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| {{#Wiki_filter:SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d) | | {{#Wiki_filter:}} |
| : r. DUKE UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED
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| * ~ ENERGY 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 10 CFR 50.4 10 CFR 50.71(e) 10 CFR 50.59 Serial: RA-23-0042 April 24, 2023 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
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| ==Subject:==
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| Submittal of Updated Final Safety Analysis Report (Revision 23),
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| 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:
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| Pursuant to 10 CFR 50.71(e), Duke Energy Carolinas, LLC (Duke Energy) hereby submits Revision 23 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 October 26, 2022. 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 22 are identified by vertical lines in the margins of the pages that are indicated as Revision 23.
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| 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 July 18, 2021 to March 8, 2023 for CNS. This report is included in Enclosure 3.
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| 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.
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| Additionally, in accordance with 10 CFR 50.71(e), Duke Energy is providing the changes made SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)
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| UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED
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| SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)
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| UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED U.S. Nuclear Regulatory Commission RA-23-0042 Page 2 to the CNS Selected Licensee Commitments (SLC) Manual since October 5, 202 1. These changes are located in Enclosure 5. The CNS SLC manual constitutes Chapter 16 of the UFSAR.
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| In addition, in accordance with NEI 99-04 , Guidelines for Managing NRC Commitments , includes notification of regulatory commitment changes made during the time period from October 29, 2021 through April 24, 2023.
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| There are no regulatory commitments contained in this letter.
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| If you have any questions regarding this submittal, please contact Ryan Treadway , Director -
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| Fleet Licensing , at (980) 373-5873.
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| I declare under penalty of perjury that the foregoing is true and correct.
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| Executed on April 24, 2023.
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| Sincerely, Nicole Flippin Vice President, Catawba Nuclear Station
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| ==Enclosures:==
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| : 1. Catawba Nuclear Station Updated Final Safety Analysis Report Update - Rev 23 Redacted Version (Publicly Available Information)
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| : 2. Catawba Nuclear Station Updated Final Safety Analysis Report Update - Rev 23 (Non-Publicly Available Information)
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| : 3. Catawba Nuclear Station 10 CFR 50.59 Evaluation Summary Report
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| : 4. Catawba Nuclear Station Technical Specification (TS) Bases Changes
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| : 5. Catawba Nuclear Station Selected Licensee Commitments (SLC) Manual Changes
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| : 6. Catawba Nuclear Station Notification of Regulatory Commitment Change
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| ==Attachment:==
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| Report of Information Removed from the Revision 23 of the Catawba Nuclear Station UFSAR SECURITY-RELATED INFORMATION- WITHHOLD UNDER 10 CFR 2.390(d)
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| UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED
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| SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)
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| UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED U.S. Nuclear Regulatory Commission RA-23-0042 Page 3 xc:
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| L. Dudes, USNRC Region II - Regional Administrator D. Rivard, USNRC Senior Resident Inspector - CNS S. Williams, USNRC NRR Project Manager - CNS SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)
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| UPON REMOVAL OF ENCLOSURE 2 THIS LETTER IS UNCONTROLLED
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| SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)
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| UPON REMOVAL OF ENCLOSUR E 2 THIS LETTER IS UNCONTROLLED U.S. Nuclear Regulatory Commission RA-23-0042 April 24, 2023 Enclosure 1 Catawba Nuclear Station Updated Final Safety Analysis Report Update - Rev 23 Redacted Version (Publicly Available Information)
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| SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)
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| UPON REMOVAL OF ENCLOSUR E 2 THIS LETTER IS UNCONTROLLED
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| SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)
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| UPON REMOVAL OF ENCLOSUR E 2 THIS LETTER IS UNCONTROLLED U.S. Nuclear Regulatory Commission RA-23-0042 April 24, 2023 Enclosure 2 Catawba Nuclear Station Updated Final Safety Analysis Report Update - Rev 23 (Non-Publicly Available Information)
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| SECURITY-RELATED INFORMATION - WITHHOLD UNDER 10 CFR 2.390(d)
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| UPON REMOVAL OF ENCLOSUR E 2 THIS LETTER IS UNCONTROLLED
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| U.S. Nuclear Regulatory Commission RA-23-0042 April 24, 2023 Enclosure 3 Catawba Nuclear Station 10 CFR 50.59 Evaluation Summary Report
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| U.S. Nuclear Regulatory Commission RA-23-0042, Enclosure 3 Page 1 of 3 Summary of 10 CFR 50.59 Evaluations
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| ==Title:==
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| Unit 1 Zone B Main Power Protective Relay Documentation Number(s):
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| Action Request (AR) 02389980 Brief
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| == Description:==
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| Engineering Change 405249, upgrades 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.
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| The relay inputs and outputs will be connected to layered communication server networks to a single Real-Time Automation Controller (RTAC) that allows data retrieval over fiber optic cables and ethernet connections.
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| EC 405249 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 1B protective relay output co-incident logic, and (4) changes to miscellaneous electro-mechanical relay accessory devices.
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| Elements of Change that Screened In:
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| : 1. Consolidation of previously separate protective relay elements into a single digital device creates a potential failure mode that was not considered with the existing equipment.
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| : 2. Introduction of digital devices that contain software creates the potential for a software common cause failure (SCCF) that does not exist with the existing analog equipment.
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| : 3. Installation of the new RTAC that monitors and sends commands to the protective relaying for data retrieval creates a potential failure mode that does not exist with the existing analog equipment.
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| From this evaluation it is concluded that the change can be implemented under 10CFR 50.59 without prior approval from the NRC.
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| U.S. Nuclear Regulatory Commission RA-23-0042, Enclosure 3 Page 2 of 3 Summary of 10 CFR 50.59 Evaluations
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| ==Title:==
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| Extend Turbine Valve Test Intervals Documentation Number(s):
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| Action Request (AR) 02398062 Brief
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| == Description:==
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| Revise SLC 16.7-5 Test Frequency to incrementally increase test interval from 4 months to 18 months.
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| The Proposed Activity is to make the following changes to Selected Licensee Commitment (SLC) 16.7-5, Turbine Overspeed Protection. The proposed changes will reduce the power reductions required to cycle the control valves and reduce the risk of turbine trip during the valve cycling and the potential for plant transient during the power reduction and during the cycling of the valves. The changes are based on a probability analysis documented in calculation CNC-1200.00-00-0006, Catawba Turbine Overspeed Protection System Maintenance and Test Interval Assessment, Reference 17. The calculation incorporates a probability analysis performed by MPR and Associates.
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| From this evaluation it is concluded that the change can be implemented under 10CFR 50.59 without prior approval from the NRC.
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| U.S. Nuclear Regulatory Commission RA-23-0042 April 24, 2023
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| ==Title:==
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| Revision to Eval 02398062 Documentation Number(s):
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| Action Request (AR) 02421113 Brief
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| == Description:==
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| This 5EVL AR# 2421113 served as a revision to the 5EVL AR# 2398062. The change in the revision scope did not change the conclusions of the screen and is in compliance with both the 50.59 revision process in AD-LS-ALL-0008 as well as the On-site Review Committee requirements of AD-LS-ALL-0019 as satisfied in the original 50.59.
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| This revision to 02398062 corrects a typographical error in the activity description. Test Requirement (TR) TR 16.7-5-5 for the mechanical trip was corrected to TR 16.7-5-4 and TR 16.7-5-6 for the electrical trip was corrected to TR 16.7-5-5. Added sentence in the problem description stating that the probability analysis assumes that hydraulic oil samples are trended per OEM recommendations.
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| From this evaluation it is concluded that the change can be implemented under 10CFR 50.59 without prior approval from the NRC.
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| U.S. Nuclear Regulatory Commission RA-23-0042 April 24, 2023
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| ==Title:==
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| Revision 7 to SLC 16.7-5 Documentation Number(s):
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| Action Request (AR) 02427994 Brief
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| == Description:==
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| Revise SLC 16.7-5 to add condition to the remedial actions to address required actions for the mechanical and electrical overspeed trip functionality. UFSAR 3.5.1.3.4 and 3.5.4 are updated to reflect the change to SLC 16.7-5.
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| The Proposed Activity revises Catawba (CNS) Selected Licensee Commitment (SLC) 16.7-5, Turbine Overspeed Protection, Revision 6, to provide additional guidance for conditions where the mechanical or electrical overspeed trip devices are non-functional or non-testable. The current SLC 16.7-5 does not provide adequate guidance with respect to Remedial Actions associated with the mechanical and electrical turbine overspeed protection functions specified in Test Requirement (TR) 16.7-5-4 and TR 16.7-5-5. Currently CNS Unit 2 has experienced issues with a sequence halt during the performance of the mechanical trip test required per TR 16.7 4. The sequence halt is caused by sluggish operation of the oil trip solenoid valve which prevents timely reset of the mechanical trip latch. The mechanical trip functioned during the last test. However, if the mechanical trip could not be reset following subsequent tests, it would become necessary to maintain the mechanical trip locked out and thus rendering the mechanical trip non-functional. In addition, the electrical trip would be untestable resulting the electrical trip being considered non-functional due to exceeding the test frequency specified in the TR It is desired to postpone testing the mechanical trip required by TR 16.7-5-4 until a scheduled shutdown when the sluggish oil trip solenoid valve can be replaced provided a revised turbine missile generation probability (P1) analysis meets the criteria for continued operation as provided for in NUREG 0800, Section 3.5.1.3, revision 3. Specifically, SLC 16.7-5, condition C is being changed to Condition D and will address the required actions if conditions A, B or C are not met. The new CONDITION C requires evaluation of Turbine Missile generation probability (P1) when either the mechanical or electrical overspeed systems are non-functional or cannot be tested at the specified frequency. The required completion time is based on the revised P1 value in accordance with the probability criteria presented in the SLC 16.7-5 BASES.
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| A completion time of 6 days is provided to evaluate P1 with the degraded mechanical or electrical trip subsystem based on the probability criteria table in NUREG 800 Section 3.5.1.3, revision 3.The new Condition C guidance is based on NUREG 0800, Section 3.5.1.3, revision 3, adopted by the NRC in March of 2007. The guidance in NUREG 0800 Section 3.5.1.3 revision 3 provides options to evaluate off normal Turbine Overspeed Protection System Conditions based on approved probability evaluations meeting the Probability Criteria established in the NUREG.
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| The CNS SER and UFSAR section 3.5.1.3 probability criteria for meeting GDC 4 for protection from turbine generated missiles are in accordance with the conditions of NUREG 0800 Section 3.5.1.3, revision 3, section titled SRP Acceptance Criteria 1-4 (pages 3-6 of the NUREG reference). Based on this review, revision 3, of NUREG 0800 Section 3.5.1.3, is applicable to Catawba.
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| From this evaluation it is concluded that the change can be implemented under 10CFR 50.59 without prior approval from the NRC.
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| U.S. Nuclear Regulatory Commission RA-23-0042 April 24, 2023 Enclosure 4 Catawba Nuclear Station Technical Specification (TS) Bases Changes
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| Removal and insertion instructions for Catawba Nuclear Station Technical Specification Bases Changes for September 28, 2021 thru April 24, 2023.
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| REMOVE THESE PAGES INSERT THESE PAGES LIST OF EFFECTIVE PAGES Pages 1-19 Pages 1-19 Revision 36 (9/28/21) Revision 44 (2/14/23)
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| TECHNICAL SPECIFICATIONS BASES TAB B 3.3 B 3.3.1-1 thru 55 B 3.3.1-1 thru 57 Revision 8 Revision 10 B 3.3.2-1 thru 50 B 3.3.2-1 thru 52 Revision 12 Revision 14 B 3.3.3-1 thru 16 B 3.3.3-1 thru 17 Revision 6 Revision 7 TAB B 3.6 B 3.6.1-1 thru 5 B 3.6.1-1 thru 5 Revision 1 Revision 2 B 3.6.10-1 thru 6 B 3.6.10-1 thru 6 Revision 4 Revision 5 B 3.6.14-1 thru 5 B 3.6.14-1 thru 5 Revision 2 Revision 3 B 3.6.16-1 thru 4 B 3.6.16-1 thru 4 Revision 3 Revision 4 B 3.6.17-1 thru 5 B 3.6.17-1 thru 5 Revision 4 Revision 5 TAB B 3.7 B 3.7.5-1 thru 9 B 3.7.5-1 thru 9 Revision 5 Revision 6 B 3.7.7-1 thru 5 B 3.7.7-1 thru 5 Revision 2 Revision 3
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| TAB B 3.7 (continued)
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| B 3.7.9-1 thru 4 B 3.7.9-1 thru 4 Revision 3 Revision 4 B 3.7.10-1 thru 9 B 3.7.10-1 thru 9 Revision 14 Revision 15 B 3.7.12-1 thru 7 B 3.7.12-1 thru 7 Revision 11 Revision 12 TAB B 3.8 B 3.8.1-1 thru 39 B 3.8.1-1 thru 38 Revision 8 Revision 9 B 3.8.4-1 thru 11 B 3.8.4-1 thru 11 Revision 11 Revision 12 B 3.8.9-1 thru 10 B 3.8.9-1 thru 8 Revision 2 Revision 3
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| 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 1.1-4 268/264 6/25/12 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 1
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| 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 2
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| 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 3.3.1-11 263/259 3/29/11 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 3
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| 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 4
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| 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 5
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| 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 3.4.13-1 267/263 3/12/12 3.4.13-2 267/263 3/12/12 3.4.14-1 173/165 9/30/98 3.4.14-2 173/165 9/30/98 3.4.14-3 299/295 10/23/18 3.4.14-4 263/259 3/29/11 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 3.6.1-2 192/184 7/31/01 Catawba Units 1 and 2 Page 6
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| 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 3.6.14-3 270/266 8/6/13 Catawba Units 1 and 2 Page 7
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| 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 3.7.11-2 263/259 3/29/11 Catawba Units 1 and 2 Page 8
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| 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 3.8.1-16 308/304 9/28/21 3.8.1-17 263/259 3/29/11 3.8.1-18 308/304 9/28/21 3.8.1-19 292/288 9/08/17 3.8.1-20 308/304 9/28/21 3.8.1-21 308/304 9/28/21 3.8.2-1 173/165 9/30/98 3.8.2-2 207/201 7/29/03 3.8.2-3 173/165 9/30/98 Catawba Units 1 and 2 Page 9
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| 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 3.9.6-1 263/259 3/29/11 Catawba Units 1 and 2 Page 10
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| 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 5.6-6 311/307 6/28/22 Catawba Units 1 and 2 Page 11
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| 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 12
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| 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 Revision 7 5/02/19 3.0-21 B 3.1.1-1 thru Revision 3 5/05/11 B 3.1.1-6 B 3.1.2-1 thru Revision 3 11/14/17 B 3.1.2-5 B 3.1.3-1 thru Revision 2 4/14/15 B 3.1.3-6 B 3.1.4-1 thru Revision 1 5/05/11 B 3.1.4-9 B 3.1.5-1 thru Revision 2 5/05/11 B 3.1.5-4 B 3.1.6-1 thru Revision 1 5/05/11 B 3.1.6-6 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 Revision 4 3/28/18 B 3.1.8-6 B 3.2.1-1 thru Revision 4 5/05/11 B 3.2.1.-11 Catawba Units 1 and 2 Page 13
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| B 3.2.2-1 thru Revision 3 5/05/11 B 3.2.2-10 B 3.2.3-1 thru Revision 2 5/05/11 B 3.2.3-4 B 3.2.4-1 thru Revision 2 5/05/11 B 3.2.4-7 B 3.3.1-1 thru Revision 10 1/5/23 B.3.3.1-57 B 3.3.2-1 thru Revision 14 11/28/22 B 3.3.2-52 B 3.3.3-1 thru Revision 7 1/5/23 B.3.3.3-17 B 3.3.4-1 thru Revision 2 5/05/11 B 3.3.4-5 B 3.3.5-1 thru Revision 3 12/18/15 B 3.3.5-6 B 3.3.6-1 thru Revision 6 08/02/12 B 3.3.6-5 B 3.3.9-1 thru Revision 3 06/02/14 B 3.3.9-5 B 3.4.1-1 thru Revision 3 5/05/11 B 3.4.1-5 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 Revision 2 5/05/11 B 3.4.3-6 B 3.4.4-1 thru Revision 2 5/05/11 B 3.4.4-3 B 3.4.5-1 thru Revision 3 5/05/11 B 3.4.5-6 B 3.4.6-1 thru Revision 5 4/26/17 B 3.4.6-6 Catawba Units 1 and 2 Page 14
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| B 3.4.7-1 thru Revision 8 5/20/20 B 3.4.7-8 B 3.4.8-1 thru Revision 5 5/20/20 B 3.4.8-5 B 3.4.9-1 thru Revision 3 08/02/12 B 3.4.9-5 B 3.4.10-1 thru Revision 4 10/23/18 B 3.4.10-4 B 3.4.11-1 thru Revision 4 5/05/11 B 3.4.11-7 B 3.4.12-1 thru Revision 6 10/23/18 B 3.4.12-13 B 3.4.13-1 thru Revision 7 3/15/12 B 3.4.13-7 B 3.4.14-1 thru Revision 3 5/05/11 B 3.4.14-6 B 3.4.15-1 thru B Revision 6 5/05/11 3.4.15-10 B 3.4.16-1 thru Revision 4 10/23/12 B 3.4.16-5 B 3.4.17-1 thru Revision 2 5/05/11 B 3.4.17-3 B 3.4.18-1 thru Revision 2 4/26/16 B 3.4.18-8 B 3.5.1-1 thru Revision 4 4/26/17 B 3.5.1-8 B 3.5.2-1 thru Revision 5 10/23/18 B 3.5.2-11 B 3.5.3-1 thru Revision 2 4/26/17 B 3.5.3-3 B 3.5.4-1 thru Revision 5 4/11/14 B.3.5.4-5 B 3.5.5-1 thru Revision 1 5/05/11 B 3.5.5-4 Catawba Units 1 and 2 Page 15
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| B 3.6.1-1 thru Revision 2 6/14/22 B 3.6.1-5 B 3.6.2-1 thru Revision 2 5/05/11 B 3.6.2-8 B 3.6.3-1 thru Revision 7 10/23/18 B 3.6.3-14 B 3.6.4-1 thru Revision 2 5/05/11 B 3.6.4-4 B 3.6.5-1 thru Revision 3 07/27/13 B 3.6.5-4 B 3.6.6-1 thru Revision 8 10/23/18 B 3.6.6-8 B 3.6.8-1 thru Revision 3 5/05/11 B 3.6.8-5 B 3.6.9-1 thru Revision 6 5/05/11 B 3.6.9-5 B 3.6.10-1 thru Revision 5 2/14/23 B 3.6.10-6 B 3.6.11-1 thru Revision 5 5/05/11 B 3.6.11-6 B 3.6.12-1 thru Revision 5 5/05/11 B 3.6.12-11 B 3.6.13-1 thru B Revision 4 5/05/11 3.6.13-9 B 3.6.14-1 thru Revision 3 6/14/22 B 3.6.14-5 B 3.6.15-1 thru Revision 1 5/05/11 B 3.6.15-4 B 3.6.16-1 thru Revision 4 6/14/22 B 3.6.16-4 B 3.6.17-1 thru Revision 5 2/14/23 B 3.6.17-5 B 3.7.1-1 thru Revision 3 10/23/18 3.7.1-5 Catawba Units 1 and 2 Page 16
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| B 3.7.2-1 thru Revision 4 10/23/18 B 3.7.2-5 B 3.7.3-1 Revision 3 10/23/18 B 3.7.3-6 B 3.7.4-1 thru Revision 3 11/14/17 B 3.7.4-4 B 3.7.5-1 thru Revision 6 9/7/22 B 3.7.5-9 B 3.7.6-1 thru Revision 6 9/10/18 B 3.7.6-3 B 3.7.7-1 thru Revision 3 6/21/22 B 3.7.7-5 B 3.7.8-1 thru Revision 10 5/21/20 B 3.7.8-12 B 3.7.9-1 thru Revision 4 6/14/22 B 3.7.9-4 B 3.7.10-1 thru Revision 15 2/14/23 B 3.7.10-9 B 3.7.11-1 thru Revision 5 4/23/20 B 3.7.11-4 B 3.7.12-1 thru Revision 12 2/14/23 B 3.7.12-7 B 3.7.13-1 thru Revision 6 7/15/19 B 3.7.13-5 B 3.7.14-1 thru Revision 2 5/05/11 B 3.7.14-3 B 3.7.15-1 thru Revision 2 5/05/11 B 3.7.15-4 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 Revision 2 5/05/11 B 3.7.17-3 Catawba Units 1 and 2 Page 17
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| B 3.8.1-1 thru Revision 9 9/7/22 B.3.8.1-38 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 Revision 4 5/05/11 B 3.8.3-8 B 3.8.4-1 thru Revision 12 6/14/22 B 3.8.4.11 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 Revision 4 5/05/11 B 3.8.6-7 B 3.8.7-1 thru Revision 3 5/05/11 B 3.8.7-4 B 3.8.8-1 thru Revision 3 5/05/11 B 3.8.8-4 B 3.8.9-1 thru Revision 3 9/7/22 B 3.8.9-8 B 3.8.10-1 thru Revision 3 5/05/11 B 3.8.10-4 B 3.9.1-1 thru Revision 3 5/05/11 B 3.9.1-4 B 3.9.2-1 thru Revision 6 3/21/17 B 3.9.2-3 B 3.9.3-1 thru Revision 5 7/15/19 B 3.9.3-5 B 3.9.4-1 thru Revision 6 1/23/18 B 3.9.4-6 Catawba Units 1 and 2 Page 18
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| B 3.9.5-1 thru Revision 7 5/21/20 B 3.9.5-5 B 3.9.6-1 thru Revision 2 5/05/11 B 3.9.6-3 B 3.9.7-1 thru Revision 1 5/05/11 B 3.9.7-3 .
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|
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| Catawba Units 1 and 2 Page 19
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| 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.
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| 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.
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| 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).
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| During AOOs, which are those events expected to occur one or more times during the unit life, the acceptable limits are:
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| : 1. The Departure from Nucleate Boiling Ratio (DNBR) shall be maintained above the Safety Limit (SL) value to prevent departure from nucleate boiling (DNB);
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| : 2. Fuel centerline melt shall not occur; and
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| : 3. The RCS pressure SL of 2735 psig shall not be exceeded.
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| 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.
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| 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.
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| Meeting the acceptable dose limit for an accident category is considered having acceptable consequences for that event.
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| Catawba Units 1 and 2 B 3.3.1-1 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES BACKGROUND (continued)
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| The RTS instrumentation is segmented into four distinct but interconnected categories as illustrated in UFSAR, Chapter 7 (Ref. 1),
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| and as identified below:
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| : 1. Field transmitters or process sensors: provide a measurable electronic signal based upon the physical characteristics of the parameter being measured;
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| : 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;
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| : 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
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| : 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.
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| 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.
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| The OPERABILITY of each transmitter or sensor can be evaluated when its "as found" calibration data are compared against its documented acceptance criteria.
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| Catawba Units 1 and 2 B 3.3.1-2 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES BACKGROUND (continued)
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| 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.
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| 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.
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| 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.
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| 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.
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| 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.
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| Catawba Units 1 and 2 B 3.3.1-3 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES BACKGROUND (continued)
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| 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.
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| 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.
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| 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.
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| 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.
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| 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 Catawba Units 1 and 2 B 3.3.1-4 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES BACKGROUND (continued) for these channels are assumed to operate within the allowances of these uncertainty magnitudes.
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| 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.
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| 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.
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| 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.
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| 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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| Catawba Units 1 and 2 B 3.3.1-5 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES BACKGROUND (continued)
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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.
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| 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.
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| 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.
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| 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.
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| 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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| Catawba Units 1 and 2 B 3.3.1-6 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, AND APPLICABILITY (continued)
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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.
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| 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.
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| 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.
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| Reactor Trip System Functions The safety analyses and OPERABILITY requirements applicable to each RTS Function are discussed below:
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| : 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.
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| 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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| Catawba Units 1 and 2 B 3.3.1-7 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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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.
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| : 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.
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| : 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.
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| The LCO requires all four of the Power Range Neutron Flux-High channels to be OPERABLE.
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| Catawba Units 1 and 2 B 3.3.1-8 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, AND APPLICABILITY (continued)
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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.
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| : 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.
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| The LCO requires all four of the Power Range Neutron Flux-Low channels to be OPERABLE.
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| 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.
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| 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 Catawba Units 1 and 2 B 3.3.1-9 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, AND APPLICABILITY (continued) against positive reactivity additions or power excursions in MODE 3, 4, 5, or 6.
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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.
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| 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.
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| The LCO requires all four of the Power Range Neutron Flux-High Positive Rate channels to be OPERABLE.
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| 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.
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| 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.
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| : 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 Catawba Units 1 and 2 B 3.3.1-10 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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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.
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| 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.
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| 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.
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| 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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| Catawba Units 1 and 2 B 3.3.1-11 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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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.
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| 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.
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| 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.
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| 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.
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| 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.
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| 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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| Catawba Units 1 and 2 B 3.3.1-12 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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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
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| '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:
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| 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.
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| 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.
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| Dynamic compensation is included for system piping delays from the core to the temperature measurement system.
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| 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 Catawba Units 1 and 2 B 3.3.1-13 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) actuation, and a single failure in the other 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 Overtemperature 'T condition and may prevent a reactor trip.
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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.
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| 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.
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| : 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.
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| 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.
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| 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:
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| 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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| Catawba Units 1 and 2 B 3.3.1-14 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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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.
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| 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.
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| Failures that affect multiple Functions require entry into the Conditions applicable to all affected Functions.
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| 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.
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| : 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.
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| : 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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| Catawba Units 1 and 2 B 3.3.1-15 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| The LCO requires four channels of Pressurizer Pressure-Low to be OPERABLE.
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| 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.
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| : b. Pressurizer Pressure-High The Pressurizer Pressure-High trip Function ensures that protection is provided against overpressurizing the RCS.
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| This trip Function operates in conjunction with the pressurizer relief and safety valves to prevent RCS overpressure conditions.
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| The LCO requires four channels of the Pressurizer Pressure-High to be OPERABLE.
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| 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.
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| 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 Catawba Units 1 and 2 B 3.3.1-16 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) overpressure protection systems provide overpressure protection when below MODE 4.
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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.
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| 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.
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| 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.
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| : 10. Reactor Coolant Flow-Low
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| : a. Reactor Coolant Flow-Low (Single Loop)
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| 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.
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| Above the P-8 setpoint, which is approximately 48% RTP, a loss of flow in any RCS loop will actuate a reactor trip. The Catawba Units 1 and 2 B 3.3.1-17 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) setpoints are based on the minimum flow specified in the COLR. Each RCS loop has three flow detectors to monitor flow. The flow signals are not used for any control system input.
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| The LCO requires three Reactor Coolant Flow-Low channels per loop to be OPERABLE in MODE 1 above P-8.
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| 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.
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| : b. Reactor Coolant Flow-Low (Two Loops)
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| 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.
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| 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.
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| The flow signals are not used for any control system input.
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| The LCO requires three Reactor Coolant Flow-Low channels per loop to be OPERABLE.
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| 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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| Catawba Units 1 and 2 B 3.3.1-18 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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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.
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| The LCO requires a total of four Undervoltage RCPs channels (one per bus) to be OPERABLE.
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| 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.
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| : 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.
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| Time delays are incorporated into the Underfrequency RCPs channels to prevent reactor trips due to momentary electrical power transients.
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| Catawba Units 1 and 2 B 3.3.1-19 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| The LCO requires a total of four Underfrequency RCPs channels (one per bus) to be OPERABLE.
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| 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.
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| Above the P-7 setpoint, the reactor trip on loss of flow in two or more RCS loops is automatically enabled.
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| : 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.
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| 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.
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| 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.
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| 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 Catawba Units 1 and 2 B 3.3.1-20 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) accomplished by the steam generators in MODES 3 and 4 and by the Residual Heat Removal (RHR) System in Mode 4, 5, or 6.
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| : 14. Turbine Trip
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| : 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.
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| The LCO requires four channels of Turbine Trip-Low Fluid Oil Pressure to be OPERABLE in MODE 1 above P-9.
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| 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.
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| : 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 Catawba Units 1 and 2 B 3.3.1-21 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES 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.
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| The LSSS for this Function is set to assure channel trip occurs when the associated stop valve is completely closed.
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| 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.
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| 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.
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| : 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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| Catawba Units 1 and 2 B 3.3.1-22 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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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.
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| 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.
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| The LCO requires two trains of SI Input from ESFAS to be OPERABLE in MODE 1 or 2.
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| A reactor trip is initiated every time an SI signal is present.
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| 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.
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| : 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:
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| : 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:
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| Catawba Units 1 and 2 B 3.3.1-23 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES 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.
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| x on decreasing power, the P-6 interlock automatically enables the NIS Source Range Neutron Flux reactor trip.
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| 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.
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| 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.
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| 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.
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| : 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:
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| (1) on increasing power, the P-7 interlock automatically enables reactor trips on the following Functions:
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| x Pressurizer Pressure-Low; x Pressurizer Water Level-High; Catawba Units 1 and 2 B 3.3.1-24 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) x Reactor Coolant Flow-Low (Two Loops);
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| x Undervoltage RCPs; and x Underfrequency RCPs.
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| 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.
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| Below the P-7 setpoint, the RCS is capable of providing sufficient natural circulation without any RCP running.
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| (2) on decreasing power, the P-7 interlock automatically blocks reactor trips on the following Functions:
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| x Pressurizer Pressure-Low; x Pressurizer Water Level-High; x Reactor Coolant Flow-Low (Two Loops);
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| x Undervoltage RCPs; and x Underfrequency RCPs.
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| 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.
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| 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.
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| 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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| Catawba Units 1 and 2 B 3.3.1-25 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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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.
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| The LCO requires four channels of Power Range Neutron Flux, P-8 interlock to be OPERABLE in MODE 1.
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| 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.
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| : 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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| Catawba Units 1 and 2 B 3.3.1-26 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| The LCO requires four channels of Power Range Neutron Flux, P-9 interlock to be OPERABLE in MODE 1.
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| 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.
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| : 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:
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| 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; Catawba Units 1 and 2 B 3.3.1-27 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES 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).
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| The LCO requires four channels of Power Range Neutron Flux, P-10 interlock to be OPERABLE in MODE 1 or 2.
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| 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.
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| : 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.
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| The LCO requires two channels of Turbine Impulse Pressure, P-13 interlock to be OPERABLE in MODE 1.
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| 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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| Catawba Units 1 and 2 B 3.3.1-28 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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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.
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| 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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| : 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.
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| OPERABILITY of both trip mechanisms on each breaker ensures that no single trip mechanism failure will prevent opening any breaker on a valid signal.
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| 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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| Catawba Units 1 and 2 B 3.3.1-29 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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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.
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| 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.
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| 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.
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| The RTS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6).
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| 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.
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| 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 Catawba Units 1 and 2 B 3.3.1-30 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES SETPOINT calibration tolerance band and non-conservative with respect ACTIONS (continued) to the NOMINAL TRIP SETPOINT, the setpoint shall be re-adjusted.
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| 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.
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| 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.
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| 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 hours. In this Condition, the remaining OPERABLE channel is adequate to perform the safety function.
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| The Completion Time of 48 hours 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.
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| If the Manual Reactor Trip Function cannot be restored to OPERABLE status within the allowed 48 hour 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 hours 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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| Catawba Units 1 and 2 B 3.3.1-31 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)
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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:
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| x Manual Reactor Trip; x RTBs; x RTB Undervoltage and Shunt Trip Mechanisms; and x Automatic Trip Logic.
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| 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 hours. If the affected Function(s) cannot be restored to OPERABLE status within the allowed 48 hour 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.
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| 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.
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| 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 hours of THERMAL POWER exceeding 75% RTP and once per 12 hours thereafter.
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| Calculating QPTR every 12 hours 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 <
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| 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 hour 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 Catawba Units 1 and 2 B 3.3.1-32 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES by a Note which only requires SR 3.2.4.2 to be performed if the Catawba Units 1 and 2 B 3.3.1-33 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)
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| 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.
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| Condition D applies to the Power Range Neutron FluxHigh and Power Range Neutron Flux-High Positive Rate Functions.
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| 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 hours allowed to place the inoperable channel in the tripped condition is justified in WCAP-14333-P-A (Ref. 11).
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| As an alternative to the above Actions, the plant must be placed in a MODE where this Function is no longer required OPERABLE. 78 hours are allowed to place the plant in MODE 3. The 78 hour Completion Time includes 72 hours for channel corrective maintenance, and an additional 6 hours 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.
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| The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypass condition for up to 12 hours 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 hour time limit is justified in Reference 11.
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| Catawba Units 1 and 2 B 3.3.1-34 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)
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| E.1 and E.2 Condition E applies to the following reactor trip Functions:
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| x Power Range Neutron Flux-Low; x Overtemperature 'T; x Overpower 'T; x Pressurizer Pressure-High; and x SG Water Level-Low Low.
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| A known inoperable channel must be placed in the tripped condition within 72 hours. 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 hours allowed to place the inoperable channel in the tripped condition is justified in Reference 11.
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| 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 hours 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.
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| The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 12 hours while performing routine surveillance testing of the other channels. The 12 hour time limit is justified in Reference 11.
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| 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 Catawba Units 1 and 2 B 3.3.1-35 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES 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 hours 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.
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| 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.
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| 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.
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| The Completion Time of 2 hours 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.
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| Required Action G.1 is modified by a Note to indicate that normal plant control operations that individually add limited positive reactivity (e.g.,
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| temperature or boron fluctuations associated with RCS inventory management or temperature control) are not precluded by this Catawba Units 1 and 2 B 3.3.1-36 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)
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| Action.
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| 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.
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| 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.
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| 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.
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| 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.
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| Catawba Units 1 and 2 B 3.3.1-37 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)
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| 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 hours 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 hours to restore the channel to OPERABLE status, and the additional hour to open the RTBs, are justified in Reference 7.
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| L.1 and L.2 Condition L applies to the following reactor trip Functions:
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| x Pressurizer Pressure-Low; x Pressurizer Water Level-High; x Reactor Coolant Flow-Low (Two Loops);
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| x Undervoltage RCPs; and x Underfrequency RCPs.
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| With one channel inoperable, the inoperable channel must be placed in the tripped condition within 72 hours. 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).
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| 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 hours allowed to place the channel in the tripped Catawba Units 1 and 2 B 3.3.1-38 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES ACTIONS (continued) condition is justified in Reference 11. An additional 6 hours 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.
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| 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.
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| The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 12 hours while performing routine surveillance testing of the other channels. The 12 hour time limit is justified in Reference 11.
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| 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 hours. If the channel cannot be restored to OPERABLE status or the channel placed in trip within the 6 hours, then THERMAL POWER must be reduced below the P-8 setpoint within the next 4 hours. 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 hours 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.
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| The Required Actions have been modified by a Note that allows placing the inoperable channel in the bypassed condition for up to 4 hours while performing routine surveillance testing of the other channels. The 4 hour time limit is justified in Reference 7.
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| Catawba Units 1 and 2 B 3.3.1-39 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)
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| 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 hours. 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 hours. The 72 hours allowed to place the inoperable channel in the tripped condition and the 4 hours allowed for reducing power are justified in Reference 11.
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| 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 hours while performing routine surveillance testing of the other channels. The 12 hour time limit is justified in Reference 11.
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| 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 hours 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 hours.
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| The Completion Time of 24 hours (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 hours allowed to restore the inoperable RTS Automatic Trip Logic train to OPERABLE status is justified in Reference 11. The additional Completion Time of 6 hours (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.
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| The Required Actions have been modified by a Note that allows bypassing one train up to 4 hours for surveillance testing, provided the other train is OPERABLE. The 4 hour 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 hour time limit. The 4 hour time limit is justified in Reference 11.
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| Catawba Units 1 and 2 B 3.3.1-40 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)
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| 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 hours 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 hours. The 24 hour Completion Time is justified in Reference 12. The Completion Time of 6 hours 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.
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| The Required Actions have been modified by a Note. The Note allows one RTB to be bypassed for up to 4 hours for surveillance testing, provided the other RTB is OPERABLE. The 4 hour time limit is justified in Reference 12.
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| 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 hour or the unit must be placed in MODE 3 within the next 6 hours. Verifying the interlock status, by visual observation of the control room status lights, manually accomplishes the interlock's Function. The Completion Time of 1 hour is based on operating experience and the minimum amount of time allowed for manual operator actions. The Completion Time of 6 hours is reasonable, based on operating experience, to reach MODE 3 from full power in an orderly manner and without challenging unit systems. The 1 hour and 6 hour 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.
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| Catawba Units 1 and 2 B 3.3.1-41 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)
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| 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 hour or the unit must be placed in MODE 2 within the next 6 hours. 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 hour is based on operating experience and the minimum amount of time allowed for manual operator actions. The Completion Time of 6 hours is reasonable, based on operating experience, to reach MODE 2 from full power in an orderly manner and without challenging unit systems.
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| 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 hours 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 hours (54 hours total time). With both diverse trip features inoperable, the reactor trip breaker is inoperable and Condition Q is entered. The Completion Time of 6 hours 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.
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| The Completion Time of 48 hours 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.
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| Catawba Units 1 and 2 B 3.3.1-42 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES ACTIONS (continued)
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| 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.
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| SURVEILLANCE The SRs for each RTS Function are identified by the SRs column of REQUIREMENTS Table 3.3.1-1 for that Function.
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| A Note has been added to the SR Table stating that Table 3.3.1-1 determines which SRs apply to which RTS Functions.
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| 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.
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| 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.
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| 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.
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| 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.
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| The Surveillance Frequency is based on operating experience, equipment Catawba Units 1 and 2 B 3.3.1-43 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| 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
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| > 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.
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| 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 hours is allowed for completing the first Surveillance after reaching 15% RTP. At lower power levels, calorimetric data are inaccurate.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| 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.
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| Catawba Units 1 and 2 B 3.3.1-44 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| 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.
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| 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 hours is allowed for completing the first Surveillance after reaching 15% RTP.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| 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.
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| 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.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| 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.
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| Catawba Units 1 and 2 B 3.3.1-45 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| 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.
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| SR 3.3.1.6 SR 3.3.1.6 is a calibration of the excore channels to the incore channels.
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| 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.
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| 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.
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| At BOC, after reaching full power steady state conditions, additional incore and excore measurements are taken and excore detectors are adjusted as necessary.
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| 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.
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| 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 hours is allowed for completing the first surveillance after reaching 75% RTP.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.3.1.7 SR 3.3.1.7 is the performance of a COT.
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| Catawba Units 1 and 2 B 3.3.1-46 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES A COT is performed on each required channel to ensure the channel will Catawba Units 1 and 2 B 3.3.1-47 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued) perform the intended Function.
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| The tested portion of the loop must trip within the Allowable Values specified in Table 3.3.1-1.
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| The setpoint shall be left set consistent with the assumptions of the setpoint methodology.
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| SR 3.3.1.7 is modified by a Note that provides a 4 hour 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 hours this Surveillance must be completed within 4 hours after entry into MODE 3.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| 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.
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| 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.
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| 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 Catawba Units 1 and 2 B 3.3.1-48 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES 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.
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| 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 or 184 days of the Frequencies prior to reactor startup and four hours after reducing power below P-10 and P-6.
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| 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 hours after reducing power below P-10" (applicable to intermediate and power range low channels) and "4 hours 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.
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| Catawba Units 1 and 2 B 3.3.1-49 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| 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 hours, then the testing required by this surveillance must be performed prior to the expiration of the 4 hour 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-
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| : 6) for periods > 4 hours. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| 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.
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| 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.
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| 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.
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| SURVEILLANCE REQUIREMENTS (continued)
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| Catawba Units 1 and 2 B 3.3.1-50 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES 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.
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| 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.
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| 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.
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| CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the setpoint methodology.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| 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.
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| Catawba Units 1 and 2 B 3.3.1-51 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| 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.
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| Catawba Units 1 and 2 B 3.3.1-52 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| 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.
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| 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.
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| 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.
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| 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.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| Catawba Units 1 and 2 B 3.3.1-53 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.3.1.13 SR 3.3.1.13 is the performance of a COT of RTS interlocks.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| 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.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| The SR is modified by a Note that excludes verification of setpoints from the TADOT. The Functions affected have no setpoints associated with them.
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| SR 3.3.1.15 SR 3.3.1.15 is the performance of a TADOT of Turbine Trip Functions.
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| 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.
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| 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.
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| Catawba Units 1 and 2 B 3.3.1-54 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| 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.
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| 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.,
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| control and shutdown rods fully inserted in the reactor core).
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| 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.
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| 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.
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| 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.
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| Catawba Units 1 and 2 B 3.3.1-55 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| 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.
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| 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).
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| 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.
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| REFERENCES 1. UFSAR, Chapter 7.
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| : 2. UFSAR, Chapter 6.
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| : 3. UFSAR, Chapter 15.
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| : 4. IEEE-279-1971.
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| : 5. 10 CFR 50.49.
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| Catawba Units 1 and 2 B 3.3.1-56 Revision No. 10
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| RTS Instrumentation B 3.3.1 BASES REFERENCES (continued)
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| : 6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| : 7. WCAP-10271-P-A, Supplement 2, Rev. 1, June 1990.
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| : 8. WCAP-13632-P-A Revision 2, Elimination of Pressure Sensor Response Time Testing Requirements Sep., 1995.
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| : 9. WCAP-14036-P-A Revision 1, Elimination of Periodic Protection Channel Response Time Tests Oct., 1998.
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| 10.10 CFR 50.67.
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| 11.WCAP-14333-P-A, Rev. 1, October 1998.
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| 12.WCAP-15376-P-A, Rev. 1, March 2003.
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| : 13. Technical Specification Task Force, Improved Standard Technical Specifications Change Traveler, TSTF-493, Clarify Application of Setpoint Methodology for LSSS Functions Revision 4.
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| : 14. Attachment 1 to TSTF-569, Rev. 2, Methodology to Eliminate Pressure Sensor and Protection Channel (for Westinghouse Plants only) Response Time Testing.
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| Catawba Units 1 and 2 B 3.3.1-57 Revision No. 10
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| ESFAS Instrumentation B 3.3.2 B 3.3 INSTRUMENTATION B 3.3.2 Engineered Safety Feature Actuation System (ESFAS) Instrumentation BASES BACKGROUND The ESFAS initiates necessary safety systems, based on the values of selected unit parameters, to protect against violating core design limits and the Reactor Coolant System (RCS) pressure boundary, and to mitigate accidents.
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| The ESFAS instrumentation is segmented into three distinct but interconnected modules as identified below:
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| x Field transmitters or process sensors and instrumentation: provide a measurable electronic signal based on the physical characteristics of the parameter being measured; x Signal processing equipment including analog protection system, field contacts, and protection channel sets: provide signal conditioning, bistable setpoint comparison, process algorithm actuation, compatible electrical signal output to protection system devices, and control board/control room/miscellaneous indications; and x Solid State Protection System (SSPS) including input, logic, and output bays: initiates the proper unit shutdown or engineered safety feature (ESF) actuation in accordance with the defined logic and based on the bistable outputs from the signal process control and protection system.
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| 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. In many cases, field transmitters or sensors that input to the ESFAS are shared with the Reactor Trip System (RTS).
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| In some cases, the same channels also provide control system inputs.
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| To account for calibration tolerances and instrument drift, which is assumed to occur between calibrations, statistical allowances are Catawba Units 1 and 2 B 3.3.2-1 Revision No. 14
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| | |
| ESFAS Instrumentation B 3.3.2 BASES BACKGROUND (continued) 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.
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| Signal Processing Equipment 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, comparable 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 6 (Ref. 1), Chapter 7 (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.
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| 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.
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| 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.
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| These requirements are described in IEEE-279-1971 (Ref. 4). The actual number of channels required for each unit parameter is specified in the UFSAR.
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| Catawba Units 1 and 2 B 3.3.2-2 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES BACKGROUND (continued)
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| 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.
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| 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 ESFAS 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 before the Allowable Value is reached. The Allowable Value accounts for changes in random measurement errors detectable by a COT. One example of such a change in measurement error is drift during the surveillance interval. If the point at which the loop trips does not exceed the Allowable Value, the loop is considered OPERABLE.
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| A trip within the Allowable Value ensures that the consequences of Design Basis Accidents (DBAs) will be acceptable, providing the unit is operated from within the LCOs at the onset of the DBA and the equipment functions as designed.
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| Each channel can be tested on line to verify that the signal processing equipment and 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 SR section.
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| The determination of the NOMINAL TRIP SETPOINTS and Allowable Values listed in Table 3.3.2-1 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 for these channels are assumed to operate within the allowances of these uncertainty magnitudes.
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| Catawba Units 1 and 2 B 3.3.2-3 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES BACKGROUND (continued)
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| 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 ESF actuation for the unit. If both trains are taken out of service or placed in test, a reactor trip will result.
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| Each train is packaged in its own cabinet for physical and electrical separation to satisfy separation and independence requirements.
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| The SSPS performs the decision logic for most ESF equipment actuation; generates the electrical output signals that initiate the required actuation; and provides the status, permissive, and annunciator output signals to the main control room of the unit.
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| The bistable outputs from the signal processing equipment are sensed by the SSPS equipment and combined into logic matrices that represent combinations indicative of various transients. If a required logic matrix combination is completed, the system will 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 safe condition. Examples are given in the Applicable Safety Analyses, LCO, and Applicability sections of this Bases.
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| Each SSPS 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.
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| 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.
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| The actuation of ESF components is accomplished through master and slave relays. The SSPS energizes the master relays appropriate for the condition of the unit. Each master relay then energizes one or more slave relays, which then cause actuation of the end devices. The master and slave relays are routinely tested to ensure operation. The test of the master relays energizes the relay, which then operates the contacts and applies a low voltage to the associated slave relays. The low voltage is not sufficient to actuate the slave relays but only demonstrates signal Catawba Units 1 and 2 B 3.3.2-4 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES BACKGROUND (continued) path continuity. The SLAVE RELAY TEST actuates the devices if their operation will not interfere with continued unit operation. For the latter case, actual component operation is prevented by the SLAVE RELAY TEST circuit, and slave relay contact operation is verified by a continuity check of the circuit containing the slave relay.
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| APPLICABLE Each of the analyzed accidents can be detected by one or SAFETY ANALYSES, more ESFAS Functions. One of the ESFAS Functions is the LCO, AND primary actuation signal for that accident. An ESFAS Function APPLICABILITY may be the primary actuation signal for more than one type of accident.
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| An ESFAS Function may also be a secondary, or backup, actuation signal for one or more other accidents. For example, Pressurizer PressureLow is a primary actuation signal for small loss of coolant accidents (LOCAs) and a backup actuation signal for steam line breaks (SLBs) outside containment. Functions such as manual initiation, not specifically credited in the accident safety analysis, are qualitatively credited in the safety analysis and the NRC staff approved licensing basis for the unit. These Functions may provide protection for conditions that do not require dynamic transient analysis to demonstrate Function performance. These Functions may also serve as backups to Functions that were credited in the accident analysis (Ref. 3).
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| The LCO requires all instrumentation performing an ESFAS Function 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 and two channels in each logic and manual initiation function. The two-out-of-three and the two-out-of-four configurations allow one channel to be tripped during maintenance or testing without causing an ESFAS initiation. Two logic or manual initiation channels are required to ensure no single random failure disables the ESFAS.
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| The required channels of ESFAS instrumentation provide unit protection in the event of any of the analyzed accidents. ESFAS protection functions are as follows:
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| Catawba Units 1 and 2 B 3.3.2-5 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| : 1. Safety Injection Safety Injection (SI) provides two primary functions:
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| : 1. Primary side water addition to ensure maintenance or recovery of reactor vessel water level (coverage of the active fuel for heat removal, clad integrity, and for limiting peak clad temperature to < 2200qF); and
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| : 2. Boration to ensure recovery and maintenance of SDM (keff < 1.0).
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| These functions are necessary to mitigate the effects of high energy line breaks (HELBs) both inside and outside of containment.
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| The SI signal is also used to initiate other Functions such as:
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| x Phase A Isolation; x Containment Purge and Exhaust Isolation; x Reactor Trip; x Turbine Trip; x Feedwater Isolation; x Start of motor driven auxiliary feedwater (AFW) pumps; x Start of control room area ventilation filtration trains; x Enabling automatic switchover of Emergency Core Cooling Systems (ECCS) suction to containment sump; x Start of annulus ventilation system filtration trains; x Start of auxiliary building filtered ventilation exhaust system trains; x Start of diesel generators Catawba Units 1 and 2 B 3.3.2-6 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) x Start of nuclear service water system pumps; and x Start of component cooling water system pumps.
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| These other functions ensure:
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| x Isolation of nonessential systems through containment penetrations; x Trip of the turbine and reactor to limit power generation; x Isolation of main feedwater (MFW) to limit secondary side mass losses; x Start of AFW to ensure secondary side cooling capability; x Filtration of the control room to ensure habitability; x Enabling ECCS suction from the refueling water storage tank (RWST) switchover on low RWST level to ensure continued cooling via use of the containment sump; x Starting of annulus ventilation and auxiliary building filtered ventilation to limit offsite releases; x Starting of diesel generators for loss of offsite power considerations; and x Starting of component cooling water and nuclear service water systems for heat removal.
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| : a. Safety Injection-Manual Initiation The LCO requires two channels to be OPERABLE. The operator can initiate SI at any time by using either of two switches in the control room. This action will cause actuation of all components in the same manner as any of the automatic actuation signals.
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| The LCO for the Manual Initiation Function ensures the proper amount of redundancy is maintained in the manual ESFAS actuation circuitry to ensure the operator has manual ESFAS initiation capability.
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| Catawba Units 1 and 2 B 3.3.2-7 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| Each train consists of one push button and the interconnecting wiring to the actuation logic cabinet. This configuration does not allow testing at power.
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| : b. Safety Injection-Automatic Actuation Logic and Actuation Relays This LCO requires two trains to be OPERABLE. Actuation logic consists of all circuitry housed within the actuation subsystems, including the initiating relay contacts responsible for actuating the ESF equipment.
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| Manual and automatic initiation of SI must be OPERABLE in MODES 1, 2, and 3. In these MODES, there is sufficient energy in the primary and secondary systems to warrant automatic initiation of ESF systems. In MODE 4, adequate time is available to manually actuate required components in the event of a DBA, but because of the large number of components actuated on a SI, actuation is simplified by the use of the manual actuation push buttons. Automatic actuation logic and actuation relays must be OPERABLE in MODE 4 to support system level manual initiation.
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| These Functions are not required to be OPERABLE in MODES 5 and 6 because there is adequate time for the operator to evaluate unit conditions and respond by manually starting individual systems, pumps, and other equipment to mitigate the consequences of an abnormal condition or accident. Unit pressure and temperature are very low and many ESF components are administratively locked out or otherwise prevented from actuating to prevent inadvertent overpressurization of unit systems.
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| : c. Safety Injection-Containment Pressure-High This signal provides protection against the following accidents:
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| x SLB inside containment; x LOCA; and x Feed line break inside containment.
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| Catawba Units 1 and 2 B 3.3.2-8 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| Containment Pressure-High provides no input to any control functions. Thus, three OPERABLE channels are sufficient to satisfy protective requirements with a two-out-of-three logic.
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| Containment Pressure-High must be OPERABLE in MODES 1, 2, and 3 when there is sufficient energy in the primary and secondary systems to pressurize the containment following a pipe break. In MODES 4, 5, and 6, there is insufficient energy in the primary or secondary systems to pressurize the containment.
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| : d. Safety Injection-Pressurizer Pressure-Low This signal provides protection against the following accidents:
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| x Inadvertent opening of a steam generator (SG) relief or safety valve; x SLB; x A spectrum of rod cluster control assembly ejection accidents (rod ejection);
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| x Inadvertent opening of a pressurizer relief or safety valve; x LOCAs; and x SG Tube Rupture.
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| Pressurizer pressure provides both control and protection functions: input to the Pressurizer Pressure Control System, reactor trip, and SI. Therefore, the actuation logic must be able to withstand both an input failure to control system, which may then require the protection function actuation, and a single failure in the other channels providing the protection function actuation. Thus, four OPERABLE channels are required to satisfy the requirements with a two-out-of-four logic.
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| Catawba Units 1 and 2 B 3.3.2-9 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| This Function must be OPERABLE in MODES 1, 2, and 3 (above P-11) to mitigate the consequences of an HELB inside containment. This signal may be manually blocked by the operator below the P-11 setpoint. Automatic SI actuation below this pressure setpoint is then performed by the Containment Pressure-High signal.
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| This Function is not required to be OPERABLE in MODE 3 below the P-11 setpoint. Other ESF functions are used to detect accident conditions and actuate the ESF systems in this MODE. In MODES 4, 5, and 6, this Function is not needed for accident detection and mitigation.
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| : 2. Deleted.
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| : 3. Containment Isolation Containment Isolation provides isolation of the containment atmosphere, and all process systems that penetrate containment, from the environment. This Function is necessary to prevent or limit the release of radioactivity to the environment in the event of a large break LOCA.
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| There are two separate Containment Isolation signals, Phase A and Phase B. Phase A isolation isolates all automatically isolable process lines, except component cooling water (CCW) and nuclear service water system (NSWS), at a relatively low containment pressure indicative of primary or secondary system leaks. For these types of events, forced circulation cooling using the reactor coolant pumps (RCPs) and SGs is the preferred (but not required) method of decay heat removal. Since CCW and NSWS are required to support RCP operation, not isolating CCW and NSWS on the low pressure Phase A signal enhances unit safety by allowing operators to use forced RCS circulation to cool the unit.
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| Isolating CCW and NSWS on the low pressure signal may force the use of feed and bleed cooling, which could prove more difficult to control.
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| Catawba Units 1 and 2 B 3.3.2-10 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| Phase A containment isolation is actuated automatically by SI, or manually via the actuation circuitry. All process lines penetrating containment, with the exception of CCW and NSWS, are isolated.
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| CCW is not isolated at this time to permit continued operation of the RCPs with cooling water flow to the thermal barrier heat exchangers and air or oil coolers. All process lines not equipped with remote operated isolation valves are manually closed, or otherwise isolated, prior to reaching MODE 4.
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| Manual Phase A Containment Isolation is accomplished by either of two switches in the control room. Either switch actuates its associated train.
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| The Phase B signal isolates CCW and NSWS. This occurs at a relatively high containment pressure that is indicative of a large break LOCA or an SLB. For these events, forced circulation using the RCPs is no longer desirable. Isolating the CCW and NSWS at the higher pressure does not pose a challenge to the containment boundary because the CCW System and NSWS are closed loops inside containment. Although some system components do not meet all of the ASME Code requirements applied to the containment itself, the systems are continuously pressurized to a pressure greater than the Phase B setpoint. Thus, routine operation demonstrates the integrity of the system pressure boundary for pressures exceeding the Phase B setpoint.
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| Furthermore, because system pressure exceeds the Phase B setpoint, any system leakage prior to initiation of Phase B isolation would be into containment. Therefore, the combination of CCW System and NSWS design and Phase B isolation ensures there is not a potential path for radioactive release from containment.
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| Catawba Units 1 and 2 B 3.3.2-11 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
| |
| Phase B containment isolation is actuated by Containment Pressure-High High, or manually, via the automatic actuation logic, as previously discussed. For containment pressure to reach a value high enough to actuate Containment PressureHigh High, a large break LOCA or SLB must have occurred. RCP operation will no longer be required and CCW to the RCPs and NSWS to the RCP motor coolers are, therefore, no longer necessary. The RCPs can be operated with seal injection flow alone and without CCW flow to the thermal barrier heat exchanger.
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| Manual Phase B Containment Isolation is accomplished by pushbuttons on the main control board. In addition to manually initiating a Phase B Containment Isolation, the pushbuttons also isolate the containment ventilation system.
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| : a. Containment Isolation-Phase A Isolation (1) Phase A Isolation-Manual Initiation Manual Phase A Containment Isolation is actuated by either of two switches in the control room. Each switch actuates its respective train.
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| (2) Phase A Isolation-Automatic Actuation Logic and Actuation Relays Automatic Actuation Logic and Actuation Relays consist of the same features and operate in the same manner as described for ESFAS Function 1.b.
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| Manual and automatic initiation of Phase A Containment Isolation must be OPERABLE in MODES 1, 2, and 3, when there is a potential for an accident to occur. In MODE 4, adequate time is available to manually actuate required components in the event of a DBA, but because of the large number of components actuated on a Phase A Containment Isolation, actuation is simplified by the use of the manual actuation push buttons. Automatic actuation logic and actuation relays must be OPERABLE in MODE 4 to support Catawba Units 1 and 2 B 3.3.2-12 Revision No. 14
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| | |
| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) system level manual initiation. In MODES 5 and 6, there is insufficient energy in the primary or secondary systems to pressurize the containment to require Phase A Containment Isolation. There also is adequate time for the operator to evaluate unit conditions and manually actuate individual isolation valves in response to abnormal or accident conditions.
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| (3) Phase A Isolation-Safety Injection Phase A Containment Isolation is also initiated by all Functions that initiate SI. The Phase A Containment Isolation requirements for these Functions are the same as the requirements for their SI function.
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| Therefore, the requirements are not repeated in Table 3.3.2-1. Instead, Function 1, SI, is referenced for all initiating Functions and requirements.
| |
| : b. Containment Isolation-Phase B Isolation Phase B Containment Isolation is accomplished by manual Initiation, Automatic Actuation Logic and Actuation Relays, and by Containment Pressure channels. The Containment Pressure trip of Phase B Containment Isolation is energized to trip in order to minimize the potential of spurious trips that may damage the RCPs.
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| (1) Phase B Isolation-Manual Initiation (2) Phase B Isolation-Automatic Actuation Logic and Actuation Relays Manual and automatic initiation of Phase B containment isolation must be OPERABLE in MODES 1, 2, and 3, when there is a potential for an accident to occur. In MODE 4, adequate time is available to manually actuate required components in the event of a DBA. However, because of the large number of components actuated on a Phase B Catawba Units 1 and 2 B 3.3.2-13 Revision No. 14
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| | |
| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) containment isolation, actuation is simplified by the use of the manual actuation push buttons. Automatic actuation logic and actuation relays must be OPERABLE in MODE 4 to support system level manual initiation. In MODES 5 and 6, there is insufficient energy in the primary or secondary systems to pressurize the containment to require Phase B containment isolation. There also is adequate time for the operator to evaluate unit conditions and manually actuate individual isolation valves in response to abnormal or accident conditions.
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| (3) Phase B Isolation-Containment Pressure -
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| High-High Containment Pressure - High-High uses four channels in a two-out-of-four logic configuration. Since containment pressure is not used for control, this arrangement exceeds the minimum redundancy requirements. Additional redundancy is warranted because this Function is energize to trip.
| |
| Containment Pressure - High-High must be OPERABLE in MODES 1, 2, and 3 when there is sufficient energy in the primary and secondary sides to pressurize the containment following a pipe break.
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| In MODES 4, 5, and 6, there is insufficient energy in the primary and secondary sides to pressurize the containment and reach the Containment Pressure -
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| High-High setpoints.
| |
| : 4. Steam Line Isolation Isolation of the main steam lines provides protection in the event of an SLB inside or outside containment. Rapid isolation of the steam lines will limit the steam break accident to the blowdown from one SG, at most. For an SLB upstream of the main steam isolation valves (MSIVs), inside or outside of containment, closure of the MSIVs limits the accident to the blowdown from only the affected SG. For an SLB downstream of the MSIVs, closure of the MSIVs terminates the accident as soon as the steam lines depressurize.
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| Steam Line Isolation also mitigates the effects of a feed line break and ensures a source of steam for the turbine driven AFW pump during a feed line break.
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| Catawba Units 1 and 2 B 3.3.2-14 Revision No. 14
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| | |
| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
| |
| : a. Steam Line Isolation-Manual Initiation Manual initiation of Steam Line Isolation can be accomplished from the control room. There are two system level switches in the control room and either switch can initiate action to immediately close all MSIVs. The LCO requires two channels to be OPERABLE. Individual valves may also be closed using individual hand switches in the control room. The LCO requires four individual channels to be OPERABLE.
| |
| : b. Steam Line Isolation-Automatic Actuation Logic and Actuation Relays Automatic actuation logic and actuation relays consist of the same features and operate in the same manner as described for ESFAS Function 1.b.
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| Manual and automatic initiation of steam line isolation must be OPERABLE in MODES 1, 2, and 3 when there is sufficient energy in the RCS and SGs to have an SLB or other accident. This could result in the release of significant quantities of energy and cause a cooldown of the primary system. The Steam Line Isolation Function is required in MODES 2 and 3 unless all MSIVs are closed and de-activated. In MODES 4, 5, and 6, there is insufficient energy in the RCS and SGs to experience an SLB or other accident releasing significant quantities of energy.
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| : c. Steam Line Isolation-Containment Pressure-High High This Function actuates closure of the MSIVs in the event of a LOCA or an SLB inside containment to maintain three unfaulted SGs as a heat sink for the reactor, and to limit the mass and energy release to containment. Containment Pressure-High High uses four channels in a two-out-of-four logic configuration. Since containment pressure is not used for control, this arrangement exceeds the minimum redundancy requirements. Additional redundancy is warranted because this Function is energize to trip.
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| Containment Pressure-High High must be OPERABLE in MODES 1, 2, and 3, when there is sufficient energy in the primary and secondary side to pressurize the containment following a pipe break. This would cause a significant increase in the containment pressure, thus allowing detection Catawba Units 1 and 2 B 3.3.2-15 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) and closure of the MSIVs. The Steam Line Isolation Function remains OPERABLE in MODES 2 and 3 unless all MSIVs are closed and de-activated. In MODES 4, 5, and 6, there is not enough energy in the primary and secondary sides to pressurize the containment to the Containment Pressure-High High setpoint.
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| : d. Steam Line Isolation-Steam Line Pressure Steam Line Pressure channels provide both protection and control functions. The protection functions include: Steam Line Pressure-Low and Steam Line Pressure-Negative Rate functions. The control functions include: Digital Feedwater Control System (DFCS) which controls SG level.
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| (1) Steam Line Pressure-Low Steam Line PressureLow provides closure of the MSIVs in the event of an SLB to maintain three unfaulted SGs as a heat sink for the reactor, and to limit the mass and energy release to containment.
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| This Function provides closure of the MSIVs in the event of a feed line break to ensure a supply of steam for the turbine driven AFW pump.
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| DFCS receives steam pressure inputs from three separate protection channels for each SG. The three inputs are median selected for each SG, with the resultant output being used by the automatic control algorithm. The median select feature prevents the failure of an input signal from affecting the control system. A loss of two or more input signals will place the control system in manual and alert the operator.
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| DFCS will maintain a steady control function during the switch to manual operation; therefore, a failure of one or more input signals will not cause a control system action that would result in a condition requiring protective actions. Thus, three OPERABLE channels on each steam line, with a two-out-of-three logic on each steam line, are sufficient to satisfy protective requirements.
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| Steam Line Pressure-Low Function must be OPERABLE in MODES 1, 2, and 3 (above P-11), with any main steam valve open, when a secondary side Catawba Units 1 and 2 B 3.3.2-16 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) break or stuck open valve could result in the rapid depressurization of the steam lines. This signal may be manually blocked by the operator below the P-11 setpoint. Below P-11, an inside containment SLB will be terminated by automatic actuation via Containment Pressure-High High. Stuck valve transients and outside containment SLBs will be terminated by the Steam Line Pressure-Negative Rate-High signal for Steam Line Isolation below P-11 when SI has been manually blocked. The Steam Line Isolation Function is required in MODES 2 and 3 unless all MSIVs are closed and de-activated. This Function is not required to be OPERABLE in MODES 4, 5, and 6 because there is insufficient energy in the secondary side of the unit to have an accident.
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| (2) Steam Line Pressure-Negative Rate-High Steam Line Pressure-Negative Rate-High provides closure of the MSIVs for an SLB when less than the P-11 setpoint, to maintain at least one unfaulted SG as a heat sink for the reactor, and to limit the mass and energy release to containment. When the operator manually blocks the Steam Line Pressure-Low main steam isolation signal when less than the P-11 setpoint, the Steam Line Pressure-Negative Rate-High signal is automatically enabled. DFCS receives steam pressure inputs from three separate protection channels for each SG. The three inputs are median selected for each SG, with the resultant output being used by the automatic control algorithm.
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| The median select feature prevents the failure of an input signal from affecting the control system. A loss of two or more input signals will place the control system in manual and alert the operator. DFCS will maintain a steady control function during the switch to manual operation; therefore, a failure of one or more input signals will not cause a control system action that would result in a condition requiring protective actions. Thus, three OPERABLE channels on each steam line, with a two-out-of-three logic on each steam line, are sufficient to satisfy protective requirements.
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| Catawba Units 1 and 2 B 3.3.2-17 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| Steam Line Pressure-Negative Rate-High must be OPERABLE in MODE 3 when less than the P-11 setpoint, when a secondary side break or stuck open valve could result in the rapid depressurization of the steam line(s). In MODES 1 and 2, and in MODE 3, when above the P-11 setpoint, this signal is automatically disabled and the Steam Line Pressure-Low signal is automatically enabled. The Steam Line Isolation Function is required to be OPERABLE in MODES 2 and 3 unless all MSIVs are closed and de-activated. In MODES 4, 5, and 6, there is insufficient energy in the primary and secondary sides to have an SLB or other accident that would result in a release of significant enough quantities of energy to cause a cooldown of the RCS.
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| : 5. Turbine Trip and Feedwater Isolation The primary functions of the Turbine Trip and Feedwater Isolation signals are to prevent damage to the turbine due to water in the steam lines, stop the excessive flow of feedwater into the SGs, and to limit the energy released into containment. These Functions are necessary to mitigate the effects of a high water level in the SGs, which could result in carryover of water into the steam lines and excessive cooldown of the primary system. The SG high water level is due to excessive feedwater flows. Feedwater Isolation serves to limit the energy released into containment upon a feedwater line or steam line break inside containment.
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| The Functions are actuated when the level in any SG exceeds the high high setpoint, and performs the following functions:
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| x Trips the main turbine; x Trips the MFW pumps; x Initiates feedwater isolation; and x Shuts the MFW regulating valves and the bypass feedwater regulating valves.
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| Turbine Trip and Feedwater Isolation signals are both actuated by SG Water Level-High High, or by an SI signal. The RTS also initiates a turbine trip signal whenever a reactor trip (P-4) is Catawba Units 1 and 2 B 3.3.2-18 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) generated. A Feedwater Isolation signal is also generated by a reactor trip (P-4) coincident with Tavg-Low and on a high water level in the reactor building doghouse. The MFW System is also taken out of operation and the AFW System is automatically started. The SI signal was discussed previously.
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| : a. Turbine Trip (1) Turbine Trip-Automatic Actuation Logic and Actuation Relays Automatic Actuation Logic and Actuation Relays consist of the same features and operate in the same manner as described for ESFAS Function 1.b.
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| (2) Turbine Trip-Steam Generator Water Level-High High (P-14)
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| This signal prevents damage to the turbine due to water in the steam lines. The ESFAS SG water level instruments provide input to the SG Water Level Control System. Therefore, the actuation logic 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.
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| Thus, four OPERABLE channels are required to satisfy the requirements with a two-out-of-four logic.
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| The setpoints are based on percent of narrow range instrument span.
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| (3) Turbine Trip-Safety Injection Turbine Trip is also initiated by all Functions that initiate SI. Therefore, the requirements are not repeated in Table 3.3.2-1. Instead Function 1, SI, is referenced for all initiating functions and requirements. Item 5.a.(1) is referenced for the applicable MODES.
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| The Turbine Trip Function must be OPERABLE in MODES 1 and 2. In lower MODES, the turbine generator is not in service and this Function is not required to be OPERABLE.
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| : b. Feedwater Isolation Catawba Units 1 and 2 B 3.3.2-19 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| (1) Feedwater Isolation-Automatic Actuation Logic and Actuation Relays Automatic Actuation Logic and Actuation Relays consist of the same features and operate in the same manner as described for ESFAS Function 1.b.
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| (2) Feedwater Isolation-Steam Generator Water Level-High High (P-14)
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| This signal provides protection against excessive feedwater flow. The ESFAS SG water level instruments provide input to the SG Water Level Control System. Therefore, the actuation logic 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.
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| Thus, four OPERABLE channels are required to satisfy the requirements with a two-out-of-four logic.
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| The setpoints are based on percent of narrow range instrument span.
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| (3) Feedwater Isolation-Safety Injection Feedwater Isolation is also initiated by all Functions that initiate SI. The Feedwater Isolation Function requirements for these Functions are the same as the requirements for their SI function. Therefore, the requirements are not repeated in Table 3.3.2-1.
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| Instead Function 1, SI, is referenced for all initiating functions and requirements. Item 5.b.(1) is referenced for the applicable MODES.
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| (4) Feedwater Isolation - RCS Tavg- Low coincident with Reactor Trip (P-4)
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| This signal provides protection against excessive cooldown, which could subsequently introduce a positive reactivity excursion after a plant trip. There are four channels of RCS Tavg - Low (one per loop),
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| with a two-out-of-four logic required coincident with a reactor trip signal (P-4) to initiate a feedwater isolation. The P-4 interlock is discussed in Function 8.a.
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| Catawba Units 1 and 2 B 3.3.2-20 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| (5) Feedwater Isolation - Doghouse Water Level - High High This signal initiates a Feedwater Isolation. The signal terminates forward feedwater flow in the event of a postulated pipe break in the main feedwater piping in the doghouses to prevent flooding safety related equipment essential to the safe shutdown of the plant. Each doghouse contains two trains of level instrumentation. The level instrumentation consists of six level switches (three per train) in each of the two reactor building doghouses. A high-high level detected by two-out-of-three switches, in either the inboard or outboard doghouse, will initiate a doghouse isolation. This signal initiates Feedwater Isolation for the specific doghouse where the High-High level is detected and trips both main feedwater pumps thus causing a main turbine trip.
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| The Feedwater Isolation Function must be OPERABLE in MODES 1 and 2 and also in MODE 3 (except for the functions listed in Table 3.3.2-1). Feedwater Isolation is not required OPERABLE when all MFIVs, MFCVs, and associated bypass valves are closed and de-activated or isolated by a closed manual valve. In lower MODES, the MFW System is not in service and this Function is not required to be OPERABLE.
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| : 6. Auxiliary Feedwater The AFW System is designed to provide a secondary side heat sink for the reactor in the event that the MFW System is not available.
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| The system has two motor driven pumps and a turbine driven pump, making it available during normal and accident operation.
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| The normal source of water for the AFW System is the condensate storage system (not safety related). A low suction pressure to the AFW pumps will automatically realign the pump suctions to the Nuclear Service Water System (NSWS)(safety related). The AFW System is aligned so that upon a pump start, flow is initiated to the respective SGs immediately.
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| : a. Auxiliary Feedwater-Automatic Actuation Logic and Actuation Relays Automatic actuation logic and actuation relays consist of the Catawba Units 1 and 2 B 3.3.2-21 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) same features and operate in the same manner as described for ESFAS Function 1.b.
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| : b. Auxiliary Feedwater-Steam Generator Water Level-Low Low SG Water Level-Low Low provides protection against a loss of heat sink. A feed line break, inside or outside of containment, or a loss of MFW, would result in a loss of SG water level. SG Water Level-Low Low provides input to the SG Level Control System. Therefore, the actuation logic must be able to withstand both an input failure to the control system which may then require a protection function actuation and a single failure in the other channels providing the protection function actuation. Thus, four OPERABLE channels are required to satisfy the requirements with two-out-of-four logic. The setpoints are based on percent of narrow range instrument span.
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| SG Water LevelLow Low in any operating SG will cause the motor driven AFW pumps to start. The system is aligned so that upon a start of the pump, water immediately begins to flow to the SGs. SG Water LevelLow Low in any two operating SGs will cause the turbine driven pumps to start.
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| : c. Auxiliary FeedwaterSafety Injection An SI signal starts the motor driven AFW pumps. The AFW initiation functions are the same as the requirements for their SI function. Therefore, the requirements are not repeated in Table 3.3.2-1. Instead, Function 1, SI, is referenced for all initiating functions and requirements.
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| : d. Auxiliary Feedwater-Loss of Offsite Power A loss of offsite power to the service buses will be accompanied by a loss of reactor coolant pumping power and the subsequent need for some method of decay heat removal. The loss of offsite power is detected by a voltage drop on each essential service bus. Loss of power to either essential service bus will start the turbine driven and motor driven AFW pumps to ensure that at least two SGs contain enough water to serve as the heat sink for reactor decay heat and sensible heat removal following the reactor trip.
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| Catawba Units 1 and 2 B 3.3.2-22 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| Functions 6.a through 6.d must be OPERABLE in MODES 1, 2, and 3 to ensure that the SGs remain the heat sink for the reactor.
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| These Functions do not have to be OPERABLE in MODES 5 and 6 because there is not enough heat being generated in the reactor to require the SGs as a heat sink. In MODE 4, AFW actuation does not need to be OPERABLE because either AFW or residual heat removal (RHR) will already be in operation to remove decay heat or sufficient time is available to manually place either system in operation.
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| : e. Auxiliary Feedwater-Trip of All Main Feedwater Pumps A Trip of all MFW pumps is an indication of a loss of MFW and the subsequent need for some method of decay heat and sensible heat removal to bring the reactor back to no load temperature and pressure. Each turbine driven MFW pump is equipped with three pressure switches on the trip oil system. A low pressure signal from two-out-of-three of these pressure switches indicates a trip of that pump. Three OPERABLE channels per pump satisfy redundancy requirements with two-out-of-three logic. A trip of all MFW pumps starts the motor driven AFW pumps to ensure that at least two SGs are available with water to act as the heat sink for the reactor. This function must be OPERABLE in MODES 1 and 2. This ensures that at least two SGs are provided with water to serve as the heat sink to remove reactor decay heat and sensible heat in the event of an accident. In MODES 3, 4, and 5, the MFW pumps may be normally shut down, and thus neither pump trip is indicative of a condition requiring automatic AFW initiation.
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| : f. Auxiliary Feedwater-Pump Suction Transfer on Suction Pressure-Low A low pressure signal in the AFW pump suction line protects the AFW pumps against a loss of the normal supply of water for the pumps, the condensate storage system. Three pressure switches per train are located on the AFW pump suction line from the condensate storage system. A low pressure signal sensed by two-out-of-three switches will align their train related motor driven AFW pump and the turbine driven AFW pump to the assured water supply (NSWS). The NSWS (safety grade) is then lined up to supply the AFW pumps to ensure an adequate supply of water for the AFW Catawba Units 1 and 2 B 3.3.2-23 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| System to maintain at least two of the SGs as the heat sink for reactor decay heat and sensible heat removal.
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| This Function must be OPERABLE in MODES 1, 2, and 3 to ensure a safety grade supply of water for the AFW System to maintain the SGs as the heat sink for the reactor. This Function does not have to be OPERABLE in MODES 5 and 6 because there is not enough heat being generated in the reactor to require the SGs as a heat sink. In MODE 4, AFW automatic suction transfer does not need to be OPERABLE because RHR will already be in operation, or sufficient time is available to place RHR in operation, to remove decay heat.
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| : 7. Automatic Switchover to Containment Sump At the end of the injection phase of a LOCA, the RWST will be nearly empty. Continued cooling must be provided by the ECCS to remove decay heat. The source of water for the ECCS pumps is automatically switched to the containment recirculation sump. The low head residual heat removal (RHR) pumps and containment spray pumps draw the water from the containment recirculation sump, the RHR pumps pump the water through the RHR heat exchanger, inject the water back into the RCS, and supply the cooled water to the other ECCS pumps. Switchover from the RWST to the containment sump must occur before the RWST empties to prevent damage to the RHR pumps and a loss of core cooling capability.
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| : a. Automatic Switchover to Containment Sump-Automatic Actuation Logic and Actuation Relays Automatic actuation logic and actuation relays consist of the same features and operate in the same manner as described for ESFAS Function 1.b.
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| : b. Automatic Switchover to Containment Sump-Refueling Water Storage Tank (RWST)
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| Level-Low Coincident With Safety Injection During the injection phase of a LOCA, the RWST is the source of water for all ECCS pumps. A low level in the RWST coincident with an SI signal provides protection against a loss of water for the ECCS pumps and indicates the end of the injection phase of the LOCA. The RWST is equipped with four level transmitters. These transmitters Catawba Units 1 and 2 B 3.3.2-24 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) provide no control functions. Since an inadvertent switchover to the containment sump could have a significant safety impact, this instrumentation is placed in a bypass condition for testing. Therefore, four channels are supplied such that, during testing, the remaining three channels could perform the intended function, and no single failure could result in either a failure to accomplish the intended function, or in an inadvertent switchover to the containment sump.
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| Automatic switchover occurs only if the RWST low level signal is coincident with SI. This prevents accidental switchover during normal operation. Accidental switchover could damage ECCS pumps if they are attempting to take suction from an empty sump. The automatic switchover Function requirements for the SI Functions are the same as the requirements for their SI function. Therefore, the requirements are not repeated in Table 3.3.2-1. Instead, Function 1, SI, is referenced for all initiating Functions and requirements.
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| These Functions must be OPERABLE in MODES 1, 2, 3, and 4 when there is a potential for a LOCA to occur, to ensure a continued supply of water for the ECCS pumps.
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| These Functions are not required to be OPERABLE in MODES 5 and 6 because there is adequate time for the operator to evaluate unit conditions and respond by manually starting systems, pumps, and other equipment to mitigate the consequences of an abnormal condition or accident. System pressure and temperature are very low and many ESF components are administratively locked out or otherwise prevented from actuating to prevent inadvertent overpressurization of unit systems.
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| : 8. Engineered Safety Feature Actuation System Interlocks To allow some flexibility in unit operations, several interlocks are included as part of the ESFAS. These interlocks permit the operator to block some signals, automatically enable other signals, prevent some actions from occurring, and cause other actions to occur. The interlock Functions back up manual actions to ensure bypassable functions are in operation under the conditions assumed in the safety analyses.
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| Catawba Units 1 and 2 B 3.3.2-25 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| : a. Engineered Safety Feature Actuation System InterlocksReactor Trip, P-4 The P-4 interlock is enabled when a reactor trip breaker (RTB) and its associated bypass breaker is open. Operators are able to reset SI 60 seconds after initiation. If a P-4 is present when SI is reset, subsequent automatic SI initiations will be blocked until the RTBs have been manually closed.
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| This Function allows operators to take manual control of SI systems after the initial phase of injection is complete while avoiding multiple SI initiations.
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| The functions of the P-4 interlock are:
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| Function Required MODE x Trip the main 1, 2 turbine x Isolate MFW with coincident 1, 2, 3 low Tavg x Prevent reactuation of SI 1, 2, 3 after a manual reset of SI x Transfer the steam dump from the load rejection None controller to the unit trip controller; and x Prevent opening of the MFW isolation valves if they were closed 1, 2, 3 on SI or SG Water Level -
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| High High Each of the above functions is interlocked with P-4 to avert or reduce the continued cooldown of the RCS following a reactor trip. A reactor trip from MODE 1 or 2 could result in an excessive cooldown of the RCS that could cause an insertion of positive reactivity with a subsequent increase in Catawba Units 1 and 2 B 3.3.2-26 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued) generated power. To avoid such a situation, the noted functions have been interlocked with P-4 as part of the design of the unit control and protection system.
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| The RTB position switches that provide input to the P-4 interlock only function to energize or de-energize or open or close contacts. Therefore, this Function has no adjustable trip setpoint with which to associate a Trip Setpoint and Allowable Value.
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| This Function does not have to be OPERABLE in MODE 4, 5, or 6 because the main turbine, the MFW System, and the Steam Dump System are not in operation.
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| : b. Engineered Safety Feature Actuation System Interlocks-Pressurizer Pressure, P-11 The P-11 interlock permits a normal unit cooldown and depressurization without actuation of SI or main steam line isolation. With two-out-of-three pressurizer pressure channels (discussed previously) less than the P-11 setpoint, the operator can manually block the Pressurizer Pressure-Low SI signal and the Steam Line Pressure-Low steam line isolation signal (previously discussed). When the Steam Line Pressure-Low steam line isolation signal is manually blocked, a main steam isolation signal on Steam Line Pressure-Negative Rate-High is enabled. This provides protection for an SLB by closure of the MSIVs. With two-out-of-three pressurizer pressure channels above the P-11 setpoint, the Pressurizer Pressure-Low SI signal and the Steam Line Pressure-Low steam line isolation signal are automatically enabled. The operator can also enable these trips by use of the respective manual reset buttons. When the Steam Line Pressure-Low steam line isolation signal is enabled, the main steam isolation on Steam Line Pressure-Negative Rate High is disabled.
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| This Function must be OPERABLE in MODES 1, 2, and 3 to allow an orderly cooldown and depressurization of the unit without the actuation of SI or main steam isolation. This Function does not have to be OPERABLE in MODE 4, 5, or 6 because system pressure must already be below the P-11 setpoint for the requirements of the heatup and cooldown curves to be met.
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| Catawba Units 1 and 2 B 3.3.2-27 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| : c. Engineered Safety Feature Actuation System Interlocks-Tavg-Low Low, P-12 On increasing reactor coolant temperature, the P-12 interlock provides an arming signal to the Steam Dump System. On a decreasing temperature, the P-12 interlock removes the arming signal to the Steam Dump System to prevent an excessive cooldown of the RCS due to a malfunctioning Steam Dump System.
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| Since Tavg is used as an indication of bulk RCS temperature, this Function meets redundancy requirements with one OPERABLE channel in each loop. These channels are used in two-out-of-four logic. This Function must be OPERABLE in MODES 1, 2, and 3 when a secondary side break or stuck open valve could result in the rapid depressurization of the steam lines. This Function does not have to be OPERABLE in MODE 4, 5, or 6 because there is insufficient energy in the secondary side of the unit to have an accident.
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| Catawba Units 1 and 2 B 3.3.2-28 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| : 9. Containment Pressure Control System Permissives The Containment Pressure Control System (CPCS) protects the Containment Building from excessive depressurization by preventing inadvertent actuation or continuous operation of the Containment Spray and Containment Air Return Systems when containment pressure is at or less than the CPCS permissive setpoint. The control scheme of CPCS is comprised of eight independent control circuits (4 per train), each having a separate and independent pressure transmitter and current alarm module.
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| Each pressure transmitter monitors the containment pressure and provides input to its respective current alarm. The current alarms are set to inhibit or terminate containment spray and containment air return systems when containment pressure falls to or below 0.25 psid. The alarm modules switch back to the permissive state (allowing the systems to operate) when containment pressure is greater than or equal to 1.0 psid.
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| This function must be OPERABLE in MODES 1, 2, 3, and 4 when there is sufficient energy in the primary and secondary sides to pressurize containment following a pipe break. In MODES 5 and 6, there is insufficient energy in the primary and secondary sides to significantly pressurize the containment.
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| : 10. Nuclear Service Water System Suction Transfer - Low Pit Level Upon an emergency low pit level signal from either NSWS pit, interlocks isolate the NSWS from Lake Wylie, align NSWS to the standby nuclear service water pond, close particular crossover valves, and start the NSWS pumps. This function is initiated on a two-out-of-three logic from either NSWS pump pit.
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| This function must be OPERABLE in MODES 1, 2, 3, and 4 to ensure cooling water remains available to essential components during a DBA. In MODES 5 and 6, the sufficient time exists for manual operator action to realign the NSWS pump suction, if required.
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| Catawba Units 1 and 2 B 3.3.2-29 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES APPLICABLE SAFETY ANALYSES, LCO, and APPLICABILITY (continued)
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| Unlike other shared NSWS equipment, the pit level interlocks do not require both normal and emergency power for OPERABILITY.
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| This is because unlike mechanical components such as pumps and valves, the interlocks are designed to fail safe upon a loss of power, initiating a transfer from Lake Wylie to the standby nuclear service water pond. The definition of OPERABILITY, which requires either normal or emergency power, provides sufficient power supply requirements and these interlocks can be considered OPERABLE provided they are powered from either an inverter or regulated power.
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| The ESFAS instrumentation satisfies Criterion 3 of 10 CFR 50.36 (Ref. 6).
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| ACTIONS A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed on Table 3.3.2-1. When the Required Channels in Table 3.3.2-1 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.
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| 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. 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 to the NOMINAL TRIP SETPOINT, the setpoint shall be re-adjusted.
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| Catawba Units 1 and 2 B 3.3.2-30 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)
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| 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 should be immediately entered if applicable in the current MODE of operation.
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| A.1 Condition A applies to all ESFAS protection functions.
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| Condition A addresses the situation where one or more channels or trains for one or more Functions are inoperable at the same time. The Required Action is to refer to Table 3.3.2-1 and to take the Required Actions for the protection functions affected. The Completion Times are those from the referenced Conditions and Required Actions.
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| B.1, B.2.1 and B.2.2 Condition B applies to manual initiation of:
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| x SI; x Containment Spray; x Phase A Isolation; and x Phase B Isolation.
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| This action addresses the train orientation of the SSPS for the functions listed above. If a channel or train is inoperable, 48 hours is allowed to return it to an OPERABLE status. Note that for containment spray and Phase B isolation, failure of one or both channels in one train renders the train inoperable. Condition B, therefore, encompasses both situations.
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| The specified Completion Time is reasonable considering that there are two automatic actuation trains and another manual initiation train OPERABLE for each Function, and the low probability of an event occurring during this interval. If the train cannot be restored to OPERABLE status, the unit must be placed in a MODE in which the LCO does not apply. This is done by placing the unit in at least MODE 3 within an additional 6 hours (54 hours total time) and in MODE 5 within an additional 30 hours (84 hours total time). The allowable 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.
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| Catawba Units 1 and 2 B 3.3.2-31 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)
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| C.1, C.2.1 and C.2.2 Condition C applies to the automatic actuation logic and actuation relays for the following functions:
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| x SI; x Phase A Isolation; x Phase B Isolation; and x Automatic Switchover to Containment Sump.
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| This action addresses the train orientation of the SSPS and the master and slave relays. If one train is inoperable, 24 hours are allowed to restore the train to OPERABLE status. The 24 hours allowed for restoring the inoperable train to OPERABLE status is justified in Reference 13. The specified Completion Time is reasonable considering that there is another train OPERABLE, and the low probability of an event occurring during this interval. If the train cannot be restored to OPERABLE status, the unit must be placed in a MODE in which the LCO does not apply. This is done by placing the unit in at least MODE 3 within an additional 6 hours (30 hours total time) and in MODE 5 within an additional 30 hours (60 hours total time). The Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
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| The Required Actions are modified by a Note that allows one train to be bypassed for up to 4 hours for surveillance testing, provided the other train is OPERABLE. The Required Actions are not required to be met during this time, unless the train is discovered inoperable during the testing. This allowance is based on the reliability analysis assumption of WCAP-10271-P-A (Ref. 7) that 4 hours is the average time required to perform train surveillance.
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| Catawba Units 1 and 2 B 3.3.2-32 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)
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| D.1, D.2.1, and D.2.2 Condition D applies to:
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| x Containment Pressure-High; x Pressurizer Pressure-Low; x Steam Line Pressure-Low; x Steam Line Pressure-Negative Rate-High; x Loss of offsite power (refer to Condition D footnote);
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| x SG Water levelLow Low; and x SG Water levelHigh High (P-14) for the Feedwater Isolation Function.
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| If one channel is inoperable, 72 hours are allowed to restore the channel to OPERABLE status or to place it in the tripped condition. Generally this Condition applies to functions that operate on two-out-of-three logic.
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| Therefore, failure of one channel places the Function in a two-out-of-two configuration. One channel must be tripped to place the Function in a one-out-of-two configuration that satisfies redundancy requirements. The 72 hours allowed to restore the channel to OPERABLE status or to place it in the tripped condition is justified in Reference 13.
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| Failure to restore the inoperable channel to OPERABLE status or place it in the tripped condition within 72 hours requires the unit be placed in MODE 3 within the following 6 hours and MODE 4 within the next 6 hours.
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| 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. In MODE 4, these Functions are no longer required OPERABLE.
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| The Required Actions are modified by a Note that allows the inoperable channel to be bypassed for up to 12 hours for surveillance testing of other channels. The 12 hours allowed for testing is justified in Reference 13.
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| Catawba Units 1 and 2 B 3.3.2-33 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)
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| E.1, E.2.1, and E.2.2 Condition E applies to:
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| x Containment Phase B Isolation Containment Pressure-High High; and x Steam Line Isolation Containment Pressure - High High.
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| Neither of these signals has input to a control function. Thus, two-out-of-three logic is necessary to meet acceptable protective requirements.
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| However, a two-out-of-three design would require tripping a failed channel. This is undesirable because a single failure would then cause spurious isolation initiation. Therefore, these channels are designed with two-out-of-four logic so that a failed channel may be bypassed rather than tripped. Note that one channel may be bypassed and still satisfy the single failure criterion. Furthermore, with one channel bypassed, a single instrumentation channel failure will not spuriously initiate isolation.
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| To avoid the inadvertent actuation of Phase B containment isolation, the inoperable channel should not be placed in the tripped condition. Instead it is bypassed. Restoring the channel to OPERABLE status, or placing the inoperable channel in the bypass condition within 72 hours, is sufficient to assure that the Function remains OPERABLE and minimizes the time that the Function may be in a partial trip condition (assuming the inoperable channel has failed high). The Completion Time is further justified based on the low probability of an event occurring during this interval. Failure to restore the inoperable channel to OPERABLE status, or place it in the bypassed condition within 72 hours, requires the unit be placed in MODE 3 within the following 6 hours and MODE 4 within the next 6 hours. 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. In MODE 4, these Functions are no longer required OPERABLE.
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| The Required Actions are modified by a Note that allows one additional channel to be bypassed for up to 12 hours for surveillance testing.
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| Placing a second channel in the bypass condition for up to 12 hours for testing purposes is acceptable based on the results of Reference 13.
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| Catawba Units 1 and 2 B 3.3.2-34 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)
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| F.1, F.2.1, and F.2.2 Condition F applies to:
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| x Manual Initiation of Steam Line Isolation; and x P-4 Interlock.
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| For the Manual Initiation and the P-4 Interlock Functions, this action addresses the train orientation of the SSPS. If a train or channel is inoperable, 48 hours is allowed to return it to OPERABLE status. The specified Completion Time is reasonable considering the nature of these Functions, the available redundancy, and the low probability of an event occurring during this interval. If the Function cannot be returned to OPERABLE status, the unit must be placed in MODE 3 within the next 6 hours and MODE 4 within the following 6 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required unit conditions from full power in an orderly manner and without challenging unit systems. In MODE 4, the unit does not have any analyzed transients or conditions that require the explicit use of the protection functions noted above.
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| G.1 and G.2 Condition G applies to manual initiation of Steam Line Isolation.
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| This action addresses the operability of the manual steam line isolation function for each individual main steam isolation valve. If a channel is inoperable, 48 hours is allowed to return it to an OPERABLE status. If the train cannot be restored to OPERABLE status, the Conditions and Required Actions of LCO 3.7.2, "Main Steam Isolation Valves," must be entered for the associated inoperable valve. The specified Completion Time is reasonable considering that there is a system level manual initiation train for this Function and the low probability of an event occurring during this interval.
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| Catawba Units 1 and 2 B 3.3.2-35 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)
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| H.1, H.2.1 and H.2.2 Condition H applies to the automatic actuation logic and actuation relays for the Steam Line Isolation, Feedwater Isolation, and AFW actuation Functions.
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| The action addresses the train orientation of the SSPS and the master and slave relays for these functions. If one train is inoperable, 24 hours are allowed to restore the train to OPERABLE status. The 24 hours allowed for restoring the inoperable train to OPERABLE status is justified in Reference 13. The Completion Time for restoring a train to OPERABLE status is reasonable considering that there is another train OPERABLE, and the low probability of an event occurring during this interval. If the train cannot be returned to OPERABLE status, the unit must be brought to MODE 3 within the next 6 hours and MODE 4 within the following 6 hours. 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. Placing the unit in MODE 4 removes all requirements for OPERABILITY of the protection channels and actuation functions. In this MODE, the unit does not have analyzed transients or conditions that require the explicit use of the protection functions noted above.
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| The Required Actions are modified by a Note that allows one train to be bypassed for up to 4 hours for surveillance testing provided the other train is OPERABLE. This allowance is based on the reliability analysis (Ref. 7) assumption that 4 hours is the average time required to perform channel surveillance.
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| Catawba Units 1 and 2 B 3.3.2-36 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)
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| I.1 and I.2 Condition I applies to the automatic actuation logic and actuation relays for the Turbine Trip Function.
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| This action addresses the train orientation of the SSPS and the master and slave relays for this Function. If one train is inoperable, 24 hours are allowed to restore the train to OPERABLE status or the unit must be placed in MODE 3 within the following 6 hours. The 24 hours allowed for restoring the inoperable train to OPERABLE status is justified in Reference 13. The Completion Time for restoring a train to OPERABLE status is reasonable considering that there is another train OPERABLE, and the low probability of an event occurring during this interval. The allowed Completion Time of 6 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging unit systems. These Functions are no longer required in MODE 3. Placing the unit in MODE 3 removes all requirements for OPERABILITY of the protection channels and actuation functions. In this MODE, the unit does not have analyzed transients or conditions that require the explicit use of the protection functions noted above.
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| The Required Actions are modified by a Note that allows one train to be bypassed for up to 4 hours for surveillance testing provided the other train is OPERABLE. This allowance is based on the reliability analysis (Ref. 7) assumption that 4 hours is the average time required to perform channel surveillance.
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| J.1 and J.2 Condition J applies to:
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| x SG Water LevelHigh High (P-14) for the Turbine Trip Function; and x Tavg-Low.
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| Catawba Units 1 and 2 B 3.3.2-37 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)
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| If one channel is inoperable, 72 hours are allowed to restore one channel to OPERABLE status or to place it in the tripped condition. If placed in the tripped condition, the Function is then in a partial trip condition where one-out-of-three logic will result in actuation. The 72 hours allowed to restore the channel to OPERABLE status or place it in the tripped condition is justified in Reference 13. Failure to restore the inoperable channel to OPERABLE status or place it in the tripped condition within 72 hours requires the unit to be placed in MODE 3 within the following 6 hours. The allowed Completion Time of 78 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging unit systems. In MODE 3, these Functions are no longer required OPERABLE.
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| The Required Actions are modified by a Note that allows the inoperable channel to be bypassed for up to 12 hours for surveillance testing of other channels. The 72 hours allowed to place the inoperable channel in the tripped condition, and the 12 hours allowed for a second channel to be in the bypassed condition for testing, are justified in Reference 13.
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| K.1 and K.2 Condition K applies to the AFW pump start on trip of all MFW pumps.
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| This action addresses the auto start function of the AFW System on loss of all MFW pumps. The OPERABILITY of the AFW System must be assured by allowing automatic start of the AFW System pumps. If a channel is inoperable, 1 hour is allowed to return it to an OPERABLE status or to place the channel in trip. If the function cannot be returned to an OPERABLE status or placed in a trip condition, 6 hours are allowed to place the unit in MODE 3. The allowed Completion Time of 6 hours is reasonable, based on operating experience, to reach MODE 3 from full power conditions in an orderly manner and without challenging unit systems. In MODE 3, the unit does not have any analyzed transients or conditions that require the explicit use of the protection function noted above.
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| Catawba Units 1 and 2 B 3.3.2-38 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)
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| L.1 and L.2 Condition L applies to the Doghouse Water Level - High High.
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| If one channel is inoperable, 6 hours are allowed to restore the channel to OPERABLE status or to place it in the tripped condition. Therefore, failure of one channel places the Function in a two-out-of-two configuration. One channel must be tripped to place the Function in a one-out-of-two configuration that satisfies redundancy requirements.
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| Alternatively, if the inoperable channel is not restored to OPERABLE status or placed in the tripped condition within 6 hours, the unit must be placed in MODE 3 within 12 hours.
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| 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. In MODE 3, this Function is no longer required OPERABLE.
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| Required Action L.1 is modified by a Note that allows the inoperable channel to be bypassed for up to 2 hours for surveillance testing of other channels.
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| M.1, M.2.1 and M.2.2 Condition M applies to the Auxiliary Feedwater Pumps Suction Transfer on Suction Pressure Low.
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| If one channel is inoperable, 1 hour is allowed to restore the channel to OPERABLE status or to place it in the tripped condition. The failure of one channel places the Function in a two-out-of-two configuration. One channel must be tripped to place the Function in a one-out-of-three configuration that satisfies redundancy requirements.
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| Failure to restore the inoperable channel to OPERABLE status or place it in the tripped condition within 1 hour requires the unit to be placed in MODE 3 within the following 6 hours and MODE 4 within the next 6 hours.
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| Catawba Units 1 and 2 B 3.3.2-39 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)
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| 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. In MODE 4, this Function is no longer required OPERABLE.
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| N.1, N.2.1 and N.2.2 Condition N applies to:
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| x RWST LevelLow Coincident with Safety Injection.
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| RWST LevelLow Coincident With SI provides actuation of switchover to the containment sump. Note that this Function requires the bistables to energize to perform their required action. The failure of up to two channels will not prevent the operation of this Function. However, placing a failed channel in the tripped condition could result in a premature switchover to the sump, prior to the injection of the minimum volume from the RWST. Placing the inoperable channel in bypass results in a two-out-of-three logic configuration, which satisfies the requirement to allow another failure without disabling actuation of the switchover when required. Restoring the channel to OPERABLE status or placing the inoperable channel in the bypass condition within 6 hours is sufficient to ensure that the Function remains OPERABLE, and minimizes the time that the Function may be in a partial trip condition (assuming the inoperable channel has failed high). The 6 hour Completion Time is justified in Reference 7. If the channel cannot be returned to OPERABLE status or placed in the bypass condition within 6 hours, the unit must be brought to MODE 3 within the following 6 hours and MODE 5 within the next 30 hours. 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. In MODE 5, the unit does not have any analyzed transients or conditions that require the explicit use of the protection functions noted above.
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| The Required Actions are modified by a Note that allows placing a second channel in the bypass condition for up to 2 hours for surveillance testing. The total of 12 hours to reach MODE 3 and 2 hours for a second channel to be bypassed is acceptable based on the results of Reference 7.
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| Catawba Units 1 and 2 B 3.3.2-40 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)
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| O.1, O.2.1 and O.2.2 Condition O applies to the P-11 and P-12 interlocks.
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| With one channel inoperable, the operator must verify that the interlock is in the required state for the existing unit condition. This action manually accomplishes the function of the interlock. Determination must be made within 1 hour. The 1 hour Completion Time is equal to the time allowed by LCO 3.0.3 to initiate shutdown actions in the event of a complete loss of ESFAS function. If the interlock is not in the required state (or placed in the required state) for the existing unit condition, the unit must be placed in MODE 3 within the next 6 hours and MODE 4 within the following 6 hours. 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. Placing the unit in MODE 4 removes all requirements for OPERABILITY of these interlocks.
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| P.1 Condition P applies to the Containment Pressure Control System Start and Terminate Permissives.
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| With one or more channels inoperable, the affected containment spray and containment air return systems components must be declared inoperable immediately. The supported system LCOs provide the appropriate Required Actions and Completion Times for the equipment made inoperable by the inoperable channel. The immediate Completion Time is appropriate since the inoperable channel could prevent the supported equipment from starting when required. Additionally, protection from an inadvertent actuation may not be provided if the terminate function is not OPERABLE.
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| Catawba Units 1 and 2 B 3.3.2-41 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES ACTIONS (continued)
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| Q.1, Q.2, Q.3.1, and Q.3.2 With one channel of NSWS Suction Transfer - Low Pit Level inoperable in one or more NSWS pits, 4 hours are allowed to place it in the tripped condition or align the NSWS to the Standby NSWS Pond. The failure of one channel places the Function in a two-out-of-two configuration. The failed channel must either be tripped to place the Function in a one-out-of-two configuration that satisfies redundancy requirements, or the NSWS realigned to fulfill the safety function.
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| Failure to place the channel in the tripped condition or to realign the NSWS suction and discharge within 4 hours requires the unit be placed in MODE 3 within the following 6 hours and MODE 5 within the next 30 hours.
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| The requirement to align the NSWS to the Standby NSWS Pond only applies to OPERABLE trains of the system.
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| 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. In MODE 5, this Function is no longer required OPERABLE.
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| R.1, R.2.1, and R.2.2 With two or more channels of NSWS Suction Transfer - Low Pit Level inoperable in one or more pits, the NSWS must be aligned to the Standby NSWS Pond within 4 hours. Failure to accomplish the realignment within 4 hours requires the unit be placed in MODE 3 within the following 6 hours and MODE 5 within the next 30 hours.
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| The requirement to align the NSWS to the Standby NSWS Pond only applies to OPERABLE trains of the system.
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| 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. In MODE 5, this Function is no longer required OPERABLE.
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| Catawba Units 1 and 2 B 3.3.2-42 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE The SRs for each ESFAS Function are identified by the SRs column REQUIREMENTS of Table 3.3.2-1.
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| A Note has been added to the SR Table to clarify that Table 3.3.2-1 determines which SRs apply to which ESFAS Functions.
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| Note that each channel of process protection supplies both trains of the ESFAS. When testing channel I, train A and train B must be examined.
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| 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.
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| SR 3.3.2.1 Performance of the CHANNEL CHECK ensures that a gross failure of instrumentation has not occurred. A CHANNEL CHECK is normally a comparison of the parameter indicated on one channel 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 the instrumentation continues to operate properly between each CHANNEL CALIBRATION.
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| Agreement criteria are determined by the unit staff, based on a combination of the channel instrument uncertainties, including indication and reliability. 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.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.3.2.2 SR 3.3.2.2 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.
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| Catawba Units 1 and 2 B 3.3.2-43 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
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| Through the semiautomatic tester, all possible logic combinations, with and without applicable permissives, are tested for each protection function. In addition, the master relay coil is pulse tested for continuity.
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| This verifies that the logic modules are OPERABLE and that there is an intact voltage signal path to the master relay coils. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.3.2.3 SR 3.3.2.3 is the performance of a TADOT. This test is a check of the Loss of Offsite Power Function. Each Function is tested up to, and including, the master transfer relay coils.
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| This test also includes trip devices that provide actuation signals directly to the SSPS. The SR is modified by a Note that excludes final actuation of pumps and valves to minimize plant upsets that would occur. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| For Functions for which TSTF-493, Clarify Application of Setpoint Methodology for LSSS Functions has been implemented, this SR is modified by two Notes as identified in Table 3.3.2-1. 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 Catawba Units 1 and 2 B 3.3.2-44 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) 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.
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| SR 3.3.2.4 SR 3.3.2.4 is the performance of a MASTER RELAY TEST. The MASTER RELAY TEST is the energizing of the master relay, verifying contact operation and a low voltage continuity check of the slave relay coil. Upon master relay contact operation, a low voltage is injected to the slave relay coil. This voltage is insufficient to pick up the slave relay, but large enough to demonstrate signal path continuity. The time allowed for the testing (4 hours) is justified in Reference 7. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.3.2.5 SR 3.3.2.5 is the performance of a COT.
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| A COT is performed on each required channel to ensure the channel will perform the intended Function. The tested portion of the loop must trip within the Allowable Values specified in Table 3.3.2-1.
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| The setpoint shall be left set consistent with the assumptions of the setpoint methodology.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| Catawba Units 1 and 2 B 3.3.2-45 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.3.2.6 SR 3.3.2.6 is the performance of a SLAVE RELAY TEST. The SLAVE RELAY TEST is the energizing of the slave relays. Contact operation is verified in one of two ways. Actuation equipment that may be operated in the design mitigation MODE is either allowed to function, or is placed in a condition where the relay contact operation can be verified without operation of the equipment. Actuation equipment that may not be operated in the design mitigation MODE is prevented from operation by the SLAVE RELAY TEST circuit. For this latter case, contact operation is verified by a continuity check of the circuit containing the slave relay. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| For slave relays or any auxiliary relays in the ESFAS circuit that are of the type Westinghouse AR or Potter & Brumfield MDR, the SLAVE RELAY TEST Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.3.2.7 SR 3.3.2.7 is the performance of a COT on the RWST level and Containment Pressure Control Start and Terminate Permissives.
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| A COT is performed on each required channel to ensure the entire channel will perform the intended Function. Setpoints must be found conservative with respect to the Allowable Values specified in Table 3.3.2-1. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| Catawba Units 1 and 2 B 3.3.2-46 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
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| For Functions for which TSTF-493, Clarify Application of Setpoint Methodology for LSSS Functions has been implemented, this SR is modified by two Notes as identified in Table 3.3.2-1. 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.
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| SR 3.3.2.8 SR 3.3.2.8 is the performance of a TADOT. This test is a check of the Manual Actuation Functions, AFW pump start on trip of all MFW pumps, AFW low suction pressure, Reactor Trip (P-4) Interlock, and Doghouse Water Level - High High Feedwater Isolation. Each Manual Actuation Function is tested up to, and including, the master relay coils. In some instances, the test includes actuation of the end device (i.e., pump starts, valve cycles, etc.). 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 during the TADOT for manual initiation Functions. The manual initiation Functions have no associated setpoints.
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| Catawba Units 1 and 2 B 3.3.2-47 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
| |
| SR 3.3.2.9 SR 3.3.2.9 is the performance of a CHANNEL CALIBRATION.
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| CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to measured parameter within the necessary range and accuracy.
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| CHANNEL CALIBRATIONS must be performed consistent with the assumptions of the unit specific setpoint methodology.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| This SR is modified by a Note stating that this test should include verification that the time constants are adjusted to the prescribed values where applicable. The applicable time constants are shown in Table 3.3.2-1.
| |
| For Functions for which TSTF-493, Clarify Application of Setpoint Methodology for LSSS Functions has been implemented, this SR is modified by two Notes as identified in Table 3.3.2-1. 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 Catawba Units 1 and 2 B 3.3.2-48 Revision No. 14
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| | |
| ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued) tolerances be in the UFSAR.
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| SR 3.3.2.10 This SR ensures the individual channel ESF RESPONSE TIMES are less than or equal to the maximum values assumed in the accident analysis.
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| Response Time testing acceptance criteria are included in the UFSAR (Ref. 2). 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 in both trains reaches the required functional state (e.g., pumps at rated discharge pressure, valves in full open or closed position).
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| 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 functions 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.
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| 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) inplace, onsite, or offsite (e.g. vendor) test measurements, or (3) utilizing vendor engineering specifications.
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| 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.
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| Catawba Units 1 and 2 B 3.3.2-49 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
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| 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.
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| 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. 15).
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| This SR is modified by a Note that clarifies that the turbine driven AFW pump is tested within 24 hours after reaching 600 psig in the SGs.
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| SR 3.3.2.11 SR 3.3.2.11 is the performance of a COT on the NSWS Suction Transfer
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| - Low Pit Level.
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| A COT is performed on each required channel to ensure the entire channel will perform the intended Function. Setpoints must be found within the Allowable Values specified in Table 3.3.2-1. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| Catawba Units 1 and 2 B 3.3.2-50 Revision No. 14
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| ESFAS Instrumentation B 3.3.2 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.3.2.12 SR 3.3.2.12 is the performance of an ACTUATION LOGIC TEST on the Doghouse Water Level-High High and NSWS Suction Transfer-Emergency Low Pit Level Functions.
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| An ACTUATION LOGIC TEST to satisfy the requirements of GL 96-01 is performed on each instrumentation to ensure all logic combinations will initiate the appropriate Function. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| REFERENCES 1. UFSAR, Chapter 6.
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| : 2. UFSAR, Chapter 7.
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| : 3. UFSAR, Chapter 15.
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| : 4. IEEE-279-1971.
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| : 5. 10 CFR 50.49.
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| : 6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| : 7. WCAP-10271-P-A, Supplement 1 and Supplement 2, Rev. 1, May 1986 and June 1990.
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| : 8. WCAP-13632-P-A Revision 2, Elimination of Pressure Sensor Response Time Testing Requirements Sep., 1995.
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| : 9. WCAP-14036-P-A Revision 1, Elimination of Periodic Protection Channel Response Time Tests Oct., 1998.
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| : 10. Not used.
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| : 11. Not used.
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| : 12. Not used.
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| : 13. WCAP-14333-P-A, Revision 1, October 1998.
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| : 14. Not used.
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| Catawba Units 1 and 2 B 3.3.2-51 Revision No. 14
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| | |
| ESFAS Instrumentation B 3.3.2 BASES REFERENCES (continued)
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| : 15. Attachment 1 to TSTF-569, Rev. 2, Methodology to Eliminate Pressure Sensor and Protection Channel (for Westinghouse Plants only) Response Time Testing.
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| Catawba Units 1 and 2 B 3.3.2-52 Revision No. 14
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| PAM Instrumentation B 3.3.3 B 3.3 INSTRUMENTATION B 3.3.3 Post Accident Monitoring (PAM) Instrumentation BASES BACKGROUND The primary purpose of the PAM instrumentation is to display unit variables that provide information required by the control room operators during accident situations. This information provides the necessary support for the operator to take the manual actions for which no automatic control is provided and that are required for safety systems to accomplish their safety functions for Design Basis Accidents (DBAs).
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| The OPERABILITY of the accident monitoring instrumentation ensures that there is sufficient information available on selected unit parameters to monitor and to assess unit status and behavior following an accident.
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| The availability of accident monitoring instrumentation is important so that responses to corrective actions can be observed and the need for, and magnitude of, further actions can be determined. These essential instruments are identified by unit specific documents (Ref. 1) addressing the recommendations of Regulatory Guide 1.97 (Ref. 2) as required by Supplement 1 to NUREG-0737 (Ref. 3).
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| The instrument channels required to be OPERABLE by this LCO include two classes of parameters identified during unit specific implementation of Regulatory Guide 1.97 as Type A and Category I variables.
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| Type A variables are included in this LCO because they provide the primary information required for the control room operator to take specific manually controlled actions for which no automatic control is provided, and that are required for safety systems to accomplish their safety functions for DBAs.
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| Category I variables are the key variables deemed risk significant because they are needed to:
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| Catawba Units 1 and 2 B 3.3.3-1 Revision No. 7
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| PAM Instrumentation B 3.3.3 BASES BACKGROUND (continued) x Determine whether other systems important to safety are performing their intended functions; x Provide information to the operators that will enable them to determine the likelihood of a gross breach of the barriers to radioactivity release; and x Provide information regarding the release of radioactive materials to allow for early indication of the need to initiate action necessary to protect the public, and to estimate the magnitude of any impending threat.
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| These key variables are identified by the unit specific Regulatory Guide 1.97 analyses (Ref. 1). These analyses identify the unit specific Type A and Category I variables and provide justification for deviating from the NRC proposed list of Category I variables.
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| The specific instrument Functions listed in Table 3.3.3-1 are discussed in the LCO section.
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| APPLICABLE The PAM instrumentation ensures the operability of Regulatory SAFETY ANALYSES Guide 1.97 Type A and Category I variables so that the control room operating staff can:
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| x Perform the diagnosis specified in the emergency operating procedures (these variables are restricted to preplanned actions for the primary success path of DBAs), e.g., loss of coolant accident (LOCA);
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| x Take the specified, pre-planned, manually controlled actions, for which no automatic control is provided, and that are required for safety systems to accomplish their safety function; x Determine whether systems important to safety are performing their intended functions; x Determine the likelihood of a gross breach of the barriers to radioactivity release; Catawba Units 1 and 2 B 3.3.3-2 Revision No. 7
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| PAM Instrumentation B 3.3.3 BASES APPLICABLE SAFETY ANALYSES (continued) x Determine if a gross breach of a barrier has occurred; and x Initiate action necessary to protect the public and to estimate the magnitude of any impending threat.
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| PAM instrumentation that meets the definition of Type A in Regulatory Guide 1.97 satisfies Criterion 3 of 10 CFR 50.36 (Ref. 4). Category I, non-Type A, instrumentation must be retained in TS because it is intended to assist operators in minimizing the consequences of accidents.
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| Therefore, Category I, non-Type A, variables are important for reducing public risk.
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| LCO The PAM instrumentation LCO provides OPERABILITY requirements for Regulatory Guide 1.97 Type A monitors, which provide information required by the control room operators to perform certain manual actions specified in the unit Emergency Operating Procedures. These manual actions ensure that a system can accomplish its safety function, and are credited in the safety analyses. Additionally, this LCO addresses Regulatory Guide 1.97 instruments that have been designated Category I, non-Type A.
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| The OPERABILITY of the PAM instrumentation ensures there is sufficient information available on selected unit parameters to monitor and assess unit status following an accident. This capability is consistent with the recommendations of Reference 1.
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| LCO 3.3.3 requires two OPERABLE channels for most Functions. Two OPERABLE channels ensure no single failure prevents operators from getting the information necessary for them to determine the safety status of the unit, and to bring the unit to and maintain it in a safe condition following an accident.
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| Furthermore, OPERABILITY of two channels allows a CHANNEL CHECK during the post accident phase to confirm the validity of displayed information.
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| In some cases, the total number of channels exceeds the number of required channels, e.g., pressurizer level has a total of three Catawba Units 1 and 2 B 3.3.3-3 Revision No. 7
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| PAM Instrumentation B 3.3.3 BASES LCO (continued) channels, however only two channels are required OPERABLE. This provides additional redundancy beyond that required by this LCO, i.e.,
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| when one channel of pressurizer level is inoperable, the required number of two channels can still be met. The ACTIONS of this LCO are only entered when the required number of channels cannot be met.
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| Type A and Category I variables are required to meet Regulatory Guide 1.97 Category I (Ref. 2) design and qualification requirements for seismic and environmental qualification, single failure criterion, utilization of emergency standby power, immediately accessible display, continuous readout, and recording of display.
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| Listed below are discussions of the specified instrument Functions listed in Table 3.3.3-1.
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| 1, 2. Reactor Coolant System (RCS) Hot and Cold Leg Temperatures RCS Hot and Cold Leg Temperatures are Category I variables provided for verification of core cooling and long term surveillance.
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| RCS hot and cold leg temperatures are used to determine RCS subcooling margin. RCS subcooling margin will allow termination of safety injection (SI), if still in progress, or reinitiation of SI if it has been stopped. RCS subcooling margin is also used for unit stabilization and cooldown control.
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| In addition, RCS cold leg temperature is used in conjunction with RCS hot leg temperature to verify the unit conditions necessary to establish natural circulation in the RCS.
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| Reactor coolant hot and cold leg temperature inputs are provided by a fast response resistance element in each loop.
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| RCS Hot and Cold Leg Temperature are diverse indications of RCS temperature. Core exit thermocouples also provide diverse indication of RCS temperature.
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| Catawba Units 1 and 2 B 3.3.3-4 Revision No. 7
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| PAM Instrumentation B 3.3.3 BASES LCO (continued)
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| : 3. Reactor Coolant System Pressure (Wide Range)
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| RCS wide range pressure is a Category I variable provided for verification of core cooling and RCS integrity long term surveillance.
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| RCS pressure is used to verify delivery of SI flow to RCS from at least one train when the RCS pressure is below the pump shutoff head. RCS pressure is also used to verify closure of manually closed spray line valves and pressurizer power operated relief valves (PORVs).
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| In addition to these verifications, RCS pressure is used for determining RCS subcooling margin. RCS pressure can also be used:
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| x to determine whether to terminate actuated SI or to reinitiate stopped SI; x to determine when to reset SI and shut off low head SI; x to manually restart low head SI; x as reactor coolant pump (RCP) trip criteria; and x to make a determination on the nature of the accident in progress and where to go next in the procedure.
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| RCS pressure is also related to three decisions about depressurization. They are:
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| x to determine whether to proceed with primary system depressurization; x to verify termination of depressurization; and x to determine whether to close accumulator isolation valves during a controlled cooldown/depressurization.
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| Catawba Units 1 and 2 B 3.3.3-5 Revision No. 7
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| PAM Instrumentation B 3.3.3 BASES LCO (continued)
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| A final use of RCS pressure is to determine whether to operate the pressurizer heaters.
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| RCS pressure is a Type A variable because the operator uses this indication to monitor the cooldown of the RCS following a steam generator tube rupture (SGTR) or small break LOCA. Operator actions to maintain a controlled cooldown, such as adjusting steam generator (SG) pressure or level, would use this indication.
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| Furthermore, RCS pressure is one factor that may be used in decisions to terminate RCP operation.
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| Two channels of wide range RCS pressure are required OPERABLE.
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| : 4. Reactor Vessel Water Level Reactor Vessel Water Level is provided for verification and long term surveillance of core cooling. It is also used for accident diagnosis and to determine reactor coolant inventory adequacy.
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| The Reactor Vessel Water Level Monitoring System provides a direct measurement of the collapsed liquid level above the fuel alignment plate. The collapsed level represents the amount of liquid mass that is in the reactor vessel above the core.
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| Measurement of the collapsed water level is selected because it is a direct indication of the water inventory.
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| Two channels of Reactor Vessel Water Level are required with plasma displays in the unit control room. Each channel consists of three differential pressure transmitters and a micro processor to calculate true vessel level or relative void content of the primary coolant.
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| : 5. Containment Sump Water Level (Wide Range)
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| Containment Sump Water Level is provided for verification and long term surveillance of RCS integrity.
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| Catawba Units 1 and 2 B 3.3.3-6 Revision No. 7
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| PAM Instrumentation B 3.3.3 BASES LCO (continued)
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| Containment Sump Water Level is used to determine:
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| x containment sump level accident diagnosis; x when to begin the recirculation procedure; and x whether to terminate SI, if still in progress.
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| Two channels of Wide Range Containment Sump Water Level are required OPERABLE. Each channel consists of wide range containment sump level indication, and two level switches.
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| : 6. Containment Pressure (Wide Range)
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| Containment Pressure (Wide Range) is provided for verification of RCS and containment OPERABILITY.
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| Containment pressure is used to verify closure of main steam isolation valves (MSIVs), containment spray operation, and Phase B containment isolation when Containment Pressure - High High is reached.
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| Two channels of wide range containment pressure are required OPERABLE.
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| : 7. Containment Area Radiation (High Range)
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| Containment Area Radiation is provided to monitor for the potential of significant radiation releases and to provide release assessment for use by operators in determining the need to invoke site emergency plans. Containment radiation level is used to determine if a high energy line break (HELB) has occurred, and whether the event is inside or outside of containment.
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| Two channels of high range containment area radiation are provided. One channel is required OPERABLE. Diversity or backup information is provided by portable instrumentation or by sampling and analysis.
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| Catawba Units 1 and 2 B 3.3.3-7 Revision No. 7
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| PAM Instrumentation B 3.3.3 BASES LCO (continued)
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| : 8. Not Used
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| : 9. Pressurizer Level Pressurizer Level is used to determine whether to terminate SI, if still in progress, or to reinitiate SI if it has been stopped.
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| Knowledge of pressurizer water level is also used to verify the unit conditions necessary to establish natural circulation in the RCS and to verify that the unit is maintained in a safe shutdown condition.
| |
| Three channels of pressurizer level are provided. Two channels are required OPERABLE.
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| : 10. Steam Generator Water Level (Narrow Range)
| |
| SG Water Level is provided to monitor operation of decay heat removal via the SGs. The Category I indication of SG level is the narrow range level instrumentation.
| |
| SG Water Level (Narrow Range) is used to:
| |
| x identify the faulted SG following a tube rupture; x verify that the intact SGs are an adequate heat sink for the reactor; x determine the nature of the accident in progress (e.g., verify an SGTR); and x verify unit conditions for termination of SI during secondary unit HELBs outside containment.
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| Four channels per SG of narrow range water level are provided.
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| Only two channels are required OPERABLE by the LCO.
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| Catawba Units 1 and 2 B 3.3.3-8 Revision No. 7
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| PAM Instrumentation B 3.3.3 BASES LCO (continued) 11, 12, 13, 14. Core Exit Temperature Core Exit Temperature is provided for verification and long term surveillance of core cooling.
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| Adequate core cooling is ensured with two valid Core Exit Temperature channels per quadrant with two CETs per required channel. Core inlet temperature data is used with core exit temperature to give radial distribution of coolant enthalpy rise across the core. Core Exit Temperature is used to determine whether to terminate SI, if still in progress, or to reinitiate SI if it has been stopped. Core Exit Temperature is also used for unit stabilization and cooldown control.
| |
| Two OPERABLE channels of Core Exit Temperature are required in each quadrant to provide indication of radial distribution of the coolant temperature rise across representative regions of the core.
| |
| Two sets of two thermocouples (1 set per redundant power train) ensure a single failure will not disable the ability to determine the radial temperature gradient.
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| : 15. Auxiliary Feedwater Flow AFW Flow is provided to monitor operation of decay heat removal via the SGs.
| |
| The AFW flow to each SG is determined by flow indicators, pump operational status indicators, and NSWS and condensate supply valve indicators in the control room. The AFW flow indicators are category 2, type D variables which are used to demonstrate the AFW assured source.
| |
| AFW flow is used three ways:
| |
| x to verify delivery of AFW flow to the SGs; x to determine whether to terminate SI if still in progress, in conjunction with SG water level (narrow range); and x to regulate AFW flow so that the SG tubes remain covered.
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| Catawba Units 1 and 2 B 3.3.3-9 Revision No. 7
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| | |
| PAM Instrumentation B 3.3.3 BASES LCO (continued)
| |
| One channel per SG of AFW flow is required to be OPERABLE.
| |
| Diverse indication of AFW flow is provided by SG level.
| |
| : 16. RCS Radiation Level The RCS radiation monitor provides indication of radiation levels within the primary coolant and alerts the operator to possible fuel clad failures.
| |
| One channel of RCS radiation level is required OPERABLE. This monitor was not installed to quantify accident conditions and cannot be assured flow following an accident. Diverse or backup information for this variable is provided by sampling and analysis of the primary coolant.
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| : 17. RCS Subcooling Margin Monitor RCS subcooling margin monitoring indication is provided to allow unit stabilization and cooldown control. RCS subcooling margin monitoring indication will provide information to the operators to allow termination of SI, if still in progress, or reinitiation of SI if it has been stopped.
| |
| The margin to saturation is calculated from RCS pressure and temperature measurements. The average of the five highest core exit thermocouples are used to represent core conditions and the wide range hot leg RTDs are used to measure loop hot leg temperatures. The ICCM System performs the calculations and comparisons to saturation curves. A graphic display over the required range gives the operator a representation of primary system conditions compared to various curves of importance (saturation, NDT, etc.). Two trains of RCS Subcooling Margin Monitor are provided and two trains are required to be OPERABLE.
| |
| A backup program exists to ensure the capability to accurately monitor RCS subcooling. The program includes training and a procedure to manually calculate subcooling margin, using control room pressure and temperature instruments.
| |
| : 18. Steam Line Pressure Steam Line Pressure is provided to monitor operation of decay heat removal via the SGs. Steam line pressure is also used to determine if a high energy secondary line rupture occurred and which SG is faulted.
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| Catawba Units 1 and 2 B 3.3.3-10 Revision No. 7
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| | |
| PAM Instrumentation B 3.3.3 BASES LCO (continued)
| |
| There are three channels of Steam Line Pressure provided for each SG. Two channels per SG are required OPERABLE by the LCO.
| |
| : 19. Refueling Water Storage Tank Level RWST level monitoring is provided to ensure an adequate supply of water to the ECCS pumps during the switchover to cold leg recirculation.
| |
| Four channels of RWST level are provided. Only two channels are required OPERABLE by the LCO.
| |
| : 20. Neutron Flux (Wide Range)
| |
| Wide Range Neutron Flux indication is provided to verify reactor shutdown.
| |
| Neutron flux is used for accident diagnosis, verification of subcriticality, and diagnosis of positive reactivity insertion.
| |
| Two channels of wide range neutron flux are required OPERABLE.
| |
| : 21. Steam Generator Water Level (Wide Range)
| |
| SG Water Level (Wide Range) is used to verify that the intact SGs are an adequate heat sink for the reactor. One channel per steam generator is required OPERABLE by the LCO. Diverse indication is provided by Steam Generator Water Level (Narrow Range).
| |
| APPLICABILITY The PAM instrumentation LCO is applicable in MODES 1, 2, and 3.
| |
| These variables are related to the diagnosis and pre-planned actions required to mitigate DBAs. The applicable DBAs are assumed to occur in MODES 1, 2, and 3. In MODES 4, 5, and 6, unit conditions are such that the likelihood of an event that would require PAM instrumentation is low; therefore, the PAM instrumentation is not required to be OPERABLE in these MODES.
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| Catawba Units 1 and 2 B 3.3.3-11 Revision No. 7
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| | |
| PAM Instrumentation B 3.3.3 BASES ACTIONS A Note has been added in the ACTIONS to clarify the application of Completion Time rules. The Conditions of this Specification may be entered independently for each Function listed on Table 3.3.3-1. When the Required Channels in Table 3.3.3-1 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.
| |
| The Completion Time(s) of the inoperable channel(s) of a Function will be tracked separately for each Function starting from the time the Condition was entered for that Function.
| |
| A.1 Condition A applies to all PAM instrument Functions. Condition A addresses the situation when one or more required channels for one or more Functions are inoperable. The Required Action is to refer to Table 3.3.3-1 and take the appropriate Required Actions for the PAM instrumentation affected. The Completion Times are those from the referenced Conditions and Required Actions.
| |
| B.1 Condition B applies when one or more Functions have one required channel that is inoperable. Required Action A.1 requires restoring the inoperable channel to OPERABLE status within 30 days. The 30 day Completion Time is based on operating experience and takes into account the remaining OPERABLE channel, the passive nature of the instrument (no critical automatic action is assumed to occur from these instruments), and the low probability of an event requiring PAM instrumentation during this interval.
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| Catawba Units 1 and 2 B 3.3.3-12 Revision No. 7
| |
| | |
| PAM Instrumentation B 3.3.3 BASES ACTIONS (continued)
| |
| C.1 Condition C applies to PAM Instrument Functions when a single required channel is inoperable and a diverse channel for the affected function remains OPERABLE. The Required Action requires the affected channel be restored to OPERABLE status within 30 days. The 30 day Completion Time is based on operating experience and takes into account the remaining OPERABLE diverse channel, the passive nature of the instrument (no critical automatic action is assumed to occur from these instruments), and the low probability of an event requiring PAM instrumentation during this interval.
| |
| D.1 Condition D applies when the Required Action and associated Completion Time for Condition B or C are not met. This Required Action specifies initiation of actions in Specification 5.6.7, which requires a written report to be submitted to the NRC immediately. This report discusses the results of the root cause evaluation of the inoperability and identifies proposed restorative actions. This action is appropriate in lieu of a shutdown requirement since alternative actions are identified before loss of functional capability, and given the likelihood of unit conditions that would require information provided by this instrumentation.
| |
| E.1 and E.2 Condition E applies when a single required channel is inoperable and no diverse channel is OPERABLE. Required Action E.1 and E.2 requires restoring the required channel or the diverse channel to OPERABLE status within 7 days. The Completion Time of 7 days is based on the relatively low probability of an event requiring PAM instrument operation and the availability of alternate means to obtain the required information.
| |
| Continuous operation with the required channel and the diverse channel inoperable is not acceptable. Therefore, requiring restoration of either the required or diverse channel to OPERABLE status limits the risk that the PAM function will be in a degraded condition should an event occur.
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| Catawba Units 1 and 2 B 3.3.3-13 Revision No. 7
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| | |
| PAM Instrumentation B 3.3.3 BASES ACTIONS (continued)
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| F.1 Condition F applies when one or more Functions have two inoperable required channels (i.e., two channels inoperable in the same Function).
| |
| Required Action F.1 requires restoring one channel in the Function(s) to OPERABLE status within 7 days. The Completion Time of 7 days is based on the relatively low probability of an event requiring PAM instrument operation and the availability of alternate means to obtain the required information. Continuous operation with two required channels inoperable in a Function is not acceptable because the alternate indications may not fully meet all performance qualification requirements applied to the PAM instrumentation. Therefore, requiring restoration of one inoperable channel of the Function limits the risk that the PAM Function will be in a degraded condition should an accident occur.
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| G.1 Not Used H.1 and H.2 If the Required Action and associated Completion Time of Conditions E or F are not met, the unit must be brought to a MODE where the requirements of this LCO do not apply. To achieve this status, the unit must be brought to at least MODE 3 within 6 hours and MODE 4 within 12 hours.
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| 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.
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| Catawba Units 1 and 2 B 3.3.3-14 Revision No. 7
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| | |
| PAM Instrumentation B 3.3.3 BASES SURVEILLANCE A Note has been added to the SR Table to clarify that SR 3.3.3.1 and REQUIREMENTS SR 3.3.3.3 apply to each PAM instrumentation Function in Table 3.3.3-1.
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| SR 3.3.3.1 Performance of the CHANNEL CHECK ensures that a gross instrumentation failure 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 the instrumentation continues to operate properly between each CHANNEL CALIBRATION. The high radiation instrumentation should be compared to similar unit instruments located throughout the unit.
| |
| Agreement criteria are determined by the unit staff, based on a combination of the channel instrument uncertainties, including isolation, 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. If the channels are within the criteria, it is an indication that the channels are OPERABLE.
| |
| As specified in the SR, a CHANNEL CHECK is only required for those channels that are normally energized.
| |
| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.3.3.2 Not Used Catawba Units 1 and 2 B 3.3.3-15 Revision No. 7
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| | |
| PAM Instrumentation B 3.3.3 BASES SURVEILLANCE REQUIREMENTS (continued)
| |
| SR 3.3.3.3 CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor. The test verifies that the channel responds to measured parameter with the necessary range and accuracy. This SR is modified by two Notes. Note 1 excludes neutron detectors. The calibration method for neutron detectors is specified in the Bases of LCO 3.3.1, "Reactor Trip System (RTS) Instrumentation." Note 2 describes the calibration methods for the Containment Area - High Range monitor.
| |
| 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 1.8.
| |
| : 2. Regulatory Guide 1.97, Rev. 2.
| |
| : 3. NUREG-0737, Supplement 1, "TMI Action Items."
| |
| : 4. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| Catawba Units 1 and 2 B 3.3.3-16 Revision No. 7
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| | |
| Containment B 3.6.1 B 3.6 CONTAINMENT SYSTEMS B 3.6.1 Containment BASES BACKGROUND The containment is a free standing steel pressure vessel surrounded by a reinforced concrete reactor building. The containment vessel, including all its penetrations, is a low leakage steel shell designed to contain the radioactive material that may be released from the reactor core following a design basis Loss of Coolant Accident (LOCA). Additionally, the containment and reactor building provide shielding from the fission products that may be present in the containment atmosphere following accident conditions.
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| The containment vessel is a vertical cylindrical steel pressure vessel with hemispherical dome and a flat circular base. It is completely enclosed by a reinforced concrete reactor building. An annular space exists between the walls and domes of the steel containment vessel and the concrete reactor building to provide for the collection, mixing, holdup, and controlled release of containment out leakage. Ice condenser containments utilize an outer concrete building for shielding and an inner steel containment for leak tightness.
| |
| Containment piping penetration assemblies provide for the passage of process, service, sampling, and instrumentation pipelines into the containment vessel while maintaining containment integrity. The reactor building provides shielding and allows controlled release of the annulus atmosphere under accident conditions, as well as environmental missile protection for the containment vessel and Nuclear Steam Supply System.
| |
| The inner steel containment and its penetrations establish the leakage limiting boundary of the containment. Maintaining the containment OPERABLE limits the leakage of fission product radioactivity from the containment to the environment. SR 3.6.1.1 leakage rate requirements comply with 10 CFR 50, Appendix J, Option B (Ref. 1), as modified by approved exemptions.
| |
| The isolation devices for the penetrations in the containment boundary are a part of the containment leak tight barrier. To maintain this leak tight barrier:
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| Catawba Units 1 and 2 B 3.6.1-1 Revision No. 2
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| Containment B 3.6.1 BASES BACKGROUND (continued)
| |
| : a. All penetrations required to be closed during accident conditions are either:
| |
| : 1. capable of being closed by an OPERABLE automatic containment isolation system, or
| |
| : 2. closed by manual valves, blind flanges, or de-activated automatic valves secured in their closed positions, except as provided in LCO 3.6.3, "Containment Isolation Valves";
| |
| : b. Each air lock is OPERABLE, except as provided in LCO 3.6.2, "Containment Air Locks";
| |
| : c. All equipment hatches are closed and sealed; and
| |
| : d. The sealing mechanism associated with a penetration (e.g., welds, bellows, or O-rings) is OPERABLE.
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| APPLICABLE The safety design basis for the containment is that the containment SAFETY ANALYSES must withstand the pressures and temperatures of the limiting Design Basis Accident (DBA) without exceeding the design leakage rates.
| |
| The DBAs that result in a challenge to containment OPERABILITY from high pressures and temperatures are a LOCA and a steam line break (Ref. 2). In addition, release of significant fission product radioactivity within containment can occur from a LOCA. In the DBA analyses, it is assumed that the containment is OPERABLE such that, for the DBAs involving release of fission product radioactivity, release to the environment is controlled by the rate of containment leakage. The containment was designed with an allowable leakage rate of 0.30% of containment air weight per day (Ref. 3). This leakage rate, used in the evaluation of offsite doses resulting from accidents, is defined in 10 CFR 50, Appendix J, Option B (Ref. 1), as La: the maximum allowable containment leakage rate at the calculated peak containment internal pressure (Pa) resulting from the limiting design basis LOCA. The allowable leakage rate represented by La forms the basis for the acceptance criteria imposed on all containment leakage rate testing. La is assumed to be 0.30% per day in the safety analysis at Pa = 14.68 psig (Ref. 3).
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| Catawba Units 1 and 2 B 3.6.1-2 Revision No. 2
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| | |
| Containment B 3.6.1 BASES APPLICABLE SAFETY ANALYSES (continued)
| |
| Satisfactory leakage rate test results are a requirement for the establishment of containment OPERABILITY.
| |
| The containment satisfies Criterion 3 of 10 CFR 50.36 (Ref. 4).
| |
| LCO Containment OPERABILITY is maintained by limiting leakage to d 1.0 La, except prior to the first startup after performing a required Containment Leakage Rate Testing Program leakage test. At this time, the applicable leakage limits must be met.
| |
| Compliance with this LCO will ensure a containment configuration, including equipment hatches, that is structurally sound and that will limit leakage to those leakage rates assumed in the safety analysis.
| |
| Individual leakage rates specified for the containment air lock (LCO 3.6.2),
| |
| purge valves with resilient seals, and reactor building bypass leakage (LCO 3.6.3) are not specifically part of the acceptance criteria of 10 CFR 50, Appendix J. Therefore, leakage rates exceeding these individual limits only result in the containment being inoperable when the leakage results in exceeding the overall acceptance criteria of 1.0 La.
| |
| APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause a release of radioactive material into containment. In MODES 5 and 6, the probability and consequences of these events are reduced due to the pressure and temperature limitations of these MODES. Therefore, containment is not required to be OPERABLE in MODE 5 to prevent leakage of radioactive material from containment. The requirements for containment during MODE 6 are addressed in LCO 3.9.3, "Containment Penetrations."
| |
| ACTIONS A.1 In the event containment is inoperable, containment must be restored to OPERABLE status within 1 hour. The 1 hour Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining containment OPERABLE during MODES 1, 2, 3, and 4. This time period also ensures that the probability of an accident (requiring containment OPERABILITY) occurring during periods when containment is inoperable is minimal.
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| Catawba Units 1 and 2 B 3.6.1-3 Revision No. 2
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| | |
| Containment B 3.6.1 BASES ACTIONS (continued)
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| B.1 and B.2 If containment cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours and to MODE 5 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
| |
| SURVEILLANCE SR 3.6.1.1 REQUIREMENTS Maintaining the containment OPERABLE requires compliance with the visual examinations and leakage rate test requirements of the Containment Leakage Rate Testing Program. Failure to meet specific leakage limits for air lock, secondary containment bypass leakage path, and purge valve with resilient seals (as specified in LCO 3.6.2 and LCO 3.6.3) does not invalidate the acceptability of the overall containment leakage determinations unless the specific leakage contribution to Type A, B, and C leakage causes one of these overall leakage limits to be exceeded. As left leakage prior to the first startup after performing a required Containment Leakage Rate Testing Program leakage test is required to be < 0.6 La for combined Type B and C leakage, and d 0.75 La for Option B for overall Type A leakage. At all other times between required leakage rate tests, the acceptance criteria is based on an overall Type A leakage limit of d 1.0 La.
| |
| At d 1.0 La the offsite dose consequences are bounded by the assumptions of the safety analysis. SR Frequencies are as required by the Containment Leakage Rate Testing Program. These periodic testing requirements verify that the containment leakage rate does not exceed the leakage rate assumed in the safety analysis.
| |
| The Surveillance is modified by two Notes. Note 1 requires that the space between each dual-ply bellows assembly on containment penetrations between the containment building and the annulus be vented to the annulus during each Type A test. Note 2 requires that the space between each dual-ply bellows assembly be subjected to a low pressure leak test with no detectable leakage. Otherwise, the assembly must be tested with the containment side of the bellows assembly pressurized to Pa and meet the requirements of SR 3.6.3.8 (bypass leakage requirements). The low pressure test is conducted following the completion of Type A tests. At the completion of the low pressure test, all test connections will be closed, except for the main steam and main feedwater penetration outer bellows Catawba Units 1 and 2 B 3.6.1-4 Revision No. 2
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| | |
| Containment B 3.6.1 BASES test connection, which will remain open and vented to the annulus.
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| REFERENCES 1. 10 CFR 50, Appendix J, Option B.
| |
| : 2. UFSAR, Chapter 15.
| |
| : 3. UFSAR, Section 6.2.
| |
| : 4. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
| |
| : 5. UFSAR Table 18-1.
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| Catawba Units 1 and 2 B 3.6.1-5 Revision No. 2
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| AVS B 3.6.10 B 3.6 CONTAINMENT SYSTEMS B 3.6.10 Annulus Ventilation System (AVS)
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| BASES BACKGROUND The AVS is required by 10 CFR 50, Appendix A, GDC 41, "Containment Atmosphere Cleanup" (Ref. 1), to ensure that radioactive materials that leak from the primary containment into the reactor building (secondary containment) following a Design Basis Accident (DBA) are filtered and adsorbed prior to exhausting to the environment.
| |
| The containment has a secondary containment called the reactor building, which is a concrete structure that surrounds the steel primary containment vessel. Between the containment vessel and the reactor building inner wall is an annulus that collects any containment leakage that may occur following a loss of coolant accident (LOCA) or rod ejection accident. This space also allows for periodic inspection of the outer surface of the steel containment vessel.
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| The AVS establishes a negative pressure in the annulus between the reactor building and the steel containment vessel. Filters in the system then control the release of radioactive contaminants to the environment.
| |
| The AVS consists of two separate and redundant trains. Each train includes a heater, prefilter/moisture separators, upstream and downstream high efficiency particulate air (HEPA) filters, an activated carbon adsorber section for removal of radioiodines, and a fan.
| |
| Ductwork, valves and/or dampers, and instrumentation also form part of the system. The prefilters/moisture separators function to remove large particles and entrained water droplets from the airstream, which reduces the moisture content. A HEPA filter bank upstream of the carbon adsorber filter bank functions to remove particulates and a second bank of HEPA filters follow the adsorber section to collect carbon fines. Only the upstream HEPA filter and the carbon adsorber section are credited in the analysis.
| |
| A heater is included within each filter train to reduce the relative humidity of the airstream, although no credit is taken in the safety analysis. The heaters are not required for OPERABILITY since the carbon laboratory tests are performed at 95% relative humidity, but have been maintained in the system to provide additional margin (Ref. 6).
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| Catawba Units 1 and 2 B 3.6.10-1 Revision No. 5
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| | |
| AVS B 3.6.10 BASES BACKGROUND (continued)
| |
| The heaters do not affect OPERABILITY of the AVS filter trains because carbon adsorber efficiency testing is performed at 30°C and 95% relative humidity. Testing per ASTM D3803-1989 at 30°C and 95% relative humidity ensures that the filter efficiency is unaffected by moisture.
| |
| Periodic operation ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action.
| |
| The system initiates and maintains a negative air pressure in the reactor building annulus by means of filtered exhaust ventilation of the reactor building annulus following receipt of a safety injection (SI) signal. The system is described in Reference 2. The AVS reduces the radioactive content in the annulus atmosphere following a DBA. Loss of the AVS could cause site boundary doses, in the event of a DBA, to exceed the values given in the licensing basis.
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| APPLICABLE The AVS design basis is established by the consequences of the SAFETY ANALYSES limiting DBA, which is a LOCA. The accident analysis (Ref. 3) assumes that only one train of the AVS is functional due to a single failure that disables the other train. The accident analysis accounts for the reduction in airborne radioactive material provided by the remaining one train of this filtration system. The amount of fission products available for release from containment is determined for a LOCA.
| |
| The modeled AVS actuation in the safety analyses is based upon a worst case response time following an SI initiated at the limiting setpoint. The CANVENT computer code is used to determine the total time required to achieve a negative pressure in the annulus under accident conditions.
| |
| The response time considers signal delay, diesel generator startup and sequencing time, system startup time, and the time for the system to attain the required pressure.
| |
| The AVS satisfies Criterion 3 of 10 CFR 50.36 (Ref. 4).
| |
| LCO In the event of a DBA, one AVS train is required to provide the minimum iodine removal assumed in the safety analysis. Two trains of the AVS must be OPERABLE to ensure that at least one train will operate, assuming that the other train is disabled by a single active failure.
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| Catawba Units 1 and 2 B 3.6.10-2 Revision No. 5
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| | |
| AVS B 3.6.10 BASES APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could lead to fission product release to containment that leaks to the reactor building. The large break LOCA, on which this system's design is based, is a full power event. Less severe LOCAs and leakage still require the system to be OPERABLE throughout these MODES. The probability and severity of a LOCA decrease as core power and Reactor Coolant System pressure decrease. With the reactor shut down, the probability of release of radioactivity resulting from such an accident is low.
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| In MODES 5 and 6, the probability and consequences of a DBA are low due to the pressure and temperature limitations in these MODES. Under these conditions, the AVS is not required to be OPERABLE.
| |
| ACTIONS A.1 With one AVS train inoperable, the inoperable train must be restored to OPERABLE status within 7 days. The 7 day Completion Time is based on consideration of such factors as the availability of the OPERABLE redundant AVS train and the low probability of a DBA occurring during this period. The Completion Time is adequate to make most repairs.
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| B.1 and B.2 If the AVS train cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours and to MODE 5 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
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| Catawba Units 1 and 2 B 3.6.10-3 Revision No. 5
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| | |
| AVS B 3.6.10 BASES SURVEILLANCE SR 3.6.10.1 REQUIREMENTS Operating each AVS train from the control room with flow through the HEPA filters and carbon adsorbers ensures that all trains are OPERABLE and that all associated controls are functioning properly. Operation for 15 continuous minutes demonstrates OPERABILITY of the system.
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| Periodic operation ensures that blockage, fan or motor failure, or excessive vibration can be detected for correction action. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
| |
| SR 3.6.10.2 This SR verifies that the required AVS filter testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The AVS filter tests are in accordance with Regulatory Guide 1.52 (Ref. 5). The VFTP includes testing HEPA filter performance, carbon adsorber efficiency, system flow rate, and the physical properties of the activated carbon (general use and following specific operations). Specific test frequencies and additional information are discussed in detail in the VFTP.
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| Catawba Units 1 and 2 B 3.6.10-4 Revision No. 5
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| | |
| AVS B 3.6.10 BASES SURVEILLANCE REQUIREMENTS (continued)
| |
| SR 3.6.10.3 The automatic startup on a safety injection signal ensures that each AVS train responds properly. The SR excludes automatic dampers and valves that are locked, sealed, or otherwise secured in the actuated position.
| |
| The SR does not apply to dampers or valves that are locked, sealed, or otherwise secured in the actuated position since the affected dampers or valves were verified to be in the actuated position prior to being locked, sealed, or otherwise secured. Placing an automatic valve or damper in a locked, sealed, or otherwise secured position requires an assessment of the operability of the system or any supported systems, including whether it is necessary for the valve or damper to be repositioned to the non-actuated position to support the accident analysis. Restoration of an automatic valve or damper to the non-actuated position requires verification that the SR has been met within its required Frequency. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.6.10.4 The AVS filter cooling electric motor-operated bypass valves are tested to verify OPERABILITY. The valves are normally closed and may need to be opened from the control room to initiate miniflow cooling through a filter unit that has been shutdown following a DBA LOCA. Miniflow cooling may be necessary to limit temperature increases in the idle filter train due to decay heat from captured fission products. The SR excludes bypass valves that are locked, sealed, or otherwise secured in the open position. The SR does not apply to bypass valves that are locked, sealed, or otherwise secured in the open position since the affected bypass valves were verified to be in the open position prior to being locked, sealed, or otherwise secured. Placing a bypass valve in a locked, sealed, or otherwise secured position requires an assessment of the operability of the system or any supported systems, including whether it is necessary for the bypass valve to be closed to support the accident analysis.
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| Restoration of a bypass valves to the closed position requires verification that the SR has been met within its required Frequency. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| Catawba Units 1 and 2 B 3.6.10-5 Revision No. 5
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| | |
| AVS B 3.6.10 BASES SR 3.6.10.5 The proper functioning of the fans, dampers, filters, adsorbers, etc., as a system is verified by the ability of each train to produce the required system flow rate. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.6.10.6 The ability of the AVS train to produce the required negative pressure of at least -0.88 inch water gauge when corrected to elevation 564 feet ensures that the annulus negative pressure is at least -0.25 inch water gauge everywhere in the annulus. The -0.88 inch water gauge annulus pressure includes a correction for an outside air temperature induced hydrostatic pressure gradient of -0.63 inch water gauge. The negative Catawba Units 1 and 2 B 3.6.10-6 Revision No. 5
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| | |
| AVS B 3.6.10 BASES SURVEILLANCE REQUIREMENTS (continued) pressure prevents unfiltered leakage from the reactor building, since outside air will be drawn into the annulus by the negative pressure differential.
| |
| The CANVENT computer code is used to model the thermal effects of a LOCA on the annulus and the ability of the AVS to develop and maintain a negative pressure in the annulus after a design basis accident. The annulus pressure drawdown time during normal plant conditions is not an input to any dose analyses. Therefore, the annulus pressure drawdown time during normal plant conditions is insignificant.
| |
| The AVS trains are tested to ensure each train will function as required.
| |
| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. Furthermore, the SR interval was developed considering that the AVS equipment OPERABILITY is demonstrated at a 31 day Frequency by SR 3.6.10.1. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
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| REFERENCES 1. 10 CFR 50, Appendix A, GDC 41.
| |
| : 2. UFSAR, Sections 6.2.3 and 9.4.9.
| |
| : 3. UFSAR, Chapter 15.
| |
| : 4. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
| |
| : 5. Regulatory Guide 1.52, Revision 2.
| |
| : 6. Catawba Nuclear Station License Amendments 90/84 for Units 1/2, August 23, 1991.
| |
| : 7. NUREG-0800, Sections 6.2.3 and 6.5.3, Rev. 2, July 1981.
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| Catawba Units 1 and 2 B 3.6.10-7 Revision No. 5
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| | |
| Divider Barrier Integrity B 3.6.14 B 3.6 CONTAINMENT SYSTEMS B 3.6.14 Divider Barrier Integrity BASES BACKGROUND The divider barrier consists of the operating deck and associated seals, personnel access doors, and equipment hatches that separate the upper and lower containment compartments. Divider barrier integrity is necessary to minimize bypassing of the ice condenser by the hot steam and air mixture released into the lower compartment during a Design Basis Accident (DBA). This ensures that most of the gases pass through the ice bed, which condenses the steam and limits pressure and temperature during the accident transient. Limiting the pressure and temperature reduces the release of fission product radioactivity from containment to the environment in the event of a DBA.
| |
| In the event of a DBA, the ice condenser inlet doors (located below the operating deck) open due to the pressure rise in the lower compartment.
| |
| This allows air and steam to flow from the lower compartment into the ice condenser. The resulting pressure increase within the ice condenser causes the intermediate deck doors and the door panels at the top of the condenser to open, which allows the air to flow out of the ice condenser into the upper compartment. The ice condenses the steam as it enters, thus limiting the pressure and temperature buildup in containment. The divider barrier separates the upper and lower compartments and ensures that the steam is directed into the ice condenser. The ice is adequate to absorb the initial blowdown of steam and water from a DBA as well as the additional heat loads that would enter containment following the initial blowdown. The additional heat loads would come from the residual heat in the reactor core, the hot piping and components, and the secondary system, including the steam generators. During the post blowdown period, the Air Return System (ARS) returns upper compartment air through the divider barrier to the lower compartment. This serves to equalize pressures in containment and to continue circulating heated air and steam from the lower compartment through the ice condenser, where the heat is removed by the remaining ice. After its initiation, the containment spray system also aids in heat removal.
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| Catawba Units 1 and 2 B 3.6.14-1 Revision No. 3
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| | |
| Divider Barrier Integrity B 3.6.14 BASES BACKGROUND (continued)
| |
| Divider barrier integrity ensures that the high energy fluids released during a DBA would be directed through the ice condenser and that the ice condenser would function as designed if called upon to act as a passive heat sink following a DBA.
| |
| APPLICABLE Divider barrier integrity ensures the functioning of the ice condenser SAFETY ANALYSES to the limiting containment pressure and temperature that could be experienced following a DBA. The limiting DBAs considered relative to containment temperature and pressure are the loss of coolant accident (LOCA) and the steam line break (SLB). The LOCA and SLB are analyzed using computer codes designed to predict the resultant containment pressure and temperature transients. DBAs are assumed not to occur simultaneously or consecutively.
| |
| Although the ice condenser is a passive system that requires no electrical power to perform its function, the Containment Spray System, RHR Spray System, and the ARS also function to assist the ice bed in limiting pressures and temperatures. Therefore, the postulated DBAs are analyzed, with respect to containment Engineered Safety Feature (ESF) systems, assuming the loss of one ESF bus, which is the worst case single active failure and results in the inoperability of one train in the Containment Spray System, RHR Spray System, and the ARS.
| |
| Additionally, a 5.0 ft2 opening is conservatively assumed to exist in the divider barrier in the LOCA and SLB DBA analyses.
| |
| The limiting DBA analyses (Ref. 1) show that the maximum peak containment pressure results from the LOCA analysis and is calculated to be less than the containment design pressure. The maximum peak containment temperature results from the SLB analysis and is discussed in the Bases for LCO 3.6.5, "Containment Air Temperature."
| |
| In addition to calculating the overall peak containment pressures, the DBA analyses include calculation of the transient differential pressures that occur across subcompartment walls during the initial blowdown phase of the accident transient. The internal containment walls and structures are designed to withstand these local transient pressure differentials for the limiting DBAs.
| |
| The divider barrier satisfies Criterion 3 of 10 CFR 50.36 (Ref. 2).
| |
| Catawba Units 1 and 2 B 3.6.14-2 Revision No. 3
| |
| | |
| Divider Barrier Integrity B 3.6.14 BASES LCO This LCO establishes the minimum equipment requirements to ensure that the divider barrier performs its safety function of ensuring that bypass leakage, in the event of a DBA, does not exceed the bypass leakage assumed in the accident analysis. Included are the requirements that the personnel access doors and equipment hatches in the divider barrier are OPERABLE and closed and that the divider barrier seal is properly installed and has not degraded with time. An exception to the requirement that the doors be closed is made to allow personnel transit entry through the divider barrier. The basis of this exception is the assumption that, for personnel transit, the time during which a door is open will be short (i.e., shorter than the Completion Time of 1 hour for Condition A). The divider barrier functions with the ice condenser to limit the pressure and temperature that could be expected following a DBA.
| |
| APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could cause an increase in containment pressure and temperature requiring the integrity of the divider barrier.
| |
| Therefore, the LCO is applicable in MODES 1, 2, 3, and 4.
| |
| The probability and consequences of these events in MODES 5 and 6 are low due to the pressure and temperature limitations of these MODES. As such, divider barrier integrity is not required in these MODES.
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| ACTIONS A.1 If one or more personnel access doors or equipment hatches (other than the pressurizer enclosure hatch) are inoperable or open, except for personnel transit entry, 1 hour is allowed to restore the door(s) and equipment hatches to OPERABLE status and the closed position. The 1 hour Completion Time is consistent with LCO 3.6.1, "Containment,"
| |
| which requires that containment be restored to OPERABLE status within 1 hour.
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| Condition A has been modified by a Note to provide clarification that, for this LCO, separate Condition entry is allowed for each personnel access door or equipment hatch.
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| B.1 If the pressurizer enclosure hatch is inoperable or open, 6 hours are allowed to restore the hatch to OPERABLE status and the closed position. The 6 hour completion time is based on the need to perform Catawba Units 1 and 2 B 3.6.14-3 Revision No. 3
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| | |
| Divider Barrier Integrity B 3.6.14 BASES ACTIONS (continued) inspections in the pressurizer compartment during power operation and analysis performed that shows an open hatch (7.5 ft2 bypass area) during a DBA does not impact the design pressure or temperature of the containment.
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| C.1 If the divider barrier seal is inoperable, 1 hour is allowed to restore the seal to OPERABLE status. The 1 hour Completion Time is consistent with LCO 3.6.1, which requires that containment be restored to OPERABLE status within 1 hour.
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| D.1 and D.2 If divider barrier integrity cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours and to MODE 5 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
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| SURVEILLANCE SR 3.6.14.1 REQUIREMENTS Verification, by visual inspection, that all personnel access doors and equipment hatches between the upper and lower containment compartments are closed provides assurance that divider barrier integrity is maintained prior to the reactor being taken from MODE 5 to MODE 4.
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| This SR is necessary because many of the doors and hatches may have been opened for maintenance during the shutdown.
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| SR 3.6.14.2 Verification, by visual inspection, that the personnel access door and equipment hatch seals, sealing surfaces, and alignments are acceptable provides assurance that divider barrier integrity is maintained. This Catawba Units 1 and 2 B 3.6.14-4 Revision No. 3
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| | |
| Divider Barrier Integrity B 3.6.14 BASES SURVEILLANCE REQUIREMENTS (continued) inspection cannot be made when the door or hatch is closed. Therefore, SR 3.6.14.2 is required for each door or hatch that has been opened, prior to the final closure. Some doors and hatches may not be opened for long periods of time. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.6.14.3 Verification, by visual inspection, after each opening of a personnel access door or equipment hatch that it has been closed makes the operator aware of the importance of closing it and thereby provides additional assurance that divider barrier integrity is maintained while in applicable MODES.
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| SR 3.6.14.4 Conducting periodic physical property tests on divider barrier seal test coupons provides assurance that the seal material has not degraded in the containment environment, including the effects of irradiation with the reactor at power. The required tests include a tensile strength test. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.6.14.5 Visual inspection of the seal around the perimeter provides assurance that the seal is properly secured in place. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| REFERENCES 1. UFSAR, Section 6.2.
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| : 2. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| : 3. UFSAR Table 18-1.
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| Catawba Units 1 and 2 B 3.6.14-5 Revision No. 3
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| Reactor Building B 3.6.16 B 3.6 CONTAINMENT SYSTEMS B 3.6.16 Reactor Building BASES BACKGROUND The reactor building is a concrete structure that surrounds the steel containment vessel. Between the containment vessel and the reactor building inner wall is an annular space that collects containment leakage that may occur following a loss of coolant accident (LOCA). This space also allows for periodic inspection of the outer surface of the steel containment vessel.
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| The Annulus Ventilation System (AVS) establishes a negative pressure in the annulus between the reactor building and the steel containment vessel under post-accident conditions. Filters in the system then control the release of radioactive contaminants to the environment. The reactor building is required to be OPERABLE to ensure retention of containment leakage and proper operation of the AVS. To ensure the retention of containment leakage within the reactor building:
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| : a. The door in each access opening is closed except when the access opening is being used for normal transit entry and exit, and
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| : b. The sealing mechanism associated with each penetration (e.g.,
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| welds, bellows, or O-rings) is OPERABLE.
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| APPLICABLE The design basis for reactor building OPERABILITY is a LOCA.
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| SAFETY ANALYSES Maintaining reactor building OPERABILITY ensures that the release of radioactive material from the containment atmosphere is restricted to those leakage paths and associated leakage rates assumed in the accident analyses.
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| The reactor building satisfies Criterion 3 of 10 CFR 50.36 (Ref. 1).
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| LCO Reactor building OPERABILITY must be maintained to ensure proper operation of the AVS and to limit radioactive leakage from the containment to those paths and leakage rates assumed in the accident analyses.
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| Catawba Units 1 and 2 B 3.6.16-1 Revision No. 4
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| | |
| Reactor Building B 3.6.16 BASES APPLICABILITY Maintaining reactor building OPERABILITY prevents leakage of radioactive material from the reactor building. Radioactive material may enter the reactor building from the containment following a LOCA.
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| Therefore, reactor building OPERABILITY is required in MODES 1, 2, 3, and 4 when a LOCA or rod ejection accident could release radioactive material to the containment atmosphere.
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| In MODES 5 and 6, the probability and consequences of these events are low due to the Reactor Coolant System temperature and pressure limitations in these MODES. Therefore, reactor building OPERABILITY is not required in MODE 5 or 6.
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| ACTIONS A.1 In the event reactor building OPERABILITY is not maintained, reactor building OPERABILITY must be restored within 24 hours. Twenty-four hours is a reasonable Completion Time considering the limited leakage design of containment and the low probability of a Design Basis Accident occurring during this time period.
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| B.1 and B.2 If the reactor building cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours and to MODE 5 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
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| SURVEILLANCE SR 3.6.16.1 REQUIREMENTS Maintaining reactor building OPERABILITY requires maintaining the door in the access opening closed, except when the access opening is being used for normal transit entry and exit. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| Catawba Units 1 and 2 B 3.6.16-2 Revision No. 4
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| Reactor Building B 3.6.16 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.6.16.2 The annulus vacuum decay test is performed to verify the reactor building is OPERABLE. A minimum annulus vacuum decay time of 87 seconds ensures that the reactor building design outside air inleakage rate is d 2000 cfm at an annulus differential pressure of -1.0 inch water gauge. Higher reactor building annulus outside air inleakage rates correlate to less holdup, mixing, and filtration of radiological effluents which increase offsite and operator doses.
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| The vacuum decay test is performed by isolating the pressure transmitter and starting the AVS fan to draw down the annulus pressure to a significant vacuum. Isolating the transmitter enables the fan to reduce the annulus pressure below the normal setpoint. The fan is then secured and the time it takes for the annulus pressure to decay or increase from -3.5 inches water gauge to -0.5 inch water gauge is measured. The time required for the pressure in the annulus to increase from -3.5 inches water gauge to -0.5 inch water gauge is known as the vacuum decay time.
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| The reactor building annulus outside air inleakage is an input to the CANVENT computer code, which provides input to the dose analyses.
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| The CANVENT computer code is used to model the thermal effects of a LOCA on the annulus and the ability of the AVS to develop and maintain a negative pressure in the annulus after a design basis accident. The code also determines AVS exhaust and recirculation airflow rates following a LOCA. The results of the CANVENT analysis for annulus conditions and AVS response to the LOCA also are used for the rod ejection accident.
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| The 2000 cfm at -1.0 inch water gauge reactor building annulus outside air inleakage rate is conservatively corrected for ambient temperature and pressure as well as annulus differential pressure conditions prior to use as an input to the CANVENT computer code. The CANVENT results are then used as an input to the dose analyses.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| Catawba Units 1 and 2 B 3.6.16-3 Revision No. 4
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| Reactor Building B 3.6.16 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.6.16.3 This SR would give advance indication of gross deterioration of the concrete structural integrity of the reactor building. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| REFERENCES 1. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| : 2. UFSAR, Sections 6.2.3 and 6.2.6.5.
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| : 3. Not used.
| |
| : 4. UFSAR Table 18-1.
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| Catawba Units 1 and 2 B 3.6.16-4 Revision No. 4
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| CVIWS B 3.6.17 B 3.6 CONTAINMENT SYSTEMS B 3.6.17 Containment Valve Injection Water System (CVIWS)
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| BASES BACKGROUND The CVIWS is required by 10 CFR 50, Appendix A, GDC 54, "Piping Systems Penetrating Containment" (Ref. 1), to ensure a water seal to a specific class of containment isolation valves (double disc gate valves) during a LOCA, to prevent leakage of containment atmosphere through the gate valves.
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| The CVIWS is designed to inject water between the two seating surfaces of double disc gate valves used for Containment isolation. The injection pressure is higher than Containment design peak pressure during a LOCA. This will prevent leakage of the Containment atmosphere through the gate valves, thereby reducing potential offsite dose below the values specified by 10 CFR 50.67 limits following the postulated accident.
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| During normal power operation, the system is in a standby mode and does not perform any function. During accident situations the CVIWS is activated to perform its safety related function, thus limiting the release of containment atmosphere past specific containment isolation valves, in order to mitigate the consequences of a LOCA. Containment isolation valves, for systems which are not used to mitigate the consequences of an accident, will be supplied with CVIWS seal water upon receipt of a Phase A isolation signal.
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| The system consists of two independent, redundant trains; one supplying gate valves that are powered by the A train diesel and the other supplying gate valves powered by the B train diesel. This separation of trains prevents the possibility of both containment isolation valves not sealing due to a single failure.
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| Each train consists of a surge chamber which is filled with water and pressurized with nitrogen. One main header exits the chamber and splits into several headers. An air operated valve, located in the main header before any of the branch headers, will open after a 60 second delay on a Phase A isolation signal. Each of the branch headers supply injection water to containment isolation valves located in the same general location, and close on the same engineered safety signal. The delay for the opening of the air operated valves is to allow adequate time for the slowest gate valve to close, before water is injected into the valve seat.
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| Catawba Units 1 and 2 B 3.6.17-1 Revision No. 5
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| | |
| CVIWS B 3.6.17 BASES BACKGROUND (continued)
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| Makeup water is provided from the Demineralized Water Storage Tank for testing and adding water to the surge chamber during normal plant operation. Assured water is provided from the essential header of the Nuclear Service Water System (NSWS). This supply is assured for at least 30 days following a postulated accident. If the water level in the surge chamber drops below the low-low level or if the surge chamber nitrogen pressure drops below the low-low pressure after a Phase A isolation signal, an air operated valve in the supply line from the NSWS will automatically open and remains open, assuring makeup to the CVIWS at a pressure greater than 110% of peak Containment accident pressure.
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| Overpressure protection is provided to relieve the pressure buildup caused by the heatup of a trapped volume of incompressible fluid between two positively closing valves (due to containment temperature transient) back into containment where an open relief path exists.
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| APPLICABLE The CVIWS design basis is established by the consequences of the SAFETY ANALYSES limiting DBA, which is a LOCA. The accident analysis (Ref. 2) assumes that only one train of the CVIWS is functional due to a single failure that disables the other train. Makeup water can be assured from the NSWS for 30 days following a postulated LOCA.
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| The CVIWS satisfies Criterion 3 of 10 CFR 50.36 (Ref. 3).
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| LCO In the event of a DBA, one CVIWS train is required to provide the seal injection assumed in the safety analysis. Two trains of the CVIWS must be OPERABLE to ensure that at least one train will operate, assuming that the other train is disabled by a single active failure.
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| Catawba Units 1 and 2 B 3.6.17-2 Revision No. 5
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| | |
| CVIWS B 3.6.17 BASES APPLICABILITY In MODES 1, 2, 3, and 4, a DBA could require a containment isolation.
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| The large break LOCA, on which this system's design is based, is a full power event. Less severe LOCAs and leakage still require the system to be OPERABLE throughout these MODES. The probability and severity of a LOCA decrease as core power and Reactor Coolant System pressure decrease. With the reactor shut down, the probability of release of radioactivity resulting from such an accident is low.
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| In MODES 5 and 6, the probability and consequences of a DBA are low due to the pressure and temperature limitations in these MODES. Under these conditions, the CVIWS is not required to be OPERABLE.
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| ACTIONS A.1 With one CVIWS train inoperable, the inoperable train must be restored to OPERABLE status within 7 days. The components in this degraded condition are capable of providing 100% of the valve injection needs after a DBA. The 7 day Completion Time is based on consideration of such factors as the availability of the OPERABLE redundant CVIWS train and the low probability of a DBA occurring during this period. The Completion Time is adequate to make most repairs.
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| B.1 and B.2 If the CVIWS train cannot be restored to OPERABLE status within the required Completion Time, the plant must be brought to a MODE in which the LCO does not apply. To achieve this status, the plant must be brought to at least MODE 3 within 6 hours and to MODE 5 within 36 hours. The allowed Completion Times are reasonable, based on operating experience, to reach the required plant conditions from full power conditions in an orderly manner and without challenging plant systems.
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| Catawba Units 1 and 2 B 3.6.17-3 Revision No. 5
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| | |
| CVIWS B 3.6.17 BASES SURVEILLANCE SR 3.6.17.1 REQUIREMENTS Verifying each CVIWS train is pressurized to t 36.4 psig ensures the system can meet the design basis. Assured water is provided from the essential header of the NSWS. The 31 day Frequency was developed in consideration of the known reliability of the system and the two train redundancy available.
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| SR 3.6.17.2 This SR verifies that each CVIWS train can perform its required function when needed by measuring the existing conditions for the valves being injected. Gate valves served by the CVIWS do not receive a conventional Type C leak rate test using air as a test medium.
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| The containment isolation valves served by the CVIWS may be tested individually or simultaneously. Containment isolation valves are leak rate tested by this SR by injecting seal water from the CVIWS to the containment isolation valves. With the containment isolation valve closed, the leakage is determined by measuring flow rate of seal water out of the containment valve injection water surge chamber.
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| The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage.
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| Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore, the Frequency was concluded to be acceptable from a reliability standpoint.
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| Furthermore, the SR interval was developed considering that the CVIWS OPERABILITY is demonstrated at a 31 day Frequency by SR 3.6.17.1.
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| SR 3.6.17.3 This SR ensures that each CVIWS train responds properly to the appropriate actuation signal. The Surveillance verifies that the automatic valves actuate to their correct position. The SR excludes automatic valves that are locked, sealed, or otherwise secured in the actuated position. The SR does not apply to valves that are locked, sealed, or otherwise secured in the actuated position since the affected valves were verified to be in the actuated position prior to being locked, sealed, or otherwise secured. Placing an automatic valve in a locked, sealed, or otherwise secured position requires an assessment of the operability of the system or any supported systems, including whether it is necessary for the valve to be repositioned to the non-actuated position to support the accident analysis. Restoration of an automatic valve to the non-actuated position requires verification that the SR has been met within its required Catawba Units 1 and 2 B 3.6.17-4 Revision No. 5
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| CVIWS B 3.6.17 BASES SURVEILLANCE SR 3.6.17.3 (continued)
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| REQUIREMENTS Frequency. The 18 month Frequency is based on the need to perform this Surveillance under the conditions that apply during a plant outage.
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| Operating experience has shown that these components usually pass the Surveillance when performed at the 18 month Frequency. Therefore the Frequency was concluded to be acceptable from a reliability standpoint.
| |
| REFERENCES 1. 10 CFR 50, Appendix A, GDC 54.
| |
| : 2. UFSAR, Section 6.2.
| |
| : 3. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| : 4. 10 CFR 50.67.
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| Catawba Units 1 and 2 B 3.6.17-5 Revision No. 5
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| | |
| AFW System B 3.7.5 B 3.7 PLANT SYSTEMS B 3.7.5 Auxiliary Feedwater (AFW) System BASES BACKGROUND The AFW System automatically supplies feedwater to the steam generators to remove decay heat from the Reactor Coolant System upon the loss of normal feedwater supply. The AFW pumps take suction through suction lines from the condensate storage system (CSS)
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| (LCO 3.7.6) and pump to the steam generator secondary side. The normal supply of water to the AFW pumps is from the condensate system. The supply valves are open with power removed from the valve operator. The assured source of water to the AFW System is supplied by the Nuclear Service Water System. The turbine and motor driven pump discharge lines to each individual steam generator join into a single line outside containment. These individual lines penetrate the containment and enter each steam generator through the auxiliary feedwater nozzle.
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| The steam generators function as a heat sink for core decay heat. The heat load is dissipated by releasing steam to the atmosphere from the steam generators via the main steam safety valves (MSSVs) (LCO 3.7.1) or SG PORVs (LCO 3.7.4). If the main condenser is available, steam may be released via the steam dump valves and recirculated to the hotwell.
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| The AFW System consists of two motor driven AFW pumps and one steam turbine driven pump configured into three trains. Each of the motor driven pumps supply 100% of the flow requirements to two steam generators, although each pump has the capability to be realigned to feed other steam generators. The turbine driven pump provides 200% of the flow requirements and supplies water to all four steam generators. Travel stops are set on the steam generator flow control valves such that the pumps can supply the minimum flow required without exceeding the maximum flow allowed. The pumps are equipped with independent recirculation lines to prevent pump operation against a closed system.
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| Each motor driven AFW pump is powered from an independent Class 1E power supply. The steam turbine driven AFW pump receives steam from two main steam lines upstream of the main steam isolation valves. Each of the steam feed lines will supply 100% of the requirements of the turbine driven AFW pump.
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| Catawba Units 1 and 2 B 3.7.5-1 Revision No. 6
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| | |
| AFW System B 3.7.5 BASES BACKGROUND (continued)
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| The AFW System is capable of supplying feedwater to the steam generators during normal unit startup, shutdown, and hot standby conditions. One turbine driven pump at full flow is sufficient to remove decay heat and cool the unit to residual heat removal (RHR) entry conditions. During unit cooldown, SG pressures and Main Steam pressures decrease simultaneously. Thus, the turbine driven AFW pump with a reduced steam supply pressure remains fully capable of providing flow to all SGs. Thus, the requirement for diversity in motive power sources for the AFW System is met.
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| The AFW System is designed to supply sufficient water to the steam generator(s) to remove decay heat with steam generator pressure at the lowest setpoint of the MSSVs plus 3% accumulation. Subsequently, the AFW System supplies sufficient water to cool the unit to RHR entry conditions, with steam released through the SG PORVs or MSSVs.
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| The motor driven AFW pumps actuate automatically on steam generator water level low-low in 1 out of 4 steam generators by the ESFAS (LCO 3.3.2). The motor driven pumps also actuate on loss of offsite power, safety injection, and trip of all MFW pumps. The turbine driven AFW pump actuates automatically on steam generator water level low-low in 2 out of 4 steam generators and on loss of offsite power.
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| The AFW System is discussed in the UFSAR, Section 10.4.9 (Ref. 1).
| |
| APPLICABLE The AFW System mitigates the consequences of any event with loss SAFETY ANALYSES of normal feedwater.
| |
| The design basis of the AFW System is to supply water to the steam generator to remove decay heat and other residual heat by delivering at least the minimum required flow rate to the steam generators at pressures corresponding to the lowest steam generator safety valve set pressure plus 3%.
| |
| In addition, the AFW System must supply enough makeup water to replace steam generator secondary inventory lost as the unit cools to MODE 4 conditions. Sufficient AFW flow must also be available to account for flow losses such as pump recirculation valve leakage and line breaks.
| |
| The limiting Design Basis Accidents (DBAs) and transients for the AFW System are as follows:
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| Catawba Units 1 and 2 B 3.7.5-2 Revision No. 6
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| | |
| AFW System B 3.7.5 BASES APPLICABLE SAFETY ANALYSES (continued)
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| : a. Feedwater Line Break (FWLB); and
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| : b. Loss of MFW.
| |
| In addition, the minimum available AFW flow and system characteristics are considered in the analysis of a small break loss of coolant accident (LOCA) and events that could lead to steam generator tube bundle uncovery for dose considerations.
| |
| A range of AFW flows is considered for the analyzed accidents, with the Main Steam Line Break being the most limiting for the maximum AFW flowrate.
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| The AFW System design is such that it can perform its function following a FWLB between the steam generator and the downstream check valve, combined with a loss of offsite power following turbine trip, and a single active failure of the steam turbine driven AFW pump. In such a case, one motor driven AFW pump would deliver to the broken MFW header at the pump runout flow until the problem was detected, and flow terminated by the operator. Sufficient flow would be delivered to the intact steam generators by the redundant AFW pump.
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| The ESFAS automatically actuates the AFW turbine driven pump and associated power operated valves and controls when required to ensure an adequate feedwater supply to the steam generators during loss of offsite power.
| |
| The AFW System satisfies the requirements of Criterion 3 of 10 CFR 50.36 (Ref. 2).
| |
| LCO This LCO provides assurance that the AFW System will perform its design safety function to mitigate the consequences of accidents that could result in overpressurization of the reactor coolant pressure boundary. Three independent AFW pumps in three diverse trains are required to be OPERABLE to ensure the availability of RHR capability for all events accompanied by a loss of offsite power and a single failure.
| |
| This is accomplished by powering two of the pumps from independent emergency buses. The third AFW pump is powered by a different means, a steam driven turbine supplied with steam from a source that is not isolated by closure of the MSIVs.
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| Catawba Units 1 and 2 B 3.7.5-3 Revision No. 6
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| | |
| AFW System B 3.7.5 BASES LCO (continued)
| |
| The AFW System is configured into three trains. The AFW System is considered OPERABLE when the components and flow paths required to provide redundant AFW flow to the steam generators are OPERABLE.
| |
| This requires that the two motor driven AFW pumps be OPERABLE in two diverse paths, each supplying AFW to separate steam generators.
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| The turbine driven AFW pump is required to be OPERABLE with redundant steam supplies from two main steam lines upstream of the MSIVs, and shall be capable of supplying AFW to any of the steam generators. The piping, valves, instrumentation, and controls in the required flow paths also are required to be OPERABLE. The NSWS assured source of water supply is configured into two trains. The turbine driven AFW pump receives NSWS from both trains of NSWS, therefore, the loss of one train of assured source renders only one AFW train inoperable. The remaining NSWS train provides an OPERABLE assured source to the other motor driven pump and the turbine driven pump.
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| The LCO is modified by a Note indicating that one AFW train, which includes a motor driven pump, is required to be OPERABLE in MODE 4.
| |
| This is because of the reduced heat removal requirements and short period of time in MODE 4 during which the AFW is required and the insufficient steam available in MODE 4 to power the turbine driven AFW pump.
| |
| APPLICABILITY In MODES 1, 2, and 3, the AFW System is required to be OPERABLE in the event that it is called upon to function when the MFW is lost. In addition, the AFW System is required to supply enough makeup water to replace the steam generator secondary inventory, lost as the unit cools to MODE 4 conditions.
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| In MODE 4 the AFW System may be used for heat removal via the steam generators.
| |
| In MODE 5 or 6, the steam generators are not normally used for heat removal, and the AFW System is not required.
| |
| ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable AFW train when entering MODE 1. There is an increased risk associated with entering MODE 1 with an AFW train inoperable and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not Catawba Units 1 and 2 B 3.7.5-4 Revision No. 6
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| | |
| AFW System B 3.7.5 BASES ACTIONS (continued) be applied in this circumstance.
| |
| A.1 If one of the two steam supplies to the turbine driven AFW train is inoperable, or if a turbine driven pump is inoperable while in MODE 3 immediately following refueling, action must be taken to restore the inoperable equipment to an OPERABLE status within 7 days. The 7 day Completion Time is reasonable, based on the following reasons:
| |
| : a. For the inoperability of a steam supply to the turbine driven AFW pump, the 7 day Completion Time is reasonable since there is a redundant steam supply line for the turbine driven pump.
| |
| : b. For the inoperability of a turbine driven AFW pump while in MODE 3 immediately subsequent to a refueling, the 7 day Completion Time is reasonable due to the minimal decay heat levels in this situation.
| |
| : c. For both the inoperability of a steam supply line to the turbine driven pump and an inoperable turbine driven AFW pump while in MODE 3 immediately following a refueling, the 7 day Completion Time is reasonable due to the availability of redundant OPERABLE motor driven AFW pumps; and due to the low probability of an event requiring the use of the turbine driven AFW pump.
| |
| Condition A is modified by a Note which limits the applicability of the Condition to when the unit has not entered MODE 2 following a refueling.
| |
| Condition A allows the turbine driven AFW pump to be inoperable for 7 days vice the 72 hour Completion Time in Condition B. This longer Completion Time is based on the reduced decay heat following refueling and prior to the reactor being critical.
| |
| B.1 With one of the required AFW trains (pump or flow path) inoperable in MODE 1, 2, or 3 for reasons other than Condition A, action must be taken to restore OPERABLE status within 72 hours. This Condition includes the loss of two steam supply lines to the turbine driven AFW pump. The 72 hour Completion Time is reasonable, based on redundant capabilities afforded by the AFW System, time needed for repairs, and the low probability of a DBA occurring during this time period.
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| Catawba Units 1 and 2 B 3.7.5-5 Revision No. 6
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| | |
| AFW System B 3.7.5 BASES ACTIONS (continued)
| |
| C.1 and C.2 When Required Action A.1 or B.1 cannot be completed within the required Completion Time, or if two AFW trains are inoperable in MODE 1, 2, or 3, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours, and in MODE 4 within 12 hours.
| |
| 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.
| |
| In MODE 4 with two AFW trains inoperable, operation is allowed to continue because only one motor driven pump AFW train is required in accordance with the Note that modifies the LCO. Although not required, the unit may continue to cool down and initiate RHR.
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| D.1 If all three AFW trains are inoperable in MODE 1, 2, or 3, the unit is in a seriously degraded condition with no safety related means for conducting a cooldown, and only limited means for conducting a cooldown with nonsafety related equipment. In such a condition, the unit should not be perturbed by any action, including a power change, that might result in a trip. The seriousness of this condition requires that action be started immediately to restore one AFW train to OPERABLE status.
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| Required Action D.1 is modified by a Note indicating that all required MODE changes or power reductions are suspended until one AFW train is restored to OPERABLE status. In this case, LCO 3.0.3 is not applicable because it could force the unit into a less safe condition.
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| E.1 In MODE 4, either the reactor coolant pumps or the RHR loops can be used to provide forced circulation. This is addressed in LCO 3.4.6, "RCS LoopsMODE 4." With one required AFW train inoperable, action must be taken to immediately restore the inoperable train to OPERABLE status. The immediate Completion Time is consistent with LCO 3.4.6.
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| Catawba Units 1 and 2 B 3.7.5-6 Revision No. 6
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| AFW System B 3.7.5 BASES SURVEILLANCE SR 3.7.5.1 REQUIREMENTS Verifying the correct alignment for manual, power operated, and automatic valves in the AFW System water and steam supply flow paths provides assurance that the proper flow paths will exist for AFW operation. This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since they are verified to be in the correct position prior to locking, sealing, or securing. This SR also does not apply to valves that cannot be inadvertently misaligned, such as check valves. This Surveillance does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position. The SR is also modified by a note that excludes automatic valves when THERMAL POWER is
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| < 10% RTP. Some automatic valves may be in a throttled position to support low power operation.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.7.5.2 Verifying that each AFW pump's developed head at the flow test point is greater than or equal to the required developed head ensures that AFW pump performance has not degraded during the cycle. Flow and differential head are normal tests of centrifugal pump performance required by the ASME Code (Ref. 3). Because it is undesirable to introduce cold AFW into the steam generators while they are operating, this testing is performed on recirculation flow. This test confirms one point on the pump design curve and is indicative of overall performance. Such inservice tests confirm component OPERABILITY, trend performance, and detect incipient failures by indicating abnormal performance.
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| Performance of inservice testing as discussed in the ASME Code (Ref. 3) and the INSERVICE TESTING PROGRAM satisfies this requirement.
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| This SR is modified by a Note indicating that the SR should be deferred until suitable test conditions are established. This deferral is required because there is insufficient steam pressure to perform the test.
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| SR 3.7.5.3 This SR verifies that AFW can be delivered to the appropriate steam generator in the event of any accident or transient that generates an ESFAS, by demonstrating that each automatic valve in the flow path actuates to its correct position on an actual or simulated actuation signal.
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| This Surveillance is not required for valves that are locked, sealed, or Catawba Units 1 and 2 B 3.7.5-7 Revision No. 6
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| AFW System B 3.7.5 BASES SURVEILLANCE REQUIREMENTS (continued) otherwise secured in the required position under administrative controls.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| This SR is modified by a Note that states the SR is not required in MODE
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| : 4. In MODE 4, the required AFW train may already be aligned and operating.
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| SR 3.7.5.4 This SR verifies that the AFW pumps will start in the event of any accident or transient that generates an ESFAS by demonstrating that each AFW pump starts automatically on an actual or simulated actuation signal in MODES 1, 2, and 3. In MODE 4, the required pump may already be operating and the autostart function is not required. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| This SR is modified by two Notes. Note 1 indicates that the SR can be deferred until suitable test conditions are established. This deferral is required because there is insufficient steam pressure to perform the test.
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| Note 2 states that the SR is not required in MODE 4. In MODE 4, the required pump may already be operating and the autostart function is not required. In MODE 4, the heat removal requirements would be less providing more time for operator action to manually start the required AFW pump if it were not in operation.
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| SR 3.7.5.5 This SR verifies that the AFW is properly aligned by verifying the flow paths from the CSS to each steam generator prior to entering MODE 2 after more than 30 days in MODE 5 or 6. OPERABILITY of AFW flow paths must be verified before sufficient core heat is generated that would require the operation of the AFW System during a subsequent shutdown.
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| The Frequency is reasonable, based on engineering judgment and other administrative controls that ensure that flow paths remain OPERABLE.
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| To further ensure AFW System alignment, flow path OPERABILITY is verified following extended outages to determine no misalignment of valves has occurred. This SR ensures that the flow path from the CSS to the steam generators is properly aligned.
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| Catawba Units 1 and 2 B 3.7.5-8 Revision No. 6
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| AFW System B 3.7.5 BASES REFERENCES 1. UFSAR, Section 10.4.9.
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| : 2. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| : 3. ASME Code for Operation and Maintenance of Nuclear Power Plants.
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| Catawba Units 1 and 2 B 3.7.5-9 Revision No. 6
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| CCW System B 3.7.7 B 3.7 PLANT SYSTEMS B 3.7.7 Component Cooling Water (CCW) System BASES BACKGROUND The CCW System provides a heat sink for the removal of process and operating heat from safety related components during a Design Basis Accident (DBA) or transient. During normal operation, the CCW System also provides this function for various nonessential components, as well as the spent fuel storage pool. The CCW System serves as a barrier to the release of radioactive byproducts between potentially radioactive systems and the Nuclear Service Water System (NSWS), and thus to the environment.
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| The CCW System is arranged as two independent, full capacity cooling loops, and has isolatable nonsafety related components. Each safety related train includes two 50% capacity pumps, surge tank, heat exchanger, piping, valves, and instrumentation. Each safety related train is powered from a separate bus. An open surge tank in the system provides sufficient inventory to protect the pumps from a lack of net positive suction head available (NPSHA) due to a moderate energy line break. The pumps have sufficient NPSHA with the surge tank empty provided the piping up to the tank is filled. The pumps on each train are automatically started on receipt of a safety injection signal, and all nonessential components are isolated.
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| Additional information on the design and operation of the system, along with a list of the components served, is presented in the UFSAR, Section 9.2 (Ref. 1). The principal safety related function of the CCW System is the removal of decay heat from the reactor via the Residual Heat Removal (RHR) System. This may be during a normal or post accident cooldown and shutdown.
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| APPLICABLE The safety related design basis function of the CCW System is to remove SAFETY ANALYSES waste heat from various components essential in mitigating design basis events which require Emergency Core Cooling System (ECCS) operation. The CCW System is also used to support normal operation.
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| The normal temperature of the CCW is 87qF, and, during unit cooldown to MODE 5 (Tcold < 200qF), a maximum temperature of 120qF is Catawba Units 1 and 2 B 3.7.7-1 Revision No. 3
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| | |
| CCW System B 3.7.7 BASES APPLICABLE SAFETY ANALYSES (continued) assumed (Ref. 1). This 120qF limit is to prevent thermal degradation of the large pump motors supplied with cooling water from the CCW System.
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| The CCW System is designed to perform its function with a single failure of any active component, assuming a loss of offsite power.
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| The CCW System also functions to cool the unit from RHR entry conditions (Tcold < 350qF), to MODE 5 (Tcold < 200qF), during normal and post accident operations. The time required to cool from 350qF to 200qF is a function of the number of CCW and RHR trains operating. One CCW train is sufficient to remove decay heat during subsequent operations with Tcold < 200qF. This assumes a maximum service water temperature of 100qF occurring simultaneously with the maximum heat loads on the system.
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| The CCW System satisfies Criterion 3 of 10 CFR 50.36 (Ref. 2).
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| LCO The CCW trains are independent of each other to the degree that each has separate controls and power supplies and the operation of one does not depend on the other. In the event of a DBA, one CCW train is required to provide the minimum heat removal capability assumed in the safety analysis for the systems to which it supplies cooling water. To ensure this requirement is met, two trains of CCW must be OPERABLE.
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| At least one CCW train will operate assuming the worst case single active failure occurs coincident with a loss of offsite power.
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| : 1. A CCW train is considered OPERABLE when:
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| : a. Both pumps and associated surge tank are OPERABLE; and
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| : b. The associated piping, valves, heat exchanger, and instrumentation and controls required to perform the safety related function are OPERABLE.
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| OR
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| : c. The trains Non-Essential Auxiliary Building Supply and Return header valves and the Non-Essential Reactor Building Supply and Return header valves are closed; and
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| : d. The trains ND heat exchanger cooling flow inlet isolation valve is Catawba Units 1 and 2 B 3.7.7-2 Revision No. 3
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| | |
| CCW System B 3.7.7 BASES LCO (continued) opened; and
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| : e. The flow path through the trains miniflow lines is isolated.
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| This alignment assures miniflow protection for the operating KC pumps through the trains ND heat exchanger and the essential header.
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| The isolation of CCW from other components or systems not required for safety may render those componenets or systems inoperable but does not affect the OPERABILITY of the CCW System.
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| APPLICABILITY In MODES 1, 2, 3, and 4, the CCW System is a normally operating system, which must be prepared to perform its post accident safety functions, primarily RCS heat removal, which is achieved by cooling the RHR heat exchanger.
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| In MODE 5 or 6, the requirements of the CCW System are determined by the systems it supports.
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| ACTIONS A.1 Required Action A.1 is modified by a Note indicating that the applicable Conditions and Required Actions of LCO 3.4.6, "RCS LoopsMODE 4,"
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| be entered if an inoperable CCW train results in an inoperable RHR loop.
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| This is an exception to LCO 3.0.6 and ensures the proper actions are taken for these components.
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| If one CCW train is inoperable, action must be taken to restore OPERABLE status within 72 hours. In this Condition, the remaining OPERABLE CCW train is adequate to perform the heat removal function.
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| The 72 hour Completion Time is reasonable, based on the redundant capabilities afforded by the OPERABLE train, and the low probability of a DBA occurring during this period.
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| B.1 and B.2 If the CCW train cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours and in MODE 5 within 36 hours. The allowed Completion Times are reasonable, based on operating Catawba Units 1 and 2 B 3.7.7-3 Revision No. 3
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| | |
| CCW System B 3.7.7 BASES ACTIONS (continued) experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
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| SURVEILLANCE SR 3.7.7.1 REQUIREMENTS This SR is modified by a Note indicating that the isolation of the CCW flow to individual components may render those components inoperable but does not affect the OPERABILITY of the CCW System.
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| Verifying the correct alignment for manual, power operated, and automatic valves in the CCW flow path to safety related equipment provides assurance that the proper flow paths exist for CCW operation.
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| This SR does not apply to valves that are locked, sealed, or otherwise secured in position, since these valves are verified to be in the correct position prior to locking, sealing, or securing. This SR also does not apply to valves that cannot be inadvertently misaligned, such as check valves. This Surveillance does not require any testing or valve manipulation; rather, it involves verification that those valves capable of being mispositioned are in the correct position.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.7.7.2 This SR verifies proper automatic operation of the CCW valves on an actual or simulated actuation safety injection, Phase 'A' Isolation, or Phase 'B' Isolation signal. The CCW System is a normally operating system that cannot be fully actuated as part of routine testing during normal operation. This Surveillance is not required for valves that are locked, sealed, or otherwise secured in the required position under administrative controls. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.7.7.3 This SR verifies proper automatic operation of the CCW pumps on an actual or simulated actuation signal. The CCW System is a normally Catawba Units 1 and 2 B 3.7.7-4 Revision No. 3
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| | |
| CCW System B 3.7.7 BASES SURVEILLANCE REQUIREMENTS (continued) operating system that cannot be fully actuated as part of routine testing during normal operation. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| REFERENCES 1. UFSAR, Section 9.2.
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| : 2. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| Catawba Units 1 and 2 B 3.7.7-5 Revision No. 3
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| SNSWP B 3.7.9 B 3.7 PLANT SYSTEMS B 3.7.9 Standby Nuclear Service Water Pond (SNSWP)
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| BASES BACKGROUND The SNSWP provides a heat sink for processing and operating heat from safety related components during a transient or accident, as well as during normal operation. This is done by utilizing the Nuclear Service Water System (NSWS) and the Component Cooling Water (CCW)
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| System.
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| The SNSWP has been defined as the water source, including necessary retaining structure, but not including the cooling water system intake structures as discussed in the UFSAR, Section 9.2 (Ref. 1). The principal functions of the SNSWP are the dissipation of sensible heat during normal operation, and dissipation of residual and sensible heat after an accident or normal operation.
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| The basic performance requirements are that a 30 day supply of water be available, and that the design basis temperatures of safety related equipment not be exceeded.
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| Additional information on the design and operation of the SNSWP can be found in Reference 1.
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| APPLICABLE The SNSWP is the seismically-assured sink for heat removed from the SAFETY ANALYSES reactor core following all accidents and anticipated operational occurrences in which the unit is cooled down and placed on residual heat removal (RHR) operation.
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| NSWS temperature influences containment pressure following a Loss of Coolant Accident and offsite dose following a Main Steam Line Break.
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| The containment peak pressure analysis can accommodate NSWS temperatures up to 100oF. The Main Steam Line Break dose analysis assumes an activity release from the steam generators for the time required to cool the Reactor Coolant System (RCS) to 210oF. The NSWS temperature assumed in the current analysis is 95.5oF. This assumption prevents the RCS cooldown time from exceeding that assumed in the current Main Steam Line Break dose analysis. Therefore, the Main Steam Line Break is limiting with respect to the assumed NSWS temperature.
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| Catawba Units 1 and 2 B 3.7.9-1 Revision No. 4
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| SNSWP B 3.7.9 BASES APPLICABLE SAFETY ANALYSES (continued)
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| To ensure that the assumptions related to NSWS temperature in the safety analyses remain valid and to ensure that long term NSWS temperature does not exceed the 100oF design basis of the NSWS components, a limit of 95oF is observed for the initial temperature of the SNSWP. This temperature is important in that it, in part, determines the capacity for energy removal from containment incorporated into the peak containment pressure analysis. NSWS temperature is also important in determining the time required to cool the RCS of a nuclear unit after the occurrence of an accident. This in turn determines the extent of releases of radioactivity to the environment following a Main Steam Line Break.
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| The peak containment pressure occurs when energy addition to containment (core decay heat) is balanced by energy removal from the Containment Spray and Component Cooling Water heat exchangers.
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| This balance is reached after the transition from injection to cold leg recirculation and after ice melt. Because of the effectiveness of the ice bed in condensing the steam which passes through it, containment pressure is insensitive to small variations in containment spray temperature prior to ice meltout.
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| Long term equipment qualification of safety related components required to mitigate the accident is based on a continuous, maximum NSWS supply temperature of 100oF or less.
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| To ensure that the NSWS initial temperature assumptions in the limiting analysis are met, Lake Wylie temperature is also monitored. During periods of time while Lake Wylie temperature is greater than 95.5qF, the emergency procedure for transfer of Emergency Core Cooling System (ECCS) flow paths to cold leg recirculation directs the operator to align both trains of containment spray to be cooled by loops of NSWS which are aligned to the SNSWP. Swapover to the SNSWP is required at 95.5qF rather than 95qF because Lake Wylie is not subject to subsequent heatup due to recirculation, as is the SNSWP. Therefore, the 100qF design basis maximum temperature is not approached.
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| The operating limits are based on conservative heat transfer analyses for the worst case accident. Reference 1 provides the details of the assumptions used in the analysis. The SNSWP is designed in accordance with Regulatory Guide 1.27 (Ref. 2), which requires a 30 day supply of cooling water in the SNSWP.
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| The SNSWP satisfies Criterion 3 of 10 CFR 50.36 (Ref. 3).
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| Catawba Units 1 and 2 B 3.7.9-2 Revision No. 4
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| | |
| SNSWP B 3.7.9 BASES LCO The SNSWP is required to be OPERABLE and is considered OPERABLE if it contains a sufficient volume of water at or below the maximum temperature that would allow the NSWS to operate for at least 30 days following the design basis accident without the loss of net positive suction head (NPSH), and without exceeding the maximum design temperature of the equipment served by the NSWS. To meet this condition, the SNSWP temperature should not exceed 95qF at 568 ft mean sea level and the level should not fall below 571 ft mean sea level during normal unit operation.
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| APPLICABILITY In MODES 1, 2, 3, and 4, the SNSWP is required to support the OPERABILITY of the equipment serviced by the SNSWP and required to be OPERABLE in these MODES.
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| In MODE 5 or 6, the requirements of the SNSWP are determined by the systems it supports.
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| ACTIONS A.1 If the SNSWP is inoperable the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours and in MODE 5 within 36 hours.
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| 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.
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| SURVEILLANCE SR 3.7.9.1 REQUIREMENTS This SR verifies that adequate long term (30 day) cooling can be maintained. The specified level also ensures that sufficient NPSH is available to operate the NSWS pumps. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. This SR verifies that the SNSWP water level is t 571 ft mean sea level.
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| SR 3.7.9.2 This SR verifies that the NSWS is available to cool the CCW System to at least its maximum design temperature with the maximum accident or normal design heat loads for 30 days following a Design Basis Accident.
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| Catawba Units 1 and 2 B 3.7.9-3 Revision No. 4
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| | |
| SNSWP B 3.7.9 BASES SURVEILLANCE REQUIREMENTS (continued)
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. This SR verifies that the average water temperature of the SNSWP is d 95qF. The SR is modified by a note that states the Surveillance is only required to be performed during the months of July, August, and September. During other months, the ambient temperature is below the surveillance limit.
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| SR 3.7.9.3 This SR verifies dam integrity by inspection to detect degradation, erosion, or excessive seepage. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| REFERENCES 1. UFSAR, Section 9.2.
| |
| : 2. Regulatory Guide 1.27.
| |
| : 3. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
| |
| : 4. UFSAR Table 18-1.
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| Catawba Units 1 and 2 B 3.7.9-4 Revision No. 4
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| CRAVS B 3.7.10 B 3.7 PLANT SYSTEMS B 3.7.10 Control Room Area Ventilation System (CRAVS)
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| BASES BACKGROUND The CRAVS ensures that the Control Room Envelope (CRE) will remain habitable for occupants during and following all credible accident conditions. This function is accomplished by pressurizing the CRE to >
| |
| 1/8 (0.125) inch water gauge with respect to all surrounding areas, filtering the outside air used for pressurization, and filtering a portion of the return air from the CRE to clean up the control room environment.
| |
| The CRAVS consists of two independent, redundant trains of equipment.
| |
| Each train consists of:
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| x a pressurizing filter train fan (1CRA-PFTF-1 or 2CRA-PFTF-1) x a filter unit (1CRA-PFT-1 or 2CRA-PFT-1) which includes moisture separator/prefilters, HEPA filters, and carbon adsorbers x the associated ductwork, dampers/valves, controls, doors, and barriers Inherent in the CRAVS ability to pressurize the control room is the control room envelope boundary. The CRE is the area within the confines of the CRE boundary that contains the spaces that control room occupants inhabit to control the unit during normal and accident conditions. This area encompasses the control room, and may encompass the non-critical areas to which frequent personnel access or continuous occupancy is not necessary in the event of an accident. The CRE is protected during the normal operation, natural events, and accident conditions. The CRE boundary is the combination of walls, floor, roof, ducting, doors, penetrations and equipment that physically form the CRE. The OPERABILITY of the CRE boundary must be maintained to ensure that the inleakage of unfiltered air into the CRE will not exceed the inleakage assumed in the licensing basis analysis of design basis accident (DBA) consequences to CRE occupants. The CRE and its boundary are defined in the Control Room Envelope Habitability Program. These boundaries must be intact or properly isolated for the CRAVS to function properly.
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| Catawba Units 1 and 2 B 3.7.10-1 Revision No. 15
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| CRAVS B 3.7.10 BASES BACKGROUND (continued)
| |
| The CRAVS can be operated either manually or automatically. Key operated selector switches located in the CRE initiate operation of all train related CRAVS equipment. The selected train is in continuous operation.
| |
| Outside air for pressurization and makeup to the CRE is supplied from two independent intakes. This outside air is mixed with return air from the CRE before being passed through the filter unit. In the filter unit, moisture separator/prefilters remove any large particles in the air, and any entrained water droplets present. A HEPA filter bank upstream of the carbon adsorber filter bank functions to remove particulates and a second bank of HEPA filters follow the carbon adsorber to collect carbon fines.
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| Only the upstream HEPA filters and carbon adsorber bank are credited in the analysis. A heater is included within each filter train to reduce the relative humidity of the airstream, although no credit is taken in the safety analysis. The heaters are not required for OPERABILITY since the carbon laboratory tests are performed at 95% relative humidity, but have been maintained in the system to provide additional margin (Ref. 9).
| |
| Testing per ASTM D3803-1989 at 30°C and 95% relative humidity ensures that the filter efficiency is unaffected by moisture. Periodic operation ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action.
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| Upon receipt of an Engineered Safety Feature (ESF) signal, the selected CRAVS train continues to operate and the pressurizing filter train fan of the non-selected train is started. This assures control room pressurization, assuming an active failure of one of the pressurizing filter train fans.
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| The outside air for pressurization is continuously monitored for the presence of smoke, radiation, or chlorine by non-safety related detectors.
| |
| If smoke, radiation, or chlorine is detected in an outside air intake, an alarm is received within the CRE, alerting the operators of this condition.
| |
| The operator will take the required action to close the affected intake, if necessary, per the guidance of the Annunciator Response Procedures.
| |
| A single CRAVS train is capable of pressurizing the CRE to greater than or equal to 0.125 inches water gauge. The CRAVS is designed in accordance with Seismic Category 1 requirements. The CRAVS operation in maintaining the CRE habitable is discussed in the UFSAR, Sections 6.4 and 9.4.1 (Refs. 1 and 2).
| |
| The CRAVS is designed to maintain a habitable environment in the CRE for 30 days of continuous occupancy after a DBA without exceeding a 5 rem total effective dose equivalent (TEDE).
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| Catawba Units 1 and 2 B 3.7.10-2 Revision No. 15
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| | |
| CRAVS B 3.7.10 BASES APPLICABLE The CRAVS components are arranged in redundant, safety related SAFETY ANALYSES ventilation trains. The CRAVS provides airborne radiological protection for the CRE occupants, as demonstrated by the CRE occupant dose analyses for the most limiting design basis loss of coolant accident, fission product release presented in the UFSAR, Chapter 15 (Ref. 3).
| |
| The CRAVS provides protection from smoke and hazardous chemicals to CRE occupants. The analysis of hazardous chemical releases demonstrates that the toxicity limits are not exceeded in the CRE following a hazardous chemical release (Ref. 1). The evaluation of a smoke challenge demonstrates that it will not result in the inability of the CRE occupants to control the reactor either from the control room or from the remote shutdown panels (Ref. 9).
| |
| The worst case single active failure of a component of the CRAVS, assuming a loss of offsite power, does not impair the ability of the system to perform its design function.
| |
| The CRAVS satisfies Criterion 3 of 10 CFR 50.36 (Ref. 4).
| |
| LCO Two independent and redundant CRAVS trains are required to be OPERABLE to ensure that at least one is available assuming a single active failure disables the other train. Total system failure, such as from a loss of both ventilation trains or from an inoperable CRE boundary, could result in exceeding a dose of 5 rem to the CRE occupants in the event of a large radioactive release.
| |
| Each CRAVS train is considered OPERABLE when the individual components necessary to limit CRE occupant exposure are OPERABLE in both trains. A CRAVS train is OPERABLE when the associated:
| |
| : a. Pressurizing filter train fan is OPERABLE;
| |
| : b. HEPA filters and carbon adsorbers are not excessively restricting flow, and are capable of performing their filtration functions; and
| |
| : c. Ductwork, valves, and dampers are OPERABLE, and air circulation can be maintained.
| |
| In order for the CRAVS trains to be considered OPERABLE, the CRE boundary must be maintained such that the CRE occupant dose from a large radioactive release does not exceed the calculated dose in the licensing basis consequence analyses for DBAs, and that the CRE occupants are protected from hazardous chemicals and smoke.
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| Catawba Units 1 and 2 B 3.7.10-3 Revision No. 15
| |
| | |
| CRAVS B 3.7.10 BASES LCO (continued)
| |
| The CRAVS 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 CRAVS 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.
| |
| The LCO is modified by a Note allowing the CRE boundary to be opened intermittently under administrative controls. This Note only applies to openings in the CRE boundary that can be rapidly restored to the design condition, such as doors, hatches, floor plugs, and access panels. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings, these controls should be proceduralized and consist of stationing a dedicated individual at the opening who is in continuous communication with the operators in the CRE. This individual will have a method to rapidly close the opening and to restore the CRE boundary to a condition equivalent to the design condition when a need for CRE isolation is indicated.
| |
| APPLICABILITY In MODES 1, 2, 3, 4, 5, and 6, the CRAVS must be OPERABLE to ensure that the CRE will remain habitable during and following a DBA.
| |
| During movement of irradiated fuel assemblies, the CRAVS must be OPERABLE to cope with the release from a fuel handling accident.
| |
| ACTIONS A.1 When one CRAVS train is inoperable for reasons other than an inoperable CRE boundary, action must be taken to restore OPERABLE status within 7 days. In this Condition, the remaining OPERABLE CRAVS train is adequate to perform the CRE protection function.
| |
| However, the overall reliability is reduced because a single failure in the OPERABLE CRAVS train could result in loss of CRAVS function. The 7 day Completion Time is based on the low probability of a DBA occurring during this time period, and ability of the remaining train to provide the required capability.
| |
| Catawba Units 1 and 2 B 3.7.10-4 Revision No. 15
| |
| | |
| CRAVS B 3.7.10 BASES ACTIONS (continued)
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| B.1, B.2, and B.3 If the unfiltered inleakage of potentially contaminated air past the CRE boundary and into the CRE can result in CRE occupant radiological dose greater than the calculated dose of the licensing basis analyses of DBA consequences (allowed to be up to 5 rem TEDE), or inadequate protection of CRE occupants from hazardous chemicals or smoke, the CRE boundary is inoperable. Actions must be taken to restore an OPERABLE CRE boundary within 90 days.
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| During the period that the CRE boundary is considered inoperable, action must be initiated to implement mitigating actions to lessen the effect on CRE occupants from the potential hazards of a radiological or chemical event or a challenge from smoke. Actions must be taken within 24 hours to verify that in the event of a DBA, the mitigating actions will ensure that CRE occupant radiological exposures will not exceed the calculated dose of the licensing basis analyses of DBA consequences, and that CRE occupants are protected from hazardous chemicals and smoke. These mitigating actions (i.e., actions that are taken to offset the consequences of the inoperable CRE boundary) should be preplanned for implementation upon entry into the condition, regardless of whether entry is intentional or unintentional. The 24 hour Completion Time is reasonable based on the low probability of a DBA occurring during this time period, and the use of mitigating actions. The 90 day Completion Time is reasonable based on the determination that the mitigating actions will ensure protection of CRE occupants within analyzed limits while limiting the probability that CRE occupants will have to implement protective measures that may adversely affect their ability to control the reactor and maintain it in a safe shutdown condition in the event of a DBA. In addition, the 90 day Completion Time is reasonable time to diagnose, plan and possibly repair, and test most problems with the CRE boundary.
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| C.1 and C.2 In MODE 1, 2, 3, or 4, if the inoperable CRAVS or CRE boundary train cannot be restored to OPERABLE status within the required Completion Time, the unit must be placed in a MODE that minimizes accident risk.
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| To achieve this status, the unit must be placed in at least MODE 3 within 6 hours, and in MODE 5 within 36 hours. 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.
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| Catawba Units 1 and 2 B 3.7.10-5 Revision No. 15
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| CRAVS B 3.7.10 BASES ACTIONS (continued)
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| D.1 In MODE 5 or 6, if the inoperable CRAVS train cannot be restored to OPERABLE status within the required Completion Time, or during movement of irradiated fuel assemblies, action must be taken to immediately place the OPERABLE CRAVS train in operation. This action ensures that the operating (or running) train is OPERABLE, that no failures preventing automatic actuation will occur, and that any active failure would be readily detected.
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| An alternative to Required Action D.1 is to immediately suspend activities that could result in a release of radioactivity that might require isolation of the CRE. This places the unit in a condition that minimizes risk. This does not preclude the movement of fuel to a safe position.
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| E.1 In MODE 5 or 6, or during movement of irradiated fuel assemblies, with two CRAVS trains inoperable, or with one or more CRAVS trains inoperable due to an inoperable CRE boundary, action must be taken immediately to suspend activities that could result in a release of radioactivity that might require isolation of the CRE. This places the unit in a condition that minimizes the accident risk. This does not preclude the movement of fuel to a safe position.
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| F.1 If both CRAVS trains are inoperable in MODE 1, 2, 3, or 4, for reasons other than Condition B, the CRAVS may not be capable of performing the intended function and the unit is in a condition outside the accident analyses. Therefore, LCO 3.0.3 must be entered immediately.
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| Catawba Units 1 and 2 B 3.7.10-6 Revision No. 15
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| CRAVS B 3.7.10 BASES SURVEILLANCE SR 3.7.10.1 REQUIREMENTS Standby systems should be checked periodically to ensure that they function properly. As the environment and normal operating conditions on this system are not too severe, testing each train once every month provides an adequate check of this system. Operation for 15 continuous minutes demonstrates OPERABILITY of the system. Periodic operation ensures that blockage, fan or motor failure, or excessive vibration can be detected for correction action. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.7.10.2 This SR verifies that the required CRAVS testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The CRAVS filter tests are in accordance with Regulatory Guide 1.52 (Ref. 5).
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| The VFTP includes testing the performance of the HEPA filter and carbon adsorber efficiencies and the physical properties of the activated carbon.
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| Specific test Frequencies and additional information are discussed in detail in the VFTP.
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| SR 3.7.10.3 This SR verifies that each CRAVS train starts and operates on an actual or simulated actuation signal. The SR excludes automatic dampers and valves that are locked, sealed, or otherwise secured in the actuated position. The SR does not apply to dampers or valves that are locked, sealed, or otherwise secured in the actuated position since the affected dampers or valves were verified to be in the actuated position prior to being locked, sealed, or otherwise secured. Placing an automatic valve or damper in a locked, sealed, or otherwise secured position requires an assessment of the operability of the system or any supported systems, including whether it is necessary for the valve or damper to be repositioned to the non-actuated position to support the accident analysis.
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| Restoration of an automatic valve or damper to the non-actuated position requires verification that the SR has been met within its required Frequency. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| Catawba Units 1 and 2 B 3.7.10-7 Revision No. 15
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| CRAVS B 3.7.10 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.7.10.4 This SR verifies the OPERABILITY of the CRE boundary by testing for unfiltered air inleakage past the CRE boundary and into the CRE. The details of the testing are specified in the Control Room Envelope Habitability Program.
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| The CRE is considered habitable when the radiological dose to CRE occupants calculated in the licensing basis analyses of DBA consequences is no more than 5 rem TEDE and the CRE occupants are protected from hazardous chemicals and smoke. This SR verifies that the unfiltered air inleakage into the CRE is no greater than the flow rate assumed in the licensing basis analyses of DBA consequences. When unfiltered air inleakage is greater than the assumed flow rate, Condition B must be entered. Required Action B.3 allows time to restore the CRE boundary to OPERABLE status provided mitigating actions can ensure that the CRE remains within the licensing basis habitability limits for the occupants following an accident. Compensatory measures are discussed in Regulatory Guide 1.196, Section C.2.7.3 (Ref. 9), which endorses, with exceptions, NEI 99-03, Section 8.4 and Appendix F (Ref. 7). These compensatory measures may also be used as mitigating actions as required by Required Action B.2. Temporary analytical methods may also be used as compensatory measures to restore OPERABILITY (Ref. 8).
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| Options for restoring the CRE boundary to OPERABLE status include changing the licensing basis DBA consequence analysis, repairing the CRE boundary, or a combination of these actions. Depending upon the nature of the problem and the corrective action, a full scope inleakage test may not be necessary to establish that the CRE boundary has been restored to OPERABLE status.
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| REFERENCES 1. UFSAR, Section 6.4.
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| : 2. UFSAR, Section 9.4.1.
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| : 3. UFSAR, Chapter 15.
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| : 4. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| : 5. Regulatory Guide 1.52, Rev. 2.
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| : 6. Catawba Nuclear Station License Amendments 90/84 for Units 1/2, August 23, 1991.
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| Catawba Units 1 and 2 B 3.7.10-8 Revision No. 15
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| | |
| CRAVS B 3.7.10 BASES REFERENCES (continued)
| |
| : 7. NEI 99-03, "Control Room Habitability Assessment", June 2001.
| |
| : 8. Letter from Eric J. Leeds (NRC) to James W. Davis (NEI) dated January 30, 2004, "NEI Draft White Paper, Use of Generic Letter 91-18 Process and Alternative Source Terms in the Context of Control Room Habitability", (ADAMS Accession No. ML040300694).
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| : 9. Regulatory Guide 1.196, Rev. 1.
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| Catawba Units 1 and 2 B 3.7.10-9 Revision No. 15
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| ABFVES B 3.7.12 B 3.7 PLANT SYSTEMS B 3.7.12 Auxiliary Building Filtered Ventilation Exhaust System (ABFVES)
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| BASES BACKGROUND The ABFVES consists of two independent and redundant trains. Each train consists of a heater demister section and a filter unit section. The heater demister section consists of a prefilter/moisture separator (to remove entrained water droplets) and an electric heater (to reduce the relative humidity of air entering the filter unit). The filter unit section consists of a prefilter, an upstream HEPA filter, an activated carbon adsorber (for the removal of gaseous activity, principally iodines), a downstream HEPA, and a fan. The downstream HEPA filter is not credited in the accident analysis, but serves to collect carbon fines.
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| Ductwork, valves or dampers, and instrumentation also form part of the system. Following receipt of a safety injection (SI) signal, the system isolates non safety portions of the ABFVES and exhausts air only from the Emergency Core Cooling System (ECCS) pump rooms.
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| The ABFVES is normally aligned to bypass the system HEPA filters and carbon adsorbers. During emergency operations, the ABFVES dampers are realigned to the filtered position, and fans are started to begin filtration. During emergency operations, the ABFVES dampers are realigned to isolate the non-safety portions of the system and only draw air from the ECCS pump rooms, as well as the Elevation 522 pipe chase, and Elevation 543 and 560 mechanical penetration rooms.
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| The ABFVES is discussed in the UFSAR, Sections 6.5, 9.4, 14.4, and 15.6 (Refs. 1, 2, 3, and 4, respectively) since it may be used for normal, as well as post accident, atmospheric cleanup functions. The heaters are not required for OPERABILITY, since the laboratory test of the carbon is performed at 95% relative humidity, but have been maintained in the system to provide additional margin (Ref. 9). Testing per ASTM D3803-1989 at 30°C and 95% relative humidity ensures that the filter efficiency is unaffected by moisture.
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| Catawba Units 1 and 2 B 3.7.12-1 Revision No. 12
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| ABFVES B 3.7.12 BASES APPLICABLE The design basis of the ABFVES is established by the large break SAFETY ANALYSES LOCA. The system evaluation assumes filtered and unfiltered leak rates in the Auxiliary Building throughout the accident. In such a case, the system limits radioactive release to within the 10 CFR 50.67 (Ref. 6) limits. The analysis of the effects and consequences of a large break LOCA is presented in Reference 4.
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| The ABFVES satisfies Criterion 3 of 10 CFR 50.36 (Ref. 7).
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| LCO Two independent and redundant trains of the ABFVES are required to be OPERABLE to ensure that at least one is available, assuming that a single failure disables the other train coincident with a loss of offsite power. Total system failure could result in the atmospheric release from the ECCS pump rooms exceeding 10 CFR 50.67 limits in the event of a Design Basis Accident (DBA).
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| ABFVES is considered OPERABLE when the individual components necessary to maintain the ECCS pump rooms filtration are OPERABLE in both trains.
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| An ABFVES train is considered OPERABLE when its associated:
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| : a. Fan is OPERABLE;
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| : b. HEPA filters and carbon adsorbers are capable of performing their filtration functions; and
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| : c. Ductwork, valves, and dampers are OPERABLE and air circulation can be maintained.
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| The ABFVES fans power supply is provided by buses which are shared between the two units.
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| Catawba Units 1 and 2 B 3.7.12-2 Revision No. 12
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| ABFVES B 3.7.12 BASES LCO (continued)
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| The LCO is modified by a Note allowing the ECCS pump rooms pressure boundary to be opened intermittently under administrative controls. For entry and exit through doors, the administrative control of the opening is performed by the person(s) entering or exiting the area. For other openings, these controls consist of stationing a dedicated individual at the opening who is in continuous communication with the control room. This individual will have a method to rapidly close the opening when a need for ECCS pump rooms pressure boundary isolation is indicated.
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| APPLICABILITY In MODES 1, 2, 3, and 4, the ABFVES is required to be OPERABLE consistent with the OPERABILITY requirements of the ECCS.
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| In MODE 5 or 6, the ABFVES is not required to be OPERABLE since the ECCS is not required to be OPERABLE.
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| ACTIONS A.1 With one ABFVES train inoperable, action must be taken to restore OPERABLE status within 7 days. During this time, the remaining OPERABLE train is adequate to perform the ABFVES function.
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| The 7 day Completion Time is appropriate because the risk contribution is less than that for the ECCS (72 hour Completion Time), and this system is not a direct support system for the ECCS. The 7 day Completion Time is based on the low probability of a DBA occurring during this time period, and ability of the remaining train to provide the required capability.
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| Concurrent failure of two ABFVES trains would result in the loss of functional capability; therefore, LCO 3.0.3 must be entered immediately.
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| B.1 If the ECCS pump rooms pressure boundary is inoperable such that the ABFVES trains cannot establish or maintain the required pressure, action must be taken to restore an OPERABLE ECCS pump rooms pressure boundary within 24 hours. During the period that the ECCS pump rooms pressure boundary is inoperable, appropriate compensatory measures (consistent with the intent, as applicable, of GDC 19, 60, 64, and 10 CFR 50.67) should be utilized to protect plant personnel from potential Catawba Units 1 and 2 B 3.7.12-3 Revision No. 12
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| ABFVES B 3.7.12 BASES ACTIONS (continued) hazards such as radioactive contamination, toxic chemicals, smoke, temperature and relative humidity, and physical security. Preplanned measures should be available to address these concerns for intentional and unintentional entry into the condition. The 24 hour Completion Time is reasonable based on the low probability of a DBA occurring during this time period and the use of compensatory measures. The 24 hour Completion Time is a typically reasonable time to diagnose, plan and possibly repair, and test most problems with the ECCS pump rooms pressure boundary.
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| C.1 and C.2 If the ABFVES train or ECCS pump rooms pressure boundary cannot be restored to OPERABLE status within the associated Completion Time, the unit must be placed in a MODE in which the LCO does not apply. To achieve this status, the unit must be placed in at least MODE 3 within 6 hours, and in MODE 5 within 36 hours. The allowed Completion Times are reasonable, based on experience, to reach the required unit conditions from full power conditions in an orderly manner and without challenging unit systems.
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| SURVEILLANCE SR 3.7.12.1 REQUIREMENTS Systems should be checked periodically to ensure that they function properly. As the environment and normal operating conditions on this system are not severe, testing each train once a month provides an adequate check on this system. Operation for t 15 continuous minutes demonstrates OPERABILITY of the system. Periodic operation ensures that blockage, fan or motor failure, or excessive vibration can be detected for corrective action. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| Catawba Units 1 and 2 B 3.7.12-4 Revision No. 12
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| ABFVES B 3.7.12 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.7.12.2 This SR verifies that the required ABFVES testing is performed in accordance with the Ventilation Filter Testing Program (VFTP). The ABFVES filter tests are in accordance with Reference 5. The VFTP includes testing HEPA filter performance, carbon adsorbers efficiency, system flow rate, and the physical properties of the activated carbon (general use and following specific operations). The system flow rate determination and in-place testing of the filter unit components is performed in the normal operating alignment with both trains in operation.
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| Flow through each filter unit in this alignment is approximately 30,000 cfm. The normal operating alignment has been chosen to minimize normal radiological protection concerns that occur when the system is operated in an abnormal alignment for an extended period of time.
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| Operation of the system in other alignments may alter flow rates to the extent that the 30,000 cfm +10% specified in Technical Specification 5.5.11 will not be met. Flow rates outside the specified band under these operating alignments will not require the system to be considered inoperable.
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| Certain postulated failures and post accident recovery operational alignments may result in post accident system operation with only one train of ABFVES in a normal alignment. Under these conditions system flow rate is expected to increase above the normal flow band specified in Technical Specification 5.5.11. An analysis has been performed which conservatively predicts the maximum flow rate under these conditions is approximately 37,000 cfm. 37,000 cfm corresponds to a face velocity of approximately 48 ft/min that is significantly more than the normal 40 ft/min velocity specified in ASTM D3803-1989 (Ref. 10). Therefore, the laboratory test of the carbon penetration is performed in accordance with ASTM D3803-1989 and Generic Letter 99-02 at a face velocity of 48 ft/min. These test results are to be adjusted for a 2.27 inch bed using the methodology presented in ASTM D3803-1989 prior to comparing them to the Technical Specification 5.5.11 limit. Specific test Frequencies and additional information are discussed in detail in the VFTP.
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| Catawba Units 1 and 2 B 3.7.12-5 Revision No. 12
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| ABFVES B 3.7.12 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.7.12.3 This SR verifies that each ABFVES train starts and operates with flow through the HEPA filters and carbon adsorbers on an actual or simulated actuation signal. The SR excludes automatic dampers and valves that are locked, sealed, or otherwise secured in the actuated position. The SR does not apply to dampers or valves that are locked, sealed, or otherwise secured in the actuated position since the affected dampers or valves were verified to be in the actuated position prior to being locked, sealed, or otherwise secured. Placing an automatic valve or damper in a locked, sealed, or otherwise secured position requires an assessment of the operability of the system or any supported systems, including whether it is necessary for the valve or damper to be repositioned to the non-actuated position to support the accident analysis. Restoration of an automatic valve or damper to the non-actuated position requires verification that the SR has been met within its required Frequency. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.7.12.4 This SR verifies the pressure boundary integrity of the ECCS pump rooms. The following rooms are considered to be ECCS pump rooms (with respect to the ABFVES): centrifugal charging pump rooms, safety injection pump rooms, residual heat removal pump rooms, and the containment spray pump rooms. Although the containment spray system is not normally considered an ECCS system, it is included in this ventilation boundary because of its accident mitigation function which requires the pumping of post accident containment sump fluid. The Elevation 522 pipe chase area is also maintained at a negative pressure by the ABFVES. Since the Elevation 543 and 560 mechanical penetration rooms communicate directly with the Elevation 522 pipe chase area, these penetration rooms are also maintained at a negative pressure by the ABFVES. The ability of the system to maintain the ECCS pump rooms at a negative pressure, with respect to potentially unfiltered adjacent areas, is periodically tested to verify proper functioning of the ABFVES. Upon receipt of a safety injection signal to initiate LOCA operation, the ABFVES is designed to maintain a slight negative pressure in the ECCS pump rooms, with respect to adjacent areas, to prevent unfiltered LEAKAGE. The ABFVES will continue to operate in this mode until the safety injection signal is reset. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| Catawba Units 1 and 2 B 3.7.12-6 Revision No. 12
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| ABFVES B 3.7.12 BASES REFERENCES 1. UFSAR, Section 6.5.
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| : 2. UFSAR, Section 9.4.
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| : 3. UFSAR, Section 14.4.
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| : 4. UFSAR, Section 15.6.
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| : 5. Regulatory Guide 1.52 (Rev. 2).
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| : 6. 10 CFR 50.67.
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| : 7. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| : 8. Not used.
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| : 9. Catawba Nuclear Station License Amendments 90/84 for Units 1/2, August 23, 1991.
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| : 10. ASTM D3803-1989.
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| Catawba Units 1 and 2 B 3.7.12-7 Revision No. 12
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| AC SourcesOperating B 3.8.1 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.1 AC SourcesOperating BASES BACKGROUND The unit Essential Auxiliary Power Distribution System AC sources consist of the offsite power sources (preferred power sources, normal and alternate(s)), and the onsite standby power sources (Train A and Train B diesel generators (DGs)). As required by 10 CFR 50, Appendix A, GDC 17 (Ref. 1), the design of the AC electrical power system provides independence and redundancy to ensure an available source of power to the Engineered Safety Feature (ESF) systems.
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| The onsite Class 1E AC Distribution System is divided into redundant load groups (trains) so that the loss of any one group does not prevent the minimum safety functions from being performed. Each train has connections to two preferred offsite power sources and a single DG.
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| At the 600V level of the onsite Class 1E AC Distribution System, each unit has one motor control center (MCC), 1EMXG and 2EMXH, that each supply power to a train of shared systems. The term shared systems is defined as the shared components of Train A or Train B of Nuclear Service Water System (NSWS), Control Room Area Ventilation System (CRAVS), Control Room Area Chilled Water System (CRACWS) and Auxiliary Building Filtered Ventilation Exhaust System (ABFVES) whose power supply can be swapped between the Units. The MCC 1EMXG is normally aligned to receive power from load center 1ELXA but if desired or required to maintain operability of the Train A shared systems, can be swapped to receive power from load center 2ELXA. The MCC 2EMXH is normally aligned to receive power from load center 2ELXB but if desired or required to maintain operability of the Train B shared systems, can be swapped to receive power from load center 1ELXB. The four NSWS pumps (1A, 2A, 1B and 2B) are shared components that receive power at the Unit and Train specific 4160V level of the onsite Class 1E AC Distribution System and whose power supply cannot be swapped between the Units. Therefore, the four NSWS pumps are not part of the shared systems, as defined above, because the power supply for a particular NSWS pump cannot come from the opposite unit.
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| There are also provisions to accommodate the connecting of the Emergency Supplemental Power Source (ESPS) to one train of either units Class 1E AC Distribution System. The ESPS consists of two 50%
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| Catawba Units 1 and 2 B 3.8.1-1 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES BACKGROUND (continued) capacity non-safety related commercial grade DGs. Manual actions are required to align the ESPS to the station and only one of the stations four onsite Class 1E Distribution System trains can be supplied by the ESPS at any given time. The ESPS is made available to support extended Completion Times in the event of an inoperable DG as well as a defense-in-depth source of AC power to mitigate a station blackout event. The ESPS would remain disconnected from the Class 1E AC Distribution System unless required for supplemental power to one of the four 4.16 kV ESF buses.
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| From the transmission network, two electrically and physically separated circuits provide AC power, through step down station auxiliary transformers, to the 4.16 kV ESF buses. A detailed description of the offsite power network and the circuits to the Class 1E ESF buses is found in the UFSAR, Chapter 8 (Ref. 2).
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| A qualified offsite circuit consists of all breakers, transformers, switches, interrupting devices, cabling, and controls required to transmit power from the offsite transmission network to the onsite Class 1E ESF bus(es).
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| Certain required unit loads are returned to service in a predetermined sequence in order to prevent overloading the transformer supplying offsite power to the onsite Class 1E Distribution System. Within 1 minute after the initiating signal is received, all automatic and permanently connected loads needed to recover the unit or maintain it in a safe condition are returned to service via the load sequencer.
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| The onsite standby power source for each 4.16 kV ESF bus is a dedicated DG. DGs A and B are dedicated to ESF buses ETA and ETB, respectively. A DG starts automatically on a safety injection (SI) signal (i.e., low pressurizer pressure or high containment pressure signals) or on an ESF bus degraded voltage or undervoltage signal (refer to LCO 3.3.5, "Loss of Power (LOP) Diesel Generator (DG) Start Instrumentation").
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| After the DG has started, it will automatically tie to its respective bus after offsite power is tripped as a consequence of ESF bus undervoltage or degraded voltage, independent of or coincident with an SI signal. With no SI signal, there is a 10 minute delay between degraded voltage signal and the DG start signal. The DGs will also start and operate in the standby mode without tying to the ESF bus on an SI signal alone. Following the trip of offsite power, a sequencer strips loads from the ESF bus. When the DG is tied to the ESF bus, loads are then sequentially connected to its respective ESF bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading the DG by automatic load application.
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| Catawba Units 1 and 2 B 3.8.1-2 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES BACKGROUND (continued)
| |
| In the event of a loss of preferred power, the ESF electrical loads are automatically connected to the DGs in sufficient time to provide for safe reactor shutdown and to mitigate the consequences of a Design Basis Accident (DBA) such as a loss of coolant accident (LOCA).
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| Certain required unit loads are returned to service in a predetermined sequence in order to prevent overloading the DG in the process.
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| Approximately 1 minute after the initiating signal is received, all loads needed to recover the unit or maintain it in a safe condition are returned to service.
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| Ratings for Train A and Train B DGs satisfy the requirements of Regulatory Guide 1.9 (Ref. 3). The continuous service rating of each DG is 7000 kW with 10% overload permissible for up to 2 hours in any 24 hour period. The ESF loads that are powered from the 4.16 kV ESF buses are listed in Reference 2.
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| APPLICABLE The initial conditions of DBA and transient analyses in the UFSAR, SAFETY ANALYSES Chapter 6 (Ref. 4) and Chapter 15 (Ref. 5), assume ESF systems are OPERABLE. The AC electrical power sources are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System (RCS), and containment design limits are not exceeded.
| |
| These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coolant System (RCS);
| |
| and Section 3.6, Containment Systems.
| |
| The OPERABILITY of the AC electrical power sources is consistent with the initial assumptions of the Accident analyses and is based upon meeting the design basis of the unit. This results in maintaining at least one train of the onsite or offsite AC sources OPERABLE during Accident conditions in the event of:
| |
| : a. An assumed loss of all offsite power or all onsite AC power; and
| |
| : b. A worst case single failure.
| |
| The AC sources satisfy Criterion 3 of 10 CFR 50.36 (Ref. 6).
| |
| LCO Two qualified circuits between the offsite transmission network and the onsite Essential Auxiliary Power System and separate and independent DGs for each train ensure availability of the required power to shut down Catawba Units 1 and 2 B 3.8.1-3 Revision No. 9
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| | |
| AC Sources-Operating B 3.8.1 BASES LCO (continued) the reactor and maintain it in a safe shutdown condition after an anticipated operational occurrence (AOO) or a postulated DBA.
| |
| Additionally, the qualified circuit(s) between the offsite transmission network and the opposite unit onsite Essential Auxiliary Power System when necessary to power shared systems and the NSWS pump(s) and the opposite unit DG(s) when necessary to power shared systems and the NSWS pump(s) ensure availability of the required power to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA.
| |
| Qualified offsite circuits are those that are described in the UFSAR and are part of the licensing basis for the unit.
| |
| In addition, one required automatic load sequencer per train must be OPERABLE.
| |
| Each offsite circuit must be capable of maintaining rated frequency and voltage, and accepting required loads during an accident, while connected to the ESF buses.
| |
| The 4.16 kV essential system is divided into two completely redundant and independent trains designated A and B, each consisting of one 4.16 kV switchgear assembly, three 4.16 kV/600 V transformers, two 600 V load centers, and associated loads.
| |
| Normally, each Class 1E 4.16 kV switchgear is powered from its associated non-Class 1E train of the 6.9 kV Normal Auxiliary Power System as discussed in "6.9 kV Normal Auxiliary Power System" in Chapter 8 of the UFSAR (Ref. 2). Additionally, a standby source of power to each 4.16 kV essential switchgear, not required by General Design Criterion 17, is provided from the 6.9 kV system via two separate and independent 6.9/4.16 kV transformers. These transformers are shared between units and provide the capability to supply a standby source of preferred power to each unit's 4.16 kV essential switchgear from either unit's 6.9 kV system. A key interlock scheme is provided to preclude the possibility of connecting the two units together at either the 6.9 or 4.16 kV level.
| |
| Each train of the 4.16 kV Essential Auxiliary Power System is also provided with a separate and independent emergency diesel generator to supply the Class 1E loads required to safely shut down the unit following a design basis accident. Additionally, each diesel generator is capable of supplying its associated 4.16 kV blackout switchgear through a connection with the 4.16 kV essential switchgear.
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| Catawba Units 1 and 2 B 3.8.1-4 Revision No. 9
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| | |
| AC Sources-Operating B 3.8.1 BASES LCO (continued)
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| Each DG must be capable of starting, accelerating to rated speed and voltage, and connecting to its respective ESF bus on detection of bus undervoltage. This will be accomplished within 11 seconds. Each DG must also be capable of accepting required loads within the assumed loading sequence intervals, and continue to operate until offsite power can be restored to the ESF buses. These capabilities are required to be met from a variety of initial conditions such as DG in standby with the engine hot and DG in standby with the engine at ambient conditions.
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| Additional DG capabilities must be demonstrated to meet required Surveillance, e.g., capability of the DG to revert to standby status on an ECCS signal while operating in parallel test mode.
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| Proper sequencing of loads, including tripping of nonessential loads, is a required function for DG OPERABILITY.
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| The AC sources in one train must be separate and independent (to the extent possible) of the AC sources in the other train. For the DGs, separation and independence are complete.
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| For the offsite AC sources, separation and independence are provided to the extent practical.
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| LCO 3.8.1.c and LCO 3.8.1.d both use the word necessary to clarify that the qualified offsite circuit(s) in LCO 3.8.1.c and the DG(s) from the opposite unit in LCO 3.8.1.d are required to shut down the reactor and maintain it in a safe shutdown condition after an AOO or a postulated DBA.
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| LCO 3.8.1.c specifies that the qualified circuit(s) between the offsite transmission network and the opposite units Onsite Essential Auxiliary Power System be OPERABLE when necessary to supply power to the shared systems and NSWS pump(s). LCO 3.8.1.d specifies that the DG(s) from the opposite unit be OPERABLE when necessary to supply power to the shared systems and NSWS pump(s). The LCO 3.8.1.c AC sources in one train must be separate and independent (to the extent possible) of the LCO 3.8.1.c AC sources in the other train. These requirements, in conjunction with the requirements for the applicable unit AC electrical power sources in LCO 3.8.1.a and LCO 3.8.1.b, ensure that power is available to two trains of the shared NSWS, CRAVS, CRACWS and ABFVES, as well as to the NSWS pump(s).
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| With no equipment inoperable, two LCO 3.8.1.c AC sources are required to be OPERABLE and two LCO 3.8.1.d AC sources are required to be OPERABLE for each unit. For example, with both units in MODE 1, Unit 1 LCO 3.8.1.c is met by an OPERABLE 2A offsite circuit and an Catawba Units 1 and 2 B 3.8.1-5 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES LCO (continued)
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| OPERABLE 2B offsite circuit. LCO 3.8.1.d is met by an OPERABLE 2A DG and an OPERABLE 2B DG. In a normal plant alignment, the 2A offsite circuit and the 2A DG are relied upon as the normal and emergency power supplies for the 2A NSWS Pump, a shared component.
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| The 2B offsite circuit and the 2B DG are relied upon as the normal and emergency power supplies for the 2B NSWS Pump, a shared component, as well as the Train B shared systems that are powered at the 600V level of the onsite Class 1E AC Distribution System. For Unit 2, LCO 3.8.1.c is met by an OPERABLE 1A offsite circuit and an OPERABLE 1B offsite circuit. LCO 3.8.1.d is met by an OPERABLE 1A DG and an OPERABLE 1B DG. In a normal plant alignment, the 1A offsite circuit and the 1A DG are relied upon as the normal and emergency power supplies for the 1A NSWS Pump, a shared component, as well as the Train A shared systems that are powered at the 600V level of the onsite Class 1E AC Distribution System. The 1B offsite circuit and the 1B DG are relied upon as the normal and emergency power supplies for the 1B NSWS Pump, shared component.
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| APPLICABILITY The AC sources and sequencers are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure that:
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| : a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and
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| : b. Adequate core cooling is provided and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.
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| A Note has been added taking exception to the Applicability requirements for the required AC sources in LCO 3.8.1.c and LCO 3.8.1.d provided the associated shared systems and NSWS pump(s) are inoperable. This exception is intended to allow declaring the shared systems and NSWS pump(s) supported by the opposite unit inoperable either in lieu of declaring the opposite unit AC sources inoperable, or at any time subsequent to entering ACTIONS for an inoperable opposite unit AC source.
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| This exception is acceptable since, with the shared systems and NSWS pump(s) supported by the opposite unit inoperable and the associated ACTIONS entered, the opposite unit AC sources provide no additional assurance of meeting the above criteria.
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| The AC power requirements for MODES 5 and 6 are covered in LCO 3.8.2, "AC SourcesShutdown."
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| Catawba Units 1 and 2 B 3.8.1-6 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS A Note prohibits the application of LCO 3.0.4.b to an inoperable DG.
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| There is an increased risk associated with entering a MODE or other specified condition in the Applicability with an inoperable DG and the provisions of LCO 3.0.4.b, which allow entry into a MODE or other specified condition in the Applicability with the LCO not met after performance of a risk assessment addressing inoperable systems and components, should not be applied in this circumstance.
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| A.1 To ensure a highly reliable power source remains with one LCO 3.8.1.a offsite circuit inoperable, it is necessary to verify the OPERABILITY of the remaining required offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not met.
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| However, if a second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition E, for two offsite circuits inoperable, is entered.
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| A.2 Required Action A.2, which only applies if the train cannot be powered from an offsite source, is intended to provide assurance that an event coincident with a single failure of the associated DG will not result in a complete loss of safety function of critical redundant required features.
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| These features are powered from the redundant AC electrical power train.
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| This includes motor driven auxiliary feedwater pumps. The turbine driven auxiliary feedwater pump is required to be considered a redundant required feature, and, therefore, required to be determined OPERABLE by this Required Action. Three independent AFW pumps are required to ensure the availability of decay heat removal capability for all events accompanied by a loss of offsite power and a single failure. System design is such that the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis.
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| The Completion Time for Required Action A.2 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:
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| : a. The train has no offsite power supplying it loads; and
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| : b. A required feature on the other train is inoperable.
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| Catawba Units 1 and 2 B 3.8.1-7 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)
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| If at any time during the existence of Condition A (one LCO 3.8.1.a offsite circuit inoperable) a redundant required feature subsequently becomes inoperable, this Completion Time begins to be tracked.
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| Discovering no offsite power to one train of the onsite Class 1E Electrical Power Distribution System coincident with one or more inoperable required support or supported features, or both, that are associated with the other train that has offsite power, results in starting the Completion Times for the Required Action. Twenty-four hours is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.
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| The remaining OPERABLE offsite circuits and DGs are adequate to supply electrical power to Train A and Train B of the onsite Class 1E Distribution System. The 24 hour Completion Time takes into account the component OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 24 hour Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
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| A.3 According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition A for a period that should not exceed 72 hours. With one offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the unit safety systems. In this Condition, however, the remaining OPERABLE offsite circuit and DGs are adequate to supply electrical power to the onsite Class 1E Distribution System.
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| The 72 hour Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
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| B.1 It is required to administratively verify the LCO 3.8.1.d DG(s) OPERABLE within 1 hour and to continue this action once per 12 hours thereafter until restoration of the required LCO 3.8.1.b DG is accomplished. This verification provides assurance that the LCO 3.8.1.d DG is capable of supplying the onsite Class 1E AC Electrical Power Distribution System.
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| If one LCO 3.8.1.d DG is discovered to be inoperable when performing the administrative verification of operability, then Condition D is entered Catawba Units 1 and 2 B 3.8.1-8 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) for that DG. If two LCO 3.8.1.d DGs are discovered to be inoperable when performing the administrative verification of operability, then Condition G is entered.
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| B.2 To ensure a highly reliable power source remains with an inoperable LCO 3.8.1.b DG, it is necessary to verify the availability of the required offsite circuits on a more frequent basis. Since the Required Action only specifies "perform," a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action being not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions and Required Actions must then be entered.
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| B.3 Required Action B.3 is intended to provide assurance that a loss of offsite power, during the period that a LCO 3.8.1.b DG is inoperable, does not result in a complete loss of safety function of critical systems. These features are designed with redundant safety related trains. This includes motor driven auxiliary feedwater pumps. The turbine driven auxiliary feedwater pump is required to be considered a redundant required feature, and, therefore, required to be determined OPERABLE by this Required Action. Three independent AFW pumps are required to ensure the availability of decay heat removal capability for all events accompanied by a loss of offsite power and a single failure. System design is such that the remaining OPERABLE motor driven auxiliary feedwater pump is not by itself capable of providing 100% of the auxiliary feedwater flow assumed in the safety analysis. Redundant required feature failures consist of inoperable features associated with a train, redundant to the train that has an inoperable LCO 3.8.1.b DG.
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| The Completion Time for Required Action B.3 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action, the Completion Time only begins on discovery that both:
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| : a. An inoperable LCO 3.8.1.b DG exists; and
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| : b. A required feature on the other train (Train A or Train B) is inoperable.
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| If at any time during the existence of this Condition (one LCO 3.8.1.b DG Catawba Units 1 and 2 B 3.8.1-9 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) inoperable) a required feature subsequently becomes inoperable, this Completion Time would begin to be tracked.
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| Discovering one required LCO 3.8.1.b DG inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the OPERABLE DG, results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is Acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.
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| In this Condition, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. Thus, on a component basis, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4 hour Completion Time takes into account the OPERABILITY of the redundant counterpart to the inoperable required feature. Additionally, the 4 hour Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
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| B.4.1 and B.4.2 Required Action B.4.1 provides an allowance to avoid unnecessary testing of OPERABLE DG(s). If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG, SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on other DG(s), the other DG(s) would be declared inoperable upon discovery and Condition D and/or G of LCO 3.8.1, as applicable, would be entered. Once the failure is repaired, the common cause failure no longer exists, and Required Action B.4.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG(s), performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of that DG.
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| In the event the inoperable DG is restored to OPERABLE status prior to completing either B.4.1 or B.4.2, the problem investigation process will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour constraint imposed while in Condition B.
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| These Conditions are not required to be entered if the inoperability of the DG is due to an inoperable support system, an independently testable component, or preplanned testing or maintenance. If required, these Catawba Units 1 and 2 B 3.8.1-10 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)
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| Required Actions are to be completed regardless of when the inoperable DG is restored to OPERABLE status.
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| According to Generic Letter 84-15 (Ref. 8), 24 hours is reasonable to confirm that the OPERABLE DG(s) is not affected by the same problem as the inoperable DG.
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| B.5 In order to extend the Completion Time for an inoperable DG from 72 hours to 14 days, it is necessary to ensure the availability of the ESPS within 1 hour of entry into TS 3.8.1 LCO and every 12 hours thereafter.
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| Since Required Action B.5 only specifies evaluate, discovering the ESPS unavailable does not result in the Required Action being not met (i.e. the evaluation is performed). However, on discovery of an unavailable ESPS, the Completion Time for Required Action B.6 starts the 72 hour and/or 24 hour clock.
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| ESPS availability requires that:
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| : 1) The load test has been performed within 30 days of entry into the extended Completion Time. The Required Action evaluation is met with an administrative verification of this prior to testing; and
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| : 2) ESPS fuel tank level is verified locally to be KRXUVXSSO\ DQG
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| : 3) ESPS supporting system parameters for starting and operating are verified to be within required limits for functional availability (e.g., battery state of charge).
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| The ESPS is not used to extend the Completion Time for more than one inoperable DG at any one time.
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| B.6 In accordance with Branch Technical Position 8-8 (Ref. 14), operation may continue in Condition B for a period that should not exceed 14 days, provided a supplemental AC power source is available.
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| In Condition B, the remaining OPERABLE DGs, available ESPS and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. The 14 day Completion Time takes into account the capacity and capability of the remaining AC sources, a Catawba Units 1 and 2 B 3.8.1-11 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) reasonable time for repairs, and the low probability of a DBA occurring during this period.
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| If the ESPS is or becomes unavailable with an inoperable LCO 3.8.1.b DG, then action is required to restore the ESPS to available status or to restore the DG to OPERABLE status within 72 hours from discovery of unavailable ESPS. However, if the ESPS unavailability occurs at or sometime after 48 hours of continuous LCO 3.8.1.b DG inoperability, then the remaining time to restore the ESPS to available status or to restore the DG to OPERABLE status is limited to 24 hours.
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| The 72 hour and 24 hour Completion Times allow for an exception to the normal time zero for beginning the allowed outage time clock. The 72 hour Completion Time only begins on discovery that both:
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| : a. An inoperable DG exists; and
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| : b. ESPS is unavailable.
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| The 24 hour Completion Time only begins on discovery that:
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| : a. An inoperable DG exists for 48 hours; and
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| : b. ESPS is unavailable.
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| Therefore, when one LCO 3.8.1.b DG is inoperable due to either preplanned maintenance (preventive or corrective) or unplanned corrective maintenance work, the Completion Time can be extended from 72 hours to 14 days if ESPS is verified available for backup operation.
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| C.1 Condition C addresses the inoperability of the LCO 3.8.1.c qualified offsite circuit(s) between the offsite transmission network and the opposite units Onsite Essential Auxiliary Power System when the LCO 3.8.1.c qualified offsite circuit(s) is necessary to supply power to the shared systems and NSWS pump(s). If Condition C is entered concurrently with the inoperability of LCO 3.8.1.d DG(s) the NOTE requires the licensed operator to evaluate if the TS 3.8.9 Distribution Systems - Operating requirement that OPERABLE AC electrical power distribution subsystems require the associated buses, load centers, motor control centers, and distribution panels to be energized to their proper voltages continues to be met. In the case where the inoperable LCO 3.8.1.c qualified offsite circuit and inoperable LCO 3.8.1.d DG are associated with the same train there is no longer assurance that train of Distribution Systems - Operating can be energized to the proper voltage and therefore TS 3.8.9 Condition A must be entered.
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| Catawba Units 1 and 2 B 3.8.1-12 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)
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| To ensure a highly reliable power source remains with one required LCO 3.8.1.c offsite circuit inoperable, it is necessary to verify the OPERABILITY of the remaining required offsite circuits on a more frequent basis. Since the Required Action only specifies perform, a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not met. However, if a second required circuit fails SR 3.8.1.1, the second offsite circuit is inoperable, and Condition A and E, as applicable, for the two offsite circuits inoperable, is entered.
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| C.2 Required Action C.2, which only applies if the train cannot be powered from an offsite source, is intended to provide assurance that an event coincident with a single failure of the associated DG will not result in a complete loss of safety function for the NSWS (including the NSWS pump), CRAVS, CRACWS or the ABFVES. The Completion Time for Required Action C.2 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal time zero for beginning the allowed outage time clock. In this Required Action, the Completion Time only begins on discovery that both:
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| : a. The train has no offsite power supplying its loads: and
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| : b. NSWS (including the NSWS pump), CRAVS, CRACWS or ABFVES on the other train that has offsite power is inoperable.
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| If at any time during the existence of Condition C (one required LCO 3.8.1.c offsite circuit inoperable) a train of NSWS (including the NSWS pump), CRAVS, CRACWS or ABFVES becomes inoperable, this Completion Time begins to be tracked.
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| Discovering no offsite power to one train of the onsite Class 1E Electrical Power Distribution System coincident with one train of NSWS (including the NSWS pump), CRAVS, CRACWS or ABFVES that is associated with the other train that has offsite power, results in starting the Completion Times for the Required Action. Twenty-four hours is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.
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| The remaining OPERABLE offsite circuits and DGs are adequate to supply electrical power to Train A and Train B of the onsite Class 1E Distribution System. The 24 hour Completion Time takes into account the component OPERABILITY of the redundant counterpart to the Catawba Units 1 and 2 B 3.8.1-13 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) inoperable NSWS (including the NSWS pump), CRAVS, CRACWS or ABFVES. Additionally, the 24 hour Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
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| C.3 Consistent with the time provided in ACTION A, operation may continue in Condition C for a period that should not exceed 72 hours. With one required LCO 3.8.1.c offsite circuit inoperable, the reliability of the offsite system is degraded, and the potential for a loss of offsite power is increased, with attendant potential for a challenge to the unit safety systems. In this Condition, however, the remaining OPERABLE offsite circuits and DGs are adequate to supply electrical power to the onsite Class 1E Distribution System.
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| If the LCO 3.8.1.c required offsite circuit cannot be restored to OPERABLE status within 72 hours, then Condition I must be entered immediately.
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| D.1 Condition D addresses the inoperability of the LCO 3.8.1.d DG(s) aligned to the opposite unit Onsite Essential Auxiliary Power System that is supplying power to a train of shared systems and to the respective NSWS pump(s). If Condition D is entered concurrently with the inoperability of LCO 3.8.1.c qualified offsite circuit, the NOTE requires the licensed operator to evaluate if the TS 3.8.9 Distribution Systems - Operating requirement that OPERABLE AC electrical power distribution subsystems require the associated buses, load centers, motor control centers, and distribution panels to be energized to their proper voltages continues to be met. In the case where the inoperable LCO 3.8.1.d DG and inoperable LCO 3.8.1.c qualified offsite circuit are associated with the same train there is no longer assurance that train of Distribution Systems
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| - Operating can be energized to the proper voltage and therefore TS 3.8.9 Condition A must be entered.
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| It is required to administratively verify the LCO 3.8.1.b safety-related DGs OPERABLE and the opposite units DG OPERABLE within one hour and to continue this action once per 12 hours thereafter until restoration of the required LCO 3.8.1.d DG and the opposite units DG is accomplished.
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| This verification provides assurance that the LCO 3.8.1.b safety-related DGs and the opposite units DG is capable of supplying the onsite Class Catawba Units 1 and 2 B 3.8.1-14 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) 1E AC Electrical Power Distribution System.
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| If one LCO 3.8.1.b DG is discovered to be inoperable when performing the administrative verification of operability, then Condition B is entered for that DG. If two LCO 3.8.1.b DGs are discovered to be inoperable, then Condition G is entered. If one LCO 3.8.1.b DG that provides power to shared systems is discovered inoperable and the LCO 3.8.1.d DG that was initially inoperable provides power to shared systems, then Condition G is also entered. If one LCO 3.8.1.b DG that provides power to shared systems is discovered inoperable and the LCO 3.8.1.d DG that was initially inoperable only provides power to its respective NSWS pump, then Condition B is entered for the LCO 3.8.1.b DG.
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| If the second LCO 3.8.1.d DG, which is the other opposite units DG, is found to be inoperable when performing the administrative verification of operability, then Condition G is entered.
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| D.2 To ensure a highly reliable power source remains with one required LCO 3.8.1.d DG inoperable, it is necessary to verify the OPERABILITY of the required offsite circuits on a more frequent basis. Since the Required Action only specifies perform, a failure of SR 3.8.1.1 acceptance criteria does not result in a Required Action not met. However, if a circuit fails to pass SR 3.8.1.1, it is inoperable. Upon offsite circuit inoperability, additional Conditions and Required Actions must then be entered.
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| D.3 Required Action D.3 is intended to provide assurance that a loss of offsite power, during the period one required LCO 3.8.1.d DG is inoperable, does not result in a complete loss of safety function for the NSWS (including the NSWS pump), CRAVS, CRACWS or the ABFVES. The Completion Time is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal time zero for beginning the allowed outage time clock. In this Required Action, the Completion Time only begins on discovery that both:
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| : a. An inoperable LCO 3.8.1.d DG exists; and
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| : b. NSWS (including the NSWS pump), CRAVS, CRACWS or ABFVES on the other train that has emergency power is inoperable.
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| Catawba Units 1 and 2 B 3.8.1-15 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)
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| If at any time during the existence of this Condition (the LCO 3.8.1.d DG inoperable) a train of NSWS (including the NSWS pump), CRAVS, CRACWS or ABFVES becomes inoperable, this Completion Time begins to be tracked.
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| Discovering the LCO 3.8.1.d DG inoperable coincident with one train of NSWS (including the NSWS pump), CRAVS, CRACWS or ABFVES that is associated with the other train that has emergency power results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown.
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| In this Condition, the remaining OPERABLE DGs and offsite circuits are adequate to supply electrical power to the onsite Class 1E Distribution System. Thus, on a component basis, single failure protection for the NSWS (including the NSWS pump), CRAVS, CRACWS or ABFVES may have been lost; however, function has not been lost. The four hour Completion Time also takes into account the capacity and capability of the remaining NSWS (including the NSWS pump), CRAVS, CRACWS and ABFVES train, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
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| D.4.1 and D.4.2 Required Action D.4.1 provides an allowance to avoid unnecessary testing of OPERABLE DGs. If it can be determined that the cause of the inoperable DG does not exist on the OPERABLE DG(s), SR 3.8.1.2 does not have to be performed. If the cause of inoperability exists on other DG(s), the other DG(s) would be declared inoperable upon discovery and Condition B and I of LCO 3.8.1, as applicable, would be entered. Once the failure is repaired, the common cause failure no longer exists and Required Action D.4.1 is satisfied. If the cause of the initial inoperable DG cannot be confirmed not to exist on the remaining DG(s),
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| performance of SR 3.8.1.2 suffices to provide assurance of continued OPERABILITY of the DG(s).
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| In the event the inoperable DG is restored to OPERABLE status prior to completing either D.4.1 or D.4.2, the problem investigation process will continue to evaluate the common cause possibility. This continued evaluation, however, is no longer under the 24 hour constraint imposed while in Condition D.
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| According to Generic Letter 84-15 (Ref. 8), 24 hours is reasonable to confirm that the OPERABLE DG(s) is not affected by the same problem Catawba Units 1 and 2 B 3.8.1-16 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) as the inoperable DG.
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| D.5 In order to extend the Completion Time for an inoperable DG from 72 hours to 14 days, it is necessary to ensure the availability of the ESPS within 1 hour of entry into TS 3.8.1 LCO and every 12 hours thereafter.
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| Since Required Action D.5 only specifies evaluate, discovering the ESPS unavailable does not result in the Required Action being not met (i.e. the evaluation is performed). However, on discovery of an unavailable ESPS, the Completion Time for Required Action D.6 starts the 72 hour and/or 24 hour clock.
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| ESPS availability requires that:
| |
| : 1) The load test has been performed within 30 days of entry into the extended Completion Time. The Required Action evaluation is met with an administrative verification of this prior to testing; and
| |
| : 2) ESPS fuel tank level is verified locally to be KRXUVXSSO\ DQG
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| : 3) ESPS supporting system parameters for starting and operating are verified to be within required limits for functional availability (e.g., battery state of charge).
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| The ESPS is not used to extend the Completion Time for more than one inoperable DG at any one time.
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| D.6 In accordance with Branch Technical Position 8-8 (Ref. 14), operation may continue in Condition D for a period that should not exceed 14 days, provided a supplemental AC power source is available.
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| In Condition D, the remaining OPERABLE DGs, unavailable ESPS, and offsite power circuits are adequate to supply electrical power to the Class 1E Distribution System. The 14 day Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
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| If the ESPS is or becomes unavailable with an inoperable LCO 3.8.1.d DG, then action is required to restore the ESPS to available status or to restore the DG to OPERABLE status within 72 hours from discovery of Catawba Units 1 and 2 B 3.8.1-17 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) unavailable ESPS. However, if the ESPS unavailability occurs at or sometime after 48 hours of continuous LCO 3.8.1.d DG inoperability, then the remaining time to restore the ESPS to available status or to restore the DG to OPERABLE status is limited to 24 hours.
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| The 72 hour and 24 hour Completion Times allow for an exception to the normal time zero for beginning the allowed outage time clock. The 72 hour Completion Time only begins on discovery that both:
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| : a. An inoperable DG exists; and
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| : b. ESPS is unavailable.
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| The 24 hour Completion Time only begins on discovery that:
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| : a. An inoperable DG exists for 48 hours; and
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| : b. ESPS is unavailable.
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| Therefore, when one LCO 3.8.1.d DG is inoperable due to either preplanned maintenance (preventive or corrective) or unplanned corrective maintenance work, the Completion Time can be extended from 72 hours to 14 days if ESPS is verified available for backup operation.
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| E.1 and E.2 Condition E is entered when both offsite circuits required by LCO 3.8.1.a are inoperable, or when the offsite circuit required by LCO 3.8.1.c and one offsite circuit required by LCO 3.8.1.a are concurrently inoperable.
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| Condition E is also entered when two offsite circuits required by LCO 3.8.1.c are inoperable.
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| Required Action E.1, which applies when two offsite circuits are inoperable, is intended to provide assurance that an event with a coincident single failure will not result in a complete loss of redundant required safety functions. The Completion Time for this failure of redundant required features is reduced to 12 hours from that allowed for one train without offsite power (Required Action A.2). The rationale for the reduction to 12 hours is that Regulatory Guide 1.93 (Ref. 7) allows a Completion Time of 24 hours for two required offsite circuits inoperable, based upon the assumption that two complete safety trains are OPERABLE. When a concurrent redundant required feature failure exists, this assumption is not the case, and a shorter Completion Time of 12 hours is appropriate. These features are powered from redundant AC safety trains. This includes motor driven auxiliary feedwater pumps.
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| Single train features, such as turbine driven auxiliary pumps, are not Catawba Units 1 and 2 B 3.8.1-18 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) included in the list.
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| The Completion Time for Required Action E.1 is intended to allow the operator time to evaluate and repair any discovered inoperabilities. This Completion Time also allows for an exception to the normal "time zero" for beginning the allowed outage time "clock." In this Required Action the Completion Time only begins on discovery that both:
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| : a. All required offsite circuits are inoperable; and
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| : b. A required feature is inoperable.
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| If at any time during the existence of Condition E (two LCO 3.8.1.a offsite circuits inoperable or one LCO 3.8.1.a offsite circuit and one LCO 3.8.1.c offsite circuit inoperable or two LCO 3.8.1.c offsite circuits inoperable) a required feature becomes inoperable, this Completion Time begins to be tracked.
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| According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition E for a period that should not exceed 24 hours. This level of degradation means that the offsite electrical power system does not have the capability to affect a safe shutdown and to mitigate the effects of an accident; however, the onsite AC sources have not been degraded. This level of degradation generally corresponds to a total loss of the immediately accessible offsite power sources.
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| Because of the normally high availability of the offsite sources, this level of degradation may appear to be more severe than other combinations of two AC sources inoperable that involve one or more DGs inoperable.
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| However, two factors tend to decrease the severity of this level of degradation:
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| : a. The configuration of the redundant AC electrical power system that remains available is not susceptible to a single bus or switching failure; and
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| : b. The time required to detect and restore an unavailable offsite power source is generally much less than that required to detect and restore an unavailable onsite AC source.
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| With both of the required offsite circuits inoperable, sufficient onsite AC sources are available to maintain the unit in a safe shutdown condition in the event of a DBA or transient. In fact, a simultaneous loss of offsite AC sources, a LOCA, and a worst case single failure were postulated as a part of the design basis in the safety analysis. Thus, the 24 hour Catawba Units 1 and 2 B 3.8.1-19 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)
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| Completion Time provides a period of time to effect restoration of one of the offsite circuits commensurate with the importance of maintaining an AC electrical power system capable of meeting its design criteria.
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| According to Reference 6, with the available offsite AC sources, two less than required by the LCO, operation may continue for 24 hours. If two offsite sources are restored within 24 hours, unrestricted operation may continue. If only one offsite source is restored within 24 hours, power operation continues in accordance with Condition A or C, as applicable.
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| F.1 and F.2 Pursuant to LCO 3.0.6, the Distribution System ACTIONS would not be entered even if all AC sources to it were inoperable, resulting in de-energization. Therefore, the Required Actions of Condition F are modified by a Note to indicate that when Condition F is entered with no AC source to any train, the Conditions and Required Actions for LCO 3.8.9, "Distribution SystemsOperating," must be immediately entered. This allows Condition F to provide requirements for the loss of one offsite circuit and one DG, without regard to whether a train is de-energized. LCO 3.8.9 provides the appropriate restrictions for a de-energized train.
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| According to Regulatory Guide 1.93 (Ref. 7), operation may continue in Condition F for a period that should not exceed 12 hours.
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| In Condition F, individual redundancy is lost in both the offsite electrical power system and the onsite AC electrical power system. Since power system redundancy is provided by two diverse sources of power, however, the reliability of the power systems in this Condition may appear higher than that in Condition E (loss of two required offsite circuits). This difference in reliability is offset by the susceptibility of this power system configuration to a single bus or switching failure. The 12 hour Completion Time takes into account the capacity and capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a DBA occurring during this period.
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| G.1 With two LCO 3.8.1.b DGs inoperable, there are no remaining standby AC sources to provide power to most of the ESF systems. With one LCO 3.8.1.b DG that provides power to the shared systems inoperable and one LCO 3.8.1.d DG that provides power to the shared systems inoperable, there are no remaining standby AC sources to the shared Catawba Units 1 and 2 B 3.8.1-20 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued) systems. Also, with two DGs required by LCO 3.8.1.d inoperable, there are no remaining standby AC sources to the two opposite unit NSWS pump(s) and at least one train of shared systems. Thus, with an assumed loss of offsite electrical power, insufficient standby AC sources are available to power the minimum required ESF functions. Since the offsite electrical power system is the only source of AC power for this level of degradation, the risk associated with continued operation for a very short time could be less than that associated with an immediate controlled shutdown (the immediate shutdown could cause grid instability, which could result in a total loss of AC power). Since any inadvertent generator trip could also result in a total loss of offsite AC power, however, the time allowed for continued operation is severely restricted.
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| The intent here is to avoid the risk associated with an immediate controlled shutdown and to minimize the risk associated with this level of degradation.
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| According to Reference 7, with both LCO 3.8.1.b DGs inoperable, with one LCO 3.8.1.b DG that provides power to the shared systems and one LCO 3.8.1.d DG that provides power to the shared systems inoperable, or with two DGs required by LCO 3.8.1.d inoperable, operation may continue for a period that should not exceed 2 hours.
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| H.1 The sequencer(s) is an essential support system to both the offsite circuit and the DG associated with a given ESF bus. Furthermore, the sequencer is on the primary success path for most major AC electrically powered safety systems powered from the associated ESF bus.
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| Therefore, loss of an ESF bus sequencer affects every major ESF system in the train. When a sequencer is inoperable, its associated unit and train related offsite circuit and DG must also be declared inoperable and their corresponding Conditions must also be entered. The 12 hour Completion Time provides a period of time to correct the problem commensurate with the importance of maintaining sequencer OPERABILITY. This time period also ensures that the probability of an accident (requiring sequencer OPERABILITY) occurring during periods when the sequencer is inoperable is minimal.
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| I.1 and I.2 If any Required Action and associated Completion Time of Conditions A, C, F, G, or H are not met, the unit must be brought to a MODE in which the LCO does not apply. Furthermore, if any Required Action and associated Completion Time of Required Actions B.2, B.3, B.4.1, B.4.2, Catawba Units 1 and 2 B 3.8.1-21 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES ACTIONS (continued)
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| B.6, D.2, D.3, D.4.1, D.4.2, and D.6 are not met, 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 hours and to MODE 5 within 36 hours. 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.
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| J.1 Condition J corresponds to a level of degradation in which all redundancy in LCO 3.8.1.a and LCO 3.8.1.b AC electrical power supplies has been lost or in which all redundancy in LCO 3.8.1.c and LCO 3.8.1.d AC electrical power supplies has been lost. At this severely degraded level, any further losses in the AC electrical power system will cause a loss of function. Therefore, no additional time is justified for continued operation. The unit is required by LCO 3.0.3 to commence a controlled shutdown.
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| SURVEILLANCE The AC sources are designed to permit inspection and testing of all REQUIREMENTS important areas and features, especially those that have a standby function, in accordance with 10 CFR 50, Appendix A, GDC 18 (Ref. 9).
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| Periodic component tests are supplemented by extensive functional tests during refueling outages (under simulated accident conditions). The SRs for demonstrating the OPERABILITY of the DGs are in accordance with the recommendations of Regulatory Guide 1.9 (Ref. 3), Regulatory Guide 1.108 (Ref. 10), and Regulatory Guide 1.137 (Ref. 11), as addressed in the UFSAR.
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| Where the SRs discussed herein specify voltage and frequency tolerances, the following is applicable. The minimum steady state output voltage of 3950 V is 95% of the nominal 4160 V output voltage. This value allows for voltage drop to the terminals of 4000 V motors whose minimum operating voltage is specified as 90% or 3600 V. It also allows for voltage drops to motors and other equipment down through the 120 V level where minimum operating voltage is also usually specified as 90%
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| of name plate rating.
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| The specified maximum steady state output voltage of 4320 V ensures that for a lightly loaded distribution system, the voltage at the terminals of 4000 V and 575 V motors is no more than the maximum rated operating voltages.
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| The specified minimum and maximum frequencies of the DG are 58.8 Hz Catawba Units 1 and 2 B 3.8.1-22 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) and 61.2 Hz, respectively. These values are equal to +/- 2% of the 60 Hz nominal frequency and are derived from the recommendations given in Regulatory Guide 1.9 (Ref. 3).
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| SR 3.8.1.1 This SR ensures proper circuit continuity for the offsite AC electrical power supply to the onsite distribution network and availability of offsite AC electrical power. The breaker alignment verifies that each breaker is in its correct position to ensure that distribution buses and loads are connected to their preferred power source, and that appropriate independence of offsite circuits is maintained. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.8.1.2 and SR 3.8.1.7 These SRs help to ensure the availability of the standby electrical power supply to mitigate DBAs and transients and to maintain the unit in a safe shutdown condition.
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| To minimize the wear on moving parts that do not get lubricated when the engine is not running, these SRs are modified by a Note (Note 2 for SR 3.8.1.2) to indicate that all DG starts for these Surveillances may be preceded by an engine prelube period and followed by a warmup period prior to loading. For the purposes of SR 3.8.1.2 and SR 3.8.1.7 testing, the DGs are started from standby conditions using a manual start, loss of offsite power signal, safety injection signal, or loss of offsite power coincident with a safety injection signal. Standby conditions for a DG mean that the diesel engine coolant and oil are being continuously circulated and temperature is being maintained consistent with manufacturer recommendations.
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| In order to reduce stress and wear on diesel engines, the manufacturer recommends a modified start in which the starting speed of DGs is limited, warmup is limited to this lower speed, and the DGs are gradually accelerated to synchronous speed prior to loading. These start procedures are the intent of Note 3, which is only applicable when such modified start procedures are recommended by the manufacturer.
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| SR 3.8.1.7 requires that the DG starts from standby conditions and achieves required voltage and frequency within 11 seconds. The 11 second start requirement supports the assumptions of the design Catawba Units 1 and 2 B 3.8.1-23 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) basis LOCA analysis in the UFSAR, Chapter 15 (Ref. 5).
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| The 11 second start requirement is not applicable to SR 3.8.1.2 (see Note 3) when a modified start procedure as described above is used. If a modified start is not used, the 11 second start requirement of SR 3.8.1.7 applies.
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| Since SR 3.8.1.7 requires a 11 second start, it is more restrictive than SR 3.8.1.2, and it may be performed in lieu of SR 3.8.1.2. This is the intent of Note 1 of SR 3.8.1.2.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.8.1.3 This Surveillance verifies that the DGs are capable of synchronizing with the offsite electrical system and accepting loads greater than or equal to the equivalent of the maximum expected accident loads. A minimum run time of 60 minutes is required to stabilize engine temperatures, while minimizing the time that the DG is connected to the offsite source.
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| Although no power factor requirements are established by this SR, the DG is normally operated at a power factor between 0.8 lagging and 1.0.
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| The 0.8 value is the design rating of the machine, while the 1.0 is an operational limitation to ensure circulating currents are minimized. The load band is provided to avoid routine overloading of the DG. Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| This SR is modified by four Notes. Note 1 indicates that diesel engine runs for this Surveillance may include gradual loading, as recommended by the manufacturer, so that mechanical stress and wear on the diesel engine are minimized. Note 2 states that momentary transients, because of changing bus loads, do not invalidate this test. Similarly, momentary power factor transients above the limit do not invalidate the test. Note 3 indicates that this Surveillance should be conducted on only one DG at a time in order to avoid common cause failures that might result from offsite Catawba Units 1 and 2 B 3.8.1-24 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) circuit or grid perturbations. Note 4 stipulates a prerequisite requirement for performance of this SR. A successful DG start must precede this test to credit satisfactory performance.
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| SR 3.8.1.4 This SR provides verification that the level of fuel oil in the day tank is at or above the level at which fuel oil is automatically added. The level is expressed as an equivalent volume in gallons, and is selected to ensure adequate fuel oil for a minimum of 1 hour of DG operation at full load plus 10%.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.8.1.5 Microbiological fouling is a major cause of fuel oil degradation. There are numerous bacteria that can grow in fuel oil and cause fouling, but all must have a water environment in order to survive. Removal of water from the fuel oil day tanks eliminates the necessary environment for bacterial survival. This is the most effective means of controlling microbiological fouling. In addition, it eliminates the potential for water entrainment in the fuel oil during DG operation. Water may come from any of several sources, including condensation, ground water, rain water, contaminated fuel oil, and breakdown of the fuel oil by bacteria. Frequent checking for and removal of accumulated water minimizes fouling and provides data regarding the watertight integrity of the fuel oil system. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program. This SR is for preventative maintenance.
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| The presence of water does not necessarily represent failure of this SR, provided the accumulated water is removed during the performance of this Surveillance.
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| SR 3.8.1.6 This Surveillance demonstrates that each required fuel oil system operates and transfers fuel oil from its associated storage tanks to its associated day tank. This is required to support continuous operation of standby power sources. This Surveillance provides assurance that the fuel oil valve is OPERABLE, and allows gravity feed of fuel oil to the day tank from underground storage tanks, to ensure the fuel oil piping system Catawba Units 1 and 2 B 3.8.1-25 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) is intact, the fuel delivery piping is not obstructed, and the controls and control systems for fuel transfer systems are OPERABLE.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.8.1.7 See SR 3.8.1.2.
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| SR 3.8.1.8 Transfer of each 4.16 kV ESF bus power supply from the normal offsite circuit to the alternate offsite circuit demonstrates the capability of the alternate circuit distribution network to power the shutdown loads. The alternate circuit distribution network consists of an offsite power source through a 6.9 kV bus incoming breaker, its associated 6.9 kV bus tie breaker and the aligned 6.9/4.16 kV transformer to the essential bus. The requirement of this SR is the transfer from the normal offsite circuit to the alternate offsite circuit via the automatic and manual actuation of the 6.9 kV bus tie breaker and 6.9 kV bus incoming breakers upon loss of the normal offsite source that is being credited. The 6.9 kV bus tie breaker provides a means for each of the offsite circuits to act as a backup in the event power is not available from one of the circuits. The Catawba power system design, without the tie breaker, meets all GDC 17 requirements as well as all other standards to which Catawba is committed. If the tie breaker is incapable of closing manually or automatically during its required MODE of applicability, then the Surveillance is not met and the normal offsite circuit that supplies that Class 1E ESF bus is inoperable and the applicable Condition shall be entered and the Required Actions shall be performed. Table B 3.8.1-1 identifies the offsite circuit affected by a non-functioning tie breaker.
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| The intent of the tie breaker is to provide an alternate means of power to a Class 1E ESF bus; this assumes there are two available offsite circuits.
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| In the event an offsite circuit is lost for any reason, the function of the tie breaker is to close, and the offsite circuit that is supplying its normally connected Class 1E ESF bus is fully OPERABLE. With the tie breaker closed, then both Class 1E ESF buses are provided power from a single offsite circuit. The normally connected offsite circuit of the Class 1E ESF bus that is being supplied through the tie breaker shall be declared inoperable and the applicable Condition shall be entered and the Required Actions shall be performed. If the tie breaker does not close, Catawba Units 1 and 2 B 3.8.1-26 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) then the associated Class 1E ESF bus will be supplied power from its associated DG. In this event, the associated offsite circuit is inoperable and the applicable Condition shall be entered and the Required Actions shall be performed. Capability of manually swapping to a standby transformer is not required to satisfy this SR. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| Catawba Units 1 and 2 B 3.8.1-27 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| Table B 3.8.1-1 (page 1 of 1)
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| Relationship between Tie Breakers and Offsite Circuits Tie Breaker Description Essential Load Center and Affected Offsite Transformer Circuit 1TA-7 7kV Bus 1TA 1ETA from 1ATC Tie Breaker 1TC-7 7kV Bus 1TC 1ETA from SATA from Unit 1 Tie Breaker 1A 2TC-7 7kV Bus 2TC 1ETA from SATA from Unit 2 Tie Breaker 1TD-7 7kV Bus 1TD 1ETB from 1ATD Tie Breaker 1TB-7 7kV Bus 1TB 1ETB from SATB from Unit 1 Tie Breaker 1B 2TB-7 7kV Bus 2TB 1ETB from SATB from Unit 2 Tie Breaker 2TA-7 7kV Bus 2TA 2ETA from 2ATC Tie Breaker 1TC-7 7kV Bus 1TC 2ETA from SATA from Unit 1 Tie Breaker 2A 2TC-7 7kV Bus 2TC 2ETA from SATA from Unit 2 Tie Breaker 2TD-7 7kV Bus 2TD 2ETB from 2ATD Tie Breaker 1TB-7 7kV Bus 1TB 2ETB from SATB from Unit 1 2B Tie Breaker 2TB-7 7kV Bus 2TB 2ETB from SATB from Unit 2 Tie Breaker Catawba Units 1 and 2 B 3.8.1-28 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.8.1.9 Each DG is provided with an engine overspeed trip to prevent damage to the engine. Recovery from the transient caused by the loss of a large load could cause diesel engine overspeed, which, if excessive, might result in a trip of the engine. This Surveillance demonstrates the DG load response characteristics and capability to reject the largest single load without exceeding predetermined voltage and frequency and while maintaining a specified margin to the overspeed trip. For this unit, the single load for each DG and its horsepower rating is as follows: Nuclear Service Water pump which is a 1000 H.P. motor. This Surveillance may be accomplished by:
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| : a. Tripping the DG output breaker with the DG carrying greater than or equal to its associated single largest post-accident load while paralleled to offsite power, or while solely supplying the bus; or
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| : b. Tripping its associated single largest post-accident load with the DG solely supplying the bus.
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| As required by Regulatory Guide 1.9 (Ref. 3), the load rejection test is acceptable if the increase in diesel speed does not exceed 75% of the difference between synchronous speed and the overspeed trip setpoint.
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| The value of 63 Hz has been selected for the frequency limit for the load rejection and it is a more conservative limit than required by Reference 3.
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| The time, voltage, and frequency tolerances specified in this SR are derived from Regulatory Guide 1.9 (Ref. 3) recommendations for response during load sequence intervals. The 3 seconds specified is equal to 60% of a typical 5 second load sequence interval associated with sequencing of the largest load. The voltage and frequency specified are consistent with the design range of the equipment powered by the DG.
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| SR 3.8.1.9.a corresponds to the maximum frequency excursion, while SR 3.8.1.9.b and SR 3.8.1.9.c are steady state voltage and frequency values to which the system must recover following load rejection. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| This SR is modified by a Note. In order to ensure that the DG is tested under load conditions that are as close to design basis conditions as possible, the Note requires that, if synchronized to offsite power, testing must be performed using a power factor d 0.9. This power factor is chosen to be representative of the actual design basis inductive loading that the DG would experience.
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| Catawba Units 1 and 2 B 3.8.1-29 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.8.1.10 This Surveillance demonstrates the DG capability to reject a full load without overspeed tripping or exceeding the predetermined voltage limits.
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| The DG full load rejection may occur because of a system fault or inadvertent breaker tripping. This Surveillance ensures proper engine generator load response under the simulated test conditions. This test simulates the loss of the total connected load that the DG experiences following a full load rejection and verifies that the DG does not trip upon loss of the load. These acceptance criteria provide for DG damage protection. While the DG is not expected to experience this transient during an event and continues to be available, this response ensures that the DG is not degraded for future application, including reconnection to the bus if the trip initiator can be corrected or isolated.
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| Although not representative of the design basis inductive loading that the DG would experience, a power factor of approximately unity (1.0) is used for testing. This power factor is chosen in accordance with manufacturer's recommendations to minimize DG overvoltage damage during testing.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| SR 3.8.1.11 As required by Regulatory Guide 1.108 (Ref. 10), paragraph 2.a.(1), this Surveillance demonstrates the as designed operation of the standby power sources during loss of the offsite source. This test verifies all actions encountered from the loss of offsite power, including shedding of the nonessential loads and energization of the emergency buses and respective loads from the DG. It further demonstrates the capability of the DG to automatically achieve the required voltage and frequency within the specified time.
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| The DG autostart time of 11 seconds is derived from requirements of the accident analysis to respond to a design basis large break LOCA. The Surveillance should be continued for a minimum of 5 minutes in order to demonstrate that all starting transients have decayed and stability is achieved.
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| Catawba Units 1 and 2 B 3.8.1-30 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| The requirement to verify the connection and power supply of the emergency bus and autoconnected loads is intended to satisfactorily show the relationship of these loads to the DG loading logic. In certain circumstances, many of these loads cannot actually be connected or loaded without undue hardship or potential for undesired operation. For instance, Emergency Core Cooling Systems (ECCS) injection valves are not desired to be stroked open, or high pressure injection systems are not capable of being operated at full flow, or residual heat removal (RHR) systems performing a decay heat removal function are not desired to be realigned to the ECCS mode of operation. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG systems to perform these functions is acceptable.
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| This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| This SR is modified by two Notes. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations. The reason for Note 2 is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems. 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.
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| 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.
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| Risk insights or deterministic methods may be used for this assessment.
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| Credit may be taken for unplanned events that satisfy this SR.
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| Catawba Units 1 and 2 B 3.8.1-31 Revision No. 9
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| AC Sources-Operating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.8.1.12 This Surveillance demonstrates that the DG automatically starts and achieves the required voltage and frequency within the specified time (11 seconds) from the design basis actuation signal (LOCA signal) and operates for t 5 minutes. The 5 minute period provides sufficient time to demonstrate stability. SR 3.8.1.12.d ensures that the emergency bus remains energized from the offsite electrical power system on an ESF signal without loss of offsite power.
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| 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 a Note. The reason for the Note is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations.
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| SR 3.8.1.13 This Surveillance demonstrates that DG non-emergency protective functions (e.g., high jacket water temperature) are bypassed on a loss of voltage signal concurrent with an ESF actuation test signal. Non-emergency automatic trips are all automatic trips except:
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| : a. Engine overspeed;
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| : b. Generator differential current;
| |
| : c. Low - low lube oil pressure; and
| |
| : d. Voltage control overcurrent relay scheme.
| |
| The non-emergency trips are bypassed during DBAs and provide an alarm on an abnormal engine condition. This alarm provides the operator with sufficient time to react appropriately. The DG availability to mitigate the DBA is more critical than protecting the engine against minor problems that are not immediately detrimental to emergency operation of the DG. Currently, DG emergency automatic trips are tested periodically per the station periodic maintenance program.
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| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| Catawba Units 1 and 2 B 3.8.1-32 Revision No. 9
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| | |
| AC SourcesOperating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
| |
| SR 3.8.1.14 Regulatory Guide 1.108 (Ref. 10), paragraph 2.a.(3), requires demonstration that the DGs can start and run continuously at full load capability for an interval of not less than 24 hours. The DG starts for this Surveillance can be performed either from standby or hot conditions. The provisions for prelubricating and warmup, discussed in SR 3.8.1.2, and for gradual loading, discussed in SR 3.8.1.3, are applicable to this SR.
| |
| In order to ensure that the DG is tested under load conditions that are as close to design conditions as possible, testing must be performed using a power factor of d 0.9. This power factor is chosen to be representative of the actual design basis inductive loading that the DG would experience.
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| The load band is provided to avoid routine overloading of the DG.
| |
| Routine overloading may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY.
| |
| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
| |
| This Surveillance is modified by a Note. The Note states that momentary transients due to changing bus loads do not invalidate this test. Similarly, momentary power factor transients above the power factor limit will not invalidate the test.
| |
| SR 3.8.1.15 This Surveillance demonstrates that the diesel engine can restart from a hot condition, such as subsequent to shutdown from normal Surveillances, and achieve the required voltage and frequency within 11 seconds. The 11 second time is derived from the requirements of the accident analysis to respond to a design basis large break LOCA. 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 ensures that the test is performed with the diesel sufficiently hot. The load band is provided to avoid routine overloading of the DG. Routine overloads may result in more frequent teardown inspections in accordance with vendor recommendations in order to maintain DG OPERABILITY. The requirement that the diesel has operated for at least an hour at full load conditions prior to performance of this Surveillance is based on Catawba Units 1 and 2 B 3.8.1-33 Revision No. 9
| |
| | |
| AC SourcesOperating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) manufacturer recommendations for achieving hot conditions. Momentary transients due to changing bus loads do not invalidate this test. Note 2 allows all DG starts to be preceded by an engine prelube period to minimize wear and tear on the diesel during testing.
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| SR 3.8.1.16 As required by Regulatory Guide 1.108 (Ref. 10), paragraph 2.a.(6), this Surveillance ensures that the manual synchronization and automatic load transfer from the DG to the offsite source can be made and the DG can be returned to standby operation when offsite power is restored. It also ensures that the autostart logic is reset to allow the DG to reload if a subsequent loss of offsite power occurs. The DG is considered to be in standby operation when the DG is at rated speed and voltage, the output breaker is open and can receive an autoclose signal on bus undervoltage, and the load sequence timers are reset.
| |
| 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 a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.
| |
| This restriction from normally performing the Surveillance in MODE 1, 2, 3, or 4 is further amplified to allow 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 Surveillance, a successful Surveillance, and a perturbation of the offsite or onsite system when they are tied together or operated independently for the 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 the Surveillance is 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.
| |
| Catawba Units 1 and 2 B 3.8.1-34 Revision No. 9
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| | |
| AC SourcesOperating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
| |
| SR 3.8.1.17 Demonstration of the test mode override ensures that the DG availability under accident conditions will not be compromised as the result of testing and the DG will automatically reset to standby operation if a LOCA actuation signal is received during operation in the test mode. Standby operation is defined as the DG running at rated speed and voltage with the DG output breaker open. These provisions for automatic switchover are required by Regulatory Guide 1.9 (Ref. 3).
| |
| The requirement to automatically energize the emergency loads with offsite power is essentially identical to that of SR 3.8.1.12. The intent in the requirement associated with SR 3.8.1.17.b is to show that the emergency loading was not affected by the DG operation in test mode. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the emergency loads to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.
| |
| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
| |
| This SR is modified by a Note. The reason for the Note is that performing the Surveillance would remove a required offsite circuit from service, perturb the electrical distribution system, and challenge safety systems.
| |
| 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.
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| Catawba Units 1 and 2 B 3.8.1-35 Revision No. 9
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| AC SourcesOperating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued)
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| SR 3.8.1.18 Under accident and loss of offsite power conditions loads are sequentially connected to the bus by the automatic load sequencer. The sequencing logic controls the permissive and starting signals to motor breakers to prevent overloading of the DGs due to high motor starting currents. The load sequence time interval tolerance in Table 8-6 of Reference 2 ensures that sufficient time exists for the DG to restore frequency and voltage prior to applying the next load and that safety analysis assumptions regarding ESF equipment time delays are not violated.
| |
| Table 8-6 of Reference 2 provides a summary of the automatic loading of ESF buses.
| |
| The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
| |
| SR 3.8.1.19 In the event of a DBA coincident with a loss of offsite power, the DGs are required to supply the necessary power to ESF systems so that the fuel, RCS, and containment design limits are not exceeded.
| |
| This Surveillance demonstrates the DG operation, as discussed in the Bases for SR 3.8.1.11, during a loss of offsite power actuation test signal in conjunction with an ESF actuation signal. In lieu of actual demonstration of connection and loading of loads, testing that adequately shows the capability of the DG system to perform these functions is acceptable. This testing may include any series of sequential, overlapping, or total steps so that the entire connection and loading sequence is verified.
| |
| The Surveillance Frequency is 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. The reason for Note 1 is to minimize wear and tear on the DGs during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations for DGs. The reason for Note 2 is that the performance of the Surveillance would remove a required offsite circuit from service, 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 Catawba Units 1 and 2 B 3.8.1-36 Revision No. 9
| |
| | |
| AC SourcesOperating B 3.8.1 BASES SURVEILLANCE REQUIREMENTS (continued) 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 3.8.1.20 This Surveillance demonstrates that the DG starting independence has not been compromised. Also, this Surveillance demonstrates that each engine can achieve proper speed within the specified time when the DGs are started simultaneously.
| |
| 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 a Note. The reason for the Note is to minimize wear on the DG during testing. For the purpose of this testing, the DGs must be started from standby conditions, that is, with the engine coolant and oil continuously circulated and temperature maintained consistent with manufacturer recommendations.
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| Catawba Units 1 and 2 B 3.8.1-37 Revision No. 9
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| AC SourcesOperating B 3.8.1 BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.
| |
| : 2. UFSAR, Chapter 8.
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| : 3. Regulatory Guide 1.9, Rev. 2, December 1979.
| |
| : 4. UFSAR, Chapter 6.
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| : 5. UFSAR, Chapter 15.
| |
| : 6. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| : 7. Regulatory Guide 1.93, Rev. 0, December 1974.
| |
| : 8. Generic Letter 84-15, "Proposed Staff Actions to Improve and Maintain Diesel Generator Reliability," July 2, 1984.
| |
| : 9. 10 CFR 50, Appendix A, GDC 18.
| |
| : 10. Regulatory Guide 1.108, Rev. 1, August 1977 (Supplement September 1977).
| |
| : 11. Regulatory Guide 1.137, Rev. 1, October 1979.
| |
| : 12. ASME, Boiler and Pressure Vessel Code, Section XI.
| |
| : 13. Response to a Request for Additional Information (RAI) concerning the June 5, 2006 License Amendment Request (LAR) Applicable to Technical Specification (TS) 3.8.1, AC Sources-Operating, Surveillance Requirement (SR) 3.8.1.13, (TAC NOS. MD3217, MD3218, MD3219, and MD3220), April 4, 2007.
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| : 14. Branch Technical Position 8-8, February 2012.
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| Catawba Units 1 and 2 B 3.8.1-38 Revision No. 9
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| | |
| 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).
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| 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.
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| Catawba Units 1 and 2 B 3.8.4-1 Revision No. 12
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| DC SourcesOperating B 3.8.4 BASES BACKGROUND (continued)
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| 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 hours.
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| 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).
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| 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 hours while supplying normal steady state loads discussed in the UFSAR, Chapter 8 (Ref. 4).
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| 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 Catawba Units 1 and 2 B 3.8.4-2 Revision No. 12
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| | |
| DC SourcesOperating B 3.8.4 BASES APPLICABLE SAFETY ANALYSES (continued) normal and emergency DC electrical power for the DGs, emergency auxiliaries, and control and switching during all MODES of operation.
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| 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).
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| 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).
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| An OPERABLE DC electrical power subsystem requires a battery and respective charger to be operating and connected to the associated DC bus.
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| 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:
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| : 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.
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| The DC electrical power requirements for MODES 5 and 6 are addressed in the Bases for LCO 3.8.5, "DC SourcesShutdown."
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| Catawba Units 1 and 2 B 3.8.4-3 Revision No. 12
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| DC SourcesOperating B 3.8.4 BASES 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 hours. 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 hours and to MODE 5 within 36 hours. 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.
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| 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.
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| 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 Catawba Units 1 and 2 B 3.8.4-4 Revision No. 12
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| DC SourcesOperating B 3.8.4 BASES 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.
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| 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.
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| Catawba Units 1 and 2 B 3.8.4-5 Revision No. 12
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| | |
| DC SourcesOperating B 3.8.4 BASES SURVEILLANCE REQUIREMENTS (continued)
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| 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.
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| 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).
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| 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.
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| Catawba Units 1 and 2 B 3.8.4-6 Revision No. 12
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| DC SourcesOperating B 3.8.4 BASES SURVEILLANCE REQUIREMENTS (continued)
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| 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.
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| 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 hours.
| |
| 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.
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| Catawba Units 1 and 2 B 3.8.4-7 Revision No. 12
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| DC SourcesOperating B 3.8.4 BASES 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-1381.05-00-0011, 125 VDC Vital Instrumentation and Control Power System 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 DC battery terminal voltage is determined through Calculation CNC-1381.05-00-0149, 125 VDC Vital I&C Power System (EPL) Voltage Drop Analysis. The DG batterys actual duty cycle is identified in calculation CNC-1381.05-00-0050, 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.
| |
| Catawba Units 1 and 2 B 3.8.4-8 Revision No. 12
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| | |
| DC SourcesOperating B 3.8.4 BASES 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.
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| 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.
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| 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.
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| 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%
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| Catawba Units 1 and 2 B 3.8.4-9 Revision No. 12
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| DC SourcesOperating B 3.8.4 BASES SURVEILLANCE REQUIREMENTS (continued) shows that the battery rate of deterioration is increasing, even if there is ample capacity to meet the load requirements.
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| 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%
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| 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.
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| Catawba Units 1 and 2 B 3.8.4-10 Revision No. 12
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| DC SourcesOperating B 3.8.4 BASES REFERENCES 1. 10 CFR 50, Appendix A, GDC 17.
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| : 2. Regulatory Guide 1.6, March 10, 1971.
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| : 3. IEEE-308-1971 and 1974.
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| : 4. UFSAR, Chapter 8.
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| : 5. IEEE-485-1983, June 1983.
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| : 6. UFSAR, Chapter 6.
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| : 7. UFSAR, Chapter 15.
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| : 8. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| : 9. IEEE-450-1975 and/or 1980.
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| : 10. Regulatory Guide 1.32, February 1977.
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| : 11. IEEE-450-1995.
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| : 12. UFSAR Table 18-1.
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| : 13. UFSAR Section 18.3.1.
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| Catawba Units 1 and 2 B 3.8.4-11 Revision No. 12
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| Distribution SystemsOperating B 3.8.9 Distribution SystemsOperating B 3.8.9 B 3.8 ELECTRICAL POWER SYSTEMS B 3.8.9 Distribution SystemsOperating BASES BACKGROUND The onsite Class 1E AC, channels of DC, trains of DC, and AC vital bus electrical power distribution systems are divided by train into two redundant and independent AC, DC, four independent channels (two per train) of DC, and four AC vital buses of electrical power distribution subsystems.
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| The AC electrical power subsystem for each train consists of a primary Engineered Safety Feature (ESF) 4.16 kV bus and secondary 600 V buses, distribution panels, motor control centers and load centers. Each 4.16 kV ESF bus has at least one separate and independent offsite source of power as well as a dedicated onsite diesel generator (DG) source. Each 4.16 kV ESF bus is normally connected to a preferred offsite source. After a loss of the preferred offsite power source to a 4.16 kV ESF bus, a transfer to the alternate source is accomplished on the non safety related 6.9 kV buses by either an automatic fast or slow transfer. If all offsite sources are unavailable, the onsite emergency DG supplies power to the 4.16 kV ESF bus. Control power for the 4.16 kV breakers is supplied from the Class 1E or the DG DC batteries.
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| Additional description of this system may be found in the Bases for LCO 3.8.1, "AC SourcesOperating," and the Bases for LCO 3.8.4, "DC SourcesOperating."
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| The secondary AC electrical power distribution system for each train includes the safety related load centers, motor control centers, and distribution panels shown in Table B 3.8.9-1.
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| The 120 VAC vital buses are arranged in two load groups per train and are normally powered from the inverters. The alternate power supply for the vital buses is a constant voltage source transformer and its use is governed by LCO 3.8.7, "InvertersOperating." The constant voltage source transformer is powered from a non-Class 1E AC bus.
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| The list of all required distribution buses is presented in Table B 3.8.9-1.
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| Catawba Units 1 and 2 B 3.8.9-1 Revision No. 3
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| Distribution SystemsOperating B 3.8.9 BASES APPLICABLE The initial conditions of Design Basis Accident (DBA) and transient SAFETY ANALYSES analyses in the UFSAR, Chapter 6 (Ref. 1), and in the UFSAR, Chapter 15 (Ref. 2), assume ESF systems are OPERABLE. The AC, DC, and AC vital bus electrical power distribution systems are designed to provide sufficient capacity, capability, redundancy, and reliability to ensure the availability of necessary power to ESF systems so that the fuel, Reactor Coolant System, and containment design limits are not exceeded. These limits are discussed in more detail in the Bases for Section 3.2, Power Distribution Limits; Section 3.4, Reactor Coolant System (RCS); and Section 3.6, Containment Systems.
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| The OPERABILITY of the AC, DC, and AC vital bus electrical power distribution systems is consistent with the initial assumptions of the accident analyses and is based upon meeting the design basis of the unit.
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| This includes maintaining power distribution systems OPERABLE during accident conditions in the event of:
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| : a. An assumed loss of all offsite power or all onsite AC electrical power; and
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| : b. A worst case single failure.
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| The distribution systems satisfy Criterion 3 of 10 CFR 50.36 (Ref. 3).
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| LCO The required power distribution subsystems listed in Table B 3.8.9-1 ensure the availability of AC, DC, and AC vital bus electrical power for the systems required to shut down the reactor and maintain it in a safe condition after an anticipated operational occurrence (AOO) or a postulated DBA. The AC, DC, and AC vital bus electrical power distribution subsystems are required to be OPERABLE.
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| Maintaining the Train A and Train B AC, channels of DC, DC Train A and Train B, and AC vital bus electrical power distribution subsystems OPERABLE ensures that the redundancy incorporated into the design of ESF is not defeated. Therefore, a single failure within any system or within the electrical power distribution subsystems will not prevent safe shutdown of the reactor.
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| OPERABLE AC electrical power distribution subsystems require the associated buses, load centers, motor control centers, and distribution panels to be energized to their proper voltages. OPERABLE channels of DC electrical power distribution subsystems require the associated buses to be energized to their proper voltage from either the associated battery or charger. OPERABLE DC train electrical power distribution subsystems Catawba Units 1 and 2 B 3.8.9-2 Revision No. 3
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| Distribution SystemsOperating B 3.8.9 BASES LCO (continued) require the associated buses to be energized to their proper voltage from either the associated battery or charger. OPERABLE AC vital bus electrical power distribution subsystems require the associated buses to be energized to their proper voltage from the associated inverter via inverted DC voltage or constant voltage transformer.
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| APPLICABILITY The electrical power distribution subsystems are required to be OPERABLE in MODES 1, 2, 3, and 4 to ensure that:
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| : a. Acceptable fuel design limits and reactor coolant pressure boundary limits are not exceeded as a result of AOOs or abnormal transients; and
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| : b. Adequate core cooling is provided, and containment OPERABILITY and other vital functions are maintained in the event of a postulated DBA.
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| Electrical power distribution subsystem requirements for MODES 5 and 6 are covered in the Bases for LCO 3.8.10, "Distribution Systems Shutdown."
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| ACTIONS A.1 With one or more required AC buses, load centers, motor control centers, or distribution panels, except AC vital buses, inoperable, and a loss of function has not occurred the remaining AC electrical power distribution subsystems are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The overall reliability is reduced, however, because a single failure in the remaining power distribution subsystems could result in the minimum required ESF functions not being supported. Therefore, the required AC buses, load centers, motor control centers, and distribution panels must be restored to OPERABLE status within 8 hours.
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| Condition A worst scenario is one train without AC power (i.e., no offsite power to the train and the associated DG inoperable). In this Condition, the unit is more vulnerable to a complete loss of AC power. It is, therefore, imperative that the unit operator's attention be focused on minimizing the potential for loss of power to the remaining train by Catawba Units 1 and 2 B 3.8.9-3 Revision No. 3
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| Distribution SystemsOperating B 3.8.9 BASES ACTIONS (continued) stabilizing the unit, and on restoring power to the affected train. The 8 hour time limit before requiring a unit shutdown in this Condition is acceptable because of:
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| : a. The potential for decreased safety if the unit operator's attention is diverted from the evaluations and actions necessary to restore power to the affected train, to the actions associated with taking the unit to shutdown within this time limit; and
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| : b. The potential for an event in conjunction with a single failure of a redundant component in the train with AC power.
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| B.1 With one AC vital bus inoperable, the remaining OPERABLE AC vital buses are capable of supporting the minimum safety functions necessary to shut down the unit and maintain it in the safe shutdown condition.
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| Overall reliability is reduced, however, since an additional single failure could result in the minimum ESF functions not being supported.
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| Therefore, the required AC vital bus must be restored to OPERABLE status within 2 hours by powering the bus from the associated inverter via inverted DC or constant voltage transformer.
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| Condition B represents one AC vital bus without power; potentially both the DC source and the associated AC source are nonfunctioning. In this situation, the unit is significantly more vulnerable to a complete loss of all noninterruptible power. It is, therefore, imperative that the operator's attention focus on stabilizing the unit, minimizing the potential for loss of power to the remaining vital buses and restoring power to the affected vital bus.
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| This 2 hour limit is more conservative than Completion Times allowed for the vast majority of components that are without adequate vital AC power.
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| Taking exception to LCO 3.0.2 for components without adequate vital AC power, that would have the Required Action Completion Times shorter than 2 hours if declared inoperable, is acceptable because of:
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| : a. The potential for decreased safety by requiring a change in unit conditions (i.e., requiring a shutdown) and not allowing stable operations to continue;
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| : b. The potential for decreased safety by requiring entry into numerous Applicable Conditions and Required Actions for components without adequate vital AC power and not providing sufficient time for the operators to perform the necessary evaluations and actions Catawba Units 1 and 2 B 3.8.9-4 Revision No. 3
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| Distribution SystemsOperating B 3.8.9 BASES ACTIONS (continued) for restoring power to the affected train; and
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| : c. The potential for an event in conjunction with a single failure of a redundant component.
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| The 2 hour Completion Time takes into account the importance to safety of restoring the AC vital bus to OPERABLE status, the redundant capability afforded by the other OPERABLE vital buses, and the low probability of a DBA occurring during this period.
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| C.1 With one DC bus inoperable, the remaining DC electrical power distribution subsystems are capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The overall reliability is reduced, however, because a single failure in the remaining DC electrical power distribution subsystem could result in the minimum required ESF functions not being supported. Therefore, the DC buses must be restored to OPERABLE status within 2 hours by powering the bus from the associated battery or charger.
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| Condition C represents one DC bus without adequate DC power; potentially both with the battery significantly degraded and the associated charger nonfunctioning. It is, therefore, imperative that the operator's attention focus on stabilizing the unit, minimizing the potential for loss of power to the remaining channels and restoring power to the affected channel.
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| This 2 hour limit is more conservative than Completion Times allowed for the vast majority of components that would be without power. Taking exception to LCO 3.0.2 for components without adequate DC power, which would have Required Action Completion Times shorter than 2 hours, is acceptable because of:
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| : a. The potential for decreased safety by requiring a change in unit conditions (i.e., requiring a shutdown) versus allowing stable operations to continue;
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| : b. The potential for decreased safety by requiring entry into numerous applicable Conditions and Required Actions for components without DC power and not providing sufficient time for the operators to perform the necessary evaluations and actions for restoring power to the affected channel; and Catawba Units 1 and 2 B 3.8.9-5 Revision No. 3
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| Distribution SystemsOperating B 3.8.9 BASES ACTIONS (continued)
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| : c. The potential for an event in conjunction with a single failure of a redundant component.
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| D.1 With a train of DC inoperable, the remaining DC train is capable of supporting the minimum safety functions necessary to shut down the reactor and maintain it in a safe shutdown condition, assuming no single failure. The reliability is reduced because a single failure in the remaining train of DC could result in the minimum required ESF functions not being supported. Therefore, the train of DC must be restored to OPERABLE status within 2 hours.
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| Condition D represents the loss of control power for an entire safety train.
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| In this situation, the unit is significantly more vulnerable to a complete loss of all DC control power with a corresponding loss of required ESF functions. It is therefore imperative that the operator's attention focus on stabilizing the unit, minimizing the potential for loss of power to the remaining Train of DC and restoring the power to the affected train.
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| The two hour limit is more conservative than Completion Times allowed for the majority of components that would be without power. Taking exception to LCO 3.0.2 for components without adequate DC power, which would have Required Action Completion Times shorter than 2 hours, is acceptable because of:
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| : a. The potential for decreased safety by requiring a change in unit conditions (i.e., requiring a shutdown) versus allowing stable operations to continue;
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| : b. The potential for decreased safety by requiring entry into numerous applicable Conditions and Required Actions for components without DC power and not providing sufficient time for the operators to perform the necessary evaluations and actions for restoring power to the affected train; and
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| : c. The potential for an event in conjunction with a single failure of a redundant component.
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| The 2 hour Completion Time for a train of DC is consistent with Regulatory Guide 1.93 (Ref. 4).
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| Catawba Units 1 and 2 B 3.8.9-6 Revision No. 3
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| Distribution SystemsOperating B 3.8.9 BASES ACTIONS (continued)
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| E.1 and E.2 If the inoperable distribution 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 hours and to MODE 5 within 36 hours. 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.
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| F.1 Condition F corresponds to a level of degradation in the electrical power distribution system that causes a required safety function to be lost.
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| When more than one inoperable electrical power distribution subsystem results in the loss of a required function, the plant is in a condition outside the accident analysis. Therefore, no additional time is justified for continued operation. LCO 3.0.3 must be entered immediately to commence a controlled shutdown.
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| SURVEILLANCE SR 3.8.9.1 REQUIREMENTS This Surveillance verifies that the AC, channels of DC, DC trains, and AC vital bus electrical power distribution systems are functioning properly, with the correct circuit breaker alignment. The correct breaker alignment ensures the appropriate separation and independence of the electrical divisions is maintained, and the appropriate voltage is available to each required bus. The verification of proper indicated voltage availability on the buses ensures that the required voltage is readily available for motive as well as control functions for critical system loads connected to these buses. The Surveillance Frequency is based on operating experience, equipment reliability, and plant risk and is controlled under the Surveillance Frequency Control Program.
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| REFERENCES 1. UFSAR, Chapter 6.
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| : 2. UFSAR, Chapter 15.
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| : 3. 10 CFR 50.36, Technical Specifications, (c)(2)(ii).
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| : 4. Regulatory Guide 1.93, December 1974.
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| Catawba Units 1 and 2 B 3.8.9-7 Revision No. 3
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| Distribution SystemsOperating B 3.8.9 BASES Table B 3.8.9-1 (page 1 of 1)
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| AC and DC Electrical Power Distribution Systems TYPE NOMINAL TRAIN A* TRAIN B*
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| VOLTAGE AC safety 4160 V Essential Bus ETA Essential Bus ETB buses 600 V Load Centers Load Centers ELXA, ELXC ELXB, ELXD 600 V Motor Control Centers Motor Control Centers EMXA, EMXC, EMXB, EMXD, EMXE, EMXG, EMXF, EMXL, EMXK, EMXI EMXJ, EMXH DC buses 125 V Bus EDA Bus EDB Bus EDC Bus EDD Distribution Panels Distribution Panels EPA, EPC EPB, EPD DC train 125 V Distribution Center Distribution Center EDE EDF AC vital buses 120 V Bus ERPA Bus ERPB Bus ERPC Bus ERPD
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| * Each train of the AC and DC electrical power distribution systems is a subsystem.
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| Catawba Units 1 and 2 B 3.8.9-8 Revision No. 3
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| U.S. Nuclear Regulatory Commission RA-23-0042 April 24, 2023 Enclosure 5 Catawba Nuclear Station Selected Licensee Commitments (SLC) Manual Changes
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| Removal and insertion instructions for Catawba Nuclear Station Selected Licensee Commitments (SLC) Manual with the attached revised page(s) for the period of October 5, 2021 thru April 24, 2023. The revised page(s) are identified by Section number and contains marginal lines indicating the areas of change.
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| REMOVE THESE PAGES INSERT THESE PAGES LIST OF EFFECTIVE SECTIONS Pages 1-5 Pages 1-5 Revision 102 Revision 115 TAB 16.2 16.2-1 16.2-1 Revision 2 Revision 3 TAB 16.5 16.5-4 16.5-4 Revision 0 Revision 1 16.5-6 16.5-6 Revision 1 Revision 3 TAB 16.6 16.6-3 16.6-3 Revision 1 Revision 2 16.6-4 16.6-4 Revision 2 Revision 3 TAB 16.7 16.7-5 16.7-5 Revision 5 Revision 7 16.7-7 16.7-7 Revision 1 Revision 2 16.7-9 16.7-9 Revision 13 Revision 15 16.7-10 16.7-10 Revision 9 Revision 10 16.7-15 16.7-15 Revision 1 Revision 3
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| TAB 16.8 16.8-1 16.8-1 Revision 7 Revision 8 16.8-3 16.8-3 Revision 1 Revision 3 TAB 16.9 16.9-22 16.9-22 Revision 1 Revision 3 TAB 16.10 16.10-5 16.10-5 Revision 1 Revision 2 TAB 16.11 16.11-2 16.11-2 Revision 6 Revision 9 16.11-7 16.11-7 Revision 12 Revision 14
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| LIST OF EFFECTIVE SECTIONS SECTION REVISION NUMBER REVISION DATE TABLE OF CONTENTS 17 10/20/22 16.1 1 08/27/08 16.2 3 08/17/22 16.3 1 08/21/09 16.5-1 7 03/30/21 16.5-2 Deleted 16.5-3 2 09/19/19 16.5-4 1 01/27/22 16.5-5 1 01/28/10 16.5-6 3 08/17/22 16.5-7 2 02/06/15 16.5-8 Deleted 16.5-9 Deleted 03/02/21 16.5-10 Deleted 16.6-1 0 10/09/02 16.6-2 Deleted 16.6-3 2 01/27/22 16.6-4 3 08/17/22 16.6-5 3 07/07/20 16.7-1 1 08/21/09 16.7-2 4 02/03/11 16.7-3 5 11/21/19 16.7-4 Deleted 16.7-5 7 06/01/22 Catawba Units 1 and 2 Page 1 Revision 115
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| LIST OF EFFECTIVE SECTIONS SECTION REVISION NUMBER REVISION DATE 16.7-6 3 06/10/16 16.7-7 2 06/14/22 16.7-8 2 08/21/09 16.7-9 15 08/17/22 16.7-10 10 01/27/22 16.7-11 1 08/21/09 16.7-12 1 08/21/09 16.7-13 3 06/10/16 16.7-14 1 08/21/09 16.7-15 3 02/23/23 16.7-16 0 06/08/09 16.7-17 0 02/10/15 16.7-18 0 05/10/16 16.8-1 8 01/27/22 16.8-2 3 12/18/19 16.8-3 3 11/28/22 16.8-4 2 11/05/07 16.8-5 3 08/21/09 16.9-1 10 01/29/19 16.9-2 6 08/03/17 16.9-3 5 07/03/18 16.9-4 5 09/11/17 16.9-5 11 10/08/19 16.9-6 12 07/03/18 Catawba Units 1 and 2 Page 2 Revision 115
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| LIST OF EFFECTIVE SECTIONS SECTION REVISION NUMBER REVISION DATE 16.9-7 4 08/21/09 16.9-8 5 08/21/09 16.9-9 3 08/21/09 16.9-10 5 08/21/09 16.9-11 3 08/21/09 16.9-12 3 02/10/15 16.9-13 4 09/27/16 16.9-14 1 09/25/06 16.9-15 2 08/21/09 16.9-16 2 08/21/09 16.9-17 0 10/09/02 16.9-18 Deleted 16.9-19 3 02/20/12 16.9-20 0 10/09/02 16.9-21 1 10/13/16 16.9-22 3 08/17/22 16.9-23 5 08/03/17 16.9-24 2 10/24/06 16.9-25 2 08/21/09 16.9-26 1 11/15/18 16.10-1 1 08/21/09 16.10-2 1 10/24/06 16.10-3 1 08/21/09 16.10-4 0 08/04/20 Catawba Units 1 and 2 Page 3 Revision 115
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| LIST OF EFFECTIVE SECTIONS SECTION REVISION NUMBER REVISION DATE 16.10-5 2 09/07/22 16.11-1 1 07/27/13 16.11-2 9 07/07/22 16.11-3 0 10/09/02 16.11-4 1 08/21/09 16.11-5 0 10/09/02 16.11-6 3 08/03/15 16.11-7 14 05/03/22 16.11-8 0 10/09/02 16.11-9 0 10/09/02 16.11-10 1 08/21/09 16.11-11 1 03/20/03 16.11-12 0 10/09/02 16.11-13 1 07/27/13 16.11-14 0 10/09/02 16.11-15 0 10/09/02 16.11-16 1 10/24/11 16.11-17 0 10/09/02 16.11-18 1 08/21/09 16.11-19 0 10/09/02 16.11-20 3 11/21/19 16.11-21 0 10/09/02 16.12-1 0 10/09/02 16.13-1 1 08/03/17 16.13-2 Deleted Catawba Units 1 and 2 Page 4 Revision 115
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| LIST OF EFFECTIVE SECTIONS SECTION REVISION NUMBER REVISION DATE 16.13-3 Deleted 16.13-4 4 10/04/21 Catawba Units 1 and 2 Page 5 Revision 115
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| TABLE OF CONTENTS SECTION TITLE PAGE
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| ==16.1 INTRODUCTION==
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| 16.1-1 16.2 APPLICABILITY 16.2-1 16.3 DEFINITIONS 16.3-1 16.5 COMMITMENTS RELATED TO REACTOR COOLANT SYSTEM 16.5-1 Reduced Inventory and Mid-Loop Operation with Irradiated 16.5-1-1 Fuel in the Core 16.5-2 Deleted 16.5-3 Chemistry 16.5-3-1 16.5-4 Pressurizer 16.5-4-1 16.5-5 Structural Integrity 16.5-5-1 16.5-6 Reactor Coolant System (RCS) Vents 16.5-6-1 16.5-7 Steam Generator (SG) Pressure/Temperature Limitation 16.5-7-1 16.5-8 Deleted 16.5-9 Deleted 16.5-10 Deleted 16.6 COMMITMENTS RELATED TO ENGINEERED SAFETY FEATURES 16.6-1 Containment Sump 16.6-1-1 16.6-2 Deleted 16.6-3 Inlet Door Position Monitoring System 16.6-3-1 16.6-4 Chlorine Detectors and Associated Circuitry 16.6-4-1 16.6-5 Residual Heat Removal/Containment Spray Sump Pump 16.6-5-1 Interlock 16.7 COMMITMENTS RELATED TO INSTRUMENTATION 16.7-1 ATWS Mitigation System Actuation Circuitry (AMSAC) 16.7-1-1 16.7-2 Seismic Instrumentation 16.7-2-1 16.7-3 Meteorological Instrumentation 16.7-3-1 Catawba Units 1 and 2 i Revision 17
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| TABLE OF CONTENTS SECTION TITLE PAGE 16.7-4 Deleted 16.7-5 Turbine Overspeed Protection 16.7-5-1 16.7-6 RN Discharge Instrumentation 16.7-6-1 16.7-7 Movable Incore Detectors 16.7-7-1 16.7-8 Groundwater Level 16.7-8-1 16.7-9 Standby Shutdown System (SSS) 16.7-9-1 16.7-10 Radiation Monitoring for Plant Operations 16.7-10-1 16.7-11 Position Indication System - Shutdown 16.7-11-1 16.7-12 Position Indication System - Test Exception 16.7-12-1 16.7-13 Auxiliary Feedwater (AFW) Pump Turbine Steam Supply 16.7-13-1 Piping Temperature Monitoring System 16.7-14 Trip of All Main Feedwater Pumps Turbine Trip 16.7-14-1 Instrumentation 16.7-15 Hydrogen Monitors 16.7-15-1 16.7-16 Reactor Trip Breaker and Solid State Protection System 16.7-16-1 (SSPS) Logic Train Out of Service Commitments 16.7-17 Spent Fuel Pool (SFP) Wide Range (WR) Level 16.7-17-1 Instrumentation 16.7-18 Leading Edge Flow Meter (LEFM) System 16.7-18-1 16.8 COMMITMENTS RELATED TO ELECTRICAL POWER SYSTEMS 16.8-1 Containment Penetration Conductor Overcurrent Protective16.8-1-1 Devices (CPCOPDs) 16.8-2 230 kV Switchyard Systems 16.8-2-1 16.8-3 230 kV Switchyard 125 VDC Power System 16.8-3-1 16.8-4 6900 V Standby Transformers 16.8-4-1 16.8-5 Diesel Generator Supplemental Testing Requirements 16.8-5-1 16.9 COMMITMENTS RELATED TO AUXILIARY SYSTEMS Catawba Units 1 and 2 ii Revision 17
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| TABLE OF CONTENTS SECTION TITLE PAGE 16.9-1 Fire Suppression Water Systems 16.9-1-1 16.9-2 Sprinkler and Spray Systems 16.9-2-1 16.9-3 CO2 Systems 16.9-3-1 16.9-4 Fire Hose Stations 16.9-4-1 16.9-5 Fire Rated Assemblies 16.9-5-1 16.9-6 Fire Detection Instrumentation 16.9-6-1 16.9-7 Boration Systems Flow Path - Shutdown 16.9-7-1 16.9-8 Boration Systems Flow Paths - Operating 16.9-8-1 16.9-9 Boration Systems Pumps - Shutdown 16.9-9-1 16.9-10 Boration Systems Charging Pumps - Operating 16.9-10-1 16.9-11 Boration Systems Borated Water Source - Shutdown 16.9-11-1 16.9-12 Boration Systems Borated Water Sources - Operating 16.9-12-1 16.9-13 Snubbers 16.9-13-1 16.9-14 Lake Wylie Water Temperature 16.9-14-1 16.9-15 Auxiliary Building Filtered Exhaust System (ABFVES) 16.9-15-1 Filter Cooling Bypass Valves 16.9-16 Fuel Handling Ventilation Exhaust System (FHVES) 16.9-16-1 Filter Cooling Bypass Valves 16.9-17 Refueling Operations - Decay Time 16.9-17-1 16.9-18 Deleted 16.9-19 Refueling Operations - Manipulator Crane 16.9-19-1 16.9-20 Refueling Operations - Crane Travel - Spent Fuel Storage 16.9-20-1 Pool Building 16.9-21 Refueling Operations - Storage Pool Water Level 16.9-21-1 16.9-22 Control Room Area Ventilation System - Intake Alarms 16.9-22-1 16.9-23 Fire Hydrants 16.9-23-1 Catawba Units 1 and 2 iii Revision 17
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| TABLE OF CONTENTS SECTION TITLE PAGE 16.9-24 Alternate Cooling for Charging Pumps 16.9-24-1 16.9-25 Tornado Isolation Dampers 16.9-25-1 16.9-26 Commitments Associated With Movement of Non-Recently 16.9-26-1 Irradiated Fuel Assemblies 16.10 COMMITMENTS RELATED TO STEAM AND POWER CONVERSION SYSTEMS 16.10-1 Steam Vent to Atmosphere 16.10-1-1 16.10-2 Condenser Circulating Water System 16.10-2-1 16.10-3 Auxiliary Feedwater (AFW) Flow Control Valve Air 16.10-3-1 Accumulators 16.10-4 Motor Driven Auxiliary Feedwater Pump Pit (WL) Sump 16.10-4-1 Pumps 16.10-5 Auxiliary Feedwater Turbine Driven Pump Pit (WL) Sump 16.10-5-1 Pumps 16.11 COMMITMENTS RELATED TO RADIOACTIVE WASTE MANAGEMENT 16.11-1 Liquid Effluents 16.11-1-1 16.11-2 Radioactive Liquid Effluent Monitoring Instrumentation 16.11-2-1 16.11-3 Dose 16.11-3-1 16.11-4 Liquid Radwaste Treatment System 16.11-4-1 16.11-5 Chemical Treatment Ponds 16.11-5-1 16.11-6 Gaseous Effluents 16.11-6-1 16.11-7 Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7-1 16.11-8 Dose - Noble Gases 16.11-8-1 16.11-9 Dose - Iodine-131, Iodine-133, Tritium, and Radioactive 16.11-9-1 Material in Particulate Form 16.11-10 Gaseous Radwaste Treatment System 16.11-10-1 16.11-11 Solid Radioactive Wastes 16.11-11-1 16.11-12 Total Dose 16.11-12-1 Catawba Units 1 and 2 iv Revision 17
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| TABLE OF CONTENTS SECTION TITLE PAGE 16.11-13 Monitoring Program 16.11-13-1 16.11-14 Land Use Census 16.11-14-1 16.11-15 Interlaboratory Comparison Program 16.11-15-1 16.11-16 Annual Radiological Environmental Operating Report and 16.11-16-1 Radioactive Effluent Release Report 16.11-17 Liquid Holdup Tanks 16.11-17-1 16.11-18 Explosive Gas Mixture 16.11-18-1 16.11-19 Gas Storage Tanks 16.11-19-1 16.11-20 Explosive Gas Monitoring Instrumentation 16.11-20-1 16.11-21 Major Changes to Liquid, Gaseous, and Solid Radwaste 16.11-21-1 Treatment Systems 16.12 COMMITMENTS RELATED TO RADIATION PROTECTION 16.12-1 Sealed Source Contamination 16.12-1-1 16.13 COMMITMENTS RELATED TO CONDUCT OF OPERATIONS 16.13-1 Fire Brigade 16.13-1-1 16.13-2 Deleted 16.13-3 Deleted 16.13-4 Minimum Station Staffing Requirements 16.13-4-1 Catawba Units 1 and 2 v Revision 17
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| Applicability 16.2 16.2 APPLICABILITY This section provides the general requirements applicable to each of the COMMITMENTS and Testing Requirements within Section 16.0, Selected Licensee Commitments (SLCs).
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| 16.2.1 COMMITMENTS shall be met during the MODES or other specified conditions in the Applicability.
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| 16.2.2 Upon discovery of a failure to meet a COMMITMENT, the associated REMEDIAL ACTION(S) shall be met, except as provided in SLC 16.2.10, SLC 16.2.11, and SLC 16.2.12. If the COMMITMENT is met or is no longer applicable prior to expiration of the specified time interval, completion of the REMEDIAL ACTION(S) is not required, unless otherwise stated.
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| 16.2.3 Deleted.
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| 16.2.4 COMMITMENTS including the associated REMEDIAL ACTIONS shall apply to each unit individually unless otherwise indicated as follows:
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| : a. Whenever the COMMITMENT refers to systems or components which are shared by both units, the REMEDIAL ACTIONS will apply to both units simultaneously. This will be indicated in the REMEDIAL ACTIONS;
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| : b. Whenever the COMMITMENT applies to only one unit, this will be identified in the APPLICABILITY section of the COMMITMENT; and
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| : c. Whenever certain portions of a COMMITMENT contain operating parameters, setpoints, etc., which are different for each unit, this will be identified in parentheses or footnotes. (For example, flow rate of 54,000 cfm (Unit 1) or 43,000 cfm (Unit 2).)
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| 16.2.5 Testing Requirements shall be met during the OPERATIONAL MODES or other specified conditions in the Applicability for individual COMMITMENTS unless otherwise stated in an individual Testing Requirement or Reference.
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| Failure to meet a Testing Requirement, whether such failure is experienced during the performance of the Testing Requirement or between performances of the Testing Requirement, shall be failure to meet the COMMITMENT.
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| Failure to perform a Testing Requirement within the specified Frequency shall be failure to meet the COMMITMENT except as provided in SLC 16.2.7.
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| Testing Requirements do not have to be performed on non-functional equipment or variables outside specified limits.
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| Catawba Units 1 and 2 16.2-1 Revision 3
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| Applicability 16.2 16.2.6 The specified Frequency for each Testing Requirement is met if the Testing Requirement is performed within 1.25 times the interval specified in the Frequency, as measured from the previous performance or as measured from the time a specified condition of the Frequency is met.
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| For Frequencies specified as once, the above interval extension does not apply.
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| If a Completion Time requires periodic performance on a once per basis, the above Frequency extension applies to each performance after the initial performance.
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| Exceptions to this SLC are stated in the individual SLCs.
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| 16.2.7 If it is discovered that a Testing Requirement was not performed within its specified Frequency, then compliance with the requirement to declare the COMMITMENT not met may be delayed, from the time of discovery, up to 24 hours or up to the limit of the specified Frequency, whichever is greater. This delay period is permitted to allow performance of the Testing Requirement. A risk evaluation shall be performed for any Testing Requirement delayed greater than 24 hours, and the risk impact shall be managed.
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| If the Testing Requirement is not performed within the delay period, the COMMITMENT must immediately be declared not met, and the applicable REMEDIAL ACTIONS must be entered.
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| When the Testing Requirement is performed within the delay period and the Testing Requirement is not met, the COMMITMENT must immediately be declared not met, and the applicable REMEDIAL ACTIONS must be entered.
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| 16.2.8 Deleted.
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| 16.2.9 Testing Requirements shall apply to each unit individually unless otherwise indicated as stated in SLC 16.2.4 for individual COMMITMENTS or whenever certain portions of a COMMITMENT contain testing parameters different for each unit, which will be identified in parentheses or footnotes.
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| 16.2.10 Under certain extenuating circumstances, as determined appropriate by the Station Manager or his/her designee, it may be acceptable to deviate from the requirements of a COMMITMENT. Such deviation shall only be authorized for a limited time period (typically 14 days or less) and only after the appropriate justification has been prepared, approved, and concurred with by the Station Manager or his/her designee. This deviation shall be implemented in accordance with existing approved procedures. This is an exception to SLC 16.2.2.
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| Catawba Units 1 and 2 16.2-2 Revision 3
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| Applicability 16.2 16.2.11 Equipment removed from service or declared non-functional to comply with REMEDIAL ACTIONS may be returned to service under administrative control solely to perform testing required to demonstrate its FUNCTIONALITY or the FUNCTIONALITY of other equipment. This is an exception to SLC 16.2.2 for the system returned to service under administrative control to perform the required testing to demonstrate FUNCTIONALITY.
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| 16.2.12 When a supported system COMMITMENT is not met solely due to a support system COMMITMENT not being met, the Conditions and REMEDIAL ACTIONS associated with this supported system are not required to be entered. Only the support system REMEDIAL ACTIONS are required to be entered. This is an exception to SLC 16.2.2 for the supported system.
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| When a support systems REMEDIAL ACTION directs a supported system to be declared non-functional or directs entry into Conditions and REMEDIAL ACTIONS for a supported system, the applicable Conditions and REMEDIAL ACTIONS shall be entered in accordance with SLC 16.2.2.
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| Catawba Units 1 and 2 16.2-3 Revision 3
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| Pressurizer 16.5-4 16.5 REACTOR COOLANT SYSTEM 16.5-4 Pressurizer COMMITMENT The pressurizer temperature shall be limited to:
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| : a. A maximum heatup of 100qF in any 1-hour period, and
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| : b. A maximum cooldown of 200qF in any 1-hour period.
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| APPLICABILITY: At all times.
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| REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. ------------NOTE------------ A.1 Restore pressurizer 30 minutes All Required Actions temperature to within limits.
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| must be completed whenever this Condition AND is entered.
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| A.2 Perform engineering Pressurizer temperature evaluation to determine 72 hours not within limits. effects of the out-of-limit condition on the structural integrity of the pressurizer.
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| AND A.3 Determine that the pressurizer remains 72 hours acceptable for continued operation.
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| B. Required Action and B.1 Initiate a Condition Report Immediately associated Completion in accordance with the Time not met. Corrective Action Program.
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| Catawba Units 1 and 2 16.5-4-1 Revision 1
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| Pressurizer 16.5-4 TESTING REQUIREMENTS TEST FREQUENCY TR 16.5-4-1 ---------------------------------NOTE---------------------------------
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| Only required to be performed during system heatup or cooldown operations.
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| Verify pressurizer temperatures are within limits. 30 minutes BASES The temperature and pressure changes during heatup and cooldown are limited to be consistent with the requirements given in the ASME Boiler and Pressure Vessel Code, Section III, Appendix G. Although the pressurizer operates in temperature ranges above those for which there is reason for concern of nonductile failure, operating limits are provided to assure compatibility of operation with the fatigue analysis performed in accordance with the ASME Code requirements.
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| REFERENCES 1. Letter from NRC to Gary R. Peterson, Duke, Issuance of Improved Technical Specifications Amendments for Catawba, September 30, 1998.
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| Catawba Units 1 and 2 16.5-4-2 Revision 1
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| RCS Vents 16.5-6 16.5 REACTOR COOLANT SYSTEM 16.5-6 Reactor Coolant System (RCS) Vents COMMITMENT One RCS vent path consisting of at least two valves in series powered from emergency buses shall be FUNCTIONAL and closed at each of the following locations:
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| : a. Reactor vessel head, and
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| : b. -------------------------------------NOTE-------------------------------------
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| If using a power operated relief valve (PORV) as a vent path, the PORV block valve is not required to be closed if the PORV is OPERABLE (MODES 1, 2, and 3) or FUNCTIONAL (MODE 4).
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| Pressurizer steam space APPLICABILITY: MODES 1, 2, 3, and 4.
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| REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One RCS vent path non- A.1 Initiate action to close and Immediately functional. remove power from all valves in the non-functional vent path.
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| AND A.2 Restore the non-functional 30 days vent path to FUNCTIONAL status.
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| (continued)
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| Catawba Units 1 and 2 16.5-6-1 Revision 3
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| RCS Vents 16.5-6 REMEDIAL ACTIONS (continued)
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| CONDITION REQUIRED ACTION COMPLETION TIME B. Both RCS vent paths B.1 Initiate action to close and Immediately non-functional. remove power from all valves in the non-functional vent paths.
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| AND B.2 Restore at least one non- 72 hours functional vent path to FUNCTIONAL status.
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| C. Required Action and C.1 Initiate a Condition Report Immediately associated Completion in accordance with the Time not met. Corrective Action Program.
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| TESTING REQUIREMENTS TEST FREQUENCY TR 16.5-6-1 ---------------------------------NOTE---------------------------------
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| This TR shall be performed during MODE 5 or MODE 6.
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| Demonstrate that each RCS vent path is FUNCTIONAL 18 months by cycling each valve in the vent path through at least one complete cycle of full travel from the control room.
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| BASES RCS vents are provided to exhaust noncondensible gases and/or steam from the primary system that could inhibit natural circulation core cooling. The FUNCTIONALITY of at least one RCS vent path from the reactor vessel head, and the pressurizer steam space ensures the capability exists to perform this function. There are no manual isolation valves in either RCS vent path.
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| Catawba Units 1 and 2 16.5-6-2 Revision 3
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| RCS Vents 16.5-6 BASES (continued)
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| The valve redundancy of the RCS vent paths serves to minimize the probability of inadvertent or irreversible actuation while ensuring that a single failure of a vent valve, power supply or control system does not prevent isolation of the vent path.
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| A Condition Report initiated from Action C should include evaluation of loss of function to exhaust non-condensable gases, loss of ability to provide inventory control for standby shutdown facility events as a letdown path, and loss of alternate letdown path for other accident events.
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| The function, capabilities, and testing requirements of the RCS vent systems are consistent with the requirements of Item II.B.1 of NUREG-0737, Clarification of TMI Action Plan Requirements, November 1980.
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| REFERENCES 1. Letter from NRC to Gary R. Peterson, Duke, Issuance of Improved Technical Specifications Amendments for Catawba, September 30, 1998.
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| Catawba Units 1 and 2 16.5-6-3 Revision 3
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| Inlet Door Position Monitoring System 16.6-3 16.6 ENGINEERED SAFETY FEATURES 16.6-3 Inlet Door Position Monitoring System COMMITMENT The Inlet Door Position Monitoring System shall be FUNCTIONAL.
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| APPLICABILITY: MODES 1, 2, 3, and 4.
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| REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Inlet Door Position A.1.1 Verify the Ice Bed Immediately Monitoring System non- Temperature Monitoring functional. System is FUNCTIONAL.
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| AND A.1.2 Verify ice bed temperature Once per 4 hours is < 27qF.
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| AND A.1.3 Restore the Inlet Door 14 days Position Monitoring System to FUNCTIONAL status.
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| OR A.2 Restore the Inlet Door 48 hours Position Monitoring System to FUNCTIONAL status.
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| B. Required Action and B.1 Initiate a Condition Report Immediately associated Completion in accordance with the Time not met. Corrective Action Program.
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| Catawba Units 1 and 2 16.6-3-1 Revision 2
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| Inlet Door Position Monitoring System 16.6-3 TESTING REQUIREMENTS TEST FREQUENCY TR 16.6-3-1 Perform CHANNEL CHECK. 12 hours TR 16.6-3-2 Perform TADOT. 18 months TR 16.6-3-3 Verify the Inlet Door Position Monitoring System correctly As the door is indicates the status of each inlet door. opened and reclosed during testing per Technical Specification 3.6.13 BASES The FUNCTIONALITY of the Inlet Door Position Monitoring System ensures that the capability is available for monitoring the individual inlet door position.
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| In the event the system is non-functional, the REMEDIAL ACTION requirements provide assurance that the ice bed heat removal capacity will be maintained.
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| REFERENCES 1. Letter from NRC to Gary R. Peterson, Duke, Issuance of Improved Technical Specifications Amendments for Catawba, September 30, 1998.
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| Catawba Units 1 and 2 16.6-3-2 Revision 2
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| Chlorine Detectors and Associated Circuitry 16.6-4 16.6 ENGINEERED SAFETY FEATURES 16.6-4 Chlorine Detectors and Associated Circuitry COMMITMENT Four chlorine detectors and associated circuitry (two per control room intake), with their Alarm Setpoints adjusted to actuate at a chlorine concentration of < 5 ppm, shall be FUNCTIONAL.
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| APPLICABILITY: All MODES.
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| REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One chlorine detector A.1 Restore the non-functional 30 days and/or associated equipment to circuitry non-functional FUNCTIONAL status.
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| in one or both control room intakes.
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| B. Required Action and B.1 -------------NOTE--------------
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| associated Completion With both intakes isolated, Time of Condition A not both Control Room Area met. Ventilation System (CRAVS) trains are inoperable and the applicable Conditions and Required Actions of Technical Specification 3.7.10 shall be entered and followed.
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| Isolate affected control 1 hour room intake(s).
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| (continued)
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| Catawba Units 1 and 2 16.6-4-1 Revision 3
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| Chlorine Detectors and Associated Circuitry 16.6-4 REMEDIAL ACTIONS (continued)
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| CONDITION REQUIRED ACTION COMPLETION TIME C. Both chlorine detectors C.1 -------------NOTE--------------
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| and/or associated With both intakes isolated, circuitry non-functional both CRAVS trains are in one or both control inoperable and the room intakes. applicable Conditions and Required Actions of Technical Specification 3.7.10 shall be entered and followed.
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| Isolate affected control Immediately room intake(s).
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| TESTING REQUIREMENTS TEST FREQUENCY TR 16.6-4-1 Perform COT. 6 months TR 16.6-4-2 Perform CHANNEL CALIBRATION. 18 months BASES The FUNCTIONALITY of the chlorine detectors and associated circuitry is provided as a defense-in-depth measure to ensure that sufficient capability is available to promptly detect and respond to an accidental chlorine release. The capability for the protection of control room personnel is consistent with the recommendations of Regulatory Guide 1.95, Revision 1, January 1977, Protection of Nuclear Power Plant Control Room Operators Against an Accidental Chlorine Release.
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| Regulatory Guide 1.95 states in Section C.2 that the capability to manually isolate the control room should be provided if a chlorine container having an inventory of 150 lbs. or less is stored more than 100 meters from the control room or its fresh air intakes. All chlorine containers at Catawba are stored or used at least 158 meters (520 feet) from the nearest control room outside air intake and the inventory of chlorine in any single container is less than or equal to 100 lbs. (Note that Catawba only uses 50-lb. cylinders with a maximum of two cylinders manifolded together.) Thus, automatic isolation/closure of an intake is Catawba Units 1 and 2 16.6-4-2 Revision 3
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| Chlorine Detectors and Associated Circuitry 16.6-4 BASES (continued) not required and it is acceptable to leave an intake open for a limited time period even if a single detector on an intake were to alarm. This follows the implied logic of the Regulatory Guide that if the quantity of gaseous chlorine onsite is small enough, it is not credible to assume a chlorine container failure results in a significant impact to the control room. This position is documented in calculation CNC-1211.00-00-0124.
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| The REMEDIAL ACTIONS described above are consistent with the guidance provided in Regulatory Guide 1.78, Revision 0, June 1974, Assumptions for Evaluating the Habitability of a Nuclear Power Plant Control Room During a Postulated Hazardous Chemical Release, and Regulatory Guide 1.95. Regulatory Guide 1.78 states in Section C.3 that the release of any hazardous chemical to be stored on the nuclear plant site in a quantity greater than 100 lbs. should be considered for its impact on control room habitability. Catawba does not allow any gaseous chlorine containers greater than 100 lbs. on site. There are also no credible accident scenarios that would cause the failure of more than 100 lbs. of chlorine.
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| REFERENCES 1. Letter from NRC to Gary R. Peterson, Duke, Issuance of Improved Technical Specifications Amendments for Catawba, September 30, 1998.
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| : 2. Letter from NRC to G.R. Peterson, Duke, Issuance of Amendments 191/183, June 28, 2001.
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| Catawba Units 1 and 2 16.6-4-3 Revision 3
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| Turbine Overspeed Protection 16.7-5 16.7 INSTRUMENTATION 16.7-5 Turbine Overspeed Protection COMMITMENT Turbine Overspeed Protection System shall be FUNCTIONAL.
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| APPLICABILITY: MODES 1, 2, and 3.
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| REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One stop valve or one A.1 Restore non-functional 72 hours control valve per high valve(s) to FUNCTIONAL pressure turbine steam status.
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| line non-functional.
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| OR A.2 Close at least one valve in 78 hours affected steam line(s).
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| OR A.3 Isolate the turbine from the 78 hours steam supply.
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| B. One intermediate stop B.1 Restore non-functional 72 hours valve or one intercept valve(s) to FUNCTIONAL valve per low pressure status.
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| turbine steam line non-functional. OR B.2 Close at least one valve in 78 hours affected steam line(s).
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| OR B.3 Isolate the turbine from the 78 hours steam supply.
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| (continued)
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| Catawba Units 1 and 2 16.7-5-1 Revision 7
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| Turbine Overspeed Protection 16.7-5 REMEDIAL ACTIONS (continued)
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| CONDITION REQUIRED ACTION COMPLETION TIME C. Electrical or Mechanical C.1 Determine missile 6 days Overspeed Protection probability P1 value and Non-Functional perform required actions as determined by the probability criteria table located in the bases.
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| OR C.2 Isolate the turbine from the 150 hours steam supply.
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| D. Turbine Overspeed D.1 Isolate the turbine from the 6 hours Protection System non- steam supply.
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| functional for reasons other than Condition A, B or C.
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| TESTING REQUIREMENTS TEST FREQUENCY TR 16.7-5-1 --------------------------------NOTES--------------------------------
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| : 1. This TR shall be performed in MODE 1 or in MODE 2 with the turbine operating.
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| : 2. Not required to be performed until 24 hours after each valve is opened.
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| Cycle while performing a direct observation of the four In accordance with high pressure turbine stop valves, six low pressure SLC 16.7-5 Bases turbine intermediate stop valves, six low pressure turbine intercept valves, and four high pressure turbine control valves, through one complete cycle from the running position.
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| TR 16.7-5-2 Perform CHANNEL CALIBRATION. 18 months (continued)
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| Catawba Units 1 and 2 16.7-5-2 Revision 7
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| Turbine Overspeed Protection 16.7-5 TEST FREQUENCY TR 16.7-5-3 Disassemble at least one each of the four high pressure 54 months turbine stop valves, six low pressure turbine intermediate stop valves, six low pressure turbine intercept valves, and four high pressure turbine control valves, and perform a visual and surface inspection of valve seats, disks, and stems, and verify no unacceptable flaws or corrosion.
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| TR 16.7-5-4 Perform mechanical trip testing. In accordance with SLC 16.7-5 Bases TR 16.7-5-5 Perform electrical trip testing. In accordance with SLC 16.7-5 Bases BASES This COMMITMENT is provided to ensure that the Turbine Overspeed Protection instrumentation and the turbine speed control valves are FUNCTIONAL and will protect the turbine from excessive overspeed.
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| Protection from turbine excessive overspeed is required since excessive overspeed of the turbine could generate potentially damaging missiles which could impact and damage safety related components, equipment, or structures.
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| The term "Isolate the turbine from the steam supply" used in Required Actions A.3, B.3, C.2 and D.1 can be met in several ways. These include:
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| Maintaining the turbine in a tripped condition; or Hydraulically gagging all four main stop valves closed; or Hydraulically gagging all four main control valves closed; or Closing the main steam isolation valves and main steam isolation valve bypass valves.
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| Calculation CNC 1200.00-00-0006 provides qualitative and quantitative assessment for interval extension on Turbine Valve Movement Testing (TVMT). The calculation concludes that it is allowable to have a maximum 18-month TVMT interval for HP Stop Valves, HP Control Valves and LP Combined Intermediate Valves, based on main turbine missile probabilities. It is desired to incrementally extend the current test frequency from 4 months to 18 months based on two successful tests at each extended test interval no greater than half the previous test interval (e.g. the 4-month frequency would be extended to 6-months; the 6-month interval would be extended to 9 months and the 9 month frequency to 12 months, the 12 month frequency to 15 months and finally the 15 month interval to 18 months). The other recommendation is that CNS trend EHC fluid quality measurements to ensure fluid quality remains within acceptable limits. CNS currently takes Monthly samples and verifies EHC fluid is within OEM recommended limits (PMRQs 02031192-02 and Catawba Units 1 and 2 16.7-5-3 Revision 7
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| Turbine Overspeed Protection 16.7-5 BASES (continued) 02031193-02). Both CNS units start at a 4M frequency for all Turbine Valve Movement Testing, within OEM acceptable limits. Extending TVMT frequencies through calculation CNC 1200.00-00-0006, the TVMT PM strategy is to extend valve testing out in 3 month increments after a minimum of 2 iterations. These TVMT intervals may be increased until the frequency reaches a maximum of 18 months between TVMT tests.
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| The testing frequencies will be extended in accordance with the strategy given below until the maximum frequency is reached.
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| 4M to 6M - Allow for testing at this interval and collect data (a minimum of 2 Turbine Valve Movement Tests at this frequency) 6M to 9M - Allow for testing at this interval and collect data (a minimum of 2 Turbine Valve Movement Tests at this frequency) 9M to 12M - Allow for testing at this interval and collect data (a minimum of 2 Turbine Valve Movement Tests at this frequency) 12M to 15M - Allow for testing at this interval and collect data (a minimum of 2 Turbine Valve Movement Tests at this frequency) 15M to 18M - Allow for testing at this interval and collect data (a minimum of 2 Turbine Valve Movement Tests at this frequency)
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| PMRQs that document current frequency and drive execution:
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| 02031173 PT/1/A/4250/02B MAIN TURB VALVE MOVT TEST 02031173 PT/1/A/4250/02C TURBINE CONTROL VALVE MOVT TEST 02031172 PT/2/A/4250/02B MAIN TURB VALVE MOVEMENT TEST 02031172 PT/2/A/4250/02C TURBINE CONTROL VALVE MOVEMENT TEST Calculation CNC 1200.00-00-0006 also performed analysis on extending out mechanical and electrical (backup) trip testing, based on turbine missile probabilities. The calculation concludes that a maximum frequency of 2-Months on mechanical trip testing and 1-Month for electrical trip testing is allowable. The maximum extensions for trip testing are based on requirements that CNS extends the interval out in steps and no more than double of the previous test interval. The other recommendation is that CNS trend EHC fluid quality measurements to ensure fluid quality remains within acceptable limits. Extending trip test frequencies through calculation CNC 1200.00-00-0006, the Turbine Trip test PM strategy is to extend trip testing out no more than double of the previous test interval after a minimum of 2 iterations. The testing frequencies will be extended in accordance with the strategy given below until the maximum frequency is reached.
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| 1W to 2W - Allow for testing at this interval and collect data (a minimum of 2 Turbine Trip Tests at this frequency) 2W to 1M - Allow for testing at this interval and collect data (a minimum of 2 Turbine Trip Tests at this frequency) 1M to 2M - This would only be optional for the mechanical trip testing upon a minimum of 2 successful mechanical trip tests.
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| Catawba Units 1 and 2 16.7-5-4 Revision 7
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| Turbine Overspeed Protection 16.7-5 BASES (continued)
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| PMRQs that document current frequency and drive execution:
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| 02031173 PT/1/B/4250/02A MAIN TURBINE WEEKLY TRIP TEST 02031172 PT/2/B/4250/02A MAIN TURBINE WEEKLY TRIP TEST NUREG 0800 3.5.1.3 documents the NRC's review with regard to turbine missile generation and concluded that the probability of unacceptable damage to safety related systems and components resulting from missile damage is acceptably low (i.e less than 10-7 per year) provided the total turbine missile generation probability (P1) is maintained below 10-4 per reactor year. The application of NUREG 0800 Section 3.5.1.3 Table 3.5.1.3-1 for favorably oriented turbines provides additional NRC approved P1 values and recommended licensee actions if the turbine is online.
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| Calculation CNC 1200.00-00-0006 contains missile generation probability (P1) values for different scenarios that can be used to determine the resulting missile probability (P1) for a given condition to be used in conjunction with the Probability Criteria Table to determine the required action. Any change in system or component reliability will require use of the same methodology used in CNC-1200.00-0006 to determine any new P1 value to ensure missile probabilities do not exceed NUREG 0800 Section 3.5.1.3 Table 3.5.1.3-1 criteria.
| |
| The turbine trip test requirement in TR 16.7-5-4 and TR 16.7-5-5 can be temporarily extended if the execution of the test creates unacceptable risk during execution. The effect of the probability (P1) must be evaluated prior to the temporary frequency extension to ensure the P1 value remains below the high value for Probability Criteria in Case B.
| |
| Both mechanical and electrical trips non-functional requires entry into Condition D.
| |
| Probability Criteria Case Annual Probability Required Actions A P1 < 10-4 This condition represents the general, minimum reliability requirement for loading the turbine and bringing the system online B 10-4 < P1 < 10-3 If this condition is reached during operation, the turbine may be kept in service until the next scheduled outage, at which time the licensee must take action to reduce P1 to meet the Case A criterion before returning the turbine to service C 10-3 < P1 < 10-2 If this condition is reached during operation, the turbine must be isolated from the steam supply within 60 days, at which time the licensee must take action to reduce P1 to meet the Case A criterion before returning the turbine to service.
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| Catawba Units 1 and 2 16.7-5-5 Revision 7
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| | |
| Turbine Overspeed Protection 16.7-5 D 10-2 < P1 If this condition is reached during operation, the turbine must be isolated from the steam supply within 6 days, at which time the licensee must take action to reduce P1 to meet the Case A criterion before returning the turbine to service.
| |
| REFERENCES 1. CNC 1200.00-00-0006 - Catawba Turbine Overspeed Protection System Maintenance and Test Interval Extension Assessment.
| |
| : 2. CNM 1200.00-0212.001 - Turbine Instruction Manual.
| |
| : 3. NUREG 0800 3.5.1.3 Turbine Missiles - Revision 3 - March 2007.
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| Catawba Units 1 and 2 16.7-5-6 Revision 7
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| | |
| Movable Incore Detectors 16.7-7 16.7 INSTRUMENTATION 16.7-7 Movable Incore Detectors COMMITMENT The Movable Incore Detection System shall be FUNCTIONAL with:
| |
| : a. At least 75% of the detector thimbles,
| |
| : b. A minimum of two detector thimbles per core quadrant, and
| |
| : c. Sufficient movable detectors, drive, and readout equipment to map these thimbles.
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| APPLICABILITY: When the Movable Incore Detection System is used for:
| |
| : a. Recalibration of the Excore Neutron Flux Detection System, or
| |
| : b. Monitoring the QUADRANT POWER TILT RATIO, or
| |
| : c. Measurement of F'HN and FQ(Z).
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| REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. Movable Incore A.1 Suspend use of the system Immediately Detection System non- for the applicable functional. monitoring or calibration functions.
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| Catawba Units 1 and 2 16.7-7-1 Revision 2
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| | |
| Movable Incore Detectors 16.7-7 TESTING REQUIREMENTS TEST FREQUENCY TR 16.7-7-1 Irradiate each detector used and determine the 24 hours acceptability of its voltage curve for:
| |
| Recalibration of the Excore Neutron Flux Detection System, or Monitoring the QUADRANT POWER TILT RATIO, or Measurement of F'HN and FQ(Z).
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| BASES The FUNCTIONALITY of the movable incore detectors with the specified minimum complement of equipment ensures that the measurements obtained from use of this system accurately represent the spatial neutron flux distribution of the core. The FUNCTIONALITY of this system is demonstrated by irradiating each detector used and determining the acceptability of its voltage curve.
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| For the purpose of measuring FQ(Z) or F'HN a full incore flux map is used.
| |
| Quarter-core flux maps, as defined in WCAP-8648, June 1976, may be used in recalibration of the Excore Neutron Flux Detection System, and full incore flux maps or symmetric incore thimbles may be used for monitoring the QUADRANT POWER TILT RATIO when one Power Range channel is inoperable.
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| REFERENCES 1. Letter from NRC to Gary R. Peterson, Duke, Issuance of Improved Technical Specifications Amendments for Catawba, September 30, 1998.
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| : 2. UFSAR Table 18-1.
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| : 3. UFSAR Section 18.2.3.
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| Catawba Units 1 and 2 16.7-7-2 Revision 2
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| | |
| SSS 16.7-9 16.7 INSTRUMENTATION 16.7-9 Standby Shutdown System (SSS)
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| COMMITMENT The SSS shall be FUNCTIONAL.
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| APPLICABILITY: MODES 1, 2, and 3.
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| REMEDIAL ACTIONS
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| ==========;============;====== I CONDITION REQUIRED ACTION COMPLETION TIME A. SSS non-functional. A.1 Restore SSS to 7 days FUNCTIONAL status.
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| B. Total accumulative B.1 Declare the standby Immediately LEAKAGE from makeup pump non-unidentified LEAKAGE, functional and enter identified LEAKAGE, Condition A.
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| and reactor coolant pump seal LEAKAGE >
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| 20 gpm.
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| C. A required cell in a 24- C.1 Enter Condition A. Immediately Volt battery bank is <
| |
| 1.36 volts on float charge.
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| D. Required Action and D.1 Prepare and submit a 14 days associated Completion Special Report to the NRC Time of Condition A not outlining the extent of met. repairs required, schedule for completing repairs, and basis for continued operation.
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| Catawba Units 1 and 2 16.7-9-1 Revision 15
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| | |
| SSS 16.7-9 TESTING REQUIREMENTS TEST FREQUENCY TR 16.7-9-1 Verify that the electrolyte level of each SSS diesel 7 days starting 24-Volt battery is > the low mark and < the high mark.
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| TR 16.7-9-2 Verify that the overall SSS diesel starting 24-Volt battery 7 days voltage is > 24 volts on float charge.
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| TR 16.7-9-3 Verify that the requirements of SLC 16.9-21 are met and 7 days the boron concentration in the storage pool is > the minimum specified in the COLR.
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| TR 16.7-9-4 Verify the fuel level in the SSS diesel generator fuel 31 days storage tank is > 67 inches.
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| TR 16.7-9-5 Verify the SSS diesel generator starts from ambient 31 days conditions and operates for > 30 minutes at > 700 kW.
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| TR 16.7-9-6 Verify that the electrolyte level of each SSS 250/125-Volt 31 days battery is above the plates.
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| TR 16.7-9-7 Verify the total SSS 250/125-Volt battery terminal voltage 31 days is > 258/129 volts on float charge.
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| TR 16.7-9-8 Perform CHANNEL CHECK of each SSS instrumentation 31 days device.
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| TR 16.7-9-9 Verify the fuel oil properties of new and stored fuel oil for In accordance with the SSS diesel generator are tested in accordance with, the Diesel Fuel Oil and maintained within the limits of, the Diesel Fuel Oil Testing Program Testing Program.
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| TR 16.7-9-10 Verify that the individual battery cell voltage of the 92 days required cells in the SSS diesel starting 24-Volt battery is
| |
| > 1.36 volts on float charge.
| |
| (continued)
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| Catawba Units 1 and 2 16.7-9-2 Revision 15
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| | |
| SSS 16.7-9 TESTING REQUIREMENTS (continued)
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| TEST FREQUENCY TR 16.7-9-11 Verify that the Standby Makeup Pumps developed head 92 days at the test flow point is > the required developed head, in accordance with the Inservice Testing Program.
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| TR 16.7-9-12 Verify that the specific gravity of the SSS 250/125-Volt 92 days battery is appropriate for continued service of the battery.
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| TR 16.7-9-13 Subject the SSS diesel generator to an inspection in 18 months accordance with procedures prepared in conjunction with its manufacturers recommendations for the class of service.
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| TR 16.7-9-14 Verify that the SSS diesel starting 24-Volt batteries, cell 18 months plates, and battery racks show no visual indication of physical damage or abnormal deterioration.
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| TR 16.7-9-15 Verify that the SSS diesel starting 24-Volt battery-to- 18 months battery and terminal connections are clean, tight, and free of corrosion.
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| TR 16.7-9-16 Verify that the SSS 250/125-Volt batteries, cell plates, 18 months and battery racks show no visual indications of physical damage or abnormal deterioration.
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| TR 16.7-9-17 Verify that the SSS 250/125-Volt battery-to-battery and 18 months terminal connections are clean, tight, free of corrosion, and coated with anti-corrosion material.
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| TR 16.7-9-18 Verify that the steam turbine driven auxiliary feedwater 18 months pump and controls from the Standby Shutdown Facility function as designed from the SSS.
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| TR 16.7-9-19 Perform CHANNEL CALIBRATION of each SSS 18 months instrumentation device.
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| (continued)
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| Catawba Units 1 and 2 16.7-9-3 Revision 15
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| | |
| SSS 16.7-9 TESTING REQUIREMENTS (continued)
| |
| TEST FREQUENCY TR 16.7-9-20 Verify proper installation of pressurizer insulation. 18 months TR 16.7-9-21 Verify pressurizer heaters powered from the SSS have a 18 months capacity of > 63.5 kW measured at motor control center SMXG.
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| TR 16.7-9-22 Verify flowpath from the reactor vessel head through the 18 months valves powered from the SSS is unobstructed.
| |
| BASES The SSS is designed to mitigate the consequences of certain postulated fire, security, and station blackout incidents by providing capability to maintain MODE 3 conditions and by controlling and monitoring vital systems from locations external to the main control room. This capability is consistent with the requirements of 10 CFR Part 50.48(c).
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| When the SSS is under Condition A and it is anticipated that Condition D will be utilized, establish the bases for continued operation (including any supporting actions) prior to entering Condition D. Risks associated with the continued operation under Condition D are evaluated and managed through existing processes and procedures. These risk contributors, risk insights, risk-informed information, and/or risk mitigation actions assessed and managed during periods when Condition D is applied, are to be included in the 14-day special report.
| |
| The TESTING REQUIREMENTS ensure that the SSS systems and components are capable of performing their intended functions. The required level in the SSS diesel generator fuel storage tank ensures sufficient fuel for 72 hours uninterrupted operation. It is assumed that, within 72 hours, either offsite power can be restored or additional fuel can be added to the storage tank.
| |
| Although the standby makeup pump is not nuclear safety related and was not designed according to ASME Code requirements, it is tested quarterly to ensure its FUNCTIONALITY. The TESTING REQUIREMENT concerning the standby makeup pump water supply ensures that an adequate water volume is available to supply the pump continuously for 72 hours.
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| Total accumulative LEAKAGE is calculated in the NC System Leakage Calculation procedure as identified + unidentified + seal leakoff (References 2 and 3). The REMEDIAL ACTION limit of 20 gpm total accumulative LEAKAGE provides additional margin to allow for Catawba Units 1 and 2 16.7-9-4 Revision 15
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| | |
| SSS 16.7-9 BASES (continued) instrument inaccuracy, and for the predicted increase in seal leakoff rate due to heatup of the reactor coolant pump seal injection water supply temperature following the SSS event (due to spent fuel pool heatup).
| |
| Following the increase in seal injection temperature, the standby makeup pump flow of 26 gpm is sufficient to provide in excess of this total accumulative LEAKAGE, thereby assuring that reactor coolant system inventory is maintained at MODE 3 conditions. The supporting evaluation is provided in CNC-1223.04-00-0072 (Ref. 4).
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| A visual inspection of the diesel starting 24-volt batteries, cell plates, and battery racks provides an indication of physical damage or abnormal deterioration that could potentially degrade battery performance. Since the battery cell jars are not transparent, a direct visual inspection of the cell plates cannot be performed. Instead, the cell plates are inspected for physical damage and abnormal deterioration by: 1) visually inspecting the jar sides of each cell for excessive bowing and/or deformation, and 2) visually inspecting the electrolyte of each cell for abnormal appearance.
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| Verifying individual cell voltage while on float charge for the SSS diesel starting 24-Volt batteries ensures that each cell is capable of supporting its 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 battery cell) in a fully charged state. The battery cell voltage limit of 1.36 volts is consistent with the nominal design voltage of the battery and is based on the manufacturers recommended minimum float charge voltage for a fully charged cell with adequate capacity. The 24-Volt starting battery is designed with two battery banks, each battery bank contains 20 individual battery cells. The 24-Volt starting battery has sufficient capacity margin to maintain SSS diesel starting functionality with one cell in each battery bank to be fully degraded with a voltage < 1.36 volts. The 24-Volt starting battery is required to have 19 individual battery cells per battery bank to maintain SSS diesel starting functionality with sufficient capacity margin.
| |
| The battery sizing calculation accounts for one degraded cell in each battery bank by assuming the degraded cells undergo a worst case polarity reversal during SSS diesel starting. The supporting evaluation is provided in CNC-1381.06-00-0056 (Ref.12).
| |
| Verification of proper installation of pressurizer insulation ensures that pressurizer heat losses during an SSS event do not exceed the capacity of the pressurizer heaters powered from the SSS.
| |
| Testing of the pressurizer heater capacity ensures the full capacity of the heaters is available to maintain a steam bubble in the pressurizer during an SSS event. The acceptance criterion includes an allowance for the voltage drop in the power cables between the SSS and the pressurizer and measurement uncertainty.
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| Catawba Units 1 and 2 16.7-9-5 Revision 15
| |
| | |
| SSS 16.7-9 BASES (continued)
| |
| Testing of the flowpath from the reactor vessel head to the pressurizer relief tank ensures sufficient flow capacity for reactor coolant inventory control during an SSS event.
| |
| REFERENCES 1. Letter from NRC to Gary R. Peterson, Duke, Issuance of Improved Technical Specifications Amendments for Catawba, September 30, 1998.
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| : 2. PT/1(2)/A/4150/001D, NC System Leakage Calculation.
| |
| : 3. PT/1(2)/A/4150/001I, Manual NC Leakage Calculation.
| |
| : 4. CNC-1223.04-00-0072, Reactor Coolant Pumps No. 1 Seal Leakoff Annunciator Alarm Setpoint for Unit 1 and Unit 2.
| |
| : 5. CNS-1560.SS-00-0001, Design Basis Specification for the Standby Shutdown Facility.
| |
| : 6. Catawba Technical Specification Amendments 206/200, July 10, 2003.
| |
| : 7. Catawba UFSAR, Section 18.2.4.
| |
| : 8. Catawba License Renewal Commitments, CNS-1274.00 0016, Section 4.5.
| |
| : 9. CNC-1223.03-00-0033, Determination of Pressurizer Heater Capacity Powered from the SSF Diesel.
| |
| : 10. Catawba Nuclear Station 10 CFR 50.48(c) Fire Protection Safety Evaluation (SE).
| |
| : 11. 10 CFR 50.48(c), Fire Protection.
| |
| : 12. CNC-1381.06-00-0056, SSF Diesel Generator Battery Sizing Calculation.
| |
| : 13. UFSAR Table 18-1.
| |
| : 14. UFSAR Section 18.3.1.
| |
| Catawba Units 1 and 2 16.7-9-6 Revision 15
| |
| | |
| Radiation Monitoring for Plant Operations 16.7-10 16.7 INSTRUMENTATION 16.7-10 Radiation Monitoring for Plant Operations COMMITMENT The radiation monitoring instrumentation channels for plant operations shown in Table 16.7-10-1 shall be FUNCTIONAL.
| |
| APPLICABILITY: As shown in Table 16.7-10-1.
| |
| REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One or more radiation A.1 Adjust the setpoint to within 4 hours monitoring channels the limit.
| |
| Alarm/Trip setpoint for plant operations OR exceeding the value shown in Table 16.7 A.2 Declare the channel non- 4 hours
| |
| : 1. functional.
| |
| (continued)
| |
| Catawba Units 1 and 2 16.7-10-1 Revision 10
| |
| | |
| Radiation Monitoring for Plant Operations 16.7-10 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME B. One Containment B.1 -------------NOTE--------------
| |
| Atmosphere - High In order to utilize Required Gaseous Radioactivity Action B.1, the following (EMF Low Range) conditions must be channel non-functional. 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 12 hours channel to FUNCTIONAL status.
| |
| (continued)
| |
| Catawba Units 1 and 2 16.7-10-2 Revision 10
| |
| | |
| Radiation Monitoring for Plant Operations 16.7-10 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME C. Required Action and C.1 Close the Containment Immediately associated Completion Purge Exhaust System Time of Condition B not (CPES) valves.
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| met.
| |
| OR Required Action B.1 not utilized.
| |
| D. One Control Room Air D.1 Initiate action to restore Immediately Intake - Radiation Level non-functional channel(s)
| |
| - High Gaseous to FUNCTIONAL status.
| |
| Radioactivity (EMF-43A
| |
| & B - Low Range) AND channel non-functional in one or both control D.2 Ensure that one Control 1 hour room intakes. Room Area Ventilation System (CRAVS) train is in operation.
| |
| E. One Fuel Storage Pool E.1 Provide a portable Immediately Area - Radiation Level continuous monitor with the (1EMF-15, 2EMF-4) same Alarm Setpoint in the channel non-functional. fuel storage pool area.
| |
| AND E.2.1 Restore non-functional 30 days monitor to FUNCTIONAL status.
| |
| OR E.2.2 Suspend all operations 30 days involving fuel movement in the fuel building.
| |
| (continued)
| |
| Catawba Units 1 and 2 16.7-10-3 Revision 10
| |
| | |
| Radiation Monitoring for Plant Operations 16.7-10 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME F. One Fuel Storage Pool F.1.1 Initiate action to restore Immediately Area - High Gaseous non-functional channel to Radioactivity (EMF-42) FUNCTIONAL status.
| |
| channel non-functional.
| |
| AND F.1.2 --------------NOTE-------------
| |
| Only applicable during fuel handling operations in the fuel building.
| |
| Ensure one Fuel Handling Immediately Ventilation Exhaust System (FHVES) train is in operation and all operating FHVES trains are in the filtered mode.
| |
| OR F.2 Suspend all operations Immediately involving fuel movement in the fuel building.
| |
| (continued)
| |
| Catawba Units 1 and 2 16.7-10-4 Revision 10
| |
| | |
| Radiation Monitoring for Plant Operations 16.7-10 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME G. One Auxiliary Building G.1.1 Initiate action to restore Immediately Ventilation - High non-functional channel to Gaseous Radioactivity FUNCTIONAL status.
| |
| (EMF-41) channel non-functional. AND G.1.2 Verify EMF-36 is Immediately FUNCTIONAL (reference SLC 16.11-7) and in service for any affected unit in MODE 1, 2, 3 or 4.
| |
| AND G.1.3 Restore non-functional 30 days channel to FUNCTIONAL status.
| |
| OR G.2 Ensure all operating Immediately ABFVES trains are in the filtered mode for any affected unit in Mode 1, 2, 3 or 4.
| |
| (continued)
| |
| Catawba Units 1 and 2 16.7-10-5 Revision 10
| |
| | |
| Radiation Monitoring for Plant Operations 16.7-10 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME H. One Component Cooling H.1 Collect and analyze grab Once per 12 hours Water System (EMF- samples for principal 46A & B) channel non- gamma emitters (listed in functional. Table 16.11-1-1, NOTE 3) at a lower limit of detection of no more than 5x10-7 PCi/ml.
| |
| AND H.2 Restore non-functional 30 days channel to FUNCTIONAL status.
| |
| I. One or more N-16 I.1 Ensure that the Condenser Immediately Leakage Monitor (EMF- Evacuation System Noble 71, 72, 73, & 74) Gas Activity Monitor (EMF-channels non-functional. 33) is FUNCTIONAL and in operation.
| |
| OR I.2 Ensure that Required Immediately Actions are met per SLC 16.11-7 if the Condenser Evacuation System Noble Gas Activity Monitor (EMF-
| |
| : 33) is non-functional or not in operation.
| |
| J. One Auxiliary Building J.1 Collect and analyze grab Once per 7 days Cooling Water System samples for principal (EMF-89) channel non- gamma emitters (listed in functional. Table 16.11-1-1, NOTE 3) at a lower limit of detection of no more than 5x10-7 PCi/ml.
| |
| AND J.2 Restore non-functional 30 days channel to FUNCTIONAL status.
| |
| Catawba Units 1 and 2 16.7-10-6 Revision 10
| |
| | |
| Radiation Monitoring for Plant Operations 16.7-10 TESTING REQUIREMENTS
| |
| -----------------------------------------------------------NOTE-----------------------------------------------------------
| |
| Refer to Table 16.7-10-1 to determine which TRs apply for each Radiation Monitoring for Plant Operations channel.
| |
| TEST FREQUENCY TR 16.7-10-1 Perform CHANNEL CHECK. 12 hours TR 16.7-10-2 Perform CHANNEL OPERATIONAL TEST. 18 months TR 16.7-10-3 Perform CHANNEL CALIBRATION. 18 months Catawba Units 1 and 2 16.7-10-7 Revision 10
| |
| | |
| Radiation Monitoring for Plant Operations 16.7-10 Table 16.7-10-1 Radiation Monitoring Instrumentation for Plant Operations MONITOR APPLICABLE REQUIRED ALARM/TRIP TESTING MODES CHANNELS SETPOINT REQUIREMENTS
| |
| : 1. Containment Atmosphere - 1, 2, 3, 4, 5, 6 1 Note (a) TR 16.7-10-1 High Gaseous TR 16.7-10-2 Radioactivity TR 16.7-10-3 (EMF Low Range)
| |
| : 2. Fuel Storage Pool Areas - With irradiated 1 d 1.7 x 10-4 PCi/ml TR 16.7-10-1 High Gaseous fuel in the fuel TR 16.7-10-2 Radioactivity storage pool TR 16.7-10-3 (EMF-42) areas
| |
| : 3. Fuel Storage Pool Areas - With fuel in the 1 < 15 mR/h TR 16.7-10-1 Radiation Level fuel storage pool Note (d) TR 16.7-10-2 (Fuel Bridge - 1EMF-15, areas TR 16.7-10-3 2EMF-4)
| |
| : 4. Control Room Air Intake - At all times 2 (1/intake) d 1.7 x 10-4 PCi/ml TR 16.7-10-1 Radiation Level - High TR 16.7-10-2 Gaseous Radioactivity TR 16.7-10-3 (EMF-43A & B - Low Range)
| |
| : 5. Auxiliary Building 1, 2, 3, 4 1 d 1.7 x 10-4 PCi/ml TR 16.7-10-1 Ventilation - High Gaseous TR 16.7-10-2 Radioactivity TR 16.7-10-3 (EMF-41)
| |
| : 6. Component Cooling Water At all times(e) 1(b) d 1 x 10-3 PCi/ml TR 16.7-10-1 System TR 16.7-10-2 (EMF-46A & B) TR 16.7-10-3
| |
| : 7. N-16 Leakage Monitor 1 (40-100% 4 (1/steamline) Note (c) TR 16.7-10-1 (EMF-71, 72, 73, & 74) reactor power) TR 16.7-10-2 TR 16.7-10-3
| |
| : 8. Auxiliary Building Cooling At all times 1 d 1 x 10-3 PCi/ml TR 16.7-10-1 Water System TR 16.7-10-2 (EMF-89) TR 16.7-10-3 Catawba Units 1 and 2 16.7-10-8 Revision 10
| |
| | |
| Radiation Monitoring for Plant Operations 16.7-10 Table 16.7-10-1 Notes (a) When venting or purging from containment to the atmosphere, the trip setpoint shall not exceed the equivalent limits of SLC 16.11-6 in accordance with the methodology and parameters in the ODCM. When not venting or purging in Modes 5 or 6, the alarm setpoint concentration (PCi/ml) shall be such that the actual submersion dose rate would not exceed 5 mR/hr without alarm. When not venting or purging in Modes 1 through 4, the alarm setpoint shall be no more than 3 times the containment atmosphere activity as indicated by the radiation monitor.
| |
| (b) For EMF-46A & B: The EMF monitor associated with the operating Component Cooling Water System train shall be FUNCTIONAL. This requirement is based on the existence of an interlock which blocks the EMF loss of flow alarm from being received in the control room when the associated train pump motor(s) are not running.
| |
| (c) The setpoint is as required by the primary to secondary leak rate monitoring program.
| |
| (d) Catawbas Spent Fuel Pools were originally licensed for compliance with 10 CFR 70.24. The basis for the 15 mR/hr setpoint can be found in 10 CFR 70.24(a)(2) which states, in part, ... The monitoring devices in the system shall have a preset alarm point of not less than 5 millirems per hour (in order to avoid false alarms) nor more than 20 millirems per hour. ... Although Catawba received exemption from 10 CFR 70.24 in 1997, the 15 mR/hr setpoint limit for detection of inadvertent criticality in the Spent Fuel Pool is still appropriate. Catawba is presently committed to compliance with 10 CFR 50.68 which requires, in part, (6) Radiation monitors are provided in storage and associated handling areas when fuel is present to detect excessive radiation levels and initiate appropriate safety actions.
| |
| Therefore, the setpoint may be elevated, using approved plant procedures, above 15 mR/hr during Independent Spent Fuel Storage Installation (ISFSI) Transportable Storage Container (TSC) transfer activities when the loaded TSC may generate dose rates in excess of 15 mR/hr at the detector location. The setpoint shall be returned to <
| |
| completion of the TSC transfer.
| |
| - 15 mR/hr upon (e) The Component Cooling Water (CCW) radiation monitors are not considered to be non-functional just because there is no CCW flow through their respective trains. The EMFs would be considered non-functional if one of the inlet/outlet CCW isolation valves to the EMF were closed, if the EMF itself was not functioning properly, or if preventive maintenance/calibration activities were being performed on the EMF rendering it out of service. For the situation where the associated train related CCW pumps are not running and a section of the CCW System (e.g., CCW heat exchanger) has been isolated and drained such that the associated radiation monitor has no process fluid to monitor, grab samples are not required.
| |
| Catawba Units 1 and 2 16.7-10-9 Revision 10
| |
| | |
| Radiation Monitoring for Plant Operations 16.7-10 BASES The FUNCTIONALITY of the radiation monitoring instrumentation for plant operations ensures that: (1) the associated action will be initiated when the radiation level monitored by each channel or combination thereof reaches its setpoint, (2) the specified coincidence logic is maintained, and (3) sufficient redundancy is maintained to permit a channel to be out of service for testing or maintenance. The radiation monitors for plant operations senses radiation levels in selected plant systems and locations and determines whether or not predetermined limits are being exceeded. The radiation monitors send actuation signals to initiate alarms or automatic isolation action and actuation of emergency exhaust or ventilation systems. Some of the final actuations are dependent on plant condition in addition to the actuation signals from the radiation monitors.
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| Operation of the Component Cooling Water (CCW) System Train A with the Train A Radiation Monitoring System (EMF) monitor non-functional and relying on the Train B EMF monitor for detection of radioactivity is not permissible. Likewise, operation of the CCW System Train B with the Train B EMF monitor non-functional and relying on the Train A EMF monitor for detection of radioactivity is not permissible. This is due to the interlock between the EMF monitor low-flow alarm and the operation of the CCW System pump motors on the same train. The EMF monitor in the operating CCW System pump train must be FUNCTIONAL, or the compensatory measures taken as specified.
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| 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 B.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 B.1.
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| REFERENCES 1. Letter from NRC to Gary R. Peterson, Duke, Issuance of Improved Technical Specifications Amendments for Catawba, September 30, 1998.
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| : 2. Letter from NRC to M. S. Tuckman, Duke, Issuance of Exemption to 10 CFR 70.24, Criticality Accident Requirements, July 29, 1997.
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| Catawba Units 1 and 2 16.7-10-10 Revision 10
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| Hydrogen Monitors 16.7-15 16.7 INSTRUMENTATION 16.7-15 Hydrogen Monitors COMMITMENT The Hydrogen Monitors shall be FUNCTIONAL.
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| APPLICABILITY: MODES 1 and 2.
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| REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One Hydrogen Monitor A.1 Restore channel to 30 days channel non-functional. FUNCTIONAL status.
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| B. Two Hydrogen Monitor B.1 Restore one Hydrogen 72 hours channels non-functional. Monitor channel to FUNCTIONAL status.
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| C. Required Action and C.1 Initiate a Condition Report Immediately associated Completion in accordance with the Time of Condition A or B Corrective Action Program.
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| not met.
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| Catawba Units 1 and 2 16.7-15-1 Revision 3
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| Hydrogen Monitors 16.7-15 TESTING REQUIREMENTS TEST FREQUENCY TR 16.7-15-1 Perform CHANNEL CHECK. 31 days TR 16.7-15-2 Perform CHANNEL CALIBRATION. 9 months TR 16.7-15-3 Perform CHANNEL CALIBRATION. 18 months BASES The Hydrogen Monitors are provided to detect high hydrogen concentration conditions that represent a potential for containment breach from a hydrogen explosion during accident conditions. With the elimination of the design basis LOCA hydrogen release (Ref. 5), the Hydrogen Monitors are no longer required to mitigate design basis accidents. The Hydrogen Monitors are now classified as Regulatory Guide 1.97, Category 3 instrumentation. The Hydrogen Monitors are used to assess the degree of core damage during a severe accident and confirm that random or deliberate ignition has taken place.
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| The FUNCTIONALITY of the Hydrogen Monitors ensures that there is sufficient information available on unit parameters to monitor and assess unit status and behavior following an accident. The availability of the Hydrogen Monitors is important so that responses to corrective actions can be observed and the need for, and the magnitude of, further actions can be determined.
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| Two FUNCTIONAL channels ensure no single failure prevents operators from getting the information necessary for them to determine the safety status of the unit. If two Hydrogen Monitor channels are non-functional, grab samples of the Containment atmosphere can be obtained and analyzed for hydrogen concentration (Ref. 6).
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| The CHANNEL CALIBRATION is a complete check of the instrument loop, including the sensor using hydrogen gas mixtures to obtain calibration points at 1 volume percent (v/o) and 4 v/o hydrogen. The test verifies that the channel responds to measured parameter with the necessary range and accuracy. The Frequency is based on operating experience associated with these monitors.
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| These SLC requirements were relocated from the Technical Specifications as a result of License Amendments 219 and 214 for Units 1 and 2, respectively.
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| Catawba Units 1 and 2 16.7-15-2 Revision 3
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| Hydrogen Monitors 16.7-15 REFERENCES 1. Letter from NRC to D.M. Jamil, Duke, License Amendments 219 and 214 for Units 1 and 2, respectively, dated March 1, 2005.
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| : 2. Catawba Updated Final Safety Analysis Report Section 1.8 and 6.2.5
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| : 3. Regulatory Guide 1.97, Rev. 2.
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| : 4. NUREG-0737, Supplement 1, TMI Action Items.
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| : 5. 10 CFR 50.44, Combustible gas control for nuclear power reactors.
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| : 6. Chemistry Management Procedure 3.4.12 Accident Contingency Sampling Plan.
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| Catawba Units 1 and 2 16.7-15-3 Revision 3
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| CPCOPDs 16.8-1 16.8 ELECTRICAL POWER SYSTEMS 16.8-1 Containment Penetration Conductor Overcurrent Protective Devices (CPCOPDs)
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| COMMITMENT Primary and backup CPCOPDs shown in Table 16.8-1-1 and 16.8-1-2 shall be FUNCTIONAL.
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| APPLICABILITY: MODES 1, 2, 3, and 4.
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| REMEDIAL ACTIONS
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| -------------------------------------------------------NOTES-------------------------------------------------------
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| : 1. Separate Condition entry is allowed for each penetration circuit.
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| : 2. Enter applicable Conditions and Required Actions for systems made inoperable or non-functional by CPCOPDs.
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| : 3. SLC 16.2-3 is not applicable to CPCOPDs in circuits which have their redundant devices tripped or removed, or their non-functional protective devices racked out or removed from the circuits.
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| CONDITION REQUIRED ACTION COMPLETION TIME A. One or more A.1.1 De-energize the circuit(s) 72 hours CPCOPD(s) non- by tripping the associated functional. redundant circuit breaker or removing the redundant fuse(s).
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| AND A.1.2 Verify the associated Once per 7 days redundant protective device(s) to be tripped or removed.
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| (continued)
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| Catawba Units 1 and 2 16.8-1-1 Revision 8
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| CPCOPDs 16.8-1 REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. (continued) OR A.2.1 De-energize the circuit(s) 72 hours by racking out the non-functional circuit breaker or removing the non-functional protective device(s).
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| AND A.2.2 Verify the non-functional Once per 7 days device(s) are removed or racked out.
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| B. Required Action and B.1 Initiate a Condition Report Immediately associated Completion in accordance with the Time not met. Corrective Action Program.
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| TESTING REQUIREMENTS
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| --------------------------------------------------------NOTE--------------------------------------------------------
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| TR 16.8-1-1, 16.8-1-2, and 16.8-1-3 are only required to be performed for 10% of the circuit breakers within each voltage level on a rotating basis during each testing interval.
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| TEST FREQUENCY TR 16.8-1-1 Perform a CHANNEL CALIBRATION of the associated 18 months protective relays for medium voltage circuits (4-15 kV).
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| (continued)
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| Catawba Units 1 and 2 16.8-1-2 Revision 8
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| CPCOPDs 16.8-1 TESTING REQUIREMENTS (continued)
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| TEST FREQUENCY TR 16.8-1-2 ---------------------------------NOTE---------------------------------
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| For each circuit breaker found non-functional during these functional tests, an additional representative sample of > 10% of all the circuit breakers of the non-functional type shall also be functionally tested until no more failures are found or all circuit breakers of that type have been functionally tested.
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| Perform an integrated protective system functional test 18 months on each medium voltage (4-15 kV) circuit breaker which includes simulated automatic actuation of the system and verify that each relay and associated circuit breakers function as designed.
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| TR 16.8-1-3 --------------------------------NOTES--------------------------------
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| : 1. Only required to be performed for 10% of each type of lower voltage circuit breakers on a rotating basis during each testing interval.
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| : 2. Circuit breakers found non-functional during functional testing shall be restored to FUNCTIONAL status prior to resuming operation of the circuit.
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| : 3. For each circuit breaker found non-functional during these functional tests, an additional representative sample of > 10% of all the circuit breakers of the non-functional type shall also be functionally tested until no more failures are found or all circuit breakers of that type have been functionally tested.
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| Inject a current in excess of the breakers nominal 18 months setpoint, measure the response time, and verify that the measured response time is < the manufacturers specified response time.
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| (continued)
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| Catawba Units 1 and 2 16.8-1-3 Revision 8
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| CPCOPDs 16.8-1 TESTING REQUIREMENTS (continued)
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| TEST FREQUENCY TR 16.8-1-4 Perform fuse inspection and maintenance program. 18 months TR 16.8-1-5 Perform inspection and preventive maintenance on each 60 months circuit breaker in accordance with procedures prepared in conjunction with its manufacturers recommendations.
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| BASES Containment electrical penetrations and penetration conductors are protected by either deenergizing circuits not required during reactor operation or by demonstrating the FUNCTIONALITY of primary and backup overcurrent protection circuit breakers during periodic testing.
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| The TESTING REQUIREMENTS applicable to lower voltage circuit breakers provide assurance of breaker reliability by testing at least one representative sample of each manufacturers brand of circuit breaker. Each manufacturers molded case circuit breakers are grouped into representative samples which are then tested on a rotating basis to ensure that all breakers are tested. If a wide variety exists within any manufacturers brand of circuit breakers, it is necessary to divide that manufacturers breakers into groups and treat each group as a separate type of breaker for testing purposes.
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| Fuse testing is in accordance with IEEE Standard 242-1975 (Reference 2).
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| This program will detect any significant degradation of the fuses or improperly sized fuses. Safety is further assured by the fail-safe nature of fuses; that is, if the fuse fails, the circuit will de-energize.
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| The lists of components for which this COMMITMENT is applicable exclude those circuits for which credible fault currents would not exceed the electrical penetration design rating.
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| REFERENCES 1. Letter from NRC to Gary R. Peterson, Duke, Issuance of Improved Technical Specifications Amendments for Catawba, September 30, 1998.
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| : 2. IEEE Standard 242-1975, IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power Systems.
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| Catawba Units 1 and 2 16.8-1-4 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED
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| : 1. 6900 VAC Swgr Primary Bkr RCP1A Reactor Coolant Pump 1A Backup Bkr 1TA-3 Primary Bkr RCP1B Reactor Coolant Pump 1B Backup Bkr 1TB-3 Primary Bkr RCP1C Reactor Coolant Pump 1C Backup Bkr 1TC-3 Primary Bkr RCP1D Reactor Coolant Pump 1D Backup Bkr 1TD-3
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| : 2. 600 VAC MCC 1EMXC-F01B Accumulator 1C Discharge Isol Vlv Primary Bkr 1NI76A Backup Fuse 1EMXC-F01C Check Vlv Test Header Cont Isol Vlv Primary Bkr 1NI95A Backup Fuse 1EMXC-F02A Train A Alternate Power to ND Letdn Primary Bkr Vlv 1ND1B Backup Fuse 1EMXC-F02B Hot Leg Inj Check Vlv Test Isol Vlv Primary Bkr 1NI153A Backup Fuse 1EMXC-F03A NC Pump 1C Thermal Barrier Outlet Primary Bkr Isol Vlv 1KC345A Backup Fuse 1EMXC-F03B Nitrogen to PRT Cont Isol Inside Vlv Primary Bkr 1NC54A Backup Fuse 1EMXC-F03C Pressurizer Power Operated Relief Primary Bkr Isol Vlv 1NC33A Backup Fuse 1EMXC-F05A NCDT Vent Inside Cont Isol Vlv Primary Bkr 1WL450A Backup Fuse Catawba Units 1 and 2 16.8-1-5 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 1EMXC-F05B Cont Sump Pumps Discharge Inside Primary Bkr Cont Isol Vlv 1WL825A Backup Fuse 1EMXC-F05C Ventilation Unit Cond Drain Tnk Primary Bkr Outside Cont Isol Vlv 1WL867A Backup Fuse 1EMXC-F06A NCDT Pumps Discharge Inside Cont Primary Bkr Isol Vlv 1WL805A Backup Fuse 1EMXC-F07B Cont Hydrogen Purge Outlet Cont Primary Bkr Isol Vlv 1VY17A Backup Fuse 1EMXD-F01A ND Pump 1A Suction from NC Loop Primary Bkr B Vlv 1ND1B Backup Fuse 1EMXD-F01B Accumulator 1B Discharge Isol Vlv Primary Bkr 1NI65B Backup Fuse 1EMXD-F01C NI Pump A to Hot Leg Check Vlv Primary Bkr Test Isol Vlv 1NI122B Backup Fuse 1EMXD-F02A ND Pump 1B Suction from NC Loop Primary Bkr C Vlv 1ND36B Backup Fuse 1EMXD-F02B ND to Hot Legs Chk 1NI125, 1NI129 Primary Bkr Test Isol Vlv 1NI154B Backup Fuse 1EMXD-F02C Pressurizer Power Operated Relief Primary Bkr Isol Vlv 1NC31B Backup Fuse 1EMXD-F05A Pressurizer Power Operated Relief Primary Bkr Isol Vlv 1NC35B Backup Fuse 1EMXD-F05B Rx Bldg Drain Hdr Inside Cont Isol Primary Bkr Vlv 1KC429B Catawba Units 1 and 2 16.8-1-6 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Backup Fuse 1EMXD-F05C NCDT Hx Clng Water Return Inside Primary Bkr Isol Vlv 1KC332B Backup Fuse 1EMXD-F06A NC Pump 1B Thermal Barrier Outlet Primary Bkr Isol Vlv 1KC364B Backup Fuse 1EMXD-F06B NC Pumps Return Hdr Inside Cont Primary Bkr Isol Vlv 1KC424B Backup Fuse 1EMXK-F01C Backup Nitrogen to PORV 1NC34A Primary Bkr from Accum Tnk 1A Vlv 1NI438A Backup Fuse 1EMXK-F02A NC Pump 1A Thermal Barrier Outlet Primary Bkr Isol Vlv 1KC394A Backup Fuse 1EMXK-F02B Lower Cont Ventilation Units Return Primary Bkr Cont Isol Vlv 1RN484A Backup Fuse 1EMXK-F02C NV Supply to Pressurizer Vlv Primary Bkr 1NV037A Backup Fuse 1EMXK-F03A S/G C Blowdown Line Sample Inside Primary Bkr Cont Isol Vlv 1NM210A Backup Fuse 1EMXK-F04A S/G A Upper Shell Sample Inside Primary Bkr Cont Isol Vlv 1NM187A Backup Fuse 1EMXK-F04B S/G A Blowdown Line Sample Inside Primary Bkr Cont Isol Vlv 1NM190A Backup Fuse 1EMXK-F04C S/G C Upper Shell Sample Inside Primary Bkr Cont Isol Vlv 1NM207A Backup Fuse Catawba Units 1 and 2 16.8-1-7 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 1EMXK-F06A Hydrogen Skimmer Fan 1A Inlet Vlv Primary Bkr 1VX1A Backup Fuse 1EMXK-F07C Electric Hydrogen Recombiner Power Primary Bkr Supply Panel 1A Backup Fuse 1EMXK-F09A Accum 1A Discharge Isol Vlv 1NI54A Primary Bkr Backup Fuse 1EMXK-F09C NC Pump Oil Fill Header Cont Isol Primary Bkr Vlv 1NC196A Backup Fuse 1EMXK-F10A Cont Air Return Damper 1ARF-D-2 Primary Bkr Backup Fuse 1EMXK-F10B VQ Fans Suction from Cont Isol Vlv Primary Bkr 1VQ2A Backup Fuse 1EMXK-F10C Cont Air Addition Cont Isol Vlv Primary Bkr 1VQ16A Backup Fuse 1EMXK-F11A Cont Air Return Fan Motor 1A Primary Bkr Backup Fuse 1EMXK-F11B Hydrogen Skimmer Fan Motor 1A Primary Bkr Backup Fuse 1EMXL-F01B Trn B Alternate Power to ND Letdn Primary Bkr Vlv 1ND37A Backup Fuse 1EMXL-F01C NI Accum D Sample Line Inside Cont Primary Bkr Isol Vlv 1NM81B Backup Fuse 1EMXL-F02A NC Pump 1D Thermal Barrier Outlet Primary Bkr Isol Vlv 1KC413B Backup Fuse Catawba Units 1 and 2 16.8-1-8 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 1EMXL-F02B Air Handling Units Glycol Return Primary Bkr Cont Isol Vlv 1NF233B Backup Fuse 1EMXL-F02C NI Accum C Sample Line Inside Cont Primary Bkr Isol Vlv 1NM78B Backup Fuse 1EMXL-F03A S/G D Blowdown Sample Line Inside Primary Bkr Cont Isol Vlv 1NM220B Backup Fuse 1EMXL-F03B NI Accum A Sample Line Inside Cont Primary Bkr Isol Vlv 1NM72B Backup Fuse 1EMXL-F03C NI Accum B Sample Line Inside Cont Primary Bkr Isol Vlv 1NM75B Backup Fuse 1EMXL-F04A S/G B Upper Shell Sample Inside Primary Bkr Cont Isol Vlv 1NM197B Backup Fuse 1EMXL-F04B S/G B Blowdown Sample Line Inside Primary Bkr Cont Isol Vlv 1NM200B Backup Fuse 1EMXL-F04C S/G D Upper Shell Sample Inside Primary Bkr Cont Isol Vlv 1NM217B Backup Fuse 1EMXL-F06A Hydrogen Skimmer Fan 1B Inlet Vlv Primary Bkr 1VX2B Backup Fuse 1EMXL-F06B Backup Nitrogen to PORV 1NC32B Primary Bkr from Accum Tnk 1B Vlv 1NI439B Backup Fuse 1EMXL-F07C Electric Hydrogen Recombiner Power Primary Bkr Supply Panel 1B Backup Fuse 1EMXL-F09A Accum 1D Discharge Isol Vlv 1NI88B Primary Bkr Catawba Units 1 and 2 16.8-1-9 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Backup Fuse 1EMXL-F10A Cont Air Return Damper 1ARF-D-4 Primary Bkr Backup Fuse 1EMXL-F10B Reactor Vessel Head Vent Vlv Primary Bkr 1NC251B Backup Fuse 1EMXL-F10C Reactor Vessel Head Vent Vlv Primary Bkr 1NC252B Backup Fuse 1EMXL-F11A Cont Air Return Fan Motor 1B Primary Bkr Backup Fuse 1EMXL-F11B Hydrogen Skimmer Fan Motor 1B Primary Bkr Backup Fuse 1EMXS-F01B NC Pumps Seal Return Inside Cont Primary Bkr Isol Vlv 1NV89A Backup Fuse 1EMXS-F02A ND Pump 1B Suction from NC Loop Primary Bkr C Vlv 1ND37A Backup Fuse 1EMXS-F02B Reactor Vessel Head Vent Vlv Primary Bkr 1NC250A Backup Fuse 1EMXS-F03D ND Pump 1A Suction from NC Loop Primary Bkr B Vlv 1ND2A Backup Fuse 1EMXS-F03E Reactor Vessel Head Vent Vlv Primary Bkr 1NC253A Backup Fuse 1EMXS-F04B S/G D Blowdown Inside Cont Isol Vlv Primary Bkr 1BB8A Backup Fuse Catawba Units 1 and 2 16.8-1-10 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 1EMXS-F04C S/G B Blowdown Inside Cont Isol Vlv Primary Bkr 1BB19A Backup Fuse 1EMXS-F05A S/G A Blowdown Inside Cont Isol Vlv Primary Bkr 1BB56A Backup Fuse 1EMXS-F05B S/G C Blowdown Inside Cont Isol Vlv Primary Bkr 1BB60A Backup Fuse 1EMXS-F05C Pressurizer Liquid Sample Line Primary Bkr Inside Cont Isol Vlv 1NM3A Backup Fuse 1EMXS-F06A Pressurizer Steam Sample Line Primary Bkr Inside Cont Isol Vlv 1NM6A Backup Fuse 1EMXS-F06B NC Hot Leg A Sample Line Inside Primary Bkr Cont Isol Vlv 1NM22A Backup Fuse 1EMXS-F06C NC Hot Leg C Sample Line Inside Primary Bkr Cont Isol Vlv 1NM25A Backup Fuse 1MXM-F01A Reactor Coolant Pump Motor Drain Primary Bkr Tnk Pump Motor Backup Fuse 1MXM-F02A NC Pump 1B Oil Lift Pump Motor 1 Primary Bkr Backup Fuse 1MXM-F02B NC Pump 1C Oil Lift Pump Motor 1 Primary Bkr Backup Fuse 1MXM-F03A Ice Condenser Power Transformer Primary Bkr ICT1A Backup Fuse 1MXM-F03B Ice Condenser Air Handling Unit 1B6 Primary Bkr Fan Motor A & B Backup Fuse Catawba Units 1 and 2 16.8-1-11 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 1MXM-F03C Ice Condenser Equipment Access Primary Bkr Door Hoist Motor 1A Backup Fuse 1MXM-F04D Lighting Transformer 1LR10 Primary Bkr Backup Fuse 1MXM-F04E Lighting Transformer 1LR13 Primary Bkr Backup Fuse 1MXM-F05A 175 Ton Polar Crane and 25 Ton Aux Primary Bkr Crane No. R013 and R015 Backup Fuse 1MXM-F05C Upper Containment Welding Feeder Primary Bkr Backup Fuse 1MXM-F06A Ice Condenser Air Handling Unit 1A7 Primary Bkr Fan Motor A & B Backup Fuse 1MXM-F06B Ice Condenser Air Handling Unit 1B8 Primary Bkr Fan Motor A & B Backup Fuse 1MXM-F06C Ice Condenser Air Handling Unit 1A9 Primary Bkr Fan Motor A & B Backup Fuse 1MXM-F06D Ice Condenser Air Handling Unit Primary Bkr 1B10 Fan Motor A & B Backup Fuse 1MXM-F07B Ice Condenser Air Handling Unit Primary Bkr 1A13 Fan Motor A & B Backup Fuse 1MXM-F07C Ice Condenser Air Handling Unit Primary Bkr 1B14 Fan Motor A & B Backup Fuse 1MXM-F08D Ice Condenser Refrigeration Floor Primary Bkr Cool Defrost Heater 1A Catawba Units 1 and 2 16.8-1-12 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Backup Fuse 1MXM-F09A Ice Condenser Air Handling Unit 1A1 Primary Bkr Fan Motor A & B Backup Fuse 1MXM-F09B Ice Condenser Air Handling Unit 1B2 Primary Bkr Fan Motor A & B Backup Fuse 1MXM-F09C Ice Condenser Air Handling Unit 1A3 Primary Bkr Fan Motor A & B Backup Fuse 1MXM-F09D Ice Condenser Air Handling Unit 1B4 Primary Bkr Fan Motor A & B Backup Fuse 1MXM-F10A Cont Floor and Equipment Sump Primary Bkr Pump Motor 1A1 Backup Fuse 1MXM-F10B Cont Floor and Equipment Sump Primary Bkr Pump Motor 1B1 Backup Fuse 1MXN-F01F Stud Tensioner Hoist 1B Primary Bkr Backup Fuse 1MXN-F02A NC Pump 1B Oil Lift Pump Motor 2 Primary Bkr Backup Fuse 1MXN-F02B NC Pump 1C Oil Lift Pump Motor 2 Primary Bkr Backup Fuse 1MXN-F02E Stud Tensioner Hoist 1C Primary Bkr Backup Fuse 1MXN-F03A Ice Condenser Power Transformer Primary Bkr ICT1B Backup Fuse Catawba Units 1 and 2 16.8-1-13 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 1MXN-F03B Ice Condenser Bridge Crane 1 Crane Primary Bkr No. R011 Backup Fuse 1MXN-F03E Stud Tensioner Hoist 1A Primary Bkr Backup Fuse 1MXN-F04D Lighting Transformer 1LR5 Primary Bkr Backup Fuse 1MXN-F04E Lighting Transformer 1LR6 Primary Bkr Backup Fuse 1MXN-F05A Ice Condenser Refrigeration Floor Primary Bkr Cool Defrost Heater 1B Backup Fuse 1MXN-F05B Ice Condenser Refrigeration Floor Primary Bkr Cool Pump Motor 1B Backup Fuse 1MXN-F05C Ice Condenser Equipment Access Primary Bkr Door Hoist Motor 1B Backup Fuse 1MXN-F06A Ice Condenser Air Handling Unit 1B1 Primary Bkr Fan Motor A & B Backup Fuse 1MXN-F06B Ice Condenser Air Handling Unit 1A2 Primary Bkr Fan Motor A & B Backup Fuse 1MXN-F06C Ice Condenser Air Handling Unit 1B3 Primary Bkr Fan Motor A & B Backup Fuse 1MXN-F06D Ice Condenser Air Handling Unit 1A4 Primary Bkr Fan Motor A & B Backup Fuse 1MXN-F07B Ice Condenser Air Handling Unit 1B5 Primary Bkr Fan Motor A & B Backup Fuse Catawba Units 1 and 2 16.8-1-14 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 1MXN-F07C Ice Condenser Air Handling Unit 1A6 Primary Bkr Fan Motor A & B Backup Fuse 1MXN-F08A Ice Condenser Air Handling Unit 1B7 Primary Bkr Fan Motor A & B Backup Fuse 1MXN-F08B Ice Condenser Air Handling Unit 1A8 Primary Bkr Fan Motor A & B Backup Fuse 1MXN-F08C Ice Condenser Air Handling Unit 1B9 Primary Bkr Fan Motor A & B Backup Fuse 1MXN-F08D Ice Condenser Air Handling Unit Primary Bkr 1A10 Fan Motor A & B Backup Fuse 1MXN-F09A Ice Condenser Air Handling Unit Primary Bkr 1B11 Fan Motor A & B Backup Fuse 1MXN-F09B Ice Condenser Air Handling Unit Primary Bkr 1A12 Fan Motor A & B Backup Fuse 1MXN-F09C Ice Condenser Air Handling Unit Primary Bkr 1B13 Fan Motor A & B Backup Fuse 1MXN-F09D Ice Condenser Air Handling Unit Primary Bkr 1A14 Fan Motor A & B Backup Fuse 1MXN-F10A Cont Floor and Equipment Sump Primary Bkr Pump Motor 1A2 Backup Fuse 1MXN-F10B Cont Floor and Equipment Sump Primary Bkr Pump Motor 1B2 Backup Fuse 1MXN-F10C Incore Instrumentation Sump Pump Primary Bkr Motor 1 Catawba Units 1 and 2 16.8-1-15 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Backup Fuse 1MXN-F10D Ice Condenser Air Handling Unit Primary Bkr 1B15 Fan Motor A & B Backup Fuse 1MXO-F01A Upper Cont Air Return Fan Motor 1C Primary Bkr Backup Fuse 1MXO-F02B Control Rod Drive Ventilation Fan Primary Bkr Motor 1A Backup Fuse 1MXO-F03A Lower Cont Ventilation Unit 1C Fan Primary Bkr Motor Backup Fuse 1MXO-F04C Upper Cont Ventilation Unit 1C Fan Primary Bkr Motor Backup Fuse 1MXO-F05C Cont Pipe Tunnel Booster Fan Motor Primary Bkr 1A Backup Fuse 1MXP-F01A Upper Cont Return Air Fan 1B Primary Bkr Backup Fuse 1MXP-F02B Control Rod Drive Ventilation Fan Primary Bkr Motor 1B Backup Fuse 1MXP-F03A Lower Cont Ventilation Unit 1B Fan Primary Bkr Motor Backup Fuse 1MXP-F04D Upper Cont Ventilation Unit 1B Fan Primary Bkr Motor Backup Fuse 1MXP-F05C Cont Pipe Tunnel Booster Fan Motor Primary Bkr 1B Backup Fuse 1MXQ-F01A Upper Cont Return Air Fan Motor 1A Catawba Units 1 and 2 16.8-1-16 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Primary Bkr Backup Fuse 1MXQ-F01B Incore Instrument Room Ventilation Primary Bkr Unit 1A Fan Motor Backup Fuse 1MXQ-F02B Control Rod Drive Ventilation Fan Primary Bkr Motor 1C Backup Fuse 1MXQ-F03A Lower Cont Ventilation Unit 1A Fan Primary Bkr Motor Backup Fuse 1MXQ-F04C Upper Cont Ventilation Unit 1A Fan Primary Bkr Motor Backup Fuse 1MXR-F01A Upper Cont Return Air Fan Motor 1D Primary Bkr Backup Fuse 1MXR-F01B Incore Instrument Room Ventilation Primary Bkr Unit 1B Fan Motor Backup Fuse 1MXR-F02B Control Rod Drive Ventilation Fan Primary Bkr Motor 1D Backup Fuse 1MXR-F03A Lower Cont Ventilation Unit 1D Fan Primary Bkr Motor Backup Fuse 1MXR-F04C Upper Cont Ventilation Unit 1D Fan Primary Bkr Motor Backup Fuse 1MXY-F02A NC Pump 1A Oil Lift Pump Motor 1 Primary Bkr Backup Fuse 1MXY-F02B NC Pump 1D Oil Lift Pump Motor 1 Primary Bkr Backup Fuse Catawba Units 1 and 2 16.8-1-17 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 1MXY-F02C Rx Bldg Lower Cont Welding Primary Bkr Machine Receptacle 1RCPL0185 Backup Fuse 1MXY-F02D Upper Cont Rx Bldg Welding Primary Bkr Receptacle 1RCPL0193 Backup Fuse 1MXY-F03A Reactor Coolant Drain Tnk Pump Primary Bkr Motor 1A Backup Fuse 1MXY-F03D Ice Condenser Refrigeration Floor Primary Bkr Cool Pump Motor 1A Backup Fuse 1MXY-F05A Lighting Transformer 1LR8 Primary Bkr Backup Fuse 1MXY-F05B Lighting Transformer 1LR11 Primary Bkr Backup Fuse 1MXY-F05C Lighting Transformer 1LR14 Primary Bkr Backup Fuse 1MXY-F06A Ice Condenser Air Handling Unit 1A5 Primary Bkr Fan Motor A & B Backup Fuse 1MXY-F06B Ice Condenser Air Handling Unit Primary Bkr 1A11 Fan Motor A & B Backup Fuse 1MXY-F06C Ice Condenser Air Handling Unit Primary Bkr 1B12 Fan Motor A & B Backup Fuse 1MXY-F06D Ice Condenser Air Handling Unit Primary Bkr 1A15 Fan Motor A & B Backup Fuse 1MXY-F08A Incore Drive Assembly Motor 1A Primary Bkr Backup Fuse Catawba Units 1 and 2 16.8-1-18 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 1MXY-F08B Incore Drive Assembly Motor 1C Primary Bkr Backup Fuse 1MXY-F08C Incore Drive Assembly Motor 1E Primary Bkr Backup Fuse 1MXY-F08D Lower Cont Auxiliary Charcoal Filter Primary Bkr Unit Fan Motor 1A Backup Fuse 1MXZ-F02A NC Pump 1A Oil Lift Pump Motor 2 Primary Bkr Backup Fuse 1MXZ-F02B NC Pump 1D Oil Lift Pump Motor 2 Primary Bkr Backup Fuse 1MXZ-F03A Reactor Coolant Drain Tnk Pump Primary Bkr Motor 1B Backup Fuse 1MXZ-F04B Lighting Transformer 1LR1 Primary Bkr Backup Fuse 1MXZ-F04C Lighting Transformer 1LR2 Primary Bkr Backup Fuse 1MXZ-F04D Lighting Transformer 1LR3 Primary Bkr Backup Fuse 1MXZ-F05A Reactor Coolant Pump Jib Hoist No.
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| Primary Bkr R019 through R022 Backup Fuse 1MXZ-F05C Lower Cont Auxiliary Charcoal Filter Primary Bkr Unit Fan Motor 1B Backup Fuse 1MXZ-F06A Incore Drive Assembly Motor 1B Primary Bkr Catawba Units 1 and 2 16.8-1-19 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Backup Fuse 1MXZ-F06B Incore Drive Assembly Motor 1D Primary Bkr Backup Fuse 1MXZ-F06C Incore Drive Assembly Motor 1F Primary Bkr Backup Fuse 1MXZ-F06D Lower Cont Rx Bldg Welding Primary Bkr Receptacle 1RCPL0194 Backup Fuse 1MXZ-F07B Lighting Transformer 1LR4 Primary Bkr Backup Fuse 1MXZ-F07C 5 Ton Jib Crane in Cont Crane No.
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| Primary Bkr R005 Backup Fuse 1MXZ-F07D Reactor Cavity Manipulator Crane Primary Bkr No. R007 and R027 Backup Fuse 1MXZ-F08A S/G Drain Pump Motor 1 Primary Bkr Backup Fuse 1MXZ-F08C 15 Ton Equipment Access Hatch Primary Bkr Hoist Crane No. R009 Backup Fuse 1MXZ-F08D Control Rod Drive 2 Ton Jib Hoist Primary Bkr Crane No. R017 Backup Fuse 1MXZ-F08E Reactor Side Fuel Handling Control Primary Bkr Console Backup Fuse SMXG-F01C Standby Makeup Pump Drain Isol Vlv Primary Bkr 1NV876 Backup Fuse SMXG-F05C Pressurizer Heaters 28, 55, and 56 Catawba Units 1 and 2 16.8-1-20 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Primary Bkr Backup Fuse SMXG-F06A Standby Makeup Pump to Seal Primary Bkr Water Line Isol Vlv 1NV877 Backup Fuse
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| : 3. 600 VAC Pressurizer Heater Power Panels PHP1A-F01A Pressurizer Heaters 1, 2, and 22 Primary Bkr Backup Fuse PHP1A-F01B Pressurizer Heaters 5, 6, and 27 Primary Bkr Backup Fuse PHP1A-F01C Pressurizer Heaters 9, 10, and 32 Primary Bkr Backup Fuse PHP1A-F02C Pressurizer Heaters 11, 12, and 35 Primary Bkr Backup Fuse PHP1A-F02D Pressurizer Heaters 13, 14, and 37 Primary Bkr Backup Fuse PHP1A-F02E Pressurizer Heaters 17, 18, and 42 Primary Bkr Backup Fuse PHP1B-F01A Pressurizer Heaters 21, 47, and 48 Primary Bkr Backup Fuse PHP1B-F01B Pressurizer Heaters 26, 53, and 54 Primary Bkr Backup Fuse PHP1B-F02C Pressurizer Heaters 36, 65, and 66 Primary Bkr Backup Fuse PHP1B-F02D Pressurizer Heaters 41, 71, and 72 Catawba Units 1 and 2 16.8-1-21 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Primary Bkr Backup Fuse PHP1B-F02E Pressurizer Heaters 46, 77, and 78 Primary Bkr Backup Fuse PHP1C-F01A Pressurizer Heaters 7, 8, and 30 Primary Bkr Backup Fuse PHP1C-F01B Pressurizer Heaters 19, 20, and 45 Primary Bkr Backup Fuse PHP1C-F01C Pressurizer Heaters 23, 49, and 50 Primary Bkr Backup Fuse PHP1C-F01D Pressurizer Heaters 29, 57, and 58 Primary Bkr Backup Fuse PHP1C-F02C Pressurizer Heaters 34, 61, and 62 Primary Bkr Backup Fuse PHP1C-F02D Pressurizer Heaters 39, 69, and 70 Primary Bkr Backup Fuse PHP1C-F02E Pressurizer Heaters 44, 75, and 76 Primary Bkr Backup Fuse PHP1D-F01A Pressurizer Heaters 3, 4, and 25 Primary Bkr Backup Fuse PHP1D-F01B Pressurizer Heaters 15, 16, and 40 Primary Bkr Backup Fuse PHP1D-F01C Spare Primary Bkr Backup Fuse Catawba Units 1 and 2 16.8-1-22 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED PHP1D-F02C Spare Primary Bkr Backup Fuse PHP1D-F02D Pressurizer Heaters 38, 67, and 68 Primary Bkr Backup Fuse PHP1D-F02E Pressurizer Heaters 43, 73, and 74 Primary Bkr Backup Fuse
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| : 4. 250 VDC Reactor Building Deadlight Panelboard 1DLD-2 Lighting Panelboard No. 1LR1, 1LR2, Primary Bkr 1LR3, 1LR4 Backup Fuse 1DLD-3 Lighting Panelboard No. 1LR13, Primary Bkr 1LR14 Backup Fuse 1DLD-4 Lighting Panelboard No. 1LR5, 1LR6 Primary Bkr Backup Fuse 1DLD-5 Lighting Panelboard No. 1LR10, Primary Bkr 1LR11 Backup Fuse 1DLD-10 Lighting Panelboard No. 1LR8 Primary Bkr Backup Fuse
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| : 5. 120 VAC Panelboards 1ELB-5 Emergency AC Lighting Primary Bkr Backup Fuse 1ELB-7 Emergency AC Lighting Primary Bkr Backup Fuse 1ELB-13 Emergency AC Lighting Primary Bkr Catawba Units 1 and 2 16.8-1-23 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Backup Fuse 1ELB-15 Emergency AC Lighting Primary Bkr Backup Fuse 1ELB-17 Emergency AC Lighting Primary Bkr Backup Fuse 1KPM-1 NC Pump Motor 1A Space Heater Primary Bkr Backup Fuse 1KPM-2 NC Pump Motor 1C Space Heater Primary Bkr Backup Fuse 1KPM-7-1 Lower Cont Ventilation Unit 1A Fan Primary Bkr Motor Space Heater Backup Fuse 1KPM-8-1 Lower Cont Ventilation Unit 1C Fan Primary Bkr Motor Space Heater Backup Fuse 1KPM-24 Control Rod Drive Ventilation Fan Primary Bkr Motor 1A, 1B, 1C, 1D Space Heaters Backup Fuse 1KPM-24-10 Control Rod Drive Ventilation Fan Primary Fuse Motor 1A Space Heaters Backup Fuse 1KPM-24-11 Control Rod Drive Ventilation Fan Primary Fuse Motor 1B Space Heaters Backup Fuse 1KPM-24-12 Control Rod Drive Ventilation Fan Primary Fuse Motor 1C Space Heaters Backup Fuse 1KPM-24-13 Control Rod Drive Ventilation Fan Primary Fuse Motor 1D Space Heaters Backup Fuse Catawba Units 1 and 2 16.8-1-24 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 1KPM-33 NI Temperature Transmitters Primary Bkr 1NITT5800, 1NITT5810, 1NITT5820, Backup Fuse 1NITT5830 1KPM-33-04 NI Temperature Transmitter Primary Fuse 1NITT5800 1KPM-33-05 NI Temperature Transmitter Primary Fuse 1NITT5810 1KPM-33-06 NI Temperature Transmitter Primary Fuse 1NITT5820 1KPM-33-07 NI Temperature Transmitter Primary Fuse 1NITT5830 1KPN-1 NC Pump Motor 1B Space Heater Primary Bkr Backup Fuse 1KPN-2 NC Pump Motor 1D Space Heater Primary Bkr Backup Fuse 1KPN-7-1 Lower Cont Ventilation Unit 1B Fan Primary Bkr Motor Space Heater Backup Fuse 1KPN-08 Lower Cont Ventilation Unit 1D Fan Primary Bkr Motor Space Heater, NC Pump Seal Backup Fuse Standpipe Vent and Drain Vlvs 1NV105, 1NV106, 1NV110, 1NV111, 1NV115, 1NV116, 1NV120, 1NV121 1KPN-08-01 Lower Cont Ventilation Unit 1D Fan Primary Fuse Motor Space Heater Backup Fuse 1KPN-08-02 NC Pump 1A Standpipe Drain and Primary Fuse Overflow Vlvs 1NV105 and 1NV106 Backup Fuse 1KPN-08-03 NC Pump 1B Standpipe Drain and Primary Fuse Overflow Vlvs 1NV110 and 1NV111 Backup Fuse Catawba Units 1 and 2 16.8-1-25 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-1 Unit 1 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 1KPN-08-04 NC Pump 1C Standpipe Drain and Primary Fuse Overflow Vlvs 1NV115 and 1NV116 Backup Fuse 1KPN-08-05 NC Pump 1D Standpipe Drain and Primary Fuse Overflow Vlvs 1NV120 and 1NV121 Backup Fuse 1KPN-11 Misc Control Power for 1ATC24 Primary Bkr Backup Fuse
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| : 6. DC Welding Circuits 1EQCB0001 Spare Primary Bkr - AA Backup Bkr - AB 1EQCB0002 Spare Primary Bkr - AA Backup Bkr - AB Catawba Units 1 and 2 16.8-1-26 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED
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| : 1. 6900 VAC Swgr Primary Bkr RCP2A Reactor Coolant Pump 2A Backup Bkr 2TA-3 Primary Bkr RCP2B Reactor Coolant Pump 2B Backup Bkr 2TB-3 Primary Bkr RCP2C Reactor Coolant Pump 2C Backup Bkr 2TC-3 Primary Bkr RCP2D Reactor Coolant Pump 2D Backup Bkr 2TD-3
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| : 2. 600 VAC MCC 2EMXC-F01B Accumulator 2C Discharge Isol Vlv Primary Bkr 2NI76A Backup Fuse 2EMXC-F01C Check Vlv Test Header Cont Isol Vlv Primary Bkr 2NI95A Backup Fuse 2EMXC-F02A Train A Alternate Power to ND Letdn Primary Bkr Vlv 2ND1B Backup Fuse 2EMXC-F02B Hot Leg Inj Check Vlv Test Isol Vlv Primary Bkr 2NI153A Backup Fuse 2EMXC-F03A NC Pump 2C Thermal Barrier Outlet Primary Bkr Isol Vlv 2KC345A Backup Fuse 2EMXC-F03B Nitrogen to PRT Cont Isol Inside Vlv Primary Bkr 2NC54A Backup Fuse 2EMXC-F03C Pressurizer Power Operated Relief Primary Bkr Isol Vlv 2NC33A Backup Fuse Catawba Units 1 and 2 16.8-1-27 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2EMXC-F05A NCDT Vent Inside Cont Isol Vlv Primary Bkr 2WL450A Backup Fuse 2EMXC-F05B Cont Sump Pumps Discharge Inside Primary Bkr Cont Isol Vlv 2WL825A Backup Fuse 2EMXC-F05C Ventilation Unit Cond Drain Tnk Primary Bkr Outside Cont Isol Vlv 2WL867A Backup Fuse 2EMXC-F06A NCDT Pumps Discharge Inside Cont Primary Bkr Isol Vlv 2WL805A Backup Fuse 2EMXC-F07B Cont Hydrogen Purge Outlet Cont Primary Bkr Isol Vlv 2VY17A Backup Fuse 2EMXD-F01A ND Pump 2A Suction from NC Loop Primary Bkr B Vlv 2ND1B Backup Fuse 2EMXD-F01B Accumulator 2B Discharge Isol Vlv Primary Bkr 2NI65B Backup Fuse 2EMXD-F01C NI Pump A to Hot Leg Check Vlv Primary Bkr Test Isol Vlv 2NI122B Backup Fuse 2EMXD-F02A ND Pump 2B Suction from NC Loop Primary Bkr C Vlv 2ND36B Backup Fuse 2EMXD-F02B ND to Hot Legs Chk 2NI125, 2NI129 Primary Bkr Test Isol Vlv 2NI154B Backup Fuse 2EMXD-F02C Pressurizer Power Operated Relief Primary Bkr Isol Vlv 2NC31B Backup Fuse Catawba Units 1 and 2 16.8-1-28 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2EMXD-F05A Pressurizer Power Operated Relief Primary Bkr Isol Vlv 2NC35B Backup Fuse 2EMXD-F05B Rx Bldg Drain Hdr Inside Cont Isol Primary Bkr Vlv 2KC429B Backup Fuse 2EMXD-F05C NCDT Hx Clng Water Return Inside Primary Bkr Isol Vlv 2KC332B Backup Fuse 2EMXD-F06A NC Pump 2B Thermal Barrier Outlet Primary Bkr Isol Vlv 2KC364B Backup Fuse 2EMXD-F06B NC Pumps Return Hdr Inside Cont Primary Bkr Isol Vlv 2KC424B Backup Fuse 2EMXK-F01C Backup Nitrogen to PORV 2NC34A Primary Bkr from Accum Tnk 2A Vlv 2NI438A Backup Fuse 2EMXK-F02A NC Pump 2A Thermal Barrier Outlet Primary Bkr Isol Vlv 2KC394A Backup Fuse 2EMXK-F02B Lower Cont Ventilation Units Return Primary Bkr Cont Isol Vlv 2RN484A Backup Fuse 2EMXK-F02C NV Supply to Pressurizer Vlv Primary Bkr 2NV037A Backup Fuse 2EMXK-F03A S/G C Blowdown Line Sample Inside Primary Bkr Cont Isol Vlv 2NM210A Backup Fuse 2EMXK-F04A S/G A Upper Shell Sample Inside Primary Bkr Cont Isol Vlv 2NM187A Backup Fuse Catawba Units 1 and 2 16.8-1-29 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2EMXK-F04B S/G A Blowdown Line Sample Inside Primary Bkr Cont Isol Vlv 2NM190A Backup Fuse 2EMXK-F04C S/G C Upper Shell Sample Inside Primary Bkr Cont Isol Vlv 2NM207A Backup Fuse 2EMXK-F06A Hydrogen Skimmer Fan 2A Inlet Vlv Primary Bkr 2VX1A Backup Fuse 2EMXK-F07C Electric Hydrogen Recombiner Power Primary Bkr Supply Panel 2A Backup Fuse 2EMXK-F09A Accum 2A Discharge Isol Vlv 2NI54A Primary Bkr Backup Fuse 2EMXK-F09C NC Pump Oil Fill Header Cont Isol Primary Bkr Vlv 2NC196A Backup Fuse 2EMXK-F10A Cont Air Return Damper 2ARF-D-2 Primary Bkr Backup Fuse 2EMXK-F10B VQ Fans Suction from Cont Isol Vlv Primary Bkr 2VQ2A Backup Fuse 2EMXK-F10C Cont Air Addition Cont Isol Vlv Primary Bkr 2VQ16A Backup Fuse 2EMXK-F11A Cont Air Return Fan Motor 2A Primary Bkr Backup Fuse 2EMXK-F11B Hydrogen Skimmer Fan Motor 2A Primary Bkr Backup Fuse Catawba Units 1 and 2 16.8-1-30 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2EMXL-F01B Trn B Alternate Power to ND Letdn Primary Bkr Vlv 2ND37A Backup Fuse 2EMXL-F01C NI Accum D Sample Line Inside Cont Primary Bkr Isol Vlv 2NM81B Backup Fuse 2EMXL-F02A NC Pump 2D Thermal Barrier Outlet Primary Bkr Isol Vlv 2KC413B Backup Fuse 2EMXL-F02B Air Handling Units Glycol Return Primary Bkr Cont Isol Vlv 2NF233B Backup Fuse 2EMXL-F02C NI Accum C Sample Line Inside Cont Primary Bkr Isol Vlv 2NM78B Backup Fuse 2EMXL-F03A S/G D Blowdown Sample Line Inside Primary Bkr Cont Isol Vlv 2NM220B Backup Fuse 2EMXL-F03B NI Accum A Sample Line Inside Cont Primary Bkr Isol Vlv 2NM72B Backup Fuse 2EMXL-F03C NI Accum B Sample Line Inside Cont Primary Bkr Isol Vlv 2NM75B Backup Fuse 2EMXL-F04A S/G B Upper Shell Sample Inside Primary Bkr Cont Isol Vlv 2NM197B Backup Fuse 2EMXL-F04B S/G B Blowdown Sample Line Inside Primary Bkr Cont Isol Vlv 2NM200B Backup Fuse 2EMXL-F04C S/G D Upper Shell Sample Inside Primary Bkr Cont Isol Vlv 2NM217B Backup Fuse Catawba Units 1 and 2 16.8-1-31 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2EMXL-F06A Hydrogen Skimmer Fan 2B Inlet Vlv Primary Bkr 2VX2B Backup Fuse 2EMXL-F06B Backup Nitrogen to PORV 2NC32B Primary Bkr from Accum Tnk 2B Vlv 2NI439B Backup Fuse 2EMXL-F07C Electric Hydrogen Recombiner Power Primary Bkr Supply Panel 2B Backup Fuse 2EMXL-F09A Accum 2D Discharge Isol Vlv 2NI88B Primary Bkr Backup Fuse 2EMXL-F10A Cont Air Return Damper 2ARF-D-4 Primary Bkr Backup Fuse 2EMXL-F10B Reactor Vessel Head Vent Vlv Primary Bkr 2NC251B Backup Fuse 2EMXL-F10C Reactor Vessel Head Vent Vlv Primary Bkr 2NC252B Backup Fuse 2EMXL-F11A Cont Air Return Fan Motor 2B Primary Bkr Backup Fuse 2EMXL-F11B Hydrogen Skimmer Fan Motor 2B Primary Bkr Backup Fuse 2EMXS-F01B NC Pumps Seal Return Inside Cont Primary Bkr Isol Vlv 2NV89A Backup Fuse 2EMXS-F02A ND Pump 2B Suction from NC Loop Primary Bkr C Vlv 2ND37A Backup Fuse Catawba Units 1 and 2 16.8-1-32 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2EMXS-F02B Reactor Vessel Head Vent Vlv Primary Bkr 2NC250A Backup Fuse 2EMXS-F03D ND Pump 2A Suction from NC Loop Primary Bkr B Vlv 2ND2A Backup Fuse 2EMXS-F03E Reactor Vessel Head Vent Vlv Primary Bkr 2NC253A Backup Fuse 2EMXS-F04B S/G D Blowdown Inside Cont Isol Vlv Primary Bkr 2BB8A Backup Fuse 2EMXS-F04C S/G B Blowdown Inside Cont Isol Vlv Primary Bkr 2BB19A Backup Fuse 2EMXS-F05A S/G A Blowdown Inside Cont Isol Vlv Primary Bkr 2BB56A Backup Fuse 2EMXS-F05B S/G C Blowdown Inside Cont Isol Vlv Primary Bkr 2BB60A Backup Fuse 2EMXS-F05C Pressurizer Liquid Sample Line Primary Bkr Inside Cont Isol Vlv 2NM3A Backup Fuse 2EMXS-F06A Pressurizer Steam Sample Line Primary Bkr Inside Cont Isol Vlv 2NM6A Backup Fuse 2EMXS-F06B NC Hot Leg A Sample Line Inside Primary Bkr Cont Isol Vlv 2NM22A Backup Fuse 2EMXS-F06C NC Hot Leg C Sample Line Inside Primary Bkr Cont Isol Vlv 2NM25A Backup Fuse Catawba Units 1 and 2 16.8-1-33 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2MXM-F01A Reactor Coolant Pump Motor Drain Primary Bkr Tnk Pump Motor Backup Fuse 2MXM-F02A NC Pump 2B Oil Lift Pump Motor 1 Primary Bkr Backup Fuse 2MXM-F02B NC Pump 2C Oil Lift Pump Motor 1 Primary Bkr Backup Fuse 2MXM-F03A Ice Condenser Power Transformer Primary Bkr ICT2A Backup Fuse 2MXM-F03B Ice Condenser Air Handling Unit 2B6 Primary Bkr Fan Motor A & B Backup Fuse 2MXM-F03C Ice Condenser Equipment Access Primary Bkr Door Hoist Motor 2A Backup Fuse 2MXM-F04D Lighting Transformer 2LR10 Primary Bkr Backup Fuse 2MXM-F04E Lighting Transformer 2LR13 Primary Bkr Backup Fuse 2MXM-F05A 175 Ton Polar Crane and 25 Ton Aux Primary Bkr Crane No. R014 and R016 Backup Fuse 2MXM-F05C Upper Containment Welding Feeder Primary Bkr Backup Fuse 2MXM-F06A Ice Condenser Air Handling Unit 2A7 Primary Bkr Fan Motor A & B Backup Fuse Catawba Units 1 and 2 16.8-1-34 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2MXM-F06B Ice Condenser Air Handling Unit 2B8 Primary Bkr Fan Motor A & B Backup Fuse 2MXM-F06C Ice Condenser Air Handling Unit 2A9 Primary Bkr Fan Motor A & B Backup Fuse 2MXM-F06D Ice Condenser Air Handling Unit Primary Bkr 2B10 Fan Motor A & B Backup Fuse 2MXM-F07B Ice Condenser Air Handling Unit Primary Bkr 2A13 Fan Motor A & B Backup Fuse 2MXM-F07C Ice Condenser Air Handling Unit Primary Bkr 2B14 Fan Motor A & B Backup Fuse 2MXM-F08D Ice Condenser Refrigeration Floor Primary Bkr Cool Defrost Heater 2A Backup Fuse 2MXM-F09A Ice Condenser Air Handling Unit 2A1 Primary Bkr Fan Motor A & B Backup Fuse 2MXM-F09B Ice Condenser Air Handling Unit 2B2 Primary Bkr Fan Motor A & B Backup Fuse 2MXM-F09C Ice Condenser Air Handling Unit 2A3 Primary Bkr Fan Motor A & B Backup Fuse 2MXM-F09D Ice Condenser Air Handling Unit 2B4 Primary Bkr Fan Motor A & B Backup Fuse 2MXM-F10A Cont Floor and Equipment Sump Primary Bkr Pump Motor 2A1 Backup Fuse Catawba Units 1 and 2 16.8-1-35 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2MXM-F10B Cont Floor and Equipment Sump Primary Bkr Pump Motor 2B1 Backup Fuse 2MXN-F01F Stud Tensioner Hoist 2B Primary Bkr Backup Fuse 2MXN-F02A NC Pump 2B Oil Lift Pump Motor 2 Primary Bkr Backup Fuse 2MXN-F02B NC Pump 2C Oil Lift Pump Motor 2 Primary Bkr Backup Fuse 2MXN-F02E Stud Tensioner Hoist 2C Primary Bkr Backup Fuse 2MXN-F03A Ice Condenser Power Transformer Primary Bkr ICT2B Backup Fuse 2MXN-F03B Ice Condenser Bridge Crane 2 Crane Primary Bkr No. R012 Backup Fuse 2MXN-F03E Stud Tensioner Hoist 2A Primary Bkr Backup Fuse 2MXN-F04D Lighting Transformer 2LR5 Primary Bkr Backup Fuse 2MXN-F04E Lighting Transformer 2LR6 Primary Bkr Backup Fuse 2MXN-F05A Ice Condenser Refrigeration Floor Primary Bkr Cool Defrost Heater 2B Backup Fuse Catawba Units 1 and 2 16.8-1-36 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2MXN-F05B Ice Condenser Refrigeration Floor Primary Bkr Cool Pump Motor 2B Backup Fuse 2MXN-F05C Ice Condenser Equipment Access Primary Bkr Door Hoist Motor 2B Backup Fuse 2MXN-F06A Ice Condenser Air Handling Unit 2B1 Primary Bkr Fan Motor A & B Backup Fuse 2MXN-F06B Ice Condenser Air Handling Unit 2A2 Primary Bkr Fan Motor A & B Backup Fuse 2MXN-F06C Ice Condenser Air Handling Unit 2B3 Primary Bkr Fan Motor A & B Backup Fuse 2MXN-F06D Ice Condenser Air Handling Unit 2A4 Primary Bkr Fan Motor A & B Backup Fuse 2MXN-F07B Ice Condenser Air Handling Unit 2B5 Primary Bkr Fan Motor A & B Backup Fuse 2MXN-F07C Ice Condenser Air Handling Unit 2A6 Primary Bkr Fan Motor A & B Backup Fuse 2MXN-F08A Ice Condenser Air Handling Unit 2B7 Primary Bkr Fan Motor A & B Backup Fuse 2MXN-F08B Ice Condenser Air Handling Unit 2A8 Primary Bkr Fan Motor A & B Backup Fuse 2MXN-F08C Ice Condenser Air Handling Unit 2B9 Primary Bkr Fan Motor A & B Backup Fuse Catawba Units 1 and 2 16.8-1-37 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2MXN-F08D Ice Condenser Air Handling Unit Primary Bkr 2A10 Fan Motor A & B Backup Fuse 2MXN-F09A Ice Condenser Air Handling Unit Primary Bkr 2B11 Fan Motor A & B Backup Fuse 2MXN-F09B Ice Condenser Air Handling Unit Primary Bkr 2A12 Fan Motor A & B Backup Fuse 2MXN-F09C Ice Condenser Air Handling Unit Primary Bkr 2B13 Fan Motor A & B Backup Fuse 2MXN-F09D Ice Condenser Air Handling Unit Primary Bkr 2A14 Fan Motor A & B Backup Fuse 2MXN-F10A Cont Floor and Equipment Sump Primary Bkr Pump Motor 2A2 Backup Fuse 2MXN-F10B Cont Floor and Equipment Sump Primary Bkr Pump Motor 2B2 Backup Fuse 2MXN-F10C Incore Instrumentation Sump Pump Primary Bkr Motor 2 Backup Fuse 2MXN-F10D Ice Condenser Air Handling Unit Primary Bkr 2B15 Fan Motor A & B Backup Fuse 2MXO-F01A Upper Cont Air Return Fan Motor 2C Primary Bkr Backup Fuse 2MXO-F02B Control Rod Drive Ventilation Fan Primary Bkr Motor 2A Backup Fuse Catawba Units 1 and 2 16.8-1-38 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2MXO-F03A Lower Cont Ventilation Unit 2C Fan Primary Bkr Motor Backup Fuse 2MXO-F04C Upper Cont Ventilation Unit 2C Fan Primary Bkr Motor Backup Fuse 2MXO-F05C Cont Pipe Tunnel Booster Fan Motor Primary Bkr 2A Backup Fuse 2MXP-F01A Upper Cont Return Air Fan 2B Primary Bkr Backup Fuse 2MXP-F02B Control Rod Drive Ventilation Fan Primary Bkr Motor 2B Backup Fuse 2MXP-F03A Lower Cont Ventilation Unit 2B Fan Primary Bkr Motor Backup Fuse 2MXP-F04D Upper Cont Ventilation Unit 2B Fan Primary Bkr Motor Backup Fuse 2MXP-F05C Cont Pipe Tunnel Booster Fan Motor Primary Bkr 2B Backup Fuse 2MXQ-F01A Upper Cont Return Air Fan Motor 2A Primary Bkr Backup Fuse 2MXQ-F01B Incore Instrument Room Ventilation Primary Bkr Unit 2A Fan Motor Backup Fuse 2MXQ-F02B Control Rod Drive Ventilation Fan Primary Bkr Motor 2C Backup Fuse Catawba Units 1 and 2 16.8-1-39 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2MXQ-F03A Lower Cont Ventilation Unit 2A Fan Primary Bkr Motor Backup Fuse 2MXQ-F04C Upper Cont Ventilation Unit 2A Fan Primary Bkr Motor Backup Fuse 2MXR-F01A Upper Cont Return Air Fan Motor 2D Primary Bkr Backup Fuse 2MXR-F01B Incore Instrument Room Ventilation Primary Bkr Unit 2B Fan Motor Backup Fuse 2MXR-F02B Control Rod Drive Ventilation Fan Primary Bkr Motor 2D Backup Fuse 2MXR-F03A Lower Cont Ventilation Unit 2D Fan Primary Bkr Motor Backup Fuse 2MXR-F04C Upper Cont Ventilation Unit 2D Fan Primary Bkr Motor Backup Fuse 2MXY-F02A NC Pump 2A Oil Lift Pump Motor 1 Primary Bkr Backup Fuse 2MXY-F02B NC Pump 2D Oil Lift Pump Motor 1 Primary Bkr Backup Fuse 2MXY-F02C Rx Bldg Lower Cont Welding Primary Bkr Machine Receptacle 2RCPL0185 Backup Fuse 2MXY-F02D Upper Cont Rx Bldg Welding Primary Bkr Receptacle 2RCPL0193 Backup Fuse Catawba Units 1 and 2 16.8-1-40 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2MXY-F03A Reactor Coolant Drain Tnk Pump Primary Bkr Motor 2A Backup Fuse 2MXY-F03D Ice Condenser Refrigeration Floor Primary Bkr Cool Pump Motor 2A Backup Fuse 2MXY-F05A Lighting Transformer 2LR8 Primary Bkr Backup Fuse 2MXY-F05B Lighting Transformer 2LR11 Primary Bkr Backup Fuse 2MXY-F05C Lighting Transformer 2LR14 Primary Bkr Backup Fuse 2MXY-F06A Ice Condenser Air Handling Unit 2A5 Primary Bkr Fan Motor A & B Backup Fuse 2MXY-F06B Ice Condenser Air Handling Unit Primary Bkr 2A11 Fan Motor A & B Backup Fuse 2MXY-F06C Ice Condenser Air Handling Unit Primary Bkr 2B12 Fan Motor A & B Backup Fuse 2MXY-F06D Ice Condenser Air Handling Unit Primary Bkr 2A15 Fan Motor A & B Backup Fuse 2MXY-F07C Rx Bldg Receptacles 2RCPL0186 Primary Bkr and 2RCPL0187 Backup Fuse 2MXY-F08A Incore Drive Assembly Motor 2A Primary Bkr Backup Fuse 2MXY-F08B Incore Drive Assembly Motor 2C Catawba Units 1 and 2 16.8-1-41 Revision 8
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| | |
| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Primary Bkr Backup Fuse 2MXY-F08C Incore Drive Assembly Motor 2E Primary Bkr Backup Fuse 2MXY-F08D Lower Cont Auxiliary Charcoal Filter Primary Bkr Unit Fan Motor 2A Backup Fuse 2MXZ-F02A NC Pump 2A Oil Lift Pump Motor 2 Primary Bkr Backup Fuse 2MXZ-F02B NC Pump 2D Oil Lift Pump Motor 2 Primary Bkr Backup Fuse 2MXZ-F03A Reactor Coolant Drain Tnk Pump Primary Bkr Motor 2B Backup Fuse 2MXZ-F04B Lighting Transformer 2LR1 Primary Bkr Backup Fuse 2MXZ-F04C Lighting Transformer 2LR2 Primary Bkr Backup Fuse 2MXZ-F04D Lighting Transformer 2LR3 Primary Bkr Backup Fuse 2MXZ-F05A Reactor Coolant Pump Jib Hoist No.
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| Primary Bkr R023 through R026 Backup Fuse 2MXZ-F05C Lower Cont Auxiliary Charcoal Filter Primary Bkr Unit Fan Motor 2B Backup Fuse 2MXZ-F06A Incore Drive Assembly Motor 2B Primary Bkr Catawba Units 1 and 2 16.8-1-42 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Backup Fuse 2MXZ-F06B Incore Drive Assembly Motor 2D Primary Bkr Backup Fuse 2MXZ-F06C Incore Drive Assembly Motor 2F Primary Bkr Backup Fuse 2MXZ-F06D Lower Cont Rx Bldg Welding Primary Bkr Receptacle 2RCPL0194 Backup Fuse 2MXZ-F07B Lighting Transformer 2LR4 Primary Bkr Backup Fuse 2MXZ-F07C 5 Ton Jib Crane in Cont Crane No.
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| Primary Bkr R006 Backup Fuse 2MXZ-F07D Reactor Cavity Manipulator Crane Primary Bkr No. R008 and R028 Backup Fuse 2MXZ-F08A S/G Drain Pump Motor 2 Primary Bkr Backup Fuse 2MXZ-F08C 15 Ton Equipment Access Hatch Primary Bkr Hoist Crane No. R010 Backup Fuse 2MXZ-F08D Control Rod Drive 2 Ton Jib Hoist Primary Bkr Crane No. R018 Backup Fuse 2MXZ-F08E Reactor Side Fuel Handling Control Primary Bkr Console Backup Fuse SMXG-F06B Standby Makeup Pump Drain Isol Vlv Primary Bkr 2NV876 Backup Fuse Catawba Units 1 and 2 16.8-1-43 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED SMXG-R05B Pressurizer Heaters 28, 55, and 56 Primary Bkr Backup Fuse SMXG-F06C Standby Makeup Pump to Seal Primary Bkr Water Line Isol Vlv 2NV877 Backup Fuse
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| : 3. 600 VAC Pressurizer Heater Power Panels PHP2A-F01A Pressurizer Heaters 1, 2, and 22 Primary Bkr Backup Fuse PHP2A-F01B Pressurizer Heaters 5, 6, and 27 Primary Bkr Backup Fuse PHP2A-F01C Pressurizer Heaters 9, 10, and 32 Primary Bkr Backup Fuse PHP2A-F02C Pressurizer Heaters 11, 12, and 35 Primary Bkr Backup Fuse PHP2A-F02D Pressurizer Heaters 13, 14, and 37 Primary Bkr Backup Fuse PHP2A-F02E Pressurizer Heaters 17, 18, and 42 Primary Bkr Backup Fuse PHP2B-F01B Pressurizer Heaters 26, 53, and 54 Primary Bkr Backup Fuse PHP2B-F01C Pressurizer Heaters 31, 59, and 60 Primary Bkr Backup Fuse PHP2B-F02C Pressurizer Heaters 36, 65, and 66 Catawba Units 1 and 2 16.8-1-44 Revision 8
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| | |
| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Primary Bkr Backup Fuse PHP2B-F02D Pressurizer Heaters 21, 41, and 71 Primary Bkr Backup Fuse PHP2B-F02E Pressurizer Heaters 46, 77, and 78 Primary Bkr Backup Fuse PHP2C-F01A Pressurizer Heaters 7, 8, and 30 Primary Bkr Backup Fuse PHP2C-F01B Pressurizer Heaters 19, 20, and 45 Primary Bkr Backup Fuse PHP2C-F01C Pressurizer Heaters 24, 51, and 52 Primary Bkr Backup Fuse PHP2C-F01D Pressurizer Heaters 29, 57, and 58 Primary Bkr Backup Fuse PHP2C-F02C Pressurizer Heaters 34, 63, and 64 Primary Bkr Backup Fuse PHP2C-F02D Pressurizer Heaters 39, 69, and 70 Primary Bkr Backup Fuse PHP2C-F02E Pressurizer Heaters 44, 74, and 76 Primary Bkr Backup Fuse PHP2D-F01A Pressurizer Heaters 3, 4, and 25 Primary Bkr Backup Fuse PHP2D-F01B Pressurizer Heaters 15, 16, and 40 Primary Bkr Catawba Units 1 and 2 16.8-1-45 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Backup Fuse PHP2D-F01C Pressurizer Heaters 23, 49, and 50 Primary Bkr Backup Fuse PHP2D-F02C Pressurizer Heaters 33, 61, and 62 Primary Bkr Backup Fuse PHP2D-F02D Pressurizer Heaters 38, 67, and 68 Primary Bkr Backup Fuse PHP2D-F02E Spare Primary Bkr Backup Fuse
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| : 4. 250 VDC Reactor Building Deadlight Panelboard 2DLD-2 Lighting Panelboard No. 2LR1, 2LR2, Primary Bkr 2LR3, 2LR4 Backup Fuse 2DLD-3 Lighting Panelboard No. 2LR13, Primary Bkr 2LR14 Backup Fuse 2DLD-4 Lighting Panelboard No. 2LR5, 2LR6 Primary Bkr Backup Fuse 2DLD-5 Lighting Panelboard No. 2LR10, Primary Bkr 2LR11 Backup Fuse 2DLD-10 Lighting Panelboard No. 2LR8 Primary Bkr Backup Fuse
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| : 5. 120 VAC Panelboards 2ELB-5 Emergency AC Lighting Primary Bkr Catawba Units 1 and 2 16.8-1-46 Revision 8
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| | |
| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Backup Fuse 2ELB-7 Emergency AC Lighting Primary Bkr Backup Fuse 2ELB-13 Emergency AC Lighting Primary Bkr Backup Fuse 2ELB-15 Emergency AC Lighting Primary Bkr Backup Fuse 2ELB-17 Emergency AC Lighting Primary Bkr Backup Fuse 2KPM-1 NC Pump Motor 2A Space Heater Primary Bkr Backup Fuse 2KPM-2 NC Pump Motor 2C Space Heater Primary Bkr Backup Fuse 2KPM-7-1 Lower Cont Ventilation Unit 2A Fan Primary Bkr Motor Space Heater Backup Fuse 2KPM-8-1 Lower Cont Ventilation Unit 2C Fan Primary Bkr Motor Space Heater Backup Fuse 2KPM-24 Control Rod Drive Ventilation Fan Primary Bkr Motor 2A, 2B, 2C, 2D Space Heaters Backup Fuse 2KPM-24-10 Control Rod Drive Ventilation Fan Primary Fuse Motor 2A Space Heaters Backup Fuse 2KPM-24-11 Control Rod Drive Ventilation Fan Primary Fuse Motor 2B Space Heaters Backup Fuse Catawba Units 1 and 2 16.8-1-47 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED 2KPM-24-12 Control Rod Drive Ventilation Fan Primary Fuse Motor 2C Space Heaters Backup Fuse 2KPM-24-13 Control Rod Drive Ventilation Fan Primary Fuse Motor 2D Space Heaters Backup Fuse 2KPM-33 NI Temperature Transmitters Primary Bkr 2NITT5800, 2NITT5810, 2NITT5820, Backup Fuse 2NITT5830 2KPM-33-06 NI Temperature Transmitter Primary Fuse 2NITT5800 2KPM-33-07 NI Temperature Transmitter Primary Fuse 2NITT5810 2KPM-33-08 NI Temperature Transmitter Primary Fuse 2NITT5820 2KPM-33-09 NI Temperature Transmitter Primary Fuse 2NITT5830 2KPN-1 NC Pump Motor 2B Space Heater Primary Bkr Backup Fuse 2KPN-2 NC Pump Motor 2D Space Heater Primary Bkr Backup Fuse 2KPN-7-1 Lower Cont Ventilation Unit 2B Fan Primary Bkr Motor Space Heater Backup Fuse 2KPN-08 Lower Cont Ventilation Unit 2D Fan Primary Bkr Motor Space Heater, NC Pump Seal Backup Fuse Standpipe Vent and Drain Vlvs 2NV105, 2NV106, 2NV110, 2NV111, 2NV115, 2NV116, 2NV120, 2NV121 2KPN-08-01 Lower Cont Ventilation Unit 2D Fan Primary Fuse Motor Space Heater Catawba Units 1 and 2 16.8-1-48 Revision 8
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| CPCOPDs 16.8-1 Table 16.8-1-2 Unit 2 CPCOPDs DEVICE NUMBER AND LOCATION SYSTEM POWERED Backup Fuse 2KPN-08-02 NC Pump 2A Standpipe Drain and Primary Fuse Overflow Vlvs 2NV105 and 2NV106 Backup Fuse 2KPN-08-03 NC Pump 2B Standpipe Drain and Primary Fuse Overflow Vlvs 2NV110 and 2NV111 Backup Fuse 2KPN-08-04 NC Pump 2C Standpipe Drain and Primary Fuse Overflow Vlvs 2NV115 and 2NV116 Backup Fuse 2KPN-08-05 NC Pump 2D Standpipe Drain and Primary Fuse Overflow Vlvs 2NV120 and 2NV121 Backup Fuse 2KPN-11 Misc Control Power for 2ATC24 Primary Bkr Backup Fuse
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| : 6. DC Welding Circuits 2EQCB0001 Spare Primary Bkr - AA Backup Bkr - AB 2EQCB0002 Spare Primary Bkr - AA Backup Bkr - AB Catawba Units 1 and 2 16.8-1-49 Revision 8
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| 230 kV Switchyard 125 VDC Power System 16.8-3 16.8 ELECTRICAL POWER SYSTEMS 16.8-3 230 kV Switchyard 125 VDC Power System COMMITMENT With the switchyard in service, providing a power exchange between the site and the transmission grid, the 230 kV Switchyard 125 VDC Power System (EBH) shall be available, with a minimum of one battery (SYB-1 or SYB-2) and one charger (SYBC-1, SYBC-S, or SYBC-2) aligned to each distribution bus.
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| APPLICABILITY: At all times.
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| REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. COMMITMENT A.1 Restore normal In accordance with alignment not met. COMMITMENT alignment. the Electronic Risk Assessment Tool BASES The effective implementation of the Maintenance Rule, 10 CFR 50.65, requires the continuous assessment of systems determined to be risk significant in the protection against core damage or radiation release.
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| It has been determined through probabilistic risk assessment (PRA) numerical methods that portions of the switchyard systems are risk significant from the standpoint of being able to recover from the Loss of Offsite Power events. This SLC serves two purposes. It defines the risk significant portion of the relaying and power control system of the switchyard through acceptable EBH system configuration alignments. These alignments provide an adequate, uninterruptable power source for relaying, control, and associated equipment requirements for normal switchyard operations. It also provides a method of tracking the relaying and power control system for the purposes of supporting 10 CFR 50.65.
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| Catawba Units 1 and 2 16.8-3-1 Revision 3
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| 230 kV Switchyard 125 VDC Power System 16.8-3 REFERENCES 1. Deleted.
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| : 2. Deleted.
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| : 3. Deleted.
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| : 4. 10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.
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| : 5. SAAG File: 160 Severe Accident Analysis Report, CNS Probability Risk Assessment (PRA) Risk Significant SSCs for the Maintenance Rule.
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| : 6. UFSAR Table 18-1.
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| : 7. UFSAR Section 18.3.1.
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| Catawba Units 1 and 2 16.8-3-2 Revision 3
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| CRAVS - Intake Alarms 16.9-22 16.9 AUXILIARY SYSTEMS 16.9-22 Control Room Area Ventilation System (CRAVS) - Intake Alarms COMMITMENT ------------------------------------------NOTE----------------------------------------
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| Applicable to the CRAVS smoke alarms only. The chlorine detection alarm is addressed in SLC 16.6-4, Chlorine Detectors and Associated Circuitry and the CRAVS radiation detection alarm is addressed in SLC 16.7-10, Radiation Monitoring for Plant Operations.
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| The CRAVS Intake Alarms shall be FUNCTIONAL.
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| APPLICABILITY: All MODES.
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| REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. CRAVS smoke intake A.1 Establish a fire watch 1 hour alarm non-functional for patrol once per hour at the one or both control room affected control room intakes. intake(s).
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| TESTING REQUIREMENTS TEST FREQUENCY TR 16.9-22-1 Verify that on a Smoke Density - High test signal, an 18 months alarm is received in the control room.
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| Catawba Units 1 and 2 16.9-22-1 Revision 3
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| CRAVS - Intake Alarms 16.9-22 BASES The CRAVS Intake Alarms provide operator information relative to smoke, chlorine and radiation concentrations at each control room intake. Operators use this information to align the CRAVS to ensure that the control room will remain habitable for operations personnel during and following accident conditions.
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| The REMEDIAL ACTION for non-functional smoke intake alarms is consistent with that for non-functional fire detection instrumentation. The fire detection instrumentation requirements are discussed in SLC 16.9-6, Fire Detection Instrumentation.
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| REFERENCES 1. Letter from NRC to Gary R. Peterson, Duke, Issuance of Improved Technical Specifications Amendments for Catawba, September 30, 1998.
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| : 2. SLC 16.6-4, Chlorine Detectors and Associated Circuitry
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| : 3. SLC 16.7-10, Radiation Monitoring for Plant Operations Catawba Units 1 and 2 16.9-22-2 Revision 3
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| Auxiliary Feedwater Turbine Driven Pump Pit (WL) Sump Pumps 16.10-5 16.10 STEAM AND POWER CONVERSION SYSTEM 16.10-5 Auxiliary Feedwater Turbine Driven Pump Pit (WL) Sump Pumps COMMITMENT The following Liquid Radwaste (WL) sump pumps in the Turbine Driven Auxiliary Feedwater (CA) pump pit shall be FUNCTIONAL on the associated Unit to support the associated Turbine Driven CA pump operability.
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| x Turbine Driven CA Pump A sump pump x Turbine Driven CA Pump B sump pump APPLICABILITY: MODES 1, 2, and 3 MODE 4 when steam generator relied upon for heat removal.
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| REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One of the two required A.1 Apply TS 3.7.5 action B for Immediately CAPT Sump Pumps is the associated CAPT.
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| not functional.
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| B. One of the two required B.1 Apply TS 3.7.5 action C for 4 hours following CAPT Sump Pumps is two AFW trains inoperable. concurrent non not functional. functionality of a CAPT sump pump AND and inoperability of the opposite train The opposite train EDG EDG (per TS 3.8.1 on the affected Unit is required action B.3) inoperable.
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| C. Both required CAPT C.1 Declare the CAPT Immediately Sump Pumps are not inoperable per the functional. applicable condition of LCO 3.7.5.
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| D. A train CAPT sump D.1 Apply SLC 16.7-9 Immediately pump not functional. Condition A.
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| * If a MDCAP is concurrently inoperable per LCO 3.7.5, this condition introduces no further inoperability (e.g. one CAPT sump pump not functional with one of the MDCAP's inoperable does NOT require entry into LCO 3.7.5 Condition C).
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| Catawba Units 1 and 2 16.10-5-1 Revision 2
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| Auxiliary Feedwater Turbine Driven Pump Pit (WL) Sump Pumps 16.10-5 TESTING REQUIREMENTS TEST FREQUENCY TR 16.10-5-1 Verify each sump pumps flow rate is greater than or In Accordance equal to the required flow rate. with the INSERVICE TEST PROGRAM BASES The CAPT Sump Pumps are safety related components with the design basis to prevent flooding of the CAPT sump. Flooding in the CAPT sump could render the CAPT incapable of performing its required safety function. To ensure the CAPT maintains this capability, at least one of the two CAPT sump pumps must be maintained functional.
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| Furthermore, independence must be maintained between the CAPT and the two (2) Motor Driven CA Pumps (MDCAP) such that failure of a single plant component cannot render both a MDCAP and the CAPT Inoperable simultaneously (assuming loss of non-emergency offsite power and a CA autostart). If only one of the two CAPT sump pumps is functional, the failure of a single EDG to start could prevent both the CAPT and MDCAP associated with the failed EDG from performing their required safety functions. The CAPT would be flooded by its lube oil cooler sump input. Therefore, two CAPT sump pumps are required functional to support the operability of the CAPT with respect to Technical Specification 3.7.5.
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| The CAPT provides residual heat removal during an SSF event. The unit related A train CAPT sump pump is powered from EMXS on the respective unit which can be powered from the SSF. Therefore, the A train CAPT sump pump is required to support Standby Shutdown System (SSS) per SLC 16.7-9.
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| TR 16.10-5-1 verifies the CAPT pit sump pumps start on high level and deliver >50 gpm flow in accordance with Reference 3, 4, and 5.
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| Examples:
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| If the CAPT sump pump "A" is not functional, a single failure of "B" DG coincident with a LOOP, would render both the "B" motor-driven CA pump and CAPT sump pump "B" inoperative. Since both CAPT sump pumps are now inoperable, the CAPT will become flooded within hours due to lube oil cooler input and potential input from doghouse flooding due to a feedline break, along with motor-driven CA pump B". Therefore, if either of the CAPT sump pumps is inoperable, Catawba ITS 3.7.5 is not satisfied since single failure criteria cannot be met and thus, the ACTION statement for one CA pump inoperable shall be entered (ACTION B).
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| If a motor-driven CA pump and either of the CAPT sump pumps are non-Catawba Units 1 and 2 16.10-5-2 Revision 2
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| Auxiliary Feedwater Turbine Driven Pump Pit (WL) Sump Pumps 16.10-5 BASES (continued) functional, ACTION B still applies since two independent CA pumps are still considered to be Operable. This is because the additional failure of an emergency diesel generator (DG) need not be considered while operating within the restrictions of the 72 hour ACTION statement.
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| Similarly, if an emergency diesel generator (DG) is inoperable and the CAPT sump pump of the same train is non functional, then the CAPT may be considered Operable for the purpose of satisfying ACTION B.
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| Finally, if a CAPT sump pump is not functional and the opposite DG is inoperable, then ITS 3.7.5 ACTION C applies and the Required Action is to be in Mode 3 in 6 hours. However, Required Actions A.2. and B.3. of ITS 3.8.1 also apply to this situation. Condition A applies when an offsite circuit is Inoperable. Condition B applies when an onsite DG circuit is Inoperable. The CAPT sump pumps must be considered "required redundant features" and per Required Action B.3., the sump pump with the Inoperable DG must be declared non-functional 4 hours from discovery of the DG being Inoperable. Per the Bases Section 3.8.1 (B.3),
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| discovering one required DG Inoperable coincident with one or more inoperable required support or supported features, or both, that are associated with the Operable DG, results in starting the Completion Time for the Required Action. Four hours from the discovery of these events existing concurrently is Acceptable because it minimizes risk while allowing time for restoration before subjecting the unit to transients associated with shutdown. In this Condition, the remaining Operable DG and Operable offsite circuits are adequate to supply the remaining CAPT sump pump. Thus, single failure protection for the required feature's function may have been lost; however, function has not been lost. The 4-hour Completion Time takes into account Operability of the redundant counterpart to the Inoperable required feature, as well as the capacity/capability of the remaining AC sources, a reasonable time for repairs, and the low probability of a OBA occurring during this period.
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| Per ITS 3.8.1 Condition G, the lnoperability of both DGs results in a 2-hour Completion time to return one DG to Operable status, and subsequent entry to ITS 3.0.3. ITS 3.7.5 Condition D for three CA trains in Modes 1, 2 or 3 results in suspension of 3.0.3 and all other LCO required Actions requiring Mode changes. The CAPT sump pumps, while support components for the CAPT, do not render it Inoperable since they can be powered by onsite circuits. Therefore, the suspension of 3.0.3 does not apply if the CAPT is Operable but both DGs are Inoperable.
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| TR 16.10-5-1 verifies the CA Turbine Driven Sump Pumps start on High level and delivers >50 gpm flow in accordance with Reference 1b, 4 and 5. The In-Service Testing also monitors component vibration and forward and reverse flow through check valves in the discharge flowpath.
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| Catawba Units 1 and 2 16.10-5-3 Revision 2
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| | |
| Auxiliary Feedwater Turbine Driven Pump Pit (WL) Sump Pumps 16.10-5 REFERENCES 1. Catawba Updated Final Safety Analysis Report
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| : a. Section 11.2.2.2.4.4, Auxiliary Feedwater Pump Pit Sumps
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| : b. Section 11.2.2.2.5.7, Auxiliary Feedwater Pump Pit Sump Pumps
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| : c. Section 7.6.6, Liquid Radwaste System
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| : d. Section 10.4.9, Auxiliary Feedwater System
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| : 2. CNC-1223.42-00-0089, Evaluation of Doghouse Flood on Motor Driven CA pump Operability.
| |
| : 3. Technical Specifications
| |
| : a. 3.7.5, Auxiliary Feedwater (AFW) System
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| : b. 3.8.1, AC Sources Operating
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| : c. 3.8.9, Distribution Systems Operating
| |
| : 4. CNTC-1565-WL-P016-01, Steam Turbine Driven Auxiliary Feedwater Sump Pumps.
| |
| : 5. CNTC-2565-WL-P006-01, Steam Turbine Driven Auxiliary Feedwater Sump Pumps.
| |
| : 6. CNC-1223.42-00-0080, Determination of CATDP Operating Duration Before Flooding From Normal Sump Inputs Leads to Pump Failure as Result of an ELAP.
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| : 7. CNC-1223.15-00-0022, Orifice Sizing for Doghouse Drains.
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| Catawba Units 1 and 2 16.10-5-4 Revision 2
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| Radioactive Liquid Effluent Monitoring Instrumentation 16.11-2 16.11 RADIOLOGICAL EFFLUENTS CONTROLS 16.11-2 Radioactive Liquid Effluent Monitoring Instrumentation COMMITMENT The Radioactive Liquid Effluent Monitoring Instrumentation channels shown in Table 16.11-2-1 shall be FUNCTIONAL with their Alarm/Trip Setpoints set to ensure that the limits of SLC 16.11-1 are not exceeded.
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| 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).
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| APPLICABILITY: Condition Applicability is as shown in Table 16.11-2-1.
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| REMEDIAL ACTIONS
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| --------------------------------------------------------NOTE-------------------------------------------------------
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| Separate Condition entry is allowed for each Function.
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| Catawba Units 1 and 2 16.11-2-1 Revision 9
| |
| | |
| Radioactive Liquid Effluent Monitoring Instrumentation 16.11-2 CONDITION REQUIRED ACTION COMPLETION TIME A. One or more A.1 Suspend the release of Immediately Radioactive Liquid radioactive liquid effluents Effluent Monitoring monitored by the affected Instrumentation channel(s).
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| channel(s) Alarm/Trip Setpoint less OR conservative than required. A.2 Declare the channel(s) Immediately non-functional.
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| B. One or more B.1 Enter the applicable Immediately Radioactive Liquid Conditions and Required Effluent Monitoring Actions specified in Table Instrumentation 16.11-2-1 for the channel(s) non- channel(s).
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| functional.
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| AND B.2.1 Restore channel to 14 Days (*Note 1)
| |
| FUNCTIONAL status.
| |
| OR B.2.2 Restore channel to 30 Days (*Note 1)
| |
| FUNCTIONAL status.
| |
| *Note 1 - Required Action B.2.1 Applies to Instruments 1.a and 1.c ONLY. (continued)
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| Required Action B.2.2 Applies to the remainder of required Instruments listed in Table 16.11-2-1.
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| Catawba Units 1 and 2 16.11-2-2 Revision 9
| |
| | |
| Radioactive Liquid Effluent Monitoring Instrumentation 16.11-2 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME C. One channel non- C.1.1 Analyze two independent Prior to initiating a functional. samples per Testing release Requirement 16.11-1-1.
| |
| AND C.1.2 Perform independent Prior to initiating a verification of the discharge release line valving.
| |
| AND C.1.3.1Perform independent Prior to initiating a verification of manual release portion of the computer input for release rate calculations performed by computer.
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| OR C.1.3.2Perform independent Prior to initiating a verification of entire release calculations for release rate calculations performed manually.
| |
| OR C.2 Suspend release of Immediately radioactive effluents via this pathway.
| |
| (continued)
| |
| Catawba Units 1 and 2 16.11-2-3 Revision 9
| |
| | |
| Radioactive Liquid Effluent Monitoring Instrumentation 16.11-2 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME D. One flow rate D.1 --------------NOTE-------------
| |
| measurement device Pump performance curves channel non-functional. generated in place may be used to estimate flow.
| |
| Estimate the flow rate of Once per 4 hours the release. during releases E. One channel non- E.1 Perform an analysis of Once per 12 hours functional. grab samples for during releases when radioactivity at a lower limit secondary specific of detection of 10-7 activity is > 0.01 microCurie/ml. microCurie/gm DOSE EQUIVALENT I-131 AND Once per 24 hours during releases when secondary specific activity is < 0.01 microCurie/gm DOSE EQUIVALENT I-131 (continued)
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| Catawba Units 1 and 2 16.11-2-4 Revision 9
| |
| | |
| Radioactive Liquid Effluent Monitoring Instrumentation 16.11-2 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME F. One channel non- F.1 Collect and analyze grab Once per 12 hours functional. samples for principal gamma emitters (listed in Table 16.11-1-1, NOTE 3) at a lower limit of detection of no more than 5x10-7 microCurie/ml.
| |
| G. Required Action and G.1 Explain why the non- In the next scheduled associated Completion functionality was not Radioactive Effluent Time of Condition B not corrected within the Release Report met. specified Completion Time. pursuant to Technical Specification 5.6.3 Catawba Units 1 and 2 16.11-2-5 Revision 9
| |
| | |
| Radioactive Liquid Effluent Monitoring Instrumentation 16.11-2 TESTING REQUIREMENTS
| |
| --------------------------------------------------------NOTE--------------------------------------------------------
| |
| Refer to Table 16.11-2-1 to determine which TRs apply for each Radioactive Liquid Effluent Monitoring Instrumentation channel.
| |
| TEST FREQUENCY TR 16.11-2-1 Perform CHANNEL CHECK. 24 hours TR 16.11-2-2 ---------------------------------NOTE---------------------------------
| |
| The CHANNEL CHECK shall consist of verifying indication of flow.
| |
| Perform CHANNEL CHECK. 24 hours during periods of release TR 16.11-2-3 Perform SOURCE CHECK. Prior to each release TR 16.11-2-4 Perform SOURCE CHECK. 31 days TR 16.11-2-5 Perform COT. 182 days TR 16.11-2-6 ---------------------------------NOTE---------------------------------
| |
| For Instrument 1, the COT shall also demonstrate that automatic isolation of this pathway and control room alarm annunciation (for EMF-57, 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 (continued)
| |
| Catawba Units 1 and 2 16.11-2-6 Revision 9
| |
| | |
| Radioactive Liquid Effluent Monitoring Instrumentation 16.11-2 TESTING REQUIREMENTS (continued)
| |
| TEST FREQUENCY TR 16.11-2-7 ---------------------------------NOTE---------------------------------
| |
| For Instrument 1, 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 Catawba Units 1 and 2 16.11-2-7 Revision 9
| |
| | |
| Radioactive Liquid Effluent Monitoring Instrumentation 16.11-2 Table 16.11-2-1 Radioactive Liquid Effluent Monitoring Instrumentation REQUIRED CONDITIONS APPLICABILITY TESTING CHANNELS REQUIREMENTS
| |
| : 1. Radioactivity Monitors Providing Alarm and Automatic Termination of Release 1.a Waste Liquid Discharge Monitor 1 per station A, B, G At all times TR 16.11-2-1 (EMF Low Range) C (Note 1) TR 16.11-2-3 TR 16.11-2-6 TR 16.11-2-7 1.b Turbine Building Sump Monitor 1 A, B, G At all times TR 16.11-2-1 (EMF-31) E (Note 1) TR 16.11-2-4 TR 16.11-2-6 TR 16.11-2-7 1.c Monitor Tank Building Liquid Discharge Monitor 1 per station A, B, G At all times TR 16.11-2-1 (EMF Low Range) C (Note 1) TR 16.11-2-3 TR 16.11-2-6 TR 16.11-2-7
| |
| : 2. Continuous Composite Samplers and Sampler Flow Monitor 2.a Conventional Waste Water Treatment Line 1 per station B, G At all times TR 16.11-2-2 (no alarm/trip function) E (Note 2) (Note 1) TR 16.11-2-7
| |
| : 3. Flow Rate Measurement Devices 3.a Waste Liquid Effluent Line 1 per station B, G At all times TR 16.11-2-2 (no alarm/trip function) D (Note 1) TR 16.11-2-7 3.b Conventional Waste Water Treatment Line 1 per station B, G At all times TR 16.11-2-2 (no alarm/trip function) D (Note 2) (Note 1) TR 16.11-2-7 3.c Low Pressure Service Water Minimum Flow Interlock 1 per station B, G At all times TR 16.11-2-2 D (Note 1) TR 16.11-2-5 TR 16.11-2-7 3.d Monitor Tank Building Waste Liquid Effluent Line 1 per station B, G At all times TR 16.11-2-2 (no alarm/trip function) D (Note 1) TR 16.11-2-7
| |
| : 4. Radioactivity Monitors Providing Alarm 4.a Service Water Monitor on Containment Spray Heat 1 per heat A, B, G At all times TR 16.11-2-1 Exchanger exchanger F (Note 1) TR 16.11-2-4 (EMF-45 A & B - Low Range) TR 16.11-2-6 TR 16.11-2-7 Note 1: At all times, unless effluent pathway is mechanically isolated such that a release to the environment is not possible.
| |
| Note 2: Condition D entry and associated Required Action not required if any flow indication remains available. Condition E entry and associated Required Action not required if the composite sampler remains available.
| |
| Catawba Units 1 and 2 16.11-2-8 Revision 9
| |
| | |
| Radioactive Liquid Effluent Monitoring Instrumentation 16.11-2 BASES The Radioactive Liquid Effluent Monitoring Instrumentation is provided to monitor and control, as applicable, the releases of radioactive materials in liquid effluents during actual or potential releases of liquid effluents. The Alarm/Trip Setpoints for these instruments shall be calculated and adjusted 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. 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.
| |
| Regarding Note 1 of Table 16.11-2-1, 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.
| |
| Note 2 allows for the continued use of any installed discharge flow indication on loop 0WCLP5110. This note also allows for use of the composite sampler if available. In some instances, the transmitter and associated components may be declared nonfunctional but still provide accurate flow indication or continue to take composite samples as required.
| |
| REFERENCES 1. Catawba Offsite Dose Calculation Manual.
| |
| : 2. 10 CFR Part 20.
| |
| : 3. 10 CFR Part 50, Appendix A.
| |
| Catawba Units 1 and 2 16.11-2-9 Revision 9
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 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 B and K are applicable at all times. All other Conditions are applicable as shown in Table 16.11-7-1.
| |
| REMEDIAL ACTIONS
| |
| --------------------------------------------------------NOTE--------------------------------------------------------
| |
| Separate Condition entry is allowed for each Function.
| |
| Catawba Units 1 and 2 16.11-7-1 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 CONDITION REQUIRED ACTION COMPLETION TIME A. One or more A.1 Suspend the release of Immediately Radioactive Gaseous radioactive gaseous Effluent Monitoring effluents monitored by the Instrumentation affected channel(s).
| |
| channel(s) Alarm/Trip Setpoint less OR conservative than required. A.2 Declare the channel(s) Immediately non-functional.
| |
| B. One or more B.1 Enter the applicable Immediately Radioactive Gaseous Conditions and Required Effluent Monitoring Actions specified in Table Instrumentation 16.11-7-1 for the channel(s) non- channel(s).
| |
| functional.
| |
| AND B.2.1 Restore channel to 14 Days (*Note 1)
| |
| FUNCTIONAL status.
| |
| OR B.2.2 Restore channel to 30 Days (*Note 1)
| |
| FUNCTIONAL status.
| |
| *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.
| |
| Catawba Units 1 and 2 16.11-7-2 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME C. One channel non- C.1 Verify that EMF-36 (Low Prior to initiating a functional. Range) is FUNCTIONAL. release OR C.2.1 Analyze two independent Prior to initiating a samples of the tanks release contents.
| |
| AND C.2.2 Perform independent Prior to initiating a verification of the discharge release line valving.
| |
| AND C.2.3.1Perform independent Prior to initiating a verification of manual release portion of the computer input for release rate calculations performed by computer.
| |
| OR C.2.3.2Perform independent Prior to initiating a verification of entire release calculations for release rate calculations performed manually.
| |
| OR C.3 Suspend release of Immediately radioactive effluents via this pathway.
| |
| (continued)
| |
| Catawba Units 1 and 2 16.11-7-3 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME D. One or more flow rate D.1 Estimate the flow rate of Once per 4 hours measurement device the release. during releases channel(s) non-functional.
| |
| E. One or more Noble Gas ------------------NOTE-------------------
| |
| Activity Monitor IF 0EMF41 is NON-FUNCTIONAL channel(s) non- AND either 1EMF36 OR 2EMF36 functional. is NON-FUNCTIONAL, perform SLC 16.7-10, Required Action G.2 E.1 Obtain grab samples from Once per 12 hours effluent pathway. during releases AND E.2 Perform an analysis of Within 24 hours of grab samples for obtaining the sample radioactivity.
| |
| (continued)
| |
| Catawba Units 1 and 2 16.11-7-4 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME F. Noble Gas Activity F.1 -------------NOTE--------------
| |
| Monitor (EMF Low In order to utilize Required Range) providing Action F.1, the following automatic termination of conditions must be release via the satisfied:
| |
| Containment Purge 1. The affected unit is in Exhaust System (CPES) MODES 5 or 6.
| |
| non-functional. 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 12 hours channel to FUNCTIONAL status.
| |
| G. Required Action and G.1 Suspend PURGING of Immediately associated Completion radioactive effluents via Time of Condition F not this pathway.
| |
| met.
| |
| OR Required Action F.1 not utilized.
| |
| (continued)
| |
| Catawba Units 1 and 2 16.11-7-5 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME H. One or more sampler H.1 Perform sampling with Continuously channel(s) non- auxiliary sampling functional. equipment as required by Table 16.11-6-1.
| |
| I. One Condenser I.1 --------------NOTE-------------
| |
| Evacuation System Applicable to effluent Noble Gas Activity releases via the Condenser Monitor (EMF-33) Steam Air Ejector (ZJ) channel non-functional. System.
| |
| Obtain grab samples from Once per 12 hours effluent pathway. during releases AND I.2 --------------NOTE-------------
| |
| Applicable to effluent releases via the Condenser Steam Air Ejector (ZJ)
| |
| System.
| |
| Perform an analysis of Within 24 hours of grab samples for obtaining the sample radioactivity.
| |
| AND (continued)
| |
| Catawba Units 1 and 2 16.11-7-6 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 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 Once per 12 hours grab samples for during releases when radioactivity at a lower limit secondary specific of detection of 10-7 activity is > 0.01 microCurie/ml. microCurie/gm DOSE EQUIVALENT I-131 AND Once per 24 hours during releases when secondary specific activity is < 0.01 microCurie/gm DOSE EQUIVALENT I-131 J. Noble Gas Activity J.1 Verify that EMF-36 is Prior to initiating a Monitor (EMF Low FUNCTIONAL. release Range) providing automatic termination of OR release via the Containment Air J.2.1 Analyze two independent Prior to initiating a Release and Addition samples of the release System non-functional. containment atmosphere.
| |
| AND (continued)
| |
| Catawba Units 1 and 2 16.11-7-7 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 REMEDIAL ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME J. (continued) J.2.2 Perform independent Prior to initiating a verification of the discharge release line valving.
| |
| AND J.2.3.1 Perform independent Prior to initiating a verification of manual release portion of the computer input for release rate calculations performed by computer.
| |
| OR J.2.3.2 Perform independent Prior to initiating a verification of entire release calculations for release rate calculations performed manually.
| |
| (continued)
| |
| Catawba Units 1 and 2 16.11-7-8 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 REMEDIAL ACTIONS (continued)
| |
| CONDITION REQUIRED ACTION COMPLETION TIME K. Required Action and K.1 Explain why the non- In the next scheduled associated Completion functionality was not Radioactive Effluent Time of Condition B or F corrected within the Release Report not met. specified Completion Time. 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 hours TR 16.11-7-4 Perform CHANNEL CHECK. 24 hours TR 16.11-7-5 Perform CHANNEL CHECK. 7 days (continued)
| |
| Catawba Units 1 and 2 16.11-7-9 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 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)
| |
| Catawba Units 1 and 2 16.11-7-10 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 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 Catawba Units 1 and 2 16.11-7-11 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Table 16.11-7-1 Radioactive Gaseous Effluent Monitoring Instrumentation (page 1 of 2)
| |
| INSTRUMENT REQUIRED CONDITIONS APPLICABLE TESTING CHANNELS MODES REQUIREMENTS
| |
| : 1. Waste Gas Holdup System 1.a Noble Gas Activity Monitor - Providing 1 per station B, K At all times TR 16.11-7-1 Alarm and Automatic Termination of A, C (Note 3) TR 16.11-7-2 Release TR 16.11-7-7 (EMF Low Range) TR 16.11-7-9 1.b Effluent System Flow Rate Measuring 1 per station B, K At all times TR 16.11-7-1 Device D (Note 3) TR 16.11-7-9
| |
| : 2. Condenser Evacuation System Noble 1 B, K At all times TR 16.11-7-3 Gas Activity Monitor A, I (Note 4) TR 16.11-7-6 (EMF-33) (BB-27 is only isolation TR 16.11-7-8 function required) (Note 1) TR 16.11-7-9
| |
| : 3. Vent System 3.a Noble Gas Activity Monitor 1 A, B, E, K At all times TR 16.11-7-4 (EMF Low Range) TR 16.11-7-6 TR 16.11-7-7 TR 16.11-7-9 3.b Deleted.
| |
| 3.c Particulate Sampler 1 B, K At all times TR 16.11-7-4 (EMF-35) A, H (Note 2) TR 16.11-7-6 TR 16.11-7-7 TR 16.11-7-9 3.d Unit Vent Stack Flow Rate Meter 1 B, K At all times TR 16.11-7-4 (no alarm/trip function) D (Note 2) TR 16.11-7-9 3.e Unit Vent Radiation Monitor Flow Meter 1 B, K At all times TR 16.11-7-4 E (Note 2) TR 16.11-7-9
| |
| : 4. Containment Purge System Noble Gas 1 A, F, G, K 5, 6 TR 16.11-7-2 Activity Monitor - Providing Alarm and TR 16.11-7-3 Automatic Termination of Release TR 16.11-7-8 (EMF Low Range) TR 16.11-7-9 (continued)
| |
| Catawba Units 1 and 2 16.11-7-12 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 Table 16.11-7-1 Radioactive Gaseous Effluent Monitoring Instrumentation (page 2 of 2)
| |
| INSTRUMENT REQUIRED CONDITIONS APPLICABLE TESTING CHANNELS MODES REQUIREMENTS
| |
| : 5. Containment Air Release and Addition 1 B, K At all times TR 16.11-7-2 System Noble Gas Activity Monitor - A, J 1, 2, 3, 4, 5, 6 TR 16.11-7-3 Providing Alarm and Automatic TR 16.11-7-7 Termination of Release TR 16.11-7-9 (EMF Low Range)
| |
| : 6. Monitor Tank Building HVAC 6.a Noble Gas Activity Monitor - Providing 1 per station B, K At all times TR 16.11-7-4 Alarm A, E (Note 2) TR 16.11-7-6 (EMF Low Range) TR 16.11-7-7 TR 16.11-7-9 6.b Effluent Flow Rate Measuring Device 1 per station B, K At all times TR 16.11-7-4 D (Note 2) 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.
| |
| Catawba Units 1 and 2 16.11-7-13 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 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.
| |
| Catawba Units 1 and 2 16.11-7-14 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 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.
| |
| Catawba Units 1 and 2 16.11-7-15 Revision 14
| |
| | |
| Radioactive Gaseous Effluent Monitoring Instrumentation 16.11-7 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.
| |
| Catawba Units 1 and 2 16.11-7-16 Revision 14
| |
| | |
| U.S. Nuclear Regulatory Commission RA-23-0042 April 24, 2023 Enclosure 6 Catawba Nuclear Station Notification of Regulatory Commitment Change
| |
| | |
| U.S. Nuclear Regulatory Commission RA-23-0042 April 24, 2023 Commitment Tracking Number: 02343000-03 Existing Commitment:
| |
| In the NRC Safety Evaluation, dated December 29, 1995, NRC Amendment Nos. 140 and 134 for Catawba Nuclear Station, Units 1 and 2:
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| "The licensee has also committed to revise the plant response procedure for earthquakes and natural disasters such that following any earthquake (including one smaller than the operating basis earthquake [OBE]), it will be assumed that none of the four leakage detection systems identified in the technical specifications are operable and to determine the status of EMF38 and EMF39. EMF39 is the containment atmosphere gaseous radioactivity monitoring system. The status of both EMF38 and EMF39 is determined by performing a source check from the control room and verifying the proper operation of the monitors in the auxiliary building. Access from the control room to the monitor skid inside the auxiliary building is located within seismic Category I structures and in a "mild" environment."
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| Revised Commitment:
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| Following any earthquake (including one smaller than the operating basis earthquake [OBE]),
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| the OPERABILITY of the four leakage detection systems identified in the technical specifications will be assessed in accordance with established procedures, as directed by the emergency response procedure for earthquakes. The status of EMF38 is determined by performing a source check from the control room and verifying the proper operation of the monitors in the auxiliary building. Access from the control room to the monitor skid inside the auxiliary building is located within seismic Category I structures and in a "mild" environment.
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| Should it be determined that either EMF38(L) or the other leakage detection systems is not functional, the appropriate steps will be taken; i.e., declare the monitor(s) inoperable and apply the action statement for TS 3.4.15 (RCS Leakage Detection Instrumentation) which may require that the associated unit(s) be taken to Cold Shutdown (Mode 5) if the minimum required Reactor Coolant Leakage Detection Systems are not operable. Cold Shutdown is a mode for which the Reactor Coolant Leakage Detection Systems are not required operable per TS 3.4.15.
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| Basis for Revision:
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| The RCS Leakage Detection Instrumentation is required in Technical Specification 3.4.15. The leakage detection instrumentation satisfies criterion 1 of 10 CFR 36, Installed instrumentation that is used to detect, and indicate in the control room, a significant abnormal degradation of the reactor coolant pressure boundary. The LCO for Technical Specification 3.4.15 requires Containment Floor and Equipment (CFAE) sump level monitors and the lncore Instrument sump high level alarm, the Containment Atmosphere Particulate Radioactivity Monitor (EMF 38) and the Containment Ventilation Unit Condensate Drain Tank (VUCDT) level monitor. None of these monitors are seismically qualified. To address the non-seismic monitors, the NRC issued Amendments 140/134 for Catawba Units 1 and 2 (see above for the original commitment wording related to the monitors).
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| To address the original commitment wording, the currently revision of RP/0/A/5000/007, Natural Disaster and Earthquake (Revision 52), Enclosure 4.4 Step 1.1 instructs Operations to declare all 4 RCS leakage detection systems inoperable following any earthquake felt in the protected area including quakes less than QBE. The step results in an unnecessary entry into TS 3.0.3 until a source check is performed on EMF-38 to establish operability. Reviewing the history of
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| U.S. Nuclear Regulatory Commission RA-23-0042 April 24, 2023 NRC and Duke Letters referenced in Amendments 140/134 for Catawba Units 1 and 2, it is evident that the intent was not to declare equipment INOPERABLE and place the units into TS 3.0.3 until after the determination could be made that either EMF38(L) or EMF39(L) is not functional. CNS license Amendment 234/230 deleted Containment Atmosphere Radioactivity Monitor (1 (2)EMF39L) from TS 3.4.15 and added incore instrument level alarm to LCO 3.a. in September of 2006.
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| The emergency response procedure for earthquakes will be changed to require Technical Specification (TS) 3.4.15, RCS Leakage Detection Instruments OPERABILITY be assessed in accordance with established processes and procedures. Should it be determined that one or more of the TS 3.4.15 instruments is INOPERABLE, the appropriate Conditions and Required Actions of TS 3.4.15 will be applied.
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| AD-OP-ALL-0105, Operability Determination, permits entry into the Operability Determination Process for deficient conditions provided there is a reasonable assurance of operability. In this case the deficient condition is the effect of a seismic event felt within the protected area and its effect on the non-seismically qualified leakage detection instrumentation. In this case EMF 38 is located in a seismically qualified structure and the operability of EMF 38 can be readily assessed by performance of a source check per RP/0/A/5000/007, Natural Disaster and Earthquake. The EMF is robust and located in a category 1 structure such that there is reasonable assurance of operability pending source checks to confirm operability in an earthquake less than OBE.
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| Therefore, this commitment change will revise the wording to immediately perform a source check on EMF 38 to ensure operability of the EMF following a an earthquake felt in the protected area, or is recorded on instrumentation including an earthquake smaller than OBE prior to declaring EMF 38 inoperable. AD-OP-ALL-0105, Operability Determination, states that if an SSC is not initially declared inoperable there must be reasonable assurance that the SSC is operable and the ODP will support that assurance.
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| As is currently, following receipt of the Control Room annunciator denoting Operational Basis Earthquake Exceeded, the Reactor Coolant System Leakage Detection Instrumentation will be declared inoperable and required actions of TS 3.4.15 will be applied.
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| U.S. Nuclear Regulatory Commission RA-23-0042 April 24, 2023 Commitment Tracking Number: AR 2442514 Existing Commitment:
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| A Preventive Maintenance (PM) Program will be implemented by November 15, 1987 for all safety related electric motor operators (EMO's). Items to be inspected every five years will include:
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| For Limitorque Actuators:
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| i) Gear housing grease (quantity, color, consistency) ii) Stem lubrication iii) Bearing lubrication iv) Limit switch grease (quantity, color, consistency) v) Wiring insulation, contacts (visual)
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| Revised Commitment:
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| For Limitorque Actuators, inspections (iv) and (v) will be performed on the same frequency as the MOV Diagnostic test. The diagnostic test frequency is controlled by Catawba's commitments to the Joint Owners Group Program on MOV Periodic Verification (JOG) and GL96-05.
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| i) Gear housing grease (quantity, color, consistency) [no commitment change]
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| ii) Stem lubrication [no commitment change]
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| iii) Bearing lubrication [no commitment change]
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| iv) Limit switch grease (quantity, color, consistency) [commitment change]
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| v) Wiring insulation, contacts (visual). [commitment change]
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| Basis for Revision:
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| Commitment Change AR 2442514 is created to align the frequency of performing inspections (referred to as Comprehensive Limitorque PMs at CNS) on Limitorque actuator limit switch grease and visual inspection on wiring insulation and contacts with other diagnostic activities.
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| Duke Power's response to NRC Bulletin 85-03 stated these inspections would be performed on a 5 year frequency. NRC Bulletin 85-03 was issued in November of 1985 to address motor-operated valve common mode failures during plant transients due to improper switch settings.
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| Duke responded to this NRC Bulletin in a later dated May 16, 1986, for McGuire, Catawba and Oconee Nuclear Stations (attached). In this letter it was documented that Duke Power would implement a PM program on all safety related motor operators that would inspect gear housing grease, stem lubrication, bearing lubrication, limit switch grease, and visual on wiring insulation and contacts on Limitorque operators every 5 years. Bulletin 85-03 was followed by two related Generic Letters (GL89-10 and GL96-05).
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| * Generic Letter 89-10 (6/28/89), "Safety Related Motor Operated Valve Testing and Surveillance"
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| * Generic Letter 96-05 (9/18/96), "Periodic Verification of Design-Basis Capability of Safety-Related Motor-Operated Valves" Over the past 35 years, MOV Design-Basis capability and reliability have improved. MOV diagnostic testing and preventive maintenance methods have also improved. Aligning MOV diagnostic testing and certain PM activities optimizes workflow and provides the benefit of having as-left diagnostics follow all PM activities. Diagnostic test frequencies are determined based on
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| U.S. Nuclear Regulatory Commission RA-23-0042 April 24, 2023 GL96-05 and the Joint Owners Group Program on MOV Periodic Verification (JOG). At Catawba, diagnostic test frequencies range from 18 months (1 refueling cycle) to 10 years depending on JOG Class, risk-ranking, and functional margin. Aligning the limit switch grease inspection and wire insulation inspection with the diagnostic test will result in extending the interval of these inspections on most MOVs.
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| The extension of these inspections is justified by operating history at CNS and benchmarking the industry. The work order and corrective action databases were queried going back to 1996 using key words such as hardened grease, limit switch, wire insulation, Limitorque, Beacon, etc.
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| There were no items identified on limit switch grease hardening and wiring/contact issues that would not warrant this extension. Also, two Catawba MOV Maintenance technicians were interviewed and over the past 10 years they have not found any hardened grease in the limit switch compartment during a PM or a complete refurb. These two technicians performed approximately half of these inspections. Catawba has approximately 240 safety related Limitorque actuators. Over the last 10 years we would have performed this inspection 480 times and only a few issues were identified (via interviews and queries). The issues found did not affect valve operation. This supports extending these inspections from 5 years to the frequency that aligns with the MOV diagnostic test that is controlled by GL 96-05.
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| Actuator inspections are administered by Catawba's PM Program which includes ongoing monitoring and appropriate adjustments based on operating experience.
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| REPORT OF INFORMATION REMOVED FROM REVISION 23 OF THE CATAWBA NUCLEAR STATION, UNITS 1 AND 2 UFSAR
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| : 1. Table 1-1, Table 3-4, Section 6.7 reflects abandonment of the old ice machines.
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| : 2. Sections 1.7.2, 4.4.6.4, and 7.8.8 eliminates the Loose Parts Monitoring System (LPMS) from the Catawba licensing basis per PWROG-20016-P-A, PWROG - Regulatory Relaxation for PWR Loose-Part-Detection Systems, Revision 0. Similarly, the discussion of U.S. Nuclear Regulatory Commission (NRC) Regulatory Guide (RG) 1.133, Loose-Part Detection Program for the Primary System of Light-Water-Cooled Reactors, Revision 1 in UFSAR Section 1.7.1 is being revised to reflect removal of the LPMS from Catawbas Licensing Basis. PWROG-20016-P-A, PWROG - Regulatory Relaxation for PWR Loose-Part-Detection Systems, Revision 0 is being added to UFSAR Reference Sections 1.7.2 and 4.4.7. Catawbas existing licensing basis for the LPMS is consistent with the guidance provided in RG 1.133, Revision 1.
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| REPORT OF INFORMATION REMOVED FROM REVISION 23 OF THE CATAWBA NUCLEAR STATION, UNITS 1 AND 2 UFSAR
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| : 1. Table 1-1, Table 3-4, Section 6.7 reflects abandonment of the old ice machines.
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| : 2. Sections 1.7.2, 4.4.6.4, and 7.8.8 eliminates the Loose Parts Monitoring System (LPMS) from the Catawba licensing basis per PWROG-20016-P-A, PWROG - Regulatory Relaxation for PWR Loose-Part-Detection Systems, Revision 0. Similarly, the discussion of U.S. Nuclear Regulatory Commission (NRC) Regulatory Guide (RG) 1.133, Loose-Part Detection Program for the Primary System of Light-Water-Cooled Reactors, Revision 1 in UFSAR Section 1.7.1 is being revised to reflect removal of the LPMS from Catawbas Licensing Basis. PWROG-20016-P-A, PWROG - Regulatory Relaxation for PWR Loose-Part-Detection Systems, Revision 0 is being added to UFSAR Reference Sections 1.7.2 and 4.4.7. Catawbas existing licensing basis for the LPMS is consistent with the guidance provided in RG 1.133, Revision 1.}}
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