ML24296A047

Submittal of Updated Final Safety Analysis Report (Revision 24), Technical Specification Bases Revisions, Ufsar/Selected Licensee Commitment Changes, 10 CFR 50.59 Evaluation Summary Report, and Notification of

ML24296A047
Person / Time
Site:	Catawba
Issue date:	10/22/2024
From:	Flippin N Duke Energy Carolinas
To:	Office of Nuclear Reactor Regulation, Document Control Desk
Shared Package
ML24296A046	List: ML24296A047 RA-24-0191, Updated Final Safety Analysis Report (Revision 24)
References
RA-24-0191
Download: ML24296A047 (1)

Text

Nicole Flippin Vice President Catawba Nuclear Station Duke Energy CN01VP I 4800 Concord Road York, SC 29745 o: 803.701.3340 nicole.flippin@duke-energy.com SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED 10 CFR 50.4 10 CFR 50.71(e) 10 CFR 50.59 Serial: RA-24-0191 October 22, 2024 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Catawba Nuclear Station, Units 1 and 2 Docket Nos. 50-413 and 50-414, Renewed License Nos. NPF-35 and NPF-52

Subject:

Submittal of Updated Final Safety Analysis Report (Revision 24),

Technical Specification Bases Revisions, UFSAR/Selected Licensee Commitment Changes, 10 CFR 50.59 Evaluation Summary Report, and Notification of a Commitment Change Ladies and Gentlemen:

Pursuant to 10 CFR 50.71(e), Duke Energy Carolinas, LLC (Duke Energy) hereby submits Revision 24 to the Updated Final Safety Analysis Report (UFSAR) for the Catawba Nuclear Station (CNS), Units 1 and 2. In accordance with 10 CFR 50.71(e)(4), this UFSAR revision is being submitted within six months following the most recent refueling outage, which concluded on April 14, 2024. Enclosure 1 provides a copy of the UFSAR that has been redacted for public use. Enclosure 2 provides a copy of the UFSAR that contains sensitive information to be withheld from public disclosure per 10 CFR 2.390(d)(1). Changes made since Revision 23 are identified by vertical lines in the margins of the pages that are indicated as Revision 24.

In accordance with 10 CFR 50.59(d)(2), Duke Energy is providing a report summarizing the 10 CFR 50.59 evaluations of changes, tests, and experiments implemented during the period from March 9, 2023 to May 15, 2024 for CNS. This report is included in Enclosure 3.

Pursuant to 10 CFR 50.4, Duke Energy is providing the CNS Technical Specification Bases changes that were made according to the provisions of Technical Specification 5.5.14, Technical Specifications (TS) Bases Control Program. Enclosure 4 contains the TS Bases Insertion/Removal Instructions, the TS List of Effective Pages (LOEP) and Bases Replacement Pages.

Additionally, in accordance with 10 CFR 50.71(e), Duke Energy is providing the changes made

r. DUKE

• ~ ENERGY

SECURITY-RELATED INFORMATION -WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED U.S. Nuclear Regulatory Commission RA-24-0191 Page 2 to the CNS Selected Licensee Commitments (SLC) Manual since April 24, 2023. These changes are located in Enclosure 5. The CNS SLC manual constitutes Chapter 16 of the UFSAR.

In addition, in accordance with NEI 99-04, Guidelines for Managing NRC Commitments, no regulatory commitment changes have been made since the previous UFSAR submittal on April 24, 2023.

There are no new regulatory commitments contained in this letter.

If you have any questions regarding this submittal, please contact Ryan Treadway, Director -

Fleet Licensing, at (980) 373-5873.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on October 22, 2024.

Sincerely,

~

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Nicole Flippin Vice President, Catawba Nuclear Station

Enclosures:

1. Catawba Nuclear Station Updated Final Safety Analysis Report Update - Rev 24 Redacted Version (Publicly Available Information)

2. Catawba Nuclear Station Updated Final Safety Analysis Report Update - Rev 24 (Non-Publicly Available Information)

3. Catawba Nuclear Station 10 CFR 50.59 Evaluation Summary Report

4. Catawba Nuclear Station Technical Specification (TS) Bases Changes

5. Catawba Nuclear Station Selected Licensee Commitments (SLC) Manual Changes

Attachment:

Report of Information Removed from the Revision 24 of the Catawba Nuclear Station UFSAR SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED

U.S. Nuclear Regulatory Commission RA-24-0191 Page 3 SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED xc:

L. Dudes, USNRC Region II - Regional Administrator D. Rivard, USNRC Senior Resident Inspector - CNS S. Williams, USNRC NRR Project Manager - CNS & ONS J. Minzer-Bryant, USNRC NRR Project Manager - CNS

U.S. Nuclear Regulatory Commission RA-24-0191 October 22, 2024 Catawba Nuclear Station Updated Final Safety Analysis Report Update - Rev 24 Redacted Version (Publicly Available Information)

SECURITY-RELATED INFORMATION -WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED SECURITY-RELATED INFORMATION -WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED

U.S. Nuclear Regulatory Commission RA-24-0191 October 22, 2024 Catawba Nuclear Station Updated Final Safety Analysis Report Update - Rev 24 (Non-Publicly Available Information)

SECURITY-RELATED INFORMATION -WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED SECURITY-RELATED INFORMATION -WITHHOLD UNDER 10 CFR 2.390(d)

UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED

U.S. Nuclear Regulatory Commission RA-24-0191 October 22, 2024 Catawba Nuclear Station 10 CFR 50.59 Evaluation Summary Report

U.S. Nuclear Regulatory Commission RA-24-0191, Enclosure 3 Page 1 of 3 Summary of 10 CFR 50.59 Evaluations

Title:

UFSAR Section 9.1.5.4.1 Revision to Permit Acoustic Emission NDE for the Reactor Vesel Head Lifting Rig and the Reactor Internals Lifting Rig Documentation Number(s):

Action Request (AR) 02483558 Brief

Description:

Catawba UFSAR Section 9.1.5.4.1(4) designates the Reactor Vessel Head Lifting Rig and the Reactor Internals Lifting Rig as Special Lifting Devices subject to ANSI N14.6-1978, Standard for Special Lifting Devices for Shipping Containers Weighing 10,000 Pounds (4500 kg) or More for Nuclear Material ANSI N14.6-1978 Section 5.5.1 requires inspections utilizing liquid penetrant or magnetic particle examination. Acoustic Emission (AE) testing is not discussed in ANSI N14.6-1978.

The Duke fleet is inconsistent in the NDE methods performed for the special lift rigs. G.O.

Programs Inspections initiated AR 02469454 which states in part:

In addition, the NDE Methods utilized across the fleet are not consistent as some sites are performing Acoustic Emissions testing while others are performing surface examinations utilizing visual and ultrasonic methods. This fleet difference has been previously identified during Fleet Outage Review Boards. Evaluate Current Licensing Basis (CLB) for NUREG-0612 and revise as necessary to allow Acoustic Emissions (AE)

NDE (Note: ONS, RNP, HNP utilize AE. Need to confirm AE meets site CLB).

Acoustic Emission is referenced in the Robinson and Oconee UFSAR Sections 9.1.5.5 and 9.1.5.4.1, respectively. The Harris UFSAR does not reference AE. Oconee revised its UFSAR in 2019 to permit AE (UFSAR Change Package 18-016, 5AD AR 02252422, 5SCR AR 02246773, 5EVAL AR 02246774).

Because Catawba committed to NUREG-0612, and by extension to ANSI N14.6-1978, performing AE is a revision to the NDE methods permitted by ANSI N14.6-1978 Section 5.5.1.

Catawba UFSAR Section 9.1.5.4.1(4) Special Lifting Devices will be revised to add For the reactor vessel head lifting rig and the reactor internals lifting rig, Acoustic Emission testing is a permitted inspection method as an alternative to the nondestructive testing specified in ANSI N14.6-1978. The same UFSAR Section will be revised to delete the sentence referencing the deleted legacy document, Duke Energy Nuclear Lifting Program Manual. A replacement sentence is not needed to exhibit Catawbas commitment to compliance with NUREG-0612.

Additionally, an editorial statement is being added to document that the NRC issued "Synopsis of Issues Associated With NUREG 0612" (ADAMS Accession Number ML20024A008) to provide Approaches Consistent With This Guideline."

From this evaluation it is concluded that the change can be implemented under 10CFR 50.59 without prior approval from the NRC.

U.S. Nuclear Regulatory Commission RA-24-0191 Enclosure 3 Page 2 of 3 Summary of 10 CFR 50.59 Evaluations

Title:

Dose updates to CNS UFSAR Table 15-14 Documentation Number(s):

Action Request (AR) 02484183 Brief

Description:

A set of updates to the Catawba Nuclear Station (CNS) Updated Final Safety Analysis Report (UFSAR) has been prepared for the UFSAR table documented in License Document Change Request (LDCR) number 2023-CNS-014 to correct errors in the Chapter 15 dose values documented in Reference 1. The focus of this 10 CFR 50.59 Evaluation is to determine if the revised dose values for the affected accident types require prior Nuclear Regulatory Commission (NRC) approval for CNS to implement.

Reference 1 was written to document errors in References 2 and 3 in the computer code input.

These errors were introduced into the software application LOCADOSE and were not the result of errors in the original source term calculation. Specifically, the following errors were noted:

• Reference 2, Radwaste Tank Failures (RTF): Liquid Radwaste Tank Failures (LRTF) o Iodine-134: 76.91 Ci used instead of 7.691 Ci correct o Xenon-135: 314.4 Ci used instead of 3144 Ci correct

• Reference 3, Loss of Coolant Accident (LOCA) o Praseodymium-144m: 268 Ci used instead of 286 Ci correct o Xenon-138: 1.45E7 Ci used instead of 1.45E8 Ci correct o Tellurium-132: 5.72E12 used instead of 5.73E12 Ci correct Table 15-14 of Reference 4 is updated to correct the input errors from revisions to References 2 and 3. The correction of these errors will result in the following changes to the Total Effective Dose Equivalent (TEDE) in the Exclusion Area Boundary (EAB), Low Population Zone (LPZ),

and Main Control Room (MCR) doses:

LRTF:

• EAB increase from 0.99 Rem to 1.08 Rem

• LPZ increase from 0.14 Rem to 0.15 Rem

• MCR increase from 1.00 Rem to 1.06 Rem LOCA:

• EAB increase from 8.79 Rem to 8.81 Rem

• LPZ increase from 3.78 Rem to 3.79 Rem

• MCR remains unchanged These increases remain well within the applicable regulatory acceptance criteria. An extent of condition review was performed by checking the other Catawba Nuclear Page: 2 Body Page 2 of 9 Station (CNS) Chapter 15 accidents. No other issues were noted for the rest of the CNS UFSAR Chapter 15 design basis accidents.

The activity under assessment here is the update to CNS UFSAR Table 15-14. This activity is assessed pursuant to industry guidelines (Ref. 6) endorsed by the NRC (Ref. 7), and pursuant

U.S. Nuclear Regulatory Commission RA-24-0191 Enclosure 3 Page 2 of 3 to the associated Duke Energy procedure (Ref. 8). The activity concludes it does not screen out from the requirements of a full evaluation pursuant to 10 CFR 50.59 (Ref. 9).

As such, this activity constitutes changes to input parameters, and not to a method of evaluation. From the discussion above, it is evident the proposed activity does not result in a departure from or revision to a method of evaluation described in the UFSAR used in establishing the design bases or in the safety analyses.

From this evaluation it is concluded that the change can be implemented under 10CFR 50.59 without prior approval from the NRC.

U.S. Nuclear Regulatory Commission RA-24-0191 October 22, 2024 Summary of 10 CFR 50.59 Evaluations

Title:

Main Power Protective Relaying Upgrade Documentation Number(s):

Action Request (AR) 02516279 Brief

Description:

Due to revisions in the design change EC405248 Rev 06, this 10CFR50.59 Evaluation supersedes the previous evaluation performed in A/R 02259347.

The proposed activity, Engineering Change (EC) 405248 Rev 06, will upgrade the Catawba Nuclear Station (CNS) main power protective relaying from electromechanical relays (analog) to microprocessor relays (digital) due to aging, obsolescence, and new North American Electric Reliability Corporation (NERC) requirements for periodic monitoring of the health of protective relay input signals (NERC PRC-005-2). Communication channels are being added to monitor the relay input signals as well as provide access to relay data for disturbance monitoring, event recording and fault recording. The relay inputs and outputs will be connected to layered communication server networks to a Real-Time Automation Controller (RTAC) that allows data retrieval over fiber optic cables and ethernet connections.

EC 405248 will replace relays associated with the transformer protection which includes the following: (1) replacing the discrete analog (electromechanical and electronic) protective relays with multifunction digital relays, (2) adding Real-Time Automation Controller (RTAC) and communications equipment, (3) changes to Zone 1A protective relay output co-incident logic, and (4) changes to miscellaneous electro-mechanical relay accessory devices.

The Main Power Protective Relay upgrades provide an equivalent function in the role of providing electrical fault protection for the main and auxiliary transformers, which are a part of the offsite power source. Therefore, the proposed activity does not require a Technical Specification LCO based on the four criteria in 10 CFR 50.36 (c)(2)(ii). Based on the discussion above, the proposed activity will not require a modification, deletion, or addition to the Catawba Technical Specifications Limiting Conditions for Operations (LCO). Engineering Change 405248, Revision 6 does not include changes to any licensing basis documents (UFSAR, TSB, SLC).

From this evaluation it is concluded that the change can be implemented under 10CFR 50.59 without prior approval from the NRC.

U.S. Nuclear Regulatory Commission RA-24-0191 October 22, 2024 Catawba Nuclear Station Technical Specification (TS) Bases Changes

Removal and insertion instructions for Catawba Nuclear Station Technical Specification Bases Changes for April 25, 2023 thru September 24, 2024.

REMOVE THESE PAGES INSERT THESE PAGES LIST OF EFFECTIVE PAGES Pages 1-19 Pages 1-19 Revision 44 (2/14/23)

Revision 48 (6/27/24)

TECHNICAL SPECIFICATIONS BASES TAB B 3.3 B 3.3.1-1 thru 55 B 3.3.1-1 thru 55 Revision 10 Revision 11 TAB B 3.4 B 3.4.14-1 thru 6 B 3.4.14-1 thru 6 Revision 3 Revision 4 TAB B 3.7 B 3.7.11-1 thru 4 B 3.7.11-1 thru 4 Revision 5 Revision 6 TAB B 3.8 B 3.8.4-1 thru 11 B 3.8.4-1 thru 11 Revision 12 Revision 13

Catawba Units 1 and 2 Page 1 Catawba Nuclear Station Technical Specifications List of Effective Pages Page Number Amendments Revision Date i

177/169 4/08/99 ii 219/214 3/01/05 iii 215/209 6/21/04 iv 173/165 9/30/98 1.1-1 173/165 9/30/98 1.1-2 268/264 6/25/12 1.1-3 314/310 11/28/22 1.1-4 317/313 11/15/23 1.1-5 281/277 4/29/16 1.1-6 314/310 11/28/22 1.1.7 179/171 8/13/99 1.2-1 173/165 9/30/98 1.2-2 173/165 9/30/98 1.2-3 173/165 9/30/98 1.3-1 298/294 2/1/18 1.3-2 298/294 2/1/18 1.3-3 312/308 9/7/22 1.3-4 298/294 2/1/18 1.3-5 298/294 2/1/18 1.3-6 298/294 2/1/18 1.3-7 312/308 9/7/22 1.3-8 312/308 9/7/22 1.3-9 298/294 2/1/18 1.3-10 298/294 2/1/18 1.3-11 298/294 2/1/18 1.3-12 298/294 2/1/18 1.3-13 298/294 2/1/18 1.3-14 298/294 2/1/18 1.4-1 173/165 9/30/98 1.4-2 173/165 9/30/98

Catawba Units 1 and 2 Page 2 1.4-3 173/165 9/30/98 1.4-4 173/165 9/30/98 2.0-1 210/204 12/19/03 3.0-1 288/284 4/26/17 3.0-2 298/294 2/1/18 3.0-3 235/231 3/19/07 3.0-4 288/284 4/26/17 3.0-5 298/294 2/1/18 3.0-6 305/301 1/31/20 3.1.1-1 263/259 3/29/11 3.1.2-1 296/292 10/23/17 3.1.2-2 263/259 3/29/11 3.1.3-1 173/165 9/30/98 3.1.3-2 275/271 04/14/15 3.1.3-3 173/165 9/30/98 3.1.4-1 173/165 9/30/98 3.1.4-2 173/165 9/30/98 3.1.4-3 263/259 3/29/11 3.1.4-4 263/259 3/29/11 3.1.5-1 173/165 9/30/98 3.1.5-2 263/259 3/29/11 3.1.6-1 173/165 9/30/98 3.1.6-2 173/165 9/30/98 3.1.6-3 263/259 3/29/11 3.1.7-1 173/165 9/30/98 3.1.7-2 173/165 9/30/98 3.1.8-1 291/287 7/26/17 3.1.8-2 263/259 3/29/11 3.2.1-1 173/165 9/30/98 3.2.1-2 173/165 9/30/98 3.2.1-3 263/259 3/29/11 3.2.1-4 263/259 3/29/11 3.2.1-5 263/259 3/29/11 3.2.2-1 173/165 9/30/98

Catawba Units 1 and 2 Page 3 3.2.2-2 173/165 9/30/98 3.2.2-3 263/259 3/29/11 3.2.2-4 263/259 3/29/11 3.2.3-1 263/259 3/29/11 3.2.4-1 173/165 9/30/98 3.2.4-2 173/165 9/30/98 3.2.4-3 173/165 9/30/98 3.2.4-4 263/259 3/29/11 3.3.1-1 173/165 9/30/98 3.3.1-2 247/240 12/30/08 3.3.1-3 247/240 12/30/08 3.3.1-4 207/201 7/29/03 3.3.1-5 247/240 12/30/08 3.3.1-6 247/240 12/30/08 3.3.1-7 247/240 12/30/08 3.3.1-8 173/165 9/30/98 3.3.1-9 263/259 3/29/11 3.3.1-10 263/259 3/29/11 3.3.1-11 318/314 2/20/24 3.3.1-12 278/274 4/08/16 3.3.1-13 263/259 3/29/11 3.3.1-14 263/259 3/29/11 3.3.1-15 263/259 3/29/11 3.3.1-16 278/274 4/08/16 3.3.1-17 263/259 3/29/11 3.3.1-18 263/259 3/29/11 3.3.1-19 278/274 4/08/16 3.3.1-20 263/259 3/29/11 3.3.1-21 263/259 3/29/11 3.3.1-22 263/259 3/29/11 3.3.2-1 173/165 9/30/98 3.3.2-2 247/240 12/30/08 3.3.2-3 247/240 12/30/08 3.3.2-4 247/240 12/30/08

Catawba Units 1 and 2 Page 4 3.3.2-5 264/260 6/13/11 3.3.2-6 264/260 6/13/11 3.3.2-7 249/243 4/2/09 3.3.2-8 249/243 4/2/09 3.3.2-9 249/243 4/2/09 3.3.2-10 263/259 3/29/11 3.3.2-11 263/259 3/29/11 3.3.2-12 263/259 3/29/11 3.3.2-13 277/273 12/18/15 3.3.2-14 277/273 12/18/15 3.3.2-15 277/273 12/18/15 3.3.2-16 277/273 12/18/15 3.3.2-17 277/273 12/18/15 3.3.2-18 310/306 10/20/21 3.3.3-1 219/214 3/1/05 3.3.3-2 219/214 3/1/05 3.3.3-3 263/259 3/29/11 3.3.3-4 219/214 3/1/05 3.3.4-1 213/207 4/29/04 3.3.4-2 263/259 3/29/11 3.3.4-3 272/268 2/27/14 3.3.5-1 173/165 9/30/98 3.3.5-2 277/273 12/18/15 3.3.6-1 196/189 3/20/02 3.3.6-2 263/259 3/29/11 3.3.6-3 196/189 3/20/02 3.3.9-1 207/201 7/29/03 3.3.9-2 207/201 7/29/03 3.3.9-3 263/259 3/29/11 3.3.9-4 263/259 3/29/11 3.4.1-1 210/204 12/19/03 3.4.1-2 210/204 12/19/03 3.4.1-3 263/259 3/29/11 3.4.1-4 283/279 6/02/16

Catawba Units 1 and 2 Page 5 3.4.1-5 (deleted) 184/176 3/01/00 3.4.1-6 (deleted) 184/176 3/01/00 3.4.2-1 173/165 9/30/98 3.4.3-1 173/165 9/30/98 3.4.3-2 263/259 3/29/11 3.4.3-3 306/302 8/4/20 3.4.3-4 212/206 3/4/04 3.4.3-5 306/302 8/4/20 3.4.3-6 212/206 3/4/04 3.4.4-1 263/259 3/29/11 3.4.5-1 207/201 7/29/03 3.4.5-2 207/201 7/29/03 3.4.5-3 263/259 3/29/11 3.4.6-1 212/206 3/4/04 3.4.6-2 263/259 3/29/11 3.4.6-3 282/278 4/26/17 3.4.7-1 212/206 3/4/04 3.4.7-2 263/259 3/29/11 3.4.7-3 282/278 4/26/17 3.4.8-1 207/201 7/29/03 3.4.8-2 282/278 4/26/17 3.4.9-1 173/165 9/30/98 3.4.9-2 263/259 3/29/11 3.4.10-1 294/290 10/23/17 3.4.10-2 299/295 10/23/18 3.4-11-1 213/207 4/29/04 3.4.11-2 173/165 9/30/98 3.4.11-3 263/259 3/29/11 3.4.11-4 263/259 3/29/11 3.4.12-1 212/206 3/4/04 3.4.12-2 213/207 4/29/04 3.4.12-3 212/206 3/4/04 3.4.12-4 212/206 3/4/04 3.4.12-5 263/259 3/29/11

Catawba Units 1 and 2 Page 6 3.4.12-6 263/259 3/29/11 3.4.12-7 263/259 3/29/11 3.4.12-8 263/259 3/29/11 3.4.13-1 317/313 11/15/23 3.4.13-2 317/313 11/15/23 3.4.13-3(new) 317/313 11/15/23 3.4.14-1 173/165 9/30/98 3.4.14-2 173/165 9/30/98 3.4.14-3 318/314 2/20/24 3.4.14-4(deleted) 318/314 2/20/24 3.4.15-1 234/230 9/30/06 3.4.15-2 234/230 9/30/06 3.4.15-3 234/230 9/30/06 3.4.15-4 263/259 3/29/11 3.4.16-1 268/264 6/25/12 3.4.16-2 268/264 6/25/12 3.4.16-3(deleted) 268/264 6/25/12 3.4.16-4(deleted) 268/264 6/25/12 3.4.17-1 263/259 3/29/11 3.4.18-1 280/276 4/26/16 3.4.18-2 280/276 4/26/16 3.5.1-1 211/205 12/23/03 3.5.1-2 263/259 3/29/11 3.5.1-3 263/259 3/29/11 3.5.2-1 253/248 10/30/09 3.5.2-2 299/295 10/23/18 3.5.2-3 263/259 3/29/11 3.5.3-1 213/207 4/29/04 3.5.3-2 173/165 9/30/98 3.5.4-1 173/165 9/30/98 3.5.4-2 269/265 7/25/12 3.5.5-1 173/165 9/30/98 3.5.5-2 263/259 3/29/11 3.6.1-1 173/165 9/30/98

Catawba Units 1 and 2 Page 7 3.6.1-2 192/184 7/31/01 3.6.2-1 173/165 9/30/98 3.6.2-2 173/165 9/30/98 3.6.2-3 173/165 9/30/98 3.6.2-4 173/165 9/30/98 3.6.2-5 263/259 3/29/11 3.6.3-1 173/165 9/30/98 3.6.3-2 290/286 7/21/17 3.6.3-3 290/286 7/21/17 3.6.3-4 290/286 7/21/17 3.6.3-5 263/259 3/29/11 3.6.3-6 299/295 10/23/18 3.6.3-7 192/184 7/31/01 3.6.4-1 263/259 3/29/11 3.6.5-1 173/165 9/30/98 3.6.5-2 263/259 3/29/11 3.6.6-1 282/278 4/26/17 3.6.6-2 299/295 10/23/18 3.6.8-1 213/207 4/29/04 3.6.8-2 263/259 3/29/11 3.6.9-1 253/248 10/30/09 3.6.9-2 263/259 3/29/11 3.6.10-1 301/297 4/18/19 3.6.10-2 315/311 2/14/23 3.6.11-1 263/259 3/29/11 3.6.11-2 263/259 3/29/11 3.6.12-1 263/259 3/29/11 3.6.12-2 263/259 3/29/11 3.6.12-3 263/259 3/29/11 3.6.13-1 256/251 6/28/10 3.6.13-2 263/259 3/29/11 3.6.13-3 263/259 3/29/11 3.6.14-1 173/165 9/30/98 3.6.14-2 263/259 3/29/11

Catawba Units 1 and 2 Page 8 3.6.14-3 270/266 8/6/13 3.6.15-1 173/165 9/30/98 3.6.15-2 263/259 3/29/11 3.6.16-1 263/259 3/29/11 3.6.16-2 263/259 3/29/11 3.6.17-1 315/311 2/14/23 3.7.1-1 173/165 9/30/98 3.7.1-2 299/295 10/23/18 3.7.1-3 281/277 4/29/16 3.7.2-1 173/165 9/30/98 3.7.2-2 299/295 10/23/18 3.7.3-1 173/165 9/30/98 3.7.3-2 299/295 10/23/18 3.7.4-1 294/290 10/23/17 3.7.4-2 263/259 3/29/11 3.7.5-1 312/308 9/7/22 3.7.5-2 173/165 9/30/98 3.7.5-3 299/295 10/23/18 3.7.5-4 263/259 3/29/11 3.7.6-1 294/290 10/23/17 3.7.6-2 263/259 3/29/11 3.7.7-1 253/248 10/30/09 3.7.7-2 263/259 3/29/11 3.7.8-1 271/267 08/09/13 3.7.8-2 271/267 08/09/13 3.7.8-3 271/267 08/09/13 3.7.8-4 300/296 11/28/18 3.7.8-5 (new) 300/296 11/28/18 3.7.9-1 263/259 3/29/11 3.7.9-2 263/259 3/29/11 3.7.10-1 250/245 7/30/09 3.7.10-2 260/255 8/9/10 3.7.10-3 315/311 2/14/23 3.7.11-1 198/191 4/23/02

Catawba Units 1 and 2 Page 9 3.7.11-2 319/315 3/8/24 3.7.12-1 301/291 4/18/19 3.7.12-2 315/311 2/14/23 3.7.13-1 301/297 4/18/19 3.7.13-2 289/285 5/08/17 3.7.14-1 263/259 3/29/11 3.7.15-1 263/259 3/29/11 3.7.16-1 233/229 9/27/06 3.7.16-2 233/229 9/27/06 3.7.16-3 233/229 9/27/06 3.7.17-1 263/259 3/29/11 3.8.1-1 304/300 11/11/19 3.8.1-2 312/308 9/7/22 3.8.1-3 304/300 11/11/19 3.8.1-4 312/308 9/7/22 3.8.1-5 (new) 304/300 11/11/19 3.8.1-6 (new) 304/300 11/11/19 3.8.1-7 312/308 9/7/22 3.8.1-8 (new) 304/300 11/11/19 3.8.1-9 (new) 304/300 11/11/19 3.8.1-10 (new) 304/300 11/11/19 3.8.1-11 308/304 9/28/21 3.8.1-12 263/259 3/29/11 3.8.1-13 308/304 9/28/21 3.8.1-14 308/304 9/28/21 3.8.1-15 308/304 9/28/21 3.8.1-16 3.8.1-17 3.8.1-18 3.8.1-19 3.8.1-20 3.8.1-21 3.8.2-1 308/304 263/259 308/304 292/288 308/304 308/304 173/165 9/28/21 3/29/11 9/28/21 9/08/17 9/28/21 9/28/21 9/30/98 3.8.2-2 207/201 7/29/03

Catawba Units 1 and 2 Page 10 3.8.2-3 173/165 9/30/98 3.8.3-1 175/167 1/15/99 3.8.3-2 263/259 3/29/11 3.8.3-3 263/259 3/29/11 3.8.4-1 173/165 9/30/98 3.8.4-2 263/259 3/29/11 3.8.4-3 292/288 9/08/17 3.8.4-4 292/288 9/08/17 3.8.4-5 262/258 12/20/10 3.8.5-1 173/165 9/30/98 3.8.5-2 207/201 7/29/03 3.8.6-1 253/248 10/30/09 3.8.6-2 253/248 10/30/09 3.8.6-3 253/248 10/30/09 3.8.6-4 263/259 3/29/11 3.8.6-5 223/218 4/27/05 3.8.7-1 173/165 9/30/98 3.8.7-2 263/259 3/29/11 3.8.8-1 173/165 9/30/98 3.8.8-2 263/259 3/29/11 3.8.9-1 312/308 9/7/22 3.8.9-2 312/308 9/7/22 3.8.9-3 263/259 3/29/11 3.8.10-1 207/201 7/29/03 3.8.10-2 263/259 3/29/11 3.9.1-1 263/259 3/29/11 3.9.2-1 215/209 6/21/04 3.9.2-2 263/259 3/29/11 3.9.3-1 227/222 9/30/05 3.9.3-2 301/297 4/18/19 3.9.4-1 207/201 7/29/03 3.9.4-2 297/293 1/4/18 3.9.5-1 293/289 9/29/17 3.9.5-2 297/293 1/4/18

Catawba Units 1 and 2 Page 11 3.9.6-1 263/259 3/29/11 3.9.7-1 263/259 3/29/11 4.0-1 284/280 6/21/16 4.0-2 233/229 9/27/06 5.1-1 273/269 2/12/15 5.2-1 273/269 2/12/15 5.2-2 273/269 2/12/15 5.2-3 Deleted 9/21/09 5.3-1 307/303 11/17/20 5.4-1 173/165 9/30/98 5.5-1 286/282 9/12/16 5.5-2 286/282 9/12/16 5.5-3 173/165 9/30/98 5.5-4 173/165 9/30/98 5.5-5 216/210 8/5/04 5.5-6 311/307 6/28/22 5.5-7 280/276 4/26/16 5.5-8 311/307 6/28/22 5.5-9 311/307 6/28/22 5.5-10 (deleted) 311/307 6/28/22 5.5-11 (deleted) 311/307 6/28/22 5.5-12 280/276 4/26/16 5.5-13 280/276 4/26/16 5.5-14 301/297 4/18/19 5.5-15 280/276 4/26/16 5.5-16 280/276 4/26/16 5.5-17 280/276 4/26/16 5.5-18 280/276 4/26/16 5.5-19 280/276 4/26/16 5.6-1 222/217 3/31/05 5.6-2 253/248 10/30/09 5.6-3 222/217 3/31/05 5.6-4 284/280 6/21/16 5.6-5 301/297 4/18/19

Catawba Units 1 and 2 Page 12 5.6-6 311/307 6/28/22 5.6-7 (new) 311/307 6/28/22 5.7-1 273/269 2/12/15 5.7-2 173/165 9/30/98

Catawba Units 1 and 2 Page 13 BASES i

Revision 1 4/08/99 ii Revision 2 3/01/05 iii Revision 1 6/21/04 B 2.1.1-1 Revision 0 9/30/98 B 2.1.1-2 Revision 1 12/19/03 B 2.1.1-3 Revision 1 12/19/03 B 2.1.2-1 Revision 0 9/30/98 B 2.1.2-2 Revision 0 9/30/98 B 2.1.2-3 Revision 0 9/30/98 B 3.0-1 thru B 3.0-21 Revision 7 5/02/19 B 3.1.1-1 thru B 3.1.1-6 Revision 3 5/05/11 B 3.1.2-1 thru B 3.1.2-5 Revision 3 11/14/17 B 3.1.3-1 thru B 3.1.3-6 Revision 2 4/14/15 B 3.1.4-1 thru B 3.1.4-9 Revision 1 5/05/11 B 3.1.5-1 thru B 3.1.5-4 Revision 2 5/05/11 B 3.1.6-1 thru B 3.1.6-6 Revision 1 5/05/11 B 3.1.7-1 Revision 0 9/30/98 B 3.1.7-2 Revision 2 1/08/04 B 3.1.7-3 Revision 2 1/08/04 B 3.1.7-4 Revision 2 1/08/04 B 3.1.7-5 Revision 2 1/08/04 B 3.1.7-6 Revision 2 1/08/04 B 3.1.8-1 thru B 3.1.8-6 Revision 4 3/28/18 B 3.2.1-1 thru B 3.2.1.-11 Revision 4 5/05/11

Catawba Units 1 and 2 Page 14 B 3.2.2-1 thru B 3.2.2-10 Revision 3 5/05/11 B 3.2.3-1 thru B 3.2.3-4 Revision 2 5/05/11 B 3.2.4-1 thru B 3.2.4-7 Revision 2 5/05/11 B 3.3.1-1 thru B.3.3.1-55 Revision 11 2/20/24 B 3.3.2-1 thru B 3.3.2-52 Revision 14 11/28/22 B 3.3.3-1 thru B.3.3.3-17 Revision 7 1/5/23 B 3.3.4-1 thru B 3.3.4-5 Revision 2 5/05/11 B 3.3.5-1 thru B 3.3.5-6 Revision 3 12/18/15 B 3.3.6-1 thru B 3.3.6-5 Revision 6 08/02/12 B 3.3.9-1 thru B 3.3.9-5 Revision 3 06/02/14 B 3.4.1-1 thru B 3.4.1-5 Revision 3 5/05/11 B 3.4.2-1 Revision 0 9/30/98 B 3.4.2-2 Revision 0 9/30/98 B 3.4.2-3 Revision 0 9/30/98 B 3.4.3-1 thru B 3.4.3-6 Revision 2 5/05/11 B 3.4.4-1 thru B 3.4.4-3 Revision 2 5/05/11 B 3.4.5-1 thru B 3.4.5-6 Revision 3 5/05/11 B 3.4.6-1 thru B 3.4.6-6 Revision 5 4/26/17

Catawba Units 1 and 2 Page 15 B 3.4.7-1 thru B 3.4.7-8 Revision 8 5/20/20 B 3.4.8-1 thru B 3.4.8-5 Revision 5 5/20/20 B 3.4.9-1 thru B 3.4.9-5 Revision 3 08/02/12 B 3.4.10-1 thru Revision 4 10/23/18 B 3.4.10-4 B 3.4.11-1 thru B 3.4.11-7 Revision 4 5/05/11 B 3.4.12-1 thru B 3.4.12-13 Revision 6 10/23/18 B 3.4.13-1 thru B 3.4.13-7 Revision 8 11/15/23 B 3.4.14-1 thru B 3.4.14-6 Revision 4 2/20/24 B 3.4.15-1 thru B 3.4.15-10 Revision 6 5/05/11 B 3.4.16-1 thru B 3.4.16-5 Revision 4 10/23/12 B 3.4.17-1 thru B 3.4.17-3 Revision 2 5/05/11 B 3.4.18-1 thru B 3.4.18-8 Revision 2 4/26/16 B 3.5.1-1 thru B 3.5.1-8 Revision 4 4/26/17 B 3.5.2-1 thru B 3.5.2-11 Revision 5 10/23/18 B 3.5.3-1 thru B 3.5.3-3 Revision 2 4/26/17 B 3.5.4-1 thru B.3.5.4-5 Revision 5 4/11/14 B 3.5.5-1 thru B 3.5.5-4 Revision 1 5/05/11

Catawba Units 1 and 2 Page 16 B 3.6.1-1 thru Revision 2 6/14/22 B 3.6.1-5 B 3.6.2-1 thru B 3.6.2-8 Revision 2 5/05/11 B 3.6.3-1 thru B 3.6.3-14 Revision 7 10/23/18 B 3.6.4-1 thru B 3.6.4-4 Revision 2 5/05/11 B 3.6.5-1 thru B 3.6.5-4 Revision 3 07/27/13 B 3.6.6-1 thru B 3.6.6-8 Revision 8 10/23/18 B 3.6.8-1 thru B 3.6.8-5 Revision 3 5/05/11 B 3.6.9-1 thru B 3.6.9-5 Revision 6 5/05/11 B 3.6.10-1 thru B 3.6.10-6 Revision 5 2/14/23 B 3.6.11-1 thru B 3.6.11-6 Revision 5 5/05/11 B 3.6.12-1 thru B 3.6.12-11 Revision 5 5/05/11 B 3.6.13-1 thru B 3.6.13-9 Revision 4 5/05/11 B 3.6.14-1 thru B 3.6.14-5 Revision 3 6/14/22 B 3.6.15-1 thru B 3.6.15-4 Revision 1 5/05/11 B 3.6.16-1 thru B 3.6.16-4 Revision 4 6/14/22 B 3.6.17-1 thru B 3.6.17-5 Revision 5 2/14/23 B 3.7.1-1 thru 3.7.1-5 Revision 3 10/23/18

Catawba Units 1 and 2 Page 17 B 3.7.2-1 thru B 3.7.2-5 Revision 4 10/23/18 B 3.7.3-1 B 3.7.3-6 Revision 3 10/23/18 B 3.7.4-1 thru B 3.7.4-4 Revision 3 11/14/17 B 3.7.5-1 thru B 3.7.5-9 Revision 6 9/7/22 B 3.7.6-1 thru B 3.7.6-3 Revision 6 9/10/18 B 3.7.7-1 thru B 3.7.7-5 Revision 3 6/21/22 B 3.7.8-1 thru B 3.7.8-12 Revision 10 5/21/20 B 3.7.9-1 thru B 3.7.9-4 Revision 4 6/14/22 B 3.7.10-1 thru B 3.7.10-9 Revision 15 2/14/23 B 3.7.11-1 thru B 3.7.11-4 Revision 6 6/27/24 B 3.7.12-1 thru B 3.7.12-7 Revision 12 2/14/23 B 3.7.13-1 thru B 3.7.13-5 Revision 6 7/15/19 B 3.7.14-1 thru B 3.7.14-3 Revision 2 5/05/11 B 3.7.15-1 thru B 3.7.15-4 Revision 2 5/05/11 B 3.7.16-1 Revision 2 9/27/06 B 3.7.16-2 Revision 2 9/27/06 B 3.7.16-3 Revision 2 9/27/06 B 3.7.16-4 Revision 0 9/27/06 B 3.7.17-1 thru B 3.7.17-3 Revision 2 5/05/11

Catawba Units 1 and 2 Page 18 B 3.8.1-1 thru B.3.8.1-38 Revision 9 9/7/22 B 3.8.2-1 Revision 0 9/30/98 B 3.8.2-2 Revision 0 9/30/98 B 3.8.2-3 Revision 0 9/30/98 B 3.8.2-4 Revision 3 11/11/19 B 3.8.2-5 Revision 2 5/10/05 B 3.8.2-6 Revision 1 5/10/05 B 3.8.3-1 thru B 3.8.3-8 Revision 4 5/05/11 B 3.8.4-1 thru B 3.8.4.11 Revision 13 7/19/23 B 3.8.5-1 Revision 0 9/30/98 B 3.8.5-2 Revision 2 7/29/03 B 3.8.5-3 Revision 1 7/29/03 B 3.8.6-1 thru B 3.8.6-7 Revision 4 5/05/11 B 3.8.7-1 thru B 3.8.7-4 Revision 3 5/05/11 B 3.8.8-1 thru B 3.8.8-4 Revision 3 5/05/11 B 3.8.9-1 thru B 3.8.9-8 Revision 3 9/7/22 B 3.8.10-1 thru B 3.8.10-4 Revision 3 5/05/11 B 3.9.1-1 thru B 3.9.1-4 Revision 3 5/05/11 B 3.9.2-1 thru B 3.9.2-3 Revision 6 3/21/17 B 3.9.3-1 thru B 3.9.3-5 Revision 5 7/15/19 B 3.9.4-1 thru B 3.9.4-6 Revision 6 1/23/18

Catawba Units 1 and 2 Page 19 B 3.9.5-1 thru B 3.9.5-5 Revision 7 5/21/20 B 3.9.6-1 thru B 3.9.6-3 Revision 2 5/05/11 B 3.9.7-1 thru B 3.9.7-3 Revision 1 5/05/11



Catawba Units 1 and 2 B 3.3.1-1 Revision No. 11 RTS Instrumentation B 3.3.1 B 3.3 INSTRUMENTATION B 3.3.1 Reactor Trip System (RTS) Instrumentation BASES BACKGROUND The RTS initiates a unit shutdown, based on the values of selected unit parameters, to protect against violating the core fuel design limits and Reactor Coolant System (RCS) pressure boundary during anticipated operational occurrences (AOOs) and to assist the Engineered Safety Features (ESF) Systems in mitigating accidents.

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

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

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

1.

The Departure from Nucleate Boiling Ratio (DNBR) shall be maintained above the Safety Limit (SL) value to prevent departure from nucleate boiling (DNB);

2.

Fuel centerline melt shall not occur; and

3.

The RCS pressure SL of 2735 psig shall not be exceeded.

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

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

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

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-2 Revision No. 11 BACKGROUND (continued)

The RTS instrumentation is segmented into four distinct but interconnected categories as illustrated in UFSAR, Chapter 7 (Ref. 1),

and as identified below:

1.

Field transmitters or process sensors: provide a measurable electronic signal based upon the physical characteristics of the parameter being measured;

2.

Process monitoring systems, including the Process Control System, the Nuclear Instrumentation System (NIS), and various field contacts and sensors: monitors various plant parameters, provides any required signal processing, and provides digital outputs when parameters exceed predetermined limits. They may also provide outputs for control, indication, alarm, computer input, and recording;

3.

Solid State Protection System (SSPS), including input, logic, and output bays: combines the input signals from the process monitoring systems per predetermined logic and initiates a reactor trip and ESF actuation when warranted by the process monitoring systems inputs; and

4.

Reactor trip switchgear, including reactor trip breakers (RTBs) and bypass breakers: provides the means to interrupt power to the control rod drive mechanisms (CRDMs) and allows the rod cluster control assemblies (RCCAs), or "rods," to fall into the core and shut down the reactor. The bypass breakers allow testing of the RTBs at power.

Field Transmitters or Sensors To meet the design demands for redundancy and reliability, more than one, and often as many as four, field transmitters or sensors are used to measure unit parameters. To account for the calibration tolerances and instrument drift, which are assumed to occur between calibrations, statistical allowances are provided in the NOMINAL TRIP SETPOINT.

The OPERABILITY of each transmitter or sensor can be evaluated when its "as found" calibration data are compared against its documented acceptance criteria.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-3 Revision No. 11 BACKGROUND (continued)

Process Monitoring Systems Generally, three or four channels of process control equipment are used for the signal processing of unit parameters measured by the field instruments. The process control equipment provides signal conditioning, compatible output signals for instruments located on the main control board, and comparison of measured input signals with setpoints established by safety analyses. These setpoints are defined in UFSAR, Chapter 7 (Ref. 1), Chapter 6 (Ref. 2), and Chapter 15 (Ref. 3). If the measured value of a unit parameter exceeds the predetermined setpoint, an output from a bistable is forwarded to the SSPS for decision logic processing. Channel separation is maintained up to and through the input bays. However, not all unit parameters require four channels of sensor measurement and signal processing. Some unit parameters provide input only to the SSPS, while others provide input to the SSPS, the main control board, the unit computer, and one or more control systems.

Generally, if a parameter is used only for input to the protection circuits, three channels with a two-out-of-three logic are sufficient to provide the required reliability and redundancy. If one channel fails in a direction that would not result in a partial Function trip, the Function is still OPERABLE with a two-out-of-two logic. If one channel fails, such that a partial Function trip occurs, a trip will not occur and the Function is still OPERABLE with a one-out-of-two logic.

Generally, if a parameter is used for input to the SSPS and a control function, four channels with a two-out-of-four logic are sufficient to provide the required reliability and redundancy. The circuit must be able to withstand both an input failure to the control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation. Again, a single failure will neither cause nor prevent the protection function actuation.

These requirements are described in IEEE-279-1971 (Ref. 4). The actual number of channels required for each unit parameter is specified in Reference 1.

Two logic channels are required to ensure no single random failure of a logic channel will disable the RTS. The logic channels are designed such that testing required while the reactor is at power may be accomplished without causing a trip. Provisions to allow removing logic channels from service during maintenance are unnecessary because of the logic system's designed reliability.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-4 Revision No. 11 BACKGROUND (continued)

Trip Setpoints and Allowable Values The NOMINAL TRIP SETPOINTS are the nominal values at which the bistables are set. Any bistable is considered to be properly adjusted when the "as left" value is within the band for CHANNEL CALIBRATION tolerance.

The NOMINAL TRIP SETPOINTS used in the bistables are based on the analytical limits (Ref. 1, 2, and 3). The selection of these NOMINAL TRIP SETPOINTS is such that adequate protection is provided when all sensor and processing time delays, calibration tolerances, instrumentation uncertainties, instrument drift, and severe environment errors for those RTS channels that must function in harsh environments as defined by 10 CFR 50.49 (Ref. 5) are taken into account. The actual as-left setpoint of the bistable assures that the actual trip occurs in time to prevent an analytical limit from being exceeded.

The Allowable Value accounts for changes in random measurement errors between COTs. One example of such a change in measurement error is drift during the surveillance interval. If the COT demonstrates that the loop trips within the Allowable Value, the loop is OPERABLE. A trip within the Allowable Value ensures that the predictions of equipment performance used to develop the NOMINAL TRIP SETPOINT are still valid, and that the equipment will initiate a trip in response to an AOO in time to prevent an analytical limit from being exceeded (and that the consequences of DBAs will be acceptable, providing the unit is operated from within the LCOs at the onset of the AOO or DBA and the equipment functions as designed). Note that in the accompanying LCO 3.3.1, the Allowable Values of Table 3.3.1-1 are the LSSS.

Each channel of the process control equipment can be tested on line to verify that the signal or setpoint accuracy is within the specified allowance requirements. Once a designated channel is taken out of service for testing, a simulated signal is injected in place of the field instrument signal. The process equipment for the channel in test is then tested, verified, and calibrated. SRs for the channels are specified in the SRs section.

The determination of the NOMINAL TRIP SETPOINTS and Allowable Values listed in Table 3.3.1-1 incorporates all of the known uncertainties applicable for each channel. The magnitudes of these uncertainties are factored into the determination of each NOMINAL TRIP SETPOINT. All field sensors and signal processing equipment

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-5 Revision No. 11 BACKGROUND (continued) for these channels are assumed to operate within the allowances of these uncertainty magnitudes.

Solid State Protection System The SSPS equipment is used for the decision logic processing of outputs from the signal processing equipment bistables. To meet the redundancy requirements, two trains of SSPS, each performing the same functions, are provided. If one train is taken out of service for maintenance or test purposes, the second train will provide reactor trip and/or ESF actuation for the unit. If both trains are taken out of service or placed in test, a reactor trip will result. Each train is packaged in its own cabinet for physical and electrical separation to satisfy separation and independence requirements. The system has been designed to trip the reactor in the event of a loss of power, directing the unit to a safe shutdown condition.

The SSPS performs the decision logic for actuating a reactor trip or ESF actuation, generates the electrical output signal that will initiate the required trip or actuation, and provides the status, permissive, and annunciator output signals to the main control room of the unit.

The outputs from the process monitoring systems are sensed by the SSPS equipment and combined into logic matrices that represent combinations indicative of various unit upset and accident transients. If a logic matrix combination is completed, the system will initiate a reactor trip or send actuation signals via master and slave relays to those components whose aggregate Function best serves to alleviate the condition and restore the unit to a stable condition. Examples are given in the Applicable Safety Analyses, LCO, and Applicability sections of this Bases.

Reactor Trip Switchgear The RTBs are in the electrical power supply line from the control rod drive motor generator set power supply to the CRDMs. Opening of the RTBs interrupts power to the CRDMs, which allows the shutdown rods and control rods to fall into the core by gravity. Each RTB is equipped with a bypass breaker to allow testing of the RTB while the unit is at power.

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During normal operation the output from the SSPS is a voltage signal that energizes the undervoltage coils in the RTBs and bypass breakers, if in use. When the required logic matrix combination is completed, the SSPS output voltage signal is removed, the undervoltage coils are de-energized, the breaker trip lever is actuated by a compressed spring that is released by de-energizing the undervoltage coil, and the RTBs and bypass breakers are tripped open. This allows the shutdown rods and control rods to fall into the core. In addition to the de-energization of the undervoltage coils, each breaker is also equipped with a shunt trip device that is energized to trip the breaker open upon receipt of a reactor trip signal from the SSPS. Either the undervoltage coil or the shunt trip mechanism is sufficient by itself, thus providing a diverse trip mechanism.

The decision logic matrix Functions are described in the functional diagrams included in Reference 1. In addition to the reactor trip or ESF, these diagrams also describe the various "permissive interlocks" that are associated with unit conditions. Each train has a built in testing device that can test the decision logic matrix Functions and the actuation devices while the unit is at power. When any one train is taken out of service for testing, the other train is capable of providing unit monitoring and protection until the testing has been completed. The testing device is semiautomatic to minimize testing time.

APPLICABLE The RTS functions to maintain the SLs during all AOOs and mitigates SAFETY ANALYSES, the consequences of DBAs in all MODES in which the RTBs are closed.

LCO, and APPLICABILITY Each of the analyzed accidents and transients can be detected by one or more RTS Functions. The accident analysis described in Reference 3 takes credit for most RTS trip Functions. RTS trip Functions not specifically credited in the accident analysis are qualitatively credited in the safety analysis and the NRC staff approved licensing basis for the unit. These RTS trip Functions may provide protection for conditions that do not require dynamic transient analysis to demonstrate Function performance. They may also serve as backups to RTS trip Functions that were credited in the accident analysis.

The LCO requires all instrumentation performing an RTS Function, listed in Table 3.3.1-1 in the accompanying LCO, to be OPERABLE. Failure of any instrument renders the affected channel(s) inoperable and reduces the reliability of the affected Functions.

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The LCO generally requires OPERABILITY of three or four channels in each instrumentation Function, two channels of Manual Reactor Trip in each logic Function, and two trains in each Automatic Trip Logic Function.

Four OPERABLE instrumentation channels in a two-out-of-four configuration are required when one RTS channel is also used as a control system input. This configuration accounts for the possibility of the shared channel failing in such a manner that it creates a transient that requires RTS action. In this case, the RTS will still provide protection, even with random failure of one of the other three protection channels.

Three operable instrumentation channels in a two-out-of-three configuration are generally required when there is no potential for control system and protection system interaction that could simultaneously create a need for RTS trip and disable one RTS channel. The two-out-of-three and two-out-of-four configurations allow one channel to be tripped during maintenance or testing without causing a reactor trip. Specific exceptions to the above general philosophy exist and are discussed below.

Reactor Trip System Functions The safety analyses and OPERABILITY requirements applicable to each RTS Function are discussed below:

1.

Manual Reactor Trip The Manual Reactor Trip ensures that the control room operator can initiate a reactor trip at any time by using either of two reactor trip switches in the control room. A Manual Reactor Trip accomplishes the same results as any one of the automatic trip Functions. It may be used by the reactor operator to shut down the reactor whenever any parameter is rapidly trending toward its Trip Setpoint.

The LCO requires two Manual Reactor Trip channels to be OPERABLE. Each channel is controlled by a manual reactor trip switch. Each channel actuates one or more reactor trip breakers in both trains. Two independent channels are required to be OPERABLE so that no single random failure will disable the Manual Reactor Trip Function.

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In MODE 1 or 2, manual initiation of a reactor trip must be OPERABLE. These are the MODES in which the shutdown rods and/or control rods are partially or fully withdrawn from the core. In MODE 3, 4, or 5, the manual initiation Function must also be OPERABLE if the shutdown rods or control rods are withdrawn or the Control Rod Drive (CRD) System is capable of withdrawing the shutdown rods or the control rods. In this condition, inadvertent control rod withdrawal is possible. In MODE 3, 4, or 5, manual initiation of a reactor trip does not have to be OPERABLE if the CRD System is not capable of withdrawing the shutdown rods or control rods. If the rods cannot be withdrawn from the core, there is no need to be able to trip the reactor because all of the rods are inserted. In MODE 6, the CRDMs are disconnected from the control rods and shutdown rods. Therefore, the manual initiation Function is not required.

2.

Power Range Neutron Flux The NIS power range detectors are located external to the reactor vessel and measure neutrons leaking from the core. The NIS power range detectors provide input to the Rod Control System and the Steam Generator (SG) Water Level Control System. Therefore, the actuation logic must be able to withstand an input failure to the control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation. Note that this Function also provides a signal to prevent automatic and manual rod withdrawal prior to initiating a reactor trip. Limiting further rod withdrawal may terminate the transient and eliminate the need to trip the reactor.

a.

Power Range Neutron Flux-High The Power Range Neutron Flux-High trip Function ensures that protection is provided, from all power levels, against a positive reactivity excursion leading to DNB during power operations. These can be caused by rod withdrawal or reductions in RCS temperature.

The LCO requires all four of the Power Range Neutron Flux-High channels to be OPERABLE.

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In MODE 1 or 2, when a positive reactivity excursion could occur, the Power Range Neutron Flux-High trip must be OPERABLE. This Function will terminate the reactivity excursion and shut down the reactor prior to reaching a power level that could damage the fuel. In MODE 3, 4, 5, or 6, the NIS power range detectors cannot detect neutron levels in this range. In these MODES, the Power Range Neutron Flux-High does not have to be OPERABLE because the reactor is shut down and reactivity excursions into the power range are extremely unlikely. Other RTS Functions and administrative controls provide protection against reactivity additions when in MODE 3, 4, 5, or 6.

b.

Power Range Neutron Flux-Low The LCO requirement for the Power Range Neutron Flux-Low trip Function ensures that protection is provided against a positive reactivity excursion from low power or subcritical conditions.

The LCO requires all four of the Power Range Neutron Flux-Low channels to be OPERABLE.

In MODE 1, below the Power Range Neutron Flux (P-10 setpoint), and in MODE 2, the Power Range Neutron Flux-Low trip must be OPERABLE. This Function may be manually blocked by the operator when two out of four power range channels are greater than approximately 10% RTP (P-10 setpoint). This Function is automatically unblocked when three out of four power range channels are below the P-10 setpoint. Above the P-10 setpoint, positive reactivity additions are mitigated by the Power Range Neutron Flux-High trip Function.

In MODE 3, 4, 5, or 6, the Power Range Neutron Flux-Low trip Function does not have to be OPERABLE because the reactor is shut down and the NIS power range detectors cannot detect neutron levels in this range. Other RTS trip Functions and administrative controls provide protection

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3.

Power Range Neutron Flux - High Positive Rate The Power Range Neutron Flux-High Positive Rate trip uses the same channels as discussed for Function 2 above.

The Power Range Neutron Flux-High Positive Rate trip Function ensures that protection is provided against rapid increases in neutron flux that are characteristic of an RCCA drive rod housing rupture and the accompanying ejection of the RCCA. This Function compliments the Power Range Neutron Flux-High and Low Setpoint trip Functions to ensure that the criteria are met for a rod ejection from the power range.

The LCO requires all four of the Power Range Neutron Flux-High Positive Rate channels to be OPERABLE.

In MODE 1 or 2, when there is a potential to add a large amount of positive reactivity from a rod ejection accident (REA), the Power Range Neutron FluxHigh Positive Rate trip must be OPERABLE.

In MODE 3, 4, 5, or 6, the Power Range Neutron Flux-High Positive Rate trip Function does not have to be OPERABLE because other RTS trip Functions and administrative controls will provide protection against positive reactivity additions. In MODE 6, no rods are withdrawn and the SDM is increased during refueling operations. The reactor vessel head is also removed or the closure bolts are detensioned preventing any pressure buildup. In addition, the NIS power range detectors cannot detect neutron levels present in this mode.

4.

Intermediate Range Neutron Flux The Intermediate Range Neutron Flux trip Function ensures that protection is provided against an uncontrolled RCCA bank rod withdrawal accident from a subcritical condition during startup. This trip Function provides redundant protection to the Power

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Range Neutron Flux-Low Setpoint trip Function. The NIS intermediate range detectors are located external to the reactor vessel and measure neutrons leaking from the core. Note that this Function also provides a signal to prevent automatic and manual rod withdrawal prior to initiating a reactor trip. Limiting further rod withdrawal may terminate the transient and eliminate the need to trip the reactor.

The LCO requires two channels of Intermediate Range Neutron Flux to be OPERABLE. Two OPERABLE channels are sufficient to ensure no single random failure will disable this trip Function.

Because this trip Function is important only during startup, there is generally no need to disable channels for testing while the Function is required to be OPERABLE. Therefore, a third channel is unnecessary.

In MODE 1 below the P-10 setpoint, and in MODE 2, when there is a potential for an uncontrolled RCCA bank rod withdrawal accident during reactor startup, the Intermediate Range Neutron Flux trip must be OPERABLE. Above the P-10 setpoint, the Power Range Neutron Flux-High Setpoint trip and the Power Range Neutron Flux-High Positive Rate trip provide core protection for a rod withdrawal accident. In MODE 3, 4, or 5, the Intermediate Range Neutron Flux trip does not have to be OPERABLE because other RTS trip functions provide protection against positive reactivity additions. The reactor cannot be started up in this condition. The core also has the required SDM to mitigate the consequences of a positive reactivity addition accident. In MODE 6, all rods are fully inserted and the core has a required increased SDM.

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5.

Source Range Neutron Flux The LCO requirement for the Source Range Neutron Flux trip Function ensures that protection is provided against an uncontrolled RCCA bank rod withdrawal accident from a subcritical condition during startup.

This trip Function provides redundant protection to the Power Range Neutron Flux-Low Setpoint and Intermediate Range Neutron Flux trip Functions. In MODES 3, 4, and 5, administrative controls also prevent the uncontrolled withdrawal of rods. The NIS source range detectors are located external to the reactor vessel and measure neutrons leaking from the core. The NIS source range detectors do not provide any inputs to control systems. The source range trip is the only RTS automatic protection function required in MODES 3, 4, and 5. Therefore, the functional capability at the specified Trip Setpoint is assumed to be available.

The LCO requires two channels of Source Range Neutron Flux to be OPERABLE. Two OPERABLE channels are sufficient to ensure no single random failure will disable this trip Function.

The Source Range Neutron Flux Function provides protection for control rod withdrawal from subcritical and control rod ejection events. The Function also provides visual neutron flux indication in the control room.

In MODE 2 when below the P-6 setpoint during a reactor startup, the Source Range Neutron Flux trip must be OPERABLE. Above the P-6 setpoint, the Intermediate Range Neutron Flux trip and the Power Range Neutron Flux-Low Setpoint trip will provide core protection for reactivity accidents. Above the P-6 setpoint, the Source Range Neutron Flux trip is blocked.

In MODE 3, 4, or 5 with the reactor shut down, the Source Range Neutron Flux trip Function must also be OPERABLE. If the CRD System is capable of rod withdrawal, the Source Range Neutron Flux trip must be OPERABLE to provide core protection against a rod withdrawal accident. If the CRD System is not capable of rod withdrawal, the source range detectors are not required to trip the reactor.

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6.

Overtemperature 'T The Overtemperature 'T trip Function is provided to ensure that the design limit DNBR is met. This trip Function also limits the range over which the Overpower 'T trip Function must provide protection. The inputs to the Overtemperature 'T trip include pressurizer pressure, coolant temperature, axial power distribution, and reactor power as indicated by loop 'T assuming full reactor coolant flow. Protection from violating the DNBR limit is assured for those transients that are slow with respect to delays from the core to the measurement system. The function monitors both variation in power and flow since a decrease in flow has the same effect on

'T as a power increase. The Overtemperature 'T trip Function uses each loop's 'T as a measure of reactor power and is compared with a setpoint that is automatically varied with the following parameters:

x reactor coolant average temperature-the Trip Setpoint is varied to correct for changes in coolant density and specific heat capacity with changes in coolant temperature; x

pressurizer pressure-the Trip Setpoint is varied to correct for changes in system pressure; and x

axial power distribution-f('I), the Trip Setpoint is varied to account for imbalances in the axial power distribution as detected by the NIS upper and lower power range detectors.

If axial peaks are greater than the design limit, as indicated by the difference between the upper and lower NIS power range detectors, the Trip Setpoint is reduced in accordance with Note 1 of Table 3.3.1-1.

Dynamic compensation is included for system piping delays from the core to the temperature measurement system.

The Overtemperature 'T trip Function is calculated for each loop as described in Note 1 of Table 3.3.1-1. Trip occurs if Overtemperature 'T is indicated in two loops. The pressure and temperature signals are used for other control functions, therefore, the actuation logic must be able to withstand an input failure to the control system, which may then require the protection function

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The LCO requires all four channels of the Overtemperature 'T trip Function to be OPERABLE. Note that the Overtemperature 'T Function receives input from channels shared with other RTS Functions. Failures that affect multiple Functions require entry into the Conditions applicable to all affected Functions.

In MODE 1 or 2, the Overtemperature 'T trip must be OPERABLE to prevent DNB. In MODE 3, 4, 5, or 6, this trip Function does not have to be OPERABLE because the reactor is not operating and there is insufficient heat production to be concerned about DNB.

7.

Overpower 'T The Overpower 'T trip Function ensures that protection is provided to ensure the integrity of the fuel (i.e., no fuel pellet melting and less than 1% cladding strain) under all possible overpower conditions.

This trip Function also limits the required range of the Overtemperature 'T trip Function and provides a backup to the Power Range Neutron Flux-High Setpoint trip.

The Overpower 'T trip Function ensures that the allowable heat generation rate (kW/ft) of the fuel is not exceeded. It uses the 'T of each loop as a measure of reactor power with a setpoint that is automatically varied with the following parameters:

x reactor coolant average temperature-the Trip Setpoint is varied to correct for changes in coolant density and specific heat capacity with changes in coolant temperature; and x

rate of change of reactor coolant average temperature-including dynamic compensation for the delays between the core and the temperature measurement system.

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The Overpower 'T trip Function is calculated for each loop as per Note 2 of Table 3.3.1-1. Trip occurs if Overpower 'T is indicated in two loops. The temperature signals are used for other control functions, therefore, the actuation logic must be able to withstand an input failure to the control system, which may then require the protection function actuation, and a single failure in the remaining channels providing the protection function actuation. Note that this Function also provides a signal to generate a turbine runback prior to reaching the Trip Setpoint. A turbine runback will reduce turbine power and reactor power. A reduction in power will normally alleviate the Overpower 'T condition and may prevent a reactor trip.

The LCO requires four channels of the Overpower 'T trip Function to be OPERABLE. Note that the Overpower 'T trip Function receives input from channels shared with other RTS Functions.

Failures that affect multiple Functions require entry into the Conditions applicable to all affected Functions.

In MODE 1 or 2, the Overpower 'T trip Function must be OPERABLE. These are the only times that enough heat is generated in the fuel to be concerned about the heat generation rates and overheating of the fuel. In MODE 3, 4, 5, or 6, this trip Function does not have to be OPERABLE because the reactor is not operating and there is insufficient heat production to be concerned about fuel overheating and fuel damage.

8.

Pressurizer Pressure The same sensors provide input to the Pressurizer Pressure-High and-Low trips and the Overtemperature 'T trip. The Pressurizer Pressure channels are also used to provide input to the Pressurizer Pressure Control System, therefore, the actuation logic must be able to withstand an input failure to the control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation.

a.

Pressurizer Pressure-Low The Pressurizer Pressure-Low trip Function ensures that protection is provided against violating the DNBR limit due to low pressure.

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The LCO requires four channels of Pressurizer Pressure-Low to be OPERABLE.

In MODE 1, when DNB is a major concern, the Pressurizer Pressure-Low trip must be OPERABLE. This trip Function is automatically enabled on increasing power by the P-7 interlock (NIS power range P-10 or turbine impulse pressure greater than approximately 10% of full power equivalent P-13). On decreasing power, this trip Function is automatically blocked below P-7. Below the P-7 setpoint, power distributions that would cause DNB concerns are unlikely.

b.

Pressurizer Pressure-High The Pressurizer Pressure-High trip Function ensures that protection is provided against overpressurizing the RCS.

This trip Function operates in conjunction with the pressurizer relief and safety valves to prevent RCS overpressure conditions.

The LCO requires four channels of the Pressurizer Pressure-High to be OPERABLE.

The Pressurizer Pressure-High LSSS is selected to be below the pressurizer safety valve actuation pressure and above the power operated relief valve (PORV) setting. This setting minimizes challenges to safety valves while avoiding unnecessary reactor trips for those pressure increases that can be controlled by the PORVs.

In MODE 1 or 2, the Pressurizer Pressure-High trip must be OPERABLE to help prevent RCS overpressurization and minimize challenges to the safety valves. In MODE 3, 4, 5, or 6, the Pressurizer Pressure-High trip Function does not have to be OPERABLE because transients that could cause an overpressure condition will either be slow to occur or will be mitigated by other trip functions required OPERABLE in these MODES. Therefore, the operator will have sufficient time when required to evaluate unit conditions and take corrective actions. Additionally, low temperature

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9.

Pressurizer Water Level-High The Pressurizer Water Level-High trip Function provides a backup signal for the Pressurizer Pressure-High trip and also provides protection against water relief through the pressurizer safety valves.

These valves are designed to pass steam in order to achieve their design energy removal rate. A reactor trip is actuated prior to the pressurizer becoming water solid. The setpoints are based on percent of instrument span. The LCO requires three channels of Pressurizer Water Level-High to be OPERABLE. The pressurizer level channels are used as input to the Pressurizer Level Control System. A fourth channel is not required to address control/protection interaction concerns. The level channels do not actuate the safety valves, and the high pressure reactor trip is set below the safety valve setting. Therefore, with the slow rate of charging available, pressure overshoot due to level channel failure cannot cause the valve to lift before reactor high pressure trip.

In MODE 1, when there is a potential for overfilling the pressurizer, the Pressurizer Water Level-High trip must be OPERABLE. This trip Function is automatically enabled on increasing power by the P-7 interlock. On decreasing power, this trip Function is automatically blocked below P-7. Below the P-7 setpoint, transients that could raise the pressurizer water level will be slow and the operator will have sufficient time to evaluate unit conditions and take corrective actions.

10.

Reactor Coolant Flow-Low

a.

Reactor Coolant Flow-Low (Single Loop)

The Reactor Coolant Flow-Low (Single Loop) trip Function ensures that protection is provided against violating the DNBR limit due to low flow in one or more RCS loops, while avoiding reactor trips due to normal variations in loop flow.

Above the P-8 setpoint, which is approximately 48% RTP, a loss of flow in any RCS loop will actuate a reactor trip. The

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The LCO requires three Reactor Coolant Flow-Low channels per loop to be OPERABLE in MODE 1 above P-8.

In MODE 1 above the P-8 setpoint, a loss of flow in one RCS loop could result in DNB conditions in the core. In MODE 1 below the P-8 setpoint, a loss of flow in two or more loops is required to actuate a reactor trip (Function 10.b) because of the lower power level and the greater margin to the design limit DNBR.

b.

Reactor Coolant Flow-Low (Two Loops)

The Reactor Coolant Flow-Low (Two Loops) trip Function ensures that protection is provided against violating the DNBR limit due to low flow in two or more RCS loops while avoiding reactor trips due to normal variations in loop flow.

Above the P-7 setpoint and below the P-8 setpoint, a loss of flow in two or more loops will initiate a reactor trip. The setpoints are based on the minimum flow specified in the COLR. Each loop has three flow detectors to monitor flow.

The flow signals are not used for any control system input.

The LCO requires three Reactor Coolant Flow-Low channels per loop to be OPERABLE.

In MODE 1 above the P-7 setpoint and below the P-8 setpoint, the Reactor Coolant Flow-Low (Two Loops) trip must be OPERABLE. Below the P-7 setpoint, all reactor trips on low flow are automatically blocked since power distributions that would cause a DNB concern at this low power level are unlikely. Above the P-7 setpoint, the reactor trip on low flow in two or more RCS loops is automatically enabled. Above the P-8 setpoint, a loss of flow in any one loop will actuate a reactor trip because of the higher power level and the reduced margin to the design limit DNBR.

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11.

Undervoltage Reactor Coolant Pumps The Undervoltage RCPs reactor trip Function ensures that protection is provided against violating the DNBR limit due to a loss of flow in two or more RCS loops. The voltage to each RCP is monitored. Above the P-7 setpoint, a loss of voltage detected on two or more RCP buses will initiate a reactor trip. This trip Function will generate a reactor trip before the Reactor Coolant Flow-Low (Two Loops) Trip Setpoint is reached. Time delays are incorporated into the Undervoltage RCPs channels to prevent reactor trips due to momentary electrical power transients.

The LCO requires a total of four Undervoltage RCPs channels (one per bus) to be OPERABLE.

In MODE 1 above the P-7 setpoint, the Undervoltage RCP trip must be OPERABLE. Below the P-7 setpoint, all reactor trips on loss of flow are automatically blocked since power distributions that would cause a DNB concern at this low power level are unlikely. Above the P-7 setpoint, the reactor trip on loss of flow in two or more RCS loops is automatically enabled.

12.

Underfrequency Reactor Coolant Pumps The Underfrequency RCPs reactor trip Function ensures that protection is provided against violating the DNBR limit due to a loss of flow in two or more RCS loops from a major network frequency disturbance. An underfrequency condition will slow down the pumps, thereby reducing their coastdown time following a pump trip. The proper coastdown time is required so that reactor heat can be removed immediately after reactor trip. The frequency of each RCP bus is monitored. Above the P-7 setpoint, a loss of frequency detected on two or more RCP buses will initiate a reactor trip. This trip Function will generate a reactor trip before the Reactor Coolant Flow-Low (Two Loops) Trip Setpoint is reached.

Time delays are incorporated into the Underfrequency RCPs channels to prevent reactor trips due to momentary electrical power transients.

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The LCO requires a total of four Underfrequency RCPs channels (one per bus) to be OPERABLE.

In MODE 1 above the P-7 setpoint, the Underfrequency RCPs trip must be OPERABLE. Below the P-7 setpoint, all reactor trips on loss of flow are automatically blocked since power distributions that would cause a DNB concern at this low power level are unlikely.

Above the P-7 setpoint, the reactor trip on loss of flow in two or more RCS loops is automatically enabled.

13.

Steam Generator Water Level-Low Low The SG Water Level-Low Low trip Function ensures that protection is provided against a loss of heat sink and actuates the AFW System prior to uncovering the SG tubes. The SGs are the heat sink for the reactor. In order to act as a heat sink, the SGs must contain a minimum amount of water. A narrow range low low level in any SG is indicative of a loss of heat sink for the reactor. The level transmitters provide input to the SG Level Control System.

Therefore, the actuation logic must be able to withstand an input failure to the control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation. This Function also performs the ESFAS function of starting the AFW pumps on low low SG level.

The LCO requires four channels of SG Water Level-Low Low per SG to be OPERABLE since these channels are shared between protection and control.

In MODE 1 or 2, when the reactor requires a heat sink, the SG Water Level-Low Low trip must be OPERABLE. The normal source of water for the SGs is the Main Feedwater (MFW) System (not safety related). The MFW System is normally in operation in MODES 1, 2, 3, or 4. The AFW System is the safety related backup source of water to ensure that the SGs remain the heat sink for the reactor. In MODE 3, 4, 5, or 6, the SG Water Level-Low Low Function does not have to be OPERABLE because the reactor is not operating or even critical. Decay heat removal is

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14.

Turbine Trip

a.

Turbine Trip-Low Fluid Oil Pressure The Turbine TripLow Fluid Oil Pressure trip Function anticipates the loss of heat removal capabilities of the secondary system following a turbine trip. This trip Function acts to minimize the pressure/temperature transient on the reactor. Any turbine trip from a power level below the P-9 setpoint, approximately 69% power, will not actuate a reactor trip. Four pressure switches monitor the control oil pressure in the Turbine Electrohydraulic Control System. A low pressure condition sensed by two-out-of-four pressure switches will actuate a reactor trip. These pressure switches do not provide any input to the control system. The unit is designed to withstand a complete loss of load and not sustain core damage or challenge the RCS pressure limitations. Core protection is provided by the Pressurizer Pressure-High trip Function and RCS integrity is ensured by the pressurizer safety valves. Turbine Trip-Low Fluid Oil Pressure is diverse to the Turbine Trip-Turbine Stop Valve Closure function.

The LCO requires four channels of Turbine Trip-Low Fluid Oil Pressure to be OPERABLE in MODE 1 above P-9.

Below the P-9 setpoint, a turbine trip does not actuate a reactor trip. In MODE 2, 3, 4, 5, or 6, there is no potential for a turbine trip, and the Turbine Trip-Low Fluid Oil Pressure trip Function does not need to be OPERABLE.

b.

Turbine Trip-Turbine Stop Valve Closure The Turbine Trip-Turbine Stop Valve Closure trip Function anticipates the loss of heat removal capabilities of the secondary system following a turbine trip from a power level above the P-9 setpoint, approximately 69% power. The trip Function anticipates the loss of secondary heat removal

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-22 Revision No. 11 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) capability that occurs when the stop valves close. Tripping the reactor in anticipation of loss of secondary heat removal acts to minimize the pressure and temperature transient on the reactor. This trip Function will not and is not required to operate in the presence of a single channel failure. The unit is designed to withstand a complete loss of load and not sustain core damage or challenge the RCS pressure limitations. Core protection is provided by the Pressurizer Pressure-High trip Function, and RCS integrity is ensured by the pressurizer safety valves. This trip Function is diverse to the Turbine Trip-Low Fluid Oil Pressure trip Function. Each turbine stop valve is equipped with one limit switch that inputs to the RTS. If all four limit switches indicate that the stop valves are closed, a reactor trip is initiated.

The LSSS for this Function is set to assure channel trip occurs when the associated stop valve is completely closed.

The LCO requires four Turbine Trip-Turbine Stop Valve Closure channels, one per valve, to be OPERABLE in MODE 1 above P-9. All four channels must trip to cause reactor trip.

Below the P-9 setpoint, a load rejection can be accommodated by the Steam Dump System. In MODE 2, 3, 4, 5, or 6, there is no potential for a load rejection, and the Turbine Trip-Stop Valve Closure trip Function does not need to be OPERABLE.

15.

Safety Injection Input from Engineered Safety Feature Actuation System The SI Input from ESFAS ensures that if a reactor trip has not already been generated by the RTS, the ESFAS automatic actuation logic will initiate a reactor trip upon any signal that initiates SI. This is a condition of acceptability for the LOCA.

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However, other transients and accidents take credit or varying levels of ESF performance and rely upon rod insertion, except for the most reactive rod that is assumed to be fully withdrawn, to ensure reactor shutdown. Therefore, a reactor trip is initiated every time an SI signal is present.

Trip Setpoint and Allowable Values are not applicable to this Function. The SI Input is provided by a manual switch or by the automatic actuation logic. Therefore, there is no measurement signal with which to associate an LSSS.

The LCO requires two trains of SI Input from ESFAS to be OPERABLE in MODE 1 or 2.

A reactor trip is initiated every time an SI signal is present.

Therefore, this trip Function must be OPERABLE in MODE 1 or 2, when the reactor is critical, and must be shut down in the event of an accident. In MODE 3, 4, 5, or 6, the reactor is not critical, and this trip Function does not need to be OPERABLE.

16.

Reactor Trip System Interlocks Reactor protection interlocks are provided to ensure reactor trips are in the correct configuration for the current unit status. They back up operator actions to ensure protection system Functions are not bypassed during unit conditions under which the safety analysis assumes the Functions are not bypassed. Therefore, the interlock Functions do not need to be OPERABLE when the associated reactor trip functions are outside the applicable MODES. These are:

a.

Intermediate Range Neutron Flux, P-6 The Intermediate Range Neutron Flux, P-6 interlock is actuated when any NIS intermediate range channel goes approximately three decades above the minimum channel reading. If both channels drop below the setpoint, the permissive will automatically be defeated. The LCO requirement for the P-6 interlock ensures that the following Functions are performed:

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-24 Revision No. 11 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) x on increasing power, the P-6 interlock allows the manual block of the NIS Source Range, Neutron Flux reactor trip. This prevents a premature block of the source range trip and allows the operator to ensure that the intermediate range is OPERABLE prior to leaving the source range.

x on decreasing power, the P-6 interlock automatically enables the NIS Source Range Neutron Flux reactor trip.

The LCO requires two channels of Intermediate Range Neutron Flux, P-6 interlock to be OPERABLE in MODE 2 when below the P-6 interlock setpoint.

Above the P-6 interlock setpoint, the NIS Source Range Neutron Flux reactor trip will be blocked, and this Function will no longer be necessary.

In MODE 3, 4, 5, or 6, the P-6 interlock does not have to be OPERABLE because the NIS Source Range is providing core protection.

b.

Low Power Reactor Trips Block, P-7 The Low Power Reactor Trips Block, P-7 interlock is actuated by input from either the Power Range Neutron Flux, P-10, or the Turbine Impulse Pressure, P-13 interlock. The LCO requirement for the P-7 interlock ensures that the following Functions are performed:

(1) on increasing power, the P-7 interlock automatically enables reactor trips on the following Functions:

x Pressurizer Pressure-Low; x

Pressurizer Water Level-High;

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-25 Revision No. 11 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) x Reactor Coolant Flow-Low (Two Loops);

x Undervoltage RCPs; and x

Underfrequency RCPs.

These reactor trips are only required when operating above the P-7 setpoint (approximately 10% power). The reactor trips provide protection against violating the DNBR limit.

Below the P-7 setpoint, the RCS is capable of providing sufficient natural circulation without any RCP running.

(2) on decreasing power, the P-7 interlock automatically blocks reactor trips on the following Functions:

x Pressurizer Pressure-Low; x

Pressurizer Water Level-High; x

Reactor Coolant Flow-Low (Two Loops);

x Undervoltage RCPs; and x

Underfrequency RCPs.

Trip Setpoint and Allowable Value are not applicable to the P-7 interlock because it is a logic Function and thus has no parameter with which to associate an LSSS.

The P-7 interlock is a logic Function with train and not channel identity. Therefore, the LCO requires one channel per train of Low Power Reactor Trips Block, P-7 interlock to be OPERABLE in MODE 1.

The low power trips are blocked below the P-7 setpoint and unblocked above the P-7 setpoint. In MODE 2, 3, 4, 5, or 6, this Function does not have to be OPERABLE because the interlock performs its Function when power level drops below 10% power, which is in MODE 1.

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c.

Power Range Neutron Flux, P-8 The Power Range Neutron Flux, P-8 interlock is actuated at approximately 48% power as determined by two-out-of-four NIS power range detectors. The P-8 interlock automatically enables the Reactor Coolant Flow-Low (Single Loop) reactor trip on low flow in one or more RCS loops on increasing power. The LCO requirement for this trip Function ensures that protection is provided against a loss of flow in any RCS loop that could result in DNB conditions in the core when greater than approximately 48% power. On decreasing power below the P-8 setpoint, the reactor trip on low flow in any loop is automatically blocked.

The LCO requires four channels of Power Range Neutron Flux, P-8 interlock to be OPERABLE in MODE 1.

In MODE 1, a loss of flow in one RCS loop could result in DNB conditions, so the Power Range Neutron Flux, P-8 interlock must be OPERABLE. In MODE 2, 3, 4, 5, or 6, this Function does not have to be OPERABLE because the core is not producing sufficient power to be concerned about DNB conditions.

d.

Power Range Neutron Flux, P-9 The Power Range Neutron Flux, P-9 interlock is actuated at approximately 69% power as determined by two-out-of-four NIS power range detectors. The LCO requirement for this Function ensures that the Turbine Trip-Low Fluid Oil Pressure and Turbine Trip-Turbine Stop Valve Closure reactor trips are enabled above the P-9 setpoint. Above the P-9 setpoint, a turbine trip will cause a load rejection beyond the capacity of the Steam Dump System. A reactor trip is automatically initiated on a turbine trip when it is above the P-9 setpoint, to minimize the transient on the reactor.

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The LCO requires four channels of Power Range Neutron Flux, P-9 interlock to be OPERABLE in MODE 1.

In MODE 1, a turbine trip could cause a load rejection beyond the capacity of the Steam Dump System, so the Power Range Neutron Flux interlock must be OPERABLE. In MODE 2, 3, 4, 5, or 6, this Function does not have to be OPERABLE because the reactor is not at a power level sufficient to have a load rejection beyond the capacity of the Steam Dump System.

e.

Power Range Neutron Flux, P-10 The Power Range Neutron Flux, P-10 interlock is actuated at approximately 10% power, as determined by two-out-of-four NIS power range detectors. If power level falls below 10% RTP on 3 of 4 channels, the nuclear instrument trips will be automatically unblocked. The LCO requirement for the P-10 interlock ensures that the following Functions are performed:

x on increasing power, the P-10 interlock allows the operator to manually block the Intermediate Range Neutron Flux reactor trip. Note that blocking the reactor trip also blocks the signal to prevent automatic and manual rod withdrawal; x

on increasing power, the P-10 interlock allows the operator to manually block the Power Range Neutron Flux-Low reactor trip; x

on increasing power, the P-10 interlock automatically provides a backup signal to block the Source Range Neutron Flux reactor trip;

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-28 Revision No. 11 APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) x the P-10 interlock provides one of the two inputs to the P-7 interlock; and x

on decreasing power, the P-10 interlock automatically enables the Power Range Neutron Flux-Low reactor trip and the Intermediate Range Neutron Flux reactor trip (and rod stop).

The LCO requires four channels of Power Range Neutron Flux, P-10 interlock to be OPERABLE in MODE 1 or 2.

OPERABILITY in MODE 1 ensures the Function is available to perform its decreasing power Functions in the event of a reactor shutdown. This Function must be OPERABLE in MODE 2 to ensure that core protection is provided during a startup or shutdown by the Power Range Neutron Flux-Low and Intermediate Range Neutron Flux reactor trips. In MODE 3, 4, 5, or 6, this Function does not have to be OPERABLE because the reactor is not at power and the Source Range Neutron Flux reactor trip provides core protection.

f.

Turbine Impulse Pressure, P-13 The Turbine Impulse Pressure, P-13 interlock is actuated when the pressure in the first stage of the high pressure turbine is greater than approximately 10% of the rated full power pressure. This is determined by one-out-of-two pressure detectors. The LCO requirement for this Function ensures that one of the inputs to the P-7 interlock is available.

The LCO requires two channels of Turbine Impulse Pressure, P-13 interlock to be OPERABLE in MODE 1.

The Turbine Impulse Chamber Pressure, P-13 interlock must be OPERABLE when the turbine generator is operating. The interlock Function is not required OPERABLE in MODE 2, 3, 4, 5, or 6 because the turbine generator is not operating.

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17.

Reactor Trip Breakers This trip Function applies to the RTBs exclusive of individual trip mechanisms. The LCO requires two OPERABLE trains of trip breakers. A trip breaker train consists of all trip breakers associated with a single RTS logic train that are racked in, closed, and capable of supplying power to the CRD System. Thus, the train may consist of the main breaker, bypass breaker, or main breaker and bypass breaker, depending upon the system configuration. Two OPERABLE trains ensure no single random failure can disable the RTS trip capability.

These trip Functions must be OPERABLE in MODE 1 or 2 when the reactor is critical. In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE when the RTBs or associated bypass breakers are closed, and the CRD System is capable of rod withdrawal.

18.

Reactor Trip Breaker Undervoltage and Shunt Trip Mechanisms The LCO requires both the Undervoltage and Shunt Trip Mechanisms to be OPERABLE for each RTB that is in service. The trip mechanisms are not required to be OPERABLE for trip breakers that are open, racked out, incapable of supplying power to the CRD System, or declared inoperable under Function 17 above.

OPERABILITY of both trip mechanisms on each breaker ensures that no single trip mechanism failure will prevent opening any breaker on a valid signal.

These trip Functions must be OPERABLE in MODE 1 or 2 when the reactor is critical. In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE when the RTBs or associated bypass breakers are closed, and the CRD System is capable of rod withdrawal.

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19.

Automatic Trip Logic The LCO requirement for the RTBs (Functions 17 and 18) and Automatic Trip Logic (Function 19) ensures that means are provided to interrupt the power to allow the rods to fall into the reactor core. Each RTB is equipped with an undervoltage coil and a shunt trip coil to trip the breaker open when needed. Each train RTB has a bypass breaker to allow testing of the trip breaker while the unit is at power. The reactor trip signals generated by the RTS Automatic Trip Logic cause the RTBs and associated bypass breakers to open and shut down the reactor.

The LCO requires two trains of RTS Automatic Trip Logic to be OPERABLE. Having two OPERABLE channels ensures that random failure of a single logic channel will not prevent reactor trip.

These trip Functions must be OPERABLE in MODE 1 or 2 when the reactor is critical. In MODE 3, 4, or 5, these RTS trip Functions must be OPERABLE when the RTBs and associated bypass breakers are closed, and the CRD System is capable of rod withdrawal.

The RTS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6).

ACTIONS A Note has been added to the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed in Table 3.3.1-1. When the Required Channels in Table 3.3.1-1 are specified (e.g., on a per steam line, per loop, per SG, etc., basis), then the Condition may be entered separately for each steam line, loop, SG, etc., as appropriate.

A channel shall be OPERABLE if the point at which the channel trips is found more conservative than the Allowable Value. In the event a channels trip setpoint is found less conservative than the Allowable Value, or the transmitter, instrument loop, signal processing electronics, or bistable is found inoperable, then all affected Functions provided by that channel must be declared inoperable and the LCO Condition(s) entered for the protection Function(s) affected. Unless otherwise specified, if plant conditions warrant, the trip setpoint may be set outside the NOMINAL TRIP SETPOINT calibration tolerance band as long as the trip setpoint is conservative with respect to the NOMINAL TRIP SETPOINT. If the trip setpoint is found outside of the NOMINAL TRIP SETPOINT calibration tolerance band and non-conservative with respect

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-31 Revision No. 11 ACTIONS (continued) to the NOMINAL TRIP SETPOINT, the setpoint shall be re-adjusted.

When the number of inoperable channels in a trip Function exceed those specified in one or other related Conditions associated with a trip Function, then the unit is outside the safety analysis. Therefore, LCO 3.0.3 must be immediately entered if applicable in the current MODE of operation.

A.1 Condition A applies to all RTS protection Functions. Condition A addresses the situation where one or more required channels for one or more Functions are inoperable at the same time. The Required Action is to refer to Table 3.3.1-1 and to take the Required Actions for the protection functions affected. The Completion Times are those from the referenced Conditions and Required Actions.

B.1 and B.2 Condition B applies to the Manual Reactor Trip in MODE 1 or 2. This action addresses the train orientation of the SSPS for this Function. With one channel inoperable, the inoperable channel must be restored to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. In this Condition, the remaining OPERABLE channel is adequate to perform the safety function.

The Completion Time of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> is reasonable considering that there are two automatic actuation trains and another manual initiation channel OPERABLE, and the low probability of an event occurring during this interval.

If the Manual Reactor Trip Function cannot be restored to OPERABLE status within the allowed 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> Completion Time, the unit must be brought to a MODE in which the requirement does not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 additional hours (54 hours6.25e-4 days <br />0.015 hours <br />8.928571e-5 weeks <br />2.0547e-5 months <br /> total time). The 6 additional hours are reasonable, based on operating experience, to reach MODE 3 from full power operation in an orderly manner and without challenging unit systems. With the unit in MODE 3, the MODE 1 and 2 requirements for this trip Function are no longer required and Condition C is entered.

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C.1 and C.2 Condition C applies to the following reactor trip Functions in MODE 3, 4, or 5 with the RTBs closed and the CRD System capable of rod withdrawal:

x Manual Reactor Trip; x

RTBs; x

RTB Undervoltage and Shunt Trip Mechanisms; and x

Automatic Trip Logic.

This action addresses the train orientation of the SSPS for these Functions. With one channel or train inoperable, the inoperable channel or train must be restored to OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. If the affected Function(s) cannot be restored to OPERABLE status within the allowed 48 hour5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> Completion Time, the unit must be placed in a condition in which the requirement does not apply. To achieve this status, the RTBs must be opened within the next hour. The additional hour provides sufficient time to accomplish the action in an orderly manner. With the RTBs open, these Functions are no longer required.

The Completion Time is reasonable considering that in this Condition, the remaining OPERABLE train is adequate to perform the safety function, and given the low probability of an event occurring during this interval.

D.1.1, D.1.2, and D.2 With one of the NIS power range detectors inoperable, 1/4 of the radial power distribution monitoring capability is lost. Therefore, SR 3.2.4.2 must be performed (Required Action D.1.1) within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of THERMAL POWER exceeding 75% RTP and once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter.

Calculating QPTR every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> compensates for the lost monitoring capability due to the inoperable NIS power range channel and allows continued unit operation at power levels> 75% RTP. At power levels <

75% RTP, operation of the core with radial power distributions beyond the design limits, at a power level where DNB conditions may exist, is prevented. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> Completion Time is consistent with the Surveillance Requirement Frequency in LCO 3.2.4, "QUADRANT POWER TILT RATIO (QPTR)." Required Action D.1.1 has been modified by a Note which only requires SR 3.2.4.2 to be performed if the

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-33 Revision No. 11 ACTIONS (continued)

Power Range Neutron Flux input to QPTR becomes inoperable. Failure of a component in the Power Range Neutron Flux Channel which renders the High Flux Trip Function inoperable may not affect the capability to monitor QPTR. As such, determining QPTR using movable incore detectors may not be necessary.

Condition D applies to the Power Range Neutron FluxHigh and Power Range Neutron Flux-High Positive Rate Functions.

The NIS power range detectors provide input to the CRD System and the SG Water Level Control System and, therefore, have a two-out-of-four trip logic. A known inoperable channel must be placed in the tripped condition. This results in a partial trip condition requiring only one-out-of-three logic for actuation. The 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed to place the inoperable channel in the tripped condition is justified in WCAP-14333-P-A (Ref. 11).

As an alternative to the above Actions, the plant must be placed in a MODE where this Function is no longer required OPERABLE. 78 hours9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> are allowed to place the plant in MODE 3. The 78 hour9.027778e-4 days <br />0.0217 hours <br />1.289683e-4 weeks <br />2.9679e-5 months <br /> Completion Time includes 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> for channel corrective maintenance, and an additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> for the MODE reduction as required by Required Action D.2. This is a reasonable time, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging plant systems. If Required Actions cannot be completed within their allowed Completion Times, LCO 3.0.3 must be entered.

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypass condition for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> while performing routine surveillance testing of other channels. The Note also allows placing the inoperable channel in the bypass condition to allow setpoint adjustments of other channels when required to reduce the setpoint in accordance with other Technical Specifications. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time limit is justified in Reference 11.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-34 Revision No. 11 ACTIONS (continued)

E.1 and E.2 Condition E applies to the following reactor trip Functions:

x Power Range Neutron Flux-Low; x

Overtemperature 'T; x

Overpower 'T; x

Pressurizer Pressure-High; and x

SG Water Level-Low Low.

A known inoperable channel must be placed in the tripped condition within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Placing the channel in the tripped condition results in a partial trip condition requiring only one-out-of-three logic for actuation of the two-out-of-four trips. The 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed to place the inoperable channel in the tripped condition is justified in Reference 11.

If the operable channel cannot be placed in the trip condition within the specified Completion Time, the unit must be placed in a MODE where these Functions are not required OPERABLE. An additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is allowed to place the unit in MODE 3. Six hours is a reasonable time, based on operating experience, to place the unit in MODE 3 from full power in an orderly manner and without challenging unit systems.

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> while performing routine surveillance testing of the other channels. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time limit is justified in Reference 11.

F.1 and F.2 Condition F applies to the Intermediate Range Neutron Flux trip when THERMAL POWER is above the P-6 setpoint and below the P-10 setpoint and one channel is inoperable. Above the P-6 setpoint and below

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-35 Revision No. 11 ACTIONS (continued) the P-10 setpoint, the NIS intermediate range detector performs the monitoring Functions. If THERMAL POWER is greater than the P-6 setpoint but less than the P-10 setpoint, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is allowed to reduce THERMAL POWER below the P-6 setpoint or increase to THERMAL POWER above the P-10 setpoint. The NIS Intermediate Range Neutron Flux channels must be OPERABLE when the power level is above the capability of the source range, P-6, and below the capability of the power range, P-10. If THERMAL POWER is greater than the P-10 setpoint, the NIS power range detectors perform the monitoring and protection functions and the intermediate range is not required. The Completion Times allow for a slow and controlled power adjustment above P-10 or below P-6 and take into account the redundant capability afforded by the redundant OPERABLE channel, and the low probability of its failure during this period. This action does not require the inoperable channel to be tripped because the Function uses one-out-of-two logic. Tripping one channel would trip the reactor. Thus, the Required Actions specified in this Condition are only applicable when channel failure does not result in reactor trip.

G.1 and G.2 Condition G applies to two inoperable Intermediate Range Neutron Flux trip channels in MODE 2 when THERMAL POWER is above the P-6 setpoint and below the P-10 setpoint.

Required Actions specified in this Condition are only applicable when channel failures do not result in reactor trip. Above the P-6 setpoint and below the P-10 setpoint, the NIS intermediate range detector performs the monitoring Functions. With no intermediate range channels OPERABLE, the Required Actions are to suspend operations involving positive reactivity additions immediately. This will preclude any power level increase since there are no OPERABLE Intermediate Range Neutron Flux channels. The operator must also reduce THERMAL POWER below the P-6 setpoint within two hours. Below P-6, the Source Range Neutron Flux channels will be able to monitor the core power level.

The Completion Time of 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> will allow a slow and controlled power reduction to less than the P-6 setpoint and takes into account the low probability of occurrence of an event during this period that may require the protection afforded by the NIS Intermediate Range Neutron Flux trip.

Required Action G.1 is modified by a Note to indicate that normal plant control operations that individually add limited positive reactivity (e.g.,

temperature or boron fluctuations associated with RCS inventory management or temperature control) are not precluded by this

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Action.

H.1 Condition H applies to the Intermediate Range Neutron Flux trip when THERMAL POWER is below the P-6 setpoint and one or two channels are inoperable. Below the P-6 setpoint, the NIS source range performs the monitoring and protection functions. The inoperable NIS intermediate range channel(s) must be returned to OPERABLE status prior to increasing power above the P-6 setpoint. The NIS intermediate range channels must be OPERABLE when the power level is above the capability of the source range, P-6, and below the capability of the power range, P-10.

I.1 Condition I applies to one inoperable Source Range Neutron Flux trip channel when in MODE 2, below the P-6 setpoint, and performing a reactor startup. With the unit in this Condition, below P-6, the NIS source range performs the monitoring and protection functions. With one of the two channels inoperable, operations involving positive reactivity additions shall be suspended immediately. This will preclude any power escalation.

With only one source range channel OPERABLE, core protection is severely reduced and any actions that add positive reactivity to the core must be suspended immediately. Required Action I.1 is modified by a Note to indicate that normal plant control operations that individually add limited positive reactivity (e.g., temperature or boron fluctuations associated with RCS inventory management or temperature control) are not precluded by this Action.

J.1 Condition J applies to two inoperable Source Range Neutron Flux trip channels when in MODE 2, below the P-6 setpoint, and performing a reactor startup, or in MODE 3, 4, or 5 with the RTBs closed and the CRD System capable of rod withdrawal. With the unit in this Condition, below P-6, the NIS source range performs the monitoring and protection functions. With both source range channels inoperable, the RTBs must be opened immediately. With the RTBs open, the core is in a more stable condition and the unit exits this Condition.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-37 Revision No. 11 ACTIONS (continued)

K.1 and K.2 Condition K applies to one inoperable source range channel in MODE 3, 4, or 5 with the RTBs closed and the CRD System capable of rod withdrawal. With the unit in this Condition, below P-6, the NIS source range performs the monitoring and protection functions. With one of the source range channels inoperable, 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> is allowed to restore it to an OPERABLE status. If the channel cannot be returned to an OPERABLE status, 1 additional hour is allowed to open the RTBs. Once the RTBs are open, the core is in a more stable condition and the unit exits this condition. The allowance of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> to restore the channel to OPERABLE status, and the additional hour to open the RTBs, are justified in Reference 7.

L.1 and L.2 Condition L applies to the following reactor trip Functions:

x Pressurizer Pressure-Low; x

Pressurizer Water Level-High; x

Reactor Coolant Flow-Low (Two Loops);

x Undervoltage RCPs; and x

Underfrequency RCPs.

With one channel inoperable, the inoperable channel must be placed in the tripped condition within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Placing the channel in the tripped condition results in a partial trip condition requiring only one additional channel to initiate a reactor trip above the P-7 setpoint 7 (and below the P-8 setpoint for the Reactor Coolant Flow-Low (Two Loops) Function).

These Functions do not have to be OPERABLE below the P-7 setpoint because, for the Pressurizer Water Level-High function, transients are slow enough for manual action; and for the other functions, power distributions that would cause a DNB concern at this low power level are unlikely. The 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed to place the channel in the tripped

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-38 Revision No. 11 ACTIONS (continued) condition is justified in Reference 11. An additional 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is allowed to reduce THERMAL POWER to below P-7 if the inoperable channel cannot be restored to OPERABLE status or placed in trip within the specified Completion Time.

Allowance of this time interval takes into consideration the redundant capability provided by the remaining redundant OPERABLE channel, and the low probability of occurrence of an event during this period that may require the protection afforded by the Functions associated with Condition L.

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> while performing routine surveillance testing of the other channels. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time limit is justified in Reference 11.

M.1 and M.2 Condition M applies to the Reactor Coolant Flow-Low (Single Loop) reactor trip Function. With one channel inoperable, the inoperable channel must be placed in trip within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. If the channel cannot be restored to OPERABLE status or the channel placed in trip within the 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, then THERMAL POWER must be reduced below the P-8 setpoint within the next 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. This places the unit in a MODE where the LCO is no longer applicable. This trip Function does not have to be OPERABLE below the P-8 setpoint because other RTS trip Functions provide core protection below the P-8 setpoint. The 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> allowed to restore the channel to OPERABLE status or place in trip and the 4 additional hours allowed to reduce THERMAL POWER to below the P-8 setpoint are justified in Reference 7.

The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> while performing routine surveillance testing of the other channels. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time limit is justified in Reference 7.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-39 Revision No. 11 ACTIONS (continued)

N.1, N.2, 0.1, and 0.2 Condition N and 0 apply to Turbine Trip on Stop Valve EH Pressure Low or on Turbine Stop Valve Closure. With one channel inoperable, the inoperable channel must be placed in the trip condition within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. If placed in the tripped condition, this results in a partial trip condition requiring fewer additional channels to initiate a reactor trip. If the channel cannot be restored to OPERABLE status or placed in the trip condition, then power must be reduced below the P-9 setpoint within the next 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed to place the inoperable channel in the tripped condition and the 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> allowed for reducing power are justified in Reference 11.

The Required Actions of Condition N have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> while performing routine surveillance testing of the other channels. The 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> time limit is justified in Reference 11.

P.1 and P.2 Condition P applies to the SI Input from ESFAS reactor trip and the RTS Automatic Trip Logic in MODES 1 and 2. These actions address the train orientation of the RTS for these Functions. With one train inoperable, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> are allowed to restore the train to OPERABLE status (Required Action P.1) or the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

The Completion Time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> (Required Action P.1) is reasonable considering that in this Condition, the remaining OPERABLE train is adequate to perform the safety function and given the low probability of an event during this interval. The 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> allowed to restore the inoperable RTS Automatic Trip Logic train to OPERABLE status is justified in Reference 11. The additional Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (Required Action P.2) is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging unit systems.

The Required Actions have been modified by a Note that allows bypassing one train up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing, provided the other train is OPERABLE. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time limit for testing the RTS Automatic Trip Logic train may include testing the RTB also, if both the Logic test and RTB test are conducted within the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time limit. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time limit is justified in Reference 11.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-40 Revision No. 11 ACTIONS (continued)

Q.1 and Q.2 Condition Q applies to the RTBs in MODES 1 and 2. These actions address the train orientation of the RTS for the RTBs. With one train inoperable, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is allowed for train corrective maintenance to restore the train to OPERABLE status or the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. The 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Completion Time is justified in Reference 12. The Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging unit systems. Placing the unit in MODE 3 removes the requirement for this particular Function.

The Required Actions have been modified by a Note. The Note allows one RTB to be bypassed for up to 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> for surveillance testing, provided the other RTB is OPERABLE. The 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> time limit is justified in Reference 12.

R.1 and R.2 Condition R applies to the P-6 and P-10 interlocks. With one or more channel(s) inoperable for one-out-of-two or two-out-of-four coincidence logic, the associated interlock must be verified to be in its required state for the existing unit condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or the unit must be placed in MODE 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. Verifying the interlock status, by visual observation of the control room status lights, manually accomplishes the interlock's Function. The Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is based on operating experience and the minimum amount of time allowed for manual operator actions. The Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging unit systems. The 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 6 hour6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Completion Times are equal to the time allowed by LCO 3.0.3 for shutdown actions in the event of a complete loss of RTS Function.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-41 Revision No. 11 ACTIONS (continued)

S.1 and S.2 Condition S applies to the P-7, P-8, P-9, and P-13 interlocks. With one or more channel(s) inoperable for one-out-of-two or two-out-of-four coincidence logic, the associated interlock must be verified to be in its required state for the existing unit condition within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or the unit must be placed in MODE 2 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. These actions are conservative for the case where power level is being raised. Verifying the interlock status, by visual observation of the control room status lights, manually accomplishes the interlock's Function. The Completion Time of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is based on operating experience and the minimum amount of time allowed for manual operator actions. The Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is reasonable, based on operating experience, to reach MODE 2 from full power in an orderly manner and without challenging unit systems.

T.1 and T.2 Condition T applies to the RTB Undervoltage and Shunt Trip Mechanisms, or diverse trip features, in MODES 1 and 2. With one of the diverse trip features inoperable, it must be restored to an OPERABLE status within 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> or the unit must be placed in a MODE where the requirement does not apply. This is accomplished by placing the unit in MODE 3 within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> (54 hours6.25e-4 days <br />0.015 hours <br />8.928571e-5 weeks <br />2.0547e-5 months <br /> total time). With both diverse trip features inoperable, the reactor trip breaker is inoperable and Condition Q is entered. The Completion Time of 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> is a reasonable time, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging unit systems. With the unit in MODE 3, the MODES 1 and 2 requirement for this function is no longer required and Condition C is entered.

The Completion Time of 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> for Required Action T.1 is reasonable considering that in this Condition there is one remaining diverse feature for the affected RTB, and one OPERABLE RTB capable of performing the safety function and given the low probability of an event occurring during this interval.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-42 Revision No. 11 ACTIONS (continued)

U.1 With two RTS trains inoperable, no automatic capability is available to shut down the reactor, and immediate plant shutdown in accordance with LCO 3.0.3 is required.

SURVEILLANCE The SRs for each RTS Function are identified by the SRs column of REQUIREMENTS Table 3.3.1-1 for that Function.

A Note has been added to the SR Table stating that Table 3.3.1-1 determines which SRs apply to which RTS Functions.

Note that each channel of process protection supplies both trains of the RTS. When testing Channel I, Train A and Train B must be examined.

Similarly, Train A and Train B must be examined when testing Channel II, Channel III, and Channel IV (if applicable). The CHANNEL CALIBRATION and COTs are performed in a manner that is consistent with the assumptions used in analytically calculating the required channel accuracies.

SR 3.3.1.1 Performance of the CHANNEL CHECK ensures that 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 two instrument channels could be an indication of excessive instrument drift in one of the channels or of something even more serious. A CHANNEL CHECK will detect gross channel failure; thus, it is key to verifying that the instrumentation continues to operate properly between each CHANNEL CALIBRATION.

Agreement criteria are determined by the unit 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 sensor or the signal processing equipment has drifted outside its limit.

The Surveillance Frequency is based on operating experience, equipment

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-43 Revision No. 11 SURVEILLANCE REQUIREMENTS (continued) reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.2 SR 3.3.1.2 compares the calorimetric heat balance calculation to the NIS channel output. If the calorimetric exceeds the NIS channel output by

> 2% RTP, the NIS is not declared inoperable, but must be adjusted. If the NIS channel output cannot be properly adjusted, the channel is declared inoperable.

Two Notes modify SR 3.3.1.2. The first Note indicates that the NIS channel output shall be adjusted consistent with the calorimetric results if the absolute difference between the NIS channel output and the calorimetric is > 2% RTP. The second Note clarifies that this Surveillance is required only if reactor power is t 15% RTP and that 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> is allowed for completing the first Surveillance after reaching 15% RTP. At lower power levels, calorimetric data are inaccurate.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.3 SR 3.3.1.3 compares the incore system to the NIS channel output. If the absolute difference is t 3%, the NIS channel is still OPERABLE, but must be readjusted.

If the NIS channel cannot be properly readjusted, the channel is declared inoperable. This Surveillance is performed to verify the f('I) input to the overtemperature 'T Function and overpower 'T Function.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-44 Revision No. 11 SURVEILLANCE REQUIREMENTS (continued)

Two Notes modify SR 3.3.1.3. Note 1 indicates that the excore NIS channel shall be adjusted if the absolute difference between the incore and excore AFD is t 3%. Note 2 clarifies that the Surveillance is required only if reactor power is t 15% RTP and that 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is allowed for completing the first Surveillance after reaching 15% RTP.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.4 SR 3.3.1.4 is the performance of a TADOT. This test shall verify OPERABILITY by actuation of the end devices.

The RTB test shall include separate verification of the undervoltage and shunt trip mechanisms. Independent verification of RTB undervoltage and shunt trip Function is not required for the bypass breakers. No capability is provided for performing such a test at power. The independent test for bypass breakers is included in SR 3.3.1.14. The bypass breaker test shall include a local shunt trip. A Note has been added to indicate that this test must be performed on the bypass breaker prior to placing it in service.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.5 SR 3.3.1.5 is the performance of an ACTUATION LOGIC TEST. The SSPS is tested using the semiautomatic tester. The train being tested is placed in the bypass condition, thus preventing inadvertent actuation.

Through the semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-45 Revision No. 11 SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.1.6 SR 3.3.1.6 is a calibration of the excore channels to the incore channels.

If the measurements do not agree, the excore channels are not declared inoperable but must be calibrated to agree with the incore detector measurements. If the excore channels cannot be adjusted, the channels are declared inoperable. This Surveillance is performed to verify the f('I) input to the overtemperature 'T Function and overpower 'T Function.

At Beginning of Cycle (BOC), the excore channels are compared to the incore detector measurements prior to exceeding 75% power. Excore detectors are adjusted as necessary. This low power surveillance satisfies the initial performance of SR 3.3.1.6 with subsequent surveillances conducted at least every 92 EFPD.

At BOC, after reaching full power steady state conditions, additional incore and excore measurements are taken and excore detectors are adjusted as necessary.

The Mj factors are normally only determined at BOC, but they may be changed at other points in the fuel cycle if the relationship between excore and incore measurements changes significantly.

A Note modifies SR 3.3.1.6. The Note states that this Surveillance is required only if reactor power is > 75% RTP and that 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is allowed for completing the first surveillance after reaching 75% RTP.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.7 SR 3.3.1.7 is the performance of a COT.

A COT is performed on each required channel to ensure the channel will perform the intended Function.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-46 Revision No. 11 SURVEILLANCE REQUIREMENTS (continued)

The tested portion of the loop must trip within the Allowable Values specified in Table 3.3.1-1.

The setpoint shall be left set consistent with the assumptions of the setpoint methodology.

SR 3.3.1.7 is modified by a Note that provides a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> delay in the requirement to perform this Surveillance for source range instrumentation when entering MODE 3 from MODE 2. This Note allows a normal shutdown to proceed without a delay for testing in MODE 2 and for a short time in MODE 3 until the RTBs are open and SR 3.3.1.7 is no longer required to be performed. If the unit is to be in MODE 3 with the RTBs closed for > 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> this Surveillance must be completed within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after entry into MODE 3.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

For Functions for which TSTF-493, Clarify Application of Setpoint Methodology for LSSS Functions (Reference 13) has been implemented, this SR is modified by two Notes as identified in Table 3.3.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value.

Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition.

The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the NOMINAL TRIP SETPOINT (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-47 Revision No. 11 SURVEILLANCE REQUIREMENTS (continued) channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second Note applies.

SR 3.3.1.8 SR 3.3.1.8 is the performance of a COT as described in SR 3.3.1.7, except it is modified by a Note that this test shall include verification that the P-6, during the Intermediate Range COT, and P-10, during the Power Range COT, interlocks are in their required state for the existing unit condition. The verification is performed by visual observation of the permissive status light in the unit control room. The Frequency is modified by a Note that allows this surveillance to be satisfied if it has been performed within the Frequency specified in the Surveillance Frequency Control Program prior to reactor startup and four hours after reducing power below P-10 and P-6. The Frequency of "prior to startup" ensures this surveillance is performed prior to critical operations and applies to the source, intermediate and power range low instrument channels. The Frequency of "4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reducing power below P-10" (applicable to intermediate and power range low channels) and "4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after reducing power below P-6" (applicable to source range channels) allows a normal shutdown to be completed and the unit removed from the MODE of Applicability for this surveillance without a delay to perform the testing required by this surveillance. The Frequency thereafter applies if the plant remains in the MODE of Applicability after the initial performances of prior to reactor startup and four hours after reducing power below P-10 or P-6. The MODE of Applicability for this surveillance is < P-10 for the power range low and intermediate range channels and <

P-6 for the source range channels.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-48 Revision No. 11 SURVEILLANCE REQUIREMENTS (continued)

Once the unit is in MODE 3, this surveillance is no longer required. If power is to be maintained < P-10 or < P-6 for more than 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />, then the testing required by this surveillance must be performed prior to the expiration of the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> limit. Four hours is a reasonable time to complete the required testing or place the unit in a MODE where this surveillance is no longer required. This test ensures that the NIS source, intermediate, and power range low channels are OPERABLE prior to taking the reactor critical and after reducing power into the applicable MODE (< P-10 or < P-

6) for periods > 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

For Functions for which TSTF-493, Clarify Application of Setpoint Methodology for LSSS Functions (Reference 13) has been implemented, this SR is modified by two Notes as identified in Table 3.3.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value.

Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition.

The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the NOMINAL TRIP SETPOINT (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second Note applies.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-49 Revision No. 11 SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.1.9 SR 3.3.1.9 is the performance of a TADOT and the Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

The SR is modified by a Note that excludes verification of setpoints from the TADOT. Since this SR applies to RCP undervoltage and underfrequency relays, setpoint verification is accomplished during the CHANNEL CALIBRATION.

SR 3.3.1.10 CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to a measured parameter within the necessary range and accuracy.

CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the setpoint methodology.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.10 is modified by a Note stating that this test shall include verification that the time constants are adjusted to the prescribed values where applicable. The applicable time constants are shown in Table 3.3.1-1.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-50 Revision No. 11 SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.1.11 SR 3.3.1.11 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10. Two Notes modify this SR. Note 1 states that neutron detectors are excluded from the CHANNEL CALIBRATION. The CHANNEL CALIBRATION for the power range neutron detectors consists of a normalization of the detectors based on a power calorimetric and flux map performed above 15% RTP. The CHANNEL CALIBRATION for the fission chamber source and intermediate range neutron detectors consists of verifying that the channels respond correctly to test inputs with the necessary range and accuracy. Note 2 states that this Surveillance is not required for the NIS power range detectors for entry into MODE 2 or 1. Note 2 is required because the unit must be in MODE 1 to perform the test for the power range detectors. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-51 Revision No. 11 SURVEILLANCE REQUIREMENTS (continued)

For Functions for which TSTF-493, Clarify Application of Setpoint Methodology for LSSS Functions (Reference 13) has been implemented, this SR is modified by two Notes as identified in Table 3.3.1-1. The first Note requires evaluation of channel performance for the condition where the as-found setting for the channel setpoint is outside its as-found tolerance but conservative with respect to the Allowable Value.

Evaluation of channel performance will verify that the channel will continue to behave in accordance with safety analysis assumptions and the channel performance assumptions in the setpoint methodology. The purpose of the assessment is to ensure confidence in the channel performance prior to returning the channel to service. For channels determined to be OPERABLE but degraded, after returning the channel to service the performance of these channels will be evaluated under the plant Corrective Action Program. Entry into the Corrective Action Program will ensure required review and documentation of the condition.

The second Note requires that the as-left setting for the channel be returned to within the as-left tolerance of the NOMINAL TRIP SETPOINT (NTSP). Where a setpoint more conservative than the NTSP is used in the plant surveillance procedures (field setting), the as-left and as-found tolerances, as applicable, will be applied to the surveillance procedure setpoint. This will ensure that sufficient margin to the Safety Limit and/or Analytical Limit is maintained. If the as-left channel setting cannot be returned to a setting within the as-left tolerance of the NTSP, then the channel shall be declared inoperable. The second Note also requires that the methodologies for calculating the as-left and the as-found tolerances be in the UFSAR. The NOMINAL TRIP SETPOINT definition includes a provision that would allow the as-left setting for the channel to be outside the tolerance band, provided the setting is conservative with respect to the NTSP. This provision is not applicable to Functions for which the second Note applies.

SR 3.3.1.12 SR 3.3.1.12 is the performance of a CHANNEL CALIBRATION, as described in SR 3.3.1.10.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-52 Revision No. 11 SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.1.13 SR 3.3.1.13 is the performance of a COT of RTS interlocks.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.14 SR 3.3.1.14 is the performance of a TADOT of the Manual Reactor Trip and the SI Input from ESFAS. The test shall independently verify the OPERABILITY of the undervoltage and shunt trip mechanisms for the Manual Reactor Trip Function for the Reactor Trip Breakers and Reactor Trip Bypass Breakers. The Reactor Trip Bypass Breaker test shall include testing of the automatic undervoltage trip.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

The SR is modified by a Note that excludes verification of setpoints from the TADOT. The Functions affected have no setpoints associated with them.

SR 3.3.1.15 SR 3.3.1.15 is the performance of a TADOT of Turbine Trip Functions.

This TADOT is as described in SR 3.3.1.4, except that this test is performed prior to reactor startup. A Note states that this Surveillance is not required if it has been performed within the previous 31 days.

Verification of the Trip Setpoint does not have to be performed for this Surveillance. Performance of this test will ensure that the turbine trip Function is OPERABLE prior to taking the reactor critical.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-53 Revision No. 11 SURVEILLANCE REQUIREMENTS (continued)

SR 3.3.1.16 and SR 3.3.1.17 SR 3.3.1.16 and SR 3.3.1.17 verify that the individual channel/train actuation response times are less than or equal to the maximum values assumed in the accident analysis. Response time testing acceptance criteria are included in the UFSAR (Ref. 1). Individual component response times are not modeled in the analyses.

The analyses model the overall or total elapsed time, from the point at which the parameter exceeds the trip setpoint value at the sensor to the point at which the equipment reaches the required functional state (i.e.,

control and shutdown rods fully inserted in the reactor core).

For channels that include dynamic transfer Functions (e.g., lag, lead/lag, rate/lag, etc.), the response time test may be performed with the transfer Function set to one, with the resulting measured response time compared to the appropriate UFSAR response time. Alternately, the response time test can be performed with the time constants set to their nominal value, provided the required response time is analytically calculated assuming the time constants are set at their nominal values. The response time may be measured by a series of overlapping tests such that the entire response time is measured.

Response time may be verified by actual response time tests in any series of sequential, overlapping or total channel measurements, or by the summation of allocated sensor, signal processing and actuation logic response times with actual response time tests on the remainder of the channel. Allocations for sensor response times may be obtained from: (1) historical records based on acceptable response time tests (hydraulic, noise, or power interrupt tests), (2) in place, onsite, or offsite (e.g. vendor) test measurements, or (3) utilizing vendor engineering specifications.

WCAP-13632-P-A Revision 2, "Elimination of Pressure Sensor Response Time Testing Requirements" provides the basis and methodology for using allocated sensor response times in the overall verification of the channel response time for specific sensors identified in the WCAP. In addition, while not specifically identified in the WCAP, ITT Barton 386A and 580A-0 sensors were compared to sensors which were identified. It was concluded that the WCAP results could be applied to these two sensor types as well. Response time verification for other sensor types must be demonstrated by test.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-54 Revision No. 11 SURVEILLANCE REQUIREMENTS (continued)

WCAP-14036-P-A Revision 1, "Elimination of Periodic Protection Channel Response Time Tests" provides the basis and methodology for using allocated signal processing and actuation logic response times in the overall verification of the protection system channel response time. The allocations for sensor, signal conditioning and actuation logic response times must be verified prior to placing the component in operational service and re-verified following maintenance that may adversely affect response time. In general, electrical repair work does not impact response time provided the parts used for repair are of the same type and value. Specific components identified in the WCAP may be replaced without verification testing. One example where response time could be affected is replacing the sensing assembly of a transmitter.

The response time may be verified for components that replace the components that were previously evaluated in Ref. 8 and Ref. 9, provided that the components have been evaluated in accordance with the NRC approved methodology as discussed in Attachment 1 to TSTF-569, Rev. 2, Methodology to Eliminate Pressure Sensor and Protection Channel (for Westinghouse Plants only) Response Time Testing, (Ref. 14).

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.3.1.16 is modified by a Note stating that neutron detectors are excluded from RTS RESPONSE TIME testing. This Note is necessary because of the difficulty in generating an appropriate detector input signal. Excluding the detectors is acceptable because the principles of detector operation ensure a virtually instantaneous response. The response time of the neutron flux signal portion of the channel shall be measured from detector output or input of the first electronic component in the channel.

REFERENCES

1. UFSAR, Chapter 7.

2. UFSAR, Chapter 6.

3. UFSAR, Chapter 15.

4. IEEE-279-1971.

5. 10 CFR 50.49.

RTS Instrumentation B 3.3.1 BASES Catawba Units 1 and 2 B 3.3.1-55 Revision No. 11 REFERENCES (continued)

6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).

7. WCAP-10271-P-A, Supplement 2, Rev. 1, June 1990.

8. WCAP-13632-P-A Revision 2, Elimination of Pressure Sensor Response Time Testing Requirements Sep., 1995.

9. WCAP-14036-P-A Revision 1, Elimination of Periodic Protection Channel Response Time Tests Oct., 1998.

10.10 CFR 50.67.

11.WCAP-14333-P-A, Rev. 1, October 1998.

12.WCAP-15376-P-A, Rev. 1, March 2003.

13. Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, Clarify Application of Setpoint Methodology for LSSS Functions Revision 4.

14. Attachment 1 to TSTF-569, Rev. 2, Methodology to Eliminate Pressure Sensor and Protection Channel (for Westinghouse Plants only) Response Time Testing.

Catawba Units 1 and 2 B 3.4.14-1 Revision No. 4 RCS PIV Leakage B 3.4.14 B 3.4 REACTOR COOLANT SYSTEM (RCS)

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

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

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

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

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

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

a.

Residual Heat Removal (RHR) System;

b.

Safety Injection System; and

c.

Chemical and Volume Control System.

RCS PIV Leakage B 3.4.14 BASES Catawba Units 1 and 2 B 3.4.14-2 Revision No. 4 BACKGROUND (continued)

The PIVs are listed in the UFSAR, Table 5-41 (Ref. 6).

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

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

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

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

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

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

Reference 8 permits leakage testing at a lower pressure differential than between the specified maximum RCS pressure and the normal pressure of the connected system during RCS operation (the maximum pressure differential) in those types of valves in which the higher service pressure

RCS PIV Leakage B 3.4.14 BASES Catawba Units 1 and 2 B 3.4.14-3 Revision No. 4 LCO (continued) will tend to diminish the overall leakage channel opening. In such cases, the observed rate may be adjusted to the maximum pressure differential by assuming leakage is directly proportional to the pressure differential to the one half power.

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

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

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

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

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

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

RCS PIV Leakage B 3.4.14 BASES Catawba Units 1 and 2 B 3.4.14-4 Revision No. 4 ACTIONS (continued)

B.1 and B.2 If leakage cannot be reduced, or the other Required Actions accomplished, the plant must be brought to a MODE in which the requirement does not apply. To achieve this status, the plant must be brought to MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. This Action may reduce the leakage and also reduces the potential for a LOCA outside the containment. The allowed Completion Times are reasonable based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.

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

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

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

The Surveillance Frequency is in accordance with the INSERVICE TESTING PROGRAM, which is based on the applicable edition and addenda of the ASME OM Code as incorporated by reference in 10 CFR 50.55a.

RCS PIV Leakage B 3.4.14 BASES Catawba Units 1 and 2 B 3.4.14-5 Revision No. 4 SURVEILLANCE REQUIREMENTS (continued)

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

Entry into MODES 3 and 4 is allowed to establish the necessary differential pressures and stable conditions to allow for performance of this Surveillance. In addition, this Surveillance is not required to be performed on the RHR System when the RHR System is aligned to the RCS in the shutdown cooling mode of operation. PIVs contained in the RHR shutdown cooling flow path must be leakage rate tested after RHR is secured and stable unit conditions and the necessary differential pressures are established.

SR 3.4.14.2 Verifying that the RHR interlock is OPERABLE ensures that RCS pressure will not pressurize the RHR system beyond its design pressure of 600 psig. The interlock setpoint that prevents the valves from being opened is set so the actual RCS pressure must be < 425 psig to open the valves. This setpoint ensures the RHR design pressure will not be exceeded and the RHR relief valves will not lift. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

RCS PIV Leakage B 3.4.14 BASES Catawba Units 1 and 2 B 3.4.14-6 Revision No. 4 REFERENCES

1.

10 CFR 50.2.

2.

10 CFR 50.55a(c).

3.

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

4.

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

5.

NUREG-0677, May 1980.

6.

UFSAR Table 5-41.

7.

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

8.

ASME Code for Operation and Maintenance of Nuclear Power Plants.

9.

Not used.

Catawba Units 1 and 2 B 3.7.11-1 Revision No. 6 CRACWS B 3.7.11 B 3.7 PLANT SYSTEMS B 3.7.11 Control Room Area Chilled Water System (CRACWS)

BASES BACKGROUND The CRACWS provides temperature control for the control room and the control room area.

The CRACWS consists of two independent and redundant trains that provide cooling to the control room and control room area. Each train consists of a chiller package, chilled water pump, and air handling units with cooling coils. Chilled water is passed through the cooling coils of the air handling unit to cool the air. Electric duct heaters are then used to control the supply air temperature.

The CRACWS provides both normal and emergency cooling to the control room and control room area. A single train will provide the required temperature control to maintain the control room approximately 74qF. The CRACWS operation in maintaining the control room temperature is discussed in the UFSAR, Section 9.4 (Ref. 1).

APPLICABLE The design basis of the CRACWS is to maintain the control room SAFETY ANALYSES temperature for 30 days of continuous occupancy.

The CRACWS components are arranged in redundant, safety related trains. During emergency operation, the CRACWS maintains the temperature between 72qF and 85qF. A single active failure of a component of the CRACWS, with a loss of offsite power, does not impair the ability of the system to perform its design function. Redundant detectors and controls are provided for control room temperature control.

The CRACWS is designed in accordance with Seismic Category I requirements. The CRACWS is capable of removing sensible and latent heat loads from the control room, which include consideration of equipment heat loads and personnel occupancy requirements, to ensure equipment OPERABILITY.

The CRACWS satisfies Criterion 3 of 10 CFR 50.36 (Ref. 2).

CRACWS B 3.7.11 BASES Catawba Units 1 and 2 B 3.7.11-2 Revision No. 6 LCO Two independent and redundant trains of the CRACWS are required to be OPERABLE to ensure that at least one is available, assuming a single failure disabling the other train. Total system failure could result in the equipment operating temperature exceeding limits in the event of an accident.

The CRACWS is considered to be OPERABLE when the individual components necessary to maintain the control room temperature are OPERABLE in both trains. These components include a chiller package, chilled water pump, and air handling unit. In addition, the CRACWS must be OPERABLE to the extent that air circulation can be maintained.

The CRACWS is shared between the two units. The system must be OPERABLE for each unit when that unit is in the MODE of Applicability.

If a CRACWS component becomes inoperable, then the Required Actions of this LCO must be entered independently for each unit that is in the MODE of applicability of the LCO.

APPLICABILITY In MODES 1, 2, 3, 4, 5, and 6, and during movement of recently irradiated fuel assemblies, the CRACWS must be OPERABLE to ensure that the control room temperature will not exceed equipment operational requirements following a design basis accident. The CRACWS is only required to be OPERABLE during fuel handling involving handling recently irradiated fuel (i.e., fuel that has occupied part of a critical reactor core within the previous 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />) due to radioactive decay.

ACTIONS A.1 With one CRACWS train inoperable, action must be taken to restore OPERABLE status within 30 days. In this Condition, the remaining OPERABLE CRACWS train is adequate to maintain the control room temperature within limits. However, the overall reliability is reduced because a single failure in the OPERABLE CRACWS train could result in loss of CRACWS function. The 30 day Completion Time is based on the low probability of an event, the consideration that the remaining train can provide the required protection, and that alternate safety or nonsafety related cooling means are available.

CRACWS B 3.7.11 BASES Catawba Units 1 and 2 B 3.7.11-3 Revision No. 6 ACTIONS (continued)

B.1 and B.2 In MODE 1, 2, 3, or 4, if the inoperable CRACWS train cannot be restored to OPERABLE status within the required Completion Time, the unit must be placed in a MODE that minimizes the risk. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and in MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

C.1 and C.2 In MODE 5 or 6, or during movement of recently irradiated fuel, if the inoperable CRACWS train cannot be restored to OPERABLE status within the required Completion Time, the OPERABLE CRACWS train must be placed in operation immediately. This action ensures that the remaining train is OPERABLE, and that active failures will be readily detected.

An alternative to Required Action C.1 is to immediately suspend activities that present a potential for releasing radioactivity. This places the unit in a condition that minimizes accident risk. This does not preclude the movement of fuel to a safe position.

D.1, D.2, and D.3 If both CRACWS trains are inoperable, the CRACWS may not be capable of performing its intended function. Therefore, the control room area temperature is required to be monitored to ensure that temperature is being maintained low enough that equipment in the control room is not adversely affected and habitability is maintained. If air circulation is limited, temperature monitoring in multiple locations in the affected areas may be required in order to ensure that the temperature limit is not exceeded. Mitigating actions, such as use of the Computer Room Chilled Water (YJ) system tie-in to the Control Room Air Handling Units, opening cabinet doors, use of fans, use of ice vests, use of alternate (i.e., non-safety-related) ventilation systems, or opening control room doors or ventilation paths, may be used to maintain control room area temperature. With the control room temperature being maintained within the temperature limit, 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is allowed to restore a CRACWS train to OPERABLE status. This Completion Time is reasonable considering that the control room temperature is being maintained within limits and the low

CRACWS B 3.7.11 BASES Catawba Units 1 and 2 B 3.7.11-4 Revision No. 6 ACTIONS (continued) probability of an event occurring requiring control room isolation.

E.1 and E.2 In MODE 1, 2, 3, or 4, if the inoperable CRACWS trains cannot be restored to OPERABLE status within the required Completion Time, the unit must be placed in a MODE that minimizes the risk. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, and in MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.

F.1 In MODE 5 or 6, or during movement of recently irradiated fuel assemblies, with two CRACWS trains inoperable, action must be taken immediately to suspend activities that could result in a release of radioactivity. This places the unit in a condition that minimizes risk. This does not preclude the movement of fuel to a safe position.

SURVEILLANCE SR 3.7.11.1 REQUIREMENTS This SR verifies that the heat removal capability of the system is sufficient to maintain the temperature in the control room at or below 90qF. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

REFERENCES

1.

UFSAR, Section 9.4.

2.

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

3.

10 CFR 50.67, Accident source term.

4.

Regulatory Guide 1.183, Revision 0.

Catawba Units 1 and 2 B 3.8.4-1 Revision No. 13 DC SourcesOperating B 3.8.4 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.4 DC SourcesOperating BASES BACKGROUND The station DC electrical power system provides the AC emergency power system with control power. It also provides both motive and control power to selected safety related equipment and preferred AC vital bus power (via inverters). As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the DC electrical power system is designed to have sufficient independence, redundancy, and testability to perform its safety functions, assuming a single failure. The DC electrical power system also conforms to the recommendations of Regulatory Guide 1.6 (Ref. 2) and IEEE-308 (Ref. 3).

The 125 VDC electrical power system consists of four independent and redundant safety related Class 1E DC electrical power subsystems (Channels A, B, C, and D). Each channel consists of one 125 VDC battery (each battery is capable of supplying 2 channels of DC loads for a train), the associated battery charger(s) for each battery, and all the associated control equipment and interconnecting cabling.

There is one spare battery charger which provides backup service in the event that the preferred battery charger is out of service. If the spare battery charger is substituted for one of the preferred battery chargers, then the requirements of independence and redundancy between trains are maintained.

During normal operation, the 125 VDC load is powered from the battery chargers with the batteries floating on the system. In case of loss of normal power to the battery charger, the DC load is automatically powered from the station batteries.

The Channels A and D of DC electrical power subsystems or the Diesel Generator (DG) DC electrical power subsystems provide through auctioneering diode assemblies, the buses EDE for the A train and EDF for the B train to supply the control power for its associated Class 1E AC power load group, 4.16 kV switchgear, and 600 V load centers. The DC electrical power subsystems also provide DC electrical power to the inverters, which in turn power the AC vital buses.

DC SourcesOperating B 3.8.4 BASES Catawba Units 1 and 2 B 3.8.4-2 Revision No. 13 BACKGROUND (continued)

The DC power distribution system is described in more detail in Bases for LCO 3.8.9, "Distribution SystemOperating," and LCO 3.8.10, "Distribution SystemsShutdown."

Each 125 V vital DC battery (EBA, EBB, EBC, EBD) has adequate storage capacity to carry the required duty cycle of its own load group and the loads of another load group for a period of two hours. Each 125 V vital DC battery is also capable of supplying the anticipated momentary loads during this two hour period. The 125 V DC DG batteries have adequate storage capacity to carry the required duty cycle for 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

Each 125 V vital DC battery is separately housed in a ventilated room apart from its charger and distribution centers. Each subsystem or channel is located in an area separated physically and electrically from the other subsystem to ensure that a single failure in one subsystem does not cause a failure in a redundant subsystem. There is no sharing between redundant Class 1E subsystems, such as batteries, battery chargers, or distribution panels, except for the spare battery charger which may be aligned to either train.

The batteries for each channel DC electrical power subsystems are sized to produce required capacity at 80% of nameplate rating, corresponding to warranted capacity at end of life cycles and the 100% design demand.

Battery size is based on 125% of required capacity. The voltage limit is 2.13 V per cell, which corresponds to a total minimum voltage output of 125 V per battery discussed in the UFSAR, Chapter 8 (Ref. 4). The criteria for sizing large lead storage batteries are defined in IEEE-485 (Ref. 5).

Each channel of DC electrical power subsystem has ample power output capacity for the steady state operation of connected loads required during normal operation, while at the same time maintaining its battery bank fully charged. Each battery charger also has sufficient capacity to restore the battery from the design minimum charge to its fully charged state within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> while supplying normal steady state loads discussed in the UFSAR, Chapter 8 (Ref. 4).

APPLICABLE The initial conditions of Design Basis Accident (DBA) and transient SAFETY ANALYSES analyses in the UFSAR, Chapter 6 (Ref. 6), and in the UFSAR, Chapter 15 (Ref. 7), assume that Engineered Safety Feature (ESF) systems are OPERABLE. The DC electrical power system provides

DC SourcesOperating B 3.8.4 BASES Catawba Units 1 and 2 B 3.8.4-3 Revision No. 13 APPLICABLE SAFETY ANALYSES (continued) normal and emergency DC electrical power for the DGs, emergency auxiliaries, and control and switching during all MODES of operation.

The OPERABILITY of the DC sources is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit. This includes maintaining the DC sources OPERABLE during accident conditions in the event of:

a.

An assumed loss of all offsite AC power or all onsite AC power; and

b.

A worst case single failure.

The DC sources satisfy Criterion 3 of 10 CFR 50.36 (Ref. 8).

LCO The DC electrical power subsystems, each subsystem consisting of one battery, battery charger and the corresponding control equipment and interconnecting cabling supplying power to the associated bus within the train are required to be OPERABLE to ensure the availability of the required power to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (AOO) or a postulated DBA. Loss of any train DC electrical power subsystem does not prevent the minimum safety function from being performed (Ref. 4).

An OPERABLE DC electrical power subsystem requires a battery and respective charger to be operating and connected to the associated DC bus.

APPLICABILITY The DC electrical power sources are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure safe unit operation and to ensure that:

a.

Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and

b.

Adequate core cooling is provided, and containment integrity and other vital functions are maintained in the event of a postulated DBA.

The DC electrical power requirements for MODES 5 and 6 are addressed in the Bases for LCO 3.8.5, "DC SourcesShutdown."

DC SourcesOperating B 3.8.4 BASES Catawba Units 1 and 2 B 3.8.4-4 Revision No. 13 ACTIONS A.1 and A.2 Condition A represents the loss of one channel for a DC source. The inoperable channel must be energized from an OPERABLE source within 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The inoperable channel may be powered from that train's other DC channel battery by closing the bus tie breakers. Each channel battery is sized and tested to supply two channels of DC for a period of two hours, in the event of a postulated DBA. Being powered from an OPERABLE source, the inoperable channel must be returned to OPERABLE status within 10 days or the plant must be prepared for a safe and orderly shutdown. The spare battery charger (ECS), which must be powered from the same train which it is supplying, may be substituted for the channels battery charger to maintain a fully OPERABLE channel.

In this case, Condition A is not applicable.

B.1 and B.2 If the inoperable channel of DC electrical power subsystem cannot be restored to OPERABLE status within the required 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 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and to MODE 5 within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging plant systems.

C.1 Condition C represents one train's loss of the ability to adequately supply the DG with the required DC power and the DG is inoperable. The DG is no longer capable of supplying the required 4.16 kV AC power and applicable Condition(s) and Required Action(s) for the AC sources must be entered immediately.

D.1 Being powered from auctioneering diode circuits from either the A channel of DC or the A Train of DG DC, distribution center EDE supplies breaker control power to the 4.16 kV AC and the 600 VAC switchgear, auxiliary feedwater pump controls, and other important DC loads. The EDF center is powered from the B Train of DG DC or the D channel of DC and provides DC power to Train B loads, similar to EDE center. With

DC SourcesOperating B 3.8.4 BASES Catawba Units 1 and 2 B 3.8.4-5 Revision No. 13 ACTIONS (continued) the loss of the channel DC power and the associated DG DC power, the load center power for the train is inoperable and the Condition(s) and Required Action(s) for the Distribution Systems must be entered immediately.

SURVEILLANCE SR 3.8.4.1 REQUIREMENTS Verifying battery terminal voltage while on float charge for the batteries helps to ensure the effectiveness of the charging system and the ability of the batteries to perform their intended function. Float charge is the condition in which the charger is supplying the continuous charge required to overcome the internal losses of a battery (or battery cell) and maintain the battery (or a battery cell) in a fully charged state. The voltage requirements are based on the nominal design voltage of the battery and are consistent with the initial voltages assumed in the battery sizing calculations. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.4.2 Not used.

SR 3.8.4.3 For the DC channel and DG batteries, visual inspection to detect corrosion of the battery terminals and connections, or measurement of the resistance of each intercell, interrack, intertier, and terminal connection, provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance. The presence of visible corrosion does not necessarily represent a failure of this SR, provided an evaluation determines that the visible corrosion does not affect the OPERABILITY of the battery.

For any connection that shows corrosion, the resistance shall be measured at that connection to verify acceptable connection resistance (Ref. 11). The limits for battery connection resistance are specified in Table 3.8.4-1.

DC SourcesOperating B 3.8.4 BASES Catawba Units 1 and 2 B 3.8.4-6 Revision No. 13 SURVEILLANCE REQUIREMENTS (continued)

The plant safety analyses do not assume a specific battery connection resistance value, but typically assume that the batteries will supply adequate power for a specified period of time. The resistance of each battery connection varies independently from all the others. Some of these individual connection resistance values may be higher or lower than the others, and the battery will still be able to perform its design function.

Overall connection resistance, which is the sum total of all connection resistances, has a direct impact on battery operability. The values listed in Table 3.8.4-1 are based on the battery manufacturers recommended connection voltage drop. As long as battery connection resistance values are at or below the values listed in Table 3.8.4-1, battery OPERABILITY will not be in question based on intercell, interrack, intertier, and terminal connection resistance.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.4.4 For the DC channel and DG batteries, visual inspection of the battery cells, cell plates, and battery racks provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance. The presence of physical damage or deterioration does not necessarily represent a failure of this SR, provided an evaluation determines that the physical damage or deterioration does not affect the OPERABILITY of the battery (its ability to perform its design function).

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.4.5 and SR 3.8.4.6 Visual inspection and resistance measurements of intercell, interrack, intertier, terminal, and the average intercell connection resistance provide an indication of physical damage or abnormal deterioration that could indicate degraded battery condition. Average intercell connection resistance is defined as the battery manufacturers maximum allowed intercell connection voltage drop divided by the maximum battery duty cycle load current, and includes the battery post to intercell connection resistance. The limits for battery connection resistance are specified in Table 3.8.4-1.

DC SourcesOperating B 3.8.4 BASES Catawba Units 1 and 2 B 3.8.4-7 Revision No. 13 SURVEILLANCE REQUIREMENTS (continued)

The plant safety analyses do not assume a specific battery connection resistance value, but typically assume that the batteries will supply adequate power for a specified period of time. The resistance of each battery connection varies independently from all the others. Some of these individual connection resistance values may be higher or lower than the others, and the battery will still be able to perform its design function.

Overall connection resistance, which is the sum total of all connection resistances, has a direct impact on battery operability. The values listed in Table 3.8.4-1 are based on the battery manufacturers recommended connection voltage drop. As long as battery connection resistance values are at or below the values listed in Table 3.8.4-1, battery OPERABILITY will not be in question based on intercell, interrack, intertier, and terminal connection resistance. The anticorrosion material, as recommended by the manufacturer for the batteries, is used to help ensure good electrical connections and to reduce terminal deterioration. The visual inspection for corrosion is not intended to require removal of and inspection under each terminal connection. The removal of visible corrosion is a preventive maintenance SR. The presence of visible corrosion does not necessarily represent a failure of this SR provided visible corrosion is removed during performance of SR 3.8.4.5.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

SR 3.8.4.7 This SR requires that each battery charger for the DC channel be capable of supplying at least 200 amps and at least 75 amps for the DG chargers.

All chargers shall be tested at a voltage of at least 125 V for t 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />.

These requirements are based on the design capacity of the chargers (Ref. 4). According to Regulatory Guide 1.32 (Ref. 10), the battery charger supply is required to be based on the largest combined demands of the various steady state loads and the charging capacity to restore the battery from the design minimum charge state to the fully charged state, irrespective of the status of the unit during these demand occurrences.

The minimum required amperes and duration ensures that these requirements can be satisfied.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

DC SourcesOperating B 3.8.4 BASES Catawba Units 1 and 2 B 3.8.4-8 Revision No. 13 SURVEILLANCE REQUIREMENTS (continued)

SR 3.8.4.8 A battery service test is a special test of battery capability, as found, to satisfy the design requirements (battery duty cycle) of the DC electrical power system. The vital batterys actual duty cycle is identified in calculation CNC-1381.05-00-0265, Catawba Unit 1 and 2 125 VDC Vital I&C Power System Battery and Charger Sizing, Voltage Drop and Short Circuit Analyses. The test duty cycle is the actual duty cycle adjusted for the temperature correction factor for 60ºF operation, and a design margin of typically 10 to 15% for load addition. The minimum DC battery terminal voltage is determined through Calculation CNC-1381.05-00-0265, Catawba Unit 1 and 2 125 VDC Vital I&C Power System Battery and Charger Sizing, Voltage Drop and Short Circuit Analysis. The DG batterys actual duty cycle is identified in calculation CNC-1381.05 0050, 125 VDC Diesel Generator Battery and Battery Charger Sizing Calculation. The test duty cycle is the actual duty cycle adjusted for the temperature correction factor for 60ºF operation, and a design margin of typically 10 to 15% for load addition. The minimum DG battery terminal voltage is determined through Calculations CNC-1381.05-00-0235, Unit 1 125 VDC Essential Diesel Power System (EPQ) Voltage Drop Analysis and CNC-1381.05-00-0236, Unit 2 125 VDC Essential Diesel Power System (EPQ) Voltage Drop Analysis. (Note: The duty cycle in the UFSAR is used for battery sizing and includes the temperature factor of 11%, a design margin of 15%, and an aging factor of 25%.)

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.

This SR is modified by two Notes. Note 1 allows the performance of a modified performance discharge test in lieu of a service test.

The modified performance discharge test is a performance discharge test that is augmented to include the high-rate, short duration discharge loads (during the first minute and 11-to-12 minute discharge periods) of the service test. The duty cycle of the modified performance test must fully envelope the duty cycle of the service test if the modified performance discharge test is to be used in lieu of the service test. Since the ampere-hours removed by the high-rate, short duration discharge periods of the service test represents a very small portion of the battery capacity, the test rate can be changed to that for the modified performance discharge test without compromising the results of the performance discharge test.

The battery terminal voltage for the modified performance discharge test should remain above the minimum battery terminal voltage specified in the battery service test for the duration of time equal to that of the service test.

DC SourcesOperating B 3.8.4 BASES Catawba Units 1 and 2 B 3.8.4-9 Revision No. 13 SURVEILLANCE REQUIREMENTS (continued)

A modified discharge test is a test of the battery capacity and its ability to provide a high rate, short duration load (usually the highest rates of the duty cycle). This will often confirm the battery's ability to meet the critical periods of the load duty cycle, in addition to determining its percentage of rated capacity. Initial conditions for the modified performance discharge test should be identical to those specified for a service test. The reason for Note 2 is that performing the Surveillance would perturb the electrical distribution system and challenge safety systems. This restriction from normally performing the Surveillance in MODE 1, 2, 3, or 4 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, at a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE 1, 2, 3, or 4. Risk insights or deterministic methods may be used for this assessment. Credit may be taken for unplanned events that satisfy this SR.

SR 3.8.4.9 A battery performance discharge test is a test of constant current capacity of a battery, normally done in the as found condition, after having been in service, to detect any change in the capacity determined by the acceptance test. The test is intended to determine overall battery degradation due to age and usage.

A battery modified performance discharge test is described in the Bases for SR 3.8.4.8. Either the battery performance discharge test or the modified performance discharge test is acceptable for satisfying SR 3.8.4.9; however, only the modified performance discharge test may be used to satisfy SR 3.8.4.9 while satisfying the requirements of SR 3.8.4.8 at the same time.

The acceptance criteria for this Surveillance are consistent with IEEE-450 (Ref. 9). This reference recommends that the battery be replaced if its capacity is below 80% of the manufacturer's rating. A capacity of 80%

DC SourcesOperating B 3.8.4 BASES Catawba Units 1 and 2 B 3.8.4-10 Revision No. 13 SURVEILLANCE REQUIREMENTS (continued) shows that the battery rate of deterioration is increasing, even if there is ample capacity to meet the load requirements.

The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. If the battery shows degradation, or if the battery has reached 85% of its expected life and capacity is < 100% of the manufacturer's rating, the Surveillance Frequency is reduced to 18 months. However (for DC vital batteries only), if the battery shows no degradation but has reached 85% of its expected life, the Surveillance Frequency is only reduced to 24 months for batteries that retain capacity t 100% of the manufacturer's rating. Degradation is indicated, according to IEEE-450 (Ref. 9), when the battery capacity drops by more than 10%

relative to its average capacity on the previous performance tests or when it is t 10% below the manufacturer's rating. This SR is modified by a Note which is applicable to the DG batteries only. The reason for the Note is that performing the Surveillance would perturb the associated electrical distribution system and challenge safety systems. This restriction from normally performing the Surveillance in MODE 1, 2, 3, or 4 is further amplified to allow portions of the Surveillance to be performed for the purpose of reestablishing OPERABILITY (e.g. post work testing following corrective maintenance, corrective modification, deficient or incomplete surveillance testing, and other unanticipated OPERABILITY concerns) provided an assessment determines plant safety is maintained or enhanced. This assessment shall, at a minimum, consider the potential outcomes and transients associated with a failed partial Surveillance, a successful partial Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the partial Surveillance; as well as the operator procedures available to cope with these outcomes. These shall be measured against the avoided risk of a plant shutdown and startup to determine that plant safety is maintained or enhanced when portions of the Surveillance are performed in MODE 1, 2, 3, or 4. Risk insights or deterministic methods may be used for this assessment. Credit may be taken for unplanned events that satisfy this SR.

DC SourcesOperating B 3.8.4 BASES Catawba Units 1 and 2 B 3.8.4-11 Revision No. 13 REFERENCES

1.

10 CFR 50, Appendix A, GDC 17.

2.

Regulatory Guide 1.6, March 10, 1971.

3.

IEEE-308-1971 and 1974.

4.

UFSAR, Chapter 8.

5.

IEEE-485-1983, June 1983.

6.

UFSAR, Chapter 6.

7.

UFSAR, Chapter 15.

8.

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

9.

IEEE-450-1975 and/or 1980.

10.

Regulatory Guide 1.32, February 1977.

11.

IEEE-450-1995.

12.

UFSAR Table 18-1.

13.

UFSAR Section 18.3.1.

U.S. Nuclear Regulatory Commission RA-24-0191 October 22, 2024 Catawba Nuclear Station Selected Licensee Commitments (SLC) Manual Changes

Removal and insertion instructions for Catawba Nuclear Station Selected Licensee Commitments (SLC) Manual with the attached revised page(s) for the period of April 24, 2023 thru September 24, 2024. The revised page(s) are identified by Section number and contains marginal lines indicating the areas of change.

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LIST OF EFFECTIVE SECTIONS Catawba Units 1 and 2 Page 5 Revision 119 SECTION REVISION NUMBER REVISION DATE 16.13-3 Deleted 16.13-4 4

10/04/21

Meteorological Instrumentation 16.7-3 Catawba Units 1 and 2 16.7-3-1 Revision 6 16.7 INSTRUMENTATION 16.7-3 Meteorological Instrumentation COMMITMENT

a.

The meteorological monitoring instrumentation channels shown in Table 16.7-3-1 shall be FUNCTIONAL.

AND

b.

The meteorological monitoring instrumentation channels shown in Table 16.7-3-2 shall be maintained to ensure 90%

data recovery on an annual basis.

APPLICABILITY:

At all times.

REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more required meteorological monitoring channel(s) non-functional.

A.1 Restore non-functional channel(s) to FUNCTIONAL status.

OR A.2 Prepare and submit a Special Report to the Commission outlining the cause of the malfunction and the plans for restoring the channel(s) to FUNCTIONAL status.

7 days 17 days B.

One or more required meteorological monitoring channel(s) having < 90% annual data recovery.

B.1 Prepare and submit a Special Report to the Commission outlining the cause of the deficiency and the plans for restoring the annual data recovery goals.

Within 10 days of determining the missed requirement

Meteorological Instrumentation 16.7-3 Catawba Units 1 and 2 16.7-3-2 Revision 6 TESTING REQUIREMENTS

---

NOTE--------------------------------------------------------

Refer to Table 16.7-3-1 to determine which TRs apply for each meteorological instrument.

TEST FREQUENCY TR 16.7-3-1 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> TR 16.7-3-2 Perform instrument calibration.

6 months TR 16.7-3-3 Perform recorder time accuracy and channel zero and full scale checks.

92 days

Meteorological Instrumentation 16.7-3 Catawba Units 1 and 2 16.7-3-3 Revision 6 Table 16.7-3-1 Meteorological Monitoring Instrumentation INSTRUMENT AND LOCATION REQUIRED CHANNELS TESTING REQUIREMENTS

1.

Wind Speed 1.a Meteorological Tower Nominal Elev. 663.5 1

TR 16.7-3-1 TR 16.7-3-2 TR 16.7-3-3 1.b Meteorological Tower Nominal Elev. 830.5 1

TR 16.7-3-1 TR 16.7-3-2 TR 16.7-3-3

2.

Wind Direction 2.a Meteorological Tower Nominal Elev. 663.5 1

TR 16.7-3-1 TR 16.7-3-2 TR 16.7-3-3 2.b Meteorological Tower Nominal Elev. 830.5 1

TR 16.7-3-1 TR 16.7-3-2 TR 16.7-3-3

3.

Air Temperature 3.a Ambient Meteorological Tower Nominal Elev. 660.25 1

TR 16.7-3-1 TR 16.7-3-2 TR 16.7-3-3 3.b Delta Temperature Meteorological Tower Nominal Elev. 827.25-660.25 1

TR 16.7-3-1 TR 16.7-3-2 TR 16.7-3-3 3.c Dew Point Meteorological Tower Nominal Elev. 660.25 1

TR 16.7-3-1 TR 16.7-3-2 TR 16.7-3-3

4.

Precipitation (1) 4.a Precipitation Sensor Pad (Near Meteorological Tower) Nominal Elev. 630.0 1

TR 16.7-3-1 TR 16.7-3-2 TR 16.7-3-3 (1)

Not required by Regulatory Guide 1.23, Revision 0.

Meteorological Instrumentation 16.7-3 Catawba Units 1 and 2 16.7-3-4 Revision 6 Table 16.7-3-2 Meteorological Monitoring Instrumentation Data Recovery Requirements INSTRUMENT AND LOCATION TYPE

1.

60M Joint Data Recovery Joint 1.a Wind Speed Nominal Elev. 830.5 1.b Wind Direction Nominal Elev.

830.5 1.c Delta Temperature Nominal Elev.

827.25-660.25

2.

10M Joint Data Recovery Joint 2.a Wind Speed Nominal Elev. 663.5 2.b Wind Direction Nominal Elev.

663.5 2.c Delta Temperature Nominal Elev.

827.25-660.25 3.a Ambient Air Temperature Nominal Elev. 660.25 Individual 3.b Dew Point Nominal Elev. 660.25 Individual

4.

Precipitation Nominal Elev. 630.0 Individual

Meteorological Instrumentation 16.7-3 Catawba Units 1 and 2 16.7-3-5 Revision 6 BASES The FUNCTIONALITY of the meteorological instrumentation ensures that sufficient meteorological data is available for estimating potential radiation doses to the public as a result of routine or accidental release of radioactive materials to the atmosphere. This capability is required to evaluate the need for initiating protective measures to protect the health and safety of the public and is consistent with the recommendations of Regulatory Guide 1.23, Onsite Meteorological Programs, February 1972, for wind speed, wind direction, and air temperature at two elevations. Since Catawba uses cooling towers, instrumentation has been provided for measuring the dew point (humidity). Precipitation is not required by Regulatory Guide 1.23, Revision 0. However, it is monitored since it is used by the model for offsite dose assessment calculations.

With respect to the control room chart recorder, the regulatory guide states:

Either analog (strip chart) or digital recording of data may be used as a basis for analysis. In lieu of providing redundant digital recorders, digital outputs may be supplemented by strip chart recorders to minimize possible loss of data due to instrument malfunction. Recorders (analog or digital) for wind direction and speed and temperature difference (two temperatures or one temperature difference measurement on a tower or mast) should be located in the reactor control room for use during plant operation.

Thus, the chart recorder in the control room is required in order to comply with the regulatory guide.

An instrument calibration will consist of the following test:

1) A bench based test, certification, and/or calibration of the tower mounted sensors for:

x wind speed x

wind direction x

ambient and delta temperature RTDs

2) An instrument loop calibration from the input of the signal processors to the end devices. The identification of an out-of-tolerance condition or failure of a component within the instrument loop renders the channel non-functional until the component is calibrated or repaired/replaced.

3) For wind direction a line phase differential compensation will be performed, which includes the tower signal cable.

4) For precipitation, a measured volume of water will be poured into the sensor and the signal conditioner modules output verified correct.

5) A CHANNEL CHECK, subsequent to any work performed. This will verify continuity of the signal cable between the sensor and signal processors.

BASES (continued)

Meteorological Instrumentation 16.7-3 Catawba Units 1 and 2 16.7-3-6 Revision 6

6) The wind speed sensors and cup-sets or wind direction sensors and vanes do not require wind tunnel testing as an assembly.

7) Replacement of cup-sets or vanes does not require an instrument calibration of the affected channel.

The greater than or equal to 90% annual data recovery requirement is to ensure that the meteorological instrumentation is maintained to minimize extended periods of instrument outage. The reporting cycle is a calendar year (January 1 through December 31). A 60-day period from the end of the calendar year is allowed for data reduction, validation, and data quality assurance, before the data recovery report is generated.

The 90% data recovery is a statistical analysis of the respective data for the required parameters. This analysis includes out-of-service time resulting from components being in Condition A of this SLC and routine calibration/servicing time.

The recorder time accuracy and channel zero and full scale checks, as required by Reference 2, facilitate the 90% data recovery by ensuring meteorological instruments are inspected and serviced in order to expeditiously identify problems and minimize extended periods of instrument outage.

REFERENCES

1.

Regulatory Guide 1.23, Revision 0.

2.

Catawba Updated Final Safety Analysis Report, Section 2.3.3.3.

Catawba Units 1 and 2 16.9-5-1 Revision 12 Fire Rated Assemblies 16.9-5 16.9 AUXILIARY SYSTEMS 16.9-5 Fire Rated Assemblies COMMITMENT All required Fire Rated Assemblies (walls, floors/ceilings, cable enclosures and other fire barriers) and all sealing devices in fire rated assembly penetrations (fire doors, fire dampers, and penetration seals) as shown on the CN-1105 drawing series shall be FUNCTIONAL.

APPLICABILITY:

At all times.

NOTE Non-functional or breached fire barrier features (walls, floors, ceilings, doors, dampers, and penetration seals) in the diesel generator rooms and the auxiliary feedwater pump rooms may affect CO2 System FUNCTIONALITY. See SLC 16.9-3, CO2 Systems.

REMEDIAL ACTIONS IF the required Fire Rated Assembly sealing device is a Fire Door, see Table 16.9-5-1 IF the required Fire Rated Assembly sealing device is a Fire Damper see Table 16.9-5-2 IF required Fire Rated Assembly is a Fire Barrier or Penetration Seal:

1. Identify the location of the impaired fire protection feature by elevation, column, and building

2. Verify the wall, floor/ceiling is a committed boundary on the CN-1105 drawing series (if not a committed boundary, SLC 16.9-5 does not apply)

3. Refer to CN-1209-10 series drawings to identify the Fire Area on both sides of the impaired feature

4. IF either of the Fire Areas is identified as High Safety Significant (HSS) (see Table 16.9-5-3) then implement the REQUIRED ACTION CONDITION A

5. IF the Fire Areas are not HSS, then identify the associated shutdown trains/methods of the Fire Areas on each side of the barrier using Table 16.9-5-4 and implement the REQUIRED ACTION as identified in the following Chart:

Shutdown Train (Side 1 & Side

2)

A B

SSS A or B A and B A

CONDITION C

CONDITION B

CONDITION B

CONDITION C

CONDITION B

B CONDITION B

CONDITION C

CONDITION B

CONDITION C

CONDITION B

SSS CONDITION B

CONDITION B

CONDITION C

CONDITION B

CONDITION B

A or B CONDITION C

CONDITION C

CONDITION B

CONDITION C

CONDITION B

A and B CONDITION B

CONDITION B

CONDITION B

CONDITION B

CONDITION C

Catawba Units 1 and 2 16.9-5-2 Revision 12 Fire Rated Assemblies 16.9-5 REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more HSS*

required Fire Rated Assemblies is non-functional.

A.1 Establish a continuous fire watch on at least one side of the assembly.

OR A.2.1 Verify at least one side of the assembly has FUNCTIONAL**** fire detection instrumentation.

AND A.2.2 Establish an hourly fire watch patrol on at least one side of the assembly.

OR A.3 Complete an evaluation as permitted by NRC RIS 2005-07 to institute required action(s).

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 1 hour 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Prior to terminating Required Action A.1 or A.2 (continued)

Catawba Units 1 and 2 16.9-5-3 Revision 12 Fire Rated Assemblies 16.9-5 REMEDIAL ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME B.

One or more LSS**

required Fire Rated Assemblies is non-functional.

B.1 Establish an hourly fire watch on at least one side of the assembly.

OR B.2.1 Verify at least one side of the assembly has FUNCTIONAL**** fire detection instrumentation.

AND B.2.2 Establish a once per shift fire watch patrol on at least one side of the assembly.

OR B.3 Complete an evaluation as permitted by NRC RIS 2005-07 to institute required action(s).

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 1 hour 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> Prior to terminating Required Action B.1 or B.2 (continued)

Catawba Units 1 and 2 16.9-5-4 Revision 12 Fire Rated Assemblies 16.9-5 REMEDIAL ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C.

One or more DID***

required Fire Rated Assemblies is non-functional.

C.1 Establish a once per shift fire watch on at least one side of the assembly.

OR C.2 Verify at least one side of the assembly has FUNCTIONAL**** fire detection instrumentation.

OR C.3 Complete an evaluation as permitted by NRC RIS 2005-07 to institute required action(s).

1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> 1 hour Prior to terminating Required Action C.1

• High Safety Significant (HSS) Fire Areas containing required Fire Rated Assemblies are defined in Table 16.9-5-3.

• • Low Safety Significant (LSS) Fire Areas containing required Fire Rated Assemblies are defined as those areas with a boundary between redundant shutdown trains.

• • • Defense-in-Depth (DID) Fire Areas containing required Fire Rated Assemblies are defined as analysis compartment boundaries or PRA compartment boundaries that do not meet the HSS or LSS definitions.

• • • • The Fire Rated Assembly must be within the radius of detector capability that is being considered as FUNCTIONAL using the table below.

Detector Radius of Detector Capability (Feet)

Intelligent 4D Multisensor - SIGA IPHS 15 Intelligent Photoelectric Smoke Detector - SIGA - PS 15 Intelligent Heat Detectors - SIGA - HRS 35 UVIR Flame Detectors X5200S N/A - Detectors are directional and overlapping

Catawba Units 1 and 2 16.9-5-5 Revision 12 Fire Rated Assemblies 16.9-5 TESTING REQUIREMENTS (continued)

TEST FREQUENCY TR 16.9-5-1 Verify each HSS and LSS interior unlocked fire door is closed.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> TR 16.9-5-2 Verify each HSS and LSS locked closed fire door is closed.

7 days TR 16.9-5-3 Perform an inspection and functional test of the release and closing mechanism and latches for each swinging fire door shown in Table 16.9-5-1.

6 months TR 16.9-5-4 Perform a visual inspection of the exposed surfaces of each required Fire Rated Assembly.

18 months TR 16.9-5-5 NOTE Any abnormal changes or degradation shall be identified and resolved via the corrective action program. Based on the investigation results, additional dampers may be selected for inspection. Samples will be grouped by unit, system, and train and shall be selected such that each damper is inspected every 15 years.

Perform a visual inspection of fire dampers in each required Fire Rated Assembly, shown in Table 16.9-5-2.

18 months, in accordance with the predefined inspection schedule

Catawba Units 1 and 2 16.9-5-6 Revision 12 Fire Rated Assemblies 16.9-5 TESTING REQUIREMENTS (continued)

TEST FREQUENCY TR 16.9-5-6 NOTE Any abnormal changes or degradation shall be identified and resolved via the corrective action program. Based on the investigation results, additional Fire Rated Assemblies may be selected for inspection. Samples shall be selected such that each Fire Rated Assembly is inspected every 15 years.

Perform a visual inspection of penetration seals in each HSS AND LSS required Fire Rated Assembly.

18 months, in accordance with the predefined inspection schedule TR 16.9-5-7 Perform an inspection and functional test of the automatic hold open, release and closing mechanism for each rolling fire door shown in Table 16.9-5-1.

18 Months

Fire Rated Assemblies 16.9-5 Table 16.9-5-1 Required Fire Doors Catawba Units 1 and 2 16.9-5-7 Revision 12 DOOR NUMBER BLDG LOCATION ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION AX500F AUX 56, FF 522+0 1/4 DID C

AX214A AUX 54-55, FF-GG 543+0 1/4 DID C

AX214B AUX 58-59, FF-GG 543+0 1/4 DID C

AX217D AUX 52-53, BB 543+0 3/34 LSS B

AX217F(1)

AUX 51, AA-BB 543+0 3/40 LSS B

AX217G AUX 52-53, BB 543+0 3/32 LSS B

AX227D AUX 54-55, MM-NN 543+0 4/22 DID C

AX227E AUX 59-60, MM-NN 543+0 4/22 DID C

AX228A AUX 56-57, EE 543+0 4/9 DID C

AX228B AUX 57-58, EE 543+0 4/10 DID C

AX248 AUX 57-58, QQ 543+0 4/ASB LSS B

AX260B AUX 61-62, BB-CC 543+0 2/36 LSS B

AX260F(1)

AUX 62, AA-BB 543+0 2/39 LSS B

AX260G AUX 61-62, BB-CC 543+0 2/31 LSS B

AX260H AUX 61-62, BB-CC 543+0 2/33 LSS B

T527#1 AUX 52-53, BB-CC 543+0 3/37 LSS B

AX202 AUX 51, NN 543+0 4/STAIR DID C

AX253A AUX 63, NN 543+0 4/STAIR DID C

AX227A AUX 59, FF-GG 543+0 4/STAIR DID C

AX260E AUX 52, CC 543+0 3/STAIR DID C

AX516M AUX 62, CC 543+0 2/STAIR DID C

AX354A AUX 55, DD-EE 554+0 22/45 LSS B

AX354B AUX 59, DD-EE 554+0 22/46 LSS B

AX418 AUX 57, BB 554+0 9/10 DID C

AX419 AUX 57, DD-EE 554+0 9/10 DID C

AX420A AUX 59, DD-EE 554+0 9/46 LSS B

AX421A AUX 55, DD-EE 554+0 10/45 LSS B

S102A AUX 53-54, AA 554+0 10/SRV LSS B

AX302 AUX 41, CC-DD 556+0 25/41 DID C

AX304 AUX 41, AA-BB 556+0 26/42 DID C

AX306 AUX 73, DD-EE 556+0 27/43 DID C

AX308 AUX 73, BB-CC 556+0 28/44 DID C

AX348B AUX 54-55, MM-NN 560+0 11/22 DID C

AX348C AUX 53-54, HH 560+0 4/11 DID C

AX348D AUX 59-60, MM-NN 560+0 11/22 DID C

AX348E AUX 60-61, HH 560+0 4/11 DID C

AX352B AUX 53, CC-DD 560+0 6/STAIR HSS A

AX352C AUX 53, CC-DD 560+0 10/STAIR DID C

AX352D AUX 46-47, BB-CC 560+0 6/RB1 HSS A

AX353 AUX 45, BB 560+0 6/8 HSS A

AX353B AUX 45, AA-BB 560+0 8/41 LSS B

AX353C AUX 45, AA-BB 560+0 8/42 DID C

(continued)

Fire Rated Assemblies 16.9-5 Table 16.9-5-1 Required Fire Doors Catawba Units 1 and 2 16.9-5-8 Revision 12 DOOR NUMBER BLDG LOCATION ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION AX393B AUX 61, CC-DD 560+0 9/STAIR DID C

AX393C AUX 61, CC-DD 560+0 5/STAIR DID C

AX393D AUX 67-68, BB-CC 560+0 5/RB2 LSS B

AX394 AUX 69, BB 560+0 5/7 DID C

AX394B AUX 69, AA-BB 560+0 7/43 LSS B

AX394C AUX 69, AA-BB 560+0 7/44 DID C

AX395 AUX 61, AA-BB 560+0 7/9 LSS B

AX396 AUX 53, AA-BB 560+0 8/10 LSS B

AX415 AUX 45-46, CC-DD 560+0 6/RB1 HSS A

AX416 AUX 68-69, CC-DD 560+0 5/RB2 LSS B

AX417 AUX 57, QQ 560+0 11/ASB LSS B

AX313D AUX 51, NN 560+0 11/STAIR DID C

AX388B AUX 63, NN 560+0 11/STAIR DID C

AX348 AUX 59, FF-GG 560+0 11/STAIR DID C

AX355A AUX 53-54, FF 568+0 4/11 DID C

AX355D AUX 60, FF 568+0 4/11 DID C

AX355E AUX 60, FF 568+0 11/STAIR DID C

AX515 AUX 54, BB 574+0 17/45 HSS A

AX516 AUX 56-57, DD 574+0 14/45 HSS A

AX516A AUX 57-58, DD 574+0 16/46 HSS A

AX516K AUX 57, AA-BB 574+0 16/17 HSS A

AX517A AUX 53-54, DD-EE 574+0 22/45 LSS B

AX517B AUX 60-61, DD-EE 574+0 22/46 LSS B

AX517C AUX 57, DD-EE 574+0 45/46 DID C

AX517D AUX 57, DD-EE 574+0 9/46 LSS B

AX517E AUX 56-57, DD-EE 574+0 10/46 LSS B

AX518 AUX 60, BB 574+0 16/46 HSS A

S303 SRV 36-37, 1N 574+0 45/SRV DID C

S303C SRV 36-37, V 574+0 45/SRV DID C

S304A AUX 60, AA 574+0 46/SRV DID C

AX500H AUX 54-55, MM-NN 577+0 18/22 DID C

AX500K AUX 53-54, HH-GG 577+0 4/18 DID C

AX500L AUX 59-60, MM-NN 577+0 18/22 DID C

AX500N AUX 60-61, HH-GG 577+0 4/18 DID C

AX513B AUX 53, CC-DD 577+0 13/STAIR HSS A

AX514 AUX 45, BB 577+0 13/15 HSS A

AX514B AUX 45-46, AA-BB 577+0 6/13 HSS A

AX517 AUX 57, EE 577+0 9/18 DID C

AX525 AUX 55-56, QQ 577+0 18/ASB LSS B

AX525B AUX 56, QQ 577+0 18/ASB LSS B

AX526D AUX 58, QQ 577+0 18/ASB LSS B

A314#3 AUX 61, CC-DD 577+0 12/STAIR HSS A

AX533C AUX 61, CC-DD 577+0 46/STAIR DID C

AX534 AUX 69, BB 577+0 12/14 HSS A

(continued)

Fire Rated Assemblies 16.9-5 Catawba Units 1 and 2 16.9-5-9 Revision 12 Table 16.9-5-1 Required Fire Doors DOOR NUMBER BLDG LOCATION ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION AX534B AUX 68-69, AA-BB 577+0 7/14 HSS A

AX535A AUX 61, AA-BB 577+0 14/46 HSS A

AX536 AUX 53, AA-BB 577+0 15/45 HSS A

AX656 AUX 53, CC-DD 577+0 45/STAIR DID C

AX500P AUX 51, NN 577+0 18/STAIR DID C

AX500S AUX 63, NN 577+0 18/STAIR DID C

AX338A AUX 60, FF-GG 577+0 18/STAIR DID C

AX602 AUX 52, UU-VV 594+0 24/ASB DID C

AX627 AUX 62, UU-VV 594+0 23/ASB DID C

AX630 AUX 58, QQ 594+0 22/ASB LSS B

AX632 AUX 57, QQ 594+0 22/ASB LSS B

AX635 AUX 60-61, QQ 594+0 22/ASB LSS B

AX635E AUX 53-54, QQ 594+0 22/ASB LSS B

AX635F AUX 53-54, QQ 594+0 22/ASB LSS B

AX655 AUX 62-63, DD 594+0 19/48 LSS B

AX656C AUX 61, CC-DD 594+0 19/22 LSS B

AX657 AUX 60-61, CC 594+0 19/22 LSS B

AX657A(2)

AUX 54, BB 594+0 21/35 HSS A

AX657B AUX 52-53, CC-DD 594+0 20/22 LSS B

AX657E(2)

AUX 53, BB 594+0 21/35 HSS A

AX657F AUX 60, DD-EE 594+0 21/22 HSS A

AX657G AUX 57-58, DD-EE 594+0 21/22 HSS A

AX657H AUX 54, DD-EE 594+0 21/22 HSS A

AX657J AUX 53, BB-CC 594+0 20/21 HSS A

AX658B AUX 51-52, DD 594+0 20/49 LSS B

S400 AUX 55-56, AA 594+0 21/SRV HSS A

S406 AUX 58-59, AA 594+0 21/SRV HSS A

AX635G AUX 51, NN 594+0 22/STAIR DID C

AX635H AUX 63, NN 594+0 22/STAIR DID C

AX654A AUX 60, FF 594+0 22/STAIR DID C

AX654B AUX 61, CC-DD 594+0 19/STAIR DID C

AX665B AUX 53, CC-DD 594+0 22/STAIR DID C

AX700B AUX 50-51, JJ-KK 605+10 24/RB1 LSS B

AX700D AUX 63-64, KK 605+10 22/23 LSS B

AX701 AUX 50-51, JJ-KK 605+10 22/RB1 LSS B

AX714B AUX 63-64, JJ-KK 605+10 23/RB2 LSS B

AX720 AUX 50-51, HH-JJ 605+10 22/RB1 LSS B

AX721 AUX 63-64, HH-JJ 605+10 22/RB2 LSS B

AX714C AUX 50-51, KK 605+10 22/24 LSS B

AX715A AUX 63-64, JJ-KK 605+10 22/RB2 LSS B

S211(2)

TB1 17, V 568+0 SRV/TB1 DID C

S212 TB1 19, V 568+0 SRV/TB1 DID C

S210 TB1 21,V 568+0 SRV/TB1 DID C

(continued)

Fire Rated Assemblies 16.9-5 Catawba Units 1 and 2 16.9-5-10 Revision 12 Table 16.9-5-1 Required Fire Doors DOOR NUMBER BLDG LOCATION ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION S206 TB1 22, V 568+0 SRV/TB1 DID C

S201 TB1 33, V 568+0 SRV/TB1 DID C

SR3(3)

TB1 30-31, V 568+0 SRV/TB1 DID C

S201A TB1 27, V 568+0 SRV/TB1 DID C

T101 TB1 31, 1K 568+0 TB1/U1 OTT DID C

S424 TB1 24-25, V 594+0 SRV/TB1 DID C

S425 TB1 23, V 594+0 SRV/TB1 DID C

S426 TB1 22, V 594+0 SRV/TB1 DID C

SR21(3)

TB1 24, V 594+0 SRV/TB1 DID C

S472 TB1 27, V 594+0 SRV/TB1 DID C

S423 TB1 29, V 594+0 SRV/TB1 DID C

S422 TB1 29, V 594+0 SRV/TB1 DID C

SR7(3)

TB1 29-30, V 594+0 SRV/TB1 DID C

S416 TB1 32, V 594+0 SRV/TB1 DID C

S444 TB1 15, V 594+0 SRV/TB1 DID C

TR4(3)

TB1 15-16, V 594+0 SRV/TB1 DID C

T200A TB1 32, 1J-1K 594+0 TB1/U1 MTOT DID C

S701 TB1 22, 1L 619+6 SRV/TB1 DID C

S704 TB1 33, 1L 619+6 SRV/TB1 DID C

S209 TB2 20, P 568+0 SRV/TB2 DID C

S208 TB2 22, P 568+0 SRV/TB2 DID C

SR2(3)

TB2 32-33, P 568+0 SRV/TB2 DID C

S462 TB2 32, P 568+0 SRV/TB2 DID C

SR4(3)

TB2 30-31, P 568+0 SRV/TB2 DID C

S1102 TB2 27, P 568+0 SRV/TB2 DID C

T151 TB2 31, 2K 568+0 TB2/U2 OTT DID C

S423E TB2 26, P-Q 594+0 SRV/TB2 DID C

S416A TB2 32, P 594+0 SRV/TB2 DID C

SR8(3)

TB2 29-30, P 594+0 SRV/TB2 DID C

S422A TB2 29, P 594+0 SRV/TB2 DID C

S423A TB2 29, P 594+0 SRV/TB2 DID C

S435 TB2 24-25, P 594+0 SRV/TB2 DID C

S436 TB2 23, P 594+0 SRV/TB2 DID C

S437 TB2 22, P 594+0 SRV/TB2 DID C

SR22(3)

TB2 24, P 594+0 SRV/TB2 DID C

S444A TB2 15, P 594+0 SRV/TB2 DID C

SR16(3)

TB2 15-16, P 594+0 SRV/TB2 DID C

S472A TB2 27, P 594+0 SRV/TB2 DID C

T250A TB2 32, 2J-2K 594+0 TB2/U2 MTOT DID C

S701A TB2 22, 2L 619+6 SRV/TB2 DID C

S704A TB2 33, 2L 619+6 SRV/TB2 DID C

AX662A NSWPS 600+0 29/30 LSS B

(1)

These doors are not equipped with closing mechanisms or latches and are therefore exempt from TESTING REQUIREMENT 16.9-5-3.

(2)

These doors are held open with a fusible link.

(3)

Rolling Door.

Fire Rated Assemblies 16.9-5 Table 16.9-5-2 Catawba Units 1 and 2 16.9-5-11 Revision 12 Required Fire Dampers DAMPER NUMBER BLDG LOCATION ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION 1VA-FD001 AUX 53/GG-FF 522+0 1/4 DID C

1VA-FD002 AUX 53/GG-HH 522+0 1/4 DID C

1VA-FD003 AUX 55-56/GG-HH 522+0 1/4 DID C

1VA-FD004 AUX 55-56/GG-HH 522+0 1/4 DID C

1VA-FD005 AUX 54-55/GG-HH 522+0 1/4 DID C

1VA-FD006 AUX 54-55/GG-HH 522+0 1/4 DID C

1VA-FD007 AUX 53/GG-FF 522+0 1/4 DID C

1VA-FD008 AUX 53/GG-FF 522+0 1/4 DID C

1VA-FD009 AUX 53-54/FF-GG 522+0 1/1 (ND PUMPS)

DID C

1VA-FD010 AUX 56-57/ GG-HH, 522+0 1/4 DID C

1VA-FD011 AUX 56-57/FF 522+0 1/4 DID C

1VA-FD012 AUX 51/NN-PP 543+0 11/STAIR DID C

1VA-FD013 AUX 54/MM 543+0 4/22 DID C

1VA-FD014 AUX 54/MM 543+0 4/22 DID C

1VA-FD015 AUX 54-55/MM-NN 543+0 4/22 DID C

1VA-FD016 AUX 54-55/MM-NN 543+0 4/22 DID C

1VA-FD017 AUX 54-55/MM-NN 543+0 4/22 DID C

1VA-FD020 AUX 55/JJ-KK 543+0 4/4 (NV PUMPS)

DID C

1VA-FD033 AUX 51-52/AA-BB 543+0 3/40 LSS B

1VA-FD034 AUX 51-52/AA-BB 543+0 3/40 LSS B

1VA-FD035 AUX 52/AA-BB 543+0 3/32 LSS B

1VA-FD036 AUX 52-53/BB 543+0 3/32 LSS B

1VA-FD038 AUX 52-53/BB 543+0 3/34 LSS B

1VA-FD039 AUX 52-53/BB 543+0 3/34 LSS B

1VA-FD040 AUX 52-53/BB 543+0 3/32 LSS B

1VA-FD041 AUX 52-53/BB 543+0 3/32 LSS B

1VA-FD042 AUX 53/CC 543+0 3/STAIR DID C

1VA-FD043 AUX 53/CC-DD 543+0 3/STAIR DID C

1VA-FD045 AUX 52-53/DD 560+0 3/6 HSS A

1VA-FD046 AUX 52-53/CC-DD 577+0 6/13 HSS A

1VA-FD047 AUX 52-53/CC-DD 577+0 6/13 HSS A

1VA-FD048 AUX 54/MM-NN 560+0 11/22 DID C

1VA-FD049 AUX 54/MM 560+0 11/22 DID C

1VA-FD050 AUX 54-55/MM 560+0 4/22 DID C

1VA-FD051 AUX 54-55/MM 560+0 4/22 DID C

1VA-FD052 AUX 55/MM-NN 560+0 11/22 DID C

1VA-FD053 AUX 55/MM 560+0 11/22 DID C

1VA-FD054 AUX 53/GG-HH 560+0 4/11 DID C

1VA-FD055 AUX 53/GG-HH 560+0 4/11 DID C

1VA-FD056 AUX 53/KK 560+0 4/11 DID C

1VA-FD057 AUX 53/GG-HH 560+0 4/11 DID C

(continued)

Fire Rated Assemblies 16.9-5 Table 16.9-5-2 REQUIRED FIRE DAMPERS Catawba Units 1 and 2 16.9-5-12 Revision 12 DAMPER NUMBER BLDG LOCATION ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION 1VA-FD058 AUX 53-54/HH 560+0 4/11 DID C

1VA-FD059 AUX 54/GG-HH 560+0 4/11 DID C

1VA-FD060 AUX 54/HH 560+0 4/11 DID C

1VA-FD061 AUX 56-57/QQ 577+0 18/ASB LSS B

1VA-FD062 AUX 55-56/QQ 577+0 18/ASB LSS B

1VA-FD063 AUX 55/MM-NN 577+0 18/22 DID C

1VA-FD064 AUX 55/MM 577+0 18/22 DID C

1VA-FD065 AUX 54/MM 577+0 18/22 DID C

1VA-FD066 AUX 54/MM 577+0 18/22 DID C

1VA-FD067 AUX 54/HH 577+0 4/18 DID C

1VA-FD068 AUX 53-54/HH 577+0 4/18 DID C

1VA-FD069 AUX 54/GG-HH 577+0 4/18 DID C

1VA-FD070 AUX 53-54/HH 577+0 4/18 DID C

1VA-FD071 AUX 53-54/HH 577+0 4/18 DID C

1VA-FD072 AUX 53/HH 577+0 4/18 DID C

1VA-FD073 AUX 53/HH 577+0 4/18 DID C

1VA-FD074 AUX 53/GG-HH 577+0 4/18 DID C

1VA-FD075 AUX 53-54/KK-LL 594+0 18/22 DID C

1VA-FD076 AUX 53-54/KK-LL 594+0 18/22 DID C

1VA-FD078 AUX 57/NN 594+0 22/STAIR DID C

1VA-FD087 AUX 55-56/QQ 594+0 22/ASB LSS B

1VA-FD088 AUX 53-54/QQ 594+0 22/ASB LSS B

1VA-FD133 AUX 53/CC-DD 594+0 22/STAIR DID C

1VA-FD139 AUX 51-52/DD 543+0 3/4 DID C

1VA-FD140 AUX 53-54/FF-GG 560+0 4/11 DID C

1VA-FD141 AUX 53-54/FF-GG 560+0 4/11 DID C

1VA-FD142 AUX 53/GG 560+0 4/11 DID C

1VA-FD143 AUX 53/JJ-HH 560+0 4/11 DID C

1VA-FD144 AUX 53/KK 560+0 4/11 DID C

1VA-FD145 AUX 51/KK 560+0 11/18 DID C

1VA-FD146 AUX 51/KK 560+0 11/18 DID C

1VA-FD147 AUX 52/MM 560+0 11/18 DID C

1VA-FD148 AUX 52/MM-NN 560+0 4/11 DID C

1VA-FD149 AUX 52-53/DD 560+0 3/6 HSS A

1VA-FD150 AUX 52-53/DD 560+0 3/6 HSS A

1VA-FD152 AUX 52-53/BB-CC 543+0 3/37 LSS B

1VA-FD153 AUX 52-53/CC 543+0 3/37 LSS B

1VA-FD154 AUX 53-54/GG-HH 594+0 4/22 DID C

1VA-FD155 AUX 53-54/GG-HH 594+0 4/22 DID C

1VA-FD159 AUX 49-50/AA-BB 543+0 CO2 HSS A

1VA-FD160 AUX 50-51/AA-BB 543+0 CO2 HSS A

1VA-FD163 AUX 56/EE 543+0 10/45 LSS B

1VA-FD164 AUX 56-57/EE 543+0 4/10 DID C

2VA-FD001 AUX 61/GG-FF 522+0 1/4 DID C

2VA-FD002 AUX 61/GG-FF 522+0 1/4 DID C

(continued)

Fire Rated Assemblies 16.9-5 Table 16.9-5-2 REQUIRED FIRE DAMPERS Catawba Units 1 and 2 16.9-5-13 Revision 12 DAMPER NUMBER BLDG LOCATION ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION 2VA-FD003 AUX 60-61/FF-GG 522+0 1/1 (ND PUMPS)

DID C

2VA-FD004 AUX 61/GG-FF 522+0 1/4 DID C

2VA-FD005 AUX 60-61/GG-HH 522+0 1/4 DID C

2VA-FD006 AUX 59-60/GG-HH 522+0 1/4 DID C

2VA-FD007 AUX 59-60/GG-HH 522+0 1/4 DID C

2VA-FD008 AUX 58-59/GG-HH 522+0 1/4 DID C

2VA-FD009 AUX 58-59/GG-HH 522+0 1/4 DID C

2VA-FD010 AUX 57-58/GG-HH 522+0 1/4 DID C

2VA-FD011 AUX 57-58/FF 522+0 1/4 DID C

2VA-FD012 AUX 59-60/MM-NN 543+0 4/22 DID C

2VA-FD013 AUX 59/MM 543+0 4/22 DID C

2VA-FD014 AUX 59/MM 543+0 4/22 DID C

2VA-FD015 AUX 59-60/MM-NN 543+0 4/22 DID C

2VA-FD020 AUX 63/NN 534+0 4/STAIR DID C

2VA-FD023 AUX 59/JJ-KK 543+0 4/4 (NV PUMPS)

DID C

2VA-FD036 AUX 61-62/DD 560+0 2/5 LSS B

2VA-FD037 AUX 61-62/CC-DD 577+0 5/12 HSS A

2VA-FD038 AUX 61-62/CC-DD 577+0 5/12 HSS A

2VA-FD040 AUX 62-63/AA-BB 543+0 2/39 LSS B

2VA-FD041 AUX 62-63/AA-BB 543+0 2/39 LSS B

2VA-FD042 AUX 62/AA-BB 543+0 2/31 LSS B

2VA-FD043 AUX 61-62/BB 543+0 2/31 LSS B

2VA-FD045 AUX 61/CC 543+0 2/STAIR DID C

2VA-FD046 AUX 61/CC-DD 543+0 2/STAIR DID C

2VA-FD048 AUX 61-62/BB 543+0 2/33 LSS B

2VA-FD049 AUX 61-62/BB 543+0 2/33 LSS B

2VA-FD050 AUX 61-62/BB 543+0 2/31 LSS B

2VA-FD051 AUX 61-62/BB 543+0 2/31 LSS B

2VA-FD053 AUX 60/MM 560+0 11/22 DID C

2VA-FD054 AUX 59/MM-NN 560+0 11/22 DID C

2VA-FD056 AUX 60/MM-NN 560+0 11/22 DID C

2VA-FD057 AUX 59-60/MM 560+0 11/22 DID C

2VA-FD058 AUX 59-60/MM 560+0 4/22 DID C

2VA-FD059 AUX 60-61/HH 560+0 4/11 DID C

2VA-FD060 AUX 61/HH-JJ 560+0 4/11 DID C

2VA-FD061 AUX 60-61/GG-HH 560+0 4/11 DID C

2VA-FD062 AUX 61/GG-HH 560+0 4/11 DID C

2VA-FD063 AUX 61/GG-HH 560+0 4/11 DID C

2VA-FD064 AUX 60-61/GG-HH 560+0 4/11 DID C

2VA-FD065 AUX 61/HH 560+0 4/11 DID C

2VA-FD069 AUX 58-59/QQ 577+0 18/ASB LSS B

2VA-FD070*

AUX 59-60/QQ 577+0 18/ASB LSS B

2VA-FD071 AUX 59-60/MM-NN 577+0 18/22 DID C

2VA-FD072 AUX 59-60/MM 577+0 18/22 DID C

(continued)

Fire Rated Assemblies 16.9-5 Table 16.9-5-2 REQUIRED FIRE DAMPERS Catawba Units 1 and 2 16.9-5-14 Revision 12 DAMPER NUMBER BLDG LOCATION ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION 2VA-FD073 AUX 60/MM 577+0 18/22 DID C

2VA-FD074 AUX 60/MM 577+0 18/22 DID C

2VA-FD075 AUX 60/HH 577+0 4/22 DID C

2VA-FD076 AUX 60/HH 577+0 4/22 DID C

2VA-FD077 AUX 60-61/HH 577+0 4/22 DID C

2VA-FD078 AUX 60-61/HH 577+0 4/22 DID C

2VA-FD079 AUX 61/HH 577+0 4/22 DID C

2VA-FD080 AUX 61/GG-HH 577+0 4/22 DID C

2VA-FD081 AUX 61/HH 577+0 4/22 DID C

2VA-FD083 AUX 63/NN 594+0 22/STAIR DID C

2VA-FD086 AUX 60/FF 594+0 22/STAIR DID C

2VA-FD087 AUX 59-60/QQ 594+0 22/ASB LSS B

2VA-FD088 AUX 60-61/QQ 594+0 22/ASB LSS B

2VA-FD093 AUX 58-59/QQ 594+0 22/ASB LSS B

2VA-FD097 AUX 61/CC-DD 594+0 22/STAIR DID C

2VA-FD108A AUX 57-59/QQ 611+0 22/ASB LSS B

2VA-FD108B AUX 57-59/QQ 611+0 22/ASB LSS B

2VA-FD114 AUX 59-60/KK-LL 594+0 18/22 DID C

2VA-FD115 AUX 59-60/KK-LL 594+0 18/22 DID C

2VA-FD137 AUX 60-61/FF-GG 560+0 4/18 DID C

2VA-FD138 AUX 60-61/FF-GG 560+0 4/18 DID C

2VA-FD139 AUX 61/GG 560+0 4/11 DID C

2VA-FD141 AUX 62-63/DD 543+0 2/4 DID C

2VA-FD142 AUX 60-61/KK 560+0 4/11 DID C

2VA-FD143 AUX 62-63/KK 560+0 4/18 DID C

2VA-FD144 AUX 63/KK 560+0 4/18 DID C

2VA-FD145 AUX 61-62/MM-NN 560+0 4/11 DID C

2VA-FD146 AUX 61-62/DD 560+0 2/5 LSS B

2VA-FD147 AUX 61-62/DD 560+0 2/5 LSS B

2VA-FD151 AUX 61-62/BB-CC 543+0 2/36 LSS B

2VA-FD152 AUX 61-62/CC 543+0 2/36 LSS B

2VA-FD153 AUX 60-61/GG-HH 594+0 4/22 DID C

2VA-FD154 AUX 60-61/GG-HH 594+0 4/22 DID C

2VA-FD157 AUX 63-64/AA-BB 543+0 CO2 HSS A

2VA-FD158 AUX 64-65/AA-BB 543+0 CO2 HSS A

2VA-FD160 AUX 57-58/QQ 543+0 4/ASB LSS B

2VA-FD161 AUX 57-58/QQ 543+0 4/ASB LSS B

2VA-FD163 AUX 58/EE 543+0 9/46 LSS B

2VA-FD164 AUX 57-58/EE 543+0 4/9 DID C

0BRS-FD001 AUX 54-55/DD-EE 554+0 10/22 DID C

0BRS-FD010 AUX 57/DD-EE 554+0 9/10 DID C

0BRS-FD019 AUX 59/DD-EE 554+0 9/22 DID C

0BRX-FD001A AUX 54-55/DD-EE 554+0 10/22 DID C

0BRX-FD001B AUX 54-55/DD-EE 554+0 10/22 DID C

(continued)

Fire Rated Assemblies 16.9-5 Table 16.9-5-2 REQUIRED FIRE DAMPERS Catawba Units 1 and 2 16.9-5-15 Revision 12 DAMPER NUMBER BLDG LOCATION ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION 0BRX-FD001C AUX 54-55/DD-EE 554+0 10/22 DID C

0BRX-FD001D AUX 54-55/DD-EE 554+0 10/22 DID C

0BRX-FD001E AUX 54-55/DD-EE 554+0 10/22 DID C

0BRX-FD001F AUX 54-55/DD-EE 554+0 10/22 DID C

0BRX-FD001G AUX 54-55/DD-EE 554+0 10/22 DID C

0BRX-FD001H AUX 54-55/DD-EE 554+0 10/22 DID C

0BRX-FD002 AUX 54-55/DD-EE 554+0 10/22 DID C

0BRX-FD009 AUX 57/AA-BB 554+0 9/10 DID C

0BRX-FD010 AUX 57/AA-BB 554+0 9/10 DID C

0BRX-FD011 AUX 57/BB-CC 554+0 9/10 DID C

0BRX-FD012 AUX 57/CC-DD 554+0 9/10 DID C

0BRX-FD013 AUX 57/CC-DD 554+0 9/10 DID C

0BRX-FD014 AUX 57/DD-EE 554+0 9/10 DID C

0BRX-FD021 AUX 60/DD-EE 554+0 9/22 DID C

0BRX-FD022A AUX 60/DD-EE 554+0 9/22 DID C

0BRX-FD022B AUX 60/DD-EE 554+0 9/22 DID C

0BRX-FD022C AUX 60/DD-EE 554+0 9/22 DID C

0BRX-FD022D AUX 60/DD-EE 554+0 9/22 DID C

0BRX-FD022E AUX 60/DD-EE 554+0 9/22 DID C

0BRX-FD022F AUX 60/DD-EE 554+0 9/22 DID C

0BRX-FD022G AUX 60/DD-EE 554+0 9/22 DID C

0BRX-FD022H AUX 60/DD-EE 554+0 9/22 DID C

0BRX-FD023 AUX 57/BB-CC 554+0 9/10 DID C

1CRA-FD005A AUX 54-55/DD-EE 594+0 21/22 HSS A

1CRA-FD005B AUX 54-55/DD-EE 594+0 21/22 HSS A

1CRA-FD008 AUX 54/AA 594+0 21/35 HSS A

1CRA-FD009 AUX 53-54/CC-DD 594+0 22/STAIR DID C

1CRA-FD010 AUX 53-54/CC 594+0 21/STAIR HSS A

1CRA-FD011 AUX 53/AA-BB 594+0 20/35 DID C

1CRA-FD012 AUX 53/BB-CC 594+0 20/21 HSS A

(continued)

Fire Rated Assemblies 16.9-5 Table 16.9-5-2 REQUIRED FIRE DAMPERS Catawba Units 1 and 2 16.9-5-16 Revision 12 DAMPER NUMBER BLDG LOCATION ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION 1CRA-FD013 AUX 52/CC-DD 594+0 20/22 LSS B

1CRA-FD016 AUX 54-55/DD-EE 574+0 22/45 LSS B

1CRA-FD017 AUX 54-55/DD 574+0 17/45 HSS A

1CRA-FD018 AUX 54-55/DD 574+0 17/45 HSS A

1CRA-FD019 AUX 54/AA-BB 574+0 17/45 HSS A

1CRA-FD020 AUX 57/CC-DD 574+0 16/17 HSS A

1CRA-FD021 AUX 53-54/DD-EE 574+0 22/45 LSS B

1CRA-FD022 AUX 55-56/DD 574+0 17/45 HSS A

1CRA-FD023 AUX 56-57/DD 574+0 17/45 HSS A

1CRA-FD024A AUX 57/DD-EE 574+0 45/46 DID C

1CRA-FD024B AUX 57/DD-EE 574+0 45/46 DID C

1CRA-FD025A AUX 54-55/DD-EE 574+0 22/45 LSS B

1CRA-FD025B AUX 54-55/DD-EE 574+0 22/45 LSS B

1CRA-FD026 AUX 54-55/EE 577+0 18/22 DID C

1CRA-FD028 AUX 53-54/EE 577+0 18/22 DID C

1CRA-FD029 AUX 54-55/EE 568+0 11/22 DID C

1CRA-FD030 AUX 54-55/EE 568+0 11/22 DID C

1CRA-FD039 AUX 57/EE-FF 577+0 18/18 (KC PUMPS)

DID C

1CR-FD001 AUX 55-56/DD-EE 594+0 21/22 HSS A

1CR-FD002 AUX 55-56/DD-EE 594+0 21/22 HSS A

1CR-FD003 AUX 54/AA-BB 594+0 21/35 HSS A

1CR-FD004 AUX 53-54/BB 594+0 21/35 HSS A

1CR-FD005 AUX 53-54/BB 594+0 21/35 HSS A

1CR-FD007 AUX 51/CC-DD 594+0 13/20 HSS A

2CRA-FD005A AUX 59-60/DD-EE 594+0 21/22 HSS A

2CRA-FD005B AUX 59-60/DD-EE 594+0 21/22 HSS A

2CRA-FD008 AUX 60/AA-BB 594+0 19/21 HSS A

2CRA-FD009 AUX 60-61/CC 594+0 19/22 LSS B

2CRA-FD012 AUX 61/CC-DD 594+0 19/22 LSS B

2CRA-FD015 AUX 59-60/DD-EE 574+0 22/46 LSS B

2CRA-FD016 AUX 59-60/DD 574+0 16/46 HSS A

2CRA-FD017 AUX 59-60/DD 574+0 16/46 HSS A

2CRA-FD018 AUX 60/AA-BB 574+0 16/46 HSS A

2CRA-FD019 AUX 58-59/DD 574+0 16/46 HSS A

2CRA-FD020 AUX 57-58/DD 574+0 16/46 HSS A

2CRA-FD021 AUX 60-61/DD-EE 574+0 22/46 LSS B

2CRA-FD022A AUX 59-60/DD-EE 574+0 22/46 LSS B

(continued)

Fire Rated Assemblies 16.9-5 Table 16.9-5-2 REQUIRED FIRE DAMPERS Catawba Units 1 and 2 16.9-5-17 Revision 12 DAMPER NUMBER BLDG LOCATION ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION 2CRA-FD022B AUX 59-60/DD-EE 574+0 22/46 LSS B

2CRA-FD023 AUX 59-60/EE 577+0 18/22 DID C

2CRA-FD025 AUX 60-61/EE 577+0 18/22 DID C

2CRA-FD026 AUX 59-60/EE 568+0 11/22 DID C

2CRA-FD027 AUX 59-60/EE 568+0 11/22 DID C

2CR-FD001 AUX 58-59/DD-EE 594+0 21/22 HSS A

2CR-FD002 AUX 58-59/DD 594+0 21/22 HSS A

2CR-FD003 AUX 63-64/CC 594+0 12/19 HSS A

1VF-FD001A AUX 51, NN-PP 605+10 22/24 LSS B

1VF-FD001B AUX 51, NN-PP 605+10 22/24 LSS B

1VF-FD002A AUX 50-51/NN-PP 631+6 24/38 DID C

1VF-FD002B AUX 50-51/NN-PP 631+6 24/38 DID C

1VF-FD004 AUX 49/PP-QQ 631+6 24/38 DID C

1VF-FD005 AUX 49-50/PP-QQ 631+6 24/38 DID C

1VF-FD006 AUX 50-51 631+6 24/38 DID C

1VF-FD007 AUX 50-51/KK-LL 605+10 22/24 LSS B

1VF-FD010 AUX 50-51/KK 605+10 22/24 LSS B

1VF-FD011 AUX 50-51/JJ-KK 631+6 22/38 LSS B

1VF-FD013 AUX 50-51/JJ-KK 616+10 22/24 LSS B

1VF-FD014 AUX 50-51/JJ-KK 616+10 22/24 LSS B

2VF-FD001A AUX 63, NN-PP 605+10 22/23 LSS B

2VF-FD001B AUX 63, NN-PP 605+10 22/23 LSS B

2VF-FD002A AUX 63-64/NN-PP 631+6 23/47 DID C

2VF-FD002B AUX 63-64/NN-PP 631+6 23/47 DID C

2VF-FD004 AUX 65/PP-QQ 631+6 23/47 DID C

2VF-FD005 AUX 64-65/PP-QQ 631+6 23/47 DID C

2VF-FD006 AUX 63-64/PP-QQ 631+6 23/47 DID C

2VF-FD007 AUX 63-64/KK-LL 605+10 22/23 LSS B

2VF-FD010 AUX 63-64/KK 605+10 22/23 LSS B

2VF-FD011 AUX 64-64/JJ-KK 631+6 22/47 LSS B

2VF-FD013 AUX 63-64/JJ-KK 616+10 22/23 LSS B

2VF-FD014 AUX 63-64/JJ-KK 616+10 22/23 LSS B

1TB-FD001 TB1 18-19/V 594+0 TB1/SRV DID C

1TB-FD002 TB1 18-19/V 594+0 TB1/SRV DID C

1TB-FD003 TB1 18-19/V 594+0 TB1/SRV DID C

1TB-FD004 TB1 18-19/V 594+0 TB1/SRV DID C

1TB-FD005 TB1 18-19/V 594+0 TB1/SRV DID C

1TB-FD006 TB1 18-19/V 594+0 TB1/SRV DID C

1TB-FD007 TB1 21-22/V 594+0 TB1/SRV DID C

1TB-FD008 TB1 21-22/V 594+0 TB1/SRV DID C

1TB-FD009 TB1 21-22/V 594+0 TB1/SRV DID C

1TB-FD010 TB1 21-22/V 594+0 TB1/SRV DID C

1TB-FD011 TB1 21-22/V 594+0 TB1/SRV DID C

1TB-FD012 TB1 21-22/V 594+0 TB1/SRV DID C

1TB-FD032 TB1 18-19/V 594+0 TB1/SRV DID C

(continued)

Fire Rated Assemblies 16.9-5 Table 16.9-5-2 REQUIRED FIRE DAMPERS Catawba Units 1 and 2 16.9-5-18 Revision 12 DAMPER NUMBER BLDG LOCATION ELEVATION FIRE AREA INTERFACE RISK CRITERIA REMEDIAL ACTION CONDITION 1TB-FD038 TB1 16-17/V 594+0 TB1/SRV DID C

1TB-FD039 TB1 16-17/V 594+0 TB1/SRV DID C

1TB-FD040 TB1 16/V 594+0 TB1/SRV DID C

1TB-FD043 TB1 30-31/1J-1K 568+0 TB1/OTT DID C

1TB-FD044 TB1 32/1J-1K 594+0 TB1/MTOT DID C

1TB-FD045 TB1 30/1J-1K 594+0 TB1/MTOT DID C

1TB-FD046 TB1 32/1K-1L 568+0 TB1/OTT DID C

2TB-FD013 TB2 21-22/P 594+0 TB2/SRV DID C

2TB-FD014 TB2 21-22/P 594+0 TB2/SRV DID C

2TB-FD015 TB2 21-22/P 594+0 TB2/SRV DID C

2TB-FD016 TB2 21-22/P 594+0 TB2/SRV DID C

2TB-FD017 TB2 21-22/P 594+0 TB2/SRV DID C

2TB-FD018 TB2 21-22/P 594+0 TB2/SRV DID C

2TB-FD019 TB2 18-19/P 594+0 TB2/SRV DID C

2TB-FD020 TB2 18-19/P 594+0 TB2/SRV DID C

2TB-FD021 TB2 18-19/P 594+0 TB2/SRV DID C

2TB-FD022 TB2 18-19/P 594+0 TB2/SRV DID C

2TB-FD023 TB2 18-19/P 594+0 TB2/SRV DID C

2TB-FD024 TB2 18-19/P 594+0 TB2/SRV DID C

2TB-FD031 TB2 32/2K-2L 568+0 TB2/OTT DID C

2TB-FD032 TB2 18/P 594+0 TB2/SRV DID C

2TB-FD036 TB2 16-17/P 594+0 TB2/SRV DID C

2TB-FD038 TB2 17-18/P 594+0 TB2/SRV DID C

2TB-FD039 TB2 32/2J-2K 594+0 TB2/MTOT DID C

2TB-FD040 TB2 30/2J-2K 594+0 TB2/MTOT DID C

2TB-FD041 TB2 30-31/2J/2K 568+0 TB2/OTT DID C

• 2VA-FD070 is exempt from inspection requirements (SLC TR 16.9-5-5) for ALARA reasons Table 16.9-5-3 HIGH SAFETY SIGNIFICANT (HSS) FIRE AREAS*

FIRE AREA BLDG ELEVATION DESCRIPTION 6

AUX 560+0 Unit 1 Electrical Pen Room El 560 12 AUX 577+0 Unit 2 Electrical Pen Room El 577 13 AUX 577+0 Unit 1 Electrical Pen Room El 577 14 AUX 577+0 Unit 2 4160V Essential Swgr Room (2ETA) 15 AUX 577+0 Unit 1 4160V Essential Swgr Room (1ETA) 16 AUX 574+0 Unit 2 Cable Room El 574 17 AUX 574+0 Unit 1 Cable Room El 574 21 AUX 594+0 Main Control Room El 594

• High Safety Significant (HSS) Fire Areas are defined as the areas with HSS fire barrier features in accordance with the Catawba NFPA 805 Monitoring Program.

Fire Rated Assemblies 16.9-5 Table 16.9-5-4 FIRE AREAS AND SHUTDOWN TRAIN / METHOD Catawba Units 1 and 2 16.9-5-19 Revision 12 FIRE AREA FIRE AREA DESCRIPTIONS ASSURED SHUTDOWN TRAIN / METHOD 1

ND & NS Pump Room El 522 (Common)

SSS 2

Unit 2 CA Pump Room El 543 SSS 3

Unit 1 CA Pump Room El 543 SSS 4

Aux Bldg. Gen Area & NV Pump Room El 543 (Common)

SSS 5

Unit 2 Electrical Pen Room El 560 A

6 Unit 1 Electrical Pen Room El 560 A

7 Unit 2 4160V Essential SWGR Room El 560 A

8 Unit 1 4160V Essential SWGR Room El 560 A

9 Unit 2 Battery Room El 554 SSS 10 Unit 1 Battery Room El 554 SSS 11 Aux Bldg. Gen Area & U1 KC Pump Room El 560 (Common)

SSS 12 Unit 2 Electrical Pen Room El 577 B

13 Unit 1 Electrical Pen Room El 577 B

14 Unit 2 4160V Essential SWGR Room El 577 B

15 Unit 1 4160V Essential SWGR Room El 577 B

16 Unit 2 Cable Room El 574 SSS 17 Unit 1 Cable Room El 574 SSS 18 Aux Bldg. Gen Area & U2 KC Pump Room El 577 (Common)

SSS 19 Unit 2 Electrical Pen Room El 594 A

20 Unit 1 Electrical Pen Room El 594 A

21 Control Room El 594 (Common)

SSS 22 Aux Bldg. Gen Area El 594 (Common)

SSS 23 Unit 2 Fuel Storage Area El 605 A

24 Unit 1 Fuel Storage Area El 605 A

25 Diesel Generator Bldg. 1A El 556 B

25A Diesel Generator Bldg. 1A Stairwell B

26 Diesel Generator Bldg. 1B El 556 A

26B Diesel Generator Bldg. 1B Stairwell A

27 Diesel Generator Bldg. 2A El 556 B

27A Diesel Generator Bldg. 2A Stairwell B

28 Diesel Generator Bldg. 2B El 556 A

28B Diesel Generator Bldg. 2B Stairwell A

29 Train A RN Pump Structure El 600 (Common)

B 30 Train B RN Pump Structure El 600 (Common)

A 31 Unit 2 Train A Aux Shutdown Panel El 543 B

32 Unit 1 Train A Aux Shutdown Panel El 543 B

33 Unit 2 Train B Aux Shutdown Panel El 543 A

34 Unit 1 Train B Aux Shutdown Panel El 543 A

35 Control Room Tagout Area El 594 A or B 36 Unit 2 Turbine Driven CA Pump Control Panel Room El 543 B

37 Unit 1 Turbine Driven CA Pump Control Panel Room El 543 B

38 Unit 1 Fuel Storage Area HVAC Room El 631 A or B (continued)

Fire Rated Assemblies 16.9-5 Table 16.9-5-4 FIRE AREAS AND SHUTDOWN TRAIN / METHOD Catawba Units 1 and 2 16.9-5-20 Revision 12 FIRE AREA FIRE AREA DESCRIPTIONS ASSURED SHUTDOWN TRAIN / METHOD 39 Unit 2 Turbine Driven CA Pump Pit El 543 B

40 Unit 1 Turbine Driven CA Pump Pit El 543 B

41 DG1A Sequencer Tunnel El 556 B

42 DG1B Sequencer Tunnel El 556 A

43 DG2A Sequencer Tunnel El 556 B

44 DG2B Sequencer Tunnel El 556 A

45 Unit 1 Cable Room Corridor El 574 B

46 Unit 2 Cable Room Corridor El 574 B

47 Unit 2 Fuel Storage Area HVAC Room El 631 A or B 48 Unit 2 Interior Doghouse A and B 49 Unit 1 Interior Doghouse A and B 50 Unit 2 Exterior Doghouse A and B 51 Unit 1 Exterior Doghouse A and B ASB Auxiliary Service Building A or B RB1 Unit 1 Reactor Building A and B RB2 Unit 2 Reactor Building A and B SRV Service Building B

SSF Standby Shutdown Facility A or B STAIR* Stairway See Note TB1 Unit 1 Turbine Building A or B TB2 Unit 2 Turbine Building A or B YRD**

Yard Area A or B

• IF the barrier in a stairway is adjacent to a HSS Fire Area (see Table 16.9-5-3), enter CONDITION A; otherwise enter CONDITION C.

• • Exterior walls that interface with the YRD do not require entry into a CONDITION statement and therefore do not have a REQUIRED ACTION.

A = A TRAIN B = B TRAIN SSS = STANDBY SHUTDOWN SYSTEM

Fire Rated Assemblies 16.9-5 BASES The functional integrity of the Fire Rated Assemblies and associated sealing Catawba Units 1 and 2 16.9-5-21 Revision 12 devices ensures that fires will be confined or adequately retarded so as not to spread between fire areas/compartments.

The fire barriers and associated penetration seals are passive elements in the facility fire protection program and are subject to periodic inspections.

Risk-informed insights from the Fire PRA process can apply to compensatory actions. The safety significance of the fire area can provide relief for required compensatory actions. In addition, the presence of functional fire detection can reduce the required compensatory actions. Functional fire detection in the area provides early warning of a fire for fire brigade response. Fire detection can provide a compensatory action equivalent to or better than fire watch. However, the assembly must be located within the detector(s) radius of detection capability.

Fire barrier penetration seals, including cable/pipe penetration seals and fire dampers, are considered FUNCTIONAL when the visually observed condition indicates no abnormal change or abnormal degradation. An evaluation is performed to determine the cause of any identified fire barrier penetration seal abnormal change in appearance or abnormal degradation and the effect of this change on the ability of the fire barrier penetration seal to perform its function. Based on this evaluation additional inspections may be performed.

Access to Fire Damper 2VA-FD070 is in a locked Hi-Rad area. Due to ALARA reasons, this damper is exempt from inspection requirements (SLC TR 16.9-5-5). The technical justification for excluding this damper from inspection is in calculation CNC-1435.00-00-0035.

During periods of time when a barrier is not FUNCTIONAL, either:

(1)

Perform the recommended fire watch in accordance with the criteria in the remedial actions, or (2) a licensee may choose to implement a different required action or a combination of actions (e.g., additional administrative controls, operator briefings, temporary procedures, interim shutdown strategies, operator manual actions, temporary fire barriers, temporary detection or suppression systems). Such a change must be made to the approved Fire Protection Plan (FPP). However, the licensee must complete a documented evaluation of the impact of the proposed required action to the FPP. The evaluation must demonstrate that the required actions would not adversely affect the ability to achieve and maintain safe shutdown in the event of a fire. Any change to the FPP must maintain compliance with the General Design Criteria and 10 CFR 50.48(a).

The evaluation of the required action should incorporate risk insights regarding the location, quantity, and type of combustible material in the fire area; the presence of ignition sources and their likelihood of occurrence; the automatic fire suppression and the fire detection

Fire Rated Assemblies 16.9-5 capability in the fire area; the manual fire suppression capability in the Catawba Units 1 and 2 16.9-5-22 Revision 12 fire area; and the human error probability where applicable.

BASES (continued)

The expectation is to promptly complete the corrective action at the first available opportunity and eliminate the reliance on the required action.

This SLC is part of the Catawba Fire Protection Program and therefore subject to the provisions of Section 2.C.(5) of the Catawba Renewed Facility Operating Licenses.

REFERENCES

1.

Catawba UFSAR, Section 9.5.1.

2.

Catawba Nuclear Station 10 CFR 50.48(c) Fire Protection Safety Evaluation (SE).

3.

Catawba Plant Design Basis Specification for Fire Protection, CNS-1465.00-00-0006, as revised.

4.

Catawba UFSAR, Section 18.2.8.

5.

Catawba License Renewal Commitments, CNS-1274.00 0016, Section 4.12.2.

6.

NRC Regulatory Issue Summary 2005-07, Compensatory Measures to Satisfy the Fire Protection Program Requirements, April 19, 2005.

7.

Catawba Renewed Facility Operating License Conditions 2.C.(5).

8.

CNC-1435.00-00-0084, Catawba NFPA 805 Monitoring Program.

9.

CNC-1435.00-00-0044, Fire Protection Nuclear Safety Capability Assessment.

10.

CNC-1435.00-00-0035, Penetration Seal Data Base and 86-10 Evaluations.

11.

CN-1209.10 series drawings.

12.

CN-1105 series drawings.

Boration Systems Flow Paths - Operating 16.9-8 Catawba Units 1 and 2 16.9-8-1 Revision 6 16.9 AUXILIARY SYSTEMS 16.9-8 Boration Systems Flow Paths - Operating COMMITMENT Two of the following three boron injection flow paths shall be FUNCTIONAL:

a.

The flow path from the boric acid tanks via a boric acid transfer pump and a charging pump to the Reactor Coolant System (RCS), and

b.

Two flow paths from the Refueling Water Storage Tank (RWST) via charging pumps to the RCS.

APPLICABILITY:

MODES 1, 2, and 3, MODE 4 with all RCS cold leg temperatures > 210qF.

REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A.

One required Boration System Flow Path non-functional.

A.1 Restore the required Boration System Flow Path to FUNCTIONAL status.

72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> B.

Required Action and associated Completion Time of Condition A not met.

B.1 Be in MODE 3.

AND B.2 Borate to a SDM equivalent to > 1% 'k/k at 200qF.

AND B.3 Restore the required Boration System Flow Path to FUNCTIONAL status.

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> 6 hours 7 days (continued)

Boration Systems Flow Paths - Operating 16.9-8 Catawba Units 1 and 2 16.9-8-2 Revision 6 REMEDIAL ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C.

Required Action and associated Completion Time of Condition B not met.

C.1 Be in MODE 4 with any RCS cold leg temperature

< 210qF.

30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> TESTING REQUIREMENTS TEST FREQUENCY TR 16.9-8-1 Verify that the temperature of the flow path from the boric acid tanks is > 65qF when it is a required water source.

7 days TR 16.9-8-2 Verify that each manual, power operated, or automatic valve in the flow path, that is not locked, sealed, or otherwise secured in position, is in the correct position.

18 months TR 16.9-8-3 Verify, during shutdown, that each automatic valve in the flow path actuates to the correct position on a safety injection test signal.

18 months TR 16.9-8-4 Verify that the flow path required by SLC 16.9-8a.

delivers > 30 gpm to the RCS.

18 months BASES The Boration System Flow Paths ensure that negative reactivity control is available during each MODE of facility operation. The components required to perform this function include separate flow paths and boric acid transfer pumps.

In MODES 1, 2, and 3, and MODE 4 with all RCS cold leg temperatures above 210qF, a minimum of two boron injection flow paths are required to ensure single functional capability in the event an assumed failure renders one of the flow paths non-functional. The boration capability of either flow path, in association with a charging pump and borated water source, is sufficient to provide a SHUTDOWN MARGIN from expected operating conditions of 1.3% 'k/k after xenon decay and cooldown to 200qF.

BASES (continued)

Boration Systems Flow Paths - Operating 16.9-8 Catawba Units 1 and 2 16.9-8-3 Revision 6 Above 210qF, the charging pumps are the only pumps that can be assured to be capable of injecting into the RCS against the maximum pressure allowed by the RCS heatup and cooldown curves.

REFERENCES

1.

Letter from NRC to Gary R. Peterson, Duke, Issuance of Improved Technical Specifications Amendments for Catawba, September 30, 1998.

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-1 Revision 15 16.11 RADIOLOGICAL EFFLUENTS CONTROLS 16.11-7 Radioactive Gaseous Effluent Monitoring Instrumentation COMMITMENT The Radioactive Gaseous Effluent Monitoring Instrumentation channels shown in Table 16.11-7-1 shall be FUNCTIONAL with their Alarm/Trip Setpoints set to ensure that the limits of SLC 16.11-6 are not exceeded.

AND The Alarm/Trip Setpoints of these channels shall be determined and adjusted in accordance with the methodology and parameters in the OFFSITE DOSE CALCULATION MANUAL (ODCM).

APPLICABILITY:

Conditions are applicable as shown in Table 16.11-7-1.

REMEDIAL ACTIONS

---

NOTE--------------------------------------------------------

Separate Condition entry is allowed for each Function.

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-2 Revision 15 CONDITION REQUIRED ACTION COMPLETION TIME A.

One or more Radioactive Gaseous Effluent Monitoring Instrumentation channel(s) Alarm/Trip Setpoint less conservative than required.

A.1 Suspend the release of radioactive gaseous effluents monitored by the affected channel(s).

OR A.2 Declare the channel(s) non-functional.

Immediately Immediately B.

One or more Radioactive Gaseous Effluent Monitoring Instrumentation channel(s) non-functional.

B.1 Enter the applicable Conditions and Required Actions specified in Table 16.11-7-1 for the channel(s).

AND B.2.1 Restore channel to FUNCTIONAL status.

OR B.2.2 Restore channel to FUNCTIONAL status.

Immediately 14 Days (*Note 1) 30 Days (*Note 1)

• Note 1 - Required Action B.2.1 applies to Instrument 1.a ONLY. (continued)

Required Action B.2.2 applies to Instruments 1.b, 2, 3.a, 3.c, 3.d, 3.e, 5, 6.a, and 6.b listed in Table 16.11-7-1.

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-3 Revision 15 REMEDIAL ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME C.

One channel non-functional.

C.1 Verify that EMF-36 (Low Range) is FUNCTIONAL.

OR C.2.1 Analyze two independent samples of the tanks contents.

AND C.2.2 Perform independent verification of the discharge line valving.

AND C.2.3.1 Perform independent verification of manual portion of the computer input for release rate calculations performed by computer.

OR C.2.3.2 Perform independent verification of entire calculations for release rate calculations performed manually.

OR C.3 Suspend release of radioactive effluents via this pathway.

Prior to initiating a release Prior to initiating a release Prior to initiating a release Prior to initiating a release Prior to initiating a release Immediately (continued)

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-4 Revision 15 REMEDIAL ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME D.

One or more flow rate measurement device channel(s) non-functional.

D.1 Estimate the flow rate of the release.

Once per 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> during releases E.

One or more Noble Gas Activity Monitor channel(s) non-functional.

---

NOTE-------------------

IF 0EMF41 is NON-FUNCTIONAL AND either 1EMF36 OR 2EMF36 is NON-FUNCTIONAL, perform SLC 16.7-10, Required Action G.2 E.1 Obtain grab samples from effluent pathway.

AND E.2 Perform an analysis of grab samples for radioactivity.

Once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> during releases Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of obtaining the sample (continued)

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-5 Revision 15 REMEDIAL ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME F.

Noble Gas Activity Monitor (EMF Low Range) providing automatic termination of release via the Containment Purge Exhaust System (CPES) non-functional.

F.1

---

NOTE--------------

In order to utilize Required Action F.1, the following conditions must be satisfied:

1. The affected unit is in MODES 5 or 6.

2. EMF-36 is FUNCTIONAL and in service for the affected unit.

3. The Reactor Coolant System for the affected unit has been vented.

4. Either the reactor vessel head is in place (bolts are not required),

or if it is not in place, the lifting of heavy loads over the reactor vessel and the movement of irradiated fuel assemblies within containment have been suspended.

Restore the non-functional channel to FUNCTIONAL status.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> G.

Required Action and associated Completion Time of Condition F not met.

OR Required Action F.1 not utilized.

G.1 Suspend PURGING of radioactive effluents via this pathway.

Immediately (continued)

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-6 Revision 15 REMEDIAL ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME H.

One or more sampler channel(s) non-functional.

H.1 Perform sampling with auxiliary sampling equipment as required by Table 16.11-6-1.

Continuously I.

One Condenser Evacuation System Noble Gas Activity Monitor (EMF-33) channel non-functional.

I.1

---

NOTE-------------

Applicable to effluent releases via the Condenser Steam Air Ejector (ZJ)

System.

Obtain grab samples from effluent pathway.

AND I.2

---

NOTE-------------

Applicable to effluent releases via the Condenser Steam Air Ejector (ZJ)

System.

Perform an analysis of grab samples for radioactivity.

AND Once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> during releases Within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of obtaining the sample (continued)

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-7 Revision 15 REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME I.

(continued)

I.3

---

NOTE-------------

Applicable to effluent releases via the Steam Generator Blowdown (BB)

System atmospheric vent valve (BB-27) in the off-normal mode.

Perform an analysis of grab samples for radioactivity at a lower limit of detection of 10-7 microCurie/ml.

Once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> during releases when secondary specific activity is > 0.01 microCurie/gm DOSE EQUIVALENT I-131 AND Once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> during releases when secondary specific activity is < 0.01 microCurie/gm DOSE EQUIVALENT I-131 J.

Noble Gas Activity Monitor (EMF Low Range) providing automatic termination of release via the Containment Air Release and Addition System non-functional.

J.1 Verify that EMF-36 is FUNCTIONAL.

OR J.2.1 Analyze two independent samples of the containment atmosphere.

AND Prior to initiating a release Prior to initiating a release (continued)

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-8 Revision 15 REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME J.

(continued)

J.2.2 Perform independent verification of the discharge line valving.

AND J.2.3.1 Perform independent verification of manual portion of the computer input for release rate calculations performed by computer.

OR J.2.3.2 Perform independent verification of entire calculations for release rate calculations performed manually.

Prior to initiating a release Prior to initiating a release Prior to initiating a release (continued)

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-9 Revision 15 REMEDIAL ACTIONS (continued)

CONDITION REQUIRED ACTION COMPLETION TIME K.

Required Action and associated Completion Time of Condition B or F not met.

K.1 Explain why the non-functionality was not corrected within the specified Completion Time.

In the next scheduled Radioactive Effluent Release Report pursuant to Technical Specification 5.6.3 TESTING REQUIREMENTS

---

NOTE--------------------------------------------------------

Refer to Table 16.11-7-1 to determine which TRs apply for each Radioactive Gaseous Effluent Monitoring Instrumentation channel.

TEST FREQUENCY TR 16.11-7-1 Perform CHANNEL CHECK.

Prior to each release TR 16.11-7-2 ---------------------------------NOTE---------------------------------

For Instruments 1a, 4, and 5, a SOURCE CHECK for these channels shall be the qualitative assessment of channel response when the channel sensor is exposed to a light-emitting diode.

Perform SOURCE CHECK.

Prior to each release TR 16.11-7-3 Perform CHANNEL CHECK.

12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> TR 16.11-7-4 Perform CHANNEL CHECK.

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> TR 16.11-7-5 Perform CHANNEL CHECK.

7 days (continued)

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-10 Revision 15 TESTING REQUIREMENTS (continued)

TEST FREQUENCY TR 16.11-7-6 ---------------------------------NOTE---------------------------------

For Instruments 2 and 3a, a SOURCE CHECK for these channels shall be the qualitative assessment of channel response when the channel sensor is exposed to a light-emitting diode.

Perform SOURCE CHECK.

31 days TR 16.11-7-7 ---------------------------------NOTE---------------------------------

For Instruments 1a, 3a, 3c, 5, and 6a, the COT shall also demonstrate, as applicable, that automatic isolation of this pathway and control room alarm annunciation (for EMF-58, alarm annunciation is in the Monitor Tank Building control room and on the Monitor Tank Building control panel remote annunciator panel) occur if any of the following conditions exist:

a.

Instrument indicates measured levels above the Alarm/Trip Setpoint, or

b.

Circuit failure/instrument downscale failure (alarm only)

Perform COT.

18 months TR 16.11-7-8 ---------------------------------NOTE---------------------------------

For Instruments 2 and 4, the COT shall also demonstrate that automatic isolation of this pathway and control room alarm annunciation occur if any of the following conditions exist:

a.

Instrument indicates measured levels above the Alarm/Trip Setpoint, or

b.

Circuit failure/instrument downscale failure (alarm only)

Perform COT.

18 months (continued)

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-11 Revision 15 TESTING REQUIREMENTS (continued)

TEST FREQUENCY TR 16.11-7-9 ---------------------------------NOTE---------------------------------

For Instruments 1a, 2, 3a, 3c, 4, 5, and 6a, the initial CHANNEL CALIBRATION shall be performed using one or more of the reference standards certified by the National Bureau of Standards (NBS) or using standards that have been obtained from suppliers that participate in measurement assurance activities with NBS. These standards shall permit calibrating the system over its intended range of energy and measurement range. For subsequent CHANNEL CALIBRATION, sources that have been related to the initial calibration shall be used.

Perform CHANNEL CALIBRATION.

18 months

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-12 Revision 15 Table 16.11-7-1 Radioactive Gaseous Effluent Monitoring Instrumentation (page 1 of 2)

INSTRUMENT REQUIRED CHANNELS CONDITIONS APPLICABLE MODES TESTING REQUIREMENTS

1.

Waste Gas Holdup System 1.a Noble Gas Activity Monitor - Providing Alarm and Automatic Termination of Release (EMF Low Range) 1 per station B, K A, C At all times (Note 3)

TR 16.11-7-1 TR 16.11-7-2 TR 16.11-7-7 TR 16.11-7-9 1.b Effluent System Flow Rate Measuring Device 1 per station B, K D

At all times (Note 3)

TR 16.11-7-1 TR 16.11-7-9

2.

Condenser Evacuation System Noble Gas Activity Monitor (EMF-33) (BB-27 is only isolation function required) (Note 1) 1 B, K A, I At all times (Note 4)

TR 16.11-7-3 TR 16.11-7-6 TR 16.11-7-8 TR 16.11-7-9

3.

Vent System 3.a Noble Gas Activity Monitor (EMF Low Range) 1 A, B, E, K At all times TR 16.11-7-4 TR 16.11-7-6 TR 16.11-7-7 TR 16.11-7-9 3.b Deleted.

3.c Particulate Sampler (EMF-35) 1 B, K A, H At all times (Note 2)

TR 16.11-7-4 TR 16.11-7-6 TR 16.11-7-7 TR 16.11-7-9 3.d Unit Vent Stack Flow Rate Meter (no alarm/trip function) 1 B, K D

At all times (Note 2)

TR 16.11-7-4 TR 16.11-7-9 3.e Unit Vent Radiation Monitor Flow Meter 1

B, K E

At all times (Note 2)

TR 16.11-7-4 TR 16.11-7-9

4.

Containment Purge System Noble Gas Activity Monitor - Providing Alarm and Automatic Termination of Release (EMF Low Range) 1 A, F, G, K 5, 6 TR 16.11-7-2 TR 16.11-7-3 TR 16.11-7-8 TR 16.11-7-9 (continued)

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-13 Revision 15 Table 16.11-7-1 Radioactive Gaseous Effluent Monitoring Instrumentation (page 2 of 2)

INSTRUMENT REQUIRED CHANNELS CONDITIONS APPLICABLE MODES TESTING REQUIREMENTS

5.

Containment Air Release and Addition System Noble Gas Activity Monitor -

Providing Alarm and Automatic Termination of Release (EMF Low Range) 1 A, B, J, K 1, 2, 3, 4, 5, 6 TR 16.11-7-2 TR 16.11-7-3 TR 16.11-7-7 TR 16.11-7-9

6.

Monitor Tank Building HVAC 6.a Noble Gas Activity Monitor - Providing Alarm (EMF Low Range) 1 per station B, K A, E At all times (Note 2)

TR 16.11-7-4 TR 16.11-7-6 TR 16.11-7-7 TR 16.11-7-9 6.b Effluent Flow Rate Measuring Device 1 per station B, K D

At all times (Note 2)

TR 16.11-7-4 TR 16.11-7-9 Note 1: The setpoint is as required by the primary to secondary leak rate monitoring program.

Note 2: Applicable at all times, unless the effluent pathway is mechanically isolated; thus, a release to the environment is not possible.

Note 3: Applicable at all times, unless the effluent pathway is mechanically isolated; thus, a release to the environment is not possible. Utilization of this note requires the pathway be isolated by locked close valve.

Note 4: When air ejectors are in operation, apply Required Action I.3 when air ejectors are NOT in operation.

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-14 Revision 15 BASES The Radioactive Gaseous Effluent Monitoring Instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in gaseous effluents during actual or potential releases of gaseous effluents. The Alarm/Trip Setpoints for these instruments shall be calculated in accordance with the methodology and parameters in the ODCM to ensure that the Alarm/Trip will occur prior to exceeding the limits of 10 CFR Part 20. Conservative Alarm/Trip Setpoints may be used during a release provided they are less than or equal to the setpoints determined by the methodology and parameters of the ODCM. The FUNCTIONALITY and use of this instrumentation is consistent with the requirements of General Design Criteria 60, 63, and 64 of Appendix A to 10 CFR Part 50. The sensitivity of any noble gas activity monitor used to show compliance with the gaseous effluent release requirements of SLC 16.11-8 shall be such that concentrations as low as 1 x 10-6 Ci/cc are measurable.

Regarding Notes 2 and 3 of Table 16.11-7-1, isolation of the effluent pathway is to be by mechanical means (e.g., valve closure). Electrical or pneumatic isolation is not required, unless the isolation is designed to receive an automatic signal to open. For EMF-50 Low Range only, isolation of the effluent pathway is only considered complete if isolated by a locked closed valve.

In MODES 5 and 6, initiation of the Containment Purge Exhaust System (CPES) with EMF-39 non-functional is not permissible. The basis for Required Action F.1 is to allow the continued operation of the CPES with EMF-39 initially FUNCTIONAL. Continued operation of the CPES is contingent upon the ability of the affected unit to meet the requirements as noted in Required Action F.1.

TR 16.11-7-7 requires the performance of a COT on the applicable Radioactive Gaseous Effluent Radiation Monitors. The test ensures that a signal from the control room module can generate the appropriate alarm and actuations. The required actuations/isolations for a High Radiation condition (i.e., radiation level above its Trip 2 setpoint) are listed below for each monitor.

0EMF Waste Gas Discharge Monitor 1WG160 closes when EMF-50 detects radiation level above its setpoint.

1/2EMF Unit Vent Noble Gas Monitor The following actuations occur when EMF-36 detects radiation level above its setpoint:

1.

Containment Air Release and Addition System fans discharge to unit vent valve VQ10 closes.

2.

Auxiliary Building unfiltered ventilation exhaust fans A and B stop.

3.

Fuel Handling Ventilation Exhaust System (FHVES) exhaust trains align to the filter units.

4.

(For 1EMF-36 only) 1WG160 closes.

1/2EMF Unit Vent Particulate Monitor (Sampler)

The following actuations occur when EMF-35 detects radiation level above its setpoint:

1.

Containment Air Release and Addition System fans discharge to unit vent valve VQ10 closes.

2.

Auxiliary Building unfiltered ventilation exhaust fans A and B stop.

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-15 Revision 15 BASES (continued)

3.

Fuel Handling Ventilation Exhaust System (FHVES) exhaust trains align to the filter units.

4.

((For 1EMF-35 only) 1WG160 closes.

1/2EMF Containment Noble Gas Monitor The following actuations occur when EMF-39 detects radiation level above its setpoint:

1.

Signals are provided to both trains of the Solid State Protection System (SSPS) to initiate a CPES isolation. This is verified by observing that Relays K615 in the SSPS A output cabinet and the SSPS B output cabinet are latched.

2.

EMF-39 isolates the CPES without going through the SSPS by stopping CPES supply fans A and B, CPES exhaust fans A and B, and by closing the appropriate valves and dampers.

3.

Containment Evacuation Alarm, unless the source range trip is blocked.

0EMF-58 This monitor provides no control function.

TR 16.11-7-8 requires the performance of a COT on the Condensate Steam Air Ejector Exhaust Monitor, 1/2EMF-33 and Containment Noble Gas Monitor, 1/2EMF-39. The test ensures that a signal from the control room module can generate the appropriate alarm and actuations. The required actuations/isolations for a High Radiation condition (i.e., radiation level above its Trip 2 setpoint) are listed below.

1/2EMF Condensate Steam Air Ejector Exhaust Monitor The following actuations occur when EMF-33 detects radiation level above its setpoint:

1. Closure of BB27 is required in order to isolate the Blowdown Tank from the environment. Because of plant limitations/restrictions:

a. Opening the valve (in order to verify it goes closed on a High Radiation signal) is only possible during outages due to the negative effects on the Blowdown System with the unit at power.

b. Testing during innages will be by verification of relay contacts opening in the valve circuit.

2. Closure of BB24, BB65, BB69, and BB73 is required to minimize the amount of potentially contaminated material being delivered to the Blowdown Tank.

3. Closure of NM269, NM270, NM271, and NM272 is required to minimize the amount of potentially contaminated material being delivered to the Conventional Sampling System.

4. Closure of NM267 is required to minimize the amount of potentially contaminated material being delivered to the Condensate Storage Tank by isolating flow through EMF-34.

5. Closure of BB48 is required to minimize the amount of potentially contaminated material being delivered from the Blowdown System discharge to the Turbine Building sump.

Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Catawba Units 1 and 2 16.11-7-16 Revision 15 BASES (continued) 1/2EMF Containment Noble Gas Monitor The following actuations occur when EMF-39 detects radiation level above its setpoint:

1.

Signals are provided to both trains of the Solid State Protection System (SSPS) to initiate a Containment Air Release and Addition System isolation. This is verified by observing that relays K615 in the SSPS Train A output cabinet and the SSPS Train B output cabinet are latched.

2.

Containment Evacuation Alarm, unless the source range trip is blocked.

REFERENCES

1.

Catawba Offsite Dose Calculation Manual.

2.

10 CFR Part 20.

3.

AR 02400313, 0EMF-50L Non-Functional.

REPORT OF INFORMATION REMOVED FROM REVISION 24 OF THE CATAWBA NUCLEAR STATION, UNITS 1 AND 2 UFSAR

1. Section 9.1.5.4.1(4) Special Lifting Devices is revised to add "For the reactor vessel head lifting rig and the reactor internals lifting rig, Acoustic Emission testing is a permitted inspection method as an alternative to the nondestructive testing specified in ANSI N14.6-1978." The same UFSAR Section is revised to delete the sentence referencing the deleted legacy document, Duke Energy Nuclear Lifting Program Manual.

A replacement sentence is not needed to exhibit Catawba's commitment to compliance with NUREG-0612.

2. Section 4.2.4.5 Fuel Assembly updates the language regarding fuel shipping container loads and removing extraneous information.

Chapter 18 has numerous changes to incorporate information regarding completion of license renewal commitments, to reflect 60 year licensed life, including:

3. Section 18.2.1 Alloy 600 Aging Management Program removes extraneous detail and summarizes that the Alloy 600 Aging Management Program is administered in accordance with applicable code cases approved in 10 CFR 50.55a.

4. Section 18.2.12.4 Control Area Chilled Water removes the admiralty brass as a material managed by this activity.

5. Section 18.2.32 Inspection of Internal Surfaces of Miscellaneous Piping Components Program removes the aging management requirements related to Waste Gas Decay Tanks and connected piping/piping components, as the basis that the indication originally noted in Waste Gas Decay Tank 0WGTKDDGT is fabrication related and not indicative of age related degradation.

6. Section 18.4.1.6.3 removes the descriptions on Service Water Piping Corrosion Program and Selective Leaching Inspection Program and replaces it with updated text at the end of the section.

7. Section 3.8.3.1.17 Pressure Seals and Gaskets removes the statement that the seals are expected to last the lift of the unit, and referred to 40 year unit life.