 applies.

Since SR 3.8.1.7 does require a 14 second start, it is more restrictive than SR 3.8.1.2, and it may be performed in lieu of SR 3.8.1.2. This procedure is the intent of Note 1 of SR 3.8.1.2.

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

SR 3.8.1.3 This Surveillance provides assurance that the DGs are capable of synchronizing and accepting greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.

Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0 while synchronized to the grid. Since the generator is rated at a particular KVA at 0.8 power factor, the 0.8 value is the design rating of the machine.

The 1.0 value is an operational condition where the reactive power component is zero, which minimizes the reactive heating of the generator.

Operating the generator at a power factor between 0.8 lagging and 1.0 avoids adverse conditions associated with underexciting the generator B 3.8-16 03/31/21

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

Cooper and more closely represents the generator operating requirements when performing its safety function (running isolated on its associated critical bus). Because each DG is rated at 4000 kW at 0.8 power factor (pf), the required load band is ~ 3600 kW at c!: 0.8 pf (~ 90% of rated load, in accordance with Regulatory Guide 1.9, Ref. 9) and less than or equal to rated load. This load band brackets the maximum expected accident loads. The load band is provided to avoid routine overloading of the DG.

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

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

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

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

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

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

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

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

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

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

B 3.8-17 03/31/21

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

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

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

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

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

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

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

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

8 3.8-18 03/31/21

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

SR 3.8.1.9 Cooper Consistent with IEEE 387-1995 (Ref. 15), Section 7.5.9 and Table 3, this SR requires demonstration that the DGs can start and run continuously at ful I load capability for an interval of not less than 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months - 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months of which is at a load equivalent to 90-100% of the continuous rating of the DG, and 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months of which is at a load equivalent to 105% to 110% of the continuous duty rating of the DG. The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelube and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.

A load band of 90-100% accident load is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. Generator loadings less than 90%

occurring during the first 1 O seconds of accident loading are bounded by the test conditions of 90 to 100% load and are well within the generator capability curves.

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

This Surveillance has been modified by three Notes. Note 1 states that momentary transients due to changing bus loads do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test. The reason for Note 2 is that during operation with the reactor critical, performance of this Surveillance could cause perturbations to the electrical distribution systems that would challenge continued steady state operation and, as a result, plant safety systems.

Note 3 ensures that the DG is tested under load conditions that are as close to worst case design basis conditions as possible. When synchronized with offsite power, testing should be performed at a power factor of :s 0.89. This power factor is representative of the actual inductive loading a DG would see under design basis accident conditions. Under certain conditions, however, Note 3 allows the surveillance to be conducted at a power factor other than :s 0.89. These conditions occur when grid voltage is high, and the additional field excitation needed to obtain a power factor of :s 0.89 results in voltages on the emergency busses that are too high. Under these conditions, the power factor should be maintained as close as practicable to 0.89 while still maintaining acceptable voltage limits on the emergency busses. In other circumstances, the grid voltage may be such that the DG excitation levels needed to obtain a power factor of 0.89 may not cause unacceptable voltages on the emergency busses, but the excitation levels are in excess of those recommended for the DG. In such cases, the B 3.8-19 03/31/21

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

Cooper power factor shall be maintained as close as practicable to 0.89 without exceeding the DG excitation limits. Credit may be taken for unplanned events that satisfy this SR.

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

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

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

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

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

SR 3.8.1.11 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.

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

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

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

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

B 3.8-20 03/31/21

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

REFERENCES Cooper The requirement to verify the connection and power supply of permanent and auto-connected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, Emergency Core Cooling Systems (ECCS) injection valves are not desired to be stroked open, or systems are not capable of being operated at full flow. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.

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

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

1.

USAR, Section Vlll-1.0.

2.

USAR, Section Vlll-2.0 and Vlll-3.0.

3.

Safety Guide 9, Revision 0, March 1971.

4.

USAR, Chapter VI.

5.

USAR, Chapter XIV.

6.

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

7.

Generic Letter 84--15.

8.

Regulatory Guide 1.93.

9.

Regulatory Guide 1.9, Revision 3, July 1993.

10.

Regulatory Guide 1.108.

B 3.8-21 03/31/21

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

LCO Cooper controlled. Relaxations from typical MODES 1, 2, and 3 LCO requirements are acceptable during shutdown MODES, based on:

a.

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

b.

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

c.

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

d.

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

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

The AC sources satisfy Criterion 3 of 10 CFR 50.36(c)(2)(ii) (Ref. 1 ).

One offsite circuit supplying the onsite Class 1 E power distribution subsystem(s) of LCO 3.8.8, "Distribution Systems - Shutdown," ensures that all required loads are powered from offsite power. An OPERABLE DG, associated with a 4.16 kV critical bus required OPERABLE by LCO 3.8.8, ensures that a diverse power source is available for providing electrical power support assuming a loss of the offsite circuit. Together, OPERABILITY of the required offsite circuit and the ability to manually start a DG ensures the availability of sufficient AC sources to operate the plant in a safe manner and to mitigate the consequences of postulated events during shutdown (e.g., fuel handling accidents).

The qualified offsite circuit must be capable of maintaining rated frequency and voltage while connected to its respective critical bus, and of accepting required loads during an accident. Qualified offsite circuits are those that are described in the USAR and are part of the licensing basis for the unit. The offsite circuit consists of incoming breaker and B 3.8-24 02/02/22

BASES LCO (continued)

APPLICABILITY Cooper AC Sources - Shutdown B 3.8.2 disconnect to the startup or emergency station service transformer, associated startup or emergency station service transformer, and the respective circuit path including feeder breakers to all 4.16 kV critical buses required by LCO 3.8.8.

The required DG must be capable of being manually started, accelerating to rated speed and voltage, connecting to its respective critical bus, and accepting required loads.

It is acceptable during shutdown conditions, for a single offsite power circuit to supply both 4.16 kV critical buses. No fast transfer capability is required for offsite circuits to be considered OPERABLE.

The AC sources are required to be OPERABLE in MODES 4 and 5 and during movement of irradiated fuel assemblies in the secondary containment to provide assurance that:

a.

Systems that provide core cooling are available;

b.

Systems needed to mitigate a fuel handling accident are available;

c.

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

d.

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

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

B 3.8-25 02/02/22

BASES ACTIONS (continued)

AC Sources - Shutdown B 3.8.2 The Completion Time of immediately is consistent with the required times for actions requiring prompt attention. The restoration of the required AC electrical power sources should be completed as quickly as possible in order to minimize the time during which the plant safety systems may be without sufficient power.

Pursuant to LCO 3.0.6, the Distribution System ACTIONS would not be entered even if all AC sources to it are inoperable, resulting in de-energization. Therefore, the Required Actions of Condition A have been modified by a Note to indicate that when Condition A is entered with no AC power to any required 4.16 kV critical bus, ACTIONS for LCO 3.8.8 must be immediately entered. This Note allows Condition A to provide requirements for the loss of the offsite circuit whether or not a division is de-energized. LCO 3.8.8 provides the appropriate restrictions for the situation involving a de-energized division.

SURVEILLANCE REQUIREMENTS SR 3.8.2.1 Cooper SR 3.8.2.1 requires the SRs from LCO 3.8.1 that are necessary for ensuring the OPERABILITY of the AC sources in other than MODES 1, 2, and 3. SR 3.8.1.8 is not required to be met since only one offsite circuit is required to be OPERABLE. SR 3.8.1. 7, SR 3.8.1.10 and SR 3.8.1.11 are not required to be met because DG start and load within a specified time and response on a loss of offsite power or ECCS initiation signal is not required. Refer to the corresponding Bases for LCO 3.8.1 for a discussion of each SR This SR is modified by a Note which precludes requiring the OPERABLE DG(s) from being paralleled with the offsite power network or otherwise rendered inoperable during the performance of SRs, and to preclude deenergizing a required 4.16 kV critical bus or disconnecting a required offsite circuit during performance of SRs. With limited AC sources available, a single event could compromise both the required circuit and the DG. It is the intent that these SRs must still be capable of being met, but actual performance is not required during periods when the DG and offsite circuit is required to be OPERABLE.

B 3.8-27 02/02/22

BASES REFERENCES

1.

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

B 3.8-28 Distribution Systems - Shutdown B 3.8.8 02/02/22

NLS2023007, Technical Specification Bases Changes

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